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US11149544 | Combined telemetry and control system for subsea applications | Dec 19, 2016 | Benoit Deville, Arnaud Croux, Stephane Vannuffelen | SCHLUMBERGER TECHNOLOGY CORPORATION | International Preliminary Report on Patentability issued in the related PCT Application PCT/US2016/067413, dated Jun. 25, 2019 (13 pages).; International Search Report and Written Opinion issued in the related PCT Application PCT/US2016/067413, dated Sep. 7, 2017 (14 pages). | 8994550; March 31, 2015; Millot et al.; 20060065401; March 30, 2006; Allen; 20070000667; January 4, 2007; MacKenzie et al.; 20120126992; May 24, 2012; Rodney et al.; 20130083627; April 4, 2013; Yates; 20130335232; December 19, 2013; Conway et al. | 2010020354; February 2010; WO; WO-2010020354; February 2010; WO | ['A technique facilitates communication in a subsea well application.', 'The technique involves deployment of a blowout preventer subsea control and telemetry system to a subsea location proximate a wellbore.', 'The blowout preventer subsea control and telemetry system is coupled to both a blowout preventer system and a wireless telemetry system.', 'The wireless telemetry system has a plurality of repeaters deployed along the wellbore.', 'The blowout preventer subsea control and telemetry system is used both to collect data from the wireless telemetry system and to control operation of the blowout preventer system.', 'For example, the blowout preventer subsea control and telemetry system may receive control signals from a surface system and also relay data to the surface system through a common communication line.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis invention is related to the field subsea control and telemetry, and, more particularly, to a blowout preventer and telemetry system.', 'DESCRIPTION OF THE RELATED ART\n \nIn many hydrocarbon well applications, a wellbore is drilled into a desired hydrocarbon-bearing formation at a subsea location.', 'A blowout preventer system may be positioned over the wellbore at the subsea location and may comprise a plurality of rams and other features controlled at least in part by a surface control system.', 'A well string, e.g. a drill string, may be deployed through the blowout preventer system and into the wellbore for performance of the desired drilling or other downhole operation.', 'In some applications, various sensors are deployed downhole and a telemetry system is used to convey data to the seabed.', 'The use of separate control systems and separate dedicated control lines, e.g. an umbilical and a separate control line cable, routed from the subsea location to surface control systems can add expense and complexity to a given subsea operation.', 'SUMMARY\n \nCertain aspects of some embodiments disclosed herein are set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms the invention might take and that these aspects are not intended to limit the scope of the invention.', 'Indeed, the invention may encompass a variety of aspects that may not be set forth below.', 'In general, a methodology and system involve deployment of a blowout preventer (BOP) subsea control and telemetry system to a subsea location proximate a wellbore.', 'The BOP subsea control and telemetry system is coupled to both a blowout preventer system and a wireless telemetry system.', 'The wireless telemetry system has a plurality of repeaters, e.g. acoustic signal repeaters, deployed along the wellbore.', 'The BOP subsea control and telemetry system is used both to collect data from the wireless telemetry system and to control operation of the blowout preventer system.', 'For example, the BOP subsea control and telemetry system may receive control signals from a surface system and also relay data to the surface system through a common communication line.', 'However, many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nCertain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements.', 'It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:\n \nFIG.', '1\n is a schematic illustration of an example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;\n \nFIG.', '2\n is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;\n \nFIG.', '3\n is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;\n \nFIG.', '4\n is a schematic illustration of a portion of an example of a blowout preventer system having a repeater employed in a wireless telemetry system, according to an embodiment of the disclosure;\n \nFIG.', '5\n is a schematic illustration of a portion of another example of a blowout preventer system having a repeater employed in a wireless telemetry system, according to an embodiment of the disclosure;\n \nFIG.', '6\n is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;\n \nFIG.', '7\n is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure; and\n \nFIG.', '8\n is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the present disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below for purposes of explanation and to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'When introducing elements of various embodiments, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Moreover, any use of “top,” “bottom,” “above,” “below,” other directional terms, and variations of these terms is made for convenience, but does not mandate any particular orientation of the components.', 'In the specification and appended claims: the terms “connect,” “connection,” “connected,” “in connection with,” and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements;” and the term “set” is used to mean “one element” or “more than one element.”', 'Further, the terms “couple,” “coupling,” “coupled,” “coupled together,” and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements.”', 'As used herein, the terms “up” and “down,” “upper” and “lower,” “upwardly” and downwardly,” “upstream” and “downstream;” “above” and “below;” and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure.', 'In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure.', 'However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.', 'With respect to certain embodiments of the present disclosure, a system and methodology are provided which facilitate communication of signals, e.g. data and control signals, between subsea systems and a surface control.', 'The system and methodology enable the desired communication in subsea applications with substantially reduced expense and complexity.', 'For example, a subsea control and telemetry system may be used to receive and transmit various signals, such as control signals and data signals.', 'In some applications, the data signals may comprise sensor data relayed to the subsea control and telemetry system via a telemetry system, e.g. a wireless telemetry system, deployed along a wellbore.', 'The control signals may comprise signals sent from a surface control regarding operation of, for example, a hydraulic actuation system used to control rams and other features of a blowout preventer system.', 'According to an embodiment, a BOP subsea control and telemetry system is deployed to a subsea location proximate a wellbore.', 'The BOP subsea control and telemetry system is coupled to both a blowout preventer system and a wireless telemetry system.', 'The wireless telemetry system has a plurality of repeaters, e.g. acoustic signal repeaters, deployed along the wellbore.', 'The BOP subsea control and telemetry system is used both to collect data from the wireless telemetry system and to control operation of the blowout preventer system.', 'In this example, the BOP subsea control and telemetry system is used to both receive control signals from a surface system and to relay data to the surface system through a common umbilical.', 'The overall well system structure reduces the expense and complexity of the system by using the BOP subsea control and telemetry system for both BOP system control and data transfer from the downhole telemetry system, e.g. downhole wireless telemetry system.', 'Consequently, the downhole telemetry system may be operated without its own dedicated cable for communication between the seabed and the surface.', 'Routing a separate cable for the telemetry system down along a tubing string can be expensive, difficult, and time-consuming.', 'By interfacing the BOP subsea control and telemetry system with surface control via a common umbilical, the desired communication between the seabed and the surface is achieved with a simpler, less expensive system.', 'The downhole telemetry system may comprise various types of systems depending on the parameters of a given application.', 'In some applications, the downhole telemetry system may be in the form of a wireless telemetry system such as an acoustic or electromagnetic wireless telemetry system.', 'Additionally, the wireless telemetry system may comprise a plurality of repeaters positioned within a borehole, e.g. along a tubing string.', 'The repeaters may each comprise equipment that can both receive and transmit messages wirelessly.', 'For example, a wireless repeater may comprise a sensor to receive a wireless signal, a transmitter to transmit the wireless signal, electronics to handle the receiving and transmitting of wireless messages, and a power source, e.g. a battery.', 'The sensor and transmitter may be combined into a single component acting as a transceiver.', 'The wireless telemetry system is able to transmit the desired data by, for example, modulating a wireless signal.', 'The method of modulation may involve the transmission of analog and/or digital information.', 'For example, the modulation method may comprise AM, FM, PSK (phase-shift keying), FSK (frequency-shift keying), OFDM (orthogonal frequency-division multiplexing), or another suitable modulation method.', 'Implementation of the specific modulation method may be managed by the electronics with respect to transmission and reception of the wireless signal.', 'The wireless repeaters may be deployed downhole and may be arranged in a communication network.', 'Additionally, a suitable network communication protocol be implemented for managing the communication between repeaters.', 'Depending on the implementation, the telemetry may be one way telemetry, half duplex telemetry, or full duplex telemetry.', 'Additionally, the wireless telemetry system may comprise a series of devices interfaced with the repeaters which may be used for producing data of interest for the user or enabling remote control of their operation.', 'The interfaces between the devices and the repeaters may be constructed to allow data acquisition from the device and/or control of the device through the wireless communication system.', 'In well applications, the repeaters of the wireless telemetry system may be deployed downhole via a suitable conveyance, e.g. a pipe.', 'For example, the suitable conveyance may comprise pipe components in a well string, including pipes used for production, for pumping downhole, for drilling, or for other well related activities.', 'The pipe may comprise production tubing, coiled tubing, casing, drill pipe, and/or other suitable tubular components.', 'The repeaters of the wireless telemetry system may be clamped onto the pipe or coupled with the pipe via dedicated carriers connected into, e.g. threadably engaged into, the well string.', 'The wireless telemetry system also may comprise an acquisition and control system which may be used to communicate with remote devices.', 'For example, the acquisition and control system may be used to control the remote devices and/or to acquire data from the remote devices.', 'The control and acquisition system also may provide an interface between the user and the telemetry data while also providing the ability for a user to operate the telemetry system.', 'The actual implementation of the control and acquisition system can vary depending on the application, but an example comprises a processor-based computer system.', 'The processor-based computer system may utilize software for interfacing with the repeaters of the wireless telemetry system and for using the repeaters as an entry point to the communication network.', 'If the wireless telemetry system is in the form of an acoustic system, the wireless signal comprises an acoustic signal.', 'The acoustic signal travels along the borehole, e.g. along a structure deployed in the borehole.', 'Acoustic signals may be propagated through fluid, e.g. gas or liquid, or through solids, e.g. metallic structures, rock structures, or organic structures.', 'The pipes, e.g. tubular components, of a well string may be used for carrying the acoustic signals and often provide a good wave guide for the acoustic signal.', 'The acoustic signals also are able to travel through a variety of complex mechanical structures associated with the well string, e.g. mechanical structures in a bottom hole assembly.', 'Acoustic signals may be generated in downhole conditions by various acoustic signal generators, such as piezo electrical transducers, used as transceiver assemblies to both receive and transmit the wireless signal.', 'Other wireless signals also may be employed for propagating information along the borehole.', 'For example, the wireless telemetry system may comprise an electro-magnetic communication system using electro-magnetic signals.', 'In such an application, a wireless signal may be in the form of a current injected into the formation.', 'An example of an electro-magnetic telemetry system is the JADE™ Telemetry System available from Schlumberger Corporation.', 'An example of an acoustic wireless telemetry system is the Muzic™ Wireless Telemetry system available from Schlumberger Corporation.', 'This type of wireless acoustic telemetry system is based on a backbone network of repeaters that can be interfaced with many types of downhole equipment.', 'For example, the acoustic wireless telemetry system may comprise repeaters connected with test valves, pressure gauges, fluid samplers, firing heads, and a variety of other devices which may be used downhole.', 'As described in greater detail below, various wireless telemetry systems may be used to relay data, e.g. sensor data, wirelessly from a downhole location to a repeater or other suitable device located at a seabed location.', 'The seabed repeater/device may be coupled with a BOP subsea control and telemetry system to enable transmission of the data to a surface control via the umbilical or other common communication line.', 'Various types of information, such as sensor data or control signals, may be carried by a wireless signal, e.g. an acoustic signal, transmitted along a tubing string, e.g. a drill string, completion string, or other well string.', 'For example, the tubing string may be deployed at least partially within a wellbore and may comprise a plurality of wireless acoustic repeaters which receive and then transmit the acoustic signal along the tubing string.', 'The acoustic signal may embody data from, for example, a sensor or a plurality of sensors deployed downhole in the wellbore to monitor pressure data, temperature data, and/or other downhole data.', 'The acoustic signal is received at each repeater and then the acoustic signal is transmitted to the next sequential repeater at a desired frequency and bit rate.', 'An example of this type of acoustic system is described in US Patent No. 8,994,550, assigned to Schlumberger Technology Corporation.', 'The wireless telemetry system may effectively comprise a network of nodes in the form of repeaters attached, e.g. clamped, to the production pipe or other tubing string components.', 'Each repeater can receive and send acoustic messages.', 'The acoustic messages generated are relayed from one node to another until reaching their final destination.', 'The repeaters also may be configured differently depending on their specific role and on their location along the tubing string.', 'The repeaters may be standalone repeaters or they can be interfaced with downhole equipment.', 'Furthermore, the wireless telemetry system may be constructed to interface with various devices via a digital interface.', 'Downhole repeaters and surface repeaters may be used at various positions along the tubing string and may comprise a surface repeater, e.g. an uppermost repeater, which is connected to a wireless acquisition front-end of the acoustic network and to a dedicated computer used to control and monitor downhole equipment.', 'In various embodiments, the wireless telemetry system is combined with a blowout preventer system in the form of an electrohydraulic system comprising several specialized valves (often called a BOP) stacked together.', 'The valves enable the controlling and sealing of a subsurface well in case of uncontrolled release of subsurface fluid.', 'The BOP may be used in an early phase of well construction (e.g. drilling, casing, cementing) before a production Christmas tree is installed.', 'The BOP (or BOPs) also may be very useful in the context of a well test in which the well is produced with a temporary subsurface to surface production system.', 'In this context, the BOP is acting as a safety barrier in case control of the well is lost.', 'Blowout preventer systems are constructed to provide control over the well in the presence of tubing and cable, e.g. in the presence of a drill string, a production pipe, coiled tubing, hydraulic lines, wireline, and/or other equipment.', 'In general, a BOP system may be composed of several BOPs which each have a specific function.', 'Examples of BOPs include a RAM BOP, having a pipe ram and a blind and shear ram, and an annular RAM.', 'In the context of a subsea operation, embodiments of the BOP system may comprise equipment such as a lower BOP stack, a lower marine riser package (LMRP), an electrohydraulic umbilical, and a control system.', 'The lower BOP stack may be attached to a wellhead through a wellhead connector and may comprise blind rams and annular rams stacked on top of each other.', 'The configuration of the lower BOP stack may be specifically selected for each BOP system and may vary from one application to another.', 'The lower BOP stack provides control over the well in case of an emergency, e.g. control over a subsurface flow either by sealing the well annulus or by cutting and sealing a production pipe.', 'According to certain embodiments, the LMRP may be constructed from an additional stack of BOPs, e.g. annular BOPs.', 'The LMRP provides an interface with a riser extending upwardly and connecting with a surface rig.', 'The interface comprises, for example, a knuckle joint and an in riser adapter.', 'The lower BOP stack and the LMRP may be connected through a BOP latch which allows disconnection of the two structures.', 'For example, the LMRP may be disconnected from the lower BOP stack during the course of a maintenance operation or an emergency.', 'Once the LMRP is disconnected, the rig recovers its freedom of movement and thus the LMRP disconnection also may be triggered in the case of bad weather.', 'As described in greater detail below, the operation of the BOP system from the surface may be facilitated by an electrohydraulic umbilical.', 'The electrohydraulic umbilical may be constructed with a bundle of hydraulic hoses and cables.', 'The hydraulic hoses may be used to provide hydraulic power to the seabed so as to enable actuation of the various BOP rams.', 'The cables may be in the form of electrical and/or optical cables used for communication with the surface as well as providing electrical power to the seabed.', 'The communication may be bi-directional from seabed to surface and from surface to seabed.', 'The control system also is coupled with the electrical and/or optical cables and may comprise a surface control system and a seabed control system coupled via the umbilical.', 'As described herein, the umbilical may be used to carry signals with respect to both the BOP system and the subsea wireless telemetry system.', 'Various embodiments described herein are useful in well test applications involving a subsea landing string in a subsea environment.', 'A well test is an operation in which a temporary set of equipment at the surface and downhole is deployed to set a well in production while monitoring certain parameters.', 'In a subsea environment, the well test is enabled by deploying a subsea landing string which has safety equipment coupled to a production pipe to control the production flow in case of emergency and to allow disconnection of the production pipe while stopping the flow.', 'Examples of landing strings which may be used with embodiments of the BOP subsea control and telemetry system are illustrated in, for example, \nFIGS.', '1-5\n and may comprise various components.', 'For example, the landing string may comprise a flow control valve, e.g. a ball valve, used to control flow along the landing string.', 'The landing string also may comprise a latch which allows disconnection of the production pipe in case of an emergency.', 'Additionally, the landing string may comprise a retainer valve which is an optional component located above the latch for controlling flow in an upper section of the tubing of the landing string.', 'The retainer valve closes in case of disconnection at the latch and prevents liquid spill if the latch is disconnected.', 'The retainer valve and the latch may be connected through, for example, a shear sub extension, e.g. a pipe that may be sheared via a shear ram BOP.', 'In some embodiments, there may be a plurality of shear ram BOPs stack together, and the shear sub extension is constructed with a corresponding space out.', 'The landing string also may comprise other equipment, such as a spanner joint, a quick union, a control system, and/or other equipment selected according to the parameters of a given well test operation.', 'The BOP system and the subsea landing string are operated concurrently in case of an emergency.', 'The BOP system enables disconnection of the riser, and the subsea landing string is constructed to allow disconnection of the production pipe.', 'Each system includes a flow control device that may be operated to control flow from the well and also flow within the production pipe.', 'The subsea landing string is deployed down into the lower BOP stack.', 'As described in greater detail below, the BOP subsea control and telemetry system enables operation and control of both the BOP system and components of the landing string via a single, common umbilical to eliminate risk associated with use a separate cable deployed for the subsea landing string.', 'Referring generally to \nFIG.', '1\n, an example of a subsea well system \n20\n is illustrated in which embodiments described herein may be employed.', 'The subsea well system \n20\n comprises a blowout preventer (BOP) system \n22\n positioned proximate a seabed \n24\n and over a wellbore \n26\n drilled into a subsea formation \n28\n.', 'It should be noted BOP system \n22\n may be used in cooperation with a variety of other types of subsea equipment such as a wellhead.', 'A BOP subsea control and telemetry system \n30\n is located at a subsea position proximate the BOP system \n22\n and is used, in part, to control functions of the blowout preventer system \n22\n.', 'Depending on the application, the BOP subsea control and telemetry system \n30\n may comprise a fully integrated system or may comprise separate systems to handle, for example, communication from seabed to surface or for control and acquisition of downhole wireless telemetry.', 'In the example illustrated, the BOP subsea control and telemetry system \n30\n is mounted to the BOP system \n22\n.', 'The subsea well system \n20\n further comprises a wireless telemetry system \n32\n having a plurality of wireless repeaters \n34\n, e.g. wireless acoustic repeaters, positioned along a tubing string \n36\n (e.g. a tubing string comprising production tubing) extending down into wellbore \n26\n.', 'At least some of the repeaters \n34\n are positioned downhole in wellbore \n26\n along the production tubing/tubing string \n36\n.', 'The wireless telemetry system \n32\n further comprises a separate repeater \n38\n, e.g. a BOP mounted repeater, located externally of the tubing string \n36\n.', 'The external repeater \n38\n is coupled in communication with the BOP subsea control and telemetry system \n30\n via, for example, a wired interface \n40\n.', 'In some applications, a plurality of repeaters \n38\n may be used to provide redundancy.', 'The BOP subsea control and telemetry system \n30\n receives telemetry data from the wireless telemetry system \n32\n and processes and/or relays the telemetry data to a surface control system \n42\n.', 'In some embodiments, the BOP subsea control and telemetry system \n30\n comprises a processor system able to process and relay telemetry data from the wireless telemetry system \n32\n to surface control system \n42\n while also processing and relaying control signals from surface control system \n42\n to BOP system \n22\n.', 'Depending on the application, the surface control system \n42\n may comprise a combined BOP surface control and acquisition system \n44\n and wireless telemetry control and acquisition system \n46\n.', 'The combined systems \n44\n, \n46\n may be used to send and/or receive signals with respect to the BOP system \n22\n and wireless telemetry system \n32\n, respectively.', 'The surface control system \n42\n may be communicatively coupled with BOP subsea control and telemetry system \n30\n via a suitable communication line \n48\n.', 'By way of example, the communication line \n48\n may be in the form of an umbilical \n50\n which is able to provide electrical signals to and from the BOP subsea control and telemetry system \n30\n.', 'The umbilical \n50\n can be used to carry control signals, e.g. commands, from surface control system \n42\n to subsea system \n30\n for controlling BOP operation.', 'In some applications, control signals also may be supplied to the wireless telemetry system \n32\n.', 'Additionally, the umbilical \n50\n can be used to carry data signals from the wireless telemetry system \n32\n and BOP system \n22\n via transmission from BOP subsea control and telemetry system \n30\n to the surface control system \n42\n.', 'In some applications, the umbilical \n50\n also may comprise hydraulic control lines for supplying hydraulic control fluid to, for example, system \n30\n and BOP system \n22\n.', 'Additionally, some embodiments may utilize redundant communication lines within the umbilical \n50\n or plural umbilicals \n50\n to provide the desired redundancy.', 'The umbilical \n50\n also may utilize different control lines for different functions.', 'For example, a communication line or lines within the umbilical \n50\n may be dedicated to safety control functions, while separate communication lines may be used for monitoring functions, telemetry functions, and/or other functions.', 'Depending on the application, the tubing string \n36\n may have a variety of configurations.', 'For example, the tubing string \n36\n may be in the form of a test string, drill string, completion string, or other suitable well string for use in a subsea application.', 'The tubing string \n36\n extends down through an internal passage \n52\n of BOP system \n22\n and into wellbore \n26\n.', 'In some applications, a riser \n54\n extends upwardly toward a sea surface \n56\n and tubing string \n36\n is deployed down through the riser \n54\n and through BOP system \n22\n into wellbore \n26\n.', 'Tubing string \n36\n also may comprise an upper tubing string \n58\n coupled with a lower tubing string \n60\n via, for example, a latch assembly \n62\n.', 'A shear sub \n63\n may be positioned above the latch assembly \n62\n or at another suitable location (see, for example, \nFIG.', '2\n).', 'The tubing string \n36\n may be deployed from a suitable surface structure located at sea surface \n56\n.', 'By way of example, the surface structure may comprise a rig and may be in the form of a platform or vessel.', 'The surface control system \n42\n may be located in whole or in part at surface \n56\n on, for example, the surface structure.', 'The wireless telemetry system \n32\n may comprise a variety of wireless systems for communicating data between repeaters \n34\n.', 'For example, signals may be transmitted electromagnetically or acoustically from one wireless repeater \n34\n to the next.', 'The uppermost repeater \n34\n may be used to communicate with BOP mounted repeater \n38\n so that data may be relayed to a location external to tubing string \n36\n and then to BOP subsea control and telemetry system \n30\n via interface \n40\n.', 'In the example illustrated, interface \n40\n is a wired interface but various wireless interfaces also may be employed to transmit data between repeater \n38\n and subsea system \n30\n.', 'Similarly, an interface \n64\n may be used to transmit signals between at least one of the repeaters \n34\n, e.g. the uppermost repeater \n34\n, and repeater \n38\n.', 'The interface \n64\n may be in the form of a wireless interface using, for example, acoustic or electromagnetic transmission of signals.', 'According to one embodiment, the wireless telemetry system \n32\n is in the form of a wireless acoustic telemetry system, such as the Muzic™ Wireless Telemetry system discussed above and available from Schlumberger Corporation.', 'This type of wireless acoustic telemetry system \n32\n may be operated by transmitting acoustic signals along tubing string \n36\n.', 'The wireless repeaters \n34\n may be in the form of acoustic repeaters coupled, e.g. clamped, to tubing string \n36\n.', 'The wireless acoustic repeaters \n34\n are able to receive acoustic signals traveling along tubing string \n36\n and to relay those acoustic signals to the next sequential repeater \n34\n.', 'This process is repeated until the data can be transmitted externally to repeater \n38\n (mounted externally of tubing string \n36\n) and then to BOP subsea control and telemetry system \n30\n.', 'In some applications, wireless interface \n64\n may be in the form of an acoustic interface using acoustic signals transferred through structural materials and/or fluid between at least one of the repeaters \n34\n and external repeater \n38\n.', 'The data may then be relayed via umbilical \n50\n to, for example, surface control system \n42\n.', 'The wireless telemetry system \n32\n may be used to transmit a variety of data from a downhole location.', 'For example, the wireless telemetry system \n32\n may be coupled with a plurality of sensors \n66\n, e.g. pressure sensors and temperature sensors, monitoring desired downhole parameters.', 'The data may be collected by sensors \n66\n in a variety of applications.', 'For example, sensors \n66\n and wireless telemetry system \n32\n may be used with various landing strings, production pipe, test strings, completion strings, drill strings, or other suitable tubing strings \n36\n.', 'In some applications, the wireless telemetry system \n32\n may be used bi-directionally to also enable communication of signals, e.g. control signals, to various devices, e.g. landing string devices, located in wellbore \n26\n.', 'Referring generally to \nFIG.', '2\n, another embodiment of subsea well system \n20\n is illustrated.', 'In this example, BOP subsea control and telemetry system \n30\n is again mounted proximate BOP system \n22\n on, for example, a suitable mounting structure \n68\n.', 'System \n30\n may be operatively coupled with wireless telemetry system \n32\n via wired interface \n40\n and with BOP system \n22\n via a suitable communication interface \n70\n which may comprise hydraulic and/or electrical control lines.', 'In some applications, the interfaces \n40\n, \n70\n may be combined in an integrated system.', 'According to an embodiment, the external repeater \n38\n may be mounted to BOP system \n22\n at an upper end of the BOP system \n22\n for communication with the uppermost repeater \n34\n, e.g. acoustic repeater, via wireless interface \n64\n.', 'The uppermost repeater \n34\n is mounted above seabed \n24\n along tubing string \n36\n.', 'In this embodiment and other embodiments described herein, the repeater \n38\n may be a BOP mounted repeater and mechanically coupled along an outside of the BOP system \n22\n.', 'However, the external repeater \n38\n also may be embedded or otherwise mounted within the structure of BOP system \n22\n and communicatively coupled with, for example, uppermost repeater \n34\n.', 'Depending on the parameters of a given application, blowout preventer system \n22\n may be coupled with a wellhead \n71\n via a suitable wellhead connector.', 'The blowout preventer system \n22\n also may comprise a variety of components, including components functionally controlled via BOP subsea control and telemetry system \n30\n.', 'By way of example, BOP system \n22\n may comprise a plurality of rams, such as a plurality of shear rams \n72\n and a plurality of pipe rams \n74\n which form a lower BOP stack \n75\n.', 'The rams utilized in lower BOP stack \n75\n are sometimes in the form of blind rams and annular rams.', 'The BOP system \n22\n also may comprise various other features, such as additional sealing and/or closure components \n76\n located in a lower marine riser package (LMRP) \n77\n.', 'By way of example, the sealing and/or closure components \n76\n may be in the form of annular BOP rams.', 'The LMRP \n77\n may be coupled with the lower BOP stack \n75\n via a suitable connector, such as a BOP latch.', 'Additionally, The LMRP \n77\n provides an interface with riser \n54\n which may extend upwardly for connection with a surface rig.', 'The interface comprises, for example, a knuckle joint and an in riser adapter.', 'The repeater \n38\n may be mounted at various positions along BOP system \n22\n selected to enable dependable communication with repeater \n34\n.', 'In the illustrated example, the repeater \n38\n is located at a position above the rams \n72\n, \n74\n.', 'However, the repeater \n38\n may be mounted at other positions along and/or within BOP system \n22\n, as described in greater detail below.', 'Similarly, tubing string \n36\n may comprise a variety of cooperating strings and components.', 'In the example illustrated, tubing string \n36\n comprises a landing string \n78\n which may be in the form of a test string.', 'However, tubing string \n36\n also may comprise other types of tubing strings.', 'In the specific example illustrated, the tubing string \n36\n is a test string comprising upper tubing section \n58\n engaged with lower tubing string \n60\n via latch assembly \n62\n.', 'In this example, the uppermost repeater \n34\n is located along tubing string \n36\n above latch assembly \n62\n.', 'Examples of other tubing string features comprise a flow valve \n80\n located below latch assembly \n62\n and positioned to enable selective blockage of flow along the lower tubing string \n60\n.', 'The landing string \n78\n may comprise many types of components to facilitate a given testing application or other application.', 'In the embodiment illustrated, the landing string \n78\n comprises additional components, such as a deep water control system \n82\n, a pressure and temperature system carrier \n84\n, a quick union \n86\n, a spanner joint \n88\n, and a retainer valve \n90\n.', 'In some applications, the landing string \n78\n also may comprise a junk basket \n92\n located within riser \n54\n above various other components.', 'If the wireless telemetry system \n32\n is in the form of a wireless acoustic telemetry system transmitting acoustic signals along tubing string \n36\n, an acoustic filter \n94\n may be located along tubing string \n36\n to filter out undesirable acoustic noise.', 'In the embodiment illustrated, the surface control system \n42\n comprises or may be coupled with an input/output device \n96\n, such as a computer.', 'The computer \n96\n may be a personal computer or other suitable computer for displaying processed data received from wireless telemetry system \n32\n.', 'For example, the computer \n96\n may comprise a display screen \n98\n for displaying downhole data collected from, for example, sensors \n66\n and relayed to the surface via wireless telemetry system \n32\n, BOP subsea control and telemetry system \n30\n, and umbilical \n50\n.', 'The computer \n96\n also may comprise an input device \n100\n, e.g. a keyboard, for providing control commands which may be relayed down to the BOP \n22\n and/or wireless telemetry system \n32\n.', 'In the example illustrated, the computer \n96\n is coupled with surface control system \n42\n via an appropriate network \n102\n such as a wired and/or wireless network.', 'Depending on the application, the computer \n96\n may be located on-site with surface control system \n42\n; or network \n102\n may be used to enable utilization of computer \n96\n from a remote location.', 'Referring generally to \nFIG.', '3\n, another embodiment of subsea well system \n20\n is illustrated.', 'This latter embodiment has certain components common to the embodiment described above and illustrated in \nFIG.', '2\n.', 'However, the uppermost repeater \n34\n is located below latch assembly \n62\n and below seabed \n24\n within wellbore \n26\n.', 'The BOP mounted repeater \n38\n is positioned closer to seabed \n24\n at a lower end of BOP system \n22\n to enable communication between the uppermost repeater \n34\n and external repeater \n38\n via wireless interface \n64\n.', 'As with the embodiment illustrated in \nFIG.', '2\n, the various illustrated BOP components, tubing string sections, and tubing string components may be adjusted or changed according to the parameters of a given subsea well operation.', 'Depending on the embodiment, the surface control system \n42\n may be constructed such that the wireless telemetry and control system \n46\n is embedded within the BOP surface control and acquisition system \n44\n or the systems can be operated separately in parallel with separate dedicated hardware and software infrastructure.', 'The level of integration and infrastructure sharing between the control systems \n44\n, \n46\n may vary depending on the parameters of a given application.', 'In a variety of subsea operations, the umbilical \n50\n and certain control systems, e.g. BOP surface control and acquisition system \n44\n, may be constructed as redundant systems.', 'A similar approach may be used for the external BOP repeater \n38\n.', 'For example, multiple repeaters \n38\n may be deployed on the BOP system \n22\n and may be redundantly coupled with multiple communication paths available within the single, common umbilical \n50\n.', 'Referring generally to \nFIGS.', '4 and 5\n, additional embodiments are illustrated in which components of the integrated control system, e.g. repeater \n38\n, may be more integrated into the BOP system \n22\n.', 'Referring initially to \nFIG.', '4\n, an embodiment is illustrated in which at least one repeater \n38\n is positioned in a service hole \n104\n located in a body structure \n106\n of BOP system \n22\n.', 'The service hole or holes \n104\n may be formed through body structure \n106\n to provide access to the open interior \n108\n of BOP system \n22\n.', 'Depending on the application, the service hole(s) \n104\n may be used to deploy pressure temperature sensors for monitoring parameters within the BOP system \n22\n.', 'The service holes \n104\n also may be connected to BOP kill lines and may be used to inject kill fluid during certain operations.', 'In the illustrated example, the repeater \n38\n is integrated into the BOP system \n22\n via placement within a corresponding service hole \n104\n.', 'An appropriate cap structure \n110\n, e.g. a flange, may be placed over the corresponding service hole \n104\n to enclose repeater \n38\n therein.', 'In the example illustrated, the repeater \n38\n is operatively coupled, e.g. electronically connected, with corresponding electronics \n112\n.', 'The electronics \n112\n are part of or work in cooperation with interface \n40\n to enable communication with the BOP subsea control and telemetry system \n30\n.', 'In some applications, redundancy may be provided by positioning a plurality of repeaters \n38\n in a plurality of service holes \n104\n.', 'As with other embodiments, the repeater or repeaters \n38\n may have a variety of structures.', 'An example is an acoustic repeater, such as an acoustic repeater used with the Muzic™ Wireless Telemetry system available from Schlumberger Corporation.', 'Depending on the application, the repeater \n38\n may be integrated into body structure \n106\n and thus placed in direct contact with the open interior passage \n108\n of BOP system \n22\n.', 'The close placement to interior \n108\n facilitates communication with, for example, the uppermost repeater \n34\n disposed along tubing string \n36\n.', 'Placement of the uppermost repeater \n34\n may be selected based on the location of the service hole \n104\n which receives the repeater \n38\n.', 'In the embodiment illustrated, the tubing string \n36\n comprises retainer valve \n90\n coupled with latch assembly \n62\n via shear sub extension \n63\n.', 'The valve \n80\n may be positioned beneath latch assembly \n62\n and coupled with, for example, a slick joint \n114\n.', 'When tubing string \n36\n, e.g. a subsea test string, is positioned within BOP system \n22\n, the shear sub extension \n63\n may be located within at least one shear ram \n72\n and slick joint \n114\n may be located within at least one pipe ram \n74\n.', 'Consequently, the uppermost repeater \n34\n may be attached to the shear sub extension \n63\n or to another suitable component proximate repeater \n38\n once tubing string \n36\n is received in BOP system \n22\n.', 'Another embodiment is illustrated in \nFIG.', '5', 'and shows repeater \n38\n positioned proximate repeater \n34\n which is clamped to the adjacent shear sub extension \n63\n.', 'For example, the uppermost repeater \n34\n may be mounted just below retainer valve \n90\n and may be conveyed via the shear sub extension \n63\n.', 'In this example, cap structure \n110\n is in the form of a specially constructed flange \n116\n which is able to seal the corresponding service hole \n104\n.', 'Flange \n116\n also may incorporate electronics \n112\n to enable electrical communication from the repeater \n38\n located in the corresponding service hole \n104\n to an external location and to the BOP subsea control and telemetry system \n30\n.', 'Positioning the repeater \n38\n in one of the service holes \n104\n facilitates placement of the repeater \n38\n in close proximity with the corresponding repeater \n34\n, e.g. the uppermost repeater \n34\n located along tubing string \n36\n.', 'The heavy mass of the BOP system \n22\n can provide multiple acoustic paths and can generate substantial attenuation and distortion.', 'By locating the repeaters \n38\n, \n34\n within a short distance, the robustness of the communication is enhanced by reducing the attenuation and distortion.', 'It should be noted the repeater \n38\n may be integrated into other ports, components, or specially designed structures of BOP system \n22\n so as to move the repeater \n38\n into close proximity with the corresponding repeater \n34\n.', 'Referring generally to \nFIG.', '6\n, another embodiment of subsea well system \n20\n is illustrated.', 'In this example, BOP subsea control and telemetry system \n30\n is again mounted proximate BOP system \n22\n on, for example, the mounting structure \n68\n.', 'System \n30\n may be operatively coupled with wireless telemetry system \n32\n and with BOP system \n22\n via suitable communication interfaces, e.g. interfaces \n40\n, \n70\n as described above.', 'In this embodiment, the BOP subsea control and telemetry system \n30\n is implemented in a downhole completions application.', 'For completions applications, a lower completion \n120\n may be run downhole on, for example, drill pipe to a setting position.', 'The wireless telemetry system \n32\n, e.g. acoustic wireless telemetry system, may be used to provide real-time data during installation.', 'The repeaters \n34\n may be deployed at appropriate locations along the tubing string \n36\n including, for example, along the lower completion \n120\n.', 'According to this embodiment, the external repeater \n38\n may be mounted to BOP system \n22\n, e.g. within or along BOP system \n22\n, for communication with the uppermost repeater \n34\n via wireless interface \n64\n.', 'The uppermost repeater \n34\n may be mounted above seabed \n24\n along tubing string \n36\n.', 'In this embodiment and other embodiments described herein, the repeater \n38\n may be a BOP mounted repeater and mechanically coupled along an outside of the BOP system \n22\n.', 'However, the external repeater \n38\n also may be embedded or otherwise mounted within the structure of BOP system \n22\n and communicatively coupled with repeater \n34\n.', 'Referring again to \nFIG.', '6\n, the lower completion \n120\n of tubing string \n36\n may comprise a variety of sand control components.', 'By way of example, the lower completion \n120\n may comprise screens \n122\n, e.g. sand screens, and a wash pipe section \n124\n located below a packer \n126\n.', 'The lower completion \n120\n also may comprise or work in cooperation with components \n128\n disposed above packer \n126\n, e.g. a service tool \n130\n.', 'One or more of the repeaters \n34\n may be located in the screens \n122\n and wash pipe section \n124\n and will be left in wellbore \n26\n at the end of the operation.', 'In this example, at least one of the repeaters \n34\n is located just above the packer \n126\n at, for example, service tool \n130\n so as to: obtain data from the lower completion \n120\n; obtain data from service tool \n130\n; and/or provide instructions to service tool \n130\n.', 'Additional repeaters \n34\n are located along the tubing string \n36\n, e.g. drill string, up to the BOP system \n22\n.', 'The upper repeater \n34\n may be used to communicate wirelessly with BOP mounted repeater \n38\n as with embodiments described above.', 'Referring generally to \nFIG.', '7\n, another embodiment of subsea well system \n20\n is illustrated for use in a subsea liner hanger application.', 'In this example, BOP subsea control and telemetry system \n30\n is again mounted proximate BOP system \n22\n on, for example, the mounting structure \n68\n.', 'System \n30\n may be operatively coupled with wireless telemetry system \n32\n and with BOP system \n22\n via suitable communication interfaces, e.g. interfaces \n40\n, \n70\n as described above.', 'In this embodiment, the BOP subsea control and telemetry system \n30\n is implemented in a downhole application utilizing a subsea liner hanger.', 'For this type of application, the lower completion portion may comprise a liner hanger \n132\n and corresponding liner string \n134\n.', 'The liner hanger \n132\n and liner string \n134\n may be run downhole on, for example, drill pipe to a desired wellbore location before setting the liner hanger \n132\n.', 'By way of example, the liner hanger \n132\n and liner string \n134\n may be run downhole via a liner hanger running tool \n136\n.', 'Some applications may utilize a measurement tool \n138\n disposed above the running tool \n136\n.', 'In some embodiments, sensors and repeaters may not be deployed below the liner hanger, however other embodiments may utilize at least one sensor \n66\n and at least one repeater \n34\n at or beneath the liner hanger \n132\n.', 'Regardless, the repeaters \n34\n may be deployed at appropriate locations along the tubing string \n36\n; and external repeater \n38\n may be mounted to BOP system \n22\n for communication with the uppermost repeater \n34\n via wireless interface \n64\n.', 'In this example, the uppermost repeater \n34\n may be mounted above seabed \n24\n along tubing string \n36\n.', 'As with other embodiments described herein, the repeater \n38\n may be a BOP mounted repeater and mechanically coupled along an outside of the BOP system \n22\n.', 'However, the external repeater \n38\n also may be embedded or otherwise mounted within the structure of BOP system \n22\n and communicatively coupled with repeater \n34\n.', 'Some liner installation and cementing operations involve relatively large vertical displacement of the tubing string \n36\n, e.g. drill string.', 'Consequently, a plurality of repeaters \n34\n, e.g. two repeaters \n34\n, may be installed at suitable upper locations to facilitate interaction with the BOP system \n22\n.', 'The upper locations of the upper repeaters \n34\n are selected so that at least one of the repeaters \n34\n remains in close proximity to BOP system \n22\n during the installation and cementing operations.', 'The close proximity minimizes acoustic impedance.', 'Referring generally to \nFIG.', '8\n, another embodiment of subsea well system \n20\n is illustrated as comprising lower completion \n120\n in the form of an intelligent completion \n140\n.', 'In this example, BOP subsea control and telemetry system \n30\n is again mounted proximate BOP system \n22\n on, for example, the mounting structure \n68\n.', 'System \n30\n may be operatively coupled with wireless telemetry system \n32\n and with BOP system \n22\n via suitable communication interfaces, e.g. interfaces \n40\n, \n70\n as described above.', 'In this embodiment, the BOP subsea control and telemetry system \n30\n is implemented in an intelligent completion application in which intelligent completion \n140\n is located in, for example, a horizontal segment \n142\n of wellbore \n26\n.', 'Similar to the other completions applications described herein, the intelligent completion \n140\n may be in the form of a lower completion run downhole and into horizontal wellbore segment \n142\n via a service tool.', 'The intelligent completion \n140\n may be installed in the well permanently.', 'By way of example, the intelligent completion \n140\n may comprise or may be coupled with an intelligent downhole tool \n144\n constructed to receive data from components of intelligent completion \n140\n and/or to provide control signals to components of intelligent completion \n140\n.', 'The intelligent downhole tool \n144\n may be placed in communication with wireless telemetry system \n32\n via, for example, an inductive coupling \n146\n and corresponding electronics \n148\n, e.g. firmware, which provides data conversion for communication between the lower intelligent completion \n140\n and the wireless telemetry system \n32\n.', 'As with other embodiments described herein, the wireless telemetry system \n32\n may comprise repeaters \n34\n deployed at appropriate locations along the tubing string \n36\n.', 'The external repeater \n38\n may again be mounted to BOP system \n22\n for communication with the uppermost repeater \n34\n via wireless interface \n64\n.', 'The uppermost repeater \n34\n may be mounted above seabed \n24\n along tubing string \n36\n.', 'In this embodiment and other embodiments described herein, the repeater \n38\n may be a BOP mounted repeater and mechanically coupled along an outside of the BOP system \n22\n.', 'However, the external repeater \n38\n also may be embedded or otherwise mounted within the structure of BOP system \n22\n and communicatively coupled with repeater \n34\n.', 'Depending on the specifics of a given application, the lower/intelligent completion \n140\n may comprise many types of components deployed in a cased section of wellbore \n26\n or in an open hole section \n150\n, as illustrated.', 'Examples of completion components comprise screen assemblies \n152\n having corresponding base pipes \n154\n and screens \n156\n, e.g. sand screens.', 'Various packers \n158\n, e.g. swell packers, may be positioned along the completion \n140\n to isolate desired well zones.', 'In some applications, the sand screen assemblies \n152\n may be deployed downhole of a liner hanger \n160\n.', 'However, the intelligent completion \n140\n may comprise many types of components selected according to the parameters of a given downhole application.', 'The methodologies and systems described herein may be used in many types of subsea operations.', 'The wireless telemetry system \n32\n may be used to convey signals acoustically along tubing string \n36\n (or via other wireless methods) from a variety of downhole sensors or other devices.', 'In some applications, the wireless telemetry system \n32\n also may be used to carry signals, e.g. commands, to devices positioned downhole in wellbore \n26\n.', 'The use of BOP subsea control and telemetry system \n30\n for relaying signals with respect to both BOP system \n22\n and wireless telemetry system \n32\n substantially simplifies communication between the surface and subsea components in many types of applications.', 'It should be noted the subsea control and telemetry system \n30\n, as well as the wireless telemetry system \n32\n, may be used in a variety of other borehole applications, including non-wellbore applications.', 'The tubing string \n36\n also may comprise a variety of components and configurations.', 'Additionally, the tubing string \n36\n may be deployed in a variety of vertical and/or deviated, e.g. horizontal, wellbores.', 'The sensors \n66\n also may be used in many types of testing and/or monitoring applications and may be deployed in desired well zones or at other desired positions along wellbore \n26\n.', 'The number and spacing of repeaters \n34\n also may be adjusted according to the parameters of a given environment and application.', 'Similarly, the location of the uppermost repeater \n34\n and the external repeater \n38\n may be selected to ensure reliable communication via interface \n64\n.', 'The processing of data may be performed at a single location or at multiple locations along the overall subsea well system \n20\n.', 'Furthermore, the configuration of the subsea control and telemetry system \n30\n as well as the surface control and acquisition system \n42\n may vary depending on the characteristics of a given system and on the types of signals relayed to or from the surface.', 'Additionally, the BOP subsea control and telemetry system \n30\n may comprise a combination of systems.', 'For example, telemetry used to transfer signals from seabed to surface may not be the same as the telemetry used to control the BOP system.', 'Similarly, BOP systems may have multiple communication systems, e.g. one communication system dedicated to safety control functions and a separate communication system dedicated to non-safety control functions.', 'However, the communication and telemetry may simply be handled via different communication lines/cables in the same umbilical \n50\n.', 'Accordingly, the communication infrastructure may comprise several distinct lines of communication through the single umbilical.', 'Additionally, the single umbilical \n50\n may have redundant communication lines used in cooperation with, for example, redundant repeaters \n38\n.', 'Various applications may utilize a BOP subsea control and telemetry system \n30\n having distinct systems for BOP system control and for wireless control and acquisition while utilizing the same umbilical.', 'Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.'] | ['1.', 'A system for use in a well application, comprising:\na blowout preventer system positioned proximate a seabed and over a wellbore;\na blowout preventer (BOP) subsea control and telemetry system located subsea proximate the blowout preventer to control functions of the blowout preventer system;\na wireless telemetry system having a plurality of wireless repeaters positioned along a tubing string extending down into the wellbore, the wireless telemetry system further comprising a BOP mounted wireless repeater located externally of the tubing string, the BOP mounted repeater being coupled with the BOP subsea control and telemetry system, wherein the BOP mounted wireless repeater communicates with at least one of the plurality of repeaters positioned along a tubing string via a wireless interface;\na surface control system comprising a blowout preventer surface control and acquisition system and a wireless telemetry control and acquisition system; and\nan umbilical coupling the surface control system and the BOP subsea control and telemetry system, the umbilical carrying signals for the blowout preventer system and the wireless telemetry system.', '2.', 'The system as recited in claim 1, wherein the wireless telemetry system comprises a wireless acoustic telemetry system.', '3.', 'The system as recited in claim 2, wherein the wireless acoustic telemetry system relays acoustic signals along the tubing string.', '4.', 'The system as recited in claim 1, wherein the wireless repeaters of the plurality of repeaters are disposed below the seabed along the tubing string.', '5.', 'The system as recited in claim 1, wherein the tubing string comprises a well test subsea landing string.', '6.', 'The system as recited in claim 1, wherein the tubing string comprises a completion string.', '7.', 'The system as recited in claim 1, wherein the BOP mounted wireless repeater is mounted on an exterior of the blowout preventer system.', '8.', 'The system as recited in claim 1, wherein the BOP mounted wireless repeater is integrated into a body structure of the blowout preventer system.', '9.', 'The system as recited in claim 1, wherein the BOP mounted wireless repeater is operatively coupled with the BOP subsea control and telemetry system via a wired interface.', '10.', 'A system, comprising:\na blowout preventer system deployed at a subsea location;\na well string deployed through the blowout preventer system and into a wellbore situated below the blowout preventer system;\na plurality of wireless repeaters disposed along the well string to relay acoustic signals along the well string;\nan external wireless repeater disposed along the blowout preventer system, the external wireless repeater being in wireless communication with the plurality of repeaters; and\na BOP subsea control and telemetry system in communication with both the blowout preventer system and the external wireless repeater, the external wireless repeater enabling communication of wireless signals along the well string.', '11.', 'The system as recited in claim 10, further comprising a surface control system comprising a blowout preventer surface control and acquisition system and a wireless telemetry control and acquisition system.', '12.', 'The system as recited in claim 11, further comprising an umbilical coupling the surface control system and the BOP subsea control and telemetry system, the umbilical carrying data and control signals for both the blowout preventer system and the external wireless repeater.', '13.', 'The system as recited in claim 10, wherein the plurality of wireless repeaters is operated to relay test data from a downhole well test application.', '14.', 'The system as recited in claim 10, wherein the plurality of wireless repeaters is operated to relay sensor data from a plurality of downhole sensors.', '15.', 'The system as recited in claim 10, wherein the blowout preventer system comprises a plurality of rams controlled by the BOP subsea control and telemetry system.', '16.', 'A method, comprising:\ndeploying a BOP subsea control and telemetry system to a subsea location proximate a wellbore;\ncoupling the BOP subsea control and telemetry system to both a blowout preventer and a wireless telemetry system having a plurality of wireless repeaters deployed along a tubing string extending down into the wellbore;\nusing the BOP subsea control and telemetry system to control operation of the blowout preventer and to collect downhole data from the wellbore via the wireless telemetry system; and\nfurther using the BOP subsea control and telemetry system to facilitate the conversion of signals received via an umbilical into wireless signals transmitted along the plurality of wireless repeaters of the wireless telemetry system.', '17.', 'The method as recited in claim 16, further comprising operatively connecting the BOP subsea control and telemetry system with a surface control.', '18.', 'The method as recited in claim 17, wherein operatively connecting comprises connecting the BOP subsea control and telemetry system with the surface control via redundant communication lines located within the umbilical.', '19.', 'The method as recited in claim 18, further comprising operating the wireless telemetry system to relay sensor data from a downhole location.', '20.', 'The method as recited in claim 19, wherein operating comprises relaying the sensor data acoustically along a tubing string and then to an external wireless repeater having an interface with the BOP subsea control and telemetry system.'] | ['FIG.', '1 is a schematic illustration of an example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;; FIG.', '2 is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;; FIG.', '3 is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;; FIG.', '4 is a schematic illustration of a portion of an example of a blowout preventer system having a repeater employed in a wireless telemetry system, according to an embodiment of the disclosure;; FIG.', '5 is a schematic illustration of a portion of another example of a blowout preventer system having a repeater employed in a wireless telemetry system, according to an embodiment of the disclosure;; FIG.', '6 is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure;; FIG. 7 is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure; and; FIG. 8 is a schematic illustration of another example of a subsea well system having a blowout preventer system and a wireless telemetry system, according to an embodiment of the disclosure.'] |
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US11150375 | Phase-based electromagnetic surveys for geological formations | Jan 16, 2013 | Ping Zhang, Nestor Cuevas, Michael Wilt, Jiuping Chen | SCHLUMBERGER TECHNOLOGY CORPORATION | Marsala et al., First Borehole to Surface Electromagnetic Survey in KSA: Reservoir Mapping and Monitoring at a New Scale, Oct. 30-Nov. 2, 2011, SPE Annual Technical Conference and Exhibition, Denver, Colorado, 9 pp.; One Petro Search Results, Jun. 21, 2021, 10 pp. (Year: 2021).; Bahr, “Geological noise in magnetotelluric data: a classification of distortion types”, Physics of The Earth and Planetary Interiors, vol. 66, 1991, pp. 24-38.; Baranwal, et al.,“3-D Modelling Study of Borehole-seafloor Marine CSEM for Shallow Water Case”, Electromagnetic Methods (EAGE), 71st EAGE Conference & Exhibition, vol. 5, 2009, pp. 3175-3179.; Groom, et al.,“Decomposition of magnetotelluric impedance tensors in the presence of local three-dimensional galvanic distortion”, Journal of Geophysical Research: Solid Earth (1978-2012), vol. 94, Issue B2, Feb. 10, 1989, pp. 1913-1925.; Zhang, et al., “Magnetotelluric strike rules”, American Geological Institute, Society of Exploration Geophysicists, vol. 52, No. 3, 1987, pp. 267-278.; International Search Report and Written Opinion issued in PCT/US2014/011760 dated Apr. 21, 2014; 14 pages.; Liu, H., Z. Wang, and Z. He, “Frequency-domain 3d borehole-surface electromagnetic modeling by the volume integral equation method,” 70th EAGE Conference & Exhibition,2008. | 5892361; April 6, 1999; Meyer, Jr. et al.; 7852087; December 14, 2010; Wilt et al.; 20070061080; March 15, 2007; Zhdanov; 20090278543; November 12, 2009; Beste et al.; 20100065278; March 18, 2010; Burtz; 20100231221; September 16, 2010; Rosthal et al.; 20110050232; March 3, 2011; Wilt et al.; 20110068795; March 24, 2011; Duvoisin, III | Foreign Citations not found. | ['An electromagnetic (EM) data acquisition method for a geological formation may include operating EM measurement devices to determine phase and amplitude data from the geological formation.', 'The EM measurement devices may include at least one first EM measurement device within a borehole in the geological formation, and at least one second EM measurement device at a surface of the geological formation.', 'The method may further include processing the phase data independent from the amplitude data to generate a geological constituent map of the geological formation, and identifying different geological constituents in the geological constituent map based upon the measured amplitude data.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nElectromagnetic (EM) data acquisition may be used to collect information regarding geological formations.', 'This information may be particularly helpful for oil and gas exploration, for example.', 'By way of example, EM data acquisition may be performed using surface-to-borehole, borehole-to-surface, and surface EM surveys.', 'With respect to surface-to-borehole and borehole-to-surface EM data acquisition, EM sources (i.e., transmitters) and EM receivers are deployed on a terrestrial surface or sea bottom, and in a borehole(s) within the geological formation as well.', 'One or more transmitters broadcasts an EM signal, such as a sinusoid or a square wave, through the earth to be detected by the receiver(s).', 'This approach utilizes galvanic and EM coupling from the EM measurements, which may be used for formation resistivity imaging from the well outwards into the reservoir, for example.', 'The results may be used to help determine the location and constituency of the geological formation, and in particular the fluid reservoirs, within the geological formation.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'An electromagnetic (EM) data acquisition method for a geological formation may include operating a plurality of EM measurement devices to determine phase and amplitude data from the geological formation.', 'The plurality of EM measurement devices may include at least one first EM measurement device within a borehole in the geological formation, and at least one second EM measurement device at a surface of the geological formation.', 'The method may further include processing the phase data independent from the amplitude data to generate a geological constituent map of the geological formation, and identifying different geological constituents in the geological constituent map based upon the measured amplitude data.', 'A related well-logging system may include a plurality of EM measurement devices to determine phase and amplitude data from a geological formation.', 'The plurality of EM measurement devices may include at least one first EM measurement device within a borehole in the geological formation, and at least one second EM measurement device at a surface of the geological formation.', 'The system may also include a processor to process the phase data independent from the amplitude data to generate a geological constituent map of the geological formation, and identify different geological constituents in the geological constituent map based upon the measured amplitude data.', 'A non-transitory computer-readable medium may have computer-executable instructions for causing a computer to perform steps including, for phase and amplitude data determined by a plurality of EM measurement devices from a geological formation, processing the phase data independent from the amplitude data to generate a geological constituent map of the geological formation.', 'The plurality of EM measurement devices may include at least one first EM measurement device within a borehole in the geological formation and at least one second EM measurement device at a surface of the geological formation.', 'A further step may include identifying different geological constituents in the geological constituent map based upon the measured amplitude data.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a schematic block diagram of a well-logging system in accordance with an example embodiment.\n \nFIG.', '2\n is a flow diagram illustrating method aspects associated with the well-logging system of \nFIG.', '1\n.', 'FIG.', '3\n is a schematic geological constituent map generated based upon the method of \nFIG.', '2\n.\n \nFIG.', '4\n is a graph of amplitude vs. depth of simulated EM data for an example geological formation with and without the presence of conductive karst in the geological formation.\n \nFIG.', '5\n is a graph of simulated relative differences in phase and amplitude vs. depth for the example of \nFIG.', '4\n.\n \nFIG.', '6\n is a graph of amplitude vs. depth of simulated EM data for another example geological formation with and without the presence of resistive karst in the geological formation.\n \nFIG.', '7\n is a graph of relative differences in phase and amplitude vs. depth for the example of \nFIG.', '6\n.', 'DETAILED DESCRIPTION', 'The present description is made with reference to the accompanying drawings, in which example embodiments are shown.', 'However, many different embodiments may be used, and thus the description should not be construed as limited to the embodiments set forth herein.', 'Rather, these embodiments are provided so that this disclosure will be thorough and complete Like numbers refer to like elements throughout.', 'Referring initially to \nFIG.', '1\n, a well-logging system \n20\n which may be used to determine constituents or materials within a geological formation \n21\n based upon surface-to-borehole (STB) or borehole-to-surface (BTS) electromagnetic (EM) measurements is first described.', 'STB and BTS measurements basically differ in whether the EM transmitters are located at the surface of the geological formation \n21\n (i.e., STB), or whether the EM transmitters are located within a borehole \n22\n within the geological formation (i.e., BTS).', 'Accordingly, while the following description will be made with reference to STB, it will be understood that the techniques set forth herein may also be applied to BTS configurations.', 'In the present example, a series or array of EM transmitters or sources \n23\n are illustratively arranged on the surface of the geological formation \n21\n, and an array of EM receivers \n26\n are deployed in the wellbore \n22\n.', 'Each transmitter \n23\n broadcasts an EM signal, such as a sinusoid or a square wave, through the earth to be detected by the receivers \n26\n.', 'The purpose is to use the galvanic and EM coupling from the array of measurements to perform formation resistivity imaging from the well outwardly into the reservoir.', 'The RF transmitters \n23\n may be a grounded wire type or a magnetically coupled loop, for example.', 'Grounded wires may be appropriate for deeper applications, in lower resistivity formations, or in applications where steel casing is used to line the wellbore \n22\n, for example.', 'Surface loops may be appropriate where the contact resistance is relatively high (e.g., dune sand, frozen ground or volcanic cover), or in relatively shallow applications, for example.', 'The EM transmitters \n23\n may be connected by power and telemetry cables \n24\n to a STB (or BTS) controller \n25\n.', 'EM receivers \n26\n are positioned within the borehole \n22\n and may be magnetic field detectors, for example, which may be appropriate where steel well casing is used.', 'Although the EM receivers \n26\n may be axial or three-component, axially-directed magnetic receiver strings have relatively higher sensitivity to conductive structures.', 'Electric dipole receivers may also be used in open-hole sections, for example, and may be appropriate for hydrocarbon detection.', 'They may be useful in horizontal wells, and may also be deployed as permanent sensors.', 'Generally speaking, an EM survey is made by placing the receivers \n26\n in an array covering the depths of interest for each transmitter \n23\n, often by lowering an array of receivers on a wireline cable \n22\n from a wireline truck \n28\n (or other suitable platform) that has computers and data storage devices to record the measurements made by the receivers.', 'The receivers \n26\n may alternatively be placed within the borehole as part of permanent or semi-permanent wellbore completion hardware, on a power and telemetry cable, on slickline, on coiled tubing, or on a drill pipe (e.g., on a logging-while-drilling (LWD) or measurement-while-drilling (MWD) tool string).', 'The depth range may differ for different applications, but a data profile is typically several hundred meters long with stations spaced every few meters above, within, and below the depth range of interest.', 'In some situations, the depth range of interest may be a geologic interval that is suspected of containing a bypassed hydrocarbon deposit or reservoir \n30\n, such as a crude oil and/or natural gas charged reservoir interval that has either not been drained or has been incompletely drained by previous hydrocarbon production activities in the area.', 'The transmitters \n23\n may be aligned in a profile emanating from the well in a particular direction, e.g., perpendicular to a geologic strike.', 'While four linear arrays of transmitters \n23\n are shown deployed in quadrants about a vertical wellbore \n22\n in the example of \nFIG.', '1\n, it will be understood by those skilled in the art that transmitters (or receivers) may be deployed in other geometries, and also that the wellbore may also be deviated or have one or more horizontal sections.', 'The surface arrays of transmitters \n23\n may also be deployed in an areal mode, where one or more transmitters are deployed in accordance with a surface grid pattern, a set of crossed profiles or along a spiral emanating outward from the well.', 'Such embodiments may be appropriate where a surface strike/dip direction is not easily discerned.', 'Such geometries may also be appropriate to deploy for offshore (i.e., sea bottom) applications.', 'One potential difficulty with STB and BTS EM measurements is that they may be highly sensitive to the presence of conductivity inhomogeneities, such as karst \n31\n in the shallow subsurface area.', 'Such inhomogeneities yield preferential channeling of the current density.', 'The channeling phenomena may be described with a first order approximation as an accumulation of charges at the boundaries of the three-dimensional (3D) karst \n31\n, which effectively yield secondary sources at the positions of the 3D inhomogeneities.', 'In turn, the secondary sources bias the fields that are recorded away from the primary source, both on the surface \n21\n of the earth as well as downhole.', 'Referring additionally to the flow diagram \n40\n of \nFIG.', '2\n, an approach is now described which may use phase values of the measured EM fields to determine subsurface electrical structure, and accordingly the constituents within the geological formation.', 'Beginning at Block \n41\n, the EM transmitters \n23\n and receivers \n26\n may be operated to determine or measure phase and amplitude data from the geological formation, as described above (Block \n42\n).', 'The phase data may be processed by a processor \n32\n independent from the amplitude data to generate a geological constituent map of the geological formation, at Block \n43\n.', 'An example constituent map of the reservoir \n30\n is shown in \nFIG.', '3\n, which illustratively includes crude oil \n50\n, and a region \n51\n including water.', 'This is possible because the phase of the measured EM fields is much less susceptible to inhomogeneities, such as the karst \n31\n, and may thereby be processed individually to provide an accurate image or representation of the constituents within the geological formation and, more particularly, within the reservoir \n30\n.', 'The processor \n32\n may be implemented using a combination of hardware (e.g., microprocessor, memory, etc.) and software (e.g., a non-transitory computer-readable medium with the appropriate instructions for causing the hardware to perform the operations described herein).', 'By way of example, the processor \n32\n may be used to process the phase data based upon an inversion algorithm.', 'Generally speaking, inversion algorithms are commonly used to process both phase and amplitude data simultaneously.', 'However, as will explained further with reference to example simulation results, the amplitude data is more susceptible to inhomogeneities, and therefore a distortion of the imaging results if the distorted amplitude data is combined with the phase data as part of the inversion processing.', 'Accordingly, the present approach utilizes the relatively unaffected phase data to generate a relatively accurate constituent map of the geological formation (or portions thereof, such as the reservoir \n30\n), separate and independent of the corresponding amplitude data.', 'However, the amplitude data may then be used to identify the different geological constituents in the geological constituent map, at Block \n44\n, which illustratively concludes the method shown in \nFIG.', '2\n (Block \n45\n).', 'More particularly, the amplitude data may correspond to a resistivity of the geological formation, and the identification of the different geological constituents may include comparing the amplitude data to reference resistivity data.', 'That is, resistivity values for gas, crude oil, water, oil/water mixtures, etc., may be measured beforehand, such that a comparison with measured amplitude data for the different constituent materials or regions within the reservoir \n30\n may be performed using the amplitude of the measured data as a function of space and time to identify these components with a relatively high degree of confidence.', 'However, when inhomogeneities such as the karst \n31\n is present in the formation, it may not be readily apparent when the measured amplitude data has been effected by these secondary materials.', 'As such, various approaches may be used to identify and remove or compensate for aberrant amplitude data resulting from inhomogeneities.', 'For example, the EM transmitters \n23\n may be sequentially operated so that the amplitude data is sequentially collected, meaning there will be respective amplitude data for each of the various positions and angles of the EM transmitters \n23\n.', 'The amplitude data sets may be compared with one another for discrepancies, such as may occur between a reading influenced by the karst \n31\n and a reading that is not.', 'For those amplitude readings that appear skewed as a result of the karst \n31\n, they may be discarded and not factored into the identification, while the measurements considered to be unaffected may be used for identification purposes (i.e., a subset of the collected amplitude data may be used).', 'Another approach is to scale measurements considered to be affected by the karst \n31\n (or other inhomogeneities) based upon a measured reference value for the geological formation \n21\n.', 'For example, such a reference measurement may be taken within the borehole (e.g., cross-well measurements, etc.), and the reference value may be used to determine an offset associated with amplitude data measured by the STB configuration.', 'Accordingly, measured amplitude values associated with the constituents in the reservoir \n30\n may be scaled based upon the in-ground measured reference value, for example, to thereby help identify constituent regions within the formation \n21\n.', 'The foregoing will be further understood with reference to example simulation results now described with reference to \nFIGS.', '4 and 5\n.', 'In \nFIG.', '4\n, amplitudes of vertical electric fields with and without the effects of conductive karst are shown, respectively.', 'The effects on amplitude as a result of the conductive karst are that the amplitude distorted by the conductive karts (plot line \n55\n) is shifted down relative to the undistorted one (plot line \n56\n).', 'Amplitude and phase differences are shown by plot lines \n60\n and \n61\n, respectively, in \nFIG.', '5\n.', 'While the amplitude shows an 85% difference, the phase has near zero difference with or without the conductive karst.', 'Referring additionally to \nFIGS.', '6 and 7\n, an example in which amplitudes of vertical electric fields are represented with and without the effects of resistive karst.', 'The plot line \n65\n represents distorted amplitude data which has been affected by resistive karst, while the plot line \n66\n represents amplitude data for the same simulated geological formation but without being effected by the resistive karst.', 'The distorted amplitude data (plot line \n65\n) is shifted up relative to the non-distorted amplitude data (plot line \n66\n).', 'Here again, \nFIG.', '7\n shows the amplitude and phase differences via plot lines \n67\n and \n68\n, respectively.', 'While the difference between the distorted and non-distorted amplitudes is 58%, the phase once again has a near zero difference with and without the effects of the resistive karst.', 'Many modifications and other embodiments will come to the mind of one skilled in the art having the benefit of the teachings presented in the foregoing descriptions and the associated drawings.', 'Therefore, it is understood that various modifications and embodiments are intended to be included within the scope of the appended claims.'] | ['1.', 'An electromagnetic (EM) data acquisition method for a geological formation, the method comprising:\noperating a plurality of EM measurement devices in a borehole-to-surface (BTS) configuration or a surface-to-borehole (STB) configuration to determine phase and amplitude data from the geological formation, the plurality of EM measurement devices comprising at least one EM receiver and an array of EM transmitters;\ninverting the phase data without the amplitude data to generate a geological constituent map of the geological formation; and\nidentifying the different geological constituents in the geological constituent map based upon the amplitude data, with reduced karst effect;\nwherein operating the plurality of EM measurement devices comprises operating each EM transmitter of the array of EM transmitters sequentially to generate separate sets of the amplitude data, and wherein identifying the different geological constituents in the geological constituent map based upon the amplitude data comprises discarding one or more of the separate sets of the amplitude data that appear skewed and using one or more of a remainder of the separate sets of the amplitude data to identify the different geological constituents in the geological constituent map;\nwherein a geological constituent is a fluid, wherein identifying the geological constituents includes identifying the type of fluid, wherein the type of fluid includes at least one of oil, gas, water, oil/water mixtures.', '2.', 'The method of claim 1 wherein the amplitude data corresponds to a resistivity of the geological formation; and wherein identifying comprises identifying the different geological constituents by comparing the amplitude data to reference resistivity data.', '3.', 'The method of claim 1 wherein the at least one EM receiver comprises an array of EM receivers.', '4.', 'The method of claim 1 further comprising determining in-ground amplitude data; and wherein identifying comprises identifying the different geological constituents further based upon the in-ground amplitude data.', '5.', 'The method of claim 1, wherein inverting the phase data without the amplitude data to generate the geological constituent map of the geological formation includes separating regions of a reservoir, each region including a different geological constituent and wherein identifying the different geological constituents in the geological constituent map includes identifying the different geological constituent in each region.', '6.', 'A well-logging system comprising:\na plurality of EM measurement devices arranged in a borehole-to-surface (BTS) configuration or a surface-to-borehole (STB) configuration to determine phase and amplitude data from a geological formation, said plurality of EM measurement devices comprising at least one EM receiver and an array of EM transmitters; and\na processor to invert the phase data without the amplitude data with at least one inversion algorithm to generate a geological constituent map of the geological formation, and identify different geological constituents in the geological constituent map based upon the amplitude data, with reduced karst effect;\nwherein each EM transmitter of the array of EM transmitters is configured to be sequentially operated to generate separate sets of the amplitude data, and the processor is configured to discard one or more of the separate sets of the amplitude data that appear skewed and to use one or more of a remainder of the separate sets of the amplitude data to identify the different geological constituents in the geological constituent map;\nwherein a geological constituent is a fluid, wherein identifying the geological constituents includes identifying the type of fluid, wherein the type of fluid includes at least one of oil, gas, water, oil/water mixtures.', '7.', 'The well-logging system of claim 6 wherein the amplitude data corresponds to a resistivity of the geological formation; and wherein said processor identifies the different geological constituents by comparing the amplitude data to reference resistivity data.', '8.', 'A non-transitory computer-readable medium having computer-executable instructions for causing a computer to perform steps comprising:\nfor phase and amplitude data determined by a plurality of EM measurement devices in a borehole-to-surface (BTS) configuration or a surface-to-borehole (STB) configuration at a geological formation, inverting the phase data without the amplitude data with at least one inversion algorithm to generate a geological constituent map of the geological formation, wherein the plurality of EM measurement devices comprise at least one EM receiver and an array of EM transmitters; and\nidentifying different geological constituents in the geological constituent map based upon the amplitude data, with reduced karst effect\nwherein each EM transmitter of the array of EM transmitters is configured to be sequentially operated to generate separate sets of the amplitude data, and wherein identifying the different geological constituents in the geological constituent map based upon the amplitude data comprises discarding one or more of the separate sets of the amplitude data that appear skewed and using one or more of a remainder of the separate sets of the amplitude data to identify the different geological constituents in the geological constituent map;\nwherein a geological constituent is a fluid, wherein identifying the geological constituents includes identifying the type of fluid, wherein the type of fluid includes at least one of oil, gas, water, oil/water mixtures.', '9.', 'The non-transitory computer-readable medium of claim 8 wherein the amplitude data corresponds to a resistivity of the geological formation; and wherein identifying comprises identifying the different geological constituents by comparing the amplitude data to reference resistivity data.', '10.', 'The non-transitory computer-readable medium of claim 8 wherein identifying comprises identifying the different geological constituents further based upon in-ground amplitude data.'] | ['FIG.', '1 is a schematic block diagram of a well-logging system in accordance with an example embodiment.; FIG.', '2 is a flow diagram illustrating method aspects associated with the well-logging system of FIG.', '1.; FIG. 3 is a schematic geological constituent map generated based upon the method of FIG.', '2.; FIG.', '4 is a graph of amplitude vs. depth of simulated EM data for an example geological formation with and without the presence of conductive karst in the geological formation.; FIG.', '5 is a graph of simulated relative differences in phase and amplitude vs. depth for the example of FIG.', '4.; FIG. 6 is a graph of amplitude vs. depth of simulated EM data for another example geological formation with and without the presence of resistive karst in the geological formation.', '; FIG. 7 is a graph of relative differences in phase and amplitude vs. depth for the example of FIG.', '6.'] |
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US11150373 | Determining dielectric constant and resistivity with induction measurement | Apr 26, 2019 | Gong Li Wang, John Rasmus, Dean Homan | SCHLUMBERGER TECHNOLOGY CORPORATION | Anderson et al., 2006, Observations of Large Dielectric Effects on Induction Logs, or, Can Source Rocks Be Detected With Induction Measurements, Paper OOO, SPWLA 47th Annual Logging Symposium, Veracruz, Mexico, Jun. 4-7, 2006 (12 pages).; Anderson et al., 2008, “Identifying Potential Gas-Producing Shales From Large Dielectric Permittivities Measured by Induction Quadrature Signals,” Paper HHHH, SPWLA 49th Annual Logging Symposium, Edinburgh, Scotland, May 25-28, 2008 (10 pages).; Misra et al., Complex Electrical Conductivity of Mudrocks and Source-Rock Formations Containing Disseminated Pyrite , URTeC: 2163422, Unconventional Resources Technology Conference (URTeC), San Antonio, Texas, USA, Jul. 20-22, 2015. (15 pages).; Misra et al., “Dielectric effects in pyrite-rich clays on multifrequency induction logs and equivalent laboratory core measurements”, Society of Petrophysicists and Well Log Analysts, SPWLA 56th Annual Logging Symposium held in Reykjavik, Iceland Jun. 25-29, 2016. (17 pages). | 4467425; August 21, 1984; Schaefer; 8135542; March 13, 2012; Luling; 8694259; April 8, 2014; Luling; 20110231098; September 22, 2011; Omeragic; 20120080197; April 5, 2012; Dickens; 20130261975; October 3, 2013; Yang; 20160003964; January 7, 2016; Celepcikay; 20160170069; June 16, 2016; Wang; 20170342818; November 30, 2017; Roberson | Foreign Citations not found. | ['The highly valuable properties of resistivity and dielectric constant of a geological formation may be determined using an induction measurement, even for a geological formation with bed boundary or dipping effects, using a one-dimensional (1D) formation model.', 'Induction measurements may be obtained in a wellbore through the geological formation using one or more downhole tools.', 'One or more processors may be used to perform an inversion to estimate resistivity and dielectric constant values of the geological formation.', 'The inversion may be performed using the induction measurements and a one-dimensional model that includes a number of geological layers.'] | ['Description\n\n\n\n\n\n\nCROSS REFERENCE TO RELATED APPLICATIONS', 'This application claims priority from and the benefit of U.S. Provisional Application Ser.', 'No. 62/663,992, entitled “Determining Dielectric Constant and Resistivity with Induction Measurement,” filed Apr. 27, 2018, which is herein incorporated by reference in its entirety for all purposes.', 'BACKGROUND\n \nThis disclosure relates to obtaining dielectric constant and resistivity of a formation using a downhole induction measurement.', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.', 'Producing hydrocarbons from a wellbore drilled into a geological formation is a remarkably complex endeavor.', 'In many cases, decisions involved in hydrocarbon exploration and production may be informed by measurements from downhole well-logging tools that are conveyed deep into the wellbore.', 'The measurements may be used to infer properties or characteristics of the geological formation surrounding the wellbore.', 'Resistivity and dielectric constant represent two highly valuable properties of the geological formation that may be inferred.', 'These properties may be measured or calculated and formatted onto a well log, which plots the properties against the depth of the well.', 'A well log showing resistivity and dielectric constant, among other properties, may allow producers to make more effective, informed exploration and production decisions, with all of the many benefits that entails.', 'For certain geological formations, a measurement known as an induction measurement may be used in combination with a homogenous model to determine resistivity and dielectric constant.', 'This may work reasonably well when the resistivity of the geological formation changes slowly or the resistivity contrast from bed to bed is small.', 'When the formation contrast is high, however, the dielectric constant and resistivity logs obtained could be adversely affected by the bed boundary or layering effect in a significant manner.', 'Indeed, when the formation is dipping relative to the plane of the downhole induction tool, a well log of resistivity and dielectric constant using a homogenous model may also be affected by the undesirable dipping effect.', 'SUMMARY\n \nA summary of certain embodiments disclosed herein is set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'One embodiment of the present disclosure relates to a method.', 'The method includes obtaining induction measurements in a wellbore through a geological formation using one or more downhole induction well-logging tools; inverting the induction measurements based on a one-dimensional model comprising a plurality of geological layers; and generating resistivity and dielectric constant values of the geological formation based on the output of the inversion of induction measurements.', 'Another embodiment of the present disclosure relates to an article of manufacture comprising tangible, non-transitory, machine-readable media comprising instructions.', 'The instructions include receiving induction measurements associated with wellbore through a geological formation obtained by one or more downhole induction well-logging tools.', 'The instructions also include inverting the induction measurements based on a cost function, wherein the cost function comprises a misfit term, an entropy term, and a smoothing term.', 'Further, the instructions include generating resistivity and dielectric constant values associated with the geological formation based on the output of the inversion of induction measurements.', 'Another embodiment of the present disclosure relates to a system comprising.', 'The system includes a downhole well-logging tool configured to obtain one or more induction measurements from a geological formation.', 'Further, the system includes a processor and a memory storing instructions to be executed by the processor.', 'The instructions include receiving the induction measurements obtained by the downhole well-logging tool.', 'The instructions also include inverting the induction measurements based on a one-dimensional model comprising a plurality of geological layers and a cost function, and wherein each geological layer of the one-dimensional model comprises a constant conductivity and a constant dielectric constant.', 'Further, the instructions include generating resistivity and dielectric constant values associated with the geological formation based on the output of the inversion of induction measurements.', 'Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:\n \nFIG.', '1\n is a schematic diagram of a well-logging system that may obtain induction measurements that may be used to identify formation resistivity and dielectric constant, in accordance with an embodiment;\n \nFIG.', '2\n illustrates a flow chart of various processes that may be performed based on analysis of induction well log data, in accordance with aspects of the present disclosure;\n \nFIG.', '3\n is a schematic diagram of a downhole coaxial array that may be used to collect induction measurements, in accordance with an embodiment;\n \nFIG.', '4\n is a schematic diagram of a downhole triaxial array that may be used to collect induction measurements, in accordance with an embodiment;\n \nFIG.', '5\n is a schematic diagram of a one-dimensional (1D) formation model that may be used to ascertain conductivity or resistivity and dielectric constant, in accordance with an embodiment;\n \nFIG.', '6\n is a flowchart of an inversion to determine conductivity or resistivity and dielectric constant, in accordance with an embodiment;\n \nFIG.', '7\n is a flowchart of an inversion to determine conductivity or resistivity and dielectric constant, in accordance with an embodiment;\n \nFIG.', '8\n is an example well log of resistivity and dielectric constant determined with inversion in a chirp model in the presence of large dielectric effect, in accordance with an embodiment;\n \nFIG.', '9\n is an example well log of resistivity and dielectric constant determined with inversion in a chirp model in the absence of large dielectric effect, in accordance with an embodiment;\n \nFIG.', '10\n is an example well log of resistivity and dielectric constant determined with inversion in a modified Oklahoma model of a relative dip of 30 degrees, in accordance with an embodiment; and\n \nFIG.', '11\n is an example well log of resistivity and dielectric constant determined with inversion in a modified Oklahoma model of a relative dip of 60 degrees, in accordance with an embodiment.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, certain features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions may be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would still be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'In general, oil and gas exploration organizations may make certain oil and gas production decisions, such as determining where to drill, based on well log data.', 'One type of well log data that may inform such decisions are from induction well logging measurements.', 'Certain techniques for obtaining and analyzing induction well logging measurements may have inaccuracies due to geological formations with bed boundary or dipping effects.', 'Moreover, induction well logging measurements may be used to determine resistivity logs and resistivity anisotropy of reservoirs because in many or a majority of conventional reservoirs, the contribution of the displacement current to, or the dielectric effect on the data is so small that the dielectric constant may not be determined at the induction frequencies.', 'However, when the dielectric effect in the geological formation is non-negligible, the resistivity log obtained based on induction well logging measurements with certain conventional techniques can be affected by the dielectric constant through the skin effect.', 'For example, geological formations containing a relatively small amount of graphite or pyrite in artificial sand packs can cause a relatively large change in the dielectric constant and, thus, may decrease the accuracy of the resistivity log with certain conventional techniques.', 'One aspect of the present disclosure relates to systems and methods for using induction well logging measurements to generate a dielectric constant well log and resistivity well log of multilayer dipping rock formations.', 'In some embodiments, the dielectric constant well log and resistivity well log may be generated based on minimizing a cost function based on a formation model, such as a one-dimensional (1D) formation model.', 'The formation model may include a plurality of pixels or planes along a well path, such as a plurality of small layers along a wellbore.', 'In some embodiments, each pixel at a region along the well path may have a constant conductivity or dielectric constant at a respective region.', 'In some embodiments, aspects of the present disclosure may including performing a full-wave inversion method to simultaneously determining the dielectric constant and resistivity of the multilayer dipping rock formation using induction well logging data.', 'It should be noted that, in accordance with aspects of the present techniques, the magnitude of the resultant dielectric constant suggests that the dielectric constant may be determined in shales and organic mudrocks with graphite or pyrite at reasonable accuracy using induction data.', 'With this in mind, \nFIG.', '1\n illustrates a well-logging system \n10\n that may employ the systems and methods of this disclosure.', 'The well-logging system \n10\n may be used to convey a well-logging tool \n12\n through a geological formation \n14\n via a wellbore \n16\n.', 'The well-logging tool \n12\n may be conveyed on a cable \n18\n via a logging winch system \n20\n.', 'Although the logging winch system \n20\n is schematically shown in \nFIG.', '1\n as a mobile logging winch system carried by a truck, the logging winch system \n20\n may be substantially fixed (e.g., a long-term installation that is substantially permanent or modular).', 'Any suitable cable \n18\n for well logging may be used.', 'The cable \n18\n may be spooled and unspooled on a drum \n22\n and an auxiliary power source \n24\n may provide energy to the logging winch system \n20\n and/or the well-logging tool \n12\n.', 'Moreover, although the well-logging tool \n12\n is described as a wireline downhole tool, it should be appreciated that any suitable conveyance may be used.', 'For example, the well-logging tool \n12\n may instead be conveyed as a logging-while-drilling (LWD) tool as part of a bottom hole assembly (BHA) of a drill string, conveyed on a slickline or via coiled tubing, and so forth.', 'For the purposes of this disclosure, the well-logging tool \n12\n may be any suitable measurement tool that obtains NMR logging measurements through depths of the wellbore \n16\n.', 'Many types of well-logging tools \n12\n may obtain induction logging measurements in the wellbore \n16\n.', 'These include, for example, the Rt Scanner, AIT, and Thrubit Induction tools by Schlumberger Technology Corporation, but induction logging measurements from other downhole tools by other manufacturers may also be used.', 'The well-logging tool \n12\n may provide induction logging measurements \n26\n to a data processing system \n28\n via any suitable telemetry (e.g., via electrical signals pulsed through the geological formation \n14\n or via mud pulse telemetry).', 'The data processing system \n28\n may process the induction logging measurements \n26\n to identify a conductivity and/or resistivity and dielectric constant at various depths of the geological formation \n14\n in the wellbore \n16\n.', 'To this end, the data processing system \n28\n thus may be any electronic data processing system that can be used to carry out the systems and methods of this disclosure.', 'For example, the data processing system \n28\n may include a processor \n30\n, which may execute instructions stored in memory \n32\n and/or storage \n34\n.', 'As such, the memory \n32\n and/or the storage \n34\n of the data processing system \n28\n may be any suitable article of manufacture that can store the instructions.', 'The memory \n32\n and/or the storage \n34\n may be ROM memory, random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive, to name a few examples.', 'A display \n36\n, which may be any suitable electronic display, may provide a visualization, a well log, or other indication of properties in the geological formation \n14\n or the wellbore \n16\n using the induction logging measurements \n26\n.\n \nFIG.', '2\n illustrates a method \n40\n of various processes that may be performed based on analysis of well logs, in accordance with aspects of the present disclosure.', 'A location of hydrocarbon deposits within a geological formation may be identified (process block \n42\n) based on well-log data.', 'In some embodiments, the well-log data may be analyzed to generate a map or profile that illustrates regions of interest with the geological formation.', 'Based on the identified locations and properties of the hydrocarbon deposits, certain downhole operations on positions or parts of the geological formation \n14\n may be performed (process block \n44\n).', 'That is, hydrocarbon exploration organizations may use the locations of the hydrocarbon deposits to determine locations in the wellbore to isolate for extracting liquid, frack, and/or drill into the Earth.', 'As such, the hydrocarbon exploration organizations may use the locations and properties of the hydrocarbon deposits and the associated overburdens to determine a path along which to drill into the Earth, how to drill into the Earth, and the like.', 'After exploration equipment has been placed within the geological formation \n14\n, the hydrocarbons that are stored in the hydrocarbon deposits may be produced (block \n46\n) via natural flowing wells, artificial lift wells, and the like.', 'Further, the produced hydrocarbons may be transported (block \n48\n) to refineries and the like via transport vehicles, pipelines, and the like.', 'Further still, the produced hydrocarbons may be processed (block \n50\n) according to various refining procedures to develop different products using the hydrocarbons.', 'It should be noted that the processes discussed with regard to the method \n40\n may include other suitable processes that may be based on the locations and properties of hydrocarbon deposits as indicated in the seismic data acquired via one or more seismic survey.', 'As such, it should be understood that the processes described above are not intended to depict an exhaustive list of processes that may be performed after determining the locations and properties of hydrocarbon deposits within the geological formation.', 'Accordingly, the systems and methods of this disclosure involve techniques to determine dielectric constant and resistivity (e.g., separately or simultaneously) in a multilayer formation using data acquired by an induction tool (e.g., induction well log measurements).', 'A multilayer formation may have a number of sedimentary beds where the dielectric constant and resistivity vary from bed to bed.', 'The bedding planes can be dipping relative to the tool plane.', 'The inverse problem may be solved iteratively with a Gauss-Newton approach.', 'The use of a maximum entropy and a first derivative or a variance of the model for regularization may cause the inversion to converge rapidly for a wide range of initial guesses.', 'The regularization parameter may be chosen to be proportional to the data misfit to avoid the potential bias caused by the regularization terms.', 'The systems and methods of the present disclosure may include calculating the dielectric constant and resistivity of a region of geological formation that is free of bed boundary and dipping effects because the layering and dipping of the formation are considered in the one-dimensional (1D) formation model of the inversion.', 'The dielectric constant obtained in this way can be used to estimate cation exchange capacity, which in turn can be used to yield an accurate hydrocarbon/water saturation in reservoirs containing shales.', 'The dielectric constant can also be used to estimate the volume and maturity of kerogen in unconventional reservoirs, which in turn can be used to determine the type and volume of hydrocarbons in the reservoirs.', 'The resistivity can be used in place of other induction resistivity logs where the dipping and/or dielectric effect are non-negligible.', 'Moreover, the dielectric effect on a resistivity log obtained with other processing method may be removed using the systems and methods of this disclosure.', 'Examples of well-logging tools \n12\n that may acquire induction data are shown in \nFIGS.', '3 and 4\n.', 'The illustrated embodiment of the well-logging tool \n12\n shown in \nFIG.', '3\n includes an array induction tool (e.g., the AIT and Thrubit Induction tools by Schlumberger Technology Corporation) that measures coaxial couplings.', 'As shown, the well-logging tool \n12\n in \nFIG.', '3\n includes a transmitter \n51\n (e.g., transmitter coil), a first receiver \n52\n (e.g., balancing receiver), and a second receiver \n53\n.', 'While the illustrated embodiment of the well-logging tool \n12\n shown in \nFIG.', '3\n includes one transmitter (e.g., transmitter \n51\n) and two receivers (e.g., receiver \n52\n), the number of transmitters and receivers is not a limit on the scope of the present invention.', 'FIG.', '4\n shows another example of an illustrated embodiment of the well-logging tool \n12\n that includes a triaxial induction tool (e.g., the Rt Scanner tool by Schlumberger Technology Corporation) with mutually orthogonal and collocated transmitter and receiver coils.', 'As shown, the well-logging tool \n12\n in \nFIG.', '4\n includes three transmitters \n57\n, three first receivers \n58\n (e.g., balancing receivers), and three second receivers \n59\n (e.g., main receivers).', 'Generally speaking, the three transmitters \n57\n induce electric eddy current in the formation that flow parallel to orthogonal planes oriented with their normals in the X (e.g., along the axis \n55\n), Y (e.g., along the axis \n54\n), and Z directions (e.g., along the axis \n56\n), which are defined by the directions of the magnetic dipole moments of each of the three transmitter coils.', 'As such, the well-logging tool \n12\n shown in \nFIG.', '4\n may measure all nine orthogonal couplings to determine formation resistivity and resistivity anisotropy as well as formation dip.', 'While the illustrated embodiment of the well-logging tool \n12\n shown in \nFIG.', '4\n includes one transmitter (e.g., transmitter \n51\n) and two receivers (e.g., receiver \n52\n), the number of transmitters \n57\n and receivers \n58\n, \n59\n is not a limit on the scope of the present invention.', 'It should be noted that inhomogeneties in the rock formations will distort the currents flowing therethrough, and the electromagnetic fields at the receivers \n58\n and \n59\n are different from what would have existed if the formation were homogeneous.', 'Wireline induction measurements in gas bearing organic mudrocks may have a quadrature or out-of-phase signal that include certain anomalies.', 'Induction measurements in some over-mature gas bearing organic mudrocks have shown additional abnormalities (e.g., strange signals) where the in-phase conductivity is abnormally high.', 'Certain conventional induction well logging techniques have attributed such behaviors to a presence of pyrite and/or graphite in the geological formation.', 'However, it should be noted that the presence of a small amount of graphite or pyrite in artificial sand packs can cause a huge change in the dielectric constant and, in some instances, the resistivity.', 'The magnitude of the resultant dielectric constant suggests that the dielectric constant can be determined in organic mudrocks with graphite or pyrite at reasonable accuracy using induction data.', "To simulate the dielectric effect on induction data, the displacement current term may be added back to the Maxwell's equation, leading to a complex-valued conductivity: \n {tilde over (σ)}=σ−\niωε\n0\nε\nr\n\u2003\u2003(1) \n where σ, the first term, is the conductivity of the formation; ε\nr \nis the dielectric constant, and ε\n0 \nis the electric permittivity of free space.", 'In some embodiments, the time dependence is exp(−iωt), where ω is the angular frequency; i is the imaginary unit, i=√{square root over (−1)}.', 'One output of the inversion may be formation conductivity or a dielectric constant based on the measurements acquired with an induction tool.', 'In the inversion, the formation model may take a layered structure where conductivity and dielectric constant vary in one direction only, designated as the z-direction.', 'FIG.', '5\n shows an illustration of a layered formation model \n60\n, which may represent a 1D formation model adopted in the inversion.', 'In general, the formation model assumes that the conductivity σ and the dielectric constant ε, may vary in the z-direction (e.g., along axis \n56\n), but are invariant in both along the x-direction (e.g., along axis \n55\n) and y-directions (e.g., along axis \n54\n).', 'Angles θ and ϕ are the relative dip and azimuth of the well path.', 'The varying conductivity σ and dielectric constant ε, along the axis \n56\n is illustrated as multiple planes \n62\n.', 'In some embodiments, each plane \n62\n may be the top or bottom interface of a pixel of the formation model.', 'For example, in the illustrated embodiment of the layered formation model \n60\n shown in \nFIG.', '5\n, plane \n62\na \nis at a first position along the axis \n56\n and plane \n62\nb \nis at a second position along the axis \n56\n.', 'Moreover, the pixel between the plane \n62\na \nand the plane \n62\nb \nis assumed to have a constant conductivity and dielectric constant.', 'The same is true with all other pixels in the model.', 'It is worthy of note that the conductivity and dielectric constant may change from pixel to pixel.', 'To help illustrate the above discussion, an example process \n63\n for determining physical properties associated with a geological formation in accordance with present disclosure is described in \nFIG.', '6\n.', 'Generally, the process \n63\n acquires (process block \n65\n) induction measurements associated with a geological formation.', 'For example, the induction measurements may be performed in real-time, such as by a data processing system \n28\n communicatively coupled to the well-logging tool \n12\n to acquire induction measurements.', 'The process \n63\n also includes inverting (process block \n67\n) the induction measurements based on a one-dimensional model.', 'In some embodiments, the one-dimensional model may assume that the conductivity and the dielectric constant varies in one direction, as discussed above with respect to \nFIG.', '5\n.', 'Further, in some embodiments, a cost function may be minimized based on an inversion.', 'As discussed herein, the cost function may include one or more parameters related to physical properties of a geological formation, such as resistivity, conductivity, dielectric constant, and position within the geological formation.', 'For example, the cost function may include a misfit term, an entropy term, and a smoothing term, as discussed in more detail below.', 'In some embodiments, one or more of the terms (e.g., the misfit term, the entropy term, and the smoothing term) may be parameterized based on the varying conductivities and dielectric constants as defined by the model.', 'Further, the process \n63\n may also include generating (process block \n69\n) at least one of resistivity values, conductivity values or dielectric constant values based on the inverted formation model.', 'Although described in a particular order, which represents a particular embodiment, it should be noted that the process \n63\n may be performed in any suitable order.', 'Additionally, embodiments of the process \n63\n may omit process blocks and/or include additional process blocks.', 'Moreover, in some embodiments, the process \n63\n may be implemented at least in part by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as memory \n32\n implemented in a data processing system \n28\n, using processing circuitry, such as a processor \n30\n implemented in the data processing system \n28\n.', 'In some embodiments, the cost function that the inversion minimizes may be given by:\n \n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \nℒ\n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n=\n \n \n \n \nχ\n \n2\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n-\n \n \n \nγ\n \nP\n \n \n\u2062\n \n \n \nℒ\n \nP\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n \n+\n \n \n \nγ\n \nS\n \n \n\u2062\n \n \n \nℒ\n \nS\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n \n \n \n,\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \nwhere\n \n\u2062\n \n \n:\n \n \n \n \n \n \n \n \n(\n \n2\n \n)\n \n \n \n \n \n \n \n \n \n \nχ\n \n2\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n=\n \n \n \n∫\n \n \n-\n \n∞\n \n \n∞\n \n \n\u2062\n \n \ndz\n \n\u2062\n \n \n{\n \n \n \n \n[\n \n \n \n \n \nd\n \nR\n \n \n\u2061\n \n \n(\n \n \n \nz\n \n;\n \nσ\n \n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n-\n \n \n \nd\n \nR\n \nOBS\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n \nΔ\n \nR\n \n \n \n]\n \n \n2\n \n \n+\n \n \n \n[\n \n \n \n \n \nd\n \nX\n \n \n\u2061\n \n \n(\n \n \n \nz\n \n;\n \nσ\n \n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n-\n \n \n \nd\n \nX\n \nOBS\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n \nΔ\n \nX\n \n \n \n]\n \n \n2\n \n \n \n}\n \n \n \n \n \n,\n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n \n \n \nℒ\n \nP\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n=\n \n \n \n-\n \n \n \n∫\n \n \n-\n \n∞\n \n \n∞\n \n \n\u2062\n \n \ndz\n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \nσ\n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \nT\n \nσ\n \n \n \n\u2061\n \n \n[\n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nσ\n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n \nσ\n \nP\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n \n-\n \n1\n \n \n]\n \n \n \n \n \n \n-\n \n \n \n∫\n \n \n-\n \n∞\n \n \n∞\n \n \n\u2062\n \n \ndz\n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n \nɛ\n \nr\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \nT\n \nɛ\n \n \n \n\u2061\n \n \n[\n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \nɛ\n \nr\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n \nɛ\n \n \nr\n \n,\n \nP\n \n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n \n-\n \n1\n \n \n]\n \n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n4\n \n)\n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \n \nℒ\n \nS\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n=\n \n \n \n \n∫\n \n \n-\n \n∞\n \n \n∞\n \n \n\u2062\n \n \n \ndz\n \n\u2061\n \n \n[\n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \n \nσ\n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \ndz\n \n \n]\n \n \n \n2\n \n \n \n+\n \n \n \nωɛ\n \n0\n \n \n\u2062\n \n \n∫\n \n \n \ndz\n \n\u2061\n \n \n[\n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \nr\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \ndz\n \n \n]\n \n \n \n2\n \n \n \n \n \n \n,\n \n \n \n \n \n \n(\n \n5\n \n)\n \n \n \n \n \n \n \n where σ and ε\nr \nare the true conductivity and dielectric constant of the formation to be determined with the inversion.', 'The first term, the misfit term, on the right-hand side of Eq.', '(2) describes how well the simulated data matches the measured data, where d\nR\nOBS \nand d\nX\nOBS \nare real and imaginary parts of the measured apparent conductivity corresponding to the coaxial coupling of an induction tool; d\nR \nand d\nx \nare the simulated counterparts of d\nR\nOBS \nand d\nX\nOBS\n, respectively.', 'd\nR \nand d\nx \nare obtained rapidly with a fast forward solver for the 1D formation, Δ\nR \nand Δ\nx \nare the standard deviations of data noises for real and imaginary apparent conductivities, respectively.', 'It should be noted that although in the current formulation, the data are assumed to be apparent conductivities, the data can also be measured voltages, or any other measurements that may be transformed from the measured voltages, e.g. phase shift and attenuation.', 'If each datum is an independent random variable, the summation of the squared differences in Eq.', '(3) obey a χ\n2 \ndistribution.', 'The second term of Eq.', '(2) is given in Eq.', '(4), which describes the entropy of the conductivity and dielectric constant models.', 'Here, T\nσ\n and T\nε\n are the averages of σ and ε\nr\n, respectively; σ\nP \nand ε\nr,P \nare the prior models for σ and ε\nr\n, respectively.', 'At least in some instances, T\nσ\n=σ\nP\n, and T\nε\n=ε\nr,P \nmay be used for the inversion.', 'It should be noted that including the entropy term into the cost function may guide the inversion towards a solution (e.g., minimized cost function) that increases (e.g., maximizes) the entropy.', 'The third term (e.g., smoothing term) of Eq. (2) is given in Eq.', '(5), which makes the inversion to preferentially look for a smoothing model among all feasible solutions.', 'It should be understood that although the first derivative is used for the smoothing term, the inversion can use other properties of the model for the same effect.', 'In one embodiment, the variance of the model can be used in place of the first derivative.', 'In another embodiment, the second derivative can also be used to impose the smoothness on the model.', 'For numerical implementations, the cost function of Eq.', '(2) may be discretized, yielding: \n (\nm\nσ\n,m\nε\n)=χ\n2\n(\nm\nσ\n,m\nε\n)−γ\nP\n(\nm\nσ\n,m\nε\n)', '+γ\nS\n(\nm\nσ\n,m\nε\n)\u2003\u2003(6) \n where m\nσ\n and m\nε\n are two N-dimensional vectors of conductivities and dielectric constants of the truncated solution domain [z\nL\n,z\nU\n] after being subdivided into N pixels with equal thickness, identified by h as shown in \nFIG.', '4\n.', 'The two vectors are given by \n \nm\nσ\n=(σ\n1\n,σ\n2\n, . . .', ', σ\nN\n)\nT\n\u2003\u2003(7) \n \nm\nε\n=ωε\n0\n(ε\nr,1\n,ε\nr,2\n, . . . , ε\nr,N\n)\nT\n\u2003\u2003(8) \n \nHere, the subscript T designates the operation of matrix transposition.', 'Note that m\nε\n corresponds to the imaginary part of the complex conductivity of Eq.', '(1).', 'm\nε\n is equivalent to the dielectric constant up to a constant of ωε\n0\n.', 'The discrete forms of the three terms in Eq.', '(6) are respectively:\n \n \n \n \n \n \n \n \n \n \n \nχ\n \n2\n \n \n\u2061\n \n \n(\n \n \n \nm\n \nσ\n \n \n,\n \n \nm\n \nɛ\n \n \n \n)\n \n \n \n=\n \n \n \n \n\uf605\n \n \n \n \nW\n \n_\n \n \nR\n \n \n\u2061\n \n \n[\n \n \n \n \nd\n \nR\n \n \n\u2061\n \n \n(\n \n \n \nm\n \nσ\n \n \n,\n \n \nm\n \nɛ\n \n \n \n)\n \n \n \n-\n \n \nd\n \nR\n \nOBS\n \n \n \n]\n \n \n \n\uf606\n \n \n2\n \n2\n \n \n+\n \n \n \n\uf605\n \n \n \n \nW\n \n_\n \n \nX\n \n \n\u2061\n \n \n[\n \n \n \n \nd\n \nX\n \n \n\u2061\n \n \n(\n \n \n \nm\n \n \nσ\n \n,\n \n \n \n\u2062\n \n \nm\n \nɛ\n \n \n \n)\n \n \n \n-\n \n \nd\n \nX\n \nOBS\n \n \n \n]\n \n \n \n\uf606\n \n \n2\n \n2\n \n \n \n \n,\n \n \n \n \n \n(\n \n9\n \n)\n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \n \nℒ\n \nP\n \n \n\u2061\n \n \n(\n \n \n \nm\n \nσ\n \n \n,\n \n \nm\n \nɛ\n \n \n \n)\n \n \n \n=\n \n \n \n \n-\n \n \n \n \n\u2062\n \n \n \nm\n \nσ\n \nT\n \n \n \nσ\n \nP\n \n \n \n \n\u2062\n \n \n(\n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nm\n \nσ\n \n \n \nσ\n \nP\n \n \n \n \n-\n \n1\n \n \n)\n \n \n \n-\n \n \n \n \nm\n \nɛ\n \nT\n \n \n \n \nωɛ\n \n0\n \n \n\u2062\n \n \nɛ\n \n \nr\n \n,\n \nP\n \n \n \n \n \n\u2062\n \n \n(\n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nm\n \nɛ\n \n \n \n \nωɛ\n \n0\n \n \n\u2062\n \n \nɛ\n \n \nr\n \n,\n \n \n \n \n\u2062\n \nP\n \n \n \n \n \n \n-\n \n1\n \n \n)\n \n \n \n \n \n,\n \n \n \n \n \n \n(\n \n10\n \n)\n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \nℒ\n \nS\n \n \n\u2061\n \n \n(\n \n \n \nm\n \nσ\n \n \n,\n \n \nm\n \nɛ\n \n \n \n)\n \n \n \n=\n \n \n \n \n\uf605\n \n \n \nD\n \n_\n \n \n\u2062\n \n \nm\n \nσ\n \n \n \n\uf606\n \n \n2\n \n2\n \n \n+\n \n \n \n\uf605\n \n \n \nD\n \n_\n \n \n\u2062\n \n \nm\n \nɛ\n \n \n \n\uf606\n \n \n2\n \n2\n \n \n \n \n \n \n \n \n(\n \n11\n \n)', 'In the above, d\nR\nOBS \nand d\nX\nOBS \nthe real and imaginary parts of measured apparent conductivities acquired at M depth points, \n \nd\nR\nOBS\n=(\nd\nR,1\nOBS\nd\nR,2\nOBS\n. . .', 'd\nR,M\nOBS\n)\nT\n\u2003\u2003(12) \n \nd\nX\nOBS\n=(\nd\nX,1\nOBS\nd\nX,2\nOBS\n. . .', 'd\nX,M\nOBS\n)', 'T\n\u2003\u2003(13) \n d\nR \nand d\nX \nare the real and imaginary parts of simulated apparent conductivities at the same depth points, \n \nd\nR\n(\nm\nσ\n,m\nε\n)=[\nd\nR,1\n(\nm\nσ\n,m\nε\n)\nd\nR,2\n(\nm\nσ\n,m\nε\n) . . .', 'd\nR,M\n(\nm\nσ\n,m\nε\n)]\nT\n\u2003\u2003(14) \n \nd\nX\n(\nm\nσ\n,m\nε\n)=[\nd\nX,1\n(\nm\nσ\n,m\nε\n)\nd\nX,2\n(\nm\nσ\n,m\nε\n) . . .', 'd\nX,M\n(\nm\nσ\n,m\nε\n)]\nT\n\u2003\u2003(15) \n matrices \nW\nR \nand \nW\nX \nare diagonal that may contain the inverses of standard deviations of the noises of real and imaginary apparent conductivities, \n \nW\nR\n=diag(Δ\nR,1\n−1\nΔ\nR,2\n−1 \n. . .', 'Δ\nR,M\n−1\n)\u2003\u2003(16) \n \nW\nX\n=diag(Δ\nX,1\n−1\nΔ\nX,2\n−1 \n. . .', 'Δ\nX,M\n−1\n)\u2003\u2003(17) \n in Eq.', '(10) \n \n \n \n \n \n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nm\n \nσ\n \n \n \nσ\n \nP\n \n \n \n \n=\n \n \n \n(\n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nσ\n \n1\n \n \n \nσ\n \nP\n \n \n \n\u2062\n \n \n \n \n\u2062\n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nσ\n \n2\n \n \n \nσ\n \nP\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n…\n \n\u2062\n \n \n \n \n\u2062\n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nσ\n \nN\n \n \n \nσ\n \nP\n \n \n \n \n)\n \n \nT\n \n \n \n,\n \n \n \n \n \n(\n \n18\n \n)\n \n \n \n \n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nm\n \nɛ\n \n \n \n \nωɛ\n \n0\n \n \n\u2062\n \n \nɛ\n \n \nr\n \n,\n \nP\n \n \n \n \n \n \n=\n \n \n \n(\n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \n \nr\n \n,\n \n1\n \n \n \n \nɛ\n \n \nr\n \n,\n \nP\n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \n \nr\n \n,\n \n2\n \n \n \n \nɛ\n \n \nr\n \n,\n \nP\n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n…\n \n\u2062\n \n \n \n \n\u2062\n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \n \nr\n \n,\n \nN\n \n \n \n \nɛ\n \n \nr\n \n,\n \nP\n \n \n \n \n \n)\n \n \nT\n \n \n \n,\n \n \n \n \n \n(\n \n19\n \n)\n \n \n \n \n \n \n \n and 1 is a constant vector, 1=(1 1 . . .', '1)\nT\n.', 'Matrix \nD\n∈R\n(N−1)×N \nin Eq.', '(11) is a difference operator, \n \n \n \n \n \n \n \n \n \nD\n \n_\n \n \n=\n \n \n(\n \n \n \n \n \n-\n \n1\n \n \n \n \n1\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n-\n \n1\n \n \n \n \n1\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n-\n \n1\n \n \n \n \n1\n \n \n \n \n)\n \n \n \n \n \n \n(\n \n20\n \n)\n \n \n \n \n \n \n \n \nA Gauss-Newton method may be used to reduce (e.g., minimize) the cost function in Eq.', '(6) to find a solution (e.g., a best-fit solution) for conductivity m\nσ\n and dielectric constant m\nε\n.', 'For the sake of conciseness of formulation, the following notations may be used:\n \n \n \n \n \n \n \n \n \nm\n \n=\n \n \n \n(\n \n \n \nm\n \nσ\n \nT\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nm\n \nɛ\n \nT\n \n \n \n)', 'T\n \n \n \n,\n \n \n \n \n \n(\n \n21\n \n)\n \n \n \n \n \n \n \n \nd\n \n≡\n \n \n \n(\n \n \n \nd\n \nR\n \nT\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nd\n \nX\n \nT\n \n \n \n)\n \n \nT\n \n \n \n,\n \n \n \n \n \n(\n \n22\n \n)\n \n \n \n \n \n \n \n \n \nd\n \nOBS\n \n \n=\n \n \n \n[\n \n \n \n \n(\n \n \nd\n \nR\n \nOBS\n \n \n)\n \n \nT\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n(\n \n \nd\n \nX\n \nOBS\n \n \n)\n \n \nT\n \n \n \n]\n \n \nT\n \n \n \n,\n \n \n \n \n \n(\n \n23\n \n)', 'W\n \n_\n \n \nD\n \n \n=\n \n \n \n(\n \n \n \n \n \n \nW\n \n_\n \n \nR\n \n \n \n \n \n0\n \n_\n \n \n \n \n \n \n \n0\n \n_\n \n \n \n \n \n \nW\n \n_\n \n \nX\n \n \n \n \n \n)\n \n \n.', '(\n \n24\n \n)', 'In Eq.', '(24), \n0\n ∈R\nM×M \nis a zero matrix.', 'Supposing the current iterative step is l, the solution at this step is \n \nm\nl\n=m\nl−1\n+v\nl−1\nq\nl−1\n\u2003\u2003(25) \n where q\nl−1 \nis the Newton search direction; v\nl−1 \nis a step length to reduce the effect of approximation error caused by the quadratic approximation at the current step.', 'The search vector may be given by \n \nq\nl−1\n=−\nG\nl−1\n−1\ng\nl−1\n\u2003\u2003(26) \n where g\nl−1 \nis the gradient of the cost function and \nG\nl−1 \nis its Hessian.', 'They are given by \n \ng\nl−1\n=J\nl−1\nt\nW\nD\nt\nW\nD\n(\nd\nl−1\n−d\nOBS\n)−γ\nr\nl−1\n∇(\nm\nl−1\n)', '+γ\nS\nl−1\n∇(\nm\nl−1\n)\u2003\u2003(27) \n \nG\nl−1\n=\nJ\nl−1\nt\nW\nD\nt\nW\nD\nJ\nl−1', '+γ\nP\nl−1\n∇∇(\nm\nl−1\n)', '+γ\nS\nl−1\n∇∇(\nm\nl−1\n)\u2003\u2003(28)', 'In the above two equations, d\nl−1 \nis the simulated data corresponding to the model m\nl−1 \nobtained at the previous step; \nJ\nl−1 \nis the Jacobian of the data term χ\n2 \nof the cost function, evaluated at m=m\nl−1\n.', '∇ and ∇ are the gradients of the maximum entropy and the smoothing terms in Eq.', '(6), respectively.', '∇∇ and ∇∇ are their Hessians, respectively.', 'A form of these four gradients and Hessians may be derived from and in Eqs.', '(10) and (11).', 'The two regularization parameters, γ\nP \nand γ\nS\n, may be dynamically adjusted with χ\n2 \nduring the iteration such that: \n γ\nP\nl−1\n=δ\nP\nχ\n2\n(\nm\nl−1\n)\u2003\u2003(29) \n γ\nS\nl−1\n=δ\nX\nχ\n2\n(\nm\nl−1\n)\u2003\u2003(30) \n where χ\n2 \n(m\nl−1\n) is the data misfit evaluated at m=m\nl−1\n, the model obtained at the previous step.', 'Numerical experiments show that setting δ\nP \nand δ\nS \nto 1 is an appropriate choice for both synthetic and field data processing.', 'Once the search direction is determined from Eq.', '(26), a linear search follows to determine the steplength v\nl−1\n.', 'Jacobian \nJ\nl−1\n∈R\n2M×2N \ncontains the first derivatives of d\nR \nand d\nX \nwith respect to pixel conductivities and dielectric constants, evaluated at m=m\nl−1\n.', 'It is given by\n \n \n \n \n \n \n \n \n \n \nJ\n \n_\n \n \n \nl\n \n-\n \n1\n \n \n \n=\n \n \n \n(\n \n \n \n \n \n \n∂\n \n \nd\n \nR\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nR\n \n \n \n \n∂\n \n \nm\n \nɛ\n \n \n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nX\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nX\n \n \n \n \n∂\n \n \nm\n \nɛ\n \n \n \n \n \n \n \n)', '\u2062\n \n \n❘\n \n \nm\n \n=\n \n \nm\n \n \nl\n \n-\n \n1\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nWhere\n \n:\n \n \n \n \n \n \n \n(\n \n31\n \n)\n \n \n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nη\n \n \n \n \n∂\n \nx\n \n \n \n=\n \n \n(\n \n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \n1\n \n \n \n \n \n∂\n \n \nx\n \n1\n \n \n \n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \n1\n \n \n \n \n \n∂\n \n \nx\n \n2\n \n \n \n \n \n \n…\n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \n1\n \n \n \n \n \n∂\n \n \nx\n \nN\n \n \n \n \n \n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \n2\n \n \n \n \n \n∂\n \n \nx\n \n1\n \n \n \n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \n2\n \n \n \n \n \n∂\n \n \nx\n \n2\n \n \n \n \n \n \n…\n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \n2\n \n \n \n \n \n∂\n \n \nx\n \nN\n \n \n \n \n \n \n \n \n⋮\n \n \n \n⋮\n \n \n \n⋱\n \n \n \n⋮\n \n \n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \nM\n \n \n \n \n \n∂\n \n \nx\n \n1\n \n \n \n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \nM\n \n \n \n \n \n∂\n \n \nx\n \n2\n \n \n \n \n \n \n…\n \n \n \n \n \n∂\n \n \nd\n \n \nη\n \n,\n \nM\n \n \n \n \n \n∂\n \n \nx\n \nN\n \n \n \n \n \n \n \n)\n \n \n \n,\n \n \nη\n \n=\n \nR\n \n \n,\n \n \nX\n \n;\n \n \nx\n \n=\n \n \nm\n \nσ\n \n \n \n \n,\n \n \nm\n \nɛ\n \n \n \n \n \n \n(\n \n32\n \n)', 'In some embodiments, the derivatives of d\nR \nand d\nX \nwith respect to conductivities of pixels may be computed with an analytical approach or using a finite difference approximation.', 'Instead of computing them directly, the derivatives with respect to dielectric constants may be derived from those with respect to conductivities.', "Making using of the Born's approximation, the following relationships may be obtained:\n \n \n \n \n \n \n \n \n \n \n \n1\n \n \nωɛ\n \n0\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n∂\n \n \nd\n \n \nR\n \n,\n \nj\n \n \n \n \n \n∂\n \n \nɛ\n \n \nr\n \n,\n \nk\n \n \n \n \n \n \n=\n \n \n \n∂\n \n \nd\n \n \nX\n \n,\n \nj\n \n \n \n \n \n∂\n \n \nσ\n \nk\n \n \n \n \n \n,\n \n \n \n \n \n(\n \n33\n \n)", '1\n \n \nωɛ\n \n0\n \n \n \n\u2062\n \n \n \n∂\n \n \nd\n \n \nX\n \n,\n \nj\n \n \n \n \n \n∂\n \n \nɛ\n \n \nr\n \n,\n \nk\n \n \n \n \n \n \n=\n \n \n-\n \n \n \n∂\n \n \nd\n \n \nR\n \n,\n \nj\n \n \n \n \n \n∂\n \n \nσ\n \nk\n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n34\n \n)\n \n \n \n \n \n \n \n for real and imaginary data at the j-th depth point and conductivity and dielectric constant of pixel k.', 'They can be written in vector form as \n \n \n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nR\n \n \n \n \n∂\n \n \nm\n \nɛ\n \n \n \n \n=\n \n \n \n∂\n \n \nd\n \nX\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n \n(\n \n35\n \n)\n \n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nX\n \n \n \n \n∂\n \n \nm\n \nɛ\n \n \n \n \n=\n \n \n-\n \n \n \n∂\n \n \nd\n \nR\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n \n \n(\n \n36\n \n)', 'Substituting Eqs.', '(35) and (36) in Eq.', '(31) yields\n \n \n \n \n \n \n \n \n \n \nJ\n \n_\n \n \n \nl\n \n-\n \n1\n \n \n \n=\n \n \n \n(\n \n \n \n \n \n \n∂\n \n \nd\n \nR\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nX\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n \n \n \n∂\n \n \nd\n \nX\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n-\n \n \n \n∂\n \n \nd\n \nR\n \n \n \n \n∂\n \n \nm\n \nσ\n \n \n \n \n \n \n \n \n)\n \n \n\u2062\n \n \n❘\n \n \nm\n \n=\n \n \nm\n \n \nl\n \n-\n \n1\n \n \n \n \n \n \n \n \n \n \n(\n \n37\n \n)\n \n \n \n \n \n \n \n \nThe use of the Jacobian in Eq.', '(37) expedites the inversion by nearly a factor of two compared to using the Jacobian in Eq.', '(31).', 'The stopping criteria for the inversion may be χ\n2\n l\nmax\n, where l is the index for iteration step.', 'M\nf \nis the number of degrees of freedom, M\nf\n=2M if all data are independent random variables.', 'In one example of the inversion, l\nmax\n, the maximum number of iterations, is set to 50, but any other suitable maximum number of iterations may be used.', 'To help illustrate the above discussion, an example process \n70\n for determining a dielectric constant and resistivity measurements in accordance with present disclosure is described in \nFIG.', '7\n.', 'Generally, the process \n70\n includes providing formation dip and initial guesses for conductivity and dielectric constant (process block \n72\n), simulating induction data (process block \n74\n), computing difference in χ\n2 \n(process block \n76\n) based on received field induction data \n78\n, and determining whether the inversion meets the stopping criteria (process block \n80\n).', 'The process \n70\n includes computing a Jacobian for conduction (process block \n82\n) when the inversion does not meet the stopping criteria, deriving a Jacobian for a dielectric constant (process block \n84\n), computing a search direction and determining a step length (process block \n86\n), and updating the conductivity and dielectric constant (process block \n88\n) and continuing with process block \n74\n.', 'When the inversion does meet the stopping criteria, the process \n70\n includes applying a low-pass filter to the conductivity and the dielectric constant (\n90\n), computing resistivity from filtered conductivity (process block \n92\n) to output the resistivity \n94\n, outputting the conductivity \n96\n, and outputting the dielectric constant \n98\n.', 'Although described in a particular order, which represents a particular embodiment, it should be noted that the process \n70\n may be performed in any suitable order.', 'Additionally, embodiments of the process \n70\n may omit process blocks and/or include additional process blocks.', 'Moreover, in some embodiments, the process \n70\n may be implemented at least in part by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as memory \n32\n implemented in a data processing system \n28\n, using processing circuitry, such as a processor \n30\n implemented in the data processing system \n28\n.', 'In some embodiments, some variants can be derived from the formulation in the above to further enhance the performance of the inversion.', 'For instance, instead of inverting for σ and ε\nr\n, one may choose to invert for the logarithms of σ and ωε\n0\nε\nr\n.', 'To accommodate the transforms, the Maximum entropy term in Eq.', '(4) can be modified to:\n \n \n \n \n \n \n \n \n \n \nℒ\n \nP\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n=\n \n \n \n-\n \n \n \n∫\n \n \n-\n \n∞\n \n \n∞\n \n \n\u2062\n \n \ndz\n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \nσ\n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n+\n \n \nγ\n \nσ\n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \nT\n \nσ\n \n \n \n+\n \n \nγ\n \nσ\n \n \n \n \n\u2061\n \n \n[\n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \nσ\n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n+\n \n \nγ\n \nσ\n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nσ\n \nP\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n+\n \n \nγ\n \nσ\n \n \n \n \n \n-\n \n1\n \n \n]\n \n \n \n \n \n \n-\n \n \n \n∫\n \n \n-\n \n∞\n \n \n∞\n \n \n\u2062\n \n \ndz\n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \nr\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n+\n \n \nγ\n \nɛ\n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \nT\n \nɛ\n \n \n \n+\n \n \nγ\n \nɛ\n \n \n \n \n\u2061\n \n \n[\n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \nr\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n+\n \n \nγ\n \nɛ\n \n \n \n \n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \n \nr\n \n,\n \nP\n \n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \n+\n \n \nγ\n \nɛ\n \n \n \n \n \n-\n \n1\n \n \n]\n \n \n \n \n \n \n \n \n \n \n(\n \n37\n \n)\n \n \n \n \n \n \n \n where γ\nσ\n γ\nε\n are two positive numbers to prevent the denominators from being vanishingly small.', 'Accordingly, the smoothing term in Eq.', '(5) can be modified to \n \n \n \n \n \n \n \n \n \n \nℒ\n \nS\n \n \n\u2061\n \n \n(\n \n \nσ\n \n,\n \n \nɛ\n \nr\n \n \n \n)\n \n \n \n=\n \n \n \n \n∫\n \n \n-\n \n∞\n \n \n∞\n \n \n\u2062\n \n \n \ndz\n \n\u2061\n \n \n[\n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \nσ\n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \ndz\n \n \n]\n \n \n \n2\n \n \n \n+\n \n \n∫\n \n \n \n \ndz\n \n\u2061\n \n \n[\n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nln\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nɛ\n \nr\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n \ndz\n \n \n]\n \n \n \n2\n \n \n.', '(\n \n38\n \n)\n \n \n \n \n \n \n \n \nTo facilitate numerical implementations, if a zone to be processed is long, the zone may be first subdivided into a sequence of short intervals.', 'The inversion may be run on each interval separately in serial or in parallel.', 'The results of all intervals may be combined to obtain an output.', 'In one example, each interval may be 30 ft with a transition zone of 25 ft on both sides.', 'The relative dip θ, or the angle made by the tool axis and the normal to the bedding planes, may be assumed to be already known and therefore may be fixed in the inversion.', 'It can be obtained with borehole image data or some advanced electromagnetic measurements (e.g., triaxial induction data).', 'Upon output, σ and ε\nr \nthat are obtained at the last iteration or any other iteration may be low-pass filtered to remove any undesirable spikes before being delivered as the final solution.', 'For example, a Gaussian filter with a standard deviation of 0.35 ft may be used as the low pass filter, but any other suitable low-pass filter may be used.', 'In addition to σ, resistivity is also provided as a reciprocal of the filtered conductivity, denoted as R. σ and R reflect the collective effect of both formation and conductive inclusions such as graphite flakes or pyrite particles.', 'The resolution of σ and R, although potentially significantly higher than that of apparent conductivity, is dependent on the tool spacing.', 'For an induction tool with a spacing of 72 in from transmitter to main receiver, when the bed thickness is larger than 2 ft, σ and R can read the true formation conductivity and dielectric constant free of bed boundary and dip effects.', 'Moreover, in comparison to apparent conductivity, there may be reduced or no skin effect and reduced or no distortion in σ and R caused by the real part of dielectric constant, which may be already corrected in the inversion together with the bed boundary and dip effects.', 'Numerical Results\n \nFIGS.', '8-11\n represent example induction well logs obtained using the inversion process as discussed herein.', 'As discussed further below, the inversion of this disclosure has proven successful in a number of situations.', 'I. Chirp Models.', 'The chirp models include an alternating sequence of resistive and conductive beds with gradually increasing thickness from top to bottom.', 'In this example, the first bed on the very top is 0.5 ft; the last one at the bottom is 6 ft.', 'The others in between are 1, 2, 4 and 6 ft, respectively from top to bottom.', 'All the resistive beds have a resistivity of 100 ohm·m, and all the conductive ones a resistivity 2 ohm·m.', 'The dielectric constants for the first model are 50,000 and 500 for the resistive and conductive beds, respectively.', 'The second model is similar to the first one except that the dielectric constant is set to one in the entire interval.', 'The data for the inversion may be acquired with the simulation of measurements of an induction tool with a spacing of 72 in from transmitter to main receiver.', 'FIG.', '8\n shows three panels \n110\n, \n112\n, \n114\n displaying well log data related to induction well logging measurements based on a first model having a first dielectric constant.', 'The well log data of each panel \n110\n, \n112\n, and \n114\n is depth (e.g., axis \n116\n) versus a respective set of logs (e.g., axes \n118\n, \n120\n, and \n122\n).', 'Panel \n110\n depicts depth versus resistivity obtained with the standard processing, panel \n112\n depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel \n114\n depicts depth versus dielectric constant obtained using the inversion process as discussed herein.', 'For the first model in \nFIG.', '8\n, comparing inversion-derived R and ε\nr \nwith their true values (square logs) shows that the inversion can resolve a bed as thin as 2 ft.', 'When the bed is 3 ft or larger, the readings of R and ε\nr \nat the middle of the bed may be similar or identical to their true values.', 'The inversion can barely see the 1-ft bed near the top of the interval, and completely misses the 0.5 ft bed on the very top.', 'The same observations are made for R for the second model as shown in \nFIG.', '9\n, where the dielectric effect is negligible.', 'However, the inversion-derived ε\nr \nis completely different from the true ε\nr\n.', 'The significant difference illustrates the limit of the inversion for determining dielectric constant from induction data.', 'Dielectric constant can be viewed as the imaginary part of a complex conductivity with reference to Eq.', '(1).', 'An imaginary conductivity of 1 mS/m corresponds to a dielectric constant of 690 for a frequency of 26 kHz.', 'The principle of induction measurements suggests that when the dielectric constant is small, the induction data is not sensitive enough to warrant a reliable estimation of dielectric constant.', 'One lower limit for dielectric constant may be 1000.\n \nFIG.', '9\n shows three panels \n124\n, \n126\n, and \n128\n displaying well log data related to induction well logging measurements based on a second model having a second dielectric constant.', 'The well log data of each panel \n124\n, \n126\n, and \n128\n is depth (e.g., axis \n130\n) versus a respective set of logs (e.g., axes \n132\n, \n134\n, and \n136\n).', 'Panel \n124\n depicts depth versus resistivity obtained with the standard processing, panel \n126\n depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel \n128\n depicts depth versus dielectric constant obtained using the inversion process as discussed herein.', 'For the second model, the true dielectric constant takes the value of one in the interval.', 'Because of the low sensitivity, the dielectric constant obtained with the inversion can be anywhere from 1 to 300.', 'For field data processing, the lower limit of dielectric constant in the inversion is set to the value corresponding to a conductivity of 1 mS/m for a given induction tool.', 'It is worth noting the difference of array induction logs for the two models.', 'Close examination shows that the resistivities of the logs for the first model (e.g., shown in \nFIG.', '8\n) with large dielectric constant are slightly higher than those for the second model (e.g., shown in \nFIG.', '9\n).', 'The increase may be attributed to the scheme for skin effect correction used in obtaining the array induction logs.', 'In contrast, inspection of two inversion-derived resistivity logs shows that the readings are nearly the same regardless of dielectric constant.', 'In other words, the inversion-derived resistivity log is free of dielectric effect.\n \nII.', 'Modified Oklahoma Model.', 'A modified Oklahoma model is made by adding a dielectric constant to the Oklahoma model that is often used to test the performance of inversion methods.', 'The model is described in more detail in Table 1.', 'Example well logs involving the modified Oklahoma model are shown in \nFIGS.', '10 and 11\n.', 'The positions of the bed boundaries are defined along the well path in the tool coordinates.', 'When the relative dip of the formation is zero, the bed thickness computed with the positions of bed boundaries is similar or identical to the true thickness of a given bed.', 'Otherwise, it should be understood as the apparent thickness of the given bed.\n \n \n \n \n \n \n \n \nTABLE 1', 'The modified Oklahoma model\n \n \n \n \n \n \n \n \n \n \n \n \n \nNo.\n \nz (ft)\n \nR (ohm · m)\n \nε\nr\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n1\n \n0\n \n1\n \n100000\n \n \n \n \n2\n \n17\n \n10\n \n10000\n \n \n \n \n3\n \n25\n \n0.4\n \n250000\n \n \n \n \n4\n \n29\n \n3\n \n33333\n \n \n \n \n5\n \n32\n \n0.9\n \n111111\n \n \n \n \n6\n \n39\n \n20\n \n5000\n \n \n \n \n7\n \n43\n \n0.7\n \n142857\n \n \n \n \n8\n \n49\n \n90\n \n1111\n \n \n \n \n9\n \n52\n \n6\n \n16667\n \n \n \n \n10\n \n57\n \n120\n \n833\n \n \n \n \n11\n \n64\n \n4\n \n25000\n \n \n \n \n12\n \n82\n \n150\n \n667\n \n \n \n \n13\n \n90\n \n40\n \n2500\n \n \n \n \n14\n \n97\n \n1.5\n \n66667\n \n \n \n \n15\n \n107\n \n100\n \n1000\n \n \n \n \n16\n \n111\n \n18\n \n5556\n \n \n \n \n17\n \n116\n \n100\n \n1000\n \n \n \n \n18\n \n119\n \n1.5\n \n66667\n \n \n \n \n19\n \n123\n \n7.5\n \n13333\n \n \n \n \n20\n \n127\n \n0.9\n \n111111\n \n \n \n \n21\n \n131\n \n2\n \n50000\n \n \n \n \n22\n \n136\n \n10\n \n10000\n \n \n \n \n23\n \n139\n \n1.8\n \n55556\n \n \n \n \n24\n \n141\n \n20\n \n5000\n \n \n \n \n25\n \n143\n \n7.5\n \n13333\n \n \n \n \n26\n \n145\n \n15\n \n6667\n \n \n \n \n27\n \n157\n \n0.7\n \n142857\n \n \n \n \n28\n \n∞\n \n1.1\n \n90909\n \n \n \n \n \n \n \n \n \n \n \nFIG.', '10\n shows three panels \n138\n, \n140\n, and \n142\n displaying resistivity and dielectric constant determined with the inversion in the modified Oklahoma model of a relative dip of 30 degrees.', 'The well log data of each panel \n138\n, \n140\n, and \n142\n is depth (e.g., axis \n144\n) versus a respective set of logs (e.g., axes \n146\n, \n148\n, and \n150\n).', 'Panel \n138\n depicts depth versus resistivity obtained with the standard processing, panel \n140\n depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel \n142\n depicts depth versus dielectric constant obtained using the inversion process as discussed herein.', 'More specifically, two-foot standard array induction resistivity logs are displayed in left panel as reference.', 'In this first case, the relative dip of the modified Oklahoma model is 30 deg.', 'The value of the dip is fed to the inversion and is fixed in the inversion.', 'As in the chirp models, the data of the 72 in.', 'induction tool is used to solve for conductivity and dielectric constant.', 'The results are displayed in \nFIG.', '10\n.', 'The resistivity R and dielectric constant ε\nr \nobtained with the inversion are displayed in the panel \n140\n and the panel \n142\n.', 'The two-foot array induction resistivity logs are displayed in the left panel as reference.', 'The square logs (e.g., ‘RES_MOD’) in the panel \n138\n and the panel \n140\n are the true resistivity of the formation.', 'The square log (e.g., ‘ESPR_MOD’) in the panel \n142\n is the true dielectric constant of the formation.', 'Both the resistivity and dielectric constant logs obtained with the inversion can well resolve the three thin layers located below 139 ft. and above 145 ft.', 'The two-foot induction resistivity logs can hardly see the three layers.', 'Above 139 ft., the reading of the inversion-derived resistivity log is nearly the same as the true resistivity at the middle of each bed.', 'In contrast, the two-foot standard induction resistivity logs read consistently lower than the true resistivity when the bed is less than 5 ft., which may be attributed to the coexistence of dipping and dielectric effect.', 'Comparison of inversion-derived resistivity and dielectric constant shows the two logs behave similarly and have similar resolution.\n \nFIG.', '11\n shows three panels \n152\n, \n154\n, and \n156\n displaying resistivity and dielectric constant determined with the inversion in the modified Oklahoma model of a relative dip of 60 degrees.', 'The well log data of each panel \n152\n, \n154\n, and \n156\n is depth (e.g., axis \n158\n) versus a respective set of logs (e.g., axes \n160\n, \n162\n, and \n164\n).', 'Panel \n152\n depicts depth versus resistivity obtained with the standard processing, panel \n154\n depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel \n156\n depicts depth versus dielectric constant obtained using the inversion process as discussed herein.', 'More specifically, two-foot standard array induction resistivity logs are displayed in the panel \n152\n as reference.', 'In \nFIG.', '11\n, the relative dip of the modified Oklahoma model is increased to 60 deg.', 'As a result, the true thicknesses of the beds are reduced to a half of those computed with the bed boundaries in Table 1.', 'To compensate for the lack of high frequency information of the 72 inch induction tool, the data of a 39 inch induction tool may be used in addition to the data of the former, which can partially offset the influence of the decrease of the true bed thicknesses.', 'The results are displayed in \nFIG.', '11\n.', 'As with \nFIG.', '10\n, the resistivity R and dielectric constant ε\nr \nobtained with the inversion are displayed in the panel \n154\n and the panel \n156\n.', 'The square logs (e.g., ‘RES_MOD’) in the panel \n152\n and the panel \n154\n are the true resistivity of the formation.', 'The square log (e.g., ‘ESPR_MOD’) in the panel \n156\n is the true dielectric constant of the formation.', 'Comparison of the inversion-derived resistivity R and dielectric constant ε\nr \nshows that the resolution of the resistivity log is slightly better than that of the dielectric constant log.', 'The dielectric constant log (e.g., ‘ESPR72_1D’) fails to resolve the three thin layers in the interval from 139 ft to 145 ft, as indicated by the dielectric constant log in the panel \n156\n being outside and not overlapping the green square log in the panel \n156\n.', 'However, the resistivity log can still distinguish between the three layers.', 'The two-foot standard induction resistivity logs are strongly affected by the dipping and bed boundary effect.', 'In contrast, the inversion-derived resistivity R and dielectric constant ε\nr \nare free of dipping and bed boundary effect.', 'The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms.', 'It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.'] | ['1.', 'A method comprising:\nobtaining induction measurements in a wellbore through a geological formation using one or more downhole induction well-logging tools;\ninverting the induction measurements based on a one-dimensional model comprising a plurality of geological layers; wherein each geological layer of the plurality of geological layers comprises a respective conductivity value and a respective dielectric constant value, and wherein inverting the induction measurements is based on a partial derivative of a simulated real apparent conductivity and a simulated imaginary apparent conductivity associated with the respective conductivity values and the respective dielectric constant values of the plurality of geological layers; and\ngenerating resistivity and dielectric constant values of the geological formation based on the output of the inversion of induction measurements.', '2.', 'The method of claim 1, wherein partial derivatives of a simulated real apparent conductivity and a simulated imaginary apparent conductivity with respect to dielectric constant are obtained with partial derivatives of the simulated real and imaginary apparent conductivities with respect to conductivity.', '3.', 'The method of claim 1, comprising outputting a resistivity well log based on the resistivity values, a dielectric well log based on the dielectric constant values, or both.', '4.', 'The method of claim 1, wherein the induction measurements are inverted based on minimizing a cost function comprising a misfit term, an entropy term, and a smoothing term.', '5.', 'The method of claim 4, wherein the misfit term, the entropy term, and the smoothing term are each dependent on a conductivity and a dielectric constant of each of the plurality of geological layers.', '6.', 'The method of claim 4, wherein the cost function is minimized based on a Gauss-Newton method.', '7.', 'The method of claim 6, wherein the Gauss-Newton method comprises two regularization parameters that are based on the misfit term.', '8.', 'The method of claim 1, wherein generating the resistivity of the geological formation based on the output of the inversion of induction measurements comprises filtering a conductivity associated with each of the plurality of geological layers.', '9.', 'An article of manufacture comprising tangible, non-transitory, machine-readable media comprising instructions that, when executed by a processor, cause the processor to:\nreceive induction measurements associated with wellbore through a geological formation obtained by one or more downhole induction well-logging tools;\ninvert the induction measurements based on minimizing a cost function, wherein the cost function comprises a misfit term, an entropy term, and a smoothing term, wherein inverting the induction measurements is based on a one-dimensional model comprising a plurality of geological layers wherein the plurality of geological layers comprises a respective constant conductivity and a respective constant dielectric constant, and wherein the cost function is discretized based on a conductivity of each geological layer of the plurality of layers; and\ngenerate resistivity and dielectric constant values associated with the geological formation based on the output of the inversion of induction measurements.', '10.', 'The article of manufacture of claim 9, wherein inverting the induction measurements is based on a partial derivative of a simulated real apparent conductivity and a simulated imaginary apparent conductivity associated with a respective conductivity value and a respective dielectric constant value of the plurality of geological layers.', '11.', 'The method of claim 10, wherein the partial derivative of the simulated real apparent conductivity and the simulated imaginary apparent conductivity with respect to dielectric constant are obtained with partial derivatives of the real and imaginary apparent conductivities with respect to conductivity.', '12.', 'The article of manufacture of claim 9, wherein the cost function is minimized based on a Gauss-Newton method.', '13.', 'The article of manufacture of claim 12, wherein the cost function is minimized iteratively until a threshold is reached, wherein the threshold is based on the misfit term.', '14.', 'A system comprising:\na downhole well-logging tool configured to obtain one or more induction measurements from a geological formation;\na processor; and\na memory storing instructions configured to be executed by the processor, the instructions comprising instructions to: receive the induction measurements obtained by the downhole well-logging tool; invert the induction measurements based on a one-dimensional model comprising a plurality of geological layers and a cost function, and wherein each geological layer of the one-dimensional model comprises a constant conductivity and a constant dielectric constant, and wherein inverting the induction measurements is based on a partial derivative of a simulated real apparent conductivity and a simulated imaginary apparent conductivity associated with a respective conductivity value and a respective dielectric constant values of the plurality of geological layers; and generate resistivity and dielectric constant values associated with the geological formation based on the output of the inversion of induction measurements.\n\n\n\n\n\n\n15.', 'The system of claim 14, wherein the induction measurements are inverted based on a cost function comprising a misfit term, an entropy term, and a smoothing term.'] | ['FIG.', '1 is a schematic diagram of a well-logging system that may obtain induction measurements that may be used to identify formation resistivity and dielectric constant, in accordance with an embodiment;; FIG.', '2 illustrates a flow chart of various processes that may be performed based on analysis of induction well log data, in accordance with aspects of the present disclosure;; FIG.', '3 is a schematic diagram of a downhole coaxial array that may be used to collect induction measurements, in accordance with an embodiment;; FIG.', '4 is a schematic diagram of a downhole triaxial array that may be used to collect induction measurements, in accordance with an embodiment;; FIG.', '5 is a schematic diagram of a one-dimensional (1D) formation model that may be used to ascertain conductivity or resistivity and dielectric constant, in accordance with an embodiment;; FIG.', '6 is a flowchart of an inversion to determine conductivity or resistivity and dielectric constant, in accordance with an embodiment;; FIG. 7 is a flowchart of an inversion to determine conductivity or resistivity and dielectric constant, in accordance with an embodiment;; FIG. 8 is an example well log of resistivity and dielectric constant determined with inversion in a chirp model in the presence of large dielectric effect, in accordance with an embodiment;; FIG.', '9 is an example well log of resistivity and dielectric constant determined with inversion in a chirp model in the absence of large dielectric effect, in accordance with an embodiment;; FIG.', '10 is an example well log of resistivity and dielectric constant determined with inversion in a modified Oklahoma model of a relative dip of 30 degrees, in accordance with an embodiment; and; FIG.', '11 is an example well log of resistivity and dielectric constant determined with inversion in a modified Oklahoma model of a relative dip of 60 degrees, in accordance with an embodiment.; FIG.', '2 illustrates a method 40 of various processes that may be performed based on analysis of well logs, in accordance with aspects of the present disclosure.', 'A location of hydrocarbon deposits within a geological formation may be identified (process block 42) based on well-log data.', 'In some embodiments, the well-log data may be analyzed to generate a map or profile that illustrates regions of interest with the geological formation.', '; FIG.', '4 shows another example of an illustrated embodiment of the well-logging tool 12 that includes a triaxial induction tool (e.g., the Rt Scanner tool by Schlumberger Technology Corporation) with mutually orthogonal and collocated transmitter and receiver coils.', 'As shown, the well-logging tool 12 in FIG.', '4 includes three transmitters 57, three first receivers 58 (e.g., balancing receivers), and three second receivers 59 (e.g., main receivers).', 'Generally speaking, the three transmitters 57 induce electric eddy current in the formation that flow parallel to orthogonal planes oriented with their normals in the X (e.g., along the axis 55), Y (e.g., along the axis 54), and Z directions (e.g., along the axis 56), which are defined by the directions of the magnetic dipole moments of each of the three transmitter coils.', 'As such, the well-logging tool 12 shown in FIG. 4 may measure all nine orthogonal couplings to determine formation resistivity and resistivity anisotropy as well as formation dip.', 'While the illustrated embodiment of the well-logging tool 12 shown in FIG.', '4 includes one transmitter (e.g., transmitter 51) and two receivers (e.g., receiver 52), the number of transmitters 57 and receivers 58, 59 is not a limit on the scope of the present invention.', 'It should be noted that inhomogeneties in the rock formations will distort the currents flowing therethrough, and the electromagnetic fields at the receivers 58 and 59 are different from what would have existed if the formation were homogeneous.; FIGS. 8-11 represent example induction well logs obtained using the inversion process as discussed herein.', 'As discussed further below, the inversion of this disclosure has proven successful in a number of situations.; FIG.', '8 shows three panels 110, 112, 114 displaying well log data related to induction well logging measurements based on a first model having a first dielectric constant.', 'The well log data of each panel 110, 112, and 114 is depth (e.g., axis 116) versus a respective set of logs (e.g., axes 118, 120, and 122).', 'Panel 110 depicts depth versus resistivity obtained with the standard processing, panel 112 depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel 114 depicts depth versus dielectric constant obtained using the inversion process as discussed herein.; FIG.', '9 shows three panels 124, 126, and 128 displaying well log data related to induction well logging measurements based on a second model having a second dielectric constant.', 'The well log data of each panel 124, 126, and 128 is depth (e.g., axis 130) versus a respective set of logs (e.g., axes 132, 134, and 136).', 'Panel 124 depicts depth versus resistivity obtained with the standard processing, panel 126 depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel 128 depicts depth versus dielectric constant obtained using the inversion process as discussed herein.; FIG.', '10 shows three panels 138, 140, and 142 displaying resistivity and dielectric constant determined with the inversion in the modified Oklahoma model of a relative dip of 30 degrees.', 'The well log data of each panel 138, 140, and 142 is depth (e.g., axis 144) versus a respective set of logs (e.g., axes 146, 148, and 150).', 'Panel 138 depicts depth versus resistivity obtained with the standard processing, panel 140 depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel 142 depicts depth versus dielectric constant obtained using the inversion process as discussed herein.; FIG.', '11 shows three panels 152, 154, and 156 displaying resistivity and dielectric constant determined with the inversion in the modified Oklahoma model of a relative dip of 60 degrees.', 'The well log data of each panel 152, 154, and 156 is depth (e.g., axis 158) versus a respective set of logs (e.g., axes 160, 162, and 164).', 'Panel 152 depicts depth versus resistivity obtained with the standard processing, panel 154 depicts depth versus resistivity obtained using the inversion process as discussed herein, and panel 156 depicts depth versus dielectric constant obtained using the inversion process as discussed herein.'] |
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US11149545 | Closed chamber impulse test with downhole flow rate measurement | May 6, 2014 | Fikri John Kuchuk, Stephane Hiron, Bertrand Theuveny, Anthony J. Fitzpatrick, James G. Filas, Alexander Starostin, Pavel Evgenievich Spesivtsev | SCHLUMBERGER TECHNOLOGY CORPORATION | Biryukov et al., “Pressure transient solutions to mixed boundary value problems for partially open wellbore geometries in porous media”, Journal of Petroleum Science and Engineering, 96-97:162-175, 2012.; Biryukov et al., “Transient Pressure Behavior of Reservoirs with Discrete Conductive Faults and Fractures”, Transport in Porous Media, 95:239-268, 2012.; Booth et al., “Grid-Based Inversion of Pressure Transient Test Data”, Presented at ECMORXII—12th European Conference on the Mathematics of Oil Recovery, Oxford, UK, Sep. 6-9, 2010.; Booth et al., “Grid-based Inversion of Pressure Transient Test Data With Stochastic Gradient Techniques”, International Journal for Uncertainty Quantification, 2 (4):323-339, 2012.; Cipolla et al., “Seismic-to-Simulation for Unconventional Reservoir Development”, SPE 146876 presented at the SPE Reservoir Characterisation and Simulation Conference and Exhibition, Abu Dhabi, UAE, Oct. 9-11, 2011.; De Brito Nogueira et al., “Integrated Workflow Characterizes Campos Basin Fractured Reservoirs Using Pressure Transient Tests”, World Oil, Feb. 2013, pp. 103-106.; Guichard et al., “The First Successful Impulse Test on Coiled Tubing Results in Reliable Reservoir Evaluation for Non-naturally Flowing Wells”, SPE 128429 presented at the SPE North Africa Technical Conference and Exhibition, Cairo, EG, Feb. 14-17, 2010.; Kuchuk et al., “Transient Pressure Test Interpretation for Continuously and Discretely Fractured Reservoirs”, SPE 158096 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, TX, USA, Oct. 8-10, 2012.; Morton et al., “Global Sensitivity Analysis for Natural Fracture Geological Modeling Parameters from Pressure Transient Tests”, SPE 164894 presented at the EAGE Annual Conference & Exhibition incorporating SPE Europec, London, UK, Jun. 10-13, 2013.; Morton et al., “Grid-Based Inversion Methods for Spatial Feature Identification and Parameter Estimation from Pressure Transient Tests”, SPE 142996 presented at the SPE EUROPEC/EAGE Annual Conference and Exhibition, Vienna, AT, May 23-26, 2011.; Morton et al., “Integrated Interpretation for Pressure Transient Tests in Discretely Fractured Reservoirs”, SPE 154531 presented at the EAGE Annual Conference & Exhibition incorporating SPE Europec, Copenhagen, DK, Jun. 4-7, 2012.; International Search Report and Written Opinion issued in corresponding International Application No. PCT/US2014/037023 dated Nov. 24, 2014.; International Preliminary Report on Patentability issued in the related PCT Application PCT/US2014/037023, dated Nov. 10, 2015 (6 pages).; Extended Search Report issued in the related EP Application 14794319.5, dated Dec. 6, 2016 (8 pages). | 5887652; March 30, 1999; Beck; 6330913; December 18, 2001; Langseth; 6357525; March 19, 2002; Langseth; 6598682; July 29, 2003; Johnson et al.; 7478555; January 20, 2009; Zhan; 20020017386; February 14, 2002; Ringgenberg; 20050103490; May 19, 2005; Pauley; 20070050145; March 1, 2007; Zhan; 20070162235; July 12, 2007; Zhan; 20080149349; June 26, 2008; Hiron et al.; 20100126717; May 27, 2010; Kuchuk et al.; 20110040536; February 17, 2011; Levitan; 20110130966; June 2, 2011; Zhan | WO0065200; November 2000; WO | ['An apparatus for performing a well test operation includes a tubular member having a surge chamber and a valve that can control fluid flow from a well into the surge chamber during the well test operation.', 'The apparatus can also include a flow control device, in addition to the valve, for further controlling fluid flow into the surge chamber from the well.', 'Flow rate and pressure data can be measured during the well test operation and used to estimate reservoir properties.', 'Various other systems, devices, and methods are also disclosed.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates to well testing and more particularly to methods and apparatuses for performing and interpreting well test measurements.', 'DESCRIPTION OF THE RELATED ART\n \nHydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation.', 'Once a wellbore is drilled, the well may be tested for purposes of determining the reservoir productivity and other properties of the subterranean formation to assist in decision making for field development.', 'The testing of the well provides such information as the formation pressure and its gradient; the average formation permeability and/or mobility; the average reservoir productivity; the permeability/mobility and reservoir productivity values at specific locations in the formation; the formation damage assessment near the wellbore; the existence or absence of a reservoir boundary; and the flow geometry and shape of the reservoir.', 'Additionally, the testing may be used to collect representative fluid samples at one or more locations.', 'Various testing tools may be used to obtain the information listed above.', 'One such tool is a wireline tester, a tool that withdraws a small amount of the formation fluid and may be desirable in view of environmental or tool constraints.', 'The wireline tester, however, produces results in a relatively shallow investigation radius; and the small quantity of the produced fluid sometimes is not enough to clean up the mud filtrate near the wellbore, leading to unrepresentative samples being captured in the test.', 'Due to the limited capability of the wireline tester, testing may be performed using a drill string that receives well fluid.', 'As compared to the wireline tester, the drill string allows a larger quantity of formation fluid to be produced in the test, which, in turn, leads to larger investigation radius, a better quality fluid sample and a more robust permeability estimate.', 'In general, tests that use a drill string may be divided into two categories: 1) Tests that produce and flow formation fluid to the surface (“drill stem tests” or DSTs); and 2) Tests that produce formation fluid and flow the formation fluid into an inner chamber of the drill string (sometimes referred to as “closed chamber tests” (CCTs) or “surge tests”).', 'For a conventional DST, production from the formation may continue as long as desired since the hydrocarbon that is being produced to the surface may be flared via a dedicated processing system.', 'The production of this volume of fluid ensures that a clean hydrocarbon is acquired at the surface and allows for a relatively large radius of investigation.', 'While providing relatively reliable results, the DST, however, may have the undesirable characteristic of using extensive surface equipment to handle the produced hydrocarbons, which, in many situations, poses an environmental handling hazard and involves additional safety precautions.', 'In contrast to the DST, the CCT is more environmentally friendly and does not require expensive surface equipment because the well fluid is communicated into an inner chamber (sometimes referred to as a “surge chamber”) of the drill string instead of being communicated to the surface of the well.', 'However, due to the downhole confinement of the fluid that is produced in a CCT, a relatively smaller quantity of fluid is produced in a CCT than in a DST.', 'Therefore, the small produced fluid volume in a CCT may lead to less satisfactory wellbore cleanup.', 'Additionally, the mixture of completion, cushion, and formation fluids inside the wellbore and the surge chamber may deteriorate the quality of any collected fluid samples.', 'Furthermore, in the initial part of the CCT, a high speed flow of formation fluid (called a “surge flow”) enters the surge chamber.', 'The pressure signal (obtained via a chamber-disposed pressure sensor) that is generated by the surge flow may be quite noisy, thereby affecting the accuracy of the formation parameters that are estimated from the pressure signal.', 'For reservoirs with weak pressure, the upper end of the surge chamber may be open to production facilities or temporary processing systems during the test.', 'This type of test is called a “slug test”.', 'When the wellbore liquid column, or the “slug”, reaches the surface, the slug test terminates and a conventional DST starts.', 'A slug test has the similar characteristics of a surge flow as a CCT, so it shares the similar issues in its data interpretation.', 'Many other operations, such as under-balanced perforating using a wireline conveyed gun, may also lead to similar issues when analyzing the measured data.', 'The primary feature of these tests is the variation of skin effect factor due to continuously increasing damage from incompatible fluid injection or continuously decreasing of skin factor from clean-up.', 'The variation of skin effect factor may be compounded with variable flow rate, making the problem more challenging.', 'The data that is obtained from a CCT, slug test, or other tests with surge flow, may be relatively difficult to interpret due to complicated wellbore dynamics and other effects.', 'Thus, there exists a continuing need for better ways to interpret test results that are obtained from these tests.', 'SUMMARY\n \nIn some embodiments, an apparatus for performing a well test operation includes a closed chamber testing system having a downhole flow control device.', 'In some embodiments, a method of performing a well test operation includes performing a well test operation with a closed chamber testing system having a downhole flow control device and estimating the reservoir properties based on pressure and flow data measured during the well test operation.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nSo that the manner in which the above recited features can be understood in detail, a more particular description may be had by reference to embodiments, some of which are illustrated in the appended drawings, wherein like reference numerals denote like elements.', 'It should be understood, however, that the appended drawings illustrate various embodiments and are therefore not to be considered limiting of its scope, and may admit to other equally effective embodiments.', 'FIG.', '1A\n schematically illustrates a closed chamber testing system before a bottom valve of the system is open and a closed chamber test begins, according to some embodiments of the disclosure.', 'FIG.', '1B\n schematically illustrates a closed chamber testing system after a bottom valve of the system is open during a closed chamber test and well fluid flows into a surge chamber of the system, according to some embodiments of the disclosure.', 'FIG.', '1C\n schematically illustrates a closed chamber testing system during a closed chamber test, according to some embodiments of the disclosure.', 'FIG.', '1D\n schematically illustrates a closed chamber testing system after a bottom valve of the system is closed during a closed chamber test, according to some embodiments of the disclosure.\n \nFIG.', '2\n is a flow diagram illustrating a method of interpreting well test data, according to some embodiments of the disclosure.', 'FIG.', '3\n is a flow diagram illustrating a method of interpreting well test data gathered while performing a closed chamber test while taking into account the multiple flow rate periods encountered during the testing operation, according to some embodiments of the disclosure.', 'FIG.', '4\n is a graph illustrating measured pressures and flow rates of formation fluid during a closed chamber test, according to some embodiments of the disclosure.', 'FIG.', '5\n schematically illustrates formation damage that may occur during drilling and methods of cleaning up formation damage during a closed chamber test, according to some embodiments of the disclosure.', 'While the foregoing is directed to embodiments described herein, other and further embodiments may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.', 'DETAILED DESCRIPTION', 'In the following description, numerous details are set forth to provide an understanding of the present disclosure.', 'It will be understood by those skilled in the art, however, that the embodiments of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.', 'In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”.', 'Further, the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”.', 'As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure.', 'Embodiments generally described herein include a closed chamber testing system having a downhole flow control device.', 'Referring to \nFIG.', '1A\n, a closed chamber testing (CCT) system \n10\n in accordance with an embodiment obtains more accurate bottom hole pressure and flow measurements, thereby leading to improved estimation of formation property parameters of a well \n8\n, which may be a subsea well or a non-subsea well.', 'The CCT system \n10\n may also offer an improvement over results obtained from wireline or other types of testing systems that have more limited radii of investigation.', 'For example, wireline testing systems may have a radius of investigation of around 10 feet or less, sometimes referred to as a microscale test.', 'Embodiments described herein, however, may have a radius of investigation of 100 feet or less, sometimes referred to as micro to macroscale.', 'Some embodiments described herein may have a radius of investigation of 1,000 feet or less, sometimes referred to as macroscale.', 'In accordance with some embodiments, the CCT system \n10\n is part of a tubular string \n14\n, such as, for example, a drill string, which extends inside a wellbore \n12\n of the well \n8\n.', 'The tubular string \n14\n may be a tubing string other than a drill string, in other embodiments.', 'The wellbore \n12\n may be cased or uncased.', 'The CCT system \n10\n includes a surge chamber \n60\n, an upper valve \n70\n, a bottom valve \n50\n, and a flow control device \n40\n.', 'The upper valve \n70\n controls fluid communication between the surge chamber \n60\n and the central fluid passageway of the drill string \n14\n above the surge chamber \n60\n.', 'The bottom valve \n50\n controls fluid communication between the surge chamber \n60\n and the formation \n20\n.', 'When the bottom valve \n50\n is closed, the surge chamber \n60\n is closed, or isolated, from the well \n8\n and formation \n20\n.', 'The flow control device \n40\n regulates the fluid flow rate within the CCT system \n10\n.', 'The flow control device \n40\n may be located above or below the lower isolation valve \n50\n within the well test system \n10\n that controls flow rate of fluid from the formation \n20\n and into a surge chamber \n60\n.', 'In some embodiments, the downhole flow control device \n40\n may be a variable or non-variable choke.', 'Pressure measurement sensors \n80\n, \n90\n may be placed above and below the choke to estimate the flow rate through the choke based upon the pressure drop across the choke.', 'The pressure drop measurement may be obtained from either absolute pressure sensors placed above and below the choke, or from a differential pressure sensor which measures the pressure change across the choke.', 'In some embodiments, a separate flow measurement sensor may be placed either above or below the choke in the flow stream.', 'A variable choke may be a choke that has the ability to change the choke diameter.', 'In some embodiments, a variable choke may have a diameter that varies along a longitudinal axis travelling from a downstream end towards an upstream end of the choke device.', 'A variable choke may incorporate an automatic control system such as a PID, PI, PD, or I feedback control loop, such that the choke is automatically adjusted to maintain a constant or nearly constant flow rate without any manual intervention from the surface and based upon either a direct measurement of flow rate or by inferring the flow rate from the pressure drop across the choke.', 'Although the flow control device \n40\n may be located above or below the valve \n50\n, the subsequent description refers to a flow control device \n40\n located below the valve \n50\n.', 'FIG.', '1A\n depicts the CCT system \n10\n in its initial state prior to the CCT (herein called the “testing operation”).', 'In this initial state, both the upper \n70\n and bottom \n50\n valves are closed.', 'The upper valve \n70\n remains closed during the testing operation.', 'The CCT system \n10\n opens the bottom valve \n50\n to begin the testing operation and closes the bottom valve \n50\n at an optimal time to terminate the surge flow and isolate the surge chamber from the bottom hole wellbore.', 'As depicted in \nFIG.', '1A\n, in accordance with some embodiments of the disclosure, prior to the testing operation, the surge chamber \n60\n may include a liquid cushion layer \n64\n that partially fills the chamber \n60\n to leave an empty region \n62\n inside the chamber \n60\n.', 'It is noted that the region \n62\n may be filled with a gas (a gas at atmospheric pressure, for example) in the initial state of the CCT system \n10\n prior to the testing operation, in accordance with some embodiments of the disclosure.', 'In such embodiments, the region \n62\n may also be referred to as the gas column \n62\n.', 'The CCT system \n10\n measures at least one downhole parameter that is responsive to the flow of well fluid into the surge chamber \n60\n during the testing operation.', 'One or more sensors may be installed inside the surge chamber \n60\n above the valve \n50\n, above the surge chamber in the tubing \n14\n, or below the valve \n50\n.', 'As a more specific example, the CCT system \n10\n may include an upper gauge, or sensor \n80\n, that is located inside and near the top of the surge chamber \n60\n to measure a parameter inside the chamber \n60\n.', 'In accordance with some embodiments of the disclosure, the upper sensor \n80\n may be a pressure sensor to measure a chamber pressure.', 'The sensor \n80\n is not limited to being a pressure sensor, however, as the sensor \n80\n may be one of a variety of other non-pressure sensors, such as temperature or other types of sensors.', 'The CCT system \n10\n may include at least one additional and/or different sensor than the upper sensor \n80\n, in some embodiments of the disclosure.', 'For example, in some embodiments of the disclosure, the CCT system \n10\n includes a lower gauge, or sensor \n90\n, which is located below the bottom valve \n50\n (and outside of the surge chamber \n60\n) to sense a parameter upstream of the bottom valve \n50\n.', 'More specifically, in accordance with some embodiments of the disclosure, the lower sensor \n90\n is located inside an interior space \n44\n of the string \n14\n, a space that exists between the bottom valve \n50\n and radial ports \n30\n that communicate well fluid from the formation to the surge chamber \n60\n during the testing operation.', 'The sensor \n90\n is not restricted to interior space \n44\n, as it could be anywhere below valve \n50\n in the various embodiments of the disclosure.', 'In some embodiments of the disclosure, the lower sensor \n90\n is a pressure sensor that provides an indication of a bottom hole pressure.', 'The upper \n80\n and/or lower \n90\n sensor may be used either individually or simultaneously for purposes of monitoring a dynamic fluid flow condition inside the wellbore.', 'More specifically, in accordance with some embodiments of the disclosure, the CCT system \n10\n includes electronics that receive indications of measured parameter(s) from the upper \n80\n and/or lower \n90\n sensor.', 'As a more specific example, for embodiments of the disclosure in which the upper \n80\n and lower \n90\n sensors are pressure sensors, the electronics \n16\n monitors at least one of the chamber pressure and the bottom hole pressure to recognize the optimal time to close the bottom valve \n50\n.', 'Thus, in accordance with the some embodiments of the disclosure, the electronics \n16\n may include control circuitry to actuate the bottom valve \n50\n to close the valve \n50\n at a time that is indicated by the bottom hole pressure or chamber pressure exhibiting a predetermined characteristic.', 'In some embodiments of the disclosure, the electronics \n16\n may include telemetry circuitry for purposes of communicating indications of the chamber pressure and/or bottom hole pressure to the surface of the well so that a human operator or a computer may monitor the measured parameter(s) and communicate with the electronics \n16\n to close the bottom valve \n50\n at the appropriate time.', 'The chamber pressure and/or bottom hole pressure may be logged by the CCT system \n10\n (via a signal that is provided by the sensor \n80\n and/or \n90\n) during the CCT testing operation for purposes of allowing formation properties to be extracted from the CCT.', 'Among the other features of the CCT system \n10\n, the CCT system \n10\n includes a packer \n15\n to form an annular seal between the exterior surface of the string \n14\n and the wellbore wall.', 'When the packer \n15\n is set, a sealed testing region \n24\n is formed below the packer \n15\n.', 'When the bottom valve \n50\n opens to begin the testing operation, well fluid flows into the radial ports \n30\n, through the downhole fluid flow control device \n40\n, through the bottom valve \n50\n, and into the chamber \n60\n as depicted in \nFIG.', '1B\n.', 'As also depicted in \nFIGS.', '1A-1D\n, in accordance with some embodiments of the disclosure, the CCT system \n10\n may include a perforation gun \n34\n and another surge apparatus that is sealed off from the well during the initial deployment of the CCT system \n10\n.', 'Prior to the beginning of the testing operation, perforating charges may be fired or another technique may be employed to establish communication of fluid flow between formation \n20\n and a wellbore \n12\n for purposes of allowing fluid to flow into the gun \n34\n and surge apparatus.', 'This inflow of fluid into the surge apparatus prior to the testing operation permits better perforation and clean up.', 'The surge apparatus may be a waste chamber that, in general, may be opened at any time to collect debris, mud filtrate or non-formation fluids (as examples) to improve the quality of fluid that enters the surge chamber \n60\n.', 'In other embodiments of the disclosure, the surge apparatus may include a chamber and a chamber communication device to control when fluid may enter the chamber.', 'More specifically, the opening of fluid communication between the chamber of the surge apparatus and the region \n24\n may be timed to occur simultaneously with a local imbalance to create a rapid flow into the chamber.', 'The local imbalance may be caused by the firing of one or more shaped charges of the perforation gun \n34\n, as further described in U.S. Pat.', 'No. 6,598,682 entitled, “RESERVOIR COMMUNICATION WITH A WELLBORE,” which issued on Jul. 29, 2003.', 'FIGS.', '1B and 1C\n depict the CCT system \n10\n during the CCT testing operation when the bottom valve \n50\n is open.', 'As shown, well fluid flows through the radial ports \n30\n, through the flow control device \n40\n, through the bottom valve \n50\n, and into the surge chamber \n60\n, thereby resulting in a flow \n96\n from the formation.', 'As the well fluid accumulates in the surge chamber \n60\n, a column height \n95\n of the fluid rises inside the chamber \n60\n.', 'Measurements from one or both of the sensors \n80\n and \n90\n may be monitored during the testing operation.', 'At an optimal time indicated by one or more downhole measurements, the bottom valve \n50\n closes to end the fluid flow into the surge chamber \n60\n.', 'After the surge flow ends, the sensor \n90\n below the bottom valve \n50\n continues to log wellbore pressure until an equilibrium condition is reached between the formation and the wellbore, or, a sufficient measurement time is reached.', 'The data measured by sensor \n90\n contains less noise because the choke \n40\n controls the fluid flow into the surge chamber \n60\n, yielding a better estimation of formation properties.', 'The CCT system \n10\n may be used in connection with a method \n300\n that is generally depicted in \nFIG.', '3\n, which is discussed in more detail below.', 'After the surge chamber \n60\n is closed by closing valve \n50\n as shown in \nFIG.', '1D\n, the bottom hole pressure continues to be logged.', 'In some embodiments of the disclosure, the upper \n80\n and lower \n90\n sensors may be pressure sensors to provide indications of the chamber pressure and bottom hole pressure, respectively.', 'For these embodiments of the disclosure, \nFIG.', '4\n depicts waveforms \n120\n and \n130\n for the flow rate and bottom hole pressure, respectively, which generally illustrate, by example, the formation fluid flow rates into the bottom hole and the bottom hole pressure during a CCT testing operation.', 'Referring to \nFIG.', '4\n, soon after the bottom valve \n50\n is open at time T\n0 \nto begin the testing operation, the bottom hole pressure waveform \n130\n decreases rapidly to a minimum pressure while the flow rate waveform \n120\n increases rapidly to a maximum flow rate.', 'Because as formation fluid flows into the surge chamber \n60\n the liquid column inside the chamber \n60\n rises, the bottom hole pressure increases due to the increasing hydrostatic pressure at the location of the lower sensor \n90\n.', 'Therefore, as depicted in \nFIG.', '4\n, the bottom hole pressure waveform \n130\n includes a segment \n130\na \nduring which the bottom hole pressure rapidly decreases at time T\n0\n, increases from approximately time T\n0 \nto time T\n1 \ndue to the increasing hydrostatic pressure, and is relatively stable from time T\n1 \nto time T\n2\n.', 'In addition to the hydrostatic pressure effect, other factors also have influences on the bottom hole pressure, such as wellbore friction, inertial effects due to the acceleration of fluid, etc.', 'One of the influences on the bottom hole pressure originates with the chamber pressure that is communicated to the bottom hole pressure through the liquid column inside the surge chamber \n60\n.', 'The chamber pressure gradually increases during the initial testing period from time T\n0 \nto time T\n1\n.', 'The gradual increase in the chamber pressure during this period is due to liquid moving into the surge chamber \n60\n, leading to the continuous shrinkage of the gas column \n62\n (see \nFIG.', '1D\n).', 'The magnitude of the chamber pressure increase is approximately proportional to the reduction of the gas column volume based on the equation of state for the gas.', 'However, as the testing operation progresses, the gas column \n62\n shrinks to such an extent that no more appreciable volume reduction of the column \n62\n is available to accommodate the incoming formation fluid.', 'The chamber pressure then experiences a dramatic growth (beginning at T\n2\n) since formation pressure starts to be passed onto the chamber pressure via the liquid column.', 'The chamber pressure continuously changes during the testing operation because the gas chamber volume is constantly reduced, although with a much slower pace after the gas column can no longer be appreciably compressed.', 'Thus, as shown in \nFIG.', '4\n, after time T\n2\n, as illustrated by the segment \n130\nb\n, the bottom hole pressure waveform \n130\n first increases sharply and then increases at a much slower pace.', 'Solution gas that was previously released from the liquid column may possibly re-dissolve back into the liquid, depending on the pressure difference between the chamber pressure and the bubble point of produced liquid hydrocarbon.', 'In accordance with some embodiments of the disclosure, the electronics \n16\n may measure the bottom hole pressure (via the lower sensor \n90\n) to detect when the bottom hole pressure increases past a predetermined pressure threshold.', 'Thus, the electronics \n16\n may, during the testing operation, continually monitor the bottom hole pressure and close the bottom valve \n50\n to shut-in, or isolate, the surge chamber \n60\n from the formation in response to the bottom hole pressure exceeding the predetermined pressure threshold.', 'In some embodiments of the disclosure, the electronics \n16\n may monitor the pressure above and below the flow control device \n40\n to determine flow rate of formation fluid through the flow control device \n40\n and into the surge chamber \n60\n.', 'Further embodiments may include a telemetry system in the test string, such as that using electrical cable, fiber optic, wireless acoustic, or wireless electromagnetic telemetry principles, to deliver measured pressure, flow, or choke status information to the surface in real time, or near real time, or to control the choke or the lower valve directly from the surface. \nFIG.', '2\n illustrates a general overview of some methods according to embodiments described herein that may be used to gather, model, analyze, and interpret the data measured during a testing operation using a CCT system along with other types data to determine a final reservoir model and determine formation properties.', 'More specifically, \nFIG.', '2\n is a diagram \n200\n that generally represents a procedure for collecting pressure and rate data from a well with a data acquisition system (box \n202\n) and using it to extract the values of reservoir parameters of interest.', 'Due to the non-linear nature of the physical processes (e.g., complex flow in the wellbore, complex rock-fluid interaction, and uncertainties about the reservoir geology), this can be an iterative procedure in which initial guesses at the parameter values are refined.', 'Various data can be processed (box \n204\n), such as pressure and rate data (which can be provided as log-log plots) so that the particular flow regime (linear, radial, bounded, wellbore storage dominated, etc.) can be identified (box \n206\n).', 'Once these are understood, parameters dominating the flow during each regime can be inferred and refined.', 'Use can be made of regression software to alter the parameter values to best fit the measured data (boxes \n208\n,\n210\n,\n212\n).', 'Methods to analyze and improve the estimation of the reservoir properties from a CCT, as described herein, may generally take into account three rate periods, as shown in \nFIG.', '4\n.', 'The rate periods may be used to classify the types of flow in order to apply the appropriate analysis model for determining formation properties.', 'Some of the rate periods that may result from the inclusion of a downhole choke in the test string include: 1) formation fluid surge (Q\nsurge \nin \nFIG.', '4\n) into the well and closed chamber test system immediately following either firing the perforating guns, or if the well is already perforated, by opening the bottom valve, 2) stabilized flow (Q\nstabil\n) through the downhole control device, and 3) a period of reducing flow (Q\nfalloff\n) as the back pressure in the chamber reduces the reservoir inflow, or due to a controlled increase in the restriction of a variable choke.', 'Following these three non-zero flow rate periods, the bottom valve \n50\n is closed which results in zero flow through the choke \n40\n while the pressure below the bottom valve \n50\n continues to build and approaches or attains the original reservoir pressure.', 'At the end of the third flow rate period, the bottom valve \n50\n can be closed by traditional means by manipulating applied hydraulic pressure in the annulus, by an automated downhole control algorithm, or by means of a telemetry command sent from the surface.', 'In some embodiments, the stabilized flow period may not be present depending upon the well and reservoir properties.', 'Regardless of the number of rate periods observed during a test operation, the method illustrated in \nFIG.', '3\n is applied to the pressure and flow rate data gathered during the test operation to determine formation properties.', 'In some embodiments, an iterative calculation of the flow rate in periods 1) and 3) may be performed based upon initial estimates of the reservoir model parameters and from pressure measurement data taken during the stabilized flow period 2).', 'Generally, the first flow period may be deemed a well “clean up” period in which reservoir fluid flushes out the debris, etc. that remains in the well following drilling.', 'The equations of state used to more accurately model the fluid flow during the clean up period are generally complex.', 'The second flow period may be deemed a stabilization flow enabling use of more simple equations to accurately model the system.', 'The third flow period may be deemed a boundary condition period as the pressure in the surge chamber \n60\n builds, compressing the gas column \n62\n above the fluid, and also using complex equations to model, but generally different equations and assumptions from those used to model flow during the first flow period.', 'Incorporating the flow control device \n40\n in the CCT system \n10\n and determining the flow rate through the flow control device \n40\n enables operators to more accurately determine which flow period the measured data comes from and thereby apply the appropriate equations to data gathered from any of the three possible flow periods.', 'Additionally, during the drilling there is invasion of the mud (internal and external mud cake) that prevents flow back of the formation fluid into the well.', 'During the perforation and testing operation, that material and other debris is flushed out of the reservoir.', 'This “clean up” process may be modeled with the flow rate data gathered during the testing operation.', 'Thus, determining the flow rates during the testing operation and modeling the clean up of a well during surge and stabilization flow periods may provide the ability to estimate the optimum time to open sample bottles and sample “clean” oil, free of any downhole debris remaining in the well after drilling.', 'Some of the aspects are discussed in more detail below.', 'FIG.', '3\n illustrates a method \n300\n of performing an iterative calculation in order to estimate the reservoir properties while taking into account the multiple flow rate periods encountered during the testing operation previously described.', 'The initial rate estimates are calculated from the pressure differentials across the downhole flow control device and/or from a flow control device performance curve, as shown in box \n302\n.', 'The final build up is analyzed to estimate the reservoir permeability and skin, as shown in box \n304\n.', 'The data for simulating the drilling induced damage in the near well bore region is assembled, as shown in box \n306\n.', 'FIG.', '5\n depicts a near well bore region by way of example.', 'As shown in this figure, the near well bore region includes a wellbore \n12\n in a reservoir \n140\n.', 'Drilling mud particulates are deposited on and in the wall of the wellbore \n12\n to form an external mud cake \n142\n and an internal mud cake \n144\n.', 'Drilling mud filtrate is also pushed into the reservoir \n140\n, forming an invaded zone \n146\n.', 'As will be appreciated, the invaded zone \n146\n can include a flushed zone \n148\n and a transition zone \n150\n.', 'Various parameters can be used to model the reservoir formation properties and the fluid flow during clean up of a well.', 'The data that may be assembled to determine drilling induced damage may include but are not limited to, for example, drilling logs, mud logs, mud properties such as solids and salinity, reservoir rock properties including permeability and skin, reservoir and well bore fluid properties, external and internal mud cake parameters, and well design.', 'Modeling of the cleanup of the well perforations during the test may be performed, as shown in box \n308\n.', 'The cleanup model input parameters are tuned to match the measured pressures, as shown in box \n310\n.', 'The cleanup model may be tuned, for example, by adjusting any of the following parameters alone or in combination: reservoir/rock properties, reservoir and well bore fluid properties, mud properties including solids, salinity, etc., and external and internal mud cake parameters.', 'A deconvolution process is performed to improve the sandface rate estimates, as shown in box \n312\n.', 'The deconvolution process may use the measured pressures and current estimates of reservoir permeability.', 'Boxes \n304\n through \n312\n are repeated as needed until the estimates of permeability and skin have converged, as shown in box \n314\n.', 'When a consistent build up analysis is achieved, the individual flow periods are analyzed, as shown in box \n316\n.', 'The results are then checked for consistency with a full test, as shown in box \n318\n.', 'The processes illustrated in \nFIG.', '2\n may be applied during the design or the execution of the testing operation with the CCT system \n10\n.', 'For example, during the design of the testing operation, the choice of sensor resolution will determine the maximum length of the final buildup.', 'Changes in pressure below the sensor resolution will not be visible to the test operation should not proceed beyond this time.', 'Maximizing the length of the buildup produces a better quality pressure response, i.e. the pressure response measured contains less noise.', 'The analysis algorithms allow estimation of maximum build up time for a given sensor resolution and reservoir properties.', 'Additionally, the final build up may be modeled and analyzed to estimate the reservoir permeability and skin prior to performing the actual test.', 'During the test design, software may predict the pressure response on a model of the reservoir, which data can then be used in a pre-test analysis to verify that the sensor resolution is sufficient for the designed test.', 'During execution of the testing operation, the evolution of the sandface skin may be used to indicate the earliest time that clean samples may expect to be taken.', 'For example, if an exponential falloff of skin is anticipated, this curve can be fitted parametrically with the skin values derived from performing boxes \n302\n through \n312\n to determine the time when the skin falls to an acceptable level or stabilizes.', 'Real time monitoring of the testing operation enables running the testing operation and reservoir estimation processes in real time.', 'Software connects to the real time system and displays the real time data alongside the designed tests.', 'The real time system may propose a previously designed test that closely matches the actual test data or an operator may manually select a previously designed test.', 'The operator decides if it is appropriate to alter the start of the final buildup time to match the buildup time used in the chosen test design.', 'In some embodiments, an inverse modeling of the reservoir parameters using a grid based parameter estimation inside a full earth model may be performed.', 'Additionally, pressure transient analysis or PTA may be performed but with embedded pressure-rate deconvolution.', 'The method may also include monitoring and modeling of clean-up of the near well region.', 'In situations where the test is being performed directly after perforating, the skin zone within and around the near wellbore region will change with time.', 'Modeling software has been created to couple the reservoir and wellbore flow, which software can be used in the Inverse Modeling procedure to estimate the final skin after clean up.', 'The method may also include deconvolution of the pressure-rate response prior to analysis.', 'This replaces the pressure response due to the observed multiple rates with the response due to a single effective rate.', 'Intelligent sensors and automated control software inside the downhole flow control device automatically close the isolation valve as the surge chamber begins to fill with reservoir fluid.', 'Commands may be transmitted electronically in real time to control the opening and closing of the flow control device and/or the isolation valve.', 'Additionally, pressure measurements may be transmitted in real time back to the surface for immediate analysis.', 'Incorporating a downhole flow control device within a closed chamber test permits measurement of downhole flow rates during an impulse test and estimation of flow rates from continuously monitored pressure measurements, decreases the amplitude of the uncontrolled surge of reservoir fluid into the wellbore at the start of the test compared to conventional CCTs while increasing the length of formation fluid flow and pressure build time, enabling more formation fluid data to be collected.', 'Increasing the length of the fluid flow and the buildup time also increases the radius of investigation of the determined reservoir properties which enhances the value of a CCT.', 'Embodiments described herein may also provide a sophisticated analysis procedure that accounts for the wellbore damage induced by the drilling that will affect the flow profiled during the testing operation.', 'The damage is estimated from data collected during the drilling operation.', 'The state of the near well bore is then used as the initial conditions for modeling the subsequent cleanup of the well and perforations during the analysis of the measured pressure data.', 'Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.'] | ['1.', 'A well-testing apparatus comprising:\na tubular member having a surge chamber;\na valve disposed in the tubular member to control fluid flow from a well into the surge chamber;\na flow control device disposed in the tubular member, wherein the flow control device includes a choke;\na pressure gauge disposed in the tubular member between the valve and the flow control device; and\na data acquisition system configured to calculate flow rates of the fluid from the well into the surge chamber during periods of surge flow, stabilized flow, and reducing flow into the surge chamber, such calculation including performing iterative calculations of flow rates of the fluid from the well into the surge chamber for the period of surge flow and for the period of reducing flow based on pressure measurement data acquired during the period of stabilized flow of the fluid from the well into the surge chamber.', '2.', 'The well-testing apparatus of claim 1, wherein the flow control device is positioned within the surge chamber.', '3.', 'The well-testing apparatus of claim 1, wherein the flow control device is positioned outside the surge chamber such that, during fluid flow from the well into the surge chamber, the fluid flows through the flow control device and then through the valve into the surge chamber.', '4.', 'The system of claim 1, comprising an additional valve at an opposite end of the surge chamber from the valve.', '5.', 'The well-testing apparatus of claim 1, wherein the choke includes a variable choke configured to be automatically adjusted to maintain a flow rate of fluid from the well into the surge chamber without manual intervention from the surface.', '6.', 'The well-testing apparatus of claim 1, wherein the pressure gauge is a first pressure gauge, and further comprising a second pressure gauge disposed in the surge chamber.', '7.', 'The well-testing apparatus of claim 6, wherein the flow control device is positioned between the first and second pressure gauges.\n\n\n\n\n\n\n8.', 'The system of claim 6, comprising electronics operable to monitor pressure sensed by at least one of the first and second pressure gauges and to actuate the valve in response to the monitored pressure.', '9.', 'A method comprising:\ninitiating a closed chamber test within a well using a downhole testing apparatus;\nrouting formation fluid into a surge chamber of the downhole testing apparatus, wherein routing the formation fluid into the surge chamber includes routing the formation fluid through a choke of the downhole testing apparatus; and\nmeasuring a flow rate of the formation fluid routed into the surge chamber, wherein measuring the flow rate of the formation fluid routed into the surge chamber includes calculating flow rates of the formation fluid routed into the surge chamber during periods of surge flow, stabilized flow, and reducing flow into the surge chamber, and calculating flow rates of the formation fluid routed into the surge chamber during the periods of surge flow and reducing flow includes performing iterative calculations of flow rates of the formation fluid routed into the surge chamber for the period of surge flow and for the period of reducing flow based on pressure measurement data acquired during the period of stabilized flow of the formation fluid into the surge chamber.', '10.', 'The method of claim 9, comprising controlling flow of the formation fluid into the surge chamber to lengthen a testing time of the closed chamber test and enhance a radius of investigation of the closed chamber test.', '11.', 'The method of claim 9, wherein initiating the closed chamber test includes opening an isolation valve to allow the formation fluid to enter the surge chamber.', '12.', 'The method of claim 9, wherein measuring the flow rate of the formation fluid through the choke includes using a pair of pressure sensors to measure a pressure drop across the choke.', '13.', 'The method of claim 9, comprising estimating reservoir properties based on pressure data and the measured flow rate of the formation fluid.', '14.', 'The method of claim 9, comprising estimating reservoir properties based on the calculated flow rates.', '15.', 'The method of claim 9, wherein calculating flow rates of the formation fluid during periods of surge flow, stabilized flow, and reducing flow includes:\ncalculating initial estimates of the flow rates for the periods;\nestimating reservoir permeability and skin;\nmodeling cleanup of well perforations; and\nimproving the accuracy of the initial estimates of the flow rates through deconvolution.', '16.', 'The method of claim 9, comprising controlling the flow rate of the formation fluid through the choke by adjusting the choke.', '17.', 'The method of claim 16, comprising automatically adjusting the choke to maintain the flow rate without manual intervention from the surface.', '18.', 'A well-testing apparatus comprising:\na tubular member having a surge chamber;\na valve disposed in the tubular member to control fluid flow from a well into the surge chamber;\na flow control device disposed in the tubular member; and\na pressure measurement sensor placed above the flow control device and another pressure measurement sensor placed below the flow control device, wherein the flow control device includes a feedback control loop to control flow through the flow control device based on pressure drop through the flow control device.', '19.', 'The well-testing apparatus of claim 18, wherein the flow control device comprises a variable choke.', '20.', 'The well-testing apparatus of claim 18, wherein the flow control device is operable to maintain nearly constant flow rate without manual intervention.'] | ['FIG.', '1A schematically illustrates a closed chamber testing system before a bottom valve of the system is open and a closed chamber test begins, according to some embodiments of the disclosure.', '; FIG.', '1B schematically illustrates a closed chamber testing system after a bottom valve of the system is open during a closed chamber test and well fluid flows into a surge chamber of the system, according to some embodiments of the disclosure.', '; FIG.', '1C schematically illustrates a closed chamber testing system during a closed chamber test, according to some embodiments of the disclosure.', '; FIG.', '1D schematically illustrates a closed chamber testing system after a bottom valve of the system is closed during a closed chamber test, according to some embodiments of the disclosure.', '; FIG.', '2 is a flow diagram illustrating a method of interpreting well test data, according to some embodiments of the disclosure.', '; FIG.', '3 is a flow diagram illustrating a method of interpreting well test data gathered while performing a closed chamber test while taking into account the multiple flow rate periods encountered during the testing operation, according to some embodiments of the disclosure.', '; FIG.', '4 is a graph illustrating measured pressures and flow rates of formation fluid during a closed chamber test, according to some embodiments of the disclosure.', '; FIG.', '5 schematically illustrates formation damage that may occur during drilling and methods of cleaning up formation damage during a closed chamber test, according to some embodiments of the disclosure.', '; FIG.', '1A depicts the CCT system 10 in its initial state prior to the CCT (herein called the “testing operation”).', 'In this initial state, both the upper 70 and bottom 50 valves are closed.', 'The upper valve 70 remains closed during the testing operation.', 'The CCT system 10 opens the bottom valve 50 to begin the testing operation and closes the bottom valve 50 at an optimal time to terminate the surge flow and isolate the surge chamber from the bottom hole wellbore.', 'As depicted in FIG.', '1A, in accordance with some embodiments of the disclosure, prior to the testing operation, the surge chamber 60 may include a liquid cushion layer 64 that partially fills the chamber 60 to leave an empty region 62 inside the chamber 60.', 'It is noted that the region 62 may be filled with a gas (a gas at atmospheric pressure, for example) in the initial state of the CCT system 10 prior to the testing operation, in accordance with some embodiments of the disclosure.', 'In such embodiments, the region 62 may also be referred to as the gas column 62.; FIGS.', '1B and 1C depict the CCT system 10 during the CCT testing operation when the bottom valve 50 is open.', 'As shown, well fluid flows through the radial ports 30, through the flow control device 40, through the bottom valve 50, and into the surge chamber 60, thereby resulting in a flow 96 from the formation.', 'As the well fluid accumulates in the surge chamber 60, a column height 95 of the fluid rises inside the chamber 60.', 'Measurements from one or both of the sensors 80 and 90 may be monitored during the testing operation.', 'At an optimal time indicated by one or more downhole measurements, the bottom valve 50 closes to end the fluid flow into the surge chamber 60.; FIG.', '3 illustrates a method 300 of performing an iterative calculation in order to estimate the reservoir properties while taking into account the multiple flow rate periods encountered during the testing operation previously described.', 'The initial rate estimates are calculated from the pressure differentials across the downhole flow control device and/or from a flow control device performance curve, as shown in box 302.', 'The final build up is analyzed to estimate the reservoir permeability and skin, as shown in box 304.', 'The data for simulating the drilling induced damage in the near well bore region is assembled, as shown in box 306.', 'FIG.', '5 depicts a near well bore region by way of example.', 'As shown in this figure, the near well bore region includes a wellbore 12 in a reservoir 140.', 'Drilling mud particulates are deposited on and in the wall of the wellbore 12 to form an external mud cake 142 and an internal mud cake 144.', 'Drilling mud filtrate is also pushed into the reservoir 140, forming an invaded zone 146.', 'As will be appreciated, the invaded zone 146 can include a flushed zone 148 and a transition zone 150.', 'Various parameters can be used to model the reservoir formation properties and the fluid flow during clean up of a well.', 'The data that may be assembled to determine drilling induced damage may include but are not limited to, for example, drilling logs, mud logs, mud properties such as solids and salinity, reservoir rock properties including permeability and skin, reservoir and well bore fluid properties, external and internal mud cake parameters, and well design.'] |
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US11149519 | Smart filtrate for strengthening formations | Mar 30, 2015 | Guido De Stefano, James Friedheim, Steven Young | SCHLUMBERGER TECHNOLOGY CORPORATION | De Loos et al., Tripodal Tris-Urea Derivatives as Gelators for Organic Solvents, Eur. J. Org. 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20120000652; January 5, 2012; Jones; 20120216990; August 30, 2012; Quintero et al.; 20130133888; May 30, 2013; Ballard; 20130213838; August 22, 2013; Keller et al.; 20130233623; September 12, 2013; Aston et al.; 20140290954; October 2, 2014; Mettath; 20140305646; October 16, 2014; Chew et al.; 20140352967; December 4, 2014; Burns et al.; 20150168597; June 18, 2015; Bai; 20150315894; November 5, 2015; Guo; 20170015887; January 19, 2017; De Stefano et al.; 20170029688; February 2, 2017; De Stefano et al. | Foreign Citations not found. | No images available | ['A method of sealing a formation that includes drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising a first sealing component into the wellbore, wherein the non-aqueous based wellbore fluid filters into the formation as a filtrate and substantially thickens is disclosed.', 'The substantially thickening may result from adding a second sealing component to the wellbore fluid, whereby the first sealing component initiates a reaction of the second sealing component.'] | ['Description\n\n\n\n\n\n\nRELATED APPLICATION', 'This application is a National Stage application of International Application No.', 'PCT/US2015/023274 filed Mar. 30, 2015, which claims priority to and the benefit of U.S. Provisional Patent Application having Ser.', 'No. 61/972,871, filed 31 Mar. 2014; U.S. Provisional Patent Application having Ser.', 'No. 61/972,755, filed 31 Mar. 2014; and U.S. Provisional Patent Application having Ser.', 'No. 61/972,805, filed 31 Mar. 2014, which are all incorporated by reference in their entirety.', 'BACKGROUND\n \nDuring the drilling or completion of an oil and gas well, the walls of oil and gas formations are often exposed to wellbore fluids which may damage producing formations.', 'To prevent such damage, a wellbore often requires the deposit of a low-permeability filtercake on the walls of the wellbore to seal the permeable formation exposed by the drilling operation.', 'The filtercake functions to limit drilling fluid losses from the wellbore as well as protect the formation from possible damage by the fluids filtering into the walls of the wellbore.', 'Solids, such as particulate fines, suspended in the drilling fluid may also contribute to damaging hydrocarbon producing formations.', 'To protect formations from damaging fluids and solids, a filtercake may be formed and/or deposited on the surface of the subterranean formation.', 'Filtercakes are typically formed when particles suspended in a wellbore fluid coat and plug the pores in the subterranean formation such that the filtercake prevents or reduces both the loss of fluids into the formation and the influx of fluids present in the formation.', 'A number of ways of forming filtercakes are known in the art, including the use of bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates.', 'SUMMARY\n \nIn one aspect, embodiments disclosed herein relate to a method of sealing a formation that includes drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising a first sealing component into the wellbore, the non-aqueous based wellbore fluid filters into the formation as a filtrate and substantially thickens.', 'In another aspect, embodiments disclosed herein relate to compositions including a non-aqueous base fluid and an encapsulated sealing component comprising a sealing component encapsulated by an encapsulant, wherein the sealing component is selected from the group consisting of peroxide, modified persulfate, metallocene, dispersed silicon carbide, or dispersed carbonaceous material chosen from the group including: graphite, graphene, graphene oxide, glassy carbon, carbon nanofoam, buckminsterfullerene, buckypaper, nanofiber, nanoplatelets, nano-onions, nanoribbons, nanohorns, single- or multi-walled carbon nanotubes, carbon black, carbon nanotubes, and combinations thereof.', 'In another aspect, embodiments disclosed herein relate to a filtrate including a base fluid, a first sealing component comprising a thixotropic fluid, and a second sealing component.', 'Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.', 'DETAILED DESCRIPTION\n \nGenerally, embodiments disclosed herein relate to methods for chemically sealing the near-wellbore region within a formation containing a filtrate.', 'More specifically, embodiments disclosed herein utilize a fluid that filters into a formation to form a filtercake on the walls of the wellbore, with the filtrate filtering a depth into the formation.', 'One or more embodiments of such fluid filtrate may include a non-aqueous based wellbore fluid and a multi-component system for the selective reaction of the components within the filtrate to affect the formation of a chemical seal within the near-wellbore formation region containing the filtrate while drilling in a wellbore.', 'One or more other embodiments of such fluid filtrate may include a non-aqueous based wellbore fluid and a thixotropic component that may be liquid under moving conditions, but solid in static conditions, such as in the near-wellbore region of the formation.\n \nEmbodiments of the present disclosure may be particularly suitable for drilling through depleted sandstone formations, as well as other depleted formation types.', 'Depleted formations pose numerous technical challenges, including wellbore instability, severe lost circulation, etc., which generally make further development uneconomical.', 'Uncontrollable drilling fluid losses frequently are unavoidable in the often large fracture characteristics of these formations.', 'While conventional wellbore strengthening techniques often involve the use of particulates to create a hoop stress and thus increase the strength of the formation through formation of a stress cage, such techniques involve the formation of new fractures, which may be undesirable for a depleted formation.', 'Thus, embodiments of the present disclosure seek to strengthen the formation through the formation of a chemical sealing layer in the near-wellbore formation region containing the filtrate.', 'Thus, the embodiments may be distinguished from conventional methods strengthening a wellbore in that the chemical sealing layer provides greater strength and stability to the near-wellbore formation region containing the filtrate as compared to the filter cake provided by the components of the drilling fluid from simple drilling fluid leak-off.', 'Conventionally, a filter cake including polymeric and solid components is used within a wellbore to bridge pore throats and/or provide filtration reduction, however, the present embodiments are directed to providing components within the filtrate in which a chemical reaction, such as polymerization or crosslinking, or viscosity change occurs in situ to change the chemical nature of the near-wellbore formation region containing the filtrate.', 'Further, in one or more embodiments, in situ refers to simultaneous with or following the filtration of the drilling fluid into the drilled formation.', 'The chemical reaction of the fluid components may be selectively activated to prevent or at least reduce premature reaction within the drill string and also achieve reaction in the near-bit area, when desired.', 'Thus, to achieve such selective activation, in one or more embodiments multiple components may be incorporated into the wellbore fluid(s).', 'To avoid or reduce premature reaction, one of the components may be encapsulated or otherwise rendered chemically non-reactive.', 'Upon activation and exposure to a second sealing component, with which the first sealing component is reactive, the two (or more) components may react and change the chemical nature of the formation region containing the filtrate and form a chemical sealing layer behind the filter cake.', 'In one or more embodiments, a first sealing component is included in a non-aqueous wellbore fluid.', 'The first sealing component may filter into the formation with the fluid filtrate during the drilling process and formation of a filter cake on the walls of the wellbore.', 'In one embodiment, the first sealing component is a thixotropic component that transitions from liquid to substantially solid upon reducing movement (once filtered into the formation), thereby forming a sealing layer in the formation behind the filter cake.', 'In other embodiments, the first sealing component acts in conjunction with a second sealing component which may be encapsulated or otherwise inactive and subsequently activated such that the first and second sealing components will react to form a chemical sealing layer behind the filter cake.', 'As mentioned, a second sealing component may optionally be used to trigger reaction with the first sealing component to form a chemical sealing layer.', 'The second sealing component may be optionally encapsulated within a material composition that effectively limits the interaction of the first sealing component with the other components of the non-aqueous based wellbore fluid or be otherwise inactivated.', 'While encapsulated, the second sealing component remains dormant; however, as will be discussed in more detail below, the material composition making up the encapsulant may be engineered to release the second sealing component within the filtrate.', 'Further, in some embodiments the second sealing component may be incorporated with the fluid in which the first sealing component is pumped or may be subsequently pumped into the wellbore, such as upon experience of drill fluid losses, or when an operator otherwise deems it necessary to affect the formation of a chemical sealing layer in the currently drilled region of the formation.', 'For example, the addition of the second sealing component to the circulating wellbore fluid in an on-demand fashion may be beneficial if a fluid loss is registered via pressure change during drilling.', 'Once fluid loss is registered, the second sealing component may be added and/or emulsified into the wellbore fluid and, once in combination with the first sealing component already present in the filtrate, affect the formation of a chemical sealing layer in the problematic portion of the freshly cut formation containing the filtrate.', 'In one or more other embodiments, as a preventative measure against fluid loss the first and second sealing components may be directly combined together in the non-aqueous based wellbore fluid and used during the wellbore operation before a fluid loss event is registered.', 'In one or more embodiments, the second sealing component is encapsulated within a material composition to form encapsulated particles.', 'In one embodiment, the encapsulating composition may be thick and strong enough not to break/fragment by the shear forces or the pressure drop at the bit upon its injection from the drill string along with the wellbore fluid.', 'However in other embodiments, depending on the composition of the selected encapsulant, the release of the second sealing component may be based upon the shear forces generated at the bit.', 'Such mechanisms may be used where the reaction between the first and second sealing components is sufficiently delayed that the fluid is able to filter into the formation as a filtrate before substantial levels of reaction have occurred.', 'In still other embodiments, the encapsulant may release the second sealing component in response to an external stimulus or triggering event, which may include temperature, pH, enzymatic degradation, oxidants, solvents, or physical disruption, such as by grinding the encapsulant particles.', 'It is also envisioned that encapsulants susceptible to triggered release may also be used in conjunction with passive diffusion encapsulants, and combined with any of the strategies disclosed above.', 'The shear forces generated by the passage of the wellbore fluid through a restriction, e.g. a perforation or a drill bit may be sufficient to release the encapsulated first sealing component.', 'Without being bound by any theory, the inventors believe that the combination of shear and elongational flow experienced in these conditions may produce enough stress to break the encapsulant.', 'Basically, the stress might first come from the turbulence experienced in the pumps of surface equipment and within the wellbore fluid itself; after that, the passage of the flow through a restriction creates first some sort of “Venturi effect” with an acceleration of the wellbore fluid which may have the effect of deforming the encapsulant and then at the outlet of the restriction another deformation of the encapsulant coming from the wellbore fluid deceleration.', 'Velocity increases and decreases are of the order of 50 to 100 times variation.', 'Strain rates experienced in restriction are from 1000 to one million reciprocal second, more specifically 10000 to 200000 reciprocal second.', 'The inventors have noticed that even if the stress experienced during pumping and along the transportation has an effect on the breakage of the encapsulant, the stress and/or velocity difference which is obtained due to the flow through a restriction may be of paramount importance.', 'The stress is closely related to the pressure drop encompassed in each unit of the well treatment (pumps, pipes, drill-bit).', 'A higher pressure drop corresponds to a higher stress applied.', 'The highest stress is observed when the fluid passes through the nozzles in a drill bit or a port of the completion string downhole.', 'By stress sufficient to break the encapsulant, it is to be under stood in the context of the present disclosure that said sufficient stress is produced by the passage through the nozzles of the drill bit or similar restriction to allow the second sealing component to be released from the encapsulant.', 'The pressure drop observed when passing through the nozzles is from about 150 to 5000 psi (10 to 345 bar), more specifically from 300 to 5000 psi (20 to 345 bar), most specifically from 300 to 1000 psi (20 to 69 bar).', 'As shown earlier, the stress may sometimes also be referred to as a velocity difference.', 'In still other embodiments, the encapsulant may release the second sealing component in response to an external stimulus or triggering event, which may include temperature, pH, enzymatic degradation, oxidants, solvents, or physical disruption, such as by grinding the encapsulant particles.', 'It is also envisioned that encapsulants susceptible to triggered release may also be used in conjunction with passive diffusion encapsulants, and combined with any of the strategies disclosed above.', 'The encapsulation material may be a heat-activated material that remains intact prior to exposure to elevated temperatures, such as those present in a downhole environment, and upon heating, slowly melt and release the molecules or ions contained within.', 'In some embodiments, the coating may melt at a temperature greater than 125° F. (52° C.).', 'Examples of such materials are vegetable fat, gelatin, and vegetable gums, and hydrogenated vegetable oil.', 'Other coatings may include materials selected from lipid materials such as, but not limited to, mono-, di-, and tri-glycerides, waxes, and organic and esters derived from animals, vegetables, minerals, and modifications.', 'Examples include glyceryl triestearates such as soybean oil, cottonseed oil, canola oil, carnuba wax, beeswax, bran wax, tallow, and palm kernel oil.', 'Heat-activated materials may also include those disclosed in U.S. Pat. No. 6,312,741, which is incorporated herein by reference in its entirety.', 'In a particular embodiment, the encapsulating material may include enteric polymers, which are defined for the purposes of the present disclosure, as polymers whose solubility characteristics are pH dependent.', 'Here, this means that salt release is promoted by a change from conditions of a first predetermined pH value to a second predetermined pH condition.', 'Enteric polymers are commonly used in the pharmaceutical industry for the controlled release of drugs and other pharmaceutical agents over time.', 'The use of enteric polymers allows for the controlled release of the monovalent or polyvalent salt under predetermined conditions of pH, or a combination of pH and temperature.', 'For example, the Glascol family of polymers are acrylic based polymers (available form Ciba Specialty Chemicals) are considered suitable enteric polymers for the present disclosure because the solubility depends upon the pH of the solution.', 'In an illustrative embodiment of the present disclosure, an enteric polymer may be selected as an encapsulating material that is substantially insoluble at pH values greater than about 7.5 and that is more soluble under conditions of decreasing pH.\n \nEncapsulating materials may also include enzymatically degradable polymers and polysaccharides such as galactomannan gums, glucans, guars, derivatized guars, starch, derivatized starch, hydroxyethyl cellulose, carboxymethyl cellulose, xanthan, cellulose, and cellulose derivatives.', 'Enzymatically degradable polymers may include glycosidic linkages that are susceptible to degradation by natural polymer degrading enzymes, which may be selected from, for example, carbohydrases, amylases, pullulanases, and cellulases.', 'In other embodiments, the enzyme may be selected from endo-amylase, exo-amylase, isoamylase, glucosidase, amylo-glucosidase, malto-hydrolase, maltosidase, isomalto-hydrolase or malto-hexaosidase.', 'One skilled in the art would appreciate that selection of an enzyme may depend on various factors such as the type of polymeric additive used in the wellbore fluid being degraded, the temperature of the wellbore, and the pH of wellbore fluid.', 'Additionally, the mean diameter of each encapsulated particle should be large enough to assure that it may be effectively retained in the filter cake.', 'In one or more embodiments, the particles formed by encapsulating the first sealing component have a mean diameter of greater than about 20 to 30 micron.', 'However, in other embodiments, the mean diameter of each encapsulated particle may be less than about 20 micron so that the particles may pass through the filtercake and be retained in the filtrate contained in the near-wellbore region of the formation.', 'In one or more embodiments, the material composition of the encapsulant comprises at least one dissolvable material, which may be a material that slowly dissolves in the non-aqueous based drilling fluid.', 'In one or more embodiments, the dissolvable material is a high temperature wax such as carnauba wax or a polyalkyleneglycol such as polyethylene glycol.', 'Carnauba wax is one of the hardest waxes, possessing a high melting point (˜170° F.) and is substantially insoluble in water and most other solvents.', 'However, under downhole conditions and in the presence of a non-aqueous wellbore fluid, over time carnauba wax may dissolve in the non-aqueous based wellbore fluid and release the second sealing component within the filtrate or in/near the filter cake.', 'In one or more embodiments, the first sealing component may be oligomers that are incorporated into the non-aqueous fluid either initially or upon the detection of a fluid loss event.', 'In more specific embodiments, the first sealing component may be vinyl ester or polybutadiene oligomers, such as those described in U.S. patent application Ser.', 'Nos. 61/436,339 and 61/498,305, which are herein incorporated by reference in their entirety.', 'However, it is also intended that other oligomers may be used as the first sealing component instead of vinyl esters and polybutadienes.', 'In such embodiments, the second sealing component may be a peroxide or other peroxide forming composition, which is optionally encapsulated.', 'Upon its release from the encapsulant, or upon exposure of the peroxide with the vinyl ester or polybutadiene oligomer, the peroxide may be able to initiate a polymerization chain reaction between the oligomers present within the filtrate to form a chemical seal within the near-wellbore region of the formation,\n \nIn yet another embodiment, the second sealing component may be a modified persulfate or a metallocene.', 'In these instances, the modified persulfate may slowly release peroxide species that are capable of initiating a polymerization chain reaction between the oligomers present within the filtrate to form a chemical seal within the near-wellbore region of the formation.', 'The use of a metallocene may also catalyze a polymerization reaction between the oligomers present within the filtrate to form a chemical seal within the formation.', 'In still other embodiments, polymerization of the oligomers of the first sealing component may be initiated by the action of a downhole tool.', 'Specifically, in the absence of a second sealing component, the polymerization of the oligomers may be initiated by ultrasonication of the desired formation area.', 'In this case, upon the incorporation of the oligomers into the filtrate a downhole tool capable of ultrasonication may be placed and/or, if already present on the drill string, activated within the wellbore in order to initiate the polymerization of the oligomers within the filtrate.', 'In another embodiment, a second sealing component comprising at least one of a dispersed silicon carbide or dispersed carbonaceous material chosen from the group including: graphite, graphene, graphene oxide, glassy carbon, carbon nanofoam, buckminsterfullerene, buckypaper, nanofiber, nanoplatelets, nano-onions, nanoribbons, nanohorns, single- or multi-walled carbon nanotubes, carbon black, carbon nanotubes, and derivatives thereof may be utilized as a sensitizer for a downhole tool.', 'Silicon carbide and carbonaceous nanomaterials display strong absorption of a large range of electromagnetic radiation, including gamma, ultraviolet, microwave, and radio wave radiation, with subsequent light emission and heat release.', 'While not adhering to any particular theory, carbon nanomaterials incorporated in the wellbore fluids of the present disclosure may exhibit dielectric loss, in which energy from incident radiation is transmitted as heat into the surrounding media, i.e. a wellbore fluid, filtrate, filtercake, polymer, gel, etc.', "In these instances, the second sealing component's sensitivity to electromagnetic radiation may be utilized to substantially and quickly increase the temperature within the filtrate in order to initiate a polymerization reaction between the oligomers, discussed above.", 'Upon the incorporation of the first sealing components into the filtrate, and second sealing component into the filtrate or the near-bit region of the wellbore, a microwave or UV source may be placed and/or, if already present on the drill string, activated within the wellbore in order to increase the temperature within the filtrate and initiate the polymerization of the oligomers within the filtrate.', 'In still another embodiment, a first sealing component comprising additives with thixotropic properties, may be incorporated into the non-aqueous based wellbore fluid in order to create a seal within the region of the formation containing the filtrate.', 'Suitable additives may include tris urea and derivatives thereof or any other oil soluble polymer possessing thixotropic properties.', 'Thixotropy is a shear thinning property wherein certain fluids are thick and viscous under static conditions but also capable of thinning and flowing when agitated or otherwise stressed.', 'Thus, upon the pumping action of the fluid during drilling the fluid with thixotropic additives will readily flow, but upon the leaking of the drilling fluid into the formation in the form of a filtrate the fluid will experience more restriction and less agitation within the pores of the formation thus rendering the filtrate thicker and more viscous.', 'This thickening of the fluid within the pores may serve to effectively seal the region of the formation containing the thickened filtrate.', 'The non-aqueous based wellbore fluids may include, for example, an oleaginous continuous phase, a non-oleaginous discontinuous phase, first and second sealing components as indicated above, weighting agents, emulsifiers, viscosifiers, and/or other additives conventionally used in drilling fluids.', 'The oleaginous fluid may be a liquid and more specifically is a natural or synthetic oil and more specifically the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids, mixtures thereof and similar compounds known to one of skill in the art; and mixtures thereof.', 'The concentration of the oleaginous fluid should be sufficient so that an invert emulsion forms and may be less than about 99% by volume of the invert emulsion.', 'In one embodiment the amount of oleaginous fluid is from about 30% to about 95% by volume and more specifically about 40% to about 90% by volume of the invert emulsion fluid.', 'The oleaginous fluid in one embodiment may include at least 5% by volume of a material selected from the group including esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.', 'The non-oleaginous fluid used in the formulation of the invert emulsion fluid disclosed herein is a liquid and specifically is an aqueous liquid.', 'More specifically, the non-oleaginous liquid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof.', 'The amount of the non-oleaginous fluid is less than the theoretical limit needed for forming an invert emulsion.', 'Thus in one embodiment the amount of non-oleaginous fluid is less that about 70% by volume, and more specifically from about 1% to about 70% by volume.', 'In another embodiment, the non-oleaginous fluid is from about 5% to about 60% by volume of the invert emulsion fluid.', 'The fluid phase may include either an aqueous fluid or an oleaginous fluid, or mixtures thereof.', 'Conventional methods can be used to prepare the drilling fluids disclosed herein, in a manner analogous to those normally used to prepare conventional oil-based drilling fluids.', 'In one embodiment, a desired quantity of oleaginous fluid such as a base oil and a suitable amount of a surfactant are mixed together and the remaining components are added sequentially with continuous mixing.', 'An invert emulsion may also be formed by vigorously agitating, mixing or shearing the oleaginous fluid and the non-oleaginous fluid.', 'Other additives that may be included in the wellbore fluids disclosed herein include for example, wetting agents, organophilic clays, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents.', 'The addition of such agents should be well known to one of ordinary skill in the art of formulating drilling fluids and muds.', 'Emulsifiers that may be used in the fluids disclosed herein include, for example, an alkoxylated ether acid.', 'In embodiment of an alkoxylated ether acid is an alkoxylated fatty alcohol terminated with an carboxylic acid, represented by the following formula:\n \n \n \n \nwhere R is C\n6\n-C\n24 \nor —C(O)R\n3 \n(where R\n3 \nis C\n10\n-C\n22\n), R\n1 \nis H or C\n1\n-C\n4\n, R\n2 \nis C\n1\n-C\n5 \nand n may range from 1 to 20.', 'Such compound may be formed by the reaction of an alcohol with a polyether (such as poly(ethylene oxide), polypropylene oxide), poly(butylene oxide), or copolymers of ethylene oxide, propylene oxide, and/or butylene oxide) to form an alkoxylated alcohol.', 'The alkoxylated alcohol may then be reacted with an α-halocarboxylic acid (such as chloroacetic acid, chloropropionic acid, etc.) to form the alkoxylated ether acid.', 'In a particular embodiment, the selection of n may be based on the lipophilicity of the compound and the type of polyether used in the alkoxylation.', 'In some particular embodiments, where R\n1 \nis H (formed from reaction with poly(ethylene oxide)), n may be 2 to 10 (between 2 and 5 in some embodiments and between 2 and 4 in more particular embodiments).', 'In other particular embodiments, where R\n1 \nis —CH\n3\n, n may range up to 20 (and up to 15 in other embodiments).', 'Further, selection of R (or R\n3\n) and R\n2 \nmay also depend on the hydrophilicity of the compound due to the extent of polyetherification (i.e., number of n).', 'In selecting each R (or R\n3\n), R\n1\n, R\n2\n, and n, the relative hydrophilicity and lipophilicity contributed by each selection may be considered so that the desired HLB value may be achieved.', 'Wetting agents that may be suitable for use in the fluids disclosed herein include crude tall oil, oxidized crude tall oil, surfactants, organic phosphate esters, modified imidazolines and amidoamines, alkyl aromatic sulfates and sulfonates, and the like, and combinations or derivatives of these.', 'Organophilic clays, normally amine treated clays, may be useful as viscosifiers and/or emulsion stabilizers in the fluid composition disclosed herein.', 'Other viscosifiers, such as oil soluble polymers, polyamide resins, polycarboxylic acids and soaps can also be used.', 'The amount of viscosifier used in the composition can vary upon the end use of the composition.', 'However, normally about 0.1% to 6% by weight range is sufficient for most applications.', 'Conventional suspending agents that may be used in the fluids disclosed herein include organophilic clays, amine treated clays, oil soluble polymers, polyamide resins, polycarboxylic acids, and soaps.', 'The amount of conventional suspending agent used in the composition, if any, may vary depending upon the end use of the composition.', 'However, normally about 0.1% to about 6% by weight is sufficient for most applications.', 'Weighting agents or density materials conventionally used in drilling fluids include galena, hematite, magnetite, iron oxides, illmenite, barite, siderite, celestite, dolomite, calcite, and the like.', 'The quantity of such material added, if any, depends upon the desired density of the final composition.', 'Weight material is added to result in a drilling fluid density of up to about 24 pounds per gallon, but a lower density may be particularly desired for drilling through depleted reservoirs, for example up to 16 ppg.', 'Gelling materials that may be used in the drilling fluids disclosed herein include bentonite, sepiolite, clay, attapulgite clay, anionic high-molecular weight polymer and biopolymers.', 'In various embodiments, methods of drilling a subterranean hole may include mixing an oleaginous fluid, a non-oleaginous fluid, an emulsifier, such as those described above, with an inactivated first sealing component and optionally a second sealing component; and drilling the subterranean hole using this fluid as the drilling fluid.', 'The fluid may be pumped down to the bottom of the well through a drill pipe, where the fluid emerges through ports in the drilling bit, for example.', 'In one embodiment, the fluid may be used in conjunction with any drilling operation, which may include, for example, vertical drilling, extended reach drilling, and directional drilling, and may be particularly suitable for drilling through depleted reservoirs, especially depleted sandstone formations.', 'The first sealing component and second sealing component may be provided together in the drilling fluid as a preventative measure to react in situ to form a chemical sealing layer in the region of the formation containing the filtrate within a wellbore drilled through a depleted reservoir.', 'In one or more other embodiments, one of the components may be provided as a background, and the second sealing component may be added once losses are registered, to react with the first sealing component (now in the filtrate) to form a chemical sealing layer within the region of formation containing the filtrate as a remediative measure.', 'Embodiments of the present disclosure may provide at least one of the following advantages.', 'The systems disclosed may be particularly suitable for drilling through depleted sandstone formations, as well as other depleted formation types, which present numerous technical challenges.', 'By adding the second sealing component once fluid losses are registered, the chemical seal formed by the reaction of the first and second sealing component may be highly localized and selectively formed directly within the loss zone.', 'This results in both material savings from the limited use of a second sealing component and time savings as it allows for selectively treating the formation while drilling, without having to trip out the drill string to treat the loss zone.', 'Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this disclosure.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A method of sealing a formation, comprising: drilling a wellbore through the formation while pumping a non-aqueous based wellbore fluid comprising a first sealing component into the wellbore;\nwherein the first sealing component comprises a vinyl ester oligomer or a polybutadiene oligomer; and\nadding a second sealing component to the wellbore fluid, wherein the second sealing, component is encapsulated by an encapsulant,\nwherein the non-aqueous based wellbore fluid and the second sealing component filter into the formation as a filtrate and thicken during the drilling; and\nforming a chemical sealing, layer in a near-wellbore formation region of the formation\nwherein the first sealing component and the second sealing component react to form the chemical sealing layer during the drilling,\nwherein the second sealing component is at least one of: metallocene; dispersed silicon carbide; and dispersed carbonaceous material selected from the group consisting of: graphite; graphene; graphene oxide; glassy carbon; carbon nanofoam; buckminsterfullerene; buckypaper; nanofiber; nanoplatelets; nano-onions; nanoribbons; nanohorns; single- or multi-walled carbon nanotubes; carbon black; carbon nanotubes; and combinations thereof.', '2.', 'The method of claim 1, wherein the encapsulant releases the second sealing component within the near-wellbore formation region.', '3.', 'The method of claim 2, wherein the encapsulant is a composition comprising a dissolvable component.', '4.', 'The method of claim 2, wherein the encapsulant is an enteric polymer.', '5.', 'The method of claim 2, wherein the second sealing component comprises encapsulated particles having mean diameters greater than 20 microns.', '6.', 'The method of claim 2, wherein the second.', 'sealing component comprises encapsulated particles having mean diameters less than 20 microns.', '7.', 'The method of claim 1, further comprising: initiating polymerization of at least one of the vinyl ester oligomer and the polybutadiene oligomer.', '8.', 'The method of claim 1, further comprising: registering at least one fluid loss during the drilling; and\npumping the second sealing component into the wellbore in response to the at least one fluid loss registered during the drilling.', '9.', 'The method of claim 1, further comprising: activating a microwave source, ultraviolet source or an ultrasonification source within the wellbore.\n\n\n\n\n\n\n10.', 'The method of claim 1, wherein the chemical sealing layer is formed in the formation behind a filter cake formed on walls of the wellbore.'] | ['No Captions Available'] |
US11142988 | Stress testing with inflatable packer assembly | Sep 29, 2017 | Pierre-Yves Corre, Patrice Milh, Stephane Briquet | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in the counterpart PCT application PCT/IB2017/001349, dated Jun. 6, 2018 (13 pages).; International Preliminary Report on Patentability issued in the PCT application PCT/IB2017/001349, dated Apr. 9, 2020 (8 pages). | 2824612; February 1958; Lynes; 2831541; April 1958; Conover; 3291219; December 1966; Nutter; 4357992; November 9, 1982; Sweeney; 4815538; March 28, 1989; Burroughs; 6286603; September 11, 2001; Parent; 9366107; June 14, 2016; Hallundb.ae butted.k; 20060090905; May 4, 2006; Brennan et al. | Foreign Citations not found. | ['An inflatable packer assembly comprising a first fixed sleeve fixed to a mandrel, a first sliding sleeve moveable along the mandrel, and a first inflatable member connected to the first fixed sleeve and the first sliding sleeve.', 'A second sliding sleeve is moveable along the mandrel, and a second inflatable member is connected to the first sliding sleeve and the second sliding sleeve.', 'A second fixed sleeve is fixed to the mandrel and slidably engages the second sliding sleeve.', 'An inflation flowline disposed within the mandrel is in fluid communication with interiors of the first and second inflatable members for inflating the first and second inflatable members to isolate a portion of a wellbore penetrating a subterranean formation.', 'An injection flowline is disposed within the mandrel for injecting a fluid into the isolated wellbore portion at a high enough pressure to create microfractures in the subterranean formation.'] | ['Description\n\n\n\n\n\n\nBACKGROUND OF THE DISCLOSURE\n \nKnowledge of in situ or downhole stresses may be utilized for analyzing various parameters related to rock mechanics.', 'Rock mechanics may affect, among other things, hydrocarbon production rates, well stability, sand control, and/or horizontal well planning.', 'Downhole formation stress information determined during geological formation exploration (e.g., during a wireline testing process and/or during a logging-while-drilling (LWD) process) may be used to, for example, design, select, and/or identify fracturing treatments used to increase hydrocarbon production.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus including an inflatable packer assembly for use in a wellbore penetrating a subterranean formation.', 'The inflatable packer assembly includes a first fixed sleeve fixed to a mandrel, a first sliding sleeve moveable along the mandrel, and a first inflatable member connected to the first fixed sleeve and the first sliding sleeve.', 'A second sliding sleeve is moveable along the mandrel.', 'A second inflatable member is connected to the first sliding sleeve and the second sliding sleeve.', 'A second fixed sleeve is fixed to the mandrel and slidably engages the second sliding sleeve.', 'An inflation flowline is disposed within the mandrel and in fluid communication with interiors of the first and second inflatable members for inflating the first and second inflatable members to isolate a portion of the wellbore.', 'An injection flowline is disposed within the mandrel for injecting a fluid into the isolated wellbore portion at a high enough pressure to create microfractures in the subterranean formation.', 'The present disclosure also introduces an apparatus including an inflatable packer assembly for use in a wellbore penetrating a subterranean formation.', 'The inflatable packer assembly includes a first fixed sleeve fixed to a mandrel, a first sliding sleeve moveable along the mandrel, and a first inflatable member connected to the first fixed sleeve and the first sliding sleeve.', 'A second sliding sleeve is moveable along the mandrel.', 'A second inflatable member is connected to the first sliding sleeve and the second sliding sleeve.', 'A third sliding sleeve is moveable along the mandrel.', 'A third inflatable member is connected to the second sliding sleeve and the third sliding sleeve.', 'A second fixed sleeve is fixed to the mandrel and slidably engages the third sliding sleeve.', 'A first inflation flowline is disposed within the mandrel for inflating the first and third inflatable members to a first pressure.', 'A second inflation flowline is disposed within the mandrel for inflating the second inflatable member to a second pressure greater than the first pressure.', 'The inflated first, second, and third inflatable members isolate first and second portions of the wellbore.', 'An injection flowline is disposed within the mandrel for injecting a fluid into at least one of the first and second isolated wellbore portions at a high enough pressure to enlarge microfractures in the subterranean formation.', 'The present disclosure also introduces a method that includes conveying an inflatable packer assembly (IPA) in a wellbore such that first and second inflatable members of the IPA straddle at least a portion of a zone of interest of a subterranean formation penetrated by the wellbore.', 'The first and second inflatable members are inflated to radially expand the first and second inflatable members into sealing engagement with a wall of the wellbore and thereby isolate a portion of the wellbore.', 'The first inflatable member extends between a fixed sleeve of the IPA and a first sliding sleeve of the IPA.', 'The second inflatable member extends between the first sliding sleeve and a second sliding sleeve of the IPA, such that inflating the first and second inflatable members moves the first sliding sleeve closer to the fixed sleeve and moves the second sliding sleeve closer to the fixed sleeve and the first sliding sleeve.', 'Fluid is injected into the isolated wellbore portion through a port of the first sliding sleeve to create or enlarge microfractures in the subterranean formation zone of interest.', 'After stopping the fluid injection, pressure in the isolated wellbore portion is monitored to determine a closing pressure of the microfractures.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '4\n is a schematic view of another example implementation of the apparatus shown in \nFIG.', '3\n according to one or more aspects of the present disclosure.', 'FIG.', '5\n is a schematic view of another example implementation of the apparatus shown in \nFIG.', '3\n according to one or more aspects of the present disclosure.', 'FIG.', '6\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.', 'One or more aspects of the present disclosure relate to stress test operations in which small-scale hydraulic fracturing techniques (such as those commonly known as “microfrac” or “minifrac”) may be utilized for measuring downhole geological formation stresses, such as for measuring the minimum principal stress of the formation.', 'Stress test operations according to one or more aspects of the present disclosure may be used to analyze fluid leak-off behavior, permeability, porosity, pore pressure, fracture closure pressure, fracture volume, and/or other example reservoir properties also within the scope of the present disclosure.', 'The stress test operations may be performed during a drilling operation, or the drilling tool/string may be removed and a wireline tool deployed into the wellbore to test and/or measure the formation.', 'In an example stress test operation, a fluid is injected into a defined interval to create a test fracture in a geological formation.', 'The fractured formation is then monitored by pressure measurements.', 'The stress test operation may be performed using little or no proppant in the fracturing fluid.', 'After the fracturing fluid is injected and the formation is fractured, the well may be shut-in, and the pressure decline of the fluid in the newly formed fracture may be observed as a function of time.', 'The data thus obtained may be used to determine parameters for designing a subsequent, full-scale formation fracturing treatment.', 'Conducting stress test operations before performing the full-scale treatment may result in improved fracture treatment design, such as may yield in enhanced production and improved economics from the fractured formation.', 'Stress test operations are significantly different from conventional full-scale fracturing operations.', 'For example, as described above, just a small amount of fracturing fluid is injected for stress test operations, and little or no proppant may be carried with the fracturing fluid.', 'The fracturing fluid used for stress test operations may be of the same type that will be used for the subsequent full-scale treatment.', 'The intended result is not a propped fracture practical for production, but a small fracture to facilitate collection of pressure data from which formation and fracture parameters can be estimated and/or otherwise determined.', 'The pressure decline data may be utilized to calculate the effective fluid loss coefficient of the fracture fluid, fracture width, fracture length, efficiency of the fracture fluid, and the fracture closure time, for example.', 'These parameters may then be utilized in, for example, a fracture design simulator to establish parameters for performing the full-scale fracturing operation.', 'The pressures utilized in stress test operations may exceed the axial force limitations of conventional downhole tools used for stress test operations.', 'One or more aspects of the present disclosure pertain to a downhole tool comprising an inflatable packer assembly that is capable of withstanding high-pressure stress test operations.', 'FIG.', '1\n is a schematic view of an example wellsite system \n100\n to which one or more aspects of the present disclosure may be applicable.', 'The wellsite system \n100\n may be onshore or offshore.', 'In the example wellsite system \n100\n shown in \nFIG.', '1\n, a wellbore \n104\n is formed in one or more subterranean formation \n102\n by rotary drilling.', 'Other example systems within the scope of the present disclosure may also or instead utilize directional drilling.', 'While some elements of the wellsite system \n100\n are depicted in \nFIG.', '1\n and described below, it is to be understood that the wellsite system \n100\n may include other components in addition to, or in place of, those presently illustrated and described.', 'As shown in \nFIG.', '1\n, a drillstring \n112\n suspended within the wellbore \n104\n comprises a bottom hole assembly (BHA) \n140\n that includes or is coupled with a drill bit \n142\n at its lower end.', 'The surface system includes a platform and derrick assembly \n110\n positioned over the wellbore \n104\n.', 'The platform and derrick assembly \n110\n may comprise a rotary table \n114\n, a kelly \n116\n, a hook \n118\n, and a rotary swivel \n120\n.', 'The drillstring \n112\n may be suspended from a lifting gear (not shown) via the hook \n118\n, with the lifting gear being coupled to a mast (not shown) rising above the surface.', 'An example lifting gear includes a crown block affixed to the top of the mast, a vertically traveling block to which the hook \n118\n is attached, and a cable passing through the crown block and the vertically traveling block.', 'In such an example, one end of the cable is affixed to an anchor point, whereas the other end is affixed to a winch to raise and lower the hook \n118\n and the drillstring \n112\n coupled thereto.', 'The drillstring \n112\n comprises one or more types of tubular members, such as drill pipes, threadedly attached one to another, perhaps including wired drilled pipe.', 'The drillstring \n112\n may be rotated by the rotary table \n114\n, which engages the kelly \n116\n at the upper end of the drillstring \n112\n.', 'The drillstring \n112\n is suspended from the hook \n118\n in a manner permitting rotation of the drillstring \n112\n relative to the hook \n118\n.', 'Other example wellsite systems within the scope of the present disclosure may utilize a top drive system to suspend and rotate the drillstring \n112\n, whether in addition to or instead of the illustrated rotary table system.', 'The surface system may further include drilling fluid or mud \n126\n stored in a pit or other container \n128\n formed at the wellsite.', 'The drilling fluid \n126\n may be oil-based mud (OBM) or water-based mud (WBM).', 'A pump \n130\n delivers the drilling fluid \n126\n to the interior of the drillstring \n112\n via a hose or other conduit \n122\n coupled to a port in the rotary swivel \n120\n, causing the drilling fluid to flow downward through the drillstring \n112\n, as indicated in \nFIG.', '1\n by directional arrow \n132\n.', 'The drilling fluid exits the drillstring \n112\n via ports in the drill bit \n142\n, and then circulates upward through the annulus region between the outside of the drillstring \n112\n and the wall \n106\n of the wellbore \n104\n, as indicated in \nFIG.', '1\n by directional arrows \n134\n.', 'In this manner, the drilling fluid \n126\n lubricates the drill bit \n142\n and carries formation cuttings up to the surface as it is returned to the container \n128\n for recirculation.', 'The BHA \n140\n may comprise one or more specially made drill collars near the drill bit \n142\n.', 'Each such drill collar may comprise one or more devices permitting measurement of downhole drilling conditions and/or various characteristic properties of the subterranean formation \n102\n intersected by the wellbore \n104\n.', 'For example, the BHA \n140\n may comprise one or more logging-while-drilling (LWD) modules \n144\n, one or more measurement-while-drilling (MWD) modules \n146\n, a rotary-steerable system and motor \n148\n, and perhaps the drill bit \n142\n.', 'Other BHA components, modules, and/or tools are also within the scope of the present disclosure, and such other BHA components, modules, and/or tools may be positioned differently in the BHA \n140\n.', 'The LWD modules \n144\n may comprise an inflatable packer assembly (IPA) for performing stress test operations as described above.', 'Example aspects of such IPA tools are described below.', 'Other examples of the LWD modules \n144\n are also within the scope of the present disclosure.', 'The MWD modules \n146\n may comprise one or more devices for measuring characteristics of the drillstring \n112\n and/or the drill bit \n142\n, such as for measuring weight-on-bit, torque, vibration, shock, stick slip, tool face direction, and/or inclination, among others.', 'The MWD modules \n146\n may further comprise an apparatus (not shown) for generating electrical power to be utilized by the downhole system.', 'This may include a mud turbine generator powered by the flow of the drilling fluid \n126\n.', 'Other power and/or battery systems may also or instead be employed.', 'The wellsite system \n100\n also includes a data processing system that can include one or more, or portions thereof, of the following: the surface equipment \n190\n, control devices and electronics in one or more modules of the BHA \n140\n (such as a downhole controller \n150\n), a remote computer system (not shown), communication equipment, and other equipment.', 'The data processing system may include one or more computer systems or devices and/or may be a distributed computer system.', 'For example, collected data or information may be stored, distributed, communicated to an operator, and/or processed locally or remotely.', 'The data processing system may, individually or in combination with other system components, perform the methods and/or processes described below, or portions thereof.', 'For example, such data processing system may include processor capability for collecting data relating to the pressure decay measured during stress test operations in conjunction with an IPA tool of the LWD modules \n144\n.', 'Methods and/or processes within the scope of the present disclosure may be implemented by one or more computer programs that run in a processor located, for example, in one or more modules of the BHA \n140\n and/or the surface equipment \n190\n.', 'Such programs may utilize data received from the BHA \n140\n via mud-pulse telemetry and/or other telemetry means, and/or may transmit control signals to operative elements of the BHA \n140\n.', 'The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the BHA \n140\n and/or surface equipment \n190\n, or may be stored on an external, tangible, non-transitory, computer-usable storage medium that is electronically coupled to such processor(s).', 'The storage medium may be one or more known or future-developed storage media, such as a magnetic disk, an optically readable disk, flash memory, or a readable device of another kind, including a remote storage device coupled over a communication link, among other examples.', 'FIG.', '2\n is a schematic view of another example wellsite system \n200\n to which one or more aspects of the present disclosure may be applicable.', 'The wellsite system \n200\n may be onshore or offshore.', 'In the example wellsite system \n200\n shown in \nFIG.', '2\n, a tool string \n204\n is conveyed into the wellbore \n104\n via a wireline and/or other conveyance means \n208\n.', 'As with the wellsite system \n100\n shown in \nFIG.', '1\n, the example wellsite system \n200\n of \nFIG.', '2\n may be utilized for stress test operations according to one or more aspects of the present disclosure.', 'The tool string \n204\n is suspended in the wellbore \n104\n from the lower end of the wireline \n208\n, which may be a multi-conductor logging cable spooled on a winch (not shown).', 'The wireline \n208\n may include at least one conductor that facilitates data communication between the tool string \n204\n and surface equipment \n290\n disposed on the surface.', 'The surface equipment \n290\n may have one or more aspects in common with the surface equipment \n190\n shown in \nFIG.', '1\n.', 'The tool string \n204\n and wireline \n208\n may be structured and arranged with respect to a service vehicle (not shown) at the wellsite.', 'For example, the wireline \n208\n may be connected to a drum (not shown) at the wellsite surface, wherein rotation of the drum raises and lowers the tool string \n204\n within the wellbore \n104\n.', 'The drum may be disposed on a service truck or a stationary platform.', 'The service truck or stationary platform may further contain the surface equipment \n290\n.', 'The tool string \n204\n comprises one or more tools and/or modules schematically represented in \nFIG.', '2\n.', 'For example, the illustrated tool string \n204\n includes several modules \n212\n, at least one of which may be or comprise at least a portion of an IPA tool as described below.', 'Other implementations of the downhole tool string \n204\n within the scope of the present disclosure may include additional or fewer components or modules relative to the example implementation depicted in \nFIG.', '2\n.', 'The wellsite system \n200\n also includes a data processing system that can include one or more of, or portions of, the following: the surface equipment \n290\n, control devices and electronics in one or more modules of the tool string \n204\n (such as a downhole controller \n216\n), a remote computer system (not shown), communication equipment, and other equipment.', 'The data processing system may include one or more computer systems or devices and/or may be a distributed computer system.', 'For example, collected data or information may be stored, distributed, communicated to an operator, and/or processed locally or remotely.', 'The data processing system may, individually or in combination with other system components, perform the methods and/or processes described below, or portions thereof.', 'For example, such data processing system may include processor capability for collecting data relating during stress test operations according to one or more aspects of the present disclosure.', 'Methods and/or processes within the scope of the present disclosure may be implemented by one or more computer programs that run in a processor located, for example, in one or more modules \n212\n of the tool string \n204\n and/or the surface equipment \n290\n.', 'Such programs may utilize data received from the downhole controller \n216\n and/or other modules \n212\n via the wireline \n208\n, and may transmit control signals to operative elements of the tool string \n204\n.', 'The programs may be stored on a tangible, non-transitory, computer-usable storage medium associated with the one or more processors of the downhole controller \n216\n, other modules \n212\n of the tool string \n204\n, and/or the surface equipment \n290\n, or may be stored on an external, tangible, non-transitory, computer-usable storage medium that is electronically coupled to such processor(s).', 'The storage medium may be one or more known or future-developed storage media, such as a magnetic disk, an optically readable disk, flash memory, or a readable device of another kind, including a remote storage device coupled over a communication link, among other examples.', 'While \nFIGS.', '1 and 2\n illustrate example wellsite systems \n100\n and \n200\n, respectively, that convey a downhole tool/string into a wellbore, other example implementations consistent with the scope of this disclosure may utilize other conveyance means to convey a tool into a wellbore, including coiled tubing, tough logging conditions (TLC), slickline, and others.', 'Additionally, other downhole tools within the scope of the present disclosure may comprise components in a non-modular construction also consistent with the scope of this disclosure.\n \nFIG.', '3\n is a schematic view of at least a portion of an example implementation of an inflatable packer assembly (IPA) \n300\n according to one or more aspects of the present disclosure.', 'The IPA \n30\n is depicted in \nFIG.', '1\n in a “dual-packer arrangement,” although other implementations are also within the scope of the present disclosure.', 'The IPA \n300\n is for use in a wellbore \n104\n penetrating a subterranean formation \n102\n, whether via the drill string \n112\n depicted in \nFIG.', '1\n, the wireline \n208\n depicted in \nFIG.', '2\n, and/or other conveyance means within the scope of the present disclosure.', 'The IPA \n300\n includes a mandrel \n304\n, an uphole (hereafter “upper”) inflatable member \n308\n, and a downhole (hereafter “lower”) inflatable member \n312\n spaced apart from the upper inflatable member \n308\n along a longitudinal axis \n305\n of the mandrel \n304\n.', 'The upper and lower inflatable members \n308\n, \n312\n extend circumferentially around the mandrel \n304\n.', 'The axial separation between the inflatable members \n308\n, \n312\n may range between about one meter (m) and about 30 m.', 'However, other distances are also within the scope of the present disclosure.', 'The inflatable members \n308\n, \n312\n may be made of various materials suitable for forming a seal with the wall \n106\n of the wellbore \n104\n.', 'For example, the inflatable members \n308\n, \n312\n may be made of rubber and/or other viscoelastic materials.', 'As shown in \nFIG.', '3\n, the inflatable members \n308\n, \n312\n inflate to fluidly isolate a portion \n105\n of the wellbore \n104\n that straddles or otherwise coincides with at least a portion of a zone of interest \n103\n in the formation \n102\n.', 'To inflate the inflatable members \n308\n, \n312\n into sealing engagement with the wellbore wall \n106\n, the inflatable members \n308\n, \n312\n may be filled with an inflation fluid \n316\n via an inflation flowline \n320\n, thus radially expanding the inflatable members \n308\n, \n312\n until substantial portions \n309\n, \n313\n contact and seal against the wellbore wall \n106\n.', 'The inflation fluid \n316\n may be or comprise fluid obtained from the wellbore \n104\n, hydraulic fluid carried with or pumped to the IPA \n300\n, and/or other substantially incompressible fluids.', 'When the inflatable members \n308\n, \n312\n are inflated, the IPA \n300\n may be operated to inject a fluid \n324\n from an injection flowline \n328\n into the isolated wellbore portion \n105\n, such as for stress testing the formation \n102\n within the zone of interest \n103\n.', 'The injected fluid \n324\n may be injected into the isolated wellbore portion \n105\n at a pressure that is high enough to create microfractures \n104\n in the formation \n102\n.', 'The injected fluid \n324\n may be or comprise fluid obtained from the wellbore \n104\n, fracturing fluid and/or other hydraulic fluid carried with or pumped to the IPA \n300\n, and/or other substantially incompressible fluids.', 'The mandrel \n304\n may be a single, discrete member or multiple connected members, each formed of a rigid material such as carbon or alloy steel.', 'The mandrel \n304\n may be generally cylindrical in shape, and may not include internally moving components.', 'The mandrel \n304\n may be substantially solid, having passages drilled or otherwise formed to create the inflation flowline \n320\n and the injection flowline \n328\n.', 'However, at least a portion of the mandrel \n304\n may be substantially hollow, and the flowlines \n320\n, \n328\n may each be or comprise one or more tubes and/or other conduits for transmitting the inflation and injected fluids \n316\n, \n324\n.', 'The inflation flowline \n320\n may comprise or be in selective or constant fluid communication with an upper inflation port \n332\n for pressurizing and depressurizing the upper inflatable member \n308\n, and a lower inflation port \n336\n for pressurizing and depressurizing the lower inflatable member \n312\n.', 'A pump (not shown) may be used to conduct the inflation fluid \n316\n into and/or otherwise pressurize the inflation flowline \n320\n and thereby independently or simultaneously inflate the upper and/or lower inflatable members \n308\n, \n312\n via the ports \n332\n, \n336\n.', 'For example, the upper and lower inflatable members \n308\n, \n312\n may be pressurized to about 1,000 pounds per square inch (psi) in a wellbore having a diameter of about 21.6 centimeters (cm).', 'The term “depressurizing” as used herein may include releasing pressure from the inflation flowline \n320\n by, for example, controlling the pressure exerted by the pump (not shown), and may also include actively removing pressure from the inflation flowline \n320\n.', 'The injection flowline \n328\n may comprise or be in selective or constant fluid communication with an injection port \n345\n between the upper and lower inflatable members \n308\n, \n312\n for injecting the fluid \n324\n into the isolated wellbore portion \n105\n, such as for stress testing the formation \n102\n as described herein.', 'A high-pressure pump (not shown) may be used to conduct the injection fluid \n324\n into and/or otherwise pressurize the injection flowline \n328\n to inject the fluid \n324\n into the isolated wellbore portion \n105\n, perhaps at a pressure high enough to create the microfractures \n104\n within the zone of interest \n106\n between the upper and lower inflatable members \n308\n, \n312\n.', 'For example, the fluid \n324\n may be injected until hydraulic pressure in the zone of interest \n103\n increases to reach an initial fracturing pressure, such that microfractures \n104\n are formed in the formation \n102\n near the wellbore wall \n106\n.', 'The microfractures \n104\n may range in length between about 10 cm and about 100 cm, and may have openings (near the wellbore wall \n106\n) ranging between about 3 mm and about 15 mm.', 'When the injected fluid \n324\n is further injected, the microfractures \n104\n gradually widen, thus lowering pressure in the isolated wellbore portion \n105\n.', 'When the injection is stopped, the microfractures \n104\n close and the pressure reaches fracture closing pressure.', 'The fracture closure pressure is equal to or slightly greater than the pressure sufficient to keep the microfractures \n104\n open, and thus represents the minimum principal stress, which acts in a direction perpendicular to the fractured surface.', 'The injection and bleed-off process may also be repeated, thus reopening the microfractures \n104\n at a fracture reopening pressure.', 'The maximum horizontal principal stress may be determined using the measured fracture reopening pressure.', 'The construction and configuration of the IPA \n300\n may permit fluid \n324\n to be injected into the formation \n102\n at a hydraulic pressure of about 12,000 psi in a wellbore \n104\n having a diameter of about 21.6 cm.', 'However, other injection pressures are also within the scope of the present disclosure.', 'An upper end of the upper inflatable member \n308\n is connected to an upper fixed sleeve \n340\n, and a lower end of the upper inflatable member \n308\n is connected to an intermediate sliding sleeve \n344\n.', 'An upper end of the lower inflatable member \n312\n is connected to the intermediate sliding sleeve \n344\n, and a lower end of the lower inflatable member \n312\n is connected to a lower sliding sleeve \n348\n.', 'The upper fixed sleeve \n340\n is attached to or otherwise fixed with respect to the mandrel \n304\n.', 'The intermediate sliding sleeve \n344\n is moveable along the mandrel \n304\n.', 'The lower sliding sleeve \n348\n is moveable along the mandrel \n304\n and a lower fixed sleeve \n352\n.', 'The lower fixed sleeve \n352\n is attached to or otherwise fixed with respect to the mandrel \n304\n.', 'The upper fixed sleeve \n340\n includes at least one seal \n341\n preventing fluid communication between the wellbore \n104\n and the interior \n310\n of the upper inflatable member \n308\n.', 'The intermediate sliding sleeve \n344\n includes a port \n345\n in selective or continuous fluid communication with the isolated wellbore portion \n105\n for communicating the injected fluid \n324\n into the isolated wellbore portion \n105\n and the formation zone of interest \n103\n.', 'The intermediate sliding sleeve \n344\n also includes sliding seals \n346\n, \n347\n preventing fluid communication between the isolated wellbore portion \n105\n and the interiors \n310\n, \n314\n of the respective upper and lower inflatable members \n308\n, \n312\n.', 'The lower sliding sleeve \n348\n includes a sliding seal \n349\n preventing fluid communication between the interior \n314\n of the lower inflatable member \n312\n and a changing volume \n356\n defined between the lower sliding sleeve \n348\n and the lower fixed sleeve \n352\n.', 'The lower fixed sleeve \n352\n includes at least one seal \n353\n (two being depicted in \nFIG.', '3\n) preventing fluid communication between the volume \n356\n and the wellbore \n104\n.', 'In operation, while the upper and lower inflatable members \n308\n, \n312\n are deflated, the IPA \n300\n is conveyed within the wellbore \n104\n until the IPA \n300\n is proximate the zone of interest \n103\n in the formation \n102\n, such as to a depth at which the upper and lower inflatable members \n308\n, \n312\n straddle the zone of interest \n103\n and the injection port \n345\n is within the zone of interest \n31\n.', 'The upper and lower inflatable members \n308\n, \n312\n are then inflated, as described above, such that the upper and lower inflatable members \n308\n, \n312\n radially expand into sealing engagement with the wellbore wall \n106\n and create the isolated portion \n105\n of the wellbore \n104\n.', 'Fluid \n324\n may then be injected through the port \n345\n at a high enough pressure to create microfractures \n104\n in the formation \n102\n.', 'The injection is then stopped, and the subsequently decreasing pressure in the isolated wellbore portion \n105\n is monitored (e.g., via measuring pressure in the injection flowline \n328\n) to determine the fracture closing pressure and the minimum principal stress.', 'The injection and bleed-off process may also be repeated to determine the fracture reopening pressure and the maximum horizontal principal stress.', 'The upper and lower inflatable members \n308\n, \n312\n may then be deflated for removal of the IPA \n300\n from the wellbore \n104\n or repositioning to another zone of interest for performing additional stress test operations.', 'In implementations in which the volume \n356\n is sealed, the movement of the lower sliding sleeve \n348\n away from the lower fixed sleeve \n352\n may create a decreased pressure in the volume \n356\n.', 'Consequently, as the upper and lower inflatable members \n308\n, \n312\n are depressurized, the decreased pressure in the volume \n356\n may act to move the lower sliding sleeve \n348\n down towards its initial position.', 'Thus, the lower sliding sleeve \n348\n and the lower fixed sleeve \n352\n may act as an auto-retract mechanism, operable to aid in retracting the upper and lower inflatable members \n308\n, \n312\n closer to the mandrel \n304\n, thereby reducing the overall diameter of the IPA \n300\n to aid in conveying the IPA \n300\n within the wellbore \n104\n.', 'In \nFIG.', '3\n, the inflation flowline \n320\n and the injection flowline \n328\n are shown as distinct flow paths.', 'However, as illustrated in \nFIG.', '4\n, the inflation and injection flowlines \n320\n, \n328\n may share a common flow path \n420\n.', 'In such implementations, among others within the scope of the present disclosure, a valve \n460\n may be in fluid communication with the common flowline \n420\n to selectively control fluid communication with the wellbore.', 'The valve \n460\n may permit fluid used to inflate the inflatable members \n308\n, \n312\n to also be selectively injected into the isolated wellbore section via the port \n345\n.', 'For example, the valve \n460\n may be a relief valve that opens a predetermined differential pressure setting.', 'The valve \n460\n may be controlled passively, actively, or by a preset relief pressure.', 'For example, the relief pressure may be set at about 500 psi in wellbore having a diameter of about 21.6 cm.', 'However, other set pressures are also within the scope of the present disclosure.', 'FIG.', '5\n is a schematic view of another implementation of the IPA \n300\n shown in \nFIG.', '1\n, designated in \nFIG.', '5\n by reference number \n500\n.', 'The IPA \n500\n is shown as a “triple packer arrangement” for use in the wellbore \n104\n for testing the formation \n102\n.', 'The IPA \n500\n shown in \nFIG.', '5\n is substantially similar to the IPA shown in \nFIG.', '3\n except as described below.', 'The IPA \n500\n includes an upper fixed sleeve \n504\n, an upper sliding sleeve \n508\n, an intermediate sliding sleeve \n512\n, a lower sliding sleeve \n516\n, and a lower fixed sleeve \n520\n.', 'The upper fixed sleeve \n504\n is substantially similar to the upper sliding sleeve \n340\n shown in \nFIG.', '3\n.', 'The upper and intermediate sliding sleeves \n508\n, \n512\n are each substantially similar to the intermediate sliding sleeve \n344\n shown in \nFIG.', '3\n.', 'The lower sliding sleeve \n516\n and the lower fixed sleeve \n520\n are substantially similar to the lower sliding sleeve \n348\n and the lower fixed sleeve \n352\n, respectively, shown in \nFIG.', '3\n.', 'An upper inflatable member \n524\n is connected to and extends between the upper fixed sleeve \n504\n and the upper sliding sleeve \n508\n.', 'An intermediate inflatable member \n528\n is connected to and extends between the upper sliding sleeve \n508\n and the intermediate sliding sleeve \n512\n.', 'When inflated, the upper and intermediate inflatable members \n524\n, \n528\n fluidly isolate a portion \n540\n of the wellbore \n104\n.', 'A lower inflatable member \n532\n is connected to and extends between the intermediate sliding sleeve \n512\n and the lower sliding sleeve \n516\n.', 'When inflated, the intermediate and lower inflatable members \n528\n, \n532\n fluidly isolate a portion \n541\n of the wellbore \n104\n.', 'The upper, intermediate, and lower inflatable members \n524\n, \n528\n, \n532\n are substantially similar to the upper and lower inflatable members \n308\n, \n312\n shown in \nFIG.', '3\n.', 'The upper fixed sleeve \n504\n is attached to or otherwise fixed with respect to the mandrel \n304\n, and includes a seal \n505\n preventing fluid communication between the wellbore \n104\n and the interior \n526\n of the upper inflatable member \n524\n.', 'The upper sliding sleeve \n508\n slides along the mandrel \n304\n, and may include an injection port \n509\n for injecting fluid into the isolated wellbore portion \n540\n.', 'The upper sliding sleeve \n508\n may also include a seal \n510\n preventing fluid communication between the isolated wellbore portion \n540\n and the interior \n526\n of the upper inflatable member \n524\n, and a seal \n511\n preventing fluid communication between the isolated wellbore portion \n540\n and the interior \n530\n of the intermediate inflatable member \n528\n.', 'The intermediate sliding sleeve \n512\n also slides along the mandrel \n304\n, and may include an injection port \n513\n for injecting fluid into the isolated wellbore portion \n541\n.', 'Just one or both of the upper and intermediate sliding sleeves \n508\n, \n512\n may include the corresponding injection port \n509\n, \n513\n.', 'The intermediate sliding sleeve \n512\n may also include a seal \n514\n preventing fluid communication between the isolated wellbore portion \n541\n and the interior \n530\n of the intermediate inflatable member \n524\n, and a seal \n515\n preventing fluid communication between the isolated wellbore portion \n541\n and the interior \n534\n of the lower inflatable member \n532\n.', 'The lower sliding sleeve \n516\n is moveable along the mandrel \n304\n and the lower fixed sleeve \n520\n, and the lower fixed sleeve \n520\n is attached to or otherwise fixed with respect to the mandrel \n304\n.', 'A changing volume \n550\n substantially similar to the volume \n356\n shown in \nFIG.', '3\n may be defined between surfaces of the lower sliding sleeve \n516\n, the lower fixed sleeve \n520\n, the mandrel \n304\n, and perhaps corresponding seals.', 'For example, the lower sliding sleeve \n516\n may include a seal \n517\n preventing fluid communication between the volume \n550\n and the interior \n534\n of the lower inflatable member \n532\n, and the lower fixed sleeve \n520\n may include one or more seals \n521\n, \n522\n preventing fluid communication between the volume \n550\n and the wellbore \n104\n.', 'The upper and lower (“outer”) inflatable members \n524\n, \n532\n are inflated and deflated via an outer packer inflation flowline \n560\n, and the intermediate inflatable member \n528\n is inflated and deflated via an inner packer inflation flowline \n564\n.', 'In other implementations, the upper, intermediate, and lower inflatable members \n524\n, \n532\n may be inflated and deflated via the flowline \n560\n, and the intermediate inflatable member \n528\n may be further pressurized (beyond the pressurization of the outer inflatable members \n524\n, \n532\n) via the flowline \n564\n.', 'The inflation fluid may be as described above with respect to \nFIG.', '3\n.', 'Various valves and other circuitry (not shown) may be operable for the inflation and deflation of the inflatable members \n524\n, \n528\n, \n532\n.', 'When the inflatable members \n524\n, \n528\n, \n532\n are inflated, the IPA \n500\n may be operated to inject a fluid from an injection flowline \n568\n into just one or both of the isolated wellbore portions \n540\n, \n541\n via the respective port \n509\n, \n513\n, such as for stress testing the formation \n102\n within a zone of interest.', 'The injected fluid may be injected into just one or both isolated wellbore portions \n540\n, \n541\n, perhaps at a pressure that is high enough to create microfractures in the formation \n102\n, similar to as depicted in \nFIG.', '3\n.', 'The injection fluid may be as described above with respect to \nFIG.', '3\n.', 'Various valves and other circuitry (not shown) may be operable for injection via just one or both ports \n509\n, \n513\n.', 'In operation, while the inflatable members \n524\n, \n528\n, \n532\n are deflated, the IPA \n500\n is conveyed within the wellbore \n104\n until the IPA \n500\n is proximate a zone of interest in the formation \n102\n.', 'The inflatable members \n524\n, \n528\n, \n532\n are then inflated to a first pressure, as described above, such that the inflatable members \n524\n, \n528\n, \n532\n radially expand into sealing engagement with the wellbore wall \n106\n and create the isolated portions \n540\n, \n541\n of the wellbore \n104\n.', 'The intermediate inflatable member \n528\n may then be further pressurized, such as to a fracturing pressure.', 'Fluid may then be injected through just one or both ports \n509\n, \n513\n at a high enough pressure to create microfractures in the formation.', 'The injection is then stopped, and the subsequently decreasing pressure in one or both isolated wellbore portions \n540\n, \n541\n is monitored (e.g., via measuring pressure in the injection flowline \n568\n), such as to determine the fracture closing pressure and the minimum principal stress.', 'The injection and bleed-off process may also be repeated to determine the fracture reopening pressure and the maximum horizontal principal stress.', 'The inflatable members \n524\n, \n528\n, \n532\n may then be deflated for removal of the IPA \n500\n from the wellbore \n104\n or repositioning to another zone of interest for performing additional stress test operations.', 'In implementations in which the volume \n550\n is sealed, the movement of the lower sliding sleeve \n516\n away from the lower fixed sleeve \n520\n may create a decreased pressure in the volume \n550\n.', 'Consequently, as the inflatable members \n524\n, \n528\n, \n532\n are depressurized, the decreased pressure in the volume \n550\n may act to move the lower sliding sleeve \n516\n down towards its initial position.', 'Thus, the lower sliding sleeve \n516\n and the lower fixed sleeve \n520\n may act as an auto-retract mechanism, operable to aid in retracting the inflatable members \n524\n, \n528\n, \n532\n closer to the mandrel \n304\n, thereby reducing the overall diameter of the IPA \n500\n to aid in conveying the IPA \n500\n within the wellbore \n104\n.', 'The inflatable packer assemblies and methods in accordance with one or more aspects of the present disclosure may be utilized with a controller for controlling pump(s), sensors, actuation mechanisms, valves, and other mechanisms.', 'FIG.', '6\n is a schematic view of at least a portion of an example implementation of a processing system \n600\n according to one or more aspects of the present disclosure.', 'The processing system \n600\n may execute example machine-readable instructions to implement at least a portion of one or more of the methods and/or processes described herein, and/or to implement a portion of one or more of the example downhole tools described herein.', 'The processing system \n600\n may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, servers, personal computers, personal digital assistant (PDA) devices, smartphones, internet appliances, and/or other types of computing devices.', 'Moreover, while it is possible that the entirety of the processing system \n600\n shown in \nFIG.', '6\n is implemented within downhole apparatus described above, one or more components or functions of the processing system \n600\n may also or instead be implemented in wellsite surface equipment, perhaps including the surface equipment \n190\n depicted in \nFIG.', '1\n, the surface equipment \n290\n depicted in \nFIG.', '2\n, and/or other surface equipment.', 'The processing system \n600\n may comprise a processor \n612\n, such as a general-purpose programmable processor, for example.', 'The processor \n612\n may comprise a local memory \n614\n, and may execute program code instructions \n632\n present in the local memory \n614\n and/or another memory device.', 'The processor \n612\n may execute, among other things, machine-readable instructions or programs to implement the methods and/or processes described herein.', 'The programs stored in the local memory \n614\n may include program instructions or computer program code that, when executed by an associated processor, cause a controller and/or control system implemented in surface equipment and/or a downhole tool to perform tasks as described herein.', 'The processor \n612\n may be, comprise, or be implemented by one or more processors of various types operable in the local application environment, and may include one or more general-purpose processors, special-purpose processors, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), processors based on a multi-core processor architecture, and/or other processors.', 'The processor \n612\n may be in communication with a main memory \n617\n, such as via a bus \n622\n and/or other communication means.', 'The main memory \n617\n may comprise a volatile memory \n618\n and a non-volatile memory \n620\n.', 'The volatile memory \n618\n may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices.', 'The non-volatile memory \n620\n may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n618\n and/or the non-volatile memory \n620\n.', 'The processing system \n600\n may also comprise an interface circuit \n624\n.', 'The interface circuit \n624\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, and/or a cellular interface, among other examples.', 'The interface circuit \n624\n may also comprise a graphics driver card.', 'The interface circuit \n624\n may also comprise a communication device, such as a modem or network interface card, to facilitate exchange of data with external computing devices via a network, such as via Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, and/or satellite, among other examples.', 'One or more input devices \n626\n may be connected to the interface circuit \n624\n.', 'One or more of the input devices \n626\n may permit a user to enter data and/or commands for utilization by the processor \n612\n.', 'Each input device \n626\n may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an image/code scanner, and/or a voice recognition system, among other examples.', 'One or more output devices \n628\n may also be connected to the interface circuit \n624\n.', 'One or more of the output devices \n628\n may be, comprise, or be implemented by a display device, such as a liquid crystal display (LCD), a light-emitting diode (LED) display, and/or a cathode ray tube (CRT) display, among other examples.', 'One or more of the output devices \n628\n may also or instead be, comprise, or be implemented by a printer, speaker, and/or other examples.', 'The processing system \n600\n may also comprise a mass storage device \n630\n for storing machine-readable instructions and data.', 'The mass storage device \n630\n may be connected to the interface circuit \n624\n, such as via the bus \n622\n.', 'The mass storage device \n630\n may be or comprise a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples.', 'The program code instructions \n632\n may be stored in the mass storage device \n630\n, the volatile memory \n618\n, the non-volatile memory \n620\n, the local memory \n614\n, and/or on a removable storage medium \n634\n, such as a CD or DVD.', 'The mass storage device \n630\n, the volatile memory \n618\n, the non-volatile memory \n620\n, the local memory \n614\n, and/or the removable storage medium \n634\n may each be a tangible, non-transitory storage medium.', 'The modules and/or other components of the processing system \n600\n may be implemented in accordance with hardware (such as in one or more integrated circuit chips, such as an ASIC), or may be implemented as software or firmware for execution by a processor.', 'In the case of firmware or software, the implementation can be provided as a computer program product including a computer readable medium or storage structure containing computer program code (i.e., software or firmware) for execution by the processor.', 'The wellbore \n104\n penetrating one or more subterranean formations \n102\n and others described herein may be an open hole or cased hole, including implementations in which the cased hole has been perforated at the particular zone of interest.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising an inflatable packer assembly for use in a wellbore penetrating a subterranean formation, comprising: a first fixed sleeve fixed to a mandrel; a first sliding sleeve moveable along the mandrel; a first inflatable member connected to the first fixed sleeve and the first sliding sleeve; a second sliding sleeve moveable along the mandrel; a second inflatable member connected to the first sliding sleeve and the second sliding sleeve; a second fixed sleeve fixed to the mandrel and slidably engaging the second sliding sleeve; an inflation flowline disposed within the mandrel and in fluid communication with interiors of the first and second inflatable members for inflating the first and second inflatable members to isolate a portion of the wellbore; and an injection flowline disposed within the mandrel for injecting a fluid into the isolated wellbore portion at a high enough pressure to create microfractures in the subterranean formation.', 'The first sliding sleeve may move along the mandrel in response to inflation and deflation of the first inflatable member, and the second sliding sleeve may move along the mandrel and the second fixed sleeve in response to inflation and deflation of the first and second inflatable members.', 'The inflation flowline and the injection flowline may form separate flowpaths.', 'The inflation flowline and the injection flowline may share a common flowpath.', 'In such implementations, among others within the scope of the present disclosure, the inflatable packer assembly may further comprise a valve in fluid communication between the injection flowline and the isolated wellbore portion to control injecting the fluid into the isolated wellbore portion.', 'The valve may be a relief having a set pressure of about 500 pounds per square inch.', 'The fluid may be injected into the isolated wellbore portion at about 12,000 pounds per square inch.', 'In such implementations, among others within the scope of the present disclosure, the first and second inflatable members may be inflated to a pressure of about 1,000 pounds per square inch.', 'The present disclosure also introduces an apparatus comprising an inflatable packer assembly for use in a wellbore penetrating a subterranean formation, comprising: a first fixed sleeve fixed to a mandrel; a first sliding sleeve moveable along the mandrel; a first inflatable member connected to the first fixed sleeve and the first sliding sleeve; a second sliding sleeve moveable along the mandrel; a second inflatable member connected to the first sliding sleeve and the second sliding sleeve; a third sliding sleeve moveable along the mandrel; a third inflatable member connected to the second sliding sleeve and the third sliding sleeve; a second fixed sleeve fixed to the mandrel and slidably engaging the third sliding sleeve; a first inflation flowline disposed within the mandrel for inflating the first and third inflatable members to a first pressure; a second inflation flowline disposed within the mandrel for inflating the second inflatable member to a second pressure greater than the first pressure, wherein the inflated first, second, and third inflatable members isolate first and second portions of the wellbore; and an injection flowline disposed within the mandrel for injecting a fluid into at least one of the first and second isolated wellbore portions at a high enough pressure to enlarge microfractures in the subterranean formation.', 'The first sliding sleeve may move along the mandrel in response to inflation and deflation of the first inflatable member, the second sliding sleeve may move along the mandrel in response to inflation and deflation of the first and second inflatable members, and the third sliding sleeve may move along the mandrel and the second fixed sleeve in response to inflation and deflation of the first, second, and third inflatable members.', 'The second pressure may be sufficient to create the microfractures.', 'The injected fluid may pressurize the at least one of the first and second isolated wellbore portions to about 12,000 pounds per square inch.', 'In such implementations, among others within the scope of the present disclosure, the first pressure may be about 1,000 pounds per square inch.', 'The present disclosure also introduces a method comprising: conveying an inflatable packer assembly (IPA) in a wellbore such that first and second inflatable members of the IPA straddle at least a portion of a zone of interest of a subterranean formation penetrated by the wellbore; inflating the first and second inflatable members to radially expand the first and second inflatable members into sealing engagement with a wall of the wellbore and thereby isolate a portion of the wellbore, wherein the first inflatable member extends between a fixed sleeve of the IPA and a first sliding sleeve of the IPA, and wherein the second inflatable member extends between the first sliding sleeve and a second sliding sleeve of the IPA, such that inflating the first and second inflatable members moves the first sliding sleeve closer to the fixed sleeve and moves the second sliding sleeve closer to the fixed sleeve and the first sliding sleeve; injecting fluid into the isolated wellbore portion through a port of the first sliding sleeve to create or enlarge micro fractures in the subterranean formation zone of interest; and after stopping the fluid injection, monitoring pressure in the isolated wellbore portion to determine a closing pressure of the microfractures.', 'Injecting the fluid may be to a pressure of at least about 12,000 pounds per square inch (psi).', 'In such implementations, among others within the scope of the present disclosure, inflating the first and second inflatable members may be to a pressure of about 1,000 psi.', 'Inflating the first and second inflatable members to isolate a portion of the wellbore may comprise inflating the first and second inflatable members and a third inflatable member to isolate first and second portions of the wellbore.', 'The third inflatable member may extend between the second sliding sleeve and a third sliding sleeve of the IPA, such that inflating the first, second, and third inflatable members may move the first sliding sleeve closer to the fixed sleeve, may move the second sliding sleeve closer to the fixed sleeve and the first sliding sleeve, and may move the third sliding sleeve closer to the fixed sleeve, the first sliding sleeve, and the second sliding sleeve.', 'In such implementations, among others within the scope of the present disclosure, inflating the first, second, and third inflatable members may comprise: inflating the first and third inflatable members to a first pressure; and inflating the second inflatable member to a second pressure greater than the first pressure.', 'The second pressure may be sufficient to create the microfractures, and injecting the fluid may enlarge the microfractures created by inflation of the second inflating member.', 'Injecting the fluid may be to a pressure of at least about 12,000 pounds per square inch (psi), and the first pressure may be about 1,000 psi.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'An apparatus comprising:\nan inflatable packer assembly for use in a wellbore penetrating a subterranean formation, comprising: a first fixed sleeve fixed to a mandrel; a first sliding sleeve moveable along the mandrel; a first inflatable member connected to the first fixed sleeve and the first sliding sleeve; a second sliding sleeve moveable along the mandrel; a second inflatable member connected to the first sliding sleeve and the second sliding sleeve; a second fixed sleeve fixed to the mandrel and slidably engaging the second sliding sleeve; an inflation flowline disposed within the mandrel and in fluid communication with interiors of the first and second inflatable members for inflating the first and second inflatable members to isolate a portion of the wellbore; and an injection flowline disposed within the mandrel for injecting a fluid into the isolated wellbore portion at a high enough pressure to create microfractures in the subterranean formation.', '2.', 'The apparatus of claim 1 wherein the first sliding sleeve moves along the mandrel in response to inflation and deflation of the first inflatable member, and wherein the second sliding sleeve moves along the mandrel and the second fixed sleeve in response to inflation and deflation of the first and second inflatable members.', '3.', 'The apparatus of claim 1 wherein the inflation flowline and the injection flowline form separate flowpaths.', '4.', 'The apparatus of claim 1 wherein the inflation flowline and the injection flowline share a common flowpath.', '5.', 'The apparatus of claim 4 wherein the inflatable packer assembly further comprises a valve in fluid communication between the injection flowline and the isolated wellbore portion to control injecting the fluid into the isolated wellbore portion.', '6.', 'The apparatus of claim 5 wherein the valve is a relief having a set pressure of about 500 pounds per square inch.', '7.', 'The apparatus of claim 1 wherein the fluid is injected into the isolated wellbore portion at about 12,000 pounds per square inch.', '8.', 'The apparatus of claim 7 wherein the first and second inflatable members are inflated to a pressure of about 1,000 pounds per square inch.', '9.', 'An apparatus comprising:\nan inflatable packer assembly for use in a wellbore penetrating a subterranean formation, comprising: a first fixed sleeve fixed to a mandrel; a first sliding sleeve moveable along the mandrel; a first inflatable member connected to the first fixed sleeve and the first sliding sleeve; a second sliding sleeve moveable along the mandrel; a second inflatable member connected to the first sliding sleeve and the second sliding sleeve; a third sliding sleeve moveable along the mandrel; a third inflatable member connected to the second sliding sleeve and the third sliding sleeve; a second fixed sleeve fixed to the mandrel and slidably engaging the third sliding sleeve; a first inflation flowline disposed within the mandrel for inflating the first and third inflatable members to a first pressure; a second inflation flowline disposed within the mandrel for inflating the second inflatable member to a second pressure greater than the first pressure, wherein the inflated first, second, and third inflatable members isolate first and second portions of the wellbore; and an injection flowline disposed within the mandrel for injecting a fluid into at least one of the first and second isolated wellbore portions at a high enough pressure to enlarge microfractures in the subterranean formation.\n\n\n\n\n\n\n10.', 'The apparatus of claim 9 wherein:\nthe first sliding sleeve moves along the mandrel in response to inflation and deflation of the first inflatable member;\nthe second sliding sleeve moves along the mandrel in response to inflation and deflation of the first and second inflatable members; and\nthe third sliding sleeve moves along the mandrel and the second fixed sleeve in response to inflation and deflation of the first, second, and third inflatable members.', '11.', 'The apparatus of claim 9 wherein the second pressure is sufficient to create the microfractures.', '12.', 'The apparatus of claim 9 wherein the injected fluid pressurizes the at least one of the first and second isolated wellbore portions to about 12,000 pounds per square inch.', '13.', 'The apparatus of claim 12 wherein the first pressure is about 1,000 pounds per square inch.', '14.', 'A method comprising:\nconveying an inflatable packer assembly (IPA) in a wellbore such that first and second inflatable members of the IPA straddle at least a portion of a zone of interest of a subterranean formation penetrated by the wellbore;\ninflating the first and second inflatable members to radially expand the first and second inflatable members into sealing engagement with a wall of the wellbore and thereby isolate a portion of the wellbore, wherein the first inflatable member extends between a fixed sleeve of the IPA and a first sliding sleeve of the IPA, and wherein the second inflatable member extends between the first sliding sleeve and a second sliding sleeve of the IPA, such that inflating the first and second inflatable members moves the first sliding sleeve closer to the fixed sleeve and moves the second sliding sleeve closer to the fixed sleeve and the first sliding sleeve;\ninjecting fluid into the isolated wellbore portion through a port of the first sliding sleeve to create or enlarge microfractures in the subterranean formation zone of interest; and\nafter stopping the fluid injection, monitoring pressure in the isolated wellbore portion to determine a closing pressure of the microfractures.', '15.', 'The method of claim 14 wherein injecting the fluid is to a pressure of at least about 12,000 pounds per square inch (psi).', '16.', 'The method of claim 15 wherein inflating the first and second inflatable members is to a pressure of about 1,000 psi.', '17.', 'The method of claim 14 wherein inflating the first and second inflatable members to isolate a portion of the wellbore comprises inflating the first and second inflatable members and a third inflatable member to isolate first and second portions of the wellbore, wherein the third inflatable member extends between the second sliding sleeve and a third sliding sleeve of the IPA, such that inflating the first, second, and third inflatable members moves the first sliding sleeve closer to the fixed sleeve, moves the second sliding sleeve closer to the fixed sleeve and the first sliding sleeve, and moves the third sliding sleeve closer to the fixed sleeve, the first sliding sleeve, and the second sliding sleeve.', '18.', 'The method of claim 17 wherein inflating the first, second, and third inflatable members comprises:\ninflating the first and third inflatable members to a first pressure; and\ninflating the second inflatable member to a second pressure greater than the first pressure.', '19.', 'The method of claim 18 wherein the second pressure is sufficient to create the microfractures, and wherein injecting the fluid enlarges the microfractures created by inflation of the second inflating member.', '20.', 'The method of claim 18 wherein injecting the fluid is to a pressure of at least about 12,000 pounds per square inch (psi), and wherein the first pressure is about 1,000 psi.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '4 is a schematic view of another example implementation of the apparatus shown in FIG.', '3 according to one or more aspects of the present disclosure.', '; FIG.', '5 is a schematic view of another example implementation of the apparatus shown in FIG.', '3 according to one or more aspects of the present disclosure.', '; FIG.', '6 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG. 1 is a schematic view of an example wellsite system 100 to which one or more aspects of the present disclosure may be applicable.', 'The wellsite system 100 may be onshore or offshore.', 'In the example wellsite system 100 shown in FIG.', '1, a wellbore 104 is formed in one or more subterranean formation 102 by rotary drilling.', 'Other example systems within the scope of the present disclosure may also or instead utilize directional drilling.', 'While some elements of the wellsite system 100 are depicted in FIG.', '1 and described below, it is to be understood that the wellsite system 100 may include other components in addition to, or in place of, those presently illustrated and described.', '; FIG.', '2 is a schematic view of another example wellsite system 200 to which one or more aspects of the present disclosure may be applicable.', 'The wellsite system 200 may be onshore or offshore.', 'In the example wellsite system 200 shown in FIG.', '2, a tool string 204 is conveyed into the wellbore 104 via a wireline and/or other conveyance means 208.', 'As with the wellsite system 100 shown in FIG.', '1, the example wellsite system 200 of FIG.', '2 may be utilized for stress test operations according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of an inflatable packer assembly (IPA) 300 according to one or more aspects of the present disclosure.', 'The IPA 30 is depicted in FIG.', '1 in a “dual-packer arrangement,” although other implementations are also within the scope of the present disclosure.', 'The IPA 300 is for use in a wellbore 104 penetrating a subterranean formation 102, whether via the drill string 112 depicted in FIG.', '1, the wireline 208 depicted in FIG.', '2, and/or other conveyance means within the scope of the present disclosure.;', 'FIG. 5 is a schematic view of another implementation of the IPA 300 shown in FIG.', '1, designated in FIG.', '5 by reference number 500.', 'The IPA 500 is shown as a “triple packer arrangement” for use in the wellbore 104 for testing the formation 102.', 'The IPA 500 shown in FIG. 5 is substantially similar to the IPA shown in FIG.', '3 except as described below.'] |
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US11142955 | Steerable drill bit system | Mar 4, 2020 | Geoffrey Downton | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report issued in PCT application PCT/US2015/064154 dated Mar. 18, 2016, 4 pages.; Written Opinion issued in PCT application PCT/US2015/064154 dated Mar. 18, 2016, 11 pages. | 20040173381; September 9, 2004; Moore et al.; 20070247328; October 25, 2007; Petrovic et al.; 20080000693; January 3, 2008; Hutton; 20090090501; April 9, 2009; Hansen; 20100006341; January 14, 2010; Downton; 20110226470; September 22, 2011; Latrille et al.; 20120132428; May 31, 2012; Polyntsev; 20120145458; June 14, 2012; Downton; 20120234606; September 20, 2012; Hall et al.; 20130092441; April 18, 2013; Hummes et al.; 20140138084; May 22, 2014; Al-Mulhem; 20140262507; September 18, 2014; Marson et al.; 20160130878; May 12, 2016; Cobern; 20160160567; June 9, 2016; Downton | 2007134748; November 2007; WO | ['A steerable drilling system in accordance to an embodiment includes a bias unit integrated with the drill bit to form a steering head and an electronic control system located remote from the steering head and electrically connected to a digital valve of the bias unit.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a continuation of U.S. application Ser.', 'No. 14/957,781, filed on Dec. 3, 2015, which claims priority to U.S. Provisional Application No. 62/089,772, filed on Dec. 9, 2014, the entire contents of which are hereby incorporated by reference herein.', 'BACKGROUND\n \nThis section provides background information to facilitate a better understanding of the various aspects of the disclosure.', 'It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.', 'Oil and gas reservoirs may be accessed by drilling wellbores to enable production of hydrocarbon fluid, e.g. oil and/or gas, to a surface location.', 'In many environments, directional drilling techniques have been employed to gain better access to the desired reservoirs by forming deviated wellbores as opposed to traditional vertical wellbores.', 'Forming deviated wellbore sections can be difficult and requires directional control over the orientation of the drill bit used to drill the deviated wellbore.', 'Rotary steerable drilling systems have been used to drill deviated wellbore sections while enabling control over the drilling directions.', 'Such drilling systems often are classified as push-the-bit systems or point-the-bit systems and allow an operator to change the orientation of the drill bit and thus the direction of the wellbore.', 'In conventional rotary steerable drilling systems, the drill bit section or housing is connected to a steering control section or housing by a field separable connection, such as a standard API (American Petroleum Institute) connection.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter.', 'In accordance to an embodiment a steering head for connecting to a drill string includes an intermediate section comprising two or more steering actuators in operation moveable in a radial direction to provide steering inputs, a first section comprising a digital valve to control flow of pressurized fluid to individual steering actuators of the two or more steering actuators, and a distal section comprising a formation cutting structure, the intermediate section positioned between the first section and the distal section.', 'A steerable drilling system in accordance to an embodiment includes a steering head having a cutting structure, a steering actuator and a digital valve that is operational to port pressurized fluid to the steering actuator, and a control source electrically connected to the digital valve to operate the digital valve.', 'A method in accordance to an embodiment includes utilizing a drill bit having a digital valves and steering actuators to propagate a borehole in a desired direction and applying functionality of one or more of a drilling mechanics module (DMM) and measurement while drilling (MWD) system to control a force and timing of the steering actuators to achieve the desired direction (i.e., meet the borehole propagation).', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The disclosure is best understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic illustration of a drill string and drilling system incorporating a steerable drill bit in accordance to one or more aspects of the disclosure.', 'FIG.', '2\n is a schematic view of a steerable drill bit in operational connection with a measurement while drilling system in accordance to one or more aspects of the disclosure.', 'FIG.', '3\n is a schematic view of a steerable drill bit assembly in operational connection with a drilling dynamics module in accordance to one or more aspects of the disclosure.', 'FIG.', '4\n is a schematic view of steerable bit separated from a downhole control unit by a drilling motor.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements.', 'Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements.', 'Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element are may be utilized to more clearly describe some elements.', 'Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.', 'A steerable drilling system \n20\n in accordance to an embodiment includes steering actuators \n36\n integrated with a drill bit \n32\n and digital valves \n34\n integrated with the drill bit and operational to selectively port pressurized fluid to the steering actuators.', 'Electrical power \n64\n and/or the timing control source \n62\n (i.e., processor) are electrically connected to the digital valves and can be located remote from the drill bit.', "In accordance to some embodiments, the timing control source is provided by a measurement while drilling (MWD) system \n40\n, for example and without limitation, Schlumberger's TeleScope™, PowerPulse™, or ImPulse™ MWD systems.", "In accordance to one or more embodiments the control source is provided by drilling dynamics module (DMM) \n41\n, e.g., Schlumberger's OptiDrill™ system.", 'The DMM may include for example drilling mechanics and dynamics sensors and a processor.', 'As will be understood by those with benefit of this disclosure, other control unit sources may be utilized and electrically connected to the bias unit of the steering system.', 'Electrical power may be provided to the bias unit at the drill bit for example from an onboard electrical source located with the MWD system or the DMM, or from another electrical source (e.g., battery, turbine, etc.).', 'Referring generally to \nFIGS.', '1-4\n, a drilling system \n20\n is illustrated as having a bottom hole assembly (BHA) \n22\n which is part of a drill string \n24\n used to form a desired, directionally drilled wellbore \n26\n.', 'The illustrated drilling system \n20\n comprises a steerable drilling system \n28\n, e.g. a rotary steerable system (RSS), generally including a bias unit \n30\n that is integrated with the drill bit \n32\n body to form a steering head \n100\n and an electronic steering control unit or system (e.g., processor, memory, etc.) generally denoted by the numeral \n62\n operationally connected to the bias unit.', 'Bias unit \n30\n includes control valves \n34\n (e.g., electrically operated digital valves) for directing drilling fluid \n46\n to respective steering actuators \n36\n, e.g., pistons and pads.', 'The steering actuators \n36\n are moved from their retracted positions toward their extended positions in response to receiving the drilling fluid.', 'Return movement of the steering actuators to the retracted position can occur as the drilling fluid supply to the actuator is stopped and the drilling fluid escapes to the annulus, for example via small diameter leakage pathways.', 'The supply of drilling fluid \n46\n to the steering actuators \n36\n is controlled by the digital control valves, the operation of which is controlled by the steering control unit using information derived from, for example, inclination and azimuth sensors, e.g., accelerometers, inclinometers, magnetometers and rate gyros.', 'A single digital valve \n34\n can drive one or two actuators \n36\n as the digital valve has two positions.', 'For example, in a first position a digital valve \n34\n can energize a first actuator and close a second actuator and vice versa in the second position or state of the digital valve.', 'Electrical power is provided to the control system \n62\n and the bias unit \n30\n from an electrical source \n64\n, such as batteries and/or a mud driven turbine.', 'The control system \n62\n may be in communication and designed to interact with sensors \n60\n to sense various parameters including without limitation the toolface direction and thus the direction the wellbore is being propagated.', 'The steering control system may be constructed as a closed loop control for closing the control loop between the directional measurements received from sensors and steering actuator output via the steering actuators.', 'The sensors \n60\n may be located in various locations in the drill string or bottom hole assembly.', 'In accordance to some embodiments, sensors \n60\n may be incorporated into the steering head \n100\n (e.g., the integral drill bit), for example accelerometers, inclinometers, rate gyros, borehole-caliper and magnetometers.', 'In accordance to some embodiments, the sensors \n60\n are incorporated in the MWD module, the DMM, and/or other systems (e.g., logging while drilling module, formation evaluation tools).', 'In accordance to at least one embodiment the steering actuators \n36\n are positioned in or on the bit body \n32\n with the formation cutting elements \n33\n and the control valve(s) \n34\n are disposed with and/or in the drill bit body.', 'In accordance to at least one embodiment, the steering actuators \n36\n are positioned with the bit body and the control valves \n34\n are disposed for example in a sub immediately adjacent to the bit body \n32\n.', 'In accordance to at least one embodiment the formation cutting elements \n33\n or structure, the steering actuators \n36\n (e.g., a ring of actuators), and control valves \n34\n are separate structures that can be assembled to form the steerable drill bit, i.e., steering head \n100\n.', 'For example, the steering head may be assembled at the drilling rig or at a location remote from the drilling rig.', 'Integrated with the drill bit \n32\n includes being located with the drill bit body \n32\n or in a sub positioned between the drill bit body \n32\n and the collar \n38\n, to form the steering head \n100\n.', 'For example, the steering head \n100\n is connected to the drill string \n24\n via a bit shaft \n70\n (\nFIGS.', '2-4\n) disposed with a collar \n38\n.', 'With reference in particular to \nFIGS.', '2-4\n, the integrated steering head \n100\n includes a first or proximate section \n102\n, carrying the digital control valves \n34\n, that is adjacent to the collar \n38\n, a distal end section \n104\n carrying the cutting elements or structures \n33\n, and an intermediate section \n106\n carrying the steering actuators \n36\n.', 'The drill bit body \n32\n forms at least the distal end \n104\n, which carry some or all of the cutting elements \n33\n.', 'The proximate and intermediate sections \n102\n, \n106\n may be portions of a unitary drill bit body \n32\n or be structures connected to the drill bit body \n32\n.', 'One or more of the sections \n102\n, \n104\n, and \n106\n may rotate independent of the other sections, for example provided that the bit cutting structure is driven by rotation of the bit shaft \n70\n, i.e., either the collar \n38\n or a motor drive rotating shaft \n70\n.', 'A single actuator \n36\n could be used to steer if it is rotated with the cutting structure, however, in the case where the actuators are allowed to rotate independent of the cutting structure the system would utilize three actuators and at least two digital valves with four possible positions or states.', 'In accordance with one or more embodiments, the steering actuators \n36\n are capable of independent rotation with respect to the cutting structures \n33\n.', 'For example, the intermediate section \n106\n can rotate independent of the rotation of the distal end section \n104\n carrying the cutting structures \n33\n.', 'In accordance to one or more embodiments, the digital valves \n34\n, i.e. proximate section \n102\n, rotate with the steering actuators \n36\n, i.e. the intermediate section \n106\n.', 'A rotary electrical connection may be made between the digital valves \n34\n and the MWD \n40\n and/or DMM \n41\n systems.', 'Real time measurements may be obtained of the actuator positions relative to the MWD and/or DMM for example utilizing the on-bit sensors \n60\n which may be rotating with the actuator section or fixed with the bit.', 'Depending on the environment and the operational parameters of the drilling job, drilling system \n20\n may comprise a variety of other features.', 'In accordance to embodiments, the bottom hole assembly \n22\n includes a measurement-while-drilling (MWD) module \n40\n.', 'As will be understood with benefit of this disclosure, in accordance to some embodiments the electrical systems of the MWD module \n40\n are electrically connected to the control valves \n34\n (e.g., digital valves) to supply the timing control signals to the control valves \n34\n and actuators \n36\n.', 'In some embodiments, the drilling system \n20\n includes a drilling mechanics module \n41\n (DMM).', 'In accordance to some embodiments supplies timing control signals to the control valves \n34\n.', 'The electrical power source \n64\n and the control system \n62\n are in operational and electrical connection with the bias unit \n30\n.', 'Operational and electrical connection can be provided in various manners.', 'In accordance to one or more embodiments, the steering system may include a drilling mud motor \n37\n.', 'For example, in \nFIG.', '1\n, the DMM and MWD are separated from the bias unit \n30\n and steering head \n100\n by the drilling mud motor.', 'To communicate past the mud motor, electromagnetic wave transmission system may be utilized.', 'Power and communications may be passed through or across the mud motor using wires.', 'Due to the rotation, orbital and axial motion of the mud motor rotor with the drill collar slip rings may be utilized to allow the wires to rotate.', 'Electrical power and/or communication may also be communicated across the mud motor utilizing wire and coil connections.', 'Various surface systems also may form a part of the drilling system \n20\n.', 'In the example illustrated, a drilling rig \n42\n is positioned above the wellbore \n26\n and a drilling mud system \n44\n is used in cooperation with the drilling rig.', 'For example, the drilling mud system \n44\n may be positioned to deliver drilling fluid \n46\n from a drilling fluid tank \n48\n.', 'The drilling fluid \n46\n is pumped through appropriate tubing \n50\n and delivered down through drilling rig \n42\n and into drill string \n24\n.', 'In many applications, the return flow of drilling fluid flows back up to the surface through an annulus \n52\n between the drill string \n24\n and the surrounding wellbore wall (see arrows showing flow down through drill string \n24\n and up through annulus \n52\n).', 'The drilling system \n20\n also may comprise a surface control system \n54\n which may be used to communicate with steerable system \n28\n.', 'The surface control system \n54\n may communicate with steerable system \n28\n in various manners.', 'In accordance to at least one embodiment, the surface control system may be connected to the digital valves for example via wired pipe.', 'Referring in particular to \nFIGS.', '2-4\n, the bias unit \n30\n including the control valves \n34\n, i.e. digital mud valves, and the actuators \n36\n are integrated into the drill bit \n32\n and/or a tubular sub connected directly to the drill bit to form a steering head \n100\n.', 'Conduit(s) \n56\n connect the drilling fluid \n46\n to each of the actuators \n36\n via digital control valves \n34\n.', 'The steering actuators \n36\n include pistons and steering pads.', 'The control valves \n34\n control the porting of the pressurized drilling fluid \n46\n to the piston arrangement driving the steering pads on the steering head to their extended position.', 'The digital control valves \n34\n may be solenoid devices opening and closing in response to an electrical pulse or signal.', 'In accordance to aspects of the disclosure, the conventional rotary steering system control unit is removed and the power and processing complexity of the measurement while drilling \n40\n (MWD) module, see for example \nFIGS.', '2 and 4\n, or of the drilling mechanics module \n41\n (DMM), see for example \nFIG.', '3\n, is used to power and sequence the opening and closing of the digital control valves and thereby operate the steering actuators \n36\n.', 'MWD and drilling mechanics modules are illustrated and described as non-limiting examples of the processing systems \n62\n and power that may be utilized to power and control the steering head based bias unit.', 'The valves may also provide an exhaust pathway to the annulus when the pressurized drilling mud to the valves is curtailed.', 'In \nFIGS.', '2 and 4\n the source of the timing and electrical energy comes for example from an electrical source \n64\n via an electrical connection \n58\n to the digital valves \n34\n.', 'The electrical source \n64\n may be considered a portion of the MWD \n40\n module. \nFIG.', '2\n illustrates the MWD \n40\n positioned close, i.e., adjacent to the steering head \n100\n, however, MWD \n40\n may be separated from the steering head \n100\n for example by a mud motor \n37\n (e.g., \nFIG.', '4\n) or other system.', 'MWD \n40\n includes the sensors \n60\n, processor \n62\n, and power source \n64\n that is required to control and operate the bias unit \n30\n (valves and actuators) integrated with the drill bit \n32\n.', "The steering process needs a sense of direction and this can come from the MWD's direction and inclination (D&I) sensors \n60\n.", 'The MWD \n40\n needs to be in communication with the surface for example via the telemetry system \n68\n, which may be part of the MWD as is traditional, for example, and without limitation, via a siren pulser or in communication with a remote pressure pulser.', 'The MWD knows the current orientation of drilling and can be told the new set point orientation or curvature for steering from the surface.', 'The MWD can also measure toolface in real time and this is required to time the phase and duration of the on/off commands to the digital actuators.', 'In \nFIG.', '3\n the source of the timing and electrical energy comes from the DMM \n41\n via an electrical connection \n58\n to the digital control valves \n34\n integrated in the steering head \n100\n.', 'The DMM \n41\n may supply the power from its on board batteries \n64\n or from a connected powered subsystem, e.g., turbine, somewhere above in the drill string, see e.g. connection \n66\n.', 'DMM \n41\n is particularly well suited for this function in that it contains all the sensors \n60\n, processor \n62\n, information and power \n64\n services required.', 'The steering process needs a sense of direction and this comes from D&I sensors in the DMM.', 'The DMM needs to be connected through to other systems that are in communication with the surface, for example via a telemetry system for example located with the MWD.', 'Either way it knows the current orientation of drilling and can be told the new set point orientation or curvature for steering from the surface.', 'The DMM can also measure toolface in real time and this is required to time the phase and duration of the on/off commands to the digital control valves \n34\n and steering actuators \n36\n.', 'Furthermore the DMM measures drilling loads and torques and can therefore be used in a curvature feedback loop to improve the systems curvature response.', 'The DMM also measures internal and external pressure and can therefore calculate pad force.', 'By modulating the duration of the pad open/close time a measure of force control can be introduced at the steering actuators \n36\n.', 'The DMM \n41\n may also be equipped with a caliper, e.g., electronic or ultrasonic, and as an extension of a flight management sensor fusion role that the DMM is able to perform within the total drilling control system.', 'This will make dogleg control even better as the short wave undulation of tortuosity will be made visible and suitable corrective measures introduced.', 'Also, the abrasion effects of the pads on the borehole, its opening up of the hole and consequent loss of dogleg will become visible and open to better remedial steps than are available today through improved control over the pad forces.', 'In accordance to aspects of the disclosure, the DMM may effectively become the heart of the steerable drilling system replacing the traditional MWD and RSS.', 'In accordance with at least one embodiment, the DMM \n41\n and MWD \n44\n are separated from the bias unit \n30\n portion of the steerable drilling system for example with another collar or physical system between the DMM and MWD and the bias unit, e.g. a drilling mud motor.', 'The same functionality is provided and available except that there is a long connection from the DMM and/or MWD through the intermediate tool.', 'The digital valves \n34\n may be controlled via an electrical connection, e.g. wired pipe, to another part of the BHA, drill string or directly from the surface.', 'In accordance to at least one embodiment, the system is a networked system where some or all of the BHA tools are connected to a power and communication system.', 'Under these conditions the steering head \n100\n would receive the power and control form the network under the control of a system master which may be resident in the MWD, DMM tool or another tool of the requisite measurement capability.', 'Upon torqueing up the steering head \n100\n with the drill string \n24\n the angular orientation between datums would be random or at least difficult to define with any precision in advance.', 'However, the alignment between the steering actuator \n36\n positions on the steering head \n100\n and the MWD \n40\n and the DMM \n41\n measurement systems should be determined within an acceptable tolerance level, for example better than 5 degrees, in order that the correct steering actuators \n36\n are activated at the correct time.', 'Where the steering head system contains a measurement of toolface, i.e. on bit sensors \n60\n, then the digital set-point of toolface is all that is required; the alignment between the steering head sensors, e.g., magnetometer and accelerometers, and the steering actuators would be defined, measured, and/or set during assembly and testing.', 'In the case where no toolface measurement is resident within the steering head then the alignment can be determined by measuring the angular offset between a datum mark on the steering head (e.g., the first section \n102\n) and a datum mark on the MWD and/or DMM collar \n38\n and this information transmitted to the MWD and/or DMM by telemetry as the toolface during the running in hole process.', 'In accordance to one or more embodiments, a first connector (e.g., male-connector) from the MWD \n40\n or DMM \n41\n could contain an indexing feature be it mechanical, capacitive, inductive, magnetic or optical in form that is read by the second connector (e.g., female connector) on the steering head system to determine the offset.', 'In accordance to some embodiments, the relative angular offset can be determined implicitly for example by a short trial steering period where the offset is determined by the direction in which the hole is propagated, as measured by the MWD and/or the DMM.', 'In accordance to some embodiments, as part of the running in hole process, a datum actuator is cycled at a defined frequency as the steering head is rotated into and touching the borehole wall, the motion sensed by the MWD and/or DMM as the actuator flutters against the borehole is monitored to determine the relative position of the datum actuator.', 'This may be a crude estimate of offset, but will provide a nominal offset for the previous implicit steering response approach, so that steering will generally be in the right direction.', 'Because the MWD and DMM are making measurements all the time they can determine the phase of drilling operation and can instruct the digital valves \n34\n to shut off the drilling fluid supply to the steering actuators \n36\n thus preserving life.', 'For example, when in the neutral (drilling straight ahead) steering mode the MWD and DMM can periodically switch off the drilling fluid supply to the steering actuators thus preserving actuator life that cannot easily be done with a single axis rotary valve system.', 'Due to their superior measurements, the MWD, DMM and surface systems can determine the changes in toolface offset that are continually occurring while drilling through different formations and under varying drilling conditions and alter the phasing of the toolface commands to the bit-system in compensation.', 'On a shorter times scale, sub bit rotation periods, the MWD, DMM and surface systems can alter the “on” duration of the digital valves \n34\n thereby altering the integrated force effectiveness of the steering actuators.', 'By such means a measure of force control is introduced to the steering action rather than a fixed angular duration push force.', 'This can be of utility for soft formation drilling where it is not desired to excavate too much of the borehole wall with the steering pads.', 'Because a digital connection exists between the steering head \n100\n and the more intelligent machines like the MWD \n40\n, DMM \n41\n, and surface control system \n54\n measurements of other quantities in the steering head can be relayed for processing and action that lead to a modification of the digital valve steering behavior, i.e., an information loop back to the steering head via an external system rather than all coming directly from an internal system.', 'For example temperature measurements at the steering head can be relayed and the operation of the steering actuators may be altered when the steering head temperature is excessive for example to preserve seal life.', 'Similarly, bit vibration may be detected and the steering actuator firing sequence may be altered to dampen the vibrations.', 'In accordance to an embodiment the digital valve system, e.g., bias unit \n30\n, may be utilized as an MWD mud pulse telemetry system.', 'The flow rate of the drilling fluid diverted to the steering actuators \n36\n is relatively high, e.g. 20 to 30 gallons per minute (gpm) per actuator, which is effectively leaked to the annulus.', 'At these flow rates a pressure pulse at the bit is generated on the order of 100 psi.', 'By modulating this pressure pulse information can be encoded on the wave form for decoding elsewhere along the drill string and/or at the surface.', 'The bias unit \n30\n may be utilized to transmit information off of the bit, such as pad force, pad stroke and other drilling parameters.', 'Utilizing the bias unit \n30\n for mud pulse telemetry can allow for limiting the cost, length and complexity of the MWD modulator.', 'Because the digital valves \n34\n are resident with the bit, i.e. the steering head \n100\n, it is easier to remove, refurbish and/or replace the digital valves and actuators \n36\n locally, for example at the drilling rig or at a shop in the drilling region.', 'The debris filter in the bias unit that screens particles that may jam the digital valves and actuators may be located at the steering head and thus easier to access as part of the steering head than located in a long, heavy and unwieldy collar.', 'It is easier to flush the steering system of debris between runs where the system is located in the steering head as opposed to being located in a long collar.', 'The bit system functionality can be tested at the drilling site before assembly into the drill string \n24\n.', 'A test bench mimicking the MWD and DMM services can be an effective approach to system test and fault find.', 'The disclosed steering system provides enhanced fault tolerance.', 'As the digital valves \n34\n act independently the system is more reliable than conventional single axis rotary valve systems.', 'If any one of the digital valves \n34\n fails the remaining digital valves and corresponding actuators \n36\n can continue to steer the wellbore, albeit at a reduced efficiency.', 'Similarly, if a steering actuator \n36\n fails (e.g., blown seal, wash out) the corresponding digital valve \n34\n can be closed to shut off the supply of drilling fluid so that a complete washout does not occur.', 'The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure.', 'Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the disclosure.', 'The scope of the invention should be determined only by the language of the claims that follow.', 'The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group.', 'The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.'] | ['1.', 'A method for propagating a borehole in a desired direction, comprising:\noperating a bias unit by controlling first, second, and third digital valves to actuate first, second, and third steering actuators;\napplying a first force and timing to the first, second, and third steering actuators;\nmeasuring a distance to a borehole wall;\nmeasuring a direction or an inclination; and\nmodulating the first force and timing to a second force and timing of the first, second, and third steering actuators based on the measured distance to the borehole wall and in response to the measured direction or inclination.', '2.', 'The method of claim 1, further comprising communicating information from the bias unit by operating at least one of the first, second, and third digital valves as a mud pulse telemetry system with a pressure pulse of approximately 100 psi.\n\n\n\n\n\n\n3.', 'The method of claim 1, wherein bit vibration is detected and an actuation sequence of the first, second, and third actuators is modulated to dampen the detected vibration.', '4.', 'The method of claim 1, further comprising causing the first, second, and third digital valves to periodically actuate and deactuate the corresponding first, second, and third steering actuators when drilling straight ahead.', '5.', 'The method of claim 1, an actuator flow rate of a pressurized drilling fluid across at least one of the first, second, and third actuators being between 20 and 30 gallons per minute (gpm) per actuator.', '6.', 'The method of claim 1, wherein modulating the first force and timing to a second force and timing includes changing a duration of the timing of actuation of the first, second, and third actuators.', '7.', 'The method of claim 1, further comprising rotating an MWD independently of the bias unit.', '8.', 'The method of claim 7, further comprising transmitting information between the MWD and the bias unit with a rotary electrical connection.', '9.', 'The method of claim 1, wherein measuring the distance to the borehole wall is accomplished with a caliper sensor.', '10.', 'A method for propagating a borehole in a desired direction, comprising:\nselectively opening first, second, and third digital valves with a first timing;\nflowing fluid from the first, second, and third digital valves to corresponding first, second, and third actuators;\nactuating the first, second, and third actuators with a first force and the first timing based on the opening of the first, second, and third digital valves;\nmeasuring a direction or an inclination;\nmeasuring a distance to a borehole wall;\nmodulating the opening of the first, second, and third digital valves with the first timing to opening the first, second, and third digital valves with a second timing based on the measured distance to the borehole wall and based on the measured direction or inclination; and\nmodulating actuating the first, second, and third actuators with the first force to actuating the first, second, and third actuators with a second force and the second timing based on the measured distance to the borehole wall and based on the measured direction or inclination.\n\n\n\n\n\n\n11.', 'The method of claim 10, wherein flowing fluid includes flowing the fluid from a drill string.', '12.', 'The method of claim 10, wherein selectively opening the first, second, and third digital valves includes opening and closing solenoid valves in response to an electrical signal.', '13.', 'The method of claim 10, further comprising flowing fluid from the first, second, and third actuators to an annulus through an exhaust pathway.', '14.', 'The method of claim 10, further comprising applying a curvature feedback loop based on measuring the direction or the inclination.', '15.', 'The method of claim 10, wherein measuring the distance to the borehole wall is accomplished with a caliper sensor.', '16.', 'The method of claim 10, further comprising closing one of the first, second, and third digital valves in response to the corresponding first, second, and third actuator failing.', '17.', 'A bias unit, comprising:\nfirst, second, and third digital valves, the first, second, and third digital valves including only a first position and a second position;\na sensor configured to measure a distance to a borehole wall;\nfirst, second, and third actuators connected to the first, second, and third digital valves with corresponding first, second, and third conduits; and\na control unit configured to change a force and timing of actuation of the first, second, and third digital valves based on the distance measured to the borehole wall and based on azimuth and inclination information.', '18.', 'The bias unit of claim 17, further comprising at least one additional sensor.\n\n\n\n\n\n\n19.', 'The bias unit of claim 18, wherein the at least one additional sensor is configured to measure the azimuth and inclination information.', '20.', 'The bias unit of claim 17, wherein the is caliper sensor.'] | ['FIG.', '1 is a schematic illustration of a drill string and drilling system incorporating a steerable drill bit in accordance to one or more aspects of the disclosure.', '; FIG.', '2 is a schematic view of a steerable drill bit in operational connection with a measurement while drilling system in accordance to one or more aspects of the disclosure.', '; FIG.', '3 is a schematic view of a steerable drill bit assembly in operational connection with a drilling dynamics module in accordance to one or more aspects of the disclosure.', '; FIG.', '4 is a schematic view of steerable bit separated from a downhole control unit by a drilling motor.'] |
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US11143775 | Automated offset well analysis | May 9, 2019 | Cheolkyun Jeong, Francisco Jose Gomez, Maurice Ringer, Paul Bolchover, Paul Muller | Schlumberger Technology Corporation | Abimbola et al. ,Safety and risk analysis of managed pressure drilling operation using Bayesian network (Year: 2015).; International Search Report and Written Opinion dated Aug. 20, 2020 in International Application No. PCT/US2020/032320, 10 pages. | 9934338; April 3, 2018; Germain et al.; 10280732; May 7, 2019; Dursun et al.; 20130341093; December 26, 2013; Jardine et al.; 20140365409; December 11, 2014; Burch; 20170191359; July 6, 2017; Dursun; 20180114158; April 26, 2018; Foubert; 20190345809; November 14, 2019; Jain | 106150476; November 2016; CN; 2008089345; July 2008; WO; 2015116101; August 2015; WO | ['A method, computing system, and non-transitory computer-readable medium, of which the method includes receiving offset well data collected while drilling one or more offset wells, generating a machine learning model configured to predict drilling risks from drilling measurements or inferences, based on the offset well data, receiving drilling parameters for a new well, determining that the drilling parameters are within an engineering design window, generating a drilling risk profile for the new well using the machine learning model, and adjusting one or more of the drilling parameters for the new well, after determining the drilling parameters are within the engineering design window, and after determining the drilling risk profile, based on the drilling risk profile.'] | ['Description\n\n\n\n\n\n\nBACKGROUND', 'In the oil and gas industry, offset well information obtained from already-drilled neighbor wells provides data that can be analyzed in order to decrease the uncertainty for a new well.', 'That is, any hazards or risks experienced while drilling the offset well may be used to guide the planning and development of the new well.', 'Currently, this analysis relies on human drilling engineers to execute a manual process of risk identification.', 'In general, the engineers gather the offset well information and empirically project a potential risk in drilling the new well.', 'The drilling parameters, well location and/or trajectory, etc. can then be modified to minimize such risk.', 'Thus, this analysis provides a rough guidance for drill planning or operation.', 'The accuracy of this guidance often turns out to be low in practice, however.', 'This may be partially caused by relying on qualitative and manual forecasting of the risk based on human intuition.', 'Based on the qualitative probability and severity, the offset well risk is computed and the results are used for prediction of a new well.', 'As such, the analysis is subject to variations due to human subjectivity and levels of skill and experience.', 'Furthermore, the experienced risks may not be calibrated for the differences between the offset well and the new well, and thus the risk events in the new well may occur at a different depth and/or with different severity based on the different characteristics of the wells.', 'Accordingly, there remains a relatively high level of uncertainty in the application of the offset well analysis.', 'SUMMARY\n \nEmbodiments of the disclosure may provide a method including receiving offset well data collected while drilling one or more offset wells, generating a machine learning model configured to predict drilling risks from drilling measurements or inferences, based on the offset well data, receiving drilling parameters for a new well, determining that the drilling parameters are within an engineering design window, generating a drilling risk profile for the new well using the machine learning model, and adjusting one or more of the drilling parameters for the new well, after determining the drilling parameters are within the engineering design window, and after determining the drilling risk profile, based on the drilling risk profile.', 'Embodiments of the disclosure may also provide a computing system including one or more processors and a memory system including one or more non-transitory computer-readable media storing instructions that, when executed by at least one of the one or more processors, cause the computing system to perform operations.', 'The operations include receiving offset well data collected while drilling one or more offset wells, generating a machine learning model configured to predict drilling risks from drilling measurements or inferences, based on the offset well data, receiving drilling parameters for a new well, determining that the drilling parameters are within an engineering design window, generating a drilling risk profile for the new well using the machine learning model, and adjusting one or more of the drilling parameters for the new well, after determining the drilling parameters are within the engineering design window, and after determining the drilling risk profile, based on the drilling risk profile.', 'Embodiments of the disclosure may further provide a non-transitory computer-readable medium storing instructions that, when executed by at least one processor of a computing system, cause the computing system to perform operations.', 'The operations include receiving offset well data collected while drilling one or more offset wells, generating a machine learning model configured to predict drilling risks from drilling measurements or inferences, based on the offset well data, receiving drilling parameters for a new well, determining that the drilling parameters are within an engineering design window, generating a drilling risk profile for the new well using the machine learning model, and adjusting one or more of the drilling parameters for the new well, after determining the drilling parameters are within the engineering design window, and after determining the drilling risk profile, based on the drilling risk profile.', 'It will be appreciated that this summary is intended merely to introduce some aspects of the present methods, systems, and media, which are more fully described and/or claimed below.', 'Accordingly, this summary is not intended to be limiting.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThe accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the present teachings and together with the description, serve to explain the principles of the present teachings.', 'In the figures:\n \nFIG.', '1\n illustrates an example of a system that includes various management components to manage various aspects of a geologic environment, according to an embodiment.\n \nFIG.', '2\n illustrates a flowchart of a method for planning a well, according to an embodiment.\n \nFIG.', '3\n illustrates a functional block diagram of a Bayesian Belief Network, according to an embodiment.\n \nFIG.', '4\n illustrates a method for drilling a well, according to an embodiment.\n \nFIG.', '5\n illustrates plots of examples of drilling parameters, according to an embodiment.\n \nFIG.', '6\n illustrates a display of an output of an engineering assessment for a well plan using specified parameters, according to an embodiment.\n \nFIG.', '7\n illustrates a view of a risk profile for a plan that meets engineering specifications, according to an embodiment.\n \nFIG.', '8\n illustrates plots of the example drilling parameters along with recommended adjustments thereto, according to an embodiment.\n \nFIG.', '9\n illustrates a view of a risk profile for the plan implementing the recommended adjustments, according to an embodiment.\n \nFIG.', '10\n illustrates a plot of projected risk from offset wells, according to an embodiment.\n \nFIG.', '11\n illustrates a schematic view of a computing system, according to an embodiment.', 'DETAILED DESCRIPTION\n \nReference will now be made in detail to embodiments, examples of which are illustrated in the accompanying drawings and figures.', 'In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the invention.', 'However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details.', 'In other instances, well-known methods, procedures, components, circuits, and networks have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.', 'It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms.', 'These terms are only used to distinguish one element from another.', 'For example, a first object or step could be termed a second object or step, and, similarly, a second object or step could be termed a first object or step, without departing from the scope of the present disclosure.', 'The first object or step, and the second object or step, are both, objects or steps, respectively, but they are not to be considered the same object or step.', 'The terminology used in the description herein is for the purpose of describing particular embodiments and is not intended to be limiting.', 'As used in this description and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise.', 'It will also be understood that the term “and/or” as used herein refers to and encompasses any possible combinations of one or more of the associated listed items.', 'It will be further understood that the terms “includes,” “including,” “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.', 'Further, as used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context.', 'Attention is now directed to processing procedures, methods, techniques, and workflows that are in accordance with some embodiments.', 'Some operations in the processing procedures, methods, techniques, and workflows disclosed herein may be combined and/or the order of some operations may be changed.', 'FIG.', '1\n illustrates an example of a system \n100\n that includes various management components \n110\n to manage various aspects of a geologic environment \n150\n (e.g., an environment that includes a sedimentary basin, a reservoir \n151\n, one or more faults \n153\n-\n1\n, one or more geobodies \n153\n-\n2\n, etc.).', 'For example, the management components \n110\n may allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment \n150\n.', 'In turn, further information about the geologic environment \n150\n may become available as feedback \n160\n (e.g., optionally as input to one or more of the management components \n110\n).', 'In the example of \nFIG.', '1\n, the management components \n110\n include a seismic data component \n112\n, an additional information component \n114\n (e.g., well/logging data), a processing component \n116\n, a simulation component \n120\n, an attribute component \n130\n, an analysis/visualization component \n142\n and a workflow component \n144\n.', 'In operation, seismic data and other information provided per the components \n112\n and \n114\n may be input to the simulation component \n120\n.', 'In an example embodiment, the simulation component \n120\n may rely on entities \n122\n.', 'Entities \n122\n may include earth entities or geological objects such as wells, surfaces, bodies, reservoirs, etc.', 'In the system \n100\n, the entities \n122\n can include virtual representations of actual physical entities that are reconstructed for purposes of simulation.', 'The entities \n122\n may include entities based on data acquired via sensing, observation, etc. (e.g., the seismic data \n112\n and other information \n114\n).', 'An entity may be characterized by one or more properties (e.g., a geometrical pillar grid entity of an earth model may be characterized by a porosity property).', 'Such properties may represent one or more measurements (e.g., acquired data), calculations, etc.', 'In an example embodiment, the simulation component \n120\n may operate in conjunction with a software framework such as an object-based framework.', 'In such a framework, entities may include entities based on pre-defined classes to facilitate modeling and simulation.', 'A commercially available example of an object-based framework is the MICROSOFT® .NET® framework (Redmond, Wash.), which provides a set of extensible object classes.', 'In the .NET® framework, an object class encapsulates a module of reusable code and associated data structures.', 'Object classes can be used to instantiate object instances for use in by a program, script, etc.', 'For example, borehole classes may define objects for representing boreholes based on well data.', 'In the example of \nFIG.', '1\n, the simulation component \n120\n may process information to conform to one or more attributes specified by the attribute component \n130\n, which may include a library of attributes.', 'Such processing may occur prior to input to the simulation component \n120\n (e.g., consider the processing component \n116\n).', 'As an example, the simulation component \n120\n may perform operations on input information based on one or more attributes specified by the attribute component \n130\n.', 'In an example embodiment, the simulation component \n120\n may construct one or more models of the geologic environment \n150\n, which may be relied on to simulate behavior of the geologic environment \n150\n (e.g., responsive to one or more acts, whether natural or artificial).', 'In the example of \nFIG.', '1\n, the analysis/visualization component \n142\n may allow for interaction with a model or model-based results (e.g., simulation results, etc.).', 'As an example, output from the simulation component \n120\n may be input to one or more other workflows, as indicated by a workflow component \n144\n.', 'As an example, the simulation component \n120\n may include one or more features of a simulator such as the ECLIPSE reservoir simulator (Schlumberger Limited, Houston Tex.), the INTERSECT reservoir simulator (Schlumberger Limited, Houston Tex.), etc.', 'As an example, a simulation component, a simulator, etc. may include features to implement one or more meshless techniques (e.g., to solve one or more equations, etc.).', 'As an example, a reservoir or reservoirs may be simulated with respect to one or more enhanced recovery techniques (e.g., consider a thermal process such as SAGD, etc.).', 'In an example embodiment, the management components \n110\n may include features of a commercially available framework such as the PETREL® seismic to simulation software framework (Schlumberger Limited, Houston, Tex.).', 'The PETREL® framework provides components that allow for optimization of exploration and development operations.', 'The PETREL® framework includes seismic to simulation software components that can output information for use in increasing reservoir performance, for example, by improving asset team productivity.', 'Through use of such a framework, various professionals (e.g., geophysicists, geologists, and reservoir engineers) can develop collaborative workflows and integrate operations to streamline processes.', 'Such a framework may be considered an application and may be considered a data-driven application (e.g., where data is input for purposes of modeling, simulating, etc.).', 'In an example embodiment, various aspects of the management components \n110\n may include add-ons or plug-ins that operate according to specifications of a framework environment.', 'For example, a commercially available framework environment marketed as the OCEAN® framework environment (Schlumberger Limited, Houston, Tex.) allows for integration of add-ons (or plug-ins) into a PETREL® framework workflow.', 'The OCEAN® framework environment leverages .NET® tools (Microsoft Corporation, Redmond, Wash.) and offers stable, user-friendly interfaces for efficient development.', 'In an example embodiment, various components may be implemented as add-ons (or plug-ins) that conform to and operate according to specifications of a framework environment (e.g., according to application programming interface (API) specifications, etc.).', 'FIG.', '1\n also shows an example of a framework \n170\n that includes a model simulation layer \n180\n along with a framework services layer \n190\n, a framework core layer \n195\n and a modules layer \n175\n.', 'The framework \n170\n may include the commercially available OCEAN® framework where the model simulation layer \n180\n is the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.', 'In an example embodiment, the PETREL® software may be considered a data-driven application.', 'The PETREL® software can include a framework for model building and visualization.', 'As an example, a framework may include features for implementing one or more mesh generation techniques.', 'For example, a framework may include an input component for receipt of information from interpretation of seismic data, one or more attributes based at least in part on seismic data, log data, image data, etc.', 'Such a framework may include a mesh generation component that processes input information, optionally in conjunction with other information, to generate a mesh.', 'In the example of \nFIG.', '1\n, the model simulation layer \n180\n may provide domain objects \n182\n, act as a data source \n184\n, provide for rendering \n186\n and provide for various user interfaces \n188\n.', 'Rendering \n186\n may provide a graphical environment in which applications can display their data while the user interfaces \n188\n may provide a common look and feel for application user interface components.', 'As an example, the domain objects \n182\n can include entity objects, property objects and optionally other objects.', 'Entity objects may be used to geometrically represent wells, surfaces, bodies, reservoirs, etc., while property objects may be used to provide property values as well as data versions and display parameters.', 'For example, an entity object may represent a well where a property object provides log information as well as version information and display information (e.g., to display the well as part of a model).', 'In the example of \nFIG.', '1\n, data may be stored in one or more data sources (or data stores, generally physical data storage devices), which may be at the same or different physical sites and accessible via one or more networks.', 'The model simulation layer \n180\n may be configured to model projects.', 'As such, a particular project may be stored where stored project information may include inputs, models, results and cases.', 'Thus, upon completion of a modeling session, a user may store a project.', 'At a later time, the project can be accessed and restored using the model simulation layer \n180\n, which can recreate instances of the relevant domain objects.', 'In the example of \nFIG.', '1\n, the geologic environment \n150\n may include layers (e.g., stratification) that include a reservoir \n151\n and one or more other features such as the fault \n153\n-\n1\n, the geobody \n153\n-\n2\n, etc.', 'As an example, the geologic environment \n150\n may be outfitted with any of a variety of sensors, detectors, actuators, etc.', 'For example, equipment \n152\n may include communication circuitry to receive and to transmit information with respect to one or more networks \n155\n.', 'Such information may include information associated with downhole equipment \n154\n, which may be equipment to acquire information, to assist with resource recovery, etc.', 'Other equipment \n156\n may be located remote from a well site and include sensing, detecting, emitting or other circuitry.', 'Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.', 'For example, \nFIG.', '1\n shows a satellite in communication with the network \n155\n that may be configured for communications, noting that the satellite may additionally or instead include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).', 'FIG.', '1\n also shows the geologic environment \n150\n as optionally including equipment \n157\n and \n158\n associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures \n159\n.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop a laterally extensive reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment \n157\n and/or \n158\n may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.', 'As mentioned, the system \n100\n may be used to perform one or more workflows.', 'A workflow may be a process that includes a number of worksteps.', 'A workstep may operate on data, for example, to create new data, to update existing data, etc.', 'As an example, a may operate on one or more inputs and create one or more results, for example, based on one or more algorithms.', 'As an example, a system may include a workflow editor for creation, editing, executing, etc. of a workflow.', 'In such an example, the workflow editor may provide for selection of one or more pre-defined worksteps, one or more customized worksteps, etc.', 'As an example, a workflow may be a workflow implementable in the PETREL® software, for example, that operates on seismic data, seismic attribute(s), etc.', 'As an example, a workflow may be a process implementable in the OCEANS framework.', 'As an example, a workflow may include one or more worksteps that access a module such as a plug-in (e.g., external executable code, etc.).', 'FIG.', '2\n illustrates a flowchart of a method \n200\n for planning a well, according to an embodiment.', 'The method \n200\n may include receiving offset well data, as at \n202\n.', 'The offset wells may be selected from a database of previously-drilled wells.', 'The database may store risks and/or hazards that were encountered in a previously-drilled well.', 'The risks or hazards may be stored in association with drilling conditions that led to the hazards, e.g., drilling parameters such as over balance pressure, flow rate, rotation rate/speed, depth, weight on bit), as well as wellbore trajectory, geological information about rock formations, etc.', 'Further, the offset well data may be collected from any number of relevant wells, e.g., any wells within a threshold distance and/or of a similar depth, trajectory, etc., as to the planned new well.', 'The method \n200\n may then proceed to determining whether an automated inference system was run for identifying risks in the wellbore, as at \n204\n.', 'An example of an automated inference system in shown in \nFIG.', '3\n.', 'In this illustration, a risk of differential sticking is identified based on drilling conditions, but it will be appreciated that this is merely one type of risk that could be identified.', 'Other types of risks that may be identified include solid-induced pack-off risk and geometry risk.', 'The automated risk inference system transforms raw data/measurements into actionable insight.', 'In \nFIG.', '3\n, for example, a potential of differential sticking agent, a friction factor agent, and a break over torque agent monitor the measured data based on each physics-based model.', 'Based on the computation in each module (agent), the inference system identifies an abnormal situation probabilistically.', 'The automated inference system is based on a Bayesian belief network and combines the monitored risk probabilistically.', 'Likewise, other the stuck-pipe related risks, such as solid-induced pack-off risk and geometry risk can be modeled and identified by the automated inference system.', 'The next stage of the method \n200\n may be to build a machine learning model that identifies risks in a planned well based on drilling measurements and/or parameters.', 'If the automated inference system was run, as determined at \n204\n, the method \n200\n may include building the machine learning model based on those interpreted risks, as at \n206\n.', 'Otherwise, the method \n200\n may build the machine learning model based on observed drilling risks, as at \n208\n.', 'The machine learning model may be configured to predict a percentage risk based on the drilling parameters used in the offset well.', 'With the machine learning model built, the method \n200\n may proceed to predicting drilling risks in the new well using the machine learning model, as at \n210\n.', 'Such predictions may inform users of likely drilling risks, and thus allow for changed drilling plans (e.g., well location or trajectory, drilling equipment selection, drilling parameters).', 'The predictions may also be used to reinforce a Bayesian Belief Network, as at \n212\n.', 'FIG.', '3\n illustrates an example of a Bayesian Belief Network (BBN) \n300\n.', 'The BBN \n300\n combines various probabilities with connected reasons or causes and effects.', 'Using a generic, simplistic example, a BBN can be used to detect lung cancer.', 'Reasons and observations about contracting lung cancer can be used in a BBN, for example, smoking (reason), factory working (reason), X-ray (observation), CT-scan (observation).', 'Then, the BBN can be used to probabilistically compute what the possibility of lung cancer is, based on the reasons and observations.', 'The BBN \n300\n may proceed in this same manner.', 'The aforementioned physics-based models/modules monitor the specialized problems and report in real-time.', 'Then BBN \n300\n systematically integrate the information for users.', 'The reinforcement at \n212\n may be accomplished using the BBN \n300\n of \nFIG.', '3\n.', 'The predicted risks in a pre-drill condition will be used as prior knowledge in hole condition monitoring (HCM) risk computation.', 'The predicted risk is a guide map before drilling whether certain drilling issues observed in offset wells are likely to be experienced in a new well, or not.', 'However, in real-time drilling, the prediction is merged with actual observations and measurements for confirming the drilling problems.', 'In a BBN framework, it is another agent providing ‘potential of drilling risks’ trained from offset wells nearby.', 'FIG.', '4\n illustrates another flowchart of a method \n400\n for drilling, according to an embodiment.', 'The method \n400\n may include receiving offset well data, as at \n402\n.', 'The method \n400\n may also include training a machine learning model based on the offset well data, as at \n404\n.', 'As noted above, the offset well data may have been processed by an automatic inference system configured to identify risks based on drilling parameters, geology etc.', 'In such case, the offset well data may be considered to include such inference information.', 'In other situations, the offset well data may not have been processed in this manner, and thus the offset well data may include drilling parameters and observed drilling conditions, e.g., including hazards encountered.', 'The method \n400\n may proceed to receiving drilling parameters for a new well, as at \n406\n, and determining that the drilling parameters meet engineering specifications for well equipment, as at \n408\n.', 'A well plan may specify many different drilling parameters.', 'FIG.', '5\n illustrates plots of four examples of such drilling parameters, namely, over balance pressure, flow rate, rotation rate, and bit depth.', 'These drilling parameters may be fed to a model of the subterranean domain, using the drilling system components selected, in order to determine that the drilling parameters meet engineering specifications for the well equipment, as at \n408\n.', 'An example of the output of such a model is shown in \nFIG.', '6\n.', "This may be a threshold determination; if the drilling parameters result in loads on the equipment that exceed the equipment's capabilities, the drilling parameters may be rejected, or the well equipment may be changed.", 'The method \n400\n may proceed to generating a drilling risk profile for the new well, using the machine learning model, based on the drilling parameters, as at \n410\n.', 'As mentioned above, the machine learning model may be trained using previously identified risk inferences in the offset well data, or through observations of drilling risk in association with drilling parameters in the offset well data.', 'The machine learning model may thus be configured to associate certain drilling parameters, conditions, etc., with certain risks, and thereby quantify the risks as a value, e.g., a percentage, ranking, etc.', 'This value may be compared with risk tolerance values, which may be predetermined or otherwise devised, in order to establish whether the risk is acceptable, or to qualify the risk as high, medium, low, etc.', 'The drilling risk profile may visually describe levels of drilling risk in the well with respect to time. \nFIG.', '7\n illustrates an example of a risk profile \n700\n.', 'In this example, the risk profile \n700\n includes three levels of risk, high, medium, and low, which may be identified by the machine learning model based on the offset data.', 'Further, the x-axis represents time (or more specifically, in this case, sample number), and the y-axis represents is the risk indicator of the stuck-pipe events.', 'If the computed risk (likelihood of the drilling events) is higher than a certain threshold value, the risk profile area may change color (represented in gray in \nFIG.', '7\n).', 'The drilling risk profile \n700\n of \nFIG.', '7\n may correspond to the drilling parameters of \nFIG.', '6\n, which were used in the engineering analysis of block \n408\n (the results of which are shown in \nFIG.', '5\n).', "Thus, even though the drilling parameters passed the engineering analysis in block \n408\n, the machine learning model's drilling risk profile indicates an area \n702\n of high risk.", 'In response to one or more high risk areas being identified, the method \n400\n may proceed to adjusting one or more of the drilling parameters based on the drilling risk profile, as at \n412\n.', 'As shown in \nFIG.', '8\n, an automated system may suggest deviations from the initial plan.', 'For example, in over balance pressure, the initial plan \n800\n may be deviated from, as indicated at \n802\n in the later samples (corresponding to the area of high risk \n702\n), toward the right of the plot.', 'For correcting the expected risks raised by Pre-Drill advisor, the controllable drilling parameters (mud weight, flowrate, drillstring velocity, speed (revolutions-per-minute or RPM), and rate of penetration (ROP)) may be adjusted.', 'For example, a Nearest Neighbor Search (NNS) algorithm may be employed to select settings within time and cost as shown in the \nFIG.', '9\n.', 'Other search algorithms may also be employed, such as grid-search techniques, depending, for example, on the reliability of the mitigation plan, computational cost, and speed.', 'FIG.', '10\n illustrates a new risk profile, generated after deviating from the initial plan \n800\n according to the adjustments to the parameters illustrated in \nFIG.', '9\n.', 'As can be seen, the area of high risk is no longer present.', 'The remaining risks may be deemed acceptable, and thus the method \n400\n may proceed to drilling a well using the drilling parameters, as at \n414\n.', 'During the drilling, however, the method \n400\n may continue, e.g., in real-time, to evaluate risk.', 'For example, the method \n400\n may include receiving measurements taken while drilling the well using the drilling parameters, as at \n416\n.', 'These measurements may then be fed to the machine learning model, which may again evaluate the risks associated with the drilling parameters, and may update the risk profile based in part on these measurements, as at \n418\n.', 'The measurements may include all the real-time drilling measurements (e.g. hookload, surface weight on bit, flow rate, rotation rate, stand pipe pressure, equivalent circulating density) and contextual information (e.g. mud density, wellbore geometry, and geomechanics information) which are used for building the machine learning model.', 'If the risk profile again indicates that high risk areas are upcoming, the method \n400\n may loop back to adjusting one or more of the drilling parameters at \n412\n and iteratively update the drilling parameters, again, potentially in real time as drilling is underway.', 'As shown in \nFIG.', '10\n, the projected risk (i.e., the risk established prior to drilling), represented by line \n1002\n, may be modified to more accurately reflect the drilling conditions as those drilling conditions become known based on the measurements taken during the drilling process.', 'As such, the “actual” risk \n1004\n may be determined, which may be different from the projected risk, as can be seen in \nFIG.', '10\n.', 'In some embodiments, the methods of the present disclosure may be executed by a computing system.', 'FIG.', '11\n illustrates an example of such a computing system \n1100\n, in accordance with some embodiments.', 'The computing system \n1100\n may include a computer or computer system \n1101\nA, which may be an individual computer system \n1101\nA or an arrangement of distributed computer systems.', 'The computer system \n1101\nA includes one or more analysis modules \n1102\n that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein.', 'To perform these various tasks, the analysis module \n602\n executes independently, or in coordination with, one or more processors \n1104\n, which is (or are) connected to one or more storage media \n1106\n.', 'The processor(s) \n1104\n is (or are) also connected to a network interface \n1107\n to allow the computer system \n1101\nA to communicate over a data network \n1109\n with one or more additional computer systems and/or computing systems, such as \n1101\nB, \n1101\nC, and/or \n1101\nD (note that computer systems \n1101\nB, \n1101\nC and/or \n1101\nD may or may not share the same architecture as computer system \n1101\nA, and may be located in different physical locations, e.g., computer systems \n1101\nA and \n1101\nB may be located in a processing facility, while in communication with one or more computer systems such as \n1101\nC and/or \n1101\nD that are located in one or more data centers, and/or located in varying countries on different continents).', 'A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.', 'The storage media \n1106\n may be implemented as one or more computer-readable or machine-readable storage media.', 'Note that while in the example embodiment of \nFIG.', '11\n storage media \n1106\n is depicted as within computer system \n1101\nA, in some embodiments, storage media \n1106\n may be distributed within and/or across multiple internal and/or external enclosures of computing system \n1101\nA and/or additional computing systems.', 'Storage media \n1106\n may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLURAY® disks, or other types of optical storage, or other types of storage devices.', 'Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes.', 'Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture).', 'An article or article of manufacture may refer to any manufactured single component or multiple components.', 'The storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.', 'In some embodiments, computing system \n1100\n contains one or more risk prediction module(s) \n1108\n.', 'In the example of computing system \n1100\n, computer system \n1101\nA includes the risk prediction module \n1108\n.', 'In some embodiments, a single risk prediction module may be used to perform some aspects of one or more embodiments of the methods disclosed herein.', 'In other embodiments, a plurality of risk prediction modules may be used to perform some aspects of methods herein.', 'It should be appreciated that computing system \n1100\n is merely one example of a computing system, and that computing system \n1100\n may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of \nFIG.', '11\n, and/or computing system \n1100\n may have a different configuration or arrangement of the components depicted in \nFIG.', '11\n.', 'The various components shown in \nFIG.', '11\n may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.', 'Further, the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices.', 'These modules, combinations of these modules, and/or their combination with general hardware are included within the scope of the present disclosure.', 'Computational interpretations, models, and/or other interpretation aids may be refined in an iterative fashion; this concept is applicable to the methods discussed herein.', 'This may include use of feedback loops executed on an algorithmic basis, such as at a computing device (e.g., computing system \n1100\n, \nFIG.', '11\n), and/or through manual control by a user who may make determinations regarding whether a given step, action, template, model, or set of curves has become sufficiently accurate for the evaluation of the subsurface three-dimensional geologic formation under consideration.', 'The foregoing description, for purpose of explanation, has been described with reference to specific embodiments.', 'However, the illustrative discussions above are not intended to be exhaustive or limiting to the precise forms disclosed.', 'Many modifications and variations are possible in view of the above teachings.', 'Moreover, the order in which the elements of the methods described herein are illustrate and described may be re-arranged, and/or two or more elements may occur simultaneously.', 'The embodiments were chosen and described in order to best explain the principals of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosed embodiments and various embodiments with various modifications as are suited to the particular use contemplated.'] | ['1.', 'A method, comprising:\nreceiving offset well data collected while drilling one or more offset wells;\ngenerating a machine-learning model configured to predict drilling risks in a new well based on the offset well data;\npredicting a risk of differential sticking in the new well;\npredicting a risk of solid-induced pack-off in the new well;\nreceiving drilling parameters for the new well;\ndetermining that the drilling parameters are within an engineering design window;\ngenerating a drilling risk profile for the new well based at least partially upon the predicted drilling risks from the machine-learning model, the predicted risk of differential sticking, and the predicted risk of solid-induced pack-off; and\nadjusting one or more of the drilling parameters for the new well, after determining the drilling parameters are within the engineering design window, and after determining the drilling risk profile, based on the drilling risk profile.', '2.', 'The method of claim 1, further comprising drilling the new well using the drilling parameters after adjusting the one or more of the drilling parameters.', '3.', 'The method of claim 2, further comprising:\nreceiving drilling data while drilling the new well;\nupdating the drilling risk profile based in part on the drilling data, using the machine-learning model; and\nadjusting one or more of the drilling parameters while drilling the new well based on the updated drilling risk profile.', '4.', 'The method of claim 1, wherein the offset well data includes one or more automatic risk inferences, and wherein generating the machine learning model comprises training the machine learning model to predict the drilling risks based on the inferences.', '5.', 'The method of claim 4, further comprising reinforcing the one or more risk inferences using the predicted risks from the offset well.', '6.', 'The method of claim 1, wherein determining that the drilling parameters are within the engineering design window comprises:\ndetermining expected loads applied to surface equipment based on the drilling parameters; and\ndetermining that the surface equipment is configured to operate with the expected loads.', '7.', 'The method of claim 1, wherein the determining the drilling risk profile for the new well using the machine learning model comprises:\ndetermining a value for the drilling risk at a plurality of depths using the machine-learning model; and\ncomparing the value to one or more risk-tolerance thresholds.', '8.', 'The method of claim 1, wherein the drilling risk profile is generated using a Bayesian belief network.', '9.', 'The method of claim 8, wherein the risk of differential sticking is not predicted using the machine-learning model.\n\n\n\n\n\n\n10.', 'The method of claim 9, wherein the risk of solid-induced packing is not predicted using the machine-learning model.\n\n\n\n\n\n\n11.', 'A computing system, comprising:\none or more processors; and\na memory system including one or more non-transitory computer-readable media storing instructions that, when executed by at least one of the one or more processors, cause the computing system to perform operations, the processor configured to: receive offset well data collected while drilling one or more offset wells; generate a machine-learning model configured to predict drilling risks in a new well based on the offset well data; predict a risk of differential sticking in the new well; predict a risk of solid-induced pack-off in the new well; receive drilling parameters for the new well; determine that the drilling parameters are within an engineering design window; generate a drilling risk profile for the new well based at least partially upon the predicted drilling risks from the machine-learning model, the predicted risk of differential sticking, and the predicted risk of solid-induced pack-off; and adjust one or more of the drilling parameters for the new well, after determining the drilling parameters are within the engineering design window, and after determining the drilling risk profile, based on the drilling risk profile.', '12.', 'The system of claim 11, wherein the processor is further configured to control drilling of the new well using the drilling parameters after adjusting the one or more of the drilling parameters.', '13.', 'The system of claim 12, wherein the processor is further configured to:\nreceive drilling data while drilling the new well;\nupdate the drilling risk profile based in part on the drilling data, using the machine-learning model; and\nadjust one or more of the drilling parameters while drilling the new well based on the updated drilling risk profile.', '14.', 'The system of claim 11, wherein the offset well data includes one or more automatic risk inferences, and wherein processor is further configured to train the machine learning model to predict the drilling risks based on the inferences.', '15.', 'The system of claim 14, wherein the processor is further configured to reinforce the one or more risk inferences using the predicted risks from the offset well.', '16.', 'The system of claim 11, wherein the processor further configured to:\ndetermine expected loads applied to surface equipment based on the drilling parameters; and\ndetermine that the surface equipment is configured to operate with the expected loads.', '17.', 'The system of claim 11, wherein the processor is further configured to:\ndetermine a value for the drilling risk at a plurality of depths using the machine-learning model; and\ncompare the value to one or more risk-tolerance thresholds.\n\n\n\n\n\n\n18.', 'A non-transitory computer-readable medium storing instructions that, when executed by at least one processor of a computing system, cause the computing system to perform operations, the operations comprising:\nreceiving offset well data collected while drilling one or more offset wells;\ngenerating a machine-learning model configured to predict drilling risks in a new well based on the offset well data;\npredicting a risk of differential sticking in the new well;\npredicting a risk of solid-induced pack-off in the new well;\nreceiving drilling parameters for the new well;\ndetermining that the drilling parameters are within an engineering design window;\ngenerating a drilling risk profile for the new well based at least partially upon the predicted drilling risks from the machine-learning model, the predicted risk of differential sticking, and the predicted risk of solid-induced pack-off; and\nadjusting one or more of the drilling parameters for the new well, after determining the drilling parameters are within the engineering design window, and after determining the drilling risk profile, based on the drilling risk profile.', '19.', 'The medium of claim 18, wherein the operations further comprise drilling the new well using the drilling parameters after adjusting the one or more of the drilling parameters.', '20.', 'The medium of claim 19, wherein the operations further comprise:\nreceiving drilling data while drilling the new well;\nupdating the drilling risk profile based in part on the drilling data, using the machine-learning model; and\nadjusting one or more of the drilling parameters while drilling the new well based on the updated drilling risk profile.', '21.', 'The medium of claim 18, wherein the offset well data includes one or more automatic risk inferences, and wherein generating the machine learning model comprises training the machine learning model to predict the drilling risks based on the inferences.', '22.', 'The medium of claim 21, wherein the operations further comprise reinforcing the one or more risk inferences using the predicted risks from the offset well.', '23.', 'The medium of claim 18, wherein determining that the drilling parameters are within the engineering design window comprises:\ndetermining expected loads applied to surface equipment based on the drilling parameters; and\ndetermining that the surface equipment is configured to operate with the expected loads.'] | ['FIG. 1 illustrates an example of a system that includes various management components to manage various aspects of a geologic environment, according to an embodiment.; FIG.', '2 illustrates a flowchart of a method for planning a well, according to an embodiment.; FIG.', '3 illustrates a functional block diagram of a Bayesian Belief Network, according to an embodiment.; FIG.', '4 illustrates a method for drilling a well, according to an embodiment.; FIG.', '5 illustrates plots of examples of drilling parameters, according to an embodiment.; FIG.', '6 illustrates a display of an output of an engineering assessment for a well plan using specified parameters, according to an embodiment.; FIG.', '7 illustrates a view of a risk profile for a plan that meets engineering specifications, according to an embodiment.; FIG.', '8 illustrates plots of the example drilling parameters along with recommended adjustments thereto, according to an embodiment.; FIG.', '9 illustrates a view of a risk profile for the plan implementing the recommended adjustments, according to an embodiment.; FIG.', '10 illustrates a plot of projected risk from offset wells, according to an embodiment.; FIG.', '11 illustrates a schematic view of a computing system, according to an embodiment.; FIG.', '1 illustrates an example of a system 100 that includes various management components 110 to manage various aspects of a geologic environment 150 (e.g., an environment that includes a sedimentary basin, a reservoir 151, one or more faults 153-1, one or more geobodies 153-2, etc.).', 'For example, the management components 110 may allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment 150.', 'In turn, further information about the geologic environment 150 may become available as feedback 160 (e.g., optionally as input to one or more of the management components 110).; FIG.', '1 also shows an example of a framework 170 that includes a model simulation layer 180 along with a framework services layer 190, a framework core layer 195 and a modules layer 175.', 'The framework 170 may include the commercially available OCEAN® framework where the model simulation layer 180 is the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.', 'In an example embodiment, the PETREL® software may be considered a data-driven application.', 'The PETREL® software can include a framework for model building and visualization.; FIG. 1 also shows the geologic environment 150 as optionally including equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop a laterally extensive reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment 157 and/or 158 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.; FIG.', '2 illustrates a flowchart of a method 200 for planning a well, according to an embodiment.', 'The method 200 may include receiving offset well data, as at 202.', 'The offset wells may be selected from a database of previously-drilled wells.', 'The database may store risks and/or hazards that were encountered in a previously-drilled well.', 'The risks or hazards may be stored in association with drilling conditions that led to the hazards, e.g., drilling parameters such as over balance pressure, flow rate, rotation rate/speed, depth, weight on bit), as well as wellbore trajectory, geological information about rock formations, etc.', 'Further, the offset well data may be collected from any number of relevant wells, e.g., any wells within a threshold distance and/or of a similar depth, trajectory, etc., as to the planned new well.; FIG.', '4 illustrates another flowchart of a method 400 for drilling, according to an embodiment.', 'The method 400 may include receiving offset well data, as at 402.', 'The method 400 may also include training a machine learning model based on the offset well data, as at 404.', 'As noted above, the offset well data may have been processed by an automatic inference system configured to identify risks based on drilling parameters, geology etc.', 'In such case, the offset well data may be considered to include such inference information.', 'In other situations, the offset well data may not have been processed in this manner, and thus the offset well data may include drilling parameters and observed drilling conditions, e.g., including hazards encountered.', '; FIG.', '10 illustrates a new risk profile, generated after deviating from the initial plan 800 according to the adjustments to the parameters illustrated in FIG.', '9.', 'As can be seen, the area of high risk is no longer present.'] |
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20180023350; January 25, 2018; Lebedeva et al.; 20180328139; November 15, 2018; Mhaskar | 2118746; September 1998; RU; 2013009773; January 2013; WO; 2013187878; December 2013; WO; 2014046799; March 2014; WO; 2014126587; August 2014; WO | ['A downhole tool includes a base pipe having an opening formed radially-therethrough.', 'The downhole tool also includes a valve positioned at least partially within the opening.', 'The valve includes a dissolvable insert and an impediment.', 'The dissolvable insert prevents the impediment from contacting a seat of the valve such that the valve permits fluid flow in both axial directions through the valve.', 'After the dissolvable insert dissolves, the impediment contacts the seat such that the valve permits fluid flow in one axial direction through the valve but prevents fluid flow in the opposing axial direction through the valve.'] | ['Description\n\n\n\n\n\n\nBACKGROUND', 'In gravel packing operations, one or more screens are positioned in a wellbore, and a gravel slurry is pumped into an annulus between the screens and the wellbore wall.', 'The gravel slurry includes a plurality of gravel particles dispersed in a carrier fluid.', 'The carrier fluid separates from the particles (i.e., dehydration) and flows through the screens and back up to the surface, leaving the gravel particles packed in the annulus.', 'When hydrocarbon fluid is produced from the surrounding formation, the packed gravel particles may prevent sand in the hydrocarbon fluid from flowing therethrough.', 'Currently, downhole tools featuring the combination of alternate path screens and inflow control devices (“ICDs”) are used for gravel packing and production.', 'However, one of the challenges associated with the merger of these two technologies is managing the dehydration of the gravel slurry.', 'In gravel packing applications with alternate path screens, the gravel slurry flows through shunt tubes once bridging has occurred in the annulus.', 'The dehydration of the gravel slurry is then achieved by having the carrier fluid flow through the screens and the ICDs, leaving the gravel particles packed in the annulus.', 'While the ICDs are beneficial during production, the volumetric flow rate of the carrier fluid through the ICDs during gravel packing may be insufficient to obtain reasonable pumping times (e.g., low flow rates due to pressure limitation) for gravel packing an entire production zone.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'A downhole tool includes a base pipe having an opening formed radially-therethrough.', 'The downhole tool also includes a valve positioned at least partially within the opening.', 'The valve includes a dissolvable insert and an impediment.', 'The dissolvable insert prevents the impediment from contacting a seat of the valve such that the valve permits fluid flow in both axial directions through the valve.', 'After the dissolvable insert dissolves, the impediment contacts the seat such that the valve permits fluid flow in one axial direction through the valve but prevents fluid flow in the opposing axial direction through the valve.', 'In another embodiment, the downhole tool includes a first base pipe having a first opening formed radially-therethrough.', 'An inflow control device is positioned at least partially in the first opening.', 'A screen is coupled to the first base pipe and positioned radially-outward from the first base pipe.', 'A second base pipe is coupled to the first base pipe.', 'The second base pipe has a second opening formed radially-therethrough.', 'A valve is positioned at least partially in the second opening.', 'The valve includes a dissolvable insert and an impediment.', 'The dissolvable insert prevents the impediment from contacting a seat of the valve such that the valve permits fluid flow in both axial directions through the valve.', 'After the dissolvable insert dissolves, the impediment contacts the seat such that the valve permits fluid flow in one axial direction through the valve but prevents fluid flow in the opposing axial direction through the valve.', 'A method for gravel packing a wellbore is also disclosed.', 'The method includes running a downhole tool into a wellbore.', 'The downhole tool includes a base pipe having a first opening and a second opening formed radially-therethrough.', 'An inflow control device is positioned at least partially in the first opening, and a valve is positioned at least partially in the second opening.', 'The downhole tool also includes a screen positioned radially-outward from the first opening, the second opening, or both.', 'A gravel slurry is pumped into the wellbore.', 'The gravel slurry includes particles dispersed in a carrier fluid.', 'The carrier fluid flows through the screen.', 'A first portion of the carrier fluid flows through the inflow control device, and a second portion of the carrier fluid flows through the valve.', 'After a dissolvable insert in the valve dissolves, an impediment in the valve prevents fluid through the valve in one direction.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThe accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the present teachings and together with the description, serve to explain the principles of the present teachings.', 'In the figures:\n \nFIG.', '1\n illustrates a cross-sectional side view of a downhole tool, according to an embodiment.\n \nFIG.', '2\n illustrates a cross-sectional side view of a portion of a return flow unit of the downhole tool, according to an embodiment.\n \nFIG.', '3\n illustrates the cross-sectional side view of the return flow unit before a dissolvable insert has dissolved, according to an embodiment.\n \nFIG.', '4\n illustrates the cross-sectional side view of the return flow unit after the dissolvable insert has dissolved, according to an embodiment.\n \nFIG.', '5\n illustrates a cross-sectional side view of another downhole tool, according to an embodiment.\n \nFIG.', '6\n illustrates an enlarged portion of the downhole tool shown in \nFIG.', '5\n, according to an embodiment.', 'FIG.', '7\n illustrates a cross-sectional view taken through line \n7\n-\n7\n in \nFIG.', '5\n, according to an embodiment.', 'FIG.', '8\n illustrates a perspective view of a valve, according to an embodiment.\n \nFIG.', '9\n illustrates another perspective view of the valve shown in \nFIG.', '8\n, according to an embodiment.', 'FIG.', '10\n illustrates a cross-sectional side view of the valve shown in \nFIG.', '8\n, according to an embodiment.', 'FIG.', '11\n illustrates a cross-sectional side view of another valve, according to an embodiment.\n \nFIG.', '12\n illustrates a cross-sectional view taken through line \n12\n-\n12\n in \nFIG.', '11\n, according to an embodiment.\n \nFIG.', '13\n illustrates a flow chart of a method for gravel packing a wellbore using the downhole tool disclosed herein, according to an embodiment.', 'DETAILED DESCRIPTION\n \nReference will now be made in detail to embodiments, examples of which are illustrated in the accompanying figures.', 'In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the present disclosure.', 'However, it will be apparent to one of ordinary skill in the art that the system and method disclosed herein may be practiced without these specific details.', 'FIG.', '1\n illustrates a cross-sectional side view of a downhole tool \n100\n, according to an embodiment.', 'The downhole tool \n100\n may be or include at least a portion of a completion assembly that may be positioned in a wellbore in a subterranean formation.', 'The downhole tool \n100\n may include a wash pipe \n108\n.', 'The downhole tool \n100\n may also include one or more completion segments (three are shown: \n110\n) that are positioned radially-outward from the wash pipe \n108\n.', 'Each completion segment \n110\n may include a base pipe \n112\n.', 'The completion segments \n110\n (e.g., the base pipes \n112\n of the completion segments \n110\n) may be coupled together using couplings \n114\n.', 'Each base pipe \n112\n may have one or more openings \n113\n formed radially-therethrough.', 'The openings \n113\n may have inflow control devices (“ICDs”) \n116\n positioned at least partially therein to balance inflow throughout the length of the downhole tool \n100\n, restrict water and/or gas production, or a combination thereof.', 'Each completion segment \n110\n may also include one or more screens \n120\n.', 'The screens \n120\n may be coupled to and positioned radially-outward from the base pipes \n112\n.', 'A drainage layer \n122\n may be formed between each base pipe \n112\n and corresponding screen \n120\n.', 'In at least one embodiment, the drainage layers \n122\n may be placed in fluid communication with one another via shunt tubes \n124\n.', 'For example, fluid may flow from the drainage layer \n122\n of one completion segment \n110\n, through a shunt tube \n124\n, and into the drainage layer \n122\n of another completion segment \n110\n.', 'The shunt tubes \n124\n may be positioned radially-outward from the base pipes \n112\n and/or the couplings \n114\n.', 'The downhole tool \n100\n may also include a return flow unit \n130\n.', 'The return flow unit \n130\n may also be positioned radially-outward from the wash pipe \n108\n.', 'The return flow unit \n130\n may be coupled to one or more of the completion segments \n110\n (e.g., using a coupling \n114\n).', 'As shown, the return flow unit \n130\n may be positioned axially-below one of the completion segments \n110\n; however, in other embodiments, the return flow unit \n130\n may be positioned axially-above one of the completion segments \n110\n or axially-between two completion segments \n110\n.', 'The return flow unit \n130\n may include a base pipe \n132\n.', 'The base pipe \n132\n may also have one or more openings \n133\n formed radially-therethrough.', 'The base pipe \n132\n of the return flow unit \n130\n may have more openings \n133\n per unit length than the base pipes \n112\n of the completion segments \n110\n.', 'The openings \n133\n in the base pipe \n132\n of the return flow unit \n130\n may have a greater aggregate surface area than the openings \n113\n in of the base pipe(s) \n112\n of one or more of the completion segments \n110\n.', 'As a result, when not obstructed, the openings \n133\n in the base pipe \n132\n may permit a greater volumetric flow rate therethrough than the openings \n113\n in the base pipe(s) \n112\n.\n \nFIG.', '2\n illustrates a cross-sectional side view of a portion of the return flow unit \n130\n, according to an embodiment.', 'The return flow unit \n130\n may include a housing \n134\n positioned radially-outward from the base pipe \n132\n.', 'The housing \n134\n may be solid (i.e., have no openings formed radially-therethrough).', 'In at least one embodiment, fluid may be introduced into an annulus \n136\n between the base pipe \n132\n and the housing \n134\n through one or more of the shunt tubes \n124\n.', 'Thus, the shunt tubes \n124\n may be configured to introduce fluid from one or more (e.g., three as shown in \nFIG.', '1\n) completion segments \n110\n into the annulus \n136\n of the return flow unit \n130\n.', 'One or more of the openings \n133\n in the base pipe \n132\n may have a valve \n800\n positioned at least partially therein.', 'Each valve \n800\n may include a dissolvable insert that dissolves when placed in contact with a predetermined fluid for a predetermined amount of time.', 'The predetermined fluid may be or include an acid, oil, water, or the like.', 'The predetermined amount of time may be less than or equal to about 1 week, less than or equal to about 3 days, less than or equal to about 1 day, less than or equal to about 12 hours, less than or equal to about 3 hours, or less than or equal to about 1 hour.', 'FIG.', '3\n illustrates a cross-sectional side view of the return flow unit \n130\n before the dissolvable inserts in the valves \n800\n have dissolved, according to an embodiment.', 'As shown by the arrows, before the dissolvable inserts have dissolved, fluid in the annulus \n136\n between the base pipe \n132\n and the housing \n134\n may flow radially-inward through the openings \n133\n and into another annulus \n138\n between the wash pipe \n108\n and the base pipe \n132\n.\n \nFIG.', '4\n illustrates a cross-sectional side view of the return flow unit \n130\n after the dissolvable inserts in the valves \n800\n have dissolved, according to an embodiment.', 'As shown by the arrows, after the dissolvable inserts have dissolved, fluid in the annulus \n136\n between the base pipe \n132\n and the housing \n134\n may be prevented from flowing through the openings \n133\n and into the annulus \n138\n between the wash pipe \n108\n and the base pipe \n132\n.', 'After the dissolvable inserts have dissolved, the valves \n800\n may function as check valves that permit fluid flow in a radially-outward direction but prevent fluid flow in a radially-inward direction.\n \nFIG.', '5\n illustrates a cross-sectional side view of another downhole tool \n500\n, and \nFIG.', '6\n illustrates an enlarged portion of the downhole tool \n500\n shown in \nFIG.', '5\n, according to an embodiment.', 'The downhole tool \n500\n is similar to the downhole tool \n100\n, and the same reference numbers are used where applicable.', 'For example, the downhole tool \n500\n may include a base pipe \n112\n having one or more openings \n113\n formed radially-therethrough.', 'As shown, one or more of the openings \n113\n may have an ICD \n116\n positioned (e.g., threaded) at least partially therein, and one or more of the openings \n113\n may have a valve \n800\n positioned (e.g., threaded) at least partially therein.', 'When the ICD(s) \n116\n and valves \n800\n are in the same base pipe \n112\n, the return flow unit \n130\n and/or the shunt tubes \n124\n may be omitted.', 'More of the openings \n113\n may have valves \n800\n positioned therein than ICDs \n116\n.', 'At least a portion of each of the valves \n800\n may extend radially-outward from the base pipe \n112\n and into an annulus \n152\n formed radially-between the base pipe \n112\n and a surrounding housing \n150\n.', 'A gap \n154\n may exist radially-between the valves \n800\n and the housing \n150\n.', 'FIG.', '7\n illustrates a cross-sectional view of the downhole tool \n500\n taken through line \n7\n-\n7\n in \nFIG.', '5\n, according to an embodiment.', 'The valves \n800\n may be circumferentially-offset from one another around the base pipe \n112\n.', 'A plurality of axial rib wires \n156\n may also be positioned circumferentially-around the base pipe \n112\n.', 'The rib wires \n156\n may be positioned radially-between the base pipe \n112\n and the housing \n150\n.', 'FIG.', '8\n illustrates a perspective view of the valve \n800\n, according to an embodiment.', 'The valve \n800\n may include a body \n810\n having a bore formed axially-therethrough.', 'The body \n810\n may include a first (e.g., lower) portion \n812\n and a second (e.g., upper) portion \n814\n.', 'The first portion \n812\n may be sized to fit within one of the openings \n113\n in the base pipe \n112\n or the openings \n133\n in the base pipe \n132\n.', 'The second portion \n814\n may be tapered.', 'More particularly, a cross-sectional length \n816\n of the second portion \n814\n may increase proceeding away from the first portion \n812\n.', 'The second portion \n814\n may also have one or more openings \n818\n formed radially-therethrough.', 'As mentioned above, the valve \n800\n may be a check valve.', 'Thus, the valve \n800\n may have an impediment \n820\n positioned at least partially therein.', 'As shown, the impediment \n820\n may be a ball.', 'FIG.', '9\n illustrates another perspective view of the valve \n800\n, according to an embodiment.', 'The dissolvable insert \n830\n may be positioned at least partially within the first (e.g., lower) portion \n812\n of the body \n810\n.', 'The dissolvable insert \n830\n may be substantially flat (e.g., a plate).', 'The dissolvable insert \n830\n may have one or more openings \n832\n formed axially-therethrough.\n \nFIG.', '10\n illustrates a cross-sectional side view of the valve \n800\n, according to an embodiment.', 'An inner surface of the body \n810\n may define a seat \n822\n.', 'As shown, the impediment \n820\n may initially be held away from (e.g., above) the seat \n822\n by the dissolvable insert \n830\n.', 'For example, the dissolvable insert \n830\n may be positioned below the seat \n822\n and include one or more axial protrusions \n834\n that hold the impediment \n820\n away from (e.g., above) the seat \n822\n.', 'In another embodiment, the dissolvable insert \n830\n may be positioned above the seat \n822\n and thus be able to hold the impediment \n820\n away from (e.g., above) the seat \n822\n.', 'In this embodiment, the protrusions \n834\n may be omitted.', 'When the impediment \n830\n is held away from the seat \n822\n, fluid may flow through the valve \n800\n in both axial directions.', 'However, when the dissolvable insert \n830\n at least partially dissolves, the impediment \n820\n may be configured to contact the seat \n822\n.', 'Thus, when the dissolvable insert \n830\n at least partially dissolves, the valve \n800\n may function as a check valve by allowing fluid to flow therethrough in one axial direction (e.g., radially-outward through the base pipe \n112\n, \n132\n) but preventing fluid from flowing therethrough in the opposing axial direction (e.g., radially-inward through the base pipe \n112\n, \n132\n).', 'The dissolvable insert \n830\n may be held in place by one or more snap rings (two are shown: \n840\n).', 'The dissolvable insert \n830\n may be positioned axially-between the two snap rings \n840\n.', 'The snap rings \n840\n may be positioned at least partially within circumferential recesses formed in the inner surface of the body \n810\n.', 'In another embodiment, the snap rings \n840\n may be omitted, and the dissolvable insert \n830\n may be positioned at least partially within a circumferential recess formed in the inner surface of the body \n810\n.', 'FIG.', '11\n illustrates a cross-sectional side view of another valve \n1100\n, and \nFIG.', '12\n illustrates a cross-sectional view of the valve \n1100\n taken through line \n12\n-\n12\n in \nFIG.', '11\n, according to an embodiment.', 'The valve \n1100\n may be the same as the valve \n800\n, or it may be different.', 'The valve \n1100\n may be used instead of, or in addition to, the valve \n800\n.', 'The valve \n1100\n may also include a body \n1110\n having a bore formed axially-therethrough.', 'An inner surface of the body \n1110\n may define a seat \n1122\n.', 'The dissolvable insert \n1130\n may be positioned within the body \n1110\n and above the seat \n1122\n.', 'As shown, the dissolvable insert \n1130\n may rest/sit on the seat \n1122\n.', 'The dissolvable insert \n1130\n may have one or more arms \n1136\n that extend radially-inward therefrom.', 'The arms \n1136\n may be configured to hold the impediment \n1120\n away from the seat \n1122\n.', 'Between the arms \n1136\n, the dissolvable insert \n1130\n may have one or more openings \n1132\n formed axially-therethrough.', 'A retaining plate \n1140\n may also be positioned within the body \n1110\n.', 'The impediment \n1120\n may be positioned axially-between the dissolvable insert \n1130\n and the retaining plate \n1140\n.', 'The retaining plate \n1140\n may have one or more arms \n1146\n that extend radially-inward therefrom.', 'The arms \n1146\n may be configured to hold the impediment \n1120\n within the valve \n1100\n.', 'Between the arms \n1146\n, the retaining plate \n1140\n may have one or more openings \n1142\n formed axially-therethrough.', 'Thus, fluid may flow through the valve \n1100\n in both axial directions prior to the dissolvable insert \n1130\n dissolving.', 'However, after the dissolvable insert \n1130\n at least partially dissolves, the valve \n1100\n may function as a check valve by allowing fluid to flow therethrough in one axial direction but preventing fluid from flowing therethrough in the opposing axial direction.\n \nFIG.', '13\n illustrates a flow chart of a method \n1300\n for gravel packing a wellbore, according to an embodiment.', 'The method \n1300\n may include running the downhole tool \n100\n, \n500\n into the wellbore, as at \n1302\n.', 'The method \n1300\n may also include pumping a gravel slurry into the wellbore, as at \n1304\n.', 'The gravel slurry may include gravel particles dispersed in a carrier fluid.', 'The carrier fluid may flow radially-inward through the screens \n120\n while the gravel particles remain positioned radially-between the screens \n120\n and the wall of the wellbore.', 'A portion of the carrier fluid may flow through the ICDs \n116\n in the base pipe \n112\n and into the annulus \n138\n between the wash pipe \n108\n and the base pipe \n112\n.', 'Another (e.g., greater) portion of the carrier fluid may flow through the valves \n800\n, \n1100\n.', 'As shown in \nFIG.', '1\n, in one embodiment, the carrier fluid may flow through the shunt tubes \n124\n and into the return flow unit \n130\n, where the carrier fluid may flow through the valves \n800\n, \n1100\n.', 'As shown in \nFIG.', '5\n, in another embodiment, the carrier fluid may flow through the valves \n800\n, \n1100\n that are in the same base pipe \n112\n as the ICD(s) \n116\n.', 'In at least one embodiment, the dissolvable inserts \n830\n, \n1130\n may dissolve after a predetermined amount of time in contact with fluids in the wellbore (e.g., oil or water).', 'In another embodiment, the dissolvable inserts \n830\n, \n1130\n may dissolve after a predetermined amount of time in contact with the gravel slurry.', 'In yet another embodiment, after the gravel slurry has been pumped, the method \n1300\n may include pumping a fluid (e.g., an acid) into the wellbore to cause the dissolvable inserts \n830\n, \n1130\n to dissolve, as at \n1306\n.', 'The fluid pumped into the wellbore may flow through the ICDs \n116\n and the valves \n800\n in the same manner as the carrier fluid.', 'As discussed above, once the dissolvable inserts \n830\n, \n1130\n dissolve, the valves \n800\n, \n1100\n may become check valves that prevent fluid from flowing radially-inward therefrom.', 'As will be appreciated, both the ICDs \n116\n and the valves \n800\n, \n1100\n may allow fluid to flow radially-inward therethrough during the gravel packing operation, but once the wellbore starts producing, the hydrocarbons may flow through the ICDs \n116\n but not the valves \n800\n, \n1100\n.', 'As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation.', 'The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”', 'The foregoing description, for purpose of explanation, has been described with reference to specific embodiments.', 'However, the illustrative discussions above are not intended to be exhaustive or to limit the invention to the precise forms disclosed.', 'Many modifications and variations are possible in view of the above teachings.', 'Moreover, the order in which the elements of the methods described herein are illustrate and described may be re-arranged, and/or two or more elements may occur simultaneously.', 'The embodiments were chosen and described in order to best explain the principals of the invention and its practical applications, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated.'] | ['1.', 'A downhole tool, comprising:\na base pipe having a first opening formed radially-therethrough; and\na valve positioned at least partially within the first opening, wherein the valve comprises a dissolvable insert and an impediment, wherein the dissolvable insert prevents the impediment from contacting a seat of the valve such that the valve permits fluid flow in both axial directions through the valve, and wherein, after the dissolvable insert dissolves, the impediment is configured to contact the seat such that the valve permits fluid flow in one axial direction through the valve but prevents fluid flow in the opposing axial direction through the valve,\nwherein the valve comprises a first portion having a substantially constant cross-sectional length, and a second portion having a cross-sectional length that increases proceeding away from the first portion,\nwherein the dissolvable insert has one or more openings formed axially-therethrough,\nwherein the seat is positioned between the dissolvable insert and the impediment, and wherein the dissolvable insert comprises an axial protrusion that contacts the impediment and prevents the impediment from contacting the seat,\nwherein an inner surface of the valve defines first and second recesses that are axially-offset from one another, wherein a first ring is positioned at least partially within the first recess, wherein a second ring is positioned at least partially within the second recess, and wherein the dissolvable insert is positioned axially between the first and second rings.', '2.', 'The downhole tool of claim 1, wherein the second portion has an opening formed radially-therethrough.\n\n\n\n\n\n\n3.', 'The downhole tool of claim 1, wherein the base pipe has a second opening formed radially-therethrough, and wherein an inflow control device is positioned at least partially within the second opening.\n\n\n\n\n\n\n4.', 'The downhole tool of claim 3, further comprising a housing positioned radially-outward from the base pipe.', '5.', 'The downhole tool of claim 4, wherein a portion of the valve extends radially-outward from the base pipe and toward the housing, and wherein a gap exists between the valve and the housing.', '6.', 'A downhole tool, comprising:\na first base pipe having one or more first openings formed radially-therethrough;\nan inflow control device positioned at least partially in each of the first openings;\na screen coupled to the first base pipe and positioned radially-outward from the first base pipe;\na second base pipe coupled to the first base pipe, the second base pipe having one or more second openings formed radially-therethrough; and\na valve positioned at least partially in each of the second openings, wherein the valve comprises a dissolvable insert and an impediment, wherein the dissolvable insert prevents the impediment from contacting a seat of the valve such that the valve permits fluid flow in both axial directions through the valve, and wherein, after the dissolvable insert dissolves, the impediment is configured to contact the seat such that the valve permits fluid flow in one axial direction through the valve but prevents fluid flow in the opposing axial direction through the valve,\nwherein the valve comprises a first portion having a substantially constant cross-sectional length, and a second portion having a cross-sectional length that increases proceeding away from the first portion,\nwherein the dissolvable insert has one or more openings formed axially-therethrough,\nwherein the seat is positioned between the dissolvable insert and the impediment, and wherein the dissolvable insert comprises an axial protrusion that contacts the impediment and prevents the impediment from contacting the seat,\nwherein an inner surface of the valve defines first and second recesses that are axially-offset from one another, wherein a first ring is positioned at least partially within the first recess, wherein a second ring is positioned at least partially within the second recess, and wherein the dissolvable insert is positioned axially between the first and second rings.', '7.', 'The downhole tool of claim 6, further comprising:\na housing positioned radially-outward from the second base pipe; and\na shunt tube that places a first annulus formed between the first base pipe and the screen in fluid communication with a second annulus formed between the second base pipe and the housing.\n\n\n\n\n\n\n8.', 'The downhole tool of claim 7, wherein the housing does not have openings formed radially-therethrough.\n\n\n\n\n\n\n9.', 'The downhole tool of claim 7, wherein a portion of the valve extends radially-outward from the second base pipe and toward the housing, and wherein a gap exists between the valve and the housing.', '10.', 'The downhole tool of claim 6, wherein the one or more second openings have a greater aggregate surface area than the one or more first openings.', '11.', 'The downhole tool of claim 6, wherein the second portion has an opening formed radially-therethrough.\n\n\n\n\n\n\n12.', 'A method for gravel packing a wellbore, comprising:\nrunning a downhole tool into a wellbore, wherein the downhole tool comprises: a base pipe having a first opening and a second opening formed radially-therethrough, wherein an inflow control device is positioned at least partially in the first opening, wherein a valve is positioned at least partially in the second opening, and wherein the valve comprises a first portion having a substantially constant cross-sectional length, and a second portion having a cross-sectional length that increases proceeding away from the first portion; and a screen positioned radially-outward from the first opening, the second opening, or both; and pumping a gravel slurry into the wellbore, wherein the gravel slurry comprises particles dispersed in a carrier fluid, wherein the carrier fluid flows through the screen, wherein a first portion of the carrier fluid flows through the inflow control device and a second portion of the carrier fluid flows through the valve, wherein the valve comprises a dissolvable insert and an impediment, the dissolvable insert having one or more openings formed axially-therethrough and an axial protrusion that contacts the impediment and prevents the impediment from contacting a seat of the valve such that that the valve permits fluid flow in both axial directions through the valve, and wherein, after the dissolvable insert in the valve dissolves, the impediment in the valve is configured to prevent fluid through the valve in one direction, wherein an inner surface of the valve defines first and second recesses that are axially-offset from one another, wherein a first ring is positioned at least partially within the first recess, wherein a second ring is positioned at least partially within the second recess, and wherein the dissolvable insert is positioned axially between the first and second rings.\n\n\n\n\n\n\n13.', 'The method of claim 12, further comprising pumping a fluid into the wellbore after pumping the gravel slurry into the wellbore, wherein the dissolvable insert dissolves after being in contact with the fluid for a predetermined amount of time that is less than 1 day.', '14.', 'The method of claim 12, wherein the second portion of the carrier fluid flows through a shunt tube prior to reaching the valve, and wherein the second portion of the carrier fluid is greater than the first portion of the carrier fluid.'] | ['FIG. 1 illustrates a cross-sectional side view of a downhole tool, according to an embodiment.; FIG.', '2 illustrates a cross-sectional side view of a portion of a return flow unit of the downhole tool, according to an embodiment.; FIG.', '3 illustrates the cross-sectional side view of the return flow unit before a dissolvable insert has dissolved, according to an embodiment.; FIG.', '4 illustrates the cross-sectional side view of the return flow unit after the dissolvable insert has dissolved, according to an embodiment.; FIG.', '5 illustrates a cross-sectional side view of another downhole tool, according to an embodiment.; FIG.', '6 illustrates an enlarged portion of the downhole tool shown in FIG.', '5, according to an embodiment.', '; FIG.', '7 illustrates a cross-sectional view taken through line 7-7 in FIG.', '5, according to an embodiment.', '; FIG.', '8 illustrates a perspective view of a valve, according to an embodiment.; FIG.', '9 illustrates another perspective view of the valve shown in FIG. 8, according to an embodiment.; FIG.', '10 illustrates a cross-sectional side view of the valve shown in FIG. 8, according to an embodiment.; FIG.', '11 illustrates a cross-sectional side view of another valve, according to an embodiment.; FIG.', '12 illustrates a cross-sectional view taken through line 12-12 in FIG.', '11, according to an embodiment.', '; FIG.', '13 illustrates a flow chart of a method for gravel packing a wellbore using the downhole tool disclosed herein, according to an embodiment.; FIG.', '1 illustrates a cross-sectional side view of a downhole tool 100, according to an embodiment.', 'The downhole tool 100 may be or include at least a portion of a completion assembly that may be positioned in a wellbore in a subterranean formation.', 'The downhole tool 100 may include a wash pipe 108.', 'The downhole tool 100 may also include one or more completion segments (three are shown: 110) that are positioned radially-outward from the wash pipe 108.', 'Each completion segment 110 may include a base pipe 112.', 'The completion segments 110 (e.g., the base pipes 112 of the completion segments 110) may be coupled together using couplings 114.', 'Each base pipe 112 may have one or more openings 113 formed radially-therethrough.', 'The openings 113 may have inflow control devices (“ICDs”) 116 positioned at least partially therein to balance inflow throughout the length of the downhole tool 100, restrict water and/or gas production, or a combination thereof.', '; FIG.', '2 illustrates a cross-sectional side view of a portion of the return flow unit 130, according to an embodiment.', 'The return flow unit 130 may include a housing 134 positioned radially-outward from the base pipe 132.', 'The housing 134 may be solid (i.e., have no openings formed radially-therethrough).', 'In at least one embodiment, fluid may be introduced into an annulus 136 between the base pipe 132 and the housing 134 through one or more of the shunt tubes 124.', 'Thus, the shunt tubes 124 may be configured to introduce fluid from one or more (e.g., three as shown in FIG.', '1) completion segments 110 into the annulus 136 of the return flow unit 130.; FIG.', '3 illustrates a cross-sectional side view of the return flow unit 130 before the dissolvable inserts in the valves 800 have dissolved, according to an embodiment.', 'As shown by the arrows, before the dissolvable inserts have dissolved, fluid in the annulus 136 between the base pipe 132 and the housing 134 may flow radially-inward through the openings 133 and into another annulus 138 between the wash pipe 108 and the base pipe 132.; FIG.', '4 illustrates a cross-sectional side view of the return flow unit 130 after the dissolvable inserts in the valves 800 have dissolved, according to an embodiment.', 'As shown by the arrows, after the dissolvable inserts have dissolved, fluid in the annulus 136 between the base pipe 132 and the housing 134 may be prevented from flowing through the openings 133 and into the annulus 138 between the wash pipe 108 and the base pipe 132.', 'After the dissolvable inserts have dissolved, the valves 800 may function as check valves that permit fluid flow in a radially-outward direction but prevent fluid flow in a radially-inward direction.', '; FIG.', '5 illustrates a cross-sectional side view of another downhole tool 500, and FIG.', '6 illustrates an enlarged portion of the downhole tool 500 shown in FIG.', '5, according to an embodiment.', 'The downhole tool 500 is similar to the downhole tool 100, and the same reference numbers are used where applicable.', 'For example, the downhole tool 500 may include a base pipe 112 having one or more openings 113 formed radially-therethrough.', 'As shown, one or more of the openings 113 may have an ICD 116 positioned (e.g., threaded) at least partially therein, and one or more of the openings 113 may have a valve 800 positioned (e.g., threaded) at least partially therein.', 'When the ICD(s) 116 and valves 800 are in the same base pipe 112, the return flow unit 130 and/or the shunt tubes 124 may be omitted.', 'More of the openings 113 may have valves 800 positioned therein than ICDs 116.', 'At least a portion of each of the valves 800 may extend radially-outward from the base pipe 112 and into an annulus 152 formed radially-between the base pipe 112 and a surrounding housing 150.', 'A gap 154 may exist radially-between the valves 800 and the housing 150.; FIG.', '7 illustrates a cross-sectional view of the downhole tool 500 taken through line 7-7 in FIG.', '5, according to an embodiment.', 'The valves 800 may be circumferentially-offset from one another around the base pipe 112.', 'A plurality of axial rib wires 156 may also be positioned circumferentially-around the base pipe 112.', 'The rib wires 156 may be positioned radially-between the base pipe 112 and the housing 150.; FIG.', '8 illustrates a perspective view of the valve 800, according to an embodiment.', 'The valve 800 may include a body 810 having a bore formed axially-therethrough.', 'The body 810 may include a first (e.g., lower) portion 812 and a second (e.g., upper) portion 814.', 'The first portion 812 may be sized to fit within one of the openings 113 in the base pipe 112 or the openings 133 in the base pipe 132.', 'The second portion 814 may be tapered.', 'More particularly, a cross-sectional length 816 of the second portion 814 may increase proceeding away from the first portion 812.', 'The second portion 814 may also have one or more openings 818 formed radially-therethrough.', 'As mentioned above, the valve 800 may be a check valve.', 'Thus, the valve 800 may have an impediment 820 positioned at least partially therein.', 'As shown, the impediment 820 may be a ball.', '; FIG.', '9 illustrates another perspective view of the valve 800, according to an embodiment.', 'The dissolvable insert 830 may be positioned at least partially within the first (e.g., lower) portion 812 of the body 810.', 'The dissolvable insert 830 may be substantially flat (e.g., a plate).', 'The dissolvable insert 830 may have one or more openings 832 formed axially-therethrough.;', 'FIG. 10 illustrates a cross-sectional side view of the valve 800, according to an embodiment.', 'An inner surface of the body 810 may define a seat 822.', 'As shown, the impediment 820 may initially be held away from (e.g., above) the seat 822 by the dissolvable insert 830.', 'For example, the dissolvable insert 830 may be positioned below the seat 822 and include one or more axial protrusions 834 that hold the impediment 820 away from (e.g., above) the seat 822.', 'In another embodiment, the dissolvable insert 830 may be positioned above the seat 822 and thus be able to hold the impediment 820 away from (e.g., above) the seat 822.', 'In this embodiment, the protrusions 834 may be omitted.; FIG.', '11 illustrates a cross-sectional side view of another valve 1100, and FIG.', '12 illustrates a cross-sectional view of the valve 1100 taken through line 12-12 in FIG.', '11, according to an embodiment.', 'The valve 1100 may be the same as the valve 800, or it may be different.', 'The valve 1100 may be used instead of, or in addition to, the valve 800.', 'The valve 1100 may also include a body 1110 having a bore formed axially-therethrough.', 'An inner surface of the body 1110 may define a seat 1122.', 'The dissolvable insert 1130 may be positioned within the body 1110 and above the seat 1122.', 'As shown, the dissolvable insert 1130 may rest/sit on the seat 1122.', 'The dissolvable insert 1130 may have one or more arms 1136 that extend radially-inward therefrom.', 'The arms 1136 may be configured to hold the impediment 1120 away from the seat 1122.', 'Between the arms 1136, the dissolvable insert 1130 may have one or more openings 1132 formed axially-therethrough.; FIG.', '13 illustrates a flow chart of a method 1300 for gravel packing a wellbore, according to an embodiment.', 'The method 1300 may include running the downhole tool 100, 500 into the wellbore, as at 1302.', 'The method 1300 may also include pumping a gravel slurry into the wellbore, as at 1304.', 'The gravel slurry may include gravel particles dispersed in a carrier fluid.', 'The carrier fluid may flow radially-inward through the screens 120 while the gravel particles remain positioned radially-between the screens 120 and the wall of the wellbore.', 'A portion of the carrier fluid may flow through the ICDs 116 in the base pipe 112 and into the annulus 138 between the wash pipe 108 and the base pipe 112.', 'Another (e.g., greater) portion of the carrier fluid may flow through the valves 800, 1100.', 'As shown in FIG.', '1, in one embodiment, the carrier fluid may flow through the shunt tubes 124 and into the return flow unit 130, where the carrier fluid may flow through the valves 800, 1100.', 'As shown in FIG.', '5, in another embodiment, the carrier fluid may flow through the valves 800, 1100 that are in the same base pipe 112 as the ICD(s) 116.'] |
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US11149542 | Dynamic system for field operations | Jun 21, 2019 | Jean-Marc Pietrzyk, Richard John Harmer | Schlumberger Technology Corporation | NPL References not found. | 4384612; May 24, 1983; Bradford; 6542076; April 1, 2003; Joao; 8649909; February 11, 2014; Phillips; 20080173480; July 24, 2008; Annaiyappa; 20160245073; August 25, 2016; Hansen; 20180089988; March 29, 2018; Schwarzkopf; 20180163527; June 14, 2018; Curry; 20190078426; March 14, 2019; Zheng; 20190268571; August 29, 2019; Pettersen; 20190293824; September 26, 2019; Liu et al. | 2019/222031; November 2019; WO | ['A method for controlling field equipment can include receiving information via an interface of a control system; analyzing the information by the control system with respect to tiered well construction activities; based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.'] | ['Description\n\n\n\n\n\n\nRELATED APPLICATION', 'This application claims priority to and the benefit of a U.S. Provisional Application having Ser.', 'No. 62/687,838, filed 21 Jun. 2018, which is incorporated by reference herein.', 'BACKGROUND\n \nA resource field can be an accumulation, pool or group of pools of one or more resources (e.g., oil, gas, oil and gas) in a subsurface environment.', 'A resource field can include at least one reservoir.', 'A reservoir may be shaped in a manner that can trap hydrocarbons and may be covered by an impermeable or sealing rock.', 'A bore can be drilled into an environment where the bore may be utilized to form a well that can be utilized in producing hydrocarbons from a reservoir.', 'A rig can be a system of components that can be operated to form a bore in an environment, to transport equipment into and out of a bore in an environment, etc.', 'As an example, a rig can include a system that can be used to drill a bore and to acquire information about an environment, about drilling, etc.', 'A resource field may be an onshore field, an offshore field or an on- and offshore field.', 'A rig can include components for performing operations onshore and/or offshore.', 'A rig may be, for example, vessel-based, offshore platform-based, onshore, etc.', 'Field planning and/or development can occur over one or more phases, which can include an exploration phase that aims to identify and assess an environment (e.g., a prospect, a play, etc.), which may include drilling of one or more bores (e.g., one or more exploratory wells, etc.).', 'SUMMARY\n \nA method for controlling field equipment can include receiving information via an interface of a control system; analyzing the information by the control system with respect to tiered well construction activities; based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'A system can include a processor; memory accessible by the processor; processor-executable instructions stored in the memory and executable to instruct the system to: receive information via an interface of a control system; perform an analysis of the information by the control system with respect to tiered well construction activities; based on the analysis, generate a workflow that includes at least a series of tiered well construction activities; and transmit a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'One or more computer-readable storage media can include processor-executable instructions to instruct a computing system to: receive information via an interface of a control system; perform an analysis of the information by the control system with respect to tiered well construction activities; based on the analysis, generate a workflow that includes at least a series of tiered well construction activities; and transmit a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'Various other apparatuses, systems, methods, etc., are also disclosed.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFeatures and advantages of the described implementations can be more readily understood by reference to the following description taken in conjunction with the accompanying drawings.\n \nFIG.', '1\n illustrates examples of equipment in a geologic environment;\n \nFIG.', '2\n illustrates examples of equipment and examples of hole types;\n \nFIG.', '3\n illustrates an example of a system;\n \nFIG.', '4\n illustrates an example of a wellsite system and an example of a computing system;\n \nFIG.', '5\n illustrates an example of a graphical user interface;\n \nFIG.', '6\n illustrates an example of a graphical user interface;\n \nFIG.', '7\n illustrates an example of a method and an example of a system;\n \nFIG.', '8\n illustrates an example of a system;\n \nFIG.', '9\n illustrates an example of a system;\n \nFIG.', '10\n illustrates an example of a system;\n \nFIG.', '11\n illustrates an example of a system;\n \nFIG.', '12\n illustrates an example of a system;\n \nFIG.', '13\n illustrates an example of the system of \nFIG.', '12\n;\n \nFIG.', '14\n illustrates an example of a system;\n \nFIG.', '15\n illustrates an example of a method;\n \nFIG.', '16\n illustrates an example of a method and an example of a graphical user interface;\n \nFIG.', '17\n illustrates an example of a method;\n \nFIG.', '18\n illustrates an example of a method;\n \nFIG.', '19\n illustrates an example of a method;\n \nFIG.', '20\n illustrates an example of a method;\n \nFIG.', '21\n illustrates an example of a method;\n \nFIG.', '22\n illustrates an example of a method and an example of a graphical user interface;\n \nFIG.', '23\n illustrates an example of a graphical user interface;\n \nFIG.', '24\n illustrates an example of a graphical user interface;\n \nFIG.', '25\n illustrates an example of a graphical user interface;\n \nFIG.', '26\n illustrates an example of a graphical user interface;\n \nFIG.', '27\n illustrates an example of a graphical user interface;\n \nFIG.', '28\n illustrates an example of a graphical user interface;\n \nFIG.', '29\n illustrates an example of a graphical user interface;\n \nFIG.', '30\n illustrates an example of a graphical user interface;\n \nFIG.', '31\n illustrates an example of a graphical user interface;\n \nFIG.', '32\n illustrates an example of a graphical user interface;\n \nFIG.', '33\n illustrates an example of a method;\n \nFIG.', '34\n illustrates an example of computing system; and\n \nFIG.', '35\n illustrates example components of a system and a networked system.', 'DETAILED DESCRIPTION', 'The following description includes the best mode presently contemplated for practicing the described implementations.', 'This description is not to be taken in a limiting sense, but rather is made merely for the purpose of describing the general principles of the implementations.', 'The scope of the described implementations should be ascertained with reference to the issued claims.\n \nFIG.', '1\n shows an example of a geologic environment \n120\n.', 'In \nFIG.', '1\n, the geologic environment \n120\n may be a sedimentary basin that includes layers (e.g., stratification) that include a reservoir \n121\n and that may be, for example, intersected by a fault \n123\n (e.g., or faults).', 'As an example, the geologic environment \n120\n may be outfitted with any of a variety of sensors, detectors, actuators, etc.', 'For example, equipment \n122\n may include communication circuitry to receive and to transmit information with respect to one or more networks \n125\n.', 'Such information may include information associated with downhole equipment \n124\n, which may be equipment to acquire information, to assist with resource recovery, etc.', 'Other equipment \n126\n may be located remote from a well site and include sensing, detecting, emitting or other circuitry.', 'Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.', 'As an example, one or more pieces of equipment may provide for measurement, collection, communication, storage, analysis, etc. of data (e.g., for one or more produced resources, etc.).', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.', 'For example, \nFIG.', '1\n shows a satellite in communication with the network \n125\n that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).', 'FIG.', '1\n also shows the geologic environment \n120\n as optionally including equipment \n127\n and \n128\n associated with a well that includes a substantially horizontal portion (e.g., a lateral portion) that may intersect with one or more fractures \n129\n.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop the reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment \n127\n and/or \n128\n may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, injection, production, etc.', 'As an example, the equipment \n127\n and/or \n128\n may provide for measurement, collection, communication, storage, analysis, etc. of data such as, for example, production data (e.g., for one or more produced resources).', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.\n \nFIG.', '1\n also shows an example of equipment \n170\n and an example of equipment \n180\n.', 'Such equipment, which may be systems of components, may be suitable for use in the geologic environment \n120\n.', 'While the equipment \n170\n and \n180\n are illustrated as land-based, various components may be suitable for use in an offshore system (e.g., an offshore rig, etc.).', 'The equipment \n170\n includes a platform \n171\n, a derrick \n172\n, a crown block \n173\n, a line \n174\n, a traveling block assembly \n175\n, drawworks \n176\n and a landing \n177\n (e.g., a monkeyboard).', 'As an example, the line \n174\n may be controlled at least in part via the drawworks \n176\n such that the traveling block assembly \n175\n travels in a vertical direction with respect to the platform \n171\n.', 'For example, by drawing the line \n174\n in, the drawworks \n176\n may cause the line \n174\n to run through the crown block \n173\n and lift the traveling block assembly \n175\n skyward away from the platform \n171\n; whereas, by allowing the line \n174\n out, the drawworks \n176\n may cause the line \n174\n to run through the crown block \n173\n and lower the traveling block assembly \n175\n toward the platform \n171\n.', 'Where the traveling block assembly \n175\n carries pipe (e.g., casing, etc.)', ', tracking of movement of the traveling block \n175\n may provide an indication as to how much pipe has been deployed.', 'A derrick can be a structure used to support a crown block and a traveling block operatively coupled to the crown block at least in part via line.', 'A derrick may be pyramidal in shape and offer a suitable strength-to-weight ratio.', 'A derrick may be movable as a unit or in a piece by piece manner (e.g., to be assembled and disassembled).', 'As an example, drawworks may include a spool, brakes, a power source and assorted auxiliary devices.', 'Drawworks may controllably reel out and reel in line.', 'Line may be reeled over a crown block and coupled to a traveling block to gain mechanical advantage in a “block and tackle” or “pulley” fashion.', 'Reeling out and in of line can cause a traveling block (e.g., and whatever may be hanging underneath it), to be lowered into or raised out of a bore.', 'Reeling out of line may be powered by gravity and reeling in by a motor, an engine, etc.', '(e.g., an electric motor, a diesel engine, etc.).', 'As an example, a crown block can include a set of pulleys (e.g., sheaves) that can be located at or near a top of a derrick or a mast, over which line is threaded.', 'A traveling block can include a set of sheaves that can be moved up and down in a derrick or a mast via line threaded in the set of sheaves of the traveling block and in the set of sheaves of a crown block.', 'A crown block, a traveling block and a line can form a pulley system of a derrick or a mast, which may enable handling of heavy loads (e.g., drillstring, pipe, casing, liners, etc.) to be lifted out of or lowered into a bore.', 'As an example, line may be about a centimeter to about five centimeters in diameter as, for example, steel cable.', 'Through use of a set of sheaves, such line may carry loads heavier than the line could support as a single strand.', 'As an example, a derrickman may be a rig crew member that works on a platform attached to a derrick or a mast.', 'A derrick can include a landing on which a derrickman may stand.', 'As an example, such a landing may be about 10 meters or more above a rig floor.', 'In an operation referred to as trip out of the hole (TOH), a derrickman may wear a safety harness that enables leaning out from the work landing (e.g., monkeyboard) to reach pipe located at or near the center of a derrick or a mast and to throw a line around the pipe and pull it back into its storage location (e.g., fingerboards), for example, until it may be desirable to run the pipe back into the bore.', 'As an example, a rig may include automated pipe-handling equipment such that the derrickman controls the machinery rather than physically handling the pipe.', 'As an example, a trip may refer to the act of pulling equipment from a bore and/or placing equipment in a bore.', 'As an example, equipment may include a drillstring that can be pulled out of a hole and/or placed or replaced in a hole.', 'As an example, a pipe trip may be performed where a drill bit has dulled or has otherwise ceased to drill efficiently and is to be replaced.', 'As an example, a trip that pulls equipment out of a borehole may be referred to as pulling out of hole (POOH) and a trip that runs equipment into a borehole may be referred to as running in hole (RIH).', 'FIG.', '2\n shows an example of a wellsite system \n200\n (e.g., at a wellsite that may be onshore or offshore).', 'As shown, the wellsite system \n200\n can include a mud tank \n201\n for holding mud and other material (e.g., where mud can be a drilling fluid), a suction line \n203\n that serves as an inlet to a mud pump \n204\n for pumping mud from the mud tank \n201\n such that mud flows to a vibrating hose \n206\n, a drawworks \n207\n for winching drill line or drill lines \n212\n, a standpipe \n208\n that receives mud from the vibrating hose \n206\n, a kelly hose \n209\n that receives mud from the standpipe \n208\n, a gooseneck or goosenecks \n210\n, a traveling block \n211\n, a crown block \n213\n for carrying the traveling block \n211\n via the drill line or drill lines \n212\n (see, e.g., the crown block \n173\n of \nFIG.', '1\n), a derrick \n214\n (see, e.g., the derrick \n172\n of \nFIG.', '1\n), a kelly \n218\n or a top drive \n240\n, a kelly drive bushing \n219\n, a rotary table \n220\n, a drill floor \n221\n, a bell nipple \n222\n, one or more blowout preventors (BOPs) \n223\n, a drillstring \n225\n, a drill bit \n226\n, a casing head \n227\n and a flow pipe \n228\n that carries mud and other material to, for example, the mud tank \n201\n.', 'In the example system of \nFIG.', '2\n, a borehole \n232\n is formed in subsurface formations \n230\n by rotary drilling; noting that various example embodiments may also use one or more directional drilling techniques, equipment, etc.', 'As shown in the example of \nFIG.', '2\n, the drillstring \n225\n is suspended within the borehole \n232\n and has a drillstring assembly \n250\n that includes the drill bit \n226\n at its lower end.', 'As an example, the drillstring assembly \n250\n may be a bottom hole assembly (BHA).', 'The wellsite system \n200\n can provide for operation of the drillstring \n225\n and other operations.', 'As shown, the wellsite system \n200\n includes the traveling block \n211\n and the derrick \n214\n positioned over the borehole \n232\n.', 'As mentioned, the wellsite system \n200\n can include the rotary table \n220\n where the drillstring \n225\n pass through an opening in the rotary table \n220\n.', 'As shown in the example of \nFIG.', '2\n, the wellsite system \n200\n can include the kelly \n218\n and associated components, etc., or a top drive \n240\n and associated components.', 'As to a kelly example, the kelly \n218\n may be a square or hexagonal metal/alloy bar with a hole drilled therein that serves as a mud flow path.', 'The kelly \n218\n can be used to transmit rotary motion from the rotary table \n220\n via the kelly drive bushing \n219\n to the drillstring \n225\n, while allowing the drillstring \n225\n to be lowered or raised during rotation.', 'The kelly \n218\n can pass through the kelly drive bushing \n219\n, which can be driven by the rotary table \n220\n.', 'As an example, the rotary table \n220\n can include a master bushing that operatively couples to the kelly drive bushing \n219\n such that rotation of the rotary table \n220\n can turn the kelly drive bushing \n219\n and hence the kelly \n218\n.', 'The kelly drive bushing \n219\n can include an inside profile matching an outside profile (e.g., square, hexagonal, etc.) of the kelly \n218\n; however, with slightly larger dimensions so that the kelly \n218\n can freely move up and down inside the kelly drive bushing \n219\n.', 'As to a top drive example, the top drive \n240\n can provide functions performed by a kelly and a rotary table.', 'The top drive \n240\n can turn the drillstring \n225\n.', 'As an example, the top drive \n240\n can include one or more motors (e.g., electric and/or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drillstring \n225\n itself.', 'The top drive \n240\n can be suspended from the traveling block \n211\n, so the rotary mechanism is free to travel up and down the derrick \n214\n.', 'As an example, a top drive \n240\n may allow for drilling to be performed with more joint stands than a kelly/rotary table approach.', 'In the example of \nFIG.', '2\n, the mud tank \n201\n can hold mud, which can be one or more types of drilling fluids.', 'As an example, a wellbore may be drilled to produce fluid, inject fluid or both (e.g., hydrocarbons, minerals, water, etc.).', 'In the example of \nFIG.', '2\n, the drillstring \n225\n (e.g., including one or more downhole tools) may be composed of a series of pipes threadably connected together to form a long tube with the drill bit \n226\n at the lower end thereof.', 'As the drillstring \n225\n is advanced into a wellbore for drilling, at some point in time prior to or coincident with drilling, the mud may be pumped by the pump \n204\n from the mud tank \n201\n (e.g., or other source) via a the lines \n206\n, \n208\n and \n209\n to a port of the kelly \n218\n or, for example, to a port of the top drive \n240\n.', 'The mud can then flow via a passage (e.g., or passages) in the drillstring \n225\n and out of ports located on the drill bit \n226\n (see, e.g., a directional arrow).', 'As the mud exits the drillstring \n225\n via ports in the drill bit \n226\n, it can then circulate upwardly through an annular region between an outer surface(s) of the drillstring \n225\n and surrounding wall(s) (e.g., open borehole, casing, etc.), as indicated by directional arrows.', 'In such a manner, the mud lubricates the drill bit \n226\n and carries heat energy (e.g., frictional or other energy) and formation cuttings to the surface where the mud (e.g., and cuttings) may be returned to the mud tank \n201\n, for example, for recirculation (e.g., with processing to remove cuttings, etc.).', 'The mud pumped by the pump \n204\n into the drillstring \n225\n may, after exiting the drillstring \n225\n, form a mudcake that lines the wellbore which, among other functions, may reduce friction between the drillstring \n225\n and surrounding wall(s) (e.g., borehole, casing, etc.).', 'A reduction in friction may facilitate advancing or retracting the drillstring \n225\n.', 'During a drilling operation, the entire drill string \n225\n may be pulled from a wellbore and optionally replaced, for example, with a new or sharpened drill bit, a smaller diameter drill string, etc.', 'As mentioned, the act of pulling a drill string out of a hole or replacing it in a hole is referred to as tripping.', 'A trip may be referred to as an upward trip or an outward trip or as a downward trip or an inward trip depending on trip direction.', 'As an example, consider a downward trip where upon arrival of the drill bit \n226\n of the drill string \n225\n at a bottom of a wellbore, pumping of the mud commences to lubricate the drill bit \n226\n for purposes of drilling to enlarge the wellbore.', 'As mentioned, the mud can be pumped by the pump \n204\n into a passage of the drillstring \n225\n and, upon filling of the passage, the mud may be used as a transmission medium to transmit energy, for example, energy that may encode information as in mud-pulse telemetry.', 'As an example, mud-pulse telemetry equipment may include a downhole device configured to effect changes in pressure in the mud to create an acoustic wave or waves upon which information may modulated.', 'In such an example, information from downhole equipment (e.g., one or more modules of the drillstring \n225\n) may be transmitted uphole to an uphole device, which may relay such information to other equipment for processing, control, etc.', 'As an example, telemetry equipment may operate via transmission of energy via the drillstring \n225\n itself.', 'For example, consider a signal generator that imparts coded energy signals to the drillstring \n225\n and repeaters that may receive such energy and repeat it to further transmit the coded energy signals (e.g., information, etc.).', 'As an example, the drillstring \n225\n may be fitted with telemetry equipment \n252\n that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the mud can cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator creates pressure pulses in the mud, and a controllable brake for selectively braking rotation of the modulator rotor to modulate pressure pulses.', 'In such example, an alternator may be coupled to the aforementioned drive shaft where the alternator includes at least one stator winding electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate the pressure pulses in the mud.', 'In the example of \nFIG.', '2\n, an uphole control and/or data acquisition system \n262\n may include circuitry to sense pressure pulses generated by telemetry equipment \n252\n and, for example, communicate sensed pressure pulses or information derived therefrom for process, control, etc.', 'The assembly \n250\n of the illustrated example includes a logging-while-drilling (LWD) module \n254\n, a measurement-while-drilling (MWD) module \n256\n, an optional module \n258\n, a rotary-steerable system (RSS) and/or motor \n260\n, and the drill bit \n226\n.', 'Such components or modules may be referred to as tools where a drillstring can include a plurality of tools.', 'As to a RSS, it involves technology utilized for direction drilling.', 'Directional drilling involves drilling into the Earth to form a deviated bore such that the trajectory of the bore is not vertical; rather, the trajectory deviates from vertical along one or more portions of the bore.', 'As an example, consider a target that is located at a lateral distance from a surface location where a rig may be stationed.', 'In such an example, drilling can commence with a vertical portion and then deviate from vertical such that the bore is aimed at the target and, eventually, reaches the target.', 'Directional drilling may be implemented where a target may be inaccessible from a vertical location at the surface of the Earth, where material exists in the Earth that may impede drilling or otherwise be detrimental (e.g., consider a salt dome, etc.), where a formation is laterally extensive (e.g., consider a relatively thin yet laterally extensive reservoir), where multiple bores are to be drilled from a single surface bore, where a relief well is desired, etc.', 'One approach to directional drilling involves a mud motor; however, a mud motor can present some challenges depending on factors such as rate of penetration (ROP), transferring weight to a bit (e.g., weight on bit, WOB) due to friction, etc.', 'A mud motor can be a positive displacement motor (PDM) that operates to drive a bit during directional drilling.', 'A PDM operates as drilling fluid is pumped through it where the PDM converts hydraulic power of the drilling fluid into mechanical power to cause the bit to rotate.', 'A PDM can operate in a so-called sliding mode, when the drillstring is not rotated from the surface.', 'A RSS can drill directionally where there is continuous rotation from surface equipment, which can alleviate the sliding of a steerable motor (e.g., a PDM).', 'A RSS may be deployed when drilling directionally (e.g., deviated, horizontal, or extended-reach wells).', 'A RSS can aim to minimize interaction with a borehole wall, which can help to preserve borehole quality.', 'A RSS can aim to exert a relatively consistent side force akin to stabilizers that rotate with the drillstring or orient the bit in the desired direction while continuously rotating at the same number of rotations per minute as the drillstring.', 'The LWD module \n254\n may be housed in a suitable type of drill collar and can contain one or a plurality of selected types of logging tools.', 'It will also be understood that more than one LWD and/or MWD module can be employed, for example, as represented at by the module \n256\n of the drillstring assembly \n250\n.', 'Where the position of an LWD module is mentioned, as an example, it may refer to a module at the position of the LWD module \n254\n, the module \n256\n, etc.', 'An LWD module can include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment.', 'In the illustrated example, the LWD module \n254\n may include a seismic measuring device.', 'The MWD module \n256\n may be housed in a suitable type of drill collar and can contain one or more devices for measuring characteristics of the drillstring \n225\n and the drill bit \n226\n.', 'As an example, the MWD tool \n254\n may include equipment for generating electrical power, for example, to power various components of the drillstring \n225\n.', 'As an example, the MWD tool \n254\n may include the telemetry equipment \n252\n, for example, where the turbine impeller can generate power by flow of the mud; it being understood that other power and/or battery systems may be employed for purposes of powering various components.', 'As an example, the MWD module \n256\n may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.\n \nFIG.', '2\n also shows some examples of types of holes that may be drilled.', 'For example, consider a slant hole \n272\n, an S-shaped hole \n274\n, a deep inclined hole \n276\n and a horizontal hole \n278\n.', 'As an example, a drilling operation can include directional drilling where, for example, at least a portion of a well includes a curved axis.', 'For example, consider a radius that defines curvature where an inclination with regard to the vertical may vary until reaching an angle between about 30 degrees and about 60 degrees or, for example, an angle to about 90 degrees or possibly greater than about 90 degrees.', 'As an example, a directional well can include several shapes where each of the shapes may aim to meet particular operational demands.', 'As an example, a drilling process may be performed on the basis of information as and when it is relayed to a drilling engineer.', 'As an example, inclination and/or direction may be modified based on information received during a drilling process.', 'As an example, deviation of a bore may be accomplished in part by use of a downhole motor and/or a turbine.', 'As to a motor, for example, a drillstring can include a positive displacement motor (PDM).', 'As an example, a system may be a steerable system and include equipment to perform method such as geosteering.', 'As mentioned, a steerable system can be or include an RSS.', 'As an example, a steerable system can include a PDM or of a turbine on a lower part of a drillstring which, just above a drill bit, a bent sub can be mounted.', 'As an example, above a PDM, MWD equipment that provides real time or near real time data of interest (e.g., inclination, direction, pressure, temperature, real weight on the drill bit, torque stress, etc.) and/or LWD equipment may be installed.', 'As to the latter, LWD equipment can make it possible to send to the surface various types of data of interest, including for example, geological data (e.g., gamma ray log, resistivity, density and sonic logs, etc.).', 'The coupling of sensors providing information on the course of a well trajectory, in real time or near real time, with, for example, one or more logs characterizing the formations from a geological viewpoint, can allow for implementing a geosteering method.', 'Such a method can include navigating a subsurface environment, for example, to follow a desired route to reach a desired target or targets.', 'As an example, a drillstring can include an azimuthal density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring inclination, azimuth and shocks; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma ray related phenomena; one or more variable gauge stabilizers; one or more bend joints; and a geosteering tool, which may include a motor and optionally equipment for measuring and/or responding to one or more of inclination, resistivity and gamma ray related phenomena.', 'As an example, geosteering can include intentional directional control of a wellbore based on results of downhole geological logging measurements in a manner that aims to keep a directional wellbore within a desired region, zone (e.g., a pay zone), etc.', 'As an example, geosteering may include directing a wellbore to keep the wellbore in a particular section of a reservoir, for example, to minimize gas and/or water breakthrough and, for example, to maximize economic production from a well that includes the wellbore.\n \nReferring again to \nFIG.', '2\n, the wellsite system \n200\n can include one or more sensors \n264\n that are operatively coupled to the control and/or data acquisition system \n262\n.', 'As an example, a sensor or sensors may be at surface locations.', 'As an example, a sensor or sensors may be at downhole locations.', 'As an example, a sensor or sensors may be at one or more remote locations that are not within a distance of the order of about one hundred meters from the wellsite system \n200\n.', 'As an example, a sensor or sensor may be at an offset wellsite where the wellsite system \n200\n and the offset wellsite are in a common field (e.g., oil and/or gas field).', 'As an example, one or more of the sensors \n264\n can be provided for tracking pipe, tracking movement of at least a portion of a drillstring, etc.\n \nAs an example, the system \n200\n can include one or more sensors \n266\n that can sense and/or transmit signals to a fluid conduit such as a drilling fluid conduit (e.g., a drilling mud conduit).', 'For example, in the system \n200\n, the one or more sensors \n266\n can be operatively coupled to portions of the standpipe \n208\n through which mud flows.', 'As an example, a downhole tool can generate pulses that can travel through the mud and be sensed by one or more of the one or more sensors \n266\n.', 'In such an example, the downhole tool can include associated circuitry such as, for example, encoding circuitry that can encode signals, for example, to reduce demands as to transmission.', 'As an example, circuitry at the surface may include decoding circuitry to decode encoded information transmitted at least in part via mud-pulse telemetry.', 'As an example, circuitry at the surface may include encoder circuitry and/or decoder circuitry and circuitry downhole may include encoder circuitry and/or decoder circuitry.', 'As an example, the system \n200\n can include a transmitter that can generate signals that can be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.', 'As an example, one or more portions of a drillstring may become stuck.', 'The term stuck can refer to one or more of varying degrees of inability to move or remove a drillstring from a bore.', 'As an example, in a stuck condition, it might be possible to rotate pipe or lower it back into a bore or, for example, in a stuck condition, there may be an inability to move the drillstring axially in the bore, though some amount of rotation may be possible.', 'As an example, in a stuck condition, there may be an inability to move at least a portion of the drillstring axially and rotationally.', 'As to the term “stuck pipe”, this can refer to a portion of a drillstring that cannot be rotated or moved axially.', 'As an example, a condition referred to as “differential sticking” can be a condition whereby the drillstring cannot be moved (e.g., rotated or reciprocated) along the axis of the bore.', 'Differential sticking may occur when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring.', 'Differential sticking can have time and financial cost.', 'As an example, a sticking force can be a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon.', 'This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking pipe as can a high differential pressure applied over a small area.', 'As an example, a condition referred to as “mechanical sticking” can be a condition where limiting or prevention of motion of the drillstring by a mechanism other than differential pressure sticking occurs.', 'Mechanical sticking can be caused, for example, by one or more of junk in the hole, wellbore geometry anomalies, cement, keyseats or a buildup of cuttings in the annulus.', 'FIG.', '3\n shows an example of a system \n300\n that includes various equipment for evaluation \n310\n, planning \n320\n, engineering \n330\n and operations \n340\n.', 'For example, a drilling workflow framework \n301\n, a seismic-to-simulation framework \n302\n, a technical data framework \n303\n and a drilling framework \n304\n may be implemented to perform one or more processes such as a evaluating a formation \n314\n, evaluating a process \n318\n, generating a trajectory \n324\n, validating a trajectory \n328\n, formulating constraints \n334\n, designing equipment and/or processes based at least in part on constraints \n338\n, performing drilling \n344\n and evaluating drilling and/or formation \n348\n.', 'In the example of \nFIG.', '3\n, the seismic-to-simulation framework \n302\n can be, for example, the PETREL framework (Schlumberger, Houston, Tex.) and the technical data framework \n303\n can be, for example, the TECHLOG framework (Schlumberger, Houston, Tex.).', 'As an example, a framework can include entities that may include earth entities, geological objects or other objects such as wells, surfaces, reservoirs, etc. Entities can include virtual representations of actual physical entities that are reconstructed for purposes of one or more of evaluation, planning, engineering, operations, etc.', 'Entities may include entities based on data acquired via sensing, observation, etc. (e.g., seismic data and/or other information).', 'An entity may be characterized by one or more properties (e.g., a geometrical pillar grid entity of an earth model may be characterized by a porosity property).', 'Such properties may represent one or more measurements (e.g., acquired data), calculations, etc.', 'A framework may be an object-based framework.', 'In such a framework, entities may include entities based on pre-defined classes, for example, to facilitate modeling, analysis, simulation, etc.', 'An example of an object-based framework is the MICROSOFT .NET framework (Redmond, Wash.), which provides a set of extensible object classes.', 'In the .NET framework, an object class encapsulates a module of reusable code and associated data structures.', 'Object classes can be used to instantiate object instances for use in by a program, script, etc.', 'For example, borehole classes may define objects for representing boreholes based on well data.', 'As an example, a framework may be implemented within or in a manner operatively coupled to the DELFI cognitive exploration and production (E&P) environment (Schlumberger, Houston, Tex.), which is a secure, cognitive, cloud-based collaborative environment that integrates data and workflows with digital technologies, such as artificial intelligence and machine learning.', 'As an example, such an environment can provide for operations that involve one or more frameworks.', 'As an example, a framework can include an analysis component that may allow for interaction with a model or model-based results (e.g., simulation results, etc.).', 'As to simulation, a framework may operatively link to or include a simulator such as the ECLIPSE reservoir simulator (Schlumberger, Houston Tex.), the INTERSECT reservoir simulator (Schlumberger, Houston Tex.), etc.', 'The aforementioned PETREL framework provides components that allow for optimization of exploration and development operations.', 'The PETREL framework includes seismic to simulation software components that can output information for use in increasing reservoir performance, for example, by improving asset team productivity.', 'Through use of such a framework, various professionals (e.g., geophysicists, geologists, well engineers, reservoir engineers, etc.) can develop collaborative workflows and integrate operations to streamline processes.', 'Such a framework may be considered an application and may be considered a data-driven application (e.g., where data is input for purposes of modeling, simulating, etc.).', 'As mentioned with respect to the DELFI environment, one or more frameworks may be interoperative and/or run upon one or another.', 'As an example, a framework environment marketed as the OCEAN framework environment (Schlumberger, Houston, Tex.) may be utilized, which allows for integration of add-ons (or plug-ins) into a PETREL framework workflow.', 'In an example embodiment, various components may be implemented as add-ons (or plug-ins) that conform to and operate according to specifications of a framework environment (e.g., according to application programming interface (API) specifications, etc.).', 'As an example, a framework can include a model simulation layer along with a framework services layer, a framework core layer and a modules layer.', 'In a framework environment (e.g., OCEAN, DELFI, etc.), a model simulation layer can include or operatively link to a model-centric framework.', 'In an example embodiment, a framework may be considered to be a data-driven application.', 'For example, the PETREL framework can include features for model building and visualization.', 'As an example, a model may include one or more grids where a grid can be a spatial grid that conforms to spatial locations per acquired data (e.g., satellite data, logging data, seismic data, etc.).', 'As an example, a model simulation layer may provide domain objects, act as a data source, provide for rendering and provide for various user interfaces.', 'Rendering capabilities may provide a graphical environment in which applications can display their data while user interfaces may provide a common look and feel for application user interface components.', 'As an example, domain objects can include entity objects, property objects and optionally other objects.', 'Entity objects may be used to geometrically represent wells, surfaces, reservoirs, etc., while property objects may be used to provide property values as well as data versions and display parameters.', 'For example, an entity object may represent a well where a property object provides log information as well as version information and display information (e.g., to display the well as part of a model).', 'As an example, data may be stored in one or more data sources (or data stores, generally physical data storage devices), which may be at the same or different physical sites and accessible via one or more networks.', 'As an example, a model simulation layer may be configured to model projects.', 'As such, a particular project may be stored where stored project information may include inputs, models, results and cases.', 'Thus, upon completion of a modeling session, a user may store a project.', 'At a later time, the project can be accessed and restored using the model simulation layer, which can recreate instances of the relevant domain objects.', 'As an example, the system \n300\n may be used to perform one or more workflows.', 'A workflow may be a process that includes a number of worksteps.', 'A workstep may operate on data, for example, to create new data, to update existing data, etc.', 'As an example, a workflow may operate on one or more inputs and create one or more results, for example, based on one or more algorithms.', 'As an example, a system may include a workflow editor for creation, editing, executing, etc. of a workflow.', 'In such an example, the workflow editor may provide for selection of one or more pre-defined worksteps, one or more customized worksteps, etc.', 'As an example, a workflow may be a workflow implementable at least in part in the PETREL framework, for example, that operates on seismic data, seismic attribute(s), etc.', 'As an example, seismic data can be data acquired via a seismic survey where sources and receivers are positioned in a geologic environment to emit and receive seismic energy where at least a portion of such energy can reflect off subsurface structures.', 'As an example, a seismic data analysis framework or frameworks (e.g., consider the OMEGA framework, marketed by Schlumberger, Houston, Tex.) may be utilized to determine depth, extent, properties, etc. of subsurface structures.', 'As an example, seismic data analysis can include forward modeling and/or inversion, for example, to iteratively build a model of a subsurface region of a geologic environment.', 'As an example, a seismic data analysis framework may be part of or operatively coupled to a seismic-to-simulation framework (e.g., the PETREL framework, etc.).', 'As an example, a workflow may be a process implementable at least in part in a framework environment and by one or more frameworks.', 'As an example, a workflow may include one or more worksteps that access a set of instructions such as a plug-in (e.g., external executable code, etc.).', 'As an example, a framework environment may be cloud-based where cloud resources are utilized that may be operatively coupled to one or more pieces of field equipment such that data can be acquired, transmitted, stored, processed, analyzed, etc., using features of a framework environment.', 'As an example, a framework environment may employ various types of services, which may be backend, frontend or backend and frontend services.', 'For example, consider a client-server type of architecture where communications may occur via one or more application programming interfaces (APIs), one or more microservices, etc.', 'As an example, a framework may provide for modeling petroleum systems.', 'For example, the modeling framework marketed as the PETROMOD framework (Schlumberger, Houston, Tex.), which includes features for input of various types of information (e.g., seismic, well, geological, etc.) to model evolution of a sedimentary basin.', 'The PETROMOD framework provides for petroleum systems modeling via input of various data such as seismic data, well data and other geological data, for example, to model evolution of a sedimentary basin.', 'The PETROMOD framework may predict if, and how, a reservoir has been charged with hydrocarbons, including, for example, the source and timing of hydrocarbon generation, migration routes, quantities, pore pressure and hydrocarbon type in the subsurface or at surface conditions.', 'In combination with a framework such as the PETREL framework, workflows may be constructed to provide basin-to-prospect scale exploration solutions.', 'Data exchange between frameworks can facilitate construction of models, analysis of data (e.g., PETROMOD framework data analyzed using PETREL framework capabilities), and coupling of workflows.', 'As mentioned, a drillstring can include various tools that may make measurements.', 'As an example, a wireline tool or another type of tool may be utilized to make measurements.', 'As an example, a tool may be configured to acquire electrical borehole images.', 'As an example, the fullbore Formation MicroImager (FMI) tool (Schlumberger, Houston, Tex.) can acquire borehole image data.', 'A data acquisition sequence for such a tool can include running the tool into a borehole with acquisition pads closed, opening and pressing the pads against a wall of the borehole, delivering electrical current into the material defining the borehole while translating the tool in the borehole, and sensing current remotely, which is altered by interactions with the material.', 'Analysis of formation information may reveal features such as, for example, vugs, dissolution planes (e.g., dissolution along bedding planes), stress-related features, dip events, etc.', 'As an example, a tool may acquire information that may help to characterize a reservoir, optionally a fractured reservoir where fractures may be natural and/or artificial (e.g., hydraulic fractures).', 'As an example, information acquired by a tool or tools may be analyzed using a framework such as the TECHLOG framework.', 'As an example, the TECHLOG framework can be interoperable with one or more other frameworks such as, for example, the PETREL framework.', 'As an example, various aspects of a workflow may be completed automatically, may be partially automated, or may be completed manually, as by a human user interfacing with a software application that executes using hardware (e.g., local and/or remote).', 'As an example, a workflow may be cyclic, and may include, as an example, four stages such as, for example, an evaluation stage (see, e.g., the evaluation equipment \n310\n), a planning stage (see, e.g., the planning equipment \n320\n), an engineering stage (see, e.g., the engineering equipment \n330\n) and an execution stage (see, e.g., the operations equipment \n340\n).', 'As an example, a workflow may commence at one or more stages, which may progress to one or more other stages (e.g., in a serial manner, in a parallel manner, in a cyclical manner, etc.).', 'As an example, a workflow can commence with an evaluation stage, which may include a geological service provider evaluating a formation (see, e.g., the evaluation block \n314\n).', 'As an example, a geological service provider may undertake the formation evaluation using a computing system executing a software package tailored to such activity; or, for example, one or more other suitable geology platforms may be employed (e.g., alternatively or additionally).', 'As an example, the geological service provider may evaluate the formation, for example, using earth models, geophysical models, basin models, petrotechnical models, combinations thereof, and/or the like.', 'Such models may take into consideration a variety of different inputs, including offset well data, seismic data, pilot well data, other geologic data, etc.', 'The models and/or the input may be stored in the database maintained by the server and accessed by the geological service provider.', 'As an example, a workflow may progress to a geology and geophysics (“G&G”) service provider, which may generate a well trajectory (see, e.g., the generation block \n324\n), which may involve execution of one or more G&G software packages.', 'Examples of such software packages include the PETREL framework.', 'As an example, a G&G service provider may determine a well trajectory or a section thereof, based on, for example, one or more model(s) provided by a formation evaluation (e.g., per the evaluation block \n314\n), and/or other data, e.g., as accessed from one or more databases (e.g., maintained by one or more servers, etc.).', 'As an example, a well trajectory may take into consideration various “basis of design” (BOD) constraints, such as general surface location, target (e.g., reservoir) location, and the like.', 'As an example, a trajectory may incorporate information about tools, bottom-hole assemblies, casing sizes, etc., that may be used in drilling the well.', 'A well trajectory determination may take into consideration a variety of other parameters, including risk tolerances, fluid weights and/or plans, bottom-hole pressures, drilling time, etc.', 'As an example, a workflow may progress to a first engineering service provider (e.g., one or more processing machines associated therewith), which may validate a well trajectory and, for example, relief well design (see, e.g., the validation block \n328\n).', 'Such a validation process may include evaluating physical properties, calculations, risk tolerances, integration with other aspects of a workflow, etc.', 'As an example, one or more parameters for such determinations may be maintained by a server and/or by the first engineering service provider; noting that one or more model(s), well trajectory(ies), etc. may be maintained by a server and accessed by the first engineering service provider.', 'For example, the first engineering service provider may include one or more computing systems executing one or more software packages.', 'As an example, where the first engineering service provider rejects or otherwise suggests an adjustment to a well trajectory, the well trajectory may be adjusted or a message or other notification sent to the G&G service provider requesting such modification.', 'As an example, one or more engineering service providers (e.g., first, second, etc.) may provide a casing design, bottom-hole assembly (BHA) design, fluid design, and/or the like, to implement a well trajectory (see, e.g., the design block \n338\n).', 'In some embodiments, a second engineering service provider may perform such design using one of more software applications.', 'Such designs may be stored in one or more databases maintained by one or more servers, which may, for example, employ STUDIO framework tools (Schlumberger, Houston, Tex.), and may be accessed by one or more of the other service providers in a workflow.', 'As an example, a second engineering service provider may seek approval from a third engineering service provider for one or more designs established along with a well trajectory.', "In such an example, the third engineering service provider may consider various factors as to whether the well engineering plan is acceptable, such as economic variables (e.g., oil production forecasts, costs per barrel, risk, drill time, etc.), and may request authorization for expenditure, such as from the operating company's representative, well-owner's representative, or the like (see, e.g., the formulation block \n334\n).", 'As an example, at least some of the data upon which such determinations are based may be stored in one or more database maintained by one or more servers.', 'As an example, a first, a second, and/or a third engineering service provider may be provided by a single team of engineers or even a single engineer, and thus may or may not be separate entities.', 'As an example, where economics may be unacceptable or subject to authorization being withheld, an engineering service provider may suggest changes to casing, a bottom-hole assembly, and/or fluid design, or otherwise notify and/or return control to a different engineering service provider, so that adjustments may be made to casing, a bottom-hole assembly, and/or fluid design.', 'Where modifying one or more of such designs is impracticable within well constraints, trajectory, etc., the engineering service provider may suggest an adjustment to the well trajectory and/or a workflow may return to or otherwise notify an initial engineering service provider and/or a G&G service provider such that either or both may modify the well trajectory.', 'As an example, a workflow can include considering a well trajectory, including an accepted well engineering plan, and a formation evaluation.', 'Such a workflow may then pass control to a drilling service provider, which may implement the well engineering plan, establishing safe and efficient drilling, maintaining well integrity, and reporting progress as well as operating parameters (see, e.g., the blocks \n344\n and \n348\n).', 'As an example, operating parameters, formation encountered, data collected while drilling (e.g., using logging-while-drilling or measuring-while-drilling technology), may be returned to a geological service provider for evaluation.', 'As an example, the geological service provider may then re-evaluate the well trajectory, or one or more other aspects of the well engineering plan, and may, in some cases, and potentially within predetermined constraints, adjust the well engineering plan according to the real-life drilling parameters (e.g., based on acquired data in the field, etc.).', 'Whether the well is entirely drilled, or a section thereof is completed, depending on the specific embodiment, a workflow may proceed to a post review (see, e.g., the evaluation block \n318\n).', 'As an example, a post review may include reviewing drilling performance.', 'As an example, a post review may further include reporting the drilling performance (e.g., to one or more relevant engineering, geological, or G&G service providers).', 'Various activities of a workflow may be performed consecutively and/or may be performed out of order (e.g., based partially on information from templates, nearby wells, etc. to fill in any gaps in information that is to be provided by another service provider).', 'As an example, undertaking one activity may affect the results or basis for another activity, and thus may, either manually or automatically, call for a variation in one or more workflow activities, work products, etc.', 'As an example, a server may allow for storing information on a central database accessible to various service providers where variations may be sought by communication with an appropriate service provider, may be made automatically, or may otherwise appear as suggestions to the relevant service provider.', 'Such an approach may be considered to be a holistic approach to a well workflow, in comparison to a sequential, piecemeal approach.', 'As an example, various actions of a workflow may be repeated multiple times during drilling of a wellbore.', 'For example, in one or more automated systems, feedback from a drilling service provider may be provided at or near real-time, and the data acquired during drilling may be fed to one or more other service providers, which may adjust its piece of the workflow accordingly.', 'As there may be dependencies in other areas of the workflow, such adjustments may permeate through the workflow, e.g., in an automated fashion.', 'In some embodiments, a cyclic process may additionally or instead proceed after a certain drilling goal is reached, such as the completion of a section of the wellbore, and/or after the drilling of the entire wellbore, or on a per-day, week, month, etc. basis.', 'Well planning can include determining a path of a well (e.g., a trajectory) that can extend to a reservoir, for example, to economically produce fluids such as hydrocarbons therefrom.', 'Well planning can include selecting a drilling and/or completion assembly which may be used to implement a well plan.', 'As an example, various constraints can be imposed as part of well planning that can impact design of a well.', 'As an example, such constraints may be imposed based at least in part on information as to known geology of a subterranean domain, presence of one or more other wells (e.g., actual and/or planned, etc.) in an area (e.g., consider collision avoidance), etc.', 'As an example, one or more constraints may be imposed based at least in part on characteristics of one or more tools, components, etc.', 'As an example, one or more constraints may be based at least in part on factors associated with drilling time and/or risk tolerance.', 'As an example, a system can allow for a reduction in waste, for example, as may be defined according to LEAN.', 'In the context of LEAN, consider one or more of the following types of waste: transport (e.g., moving items unnecessarily, whether physical or data); inventory (e.g., components, whether physical or informational, as work in process, and finished product not being processed); motion (e.g., people or equipment moving or walking unnecessarily to perform desired processing); waiting (e.g., waiting for information, interruptions of production during shift change, etc.); overproduction (e.g., production of material, information, equipment, etc. ahead of demand); over processing (e.g., resulting from poor tool or product design creating activity); and defects (e.g., effort involved in inspecting for and fixing defects whether in a plan, data, equipment, etc.).', 'As an example, a system that allows for actions (e.g., methods, workflows, etc.) to be performed in a collaborative manner can help to reduce one or more types of waste.', 'As an example, a system can be utilized to implement a method for facilitating distributed well engineering, planning, and/or drilling system design across multiple computation devices where collaboration can occur among various different users (e.g., some being local, some being remote, some being mobile, etc.).', 'In such a system, the various users via appropriate devices may be operatively coupled via one or more networks (e.g., local and/or wide area networks, public and/or private networks, land-based, marine-based and/or areal networks, etc.).', 'As an example, a system may allow well engineering, planning, and/or drilling system design to take place via a subsystems approach where a wellsite system is composed of various subsystem, which can include equipment subsystems and/or operational subsystems (e.g., control subsystems, etc.).', 'As an example, computations may be performed using various computational platforms/devices that are operatively coupled via communication links (e.g., network links, etc.).', 'As an example, one or more links may be operatively coupled to a common database (e.g., a server site, etc.).', 'As an example, a particular server or servers may manage receipt of notifications from one or more devices and/or issuance of notifications to one or more devices.', 'As an example, a system may be implemented for a project where the system can output a well plan, for example, as a digital well plan, a paper well plan, a digital and paper well plan, etc.', 'Such a well plan can be a complete well engineering plan or design for the particular project.', 'FIG.', '4\n shows an example of a wellsite system \n400\n, specifically, \nFIG.', '4\n shows the wellsite system \n400\n in an approximate side view and an approximate plan view along with a block diagram of a system \n470\n.', 'In the example of \nFIG.', '4\n, the wellsite system \n400\n can include a cabin \n410\n, a rotary table \n422\n, drawworks \n424\n, a mast \n426\n (e.g., optionally carrying a top drive, etc.), mud tanks \n430\n (e.g., with one or more pumps, one or more shakers, etc.), one or more pump buildings \n440\n, a boiler building \n442\n, an HPU building \n444\n (e.g., with a rig fuel tank, etc.), a combination building \n448\n (e.g., with one or more generators, etc.), pipe tubs \n462\n, a catwalk \n464\n, a flare \n468\n, etc.', 'Such equipment can include one or more associated functions and/or one or more associated operational risks, which may be risks as to time, resources, and/or humans.', 'As shown in the example of \nFIG.', '4\n, the wellsite system \n400\n can include a system \n470\n that includes one or more processors \n472\n, memory \n474\n operatively coupled to at least one of the one or more processors \n472\n, instructions \n476\n that can be, for example, stored in the memory \n474\n, and one or more interfaces \n478\n.', 'As an example, the system \n470\n can include one or more processor-readable media that include processor-executable instructions executable by at least one of the one or more processors \n472\n to cause the system \n470\n to control one or more aspects of the wellsite system \n400\n.', 'In such an example, the memory \n474\n can be or include the one or more processor-readable media where the processor-executable instructions can be or include instructions.', 'As an example, a processor-readable medium can be a computer-readable storage medium that is not a signal and that is not a carrier wave.\n \nFIG.', '4\n also shows a battery \n480\n that may be operatively coupled to the system \n470\n, for example, to power the system \n470\n.', 'As an example, the battery \n480\n may be a back-up battery that operates when another power supply is unavailable for powering the system \n470\n.', 'As an example, the battery \n480\n may be operatively coupled to a network, which may be a cloud network.', 'As an example, the battery \n480\n can include smart battery circuitry and may be operatively coupled to one or more pieces of equipment via a SMBus or other type of bus.', 'In the example of \nFIG.', '4\n, services \n490\n are shown as being available, for example, via a cloud platform.', 'Such services can include data services \n492\n, query services \n494\n and drilling services \n496\n.', 'As an example, the services \n490\n may be part of a system such as the system \n300\n of \nFIG.', '3\n.', 'FIG.', '5\n shows an example of a graphical user interface (GUI) \n500\n that includes information associated with a well plan.', 'Specifically, the GUI \n500\n includes a panel \n510\n where surfaces representations \n512\n and \n514\n are rendered along with well trajectories where a location \n516\n can represent a position of a drillstring \n517\n along a well trajectory.', 'The GUI \n500\n may include one or more editing features such as an edit well plan set of features \n530\n.', 'The GUI \n500\n may include information as to individuals of a team \n540\n that are involved, have been involved and/or are to be involved with one or more operations.', 'The GUI \n500\n may include information as to one or more activities \n550\n.', 'As shown in the example of \nFIG.', '5\n, the GUI \n500\n can include a graphical control of a drillstring \n560\n where, for example, various portions of the drillstring \n560\n may be selected to expose one or more associated parameters (e.g., type of equipment, equipment specifications, operational history, etc.).', 'FIG.', '5\n also shows an example of a table \n570\n as a point spreadsheet that specifies information for a plurality of wells.', 'As shown in the example table \n570\n, coordinates such as “x” and “y” and “depth” can be specified for various features of the wells, which can include pad parameters, spacings, toe heights, step outs, initial inclinations, kick offs, etc.', 'In the example of \nFIG.', '5\n, the drillstring graphical control \n560\n includes components such as drill pipe, heavy weight drill pipe (HWDP), subs, collars, jars, stabilizers, motor(s) and a bit.', 'A drillstring can be a combination of drill pipe, a bottom hole assembly (BHA) and one or more other tools, which can include one or more tools that can help a drill bit turn and drill into material (e.g., a formation).', 'FIG.', '6\n shows an example of a graphical user interface \n600\n that includes a schedule organized with respect to time (days, dates, etc.)', 'and with respect to various types of operations.', 'The GUI \n600\n can be part of a well planning system, which may be part of a field development framework.', 'For example, the various operations in the GUI \n600\n can be implemented to drill at least a portion of a well in a geologic environment (e.g., an oil field or oilfield) where the well may be completed for one or more purposes (e.g., production of hydrocarbons, injection of fluid(s), fracturing of rock, etc.).', 'As an example, the GUIs \n500\n and \n600\n can be part of a field development framework.', 'For example, the well plan \n510\n of the GUI \n500\n may be based at least in part on information rendered in the GUI \n600\n.', 'As an example, an interaction with the GUI \n500\n may be processed by one or more processors to generation information that can be rendered to the GUI \n600\n and, for example, vice versa.', 'As mentioned, a framework may be implemented using computing resources (e.g., hardware, communication equipment, etc.)', 'as may be available, for example, in the cloud, a server, a workstation, etc.', 'As an example, a framework can include components that can take certain inputs and generate certain outputs.', 'The outputs of a component may be used as inputs of another component or other components such that a real-time workflow can be constructed.\n \nFIG.', '7\n shows an example of a method \n700\n and an example of a system \n790\n.', 'The method \n710\n includes a selection block \n710\n for selecting an operational context (e.g., well construction, etc.), a provision block \n720\n for provisioning equipment and/or interfaces for purposes of data acquisition and control, a performance block \n730\n for performing operations based at least in part on a digital plan, and a control block \n740\n for controlling performance of operations based at least in part on feedback (e.g., based at least in part on acquired data, etc.).', 'The method \n700\n is shown as including various computer-readable storage medium (CRM) blocks \n711\n, \n721\n, \n731\n, and \n741\n that can include processor-executable instructions that can instruct a computing system, which can be a control system, to perform one or more of the actions described with respect to the method \n700\n.', 'In the example of \nFIG.', '7\n, a system \n790\n includes one or more information storage devices \n791\n, one or more computers \n792\n, one or more networks \n795\n and instructions \n796\n.', 'As to the one or more computers \n792\n, each computer may include one or more processors (e.g., or processing cores) \n793\n and memory \n794\n for storing the instructions \n796\n, for example, executable by at least one of the one or more processors \n793\n (see, e.g., the blocks \n711\n, \n721\n, \n731\n and \n741\n).', 'As an example, a computer may include one or more network interfaces (e.g., wired or wireless), one or more graphics cards, a display interface (e.g., wired or wireless), etc.', 'As an example, the method \n700\n may be a workflow that can be implemented using one or more frameworks that may be within a framework environment.', 'As an example, the system \n790\n can include local and/or remote resources.', 'For example, consider a browser application executing on a client device as being a local resource with respect to a user of the browser application and a cloud-based computing device as being a remote resources with respect to the user.', 'In such an example, the user may interact with the client device via the browser application where information is transmitted to the cloud-based computing device (or devices) and where information may be received in response and rendered to a display operatively coupled to the client device (e.g., via services, APIs, etc.).', 'FIG.', '8\n shows an example of a system \n800\n that can be a well construction ecosystem.', 'As shown, the system \n800\n includes rig infrastructure \n810\n and a drill plan component \n820\n that can generation or otherwise transmit information associated with a plan to be executed utilizing the rig infrastructure \n810\n, for example, via the drilling operations layer \n840\n, which includes a wellsite component \n842\n and an offsite component \n844\n.', 'As shown, data acquired and/or generated by the drilling operations layer \n840\n can be transmitted to a data archiving component \n850\n, which may be utilized, for example, for purposes of planning one or more operations (e.g., per the drilling plan component \n820\n.', 'An example of the system \n800\n of \nFIG.', '8\n is described in a US Provisional Application having Ser.', 'No. 62/670,803 filed 13 May 2018.', 'This is further described in the application with international application no.', 'PCT/US2019/031641, filed 10 May 2019 which is also incorporated by reference.\n \nFIG.', '9\n shows an example of a system \n900\n that includes data \n910\n that can be received by a project management component \n920\n via a project portal where the component \n920\n includes workflow management features, which can include features that operate on the data \n910\n to generate a digital plan such as a drilling digital plan, which may include executable instructions to control one or more pieces of equipment at a rigsite.', 'As shown, the digital plan may be transmitted to a drilling operations component \n930\n (see, e.g., the layer \n840\n of \nFIG.', '8\n).', 'In \nFIG.', '9\n, the project management component \n920\n can output information to an engineering design component \n950\n and an operational design component \n970\n, which include various features as to physical equipment that can be utilized to drill a well.', 'The components \n950\n and \n970\n can be operatively coupled to analysis components such as an automatic engineering analysis component \n980\n and an offset well analysis component \n990\n, which may receive information from a data archiving component \n915\n (e.g., a data storage that includes information organized with respect to offset wells, etc.).', 'As shown in \nFIG.', '9\n, the components \n950\n and \n970\n can be operatively coupled, for example, to facilitate design of equipment that comports with operational conditions (e.g., activities, risk, etc.).', 'As an example, during a process, such as building a drillstring, engineering analyses may be ongoing, optionally automatically such that design considerations for a particular well are taken into account during the building of the drillstring (e.g., an actual drillstring, a plan for a drillstring, etc.).', 'As an example, offset data may be provided on a real-time basis as it becomes available and utilized for purposes of engineering analyses, for example, to account for information gained through drilling at an offset site.\n \nFIG.', '10\n shows an example of a system \n1000\n that includes various layers and operational blocks, including an applications layer \n1010\n that can include a remote access and interface block \n1020\n (e.g., for access to interfaces of rigsite equipment from one or more remote locations, etc.), an intelligence and inferencing block \n1030\n (e.g., resources optionally remote from a rigsite, etc.), an applications delivery and/or GUIs block \n1040\n (e.g., optionally including one or more application programming interfaces, etc.), and a framework layer \n1050\n that includes a core services and/or resources block \n1060\n.', 'In the example of \nFIG.', '10\n, the applications layers \n1010\n can include various applications that can be executable using one or more of the framework layer \n1050\n resources.', 'Such applications can include, for example, applications that operate locally, remotely and/or a combination of remotely and locally.', 'As an example, the system \n1000\n of \nFIG.', '10\n can be utilized as part of a drilling operations layer such as the layer \n840\n of \nFIG.', '8\n.', 'For example, the system \n1000\n of \nFIG.', '10\n may be the offsite component \n844\n (e.g., office site operations control, management, etc.).', 'FIG.', '11\n shows an example of a system \n1100\n that may be implemented, at least in part, via cloud resources \n1101\n.', 'In the example of \nFIG.', '11\n, locations are indicated such as by a rig \n1120\n and an office \n1130\n where the rig \n1120\n can be a rigsite location or locations of rigsites and where the office \n1130\n can be an office location or locations of offices where an office may be at a rigsite or at another site, which may be remote from the rigsite.', 'As shown in \nFIG.', '11\n, the office \n1130\n may access a core \n1160\n via the cloud resources \n1101\n via one or more mechanisms such as via one or more security mechanisms (e.g., security protocol(s) that may rely on a key or keys for authentication, etc.) and one or more application programming interfaces (APIs).', 'As an example, an API can provide for making a call and receiving information responsive to the call.', 'A call may include information that is utilized to determine what information is to be returned responsive to the call.', 'As an example, a local API call may be from an application to an operating system where the API exposes one or more OS functionalities (e.g., access to hardware states, etc.).', 'In a client-server architecture, a call transmitted from a client device to a server device may include information that is utilized by the server device to determine what information to package in a response and/or, for example, utilized to issue a signal to one or more pieces of equipment (e.g., a control signal, etc.).', 'Remote APIs may be implemented to maintain object abstraction in object-oriented programming.', 'For example, a method call, executed locally on a proxy object, can be utilized to invoke a corresponding method on a remote object, using the remoting protocol, and to acquire the result to be used locally as return value.', 'In the example of \nFIG.', '11\n, the office \n1130\n may access the core \n1160\n via various features in one or more manners (see, e.g., the offices \n1130\n to the left and the office \n1130\n to the right).', 'As an example, the office \n1130\n or offices \n1130\n may access the core \n1160\n for utilization of one or more intelligence and/or inferencing features such as indicated by the intelligence and inferencing block \n1030\n of the system \n1000\n of \nFIG.', '10\n.', 'As to the rig \n1120\n, it may be operatively coupled to the core \n1160\n via one or more features such as the access and interface features \n1020\n of the system \n1000\n of \nFIG.', '10\n.', 'As an example, the rig \n1120\n may be operatively coupled to the core \n1160\n via the Advanced Message Queuing Protocol (AMQP), which may be implemented in a secure manner (e.g., AMQPS).', 'Such a protocol can operate as an application layer protocol for message-oriented middleware, etc.', 'Features of AMQP include message orientation, queuing, routing (e.g., including point-to-point and publish-and-subscribe), reliability and security.', 'AMQP mandates the behavior of the messaging provider and client to the extent that implementations from different vendors are interoperable (e.g., akin to SMTP, HTTP, FTP, etc. for interoperable systems).', 'Another approach may utilize a technology such as JAVA messaging service (JMS), which defines an API and a set of behaviors that a messaging implementation is to provide.', 'Specifically, JMS is an API specification (part of the Java EE specification) that defines how message producers and consumers are implemented; whereas, AMQP is considered to be a wire-level protocol.', 'A wire-level protocol is a description of the format of the data that is sent across the network as a stream of bytes.', 'Consequently, a tool that can create and interpret messages that conform to this data format can interoperate with another compliant tool irrespective of implementation language.', 'As shown in the example of \nFIG.', '11\n, the operative coupling of the rig \n1120\n can provide for an Internet of Things (loT) scenario where, for example, various pieces and/or groups of equipment at a rigsite can be provisioned for purposes of data receipt and/or transmission, which may occur, for example, via an AMQP approach.', 'As shown in the example of \nFIG.', '11\n, communications can be routed to a stream block \n1162\n that may host an “Internet of Things” (loT) directory, for example, of provisioned equipment (e.g. data acquisition units, control units, etc.).', 'Such communications may be output to the rig \n1120\n for purposes of onsite instructing of equipment and/or people.', 'As an example, output may be a control signal that causes a piece of drilling equipment or other rigsite equipment to perform an action (e.g., a controlled action).', 'As shown in the example of \nFIG.', '11\n, the stream block \n1162\n can provide data to a data pipeline that is operatively coupled to other resources within the core \n1160\n.', 'For example, the data pipeline may receive information that may be in a particular format (e.g., Digital Log Information Standard (DLIS), Energistics Transfer Protocol (ETP), Wellsite Information Transfer Standard Markup Language (WITSML), etc.).', 'As to examples of resources, which may be cloud resources, database resources, intelligence resources (e.g., AI, etc.), inference resources, security resources, etc., the example of \nFIG.', '11\n shows APACHE resources (Apache Software Foundation, Forest Hill, Md.) that include CASSANDRA database resources and STORM artificial intelligence (AI) resources.', 'The CASSANDRA resources may include a query language (CQL), which offers a model akin to SQL in the sense that data are put in tables containing rows of columns.', 'As to STORM resources, a system can include an analysis engine, which may include a Bayesian network, which may operate as to making inferences based on historical data, modeled data, etc.', 'As an example, a method can include identifying one or more types of events by implementing a topology that includes a directed acyclic graph.', 'For example, the STORM application can include utilization of a topology that includes a directed acyclic graph (DAG).', 'A DAG can be a finite directed graph with no directed cycles that includes many vertices and edges, with each edge directed from one vertex to another, such that there is no way to start at any vertex v and follow a consistently-directed sequence of edges that eventually loops back to v again.', 'As an example, a DAG can be a directed graph that includes a topological ordering, a sequence of vertices such that individual edges are directed from earlier to later in the sequence.', 'As an example, a DAG may be used to model different kinds of information.', 'Another resource is RABBITMQ (Pivotal Software, San Francisco, Calif.), which is a message broker resource (e.g., message-oriented middleware) that implemented the Advanced Message Queuing Protocol (AMQP) and has been extended with a plug-in architecture to support Streaming Text Oriented Messaging Protocol (STOMP), MQTT, and other protocols.', 'Another resource is MONGODB (MongoDB Inc., New York, N.Y.), which is a cross-platform document-oriented database program.', 'Classified as a NoSQL database program, MONGODB uses the JAVASCRIPT Object Notation (JSON) format-like documents with schemas.', 'As an example, the JSON format may be utilized for one or more purposes in a system such as the system \n1100\n.', 'For example, consider specifying data, specifying interactions, etc., in a client-server type of architecture (e.g., frontend/backend, etc.) using the JSON format.\n \nFIG.', '12\n shows an example of a system \n1200\n that includes various blocks including a digital drill plan (DDP) block \n1205\n, a domain planner block \n1210\n, an operation orchestration block \n1220\n, a domain tactical planning block \n1230\n, an actions dispatcher block \n1240\n, an actions execution and monitoring block \n1250\n, an inference engine block \n1260\n, a drilling interpretation block \n1270\n, and a core services block \n1280\n.', 'As shown in \nFIG.', '12\n, various arrows indicate some examples of actions that can be performed utilizing the system \n1200\n.', 'In the example of \nFIG.', '12\n, the inference engine \n1260\n can provide feedback (FB) based at least in part on events as may be provided as output via the drilling interpretation block \n1270\n.', 'As shown, the drilling interpretation block \n1270\n can receive data and one or more models (e.g., as to one or more drilling operations, production, injection, materials modeling, fluids modeling, etc.).', 'As shown data may be provided via the core services block \n1280\n (see, e.g., core services \n1060\n and \n1160\n of \nFIGS.', '10 and 11\n).', 'The system \n1200\n can include features for dispatching activities, for example, via the operation orchestration block \n1220\n, which may dispatch activities in response to information (e.g., instructions, etc.)', 'in the digital drill plan block \n1205\n (e.g., consider executable commands, instructions, etc., as may be specified in a digital drill plan, which may be a digital well plan as explained with respect to \nFIG.', '6\n where various activities are illustrated in the GUI \n600\n).', 'The system \n1200\n can include features for execution of activities, which may be classified as tasks.', 'In such an example, the domain tactical planning block \n1230\n may act to receive activities and to output tasks based on the activities.', 'As an example, the actions dispatcher block \n1240\n can provide logic that requests replanning of tasks and/or activities, which may occur responsive to feedback (FB) as provided via the inference engine block \n1260\n.', 'For example, equipment at a rigsite may transmit (e.g., via pull and/or push) data to the core services block \n1280\n where the data are received via the drilling interpretation block \n1270\n, which may utilize one or more models to interpret at least a portion of the data based at least in part on one or more of the one or more models.', 'In such an example, one or more events may be output where such one or more events are received by the inference engine block \n1260\n, which can infer how such one or more events may impact activities and/or tasks.', 'As the actions dispatcher block \n1240\n is responsible for dispatching, the inference engine block \n1260\n can output feedback as information that may, for example, call for replanning (e.g., via the domain tactical planning block \n1230\n).', 'In such an example, real-time operations can be controlled with one or more feedback loops as tasks are executed and data are acquired and received at a rigsite by one or more pieces of equipment.', 'In the example of \nFIG.', '12\n, the inference engine block \n1260\n, which may include one or more features of the APACHE STORM resources, can be cast in a drilling operations context as informed by the drilling interpretation block \n1270\n.', 'For example, the drilling interpretation block \n1270\n can inform an inference engine such that inferences are made in the context of drilling operations.', 'While the foregoing example refers to output of the inference engine block \n1260\n to the actions dispatcher block \n1240\n, as shown in \nFIG.', '12\n, the inference engine block \n1260\n can provide feedback to one or more other blocks.', 'For example, the inference engine block \n1260\n can provide feedback to the operations orchestration block \n1220\n and/or the actions execution and monitoring block \n1250\n.', 'In such an example, an informed inference engine can be cast in the context of drilling operations such that inferences, which can be data-based and/or model-based inferences, can affect control of equipment at one or more levels of the system \n1200\n.', 'Such an approach provides for multi-level robustness such that data from equipment at one or more rigsites can inform drilling operations, optionally in real-time.\n \nFIG.', '13\n shows an example of an implementation of the system \n1200\n of \nFIG.', '12\n, with various examples of components and features.', 'The example of \nFIG.', '13\n shows the various blocks \n1210\n, \n1220\n, \n1230\n, \n1240\n, \n1250\n, \n1260\n, \n1270\n and \n1280\n with respect to the digital drill plan block \n1205\n.', 'The blocks can be components of a computational system.', 'As shown in \nFIG.', '13\n, the domain tactical planning block \n1230\n can include a local constraints pool.', 'In such an example, constraints may be provided by one or more entities where, for example, the constraints may pertain to one or more of policies, standards, procedures, and guidelines.', 'As an example, a component of a system may fuse information from different entities to generate constraints, which may be utilizes to output tasks, replan tasks, set limits, set work instructions, output checklists, etc.', 'As an example, the actions execution and monitoring block \n1250\n can output information that may be compared to one or more constraints.', 'As shown in the example of \nFIG.', '13\n, a comparison of constraints between those of tactical planning values, ranges, etc., and actual values, ranges, etc., may trigger a replan request and/or one or more other actions.', 'For example, consider a constraint on mud flow rate per a procedure of an entity where monitoring of mud flow rate indicates that mud flow rate exceeded the constraint (e.g., as an upper limit constraint) or fell below the constraint (e.g., as a lower limit constraint).', 'In such an example, the system \n1200\n may identify the source of the constraint and determine whether a replan or other action is warranted.', 'For example, a notification may be issued for an operator to review the numeric values in light of a procedure specified by an entity to determine whether the result of the comparison warrants action (e.g., replanning, etc.).', 'As an example, a hierarchical, tiered structure may be utilized to assess one or more procedures, activities, tasks, etc., which may be in view of a tiered structure of policies, standards, procedures and guidelines as may be specified by one or more entities.', 'Such a linking of field operations to entity information can provide for tracing backwards, forwards, etc., to determine if an entities goals are met in a well construction project, to identify whether data indicate that a goal may or may not be met, etc.\n \nFIG.', '14\n shows an example of a system \n1400\n that includes various layers of organization including equipment operations \n1402\n, well centric operations and rig equipment management \n1404\n, offsite operations management \n1406\n and cold data storage \n1408\n.', 'As shown, the system \n1400\n includes a collaboration framework \n1410\n with components \n1412\n, \n1414\n, \n1416\n and \n1418\n for messaging, CMS, BI, and reporting, respectively.', 'As shown, the system \n1400\n includes rig equipment \n1420\n including sensors \n1411\n and \n1412\n, a rig control system \n1413\n, a fluid control system \n1414\n, one or more other systems \n1415\n, data acquisition hardware \n1416\n coupled to sensors, an equipment control interface \n1417\n, and a field gateway \n1440\n that includes an equipment gateway \n1441\n, an asset centric processing component \n1442\n, a well centric processing component \n1443\n and a cloud gateway \n1444\n that can operatively couple the rig equipment \n1420\n to cloud resources.', 'As shown in \nFIG.', '14\n, the system \n1400\n includes cloud resources \n1450\n, including operation planning resources \n1451\n, an Internet-of-Things (loT) hub \n1452\n, asset centric processing \n1453\n, well centric processing \n1454\n and rig operations provisioning (e.g., for provisioning resources, etc.).', 'The system \n1400\n in \nFIG.', '14\n is shown as including or otherwise being operatively coupled to a data storage such as a cloud data lake \n1460\n, which can include a drilling data pond \n1462\n, an IT data lake \n1464\n, and an E&P data lake \n1466\n.', 'The system \n1400\n includes various development operations features as may be available via a development operations framework \n1480\n.', 'Such features can include deployment features \n1483\n, infrastructure monitoring features \n1484\n, and configuration management features \n1485\n.', 'FIG.', '15\n shows an example of a method \n1500\n that may implement a system such as, for example, the system \n1200\n of \nFIG.', '12\n, the system of \n1000\n of \nFIG.', '10\n and/or the system \n1100\n of \nFIG.', '11\n.', 'In \nFIG.', '15\n, the method \n1500\n is in the context of constructing a well, which may be specified, for example, in a digital drill plan or digital well plan (see, e.g., the digital drill plan block \n1205\n of \nFIG.', '12\n, the GUI \n600\n of \nFIG.', '6\n, etc.).', 'In the method \n1500\n, a context block \n1510\n provides the context of constructing a well while a parallel process or processes occur via a planning block \n1520\n, which can provide on-going planning (e.g., and/or replanning) during a well construction process per the context block \n1510\n.', 'As shown, the method \n1500\n includes a process block \n1530\n, a sub-process block \n1540\n, an activity block \n1550\n, a sub-activity block \n1560\n, and an activity workflow block \n1570\n.', 'Such blocks can be associated with various blocks of the system \n1200\n, which, as mentioned, can provide for real-time operations associated with a rigsite, which can include drilling operations.', 'The method \n1500\n may be performed, at least in part, in a hierarchal manner.', 'For example, the method \n1500\n may include tiers or levels where various planning processes may operate at corresponding tiers or levels, optionally in a cross-sectional manner such that a change at one tier or level can be propagated (e.g., affect) one or more aspects of another tier or level.', 'As an example, a system can include or be operatively coupled to a planning framework, which can include implementation of one or more planning domain definition languages (PDDLs).', 'An article by Fox, M., and Long, D. 2003.', 'PDDL2.1: An extension to PDDL for expressing temporal planning domains.', 'Journal of Artificial Intelligence Research 20 (2003) 61-124, is incorporated by reference herein.', 'As an example, the domain tactical planning block \n1230\n of the system \n1200\n of \nFIG.', '12\n can include or be operatively coupled to a planning framework that utilizes one or more PDDLs.', 'As illustrated in the example method \n1500\n of \nFIG.', '15\n, well construction can be planned to generate a plan that may be suitable for execution.', 'During execution, circumstances (e.g., events, conditions, etc.) may change such that there is a deviation from a generated plan.', 'As an example, a planning framework may be operable to generate a plan and to replan, whether during a planning phase and/or during an execution phase.', 'As illustrated in the example of \nFIG.', '15\n, well construction can include various activities that can be organized into levels or tiers.', 'As an example, a well construction project can be defined using one or more flow-charts of activities where at least some of the activities can be performed at least in part using equipment at a wellsite.', 'For example, consider a wellsite system (e.g., or rigsite system) such as the wellsite system \n200\n of \nFIG.', '2\n, wellsite system \n400\n of \nFIG.', '4\n, etc.; noting that an offshore wellsite system may be utilized.', 'As to equipment at a wellsite that may be controlled using instructions within a digital well plan generated by a planning process (e.g., optionally using a planning framework, etc.), consider the mud pump \n204\n, the drawworks \n207\n, the rotary table \n220\n, and the top drive \n240\n.', 'Such equipment may be operated, for example, to drill ahead in a borehole where drilling ahead is to construct a section of a planned well.', 'Such equipment may be operated according to a digital well plan that is formulated using constraints as may be from one or more sources (e.g., an entity, equipment, formation characteristics, etc.).', 'A top drive may be operated to achieve a certain amount of surface torque that translates into rotational speed of a bit at an end of a drillstring, a mud pump may be operated to achieve a desired removal rate of cuttings from drilling, and a drawworks may be operated to achieve a desired weight on the bit during drilling.', 'As an example, a digital well plan can include data structures that represent corresponding activities where such data structures can include or be associated with one or more processes that may be tailored for performance using particular equipment.', 'As to constraints, a constraint may flow from an entity (e.g., a field services provider, a regulator, etc.) to a digital well plan and an activity data structure therein and/or a constraint may flow from equipment to a digital well plan.', 'While the method \n1500\n of \nFIG.', '15\n is illustrated as including planning from the context block \n1510\n downwards to the activity workflow block \n1570\n, constraints that affect planning of the planning block \n1520\n.', 'As an example, one or more workflows can be modeled using Planning Domain Description Language (PDDL) as a temporal planning problem.', 'As an example, a planning engine of a planning framework can take a PDDL model as input, description of the current state of the processing, machines, human workers and compute a plan that suggests order of performing activities.', 'As an example, a plan can be a machine-readable file or files that is or are executed by a component such as a plan dispatcher or actions dispatcher (see, e.g., the actions dispatcher \n1240\n of the system \n1200\n of \nFIG.', '12\n).', 'Such a plan may be described with appropriate conditions that are to be monitored by a monitoring component (see, e.g., the actions execution and monitoring component \n1250\n of the system \n1200\n of \nFIG.', '12\n) to ensure constraints are respected, where constrains may include static constraints and dynamic constraints.', 'As an example, a dynamic constraint may arise responsive to monitoring, for example, where logging while drilling determines that a formation characteristic has changed in a manner that may not be adequately accounted for in a plan.', 'As illustrated in the system \n1200\n of \nFIG.', '12\n, a comparison block can be utilized to trigger a replan request, which may be triggered by a new constraint, data that indicates a deviation from an existing constraint, etc.', 'In such an example, the system \n1200\n may operate dynamically responsive to one or more changes in circumstances.\n \nFIG.', '16\n shows an example of a method \n1600\n and an example of a graphical user interface (GUI) \n1690\n.', 'As shown, the method \n1600\n includes prescriptive blocks \n1610\n and \n1630\n and a dynamic block \n1620\n.', 'Such blocks may be associated with various blocks of the method \n1500\n of \nFIG.', '15\n.', 'For example, the process block \n1510\n, the sub-process block \n1530\n and the activity block \n1540\n may be associated with the prescriptive block \n1610\n and the activity workflow block \n1570\n may be associated with the dynamic block \n1620\n, while operational tasks as part of an activity workflow may be associated with the prescriptive block \n1630\n.', 'As to the GUI \n1690\n, it includes the blocks \n1610\n, \n1620\n and \n1630\n as arranged with respect to swim lanes.', 'As shown, the dynamic block \n1620\n can include various maps with respect to time that correspond to dynamic sequences of tasks.', 'As an example, a map can include information that relates to a software instruction (SWI) such as a machine readable command, signal, etc., that can be issued to one or more pieces of equipment to perform one or more actions.', 'As mentioned, an action can be based on a constraint and/or can be constrained.', 'As an example, an action may be to perform a flow check at intervals of 24 hours and/or at intervals of 500 feet of drilled borehole.', 'In such an example, the two different constraints may be from two different sources, which are to be adhered to and/or reconciled.', 'As an example, instructions can be generated and utilized to control equipment, to issue a notice, etc., such that well construction complies with the foregoing constraints.', 'As an example, where 500 feet of drilled borehole occurs in less than 24 hours, drilling may be stopped and a flow check action performed and a timer reset for 24 hours to address the non-triggered constraint.', 'As an example, a replan request may be issued that can replan a digital well plan as to the 24 hour constraint such that it is positioned within a dynamic sequence of tasks with associated instructions generated for execution to perform the activity at the appropriate time, unless another 500 feet of drilled borehole occurs prior to 24 hours passing.', 'In such an example, one of the constraints has more uncertainty than the other one of the constraints.', 'As an example, a planning framework may be implemented to generate estimates of time or to utilize estimates of time to determine whether one constraint or the other is more likely to trigger the flow check action.', 'As mentioned, where sensor data indicates that a drilling rate (e.g., rate of penetration, ROP) is decreasing to an extent that 500 feet of drilled borehole is unlikely to occur in a 24 hour period, a dynamic sequence of tasks as in the GUI \n1690\n may be updated and appropriate instructions issued, staged, etc., such that the flow check occurs responsive to a 24 hour timer (e.g., or a lesser time that builds in a safety margin).', 'As an example, the GUI \n1690\n may render one or more notifications to a display that may indicate when a policy, a standard, a procedure, a guideline may be at risk of non-compliance (see, e.g., the GUI \n2700\n of \nFIG.', '27\n).', 'In such an example, a user may interrogate the reason for the risk of non-compliance.', 'For example, consider clicking on one of the graphics in the GUI \n1690\n to access and render information provided by an entity or entities that may have given rise to a constraint.', 'As an example, one constraint for an activity may remain in compliance while another falls out of compliance.', 'As an example, a reporting feature may mark such instances and circumstances that caused an out-of-compliance occurrence.', 'As an example, as mentioned with respect to the system \n1200\n of \nFIG.', '12\n, a condition related to one or more constraints may be sufficient to trigger a replan request, which may dynamically replan one or more aspects of a well construction plan, which may then be updated in a GUI such as the GUI \n1690\n of \nFIG.', '16\n.\n \nFIG.', '17\n shows an example of a method \n1700\n that is directed to a particular sub-process in the context of well construction, as illustrated in the example of \nFIG.', '15\n.', 'As shown, at a sub-process tier or level, the method \n1700\n can include a movement block \n1710\n for moving a rig (e.g., to a rigsite), a construction block \n1720\n for constructing a section X of a well at the rigsite utilizing the rig, and a construction block \n1730\n for constructing another section Y of the well at the rigsite utilizing the rig.', 'The blocks \n1710\n, \n1720\n and \n1730\n may be performed according to one or more constraints, which may pertain to one or more goals.', 'For example, consider a human safety goal and/or an equipment safety goal.', 'Such goals may be based at least in part on information received from one or more entities as, for example, one or more of policies, standards, procedures or guidelines.', 'As an example, to achieve a goal, a constraint may be to limit the ground speed of a portion of the rig equipment to being less than X kph while another goal may be a time-based goal where a minimum ground speed is to be at least Y kph where X is greater than Y. As explained with respect to the example of \nFIG.', '13\n, monitoring may occur where ground speed can be determined and compared to a constraint where a result of a comparison may be utilized for one or more purposes (e.g., notifications, replanning, etc.).', 'FIG.', '18\n shows an example of a method \n1800\n that is directed to a particular activity in the context of well construction, as illustrated in the example of \nFIG.', '15\n.', 'As shown, at an activity tier or level, the method \n1800\n can include a drill block \n1810\n for drilling a section of a well (e.g., section X, section Y, etc.), a case block \n1820\n for casing a section of a well that has been drilled, a cement block \n1830\n for cementing a section of a well (e.g., a cased section of a well), and a secure block \n1840\n for securing a section of a well.', 'As an example, the method \n1800\n may be implemented a plurality of times for a plurality of sections (e.g., section X, section Y, etc.).', 'As an example, the method \n1800\n may be performed using information received from one or more entities where such information may be translatable into one or more goals, one or more constraints, etc.', 'As mentioned, a method can include replanning.', 'For example, in response to data and/or modeling, one or more events may be directed to an inference engine, which can provide feedback to one or more portions of a system such as the system \n1200\n of \nFIG.', '12\n.', 'In such an example, one or more activities may be effected and result in one or more activities being changed and/or one or more tasks being changed (see, e.g., the domain tactical planning block \n1230\n, which may respond to a call from the actions dispatcher block \n1240\n to replan an activity and/or a task, which may affect one or more other activities and/or tasks, etc.).', 'As shown, a system may implement logic, which may be model-based logic, which can provide a logical model as to how a well is constructed, as illustrated in \nFIG.', '18\n at a particular level of granularity (e.g., a tier of specificity, etc.).', 'FIG.', '19\n shows an example of a method \n1900\n as associated with sub-activities in the context of well construction.', 'As shown, the method \n1900\n can include a drilling run block \n1910\n, a wireline run block \n1920\n and a clean out run block \n1930\n.', 'With respect to the method \n1500\n of \nFIG.', '15\n, note that sub-activities may be generated via the planning block \n1520\n, for example, one or more sub-activities may be dynamic in that operations are performed at a rigsite where data may be acquired during such activities, which may provide feedback, which can be utilized in a dynamic manner such that one or more aspects of the method \n1900\n may be updated in real-time.', 'As an example, the method \n1900\n may be performed using information received from one or more entities where such information may be translatable into one or more goals, one or more constraints, etc.\n \nFIG.', '20\n shows an example of a method \n2000\n as associated with an activity workflow in the context of well construction.', 'As shown, the method \n2000\n can include a make up BHA block \n2010\n for making up a bottom hole assembly (BHA) for drilling at least a portion of a well, a trip in to depth block \n2020\n for tripping the made up BHA to a depth, a drill to depth block \n2030\n for utilizing the BHA for drilling to a depth (e.g., as may be specified by a digital drill plan for a particular section of a well), a circulate to condition hole block \n2040\n for circulating material (e.g., fluid, etc.) to condition a bore hole, a conduct flow check block \n2050\n for conducting a flow check as to flow of fluid (e.g., liquid, gas, slurry, etc.)', 'in at least a portion of a bore hole, a trip out to depth block \n2060\n for tripping out at least a portion of the BHA to a depth (e.g., surface, sea bottom, etc.), and a lay down BHA block \n2070\n for laying down a BHA (e.g., or portion thereof).', 'As an example, the method \n2000\n may be performed using information received from one or more entities where such information may be translatable into one or more goals, one or more constraints, etc.', 'With respect to the example method \n1500\n of \nFIG.', '15\n, the activity workflow block \n1570\n is illustrated to be an end block of the method \n1500\n.', 'As an example, such a block may be performed where planning of the planning block \n1520\n may actively plan one or more operations for the well and/or for one or more other wells, whether under construction or completed.', 'For example, information acquired during the method \n1500\n may be utilized to plan and/or perform operations at one or more other sites, which may be rigsites, wellsites, etc.', 'For example, consider replanning an existing digital drill plan for another well and/or planning a stimulation treatment for another well, which may be a production well that has already produced some amount of fluid from a reservoir, etc.', 'Such a stimulation treatment may, for example, be based on knowledge acquired during a method such as the method \n1500\n, where such a treatment can increase production (e.g., total production) from the well to be treated.', 'FIG.', '21\n shows an example of a method \n2100\n as various operational tasks that may be associated with the make up BHA block \n2010\n of the method \n2000\n of \nFIG.', '20\n.', 'As shown, the operational tasks can be specified in a logical manner where various tasks are assigned to particular resources (e.g., individuals, machines, teams, etc.).', 'In the example of \nFIG.', '21\n, the resources include a logistics coordination resource, a toolpusher resource, a directional driller resource, a roust about resource, a driller resource and a measurement while drilling (MWD) resource.', 'As shown, various tasks can be depended on other tasks.', 'In the example of \nFIG.', '21\n, tasks are shown as including procurement of hardware, preparation of a rig to drill a section (e.g., section X), confirmation and strapping of BHA components (e.g., to make up the BHA), preparation of a bit, pre-run MWD checks and programming, movement of the BHA equipment to rig floor, various driller tasks are then listed for performance once particular other tasks have been completed.', 'As shown, where various pieces of equipment are available at the rig floor, tasks can include picking up a bit breaker, picking up a motor and bit, picking up a MWD tool, etc., which can be strung (assembled) as a BHA as part of a drillstring.', 'As an example, \nFIG.', '22\n shows how well construction may be cast in terms of one or more tiers or levels.', 'For example, a structural representation of well construction can include processes, sub-processes, activities/sub-activities, and activity workflows/sub-activity workflows.', 'Such a logical structure can be utilized in real-time in a prescriptive and/or dynamic manner.', 'Such a logical structure can be utilized and/or modified in a data-driven manner where data may be utilized directly and/or via one or more models.', 'In such an example, events may be output to an inference engine that can output feedback to inform one or more features of a system that act to determine how well construction is structured and how operations are executed.', 'In such an example, an overall dynamic approach can provide for enhanced operations at one or more sites for constructing one or more wells where, for example, one or more of such wells may be under construction.', 'As mentioned, output from a dynamic system may inform one or more operations as to one or more producing wells, for example, as to operational parameters, stimulation treatment, etc.\n \nFIG.', '22\n specifically shows an example of a method \n2200\n and an example of a graphical user interface (GUI) \n2201\n that can be an interactive interface that renders information as to the method \n2200\n and/or a system such as the system \n1000\n of \nFIG.', '10\n.', 'As shown in \nFIG.', '22\n, the method \n2200\n includes a context block \n2210\n that provides the context of constructing a well while a parallel process or processes occur via a planning block \n2220\n, which provides on-going planning (e.g., and/or replanning) during a well construction process per the context block \n2210\n.', 'As shown, the method \n2200\n includes a process block \n2230\n, a sub-process block \n2240\n, an activity block \n2250\n, a sub-activity block \n2260\n, and an activity workflow block \n2270\n.', 'Such blocks can be associated with various blocks of the system \n1200\n, which, as mentioned, can provide for real-time operations associated with a rigsite, which can include drilling operations.', 'In the example of \nFIG.', '22\n, there is a single process, 5 example sub-processes, 6 example activities, 17 example sub-activities and over 30 example items as to an activity workflow where various activities are for fluids.', 'As shown, a tiered or leveled approach can provide a hierarchy that is logical as well as prescriptive and dynamic.\n \nFIG.', '23\n shows an example of a graphical user interface \n2300\n that includes a multi-dimensional system, which may be referred to as an operational space or a field development space for visualizing various operations that may be part of a well plan.', 'For example, the GUI \n2300\n includes: a physical well structure dimension with location, surface section, intermediate section and production section labels that demarcate physical structures of a well that may be drilled into a geologic environment; a well plan engineering dimension that includes development activities such as, for example, one or more of rig selection, trajectory design, casing design, bit design, drilling fluids design, cementing design, and logging design, which may be organized along the well plan engineering dimension in an order that can correspond to an approximate order based on dependencies (e.g., a BHA design being dependent on a bit design, a trajectory design, etc.); an activity plan dimension that can correspond to a linear progression in time as to field development operations; and one or more scenario dimensions that can highlight one or more regions within the foregoing three dimensions where one or more development operations can benefit from one or more adjustments.', 'As an example, a scenario dimension may be a risk dimension that highlights a risk in a multidimensional space.', 'As shown in \nFIG.', '23\n, a risk dimension indicates that a risk of a tool failure exists if pumping of a particular fluid occurs at a rate of 3,000 gallons per minute (GPM).', 'The risk dimension is shown as a cloud or multidimensional indicator (e.g., circle, polygon, polyhedron, sphere, ellipsoid, etc.) about a region where such a risk exists.', 'Within the highlighted region, a BHA specification exists along with a fluid as represented by markers.', 'The markers are indicated as being at a particular position along the physical well structure dimension, the well plan engineering dimension and activity plan dimension.', 'As indicated, the highlighted risk exists along a drilling activity within the surface section of the physical well structure.\n \nFIG.', '23\n also shows a graphical representation of a portion of a geological environment into which the physical well is being drilled or to be drilled.', 'The graphical representation can be a graphical user interface and/or part of the GUI \n2200\n.', 'The graphical representation, as a GUI, can include control graphics that can be selected (e.g., actuated), which may, for example, cause rendering of one or more other GUIs to a display.', 'For example, along a right side column, icons are shown that can correspond to framework tools that can be instantiated and utilized.', 'Such tools may be highlighted to correspond to one or more features highlighted in the multidimensional system.', 'For example, where a risk exists with respect to a BHA, a BHA control graphic may be highlighted that upon actuation switches a user to a BHA GUI that can adjust one or more parameters associated with a BHA (see, e.g., the drillstring \n560\n of the GUI \n500\n of \nFIG.', '5\n).', 'In \nFIG.', '23\n, the GUI \n2300\n shows in a plane, defined by the physical well structure dimension and the activity plan dimension, a series of lines that represent operations with respect to depth or length along a well trajectory.', 'In a glance, a user or users may understand how a well is to be drilled as part of a plan to develop a field.', 'During drilling, a marker may be rendered in the plane based on information received from the field to show where a bit may be during drilling, etc.\n \nFIG.', '24\n shows an example of a graphical user interface \n2400\n that includes the well plan engineering dimension along with some examples such as rig selection, trajectory design, casing design, bit design, drilling fluids design, cementing design, and logging design.', 'Such designs can be present for one or more positions along the physical well structure dimension.', 'As an example, “bit design” may be present along the subsurface sections of the physical well structure dimension and may change depending on section (e.g., where tripping out and tripping in may be performed as part of a bit change according to a bit design).', 'FIG.', '25\n shows an example of a graphical user interface \n2500\n that includes the activity plan dimension along with some examples of markers for location and sections: construct location, construct 12% inch section, construct 8½ inch section, and construct 6% inch section.', 'Such sections can correspond to sections of the physical well structure; noting that the activity plan dimension can be a time dimension, which may be linear, non-linear, continuous, non-continuous, continuous and non-continuous, etc.\n \nFIG.', '26\n shows an example of a graphical user interface \n2600\n as including graphical controls associated with digital documents (e.g., digital files).', 'For example, an operations procedure document (OP), a checklist document, a work instructions document (WI), or other document may be linked with one or more points within the multidimensional system.', 'The example of \nFIG.', '26\n includes two highlighted scenarios that can correspond to risk or level of risk for one or more activities along the activity plan dimension.', 'As an example, a highlighted region can correspond to a single point in the physical well structure dimension and the plan activity dimension plane or a highlighted region can correspond to multiple points in the physical well structure dimension and the plan activity dimension plane.', 'As an example, a user may navigate a cursor to a highlighted region (e.g., or touch a highlighted region on a touchscreen) to activate a menu that can list menu options that are associated with conditions, specifications, etc., that underlie a reason as to why the region was highlighted (e.g., increased level of risk, conflicting parameters in design, etc.).', 'FIG.', '26\n also shows an example graphic of a bore drilling issue that can be due to bore geometry (e.g., well trajectory geometry) and another graphic of a bore drilling issue that can be due to an accumulation of debris (“junk”) in the bore, which may interfere with drilling operations.', 'As indicated in \nFIG.', '26\n, the notification as to the issue is associated with a position in the multi-dimensional space defined by dimensions for physical well structure, well plan engineering and activity plan.', 'The issue is shown as being associated with a particular BHA and a fluid.', 'As an example, a method can include rendering an issue in a multi-dimensional environment where the rendering can occur prior to performing one or more activities along the activity plan dimension.\n \nFIG.', '27\n shows an example of a graphical user interface \n2700\n that illustrates a workflow that can fuse various types of policies, standards, procedures, and guidelines.', 'For example, various entities can specify logic that can include technical logic for performing one or more field operations.', 'Such logic can be particular to an entity, for example, based on expertise, risk, etc., of the entity and what that entity may be providing as a service, as a product, etc.', 'For example, a particular downhole tool may be supplied by an entity to perform a field operation where the entity has expertise as to how the downhole tool is to be utilized, under what conditions it is to be utilized, etc.', 'As illustrated in the GUI \n2700\n, a workflow can fuse logic from a plurality of different entities such that a tiered output can be generated, which is shown as including a plurality of levels: L2 to L7.', 'Further, the GUI \n2700\n provides guidance as to levels and sequences of activities that describe well construction and tasks and operational steps, which can include work instructions, checklists, etc.', 'The tiered output can be utilized to construct a well and may include executable commands, instructions, etc., that may be consumed by one or more pieces of equipment, which may, in response to receipt thereof, perform one or more actions, be configured for performance of one or more actions, etc.', 'For example, consider a programmable downhole tool being programmed per a work instruction associated with the level L6 Tasks.', 'As an example, a programmable downhole tool may be programmed to acquire sensor data at an instructed resolution, frequency, acquisition algorithm, etc.', 'The approach of \nFIG.', '27\n can allow for rendering a work breakdown structure (WBS) that provides an ability to trace goals and constraints associated with well construction from a high level (e.g., strategic level) down to a lower level (e.g., tactical level).', 'For example, components of the GUI \n2700\n can allow for tying back the “why” something is being done to a source reference (e.g., one of the entities).', 'While the GUI \n2700\n shows various arrows from left to right, an approach may operate from right to left.', 'For example, consider selection of the work instructions, rendering of a drop-down list of itemized work instructions, selection of one of the itemized work instructions of the list, and highlighting at least one of the entities as being a source of the selected one of the itemized work instructions of the list.', 'In such an example, the client operator entity may be highlighted where a procedure layer is specifically highlighted, which may be selected to render information from that procedure layer that gave rise to the selected one of the itemized work instructions of the list.', 'If a user perceives a conflict, a lack of clarity, etc., the user may query the client operator as to the particular procedure.', 'As an example, where the procedure is then revised (e.g., updated), the fusion process may be performed to regenerate one or more of the levels, for example, to revise one or more of the tasks of L6 such that revised work instructions are output.', 'The example workflow of the GUI \n2700\n of \nFIG.', '27\n may be utilized at one or more times such as during one or more phases.', 'For example, consider a phase that involves selection of a third party where various third party entities are plugged in to see results of fusion.', 'Such results may be analyzed to determine an optimal third party (e.g., an equipment supplier, a service provider, etc.).', 'As another example, consider a construction phase where a revision to a plan may be desirable such as a revision to a policy and where the fusion process can be performed to update the tiered levels that provide the sequence of activities.', 'Yet another example can be a forensic analysis where the workflow is utilized to determine whether actual activities performed during construction followed one or more policies, standards, procedures, guidelines, etc., of one or more entities.', 'In such an example, a database of tiered actual data may be compared to the tiered output and where a discrepancy exists, the workflow of the GUI \n2700\n may proceed from right to left to highlight entity information that can be examined to determine whether or not a variance in tiered actual data complied or did not comply with one or more policies, standards, procedures, guidelines, etc.', 'For example, during actual operations to construct a well, an operator may be aware of the scope of a procedure such that some variance is possible, which may not be present in the logic used for fusion.', 'In such an example, the logic may optionally be revised to account for such a variance.', 'As an example, a workflow such as the workflow of the GUI \n2700\n of \nFIG.', '27\n may be utilized to confirm that a well was constructed per the specifications provided by one or more entities.', 'As an example, a computational framework can include an interface that receives data that specifies logic for policies, standards, procedures, guidelines, etc., and a component that fuses logic to generate output.', 'Such a computational framework can include an interface that receives data that are associated with actual field operations and that compares that data to generated output where, in response to one or more comparisons, a component identifies one or more policies, standards, procedures, guidelines, etc., which may be associated with one or more entities.', 'As an example, a computational framework can provide a logical, traceable structure for one or more purposes of planning, assessing, revising, etc., operations associated with construction of a well or wells.', 'As an example, a workflow can include logic associated at the well level and then cascaded down within a system.', 'For example, consider the following tiered logical approaches: \n \n \n \nA.', 'Well cost \n \n1.', 'Section cost \n \na. Run cost/foot, etc.', 'A.', 'No well control events during well construction \n \n1.', 'Maintain two barriers \n \na.', 'Maintain a kick tolerance of X bbls in this section\n \nb.', 'Obtain a Leak off Test of XX.XX ppg in this hole section \n \ni. Flow check each 500 ft interval\n \n \n \n \n \n \n \n \n \n \n \nThe foregoing examples may be expressed using a checklist or checklists.', 'For example, a graphical user interface can translate such tiered logic into checklist graphical controls where “checks” are entered automatically, manually, etc.', 'For example, consider equipment that transmits a signal after performing an operation such as a data acquisition operation for a flow check, which can include depth information (e.g., measured depth).', 'In such an example, where flow checking is performed at each 500 feet, a signal may be transmitted to a computational framework that “checks off” an item or items on a checklist as rendered to a graphical user interface.', 'In such an approach, a user may visualize one or more processes as it or they are performed.', 'Where the user receives an indication that a process has been performed, the user may, as appropriate, manually enter a check (e.g., a “check off”).', 'If a check is missing or delayed, the computational framework may issue a notification, which may cause a user to assess operations to determine why a particular item on the checklist has not been “checked off”.', 'FIGS.', '28, 29, 30 and 31\n show examples of graphical user interfaces \n2800\n, \n2900\n, \n3000\n, and \n3100\n that include information as to logic of policies, standards, goals and constraints.', 'One or more of the GUIs \n2800\n, \n2900\n, \n3000\n and \n3100\n may be part of a workflow or workflows of a computational framework such as one associated with the GUI \n2700\n of \nFIG.', '27\n.', 'For example, the policy and/or standard information may represent types of information that can be received by an interface of a computational framework, which may generate logic based thereon to fuse such information into output for construction of a well.', 'As shown in the GUI \n2800\n of \nFIG.', '28\n, the information can provide for numeric data that can be compared to actual data for constructing a well.', 'In such an example, comparisons may be made, which may be utilized for performing “check offs” on a checklist, determining whether one or more policies, etc., have been followed, etc., issuing one or more notifications, etc.', 'The GUI \n2800\n shows some examples of goals to be achieved such as “no loss of well control” and “maintain structural integrity of well”.', 'As shown, various types of data can be indicative of such goals where such data can be sensor data and/or determined using sensor data.', 'In the example GUI \n2900\n of \nFIG.', '29\n, a goal is to have no HSE events such that a policy is met that minimizes risk to humans operating technology/equipment provided for a well construction process.', 'As to the examples of constraints, one or more of these may be expressed in a logical manner, optionally via a checklist where the checklist may be part of a larger logical structure (e.g., a larger checklist) where various operations are not to proceed until various items are “checked off”.', 'Where information, actions, etc., occur prior to a particular constraint being met, a computational framework may issue a notification and may optionally lock out a system in a manner that is to be cleared or overridden to proceed.', 'Such an approach may provide for additional assurances as to the goal to be achieved (e.g., minimize risk to humans, etc.).', 'In the example GUI \n3000\n of \nFIG.', '30\n, various goals are presented as associated with a policy and/or a standard to identify the most cost effective method to extract hydrocarbons from a reservoir with consideration for the life cycle of a well.', 'As shown, one of the goals is to place the well at the desired position within the reservoir.', 'Such a goal can be a location phase as may be associated with planning and generating a well trajectory.', 'Meeting that goal may generate information for a multi-dimensional plot as shown in the GUI \n2600\n of \nFIG.', '26\n (see, e.g., location and sections).', 'In the example GUI \n3100\n of \nFIG.', '31\n, various goals are presented as associated with one or more policies to conform to country, state and/or government regulations, which pertain to actions that would contradict regulations and providing information as demanded by regulatory authorities in a timely manner.', 'As shown under constraints, numeric data may be acquired and provided where a comparison may be made during one or more phases to determine whether operations conform to one or more of the one or more policies.', 'As an example, one or more of the constraints may be translated into one or more automated controls.', 'For example, consider a controller that is programmed using a constraint to acquire test data as to well control equipment at intervals of XX days (or less).', 'In such an example, conformance with the policy can be achieved using at least some degree of automation.', 'As shown in the example GUI \n3100\n, relief well information may be germane to policy compliance, which may include generating tiered levels for construction of a relief well.', 'As an example, a multi-dimensional space can include activities of an activity plan for constructing a relief well that is triggered based on operations performed for construction of a main well, which may be a policy-based trigger.', 'For example, consider conditions associated with construction of the main well that indicate, according to a policy, that a relief well is to be built.', 'Such conditions, as indicated by actual field data acquired during construction of the main well, may trigger revision of a plan to include activities to build the relief well, which may have its own associated policies, standards, procedures, guidelines, etc.', 'In such an example, a workflow as in the GUI \n2700\n may be executed that performs fusion for generation of tiers that express at least a sequence of activities that describe construction of a relief well.\n \nFIG.', '32\n shows an example of a graphical user interface \n3200\n that includes various types of information for construction of a well where times are rendered for corresponding actions.', 'In the example of \nFIG.', '32\n, the information may be part of a work breakdown structure (WBS); noting that the information of the GUI \n1690\n of \nFIG.', '16\n may be part of a WBS.', 'In the example of \nFIG.', '32\n, the times are shown as a clean time (CT) in hours, an estimated time (ET) in hours and a total or cumulative time (TT), which is in days.', 'The clean time may be for performing an action or actions without occurrence of non-productive time (NPT) while the estimated time can include NPT, which may be determined using one or more databases, probabilistic analysis, etc.', 'In the example of \nFIG.', '32\n, the total time (or cumulative time) may be a sum of the estimated time column.', 'As an example, during execution and/or replanning the GUI \n3200\n may be rendered and revised accordingly to reflect changes.', 'As an example, the GUI \n3200\n may be rendered to a display with a GUI such as the GUI \n1690\n of \nFIG.', '16\n or, for example, one of the GUIs may be accessible via another one of the GUIs.', 'As shown in the example of \nFIG.', '32\n, the GUI \n3200\n can include selectable elements and/or highlightable elements.', 'As an example, an element may be highlighted responsive to a signal that indicates that an activity is currently being performed, is staged, is to be revised, etc.', 'For example, a color coding scheme may be utilized to convey information to a user via the GUI \n3200\n.', 'FIG.', '33\n shows an example of a method \n3300\n for controlling field equipment where the method \n3300\n includes a reception block \n3310\n for receiving information via an interface of a control system; an analysis block \n3320\n for analyzing the information by the control system with respect to tiered well construction activities; a generation block \n3330\n for, based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and a transmission block \n3340\n for transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'As mentioned, a method can include utilizing constraints for generating a workflow that includes at least a series of tiered well construction activities.', 'As an example, a method can be dynamic and generate a workflow responsive to a change in circumstances, for example, a change with respect to circumstances considered during planning.', 'As an example, a method may generate a revised workflow.', 'The method \n3300\n of \nFIG.', '33\n is shown as including various computer-readable storage medium (CRM) blocks \n3311\n, \n3321\n, \n3331\n, and \n3341\n that can include processor-executable instructions that can instruct a computing system, which can be a control system, to perform one or more of the actions described with respect to the method \n3300\n.', 'As an example, a system such as the system \n790\n of \nFIG.', '7\n may be utilized to implement one or more portions of the method \n3300\n.', 'As an example, the instructions \n796\n may include instructions executable by at least one of the one or more processors \n793\n (see, e.g., the blocks \n3311\n, \n3321\n, \n3331\n and \n3341\n).', 'As an example, a method can generate a work breakdown structure (WBS), which may represent a workflow.', 'Such an approach can allow for linking data, instructions, information, etc., to the WBS, which can facilitate control, rendering, reporting, revisions, etc.', 'As an example, a WBS can provide for linking to operations to perform under certain conditions in the well.', 'For example, a WBS can be “live” and provide for real-time reporting, particularly as to constraints, which may be associated with reporting demands, compliance, etc.', 'As an example, a WBS can provide for assessing what had been planned in comparison to actual execution, which may be utilized to plan a subsequent well and/or revise construction of a well that is under construction.', 'As an example, a PDDL approach may utilized planned versus actual information to improve planning over time.', 'As an example, a WBS can be used to describe a plan where it can be dynamically updated during execution such that an original plan and one or more revised plans result.', 'In such an example, the revised plans can be part of a “live” plan at various points in time that has evolved dynamically during life of well construction.', 'Such a live plan can be associated with various types of actual data as to conditions, etc., that occurred during well construction.', 'As an example, a live plan can be associated with data concerning equipment, servicing of equipment, weather, people, etc.', 'With a dynamic planning approach, deltas may be discerned with respect to time during well construction, which can allow for a comparison of cumulative deltas to understand better how one delta may have given rise to another delta or, for example, where deltas are independent.', 'As mentioned, a data structure can be linked to instructions such as software instruction (SWIs) that may be for issuing notifications, rendering information, controlling a piece of equipment associated with movement of downhole equipment, etc.', 'As mentioned, a controller or controllers may provide for control of a rotary table, a top drive, a drilling fluid pump, a drawworks, etc., can be controlled, for example, to drill a borehole (e.g., deepen a borehole).', 'As an example, a WBS can be linked to resources that may be for performing one or more activities.', 'For example, consider a WBS that includes digital commands that can be issued to provision one or more resources.', 'As an example, a resource may be a material resource, an equipment resource, a human resource, a computational resource (e.g., cloud-based resource, etc.), etc.', 'As an example, a WBS may be part of a system that includes one or more interfaces that can receive information pertaining to resources.', 'For example, where provisioning is for a downhole tool for performing an activity and the downhole tool is not available at a particular time according to a plan specified by the WBS, the system may issue a notification and/or issue a signal that aims to provision the resource from a different source or to provision a fungible resource, which may result in a change to one or more constraints, introduction of a new constraint, etc.', 'As an example, a WBS can provide for relational linking of one or more types of information, which may be instructions that are executable by a machine.', 'As an example, a relational link may be to an object as in object-oriented programming.', 'As an example, a hierarchical architecture may be provided for attaching information to a WBS, which may occur via manual interaction and/or automatically.', 'For example, consider a WBS that specifies a particular activity where that activity is used to search a database of work instructions, which may be machine executable, to link such work instructions to the WBS.', 'In such an example, an assessment may occur to determine whether one or more constraints are to be revised, one or more new constraints added, etc.', 'For example, consider a manufacturers update to instructions for operation of a tool where the instructions can be assessed to formulate a constraint that may cause some amount of replanning and revision to the WBS.', 'As an example, a WBS can be extensible in that one or more types of information may be linked (e.g., associated, attached, etc.), which may cause one or more dynamic actions such as revision to the WBS.', 'As an example, where drilling is performed in part via textual instructions for humans, such information may be linked to a WBS.', 'In such an example, a human may review the WBS (e.g., via one or more GUls, etc.) to gain insight into the text, how the text was interpreted, what actions were taken by a human or humans, etc.', 'As an example, a method can include analyzing text and/or human notes to plan, replan, etc.', 'For example, consider a PDDL type of approach that can utilize such text, human notes, etc.', 'As an example, where a service provider entity is performing an activity and an instruction is received from a customer that may be a change order or other update, a WBS may be utilized for assessing the change or update and, if appropriate, replanning, with estimates of individual times, resources, outcomes, total time, etc.', 'As an example, a change or update may be assessed in a manner described with respect to the GUI \n2700\n of \nFIG.', '27\n where a check can be performed to determine whether or not compliance may be an issue with respect to one or more entities.', 'As an example, a WBS can provide for a section-by-section comparison of different sections of a well.', 'For example, consider a comparison of a number of bit runs, a number of tasks to construct a section, etc.\n \nAs mentioned, a WBS can depend on constraints, which can include one or more of time based, process based (e.g., do it in this order, etc.), formation based (e.g., per an earth model, etc.), equipment based (e.g., operating specifications, etc.), etc.', 'As an example, constraints can be attached to a WBS and can be used to define a WBS.', 'As mentioned, a WBS can be dynamic in that it can be revised in response to one or more changes in constraints.', 'As mentioned, a fusion process can be a logical process that aims to fuse information that explicitly and/or implicitly provides constraints.', 'As an example, at a borehole level, a WBS may be analyzed for a borehole section level such as number of days to construct and in how many bit runs.', 'Such a WBS may then be analyzed for a bit run level, for example, to assess amount of time per bit run.', 'As an example, a WBS can allow for breaking down goals and constraints and where they can be logically attached to various events taking place.', 'As an example, a WBS can provide for “what if” scenario analyses.', 'For example, consider an analysis as to a change in procedure (e.g., as may be associated with a client or other entity).', 'As an example, a WBS may be extensible in that a variety of types of information may be logically linked to the WBS where such information may optionally be assessed to determine whether the WBS is to be revised.', 'Such an approach can allow detail to be controlled on a case-by-case basis.', 'For example, a basic WBS may be utilized free from attachments or a WBS may be heavily attached to various types and amounts of information.', 'As mentioned, in some instances, attached information may be of a type that can be recognized by a planning framework where such information may be assessed to determine whether or not it has an impact on planning (e.g., generation of a WBS, etc.).', 'As explained with respect to the GUI \n2700\n of \nFIG.', '27\n, a system may provide for forensics, for example, to trace back to determine what happened when to facilitate a determination as to why.', 'As an example, a WBS can be a structure that is storable and assessable by a computational framework.', 'For example, consider assessing whether one or more standard operating procedures (SOPs) were followed and, if not, when an actual operating procedure deviated from an SOP.', 'In such an example, a constraint or constraints may be identified as being a reason for lack of compliance, for example, consider conflicting constraints, constraints that differ (e.g., time versus depth, etc.), etc.', 'As an example, for a reservoir section of a wellbore, an assessment may pertain to when the hydrocarbons are exposed, which may be a reportable event and an event that causes an overall assessment as to resources, timing, etc., to get to that event.', 'In such an example, a WBS may be utilized to perform such an assessment, optionally with reporting of compliance.', 'As an example, a system can include generating a primary plan WBS, a preemptive plan WBS, and a contingency plan WBS, which may be based on primary risks.', 'In such an approach, a system may be switch to one or more of the plans depending on circumstances.', 'As an example, during execution of a primary plan WBS, one or more other types of plans may be revised (e.g., preemptive, contingency, etc.).', 'As an example, a system can provide for management of a set of constraints and dynamically change a series of well construction activities to honor the constraints, which may occur in a planning phase of the well and/or in an execution phase of a plan.', 'As an example, a sequence of activities may be automatically and/or dynamically generated.', 'For example, consider an approach that provides information regarding a desired trajectory in a subsurface region where the information is accessed and utilized to automatically generate a digital well plan (e.g., a WBS, etc.).', 'As an example, depending on circumstances, a revised digital well plan may be dynamically generated.', 'As an example, a digital well plan can be utilized for controlling equipment or advising a human (e.g., via a GUI, etc.).', 'As an example, a method can include attaching a prescribed process to a level of an activity structure that influences the equipment control.', 'For example, consider a prescribed process from a tool manufacturer that can be attached to a WBS where the prescribed process may include executable instructions that are executable by a processor of the tool to perform one or more actions.', 'As an example, a method can include attaching constraints to a level of an activity structure.', 'For example, consider a GUI such as the GUI \n1690\n of \nFIG.', '16\n or the GUI \n3200\n of \nFIG.', '32\n where a user may click on an activity and attach a constraint.', 'For example, consider a right-click that causes rendering of a menu with options to add one or more types of constraints.', 'In such an example, a replan trigger may be issued where the type of constraint is of a type that can affect planning (e.g., or execution of a plan).', 'As an example, a WBS can be a type of data structure that is defined to accommodate planning and field operations.', 'As an example, such a structure may be generated by a system starting with plan goals or starting with field operations.', 'For example, such a structure may be relatively consistent looking forward or looking backward.', 'As mentioned with respect to the GUI \n2700\n of \nFIG.', '27\n, a system can provide for tracing backwards and/or forwards, for example, to associate activities with policies, standards, procedures, guidelines and/or one or more other sources of information, which may optionally be fused to logically generate a data structure that represents a series of tiered well construction activities.', 'As an example, a structure may be statically generated or dynamically generated in a planning platform based on a combination of defined constraints and well design choices.', 'As an example, information to dynamically generate a WBS may be packaged into a machine readable digital format that can be loaded into a wellsite operating system (see, e.g., the system \n470\n of \nFIG.', '4\n).', 'As an example, tiered well construction activities may include activities that are tiered via static analysis and may include activities that are tiered via dynamic analysis.', 'As an example, an activity may be specified to be fixed in one or more manners, for example, with respect to constraints such that the activity is not dynamically altered; whereas, another activity may be specified to be dynamic in one or more manners, for example, with respect to constraints such that the activity can be dynamically altered.', 'For example, consider a safety meeting as being an activity that is fixed; whereas, a directional drilling activity that aims to reach a target can be an activity that includes some amount of dependency on circumstances such that it can be dynamically altered in one or more manners (e.g., rate of penetration, dogleg, length, etc., as long as the target is reasonable reached).', 'As an example, a method for controlling field equipment can include receiving information via an interface of a control system; analyzing the information by the control system with respect to tiered well construction activities; based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'In such an example, the at least one of the series of tiered well construction activities can include a drilling operation.', 'As an example, a method can include analyzing that considered one or more constraints, which may be from one or more sources.', 'As an example, a method can include generating a workflow that includes at least a series of tiered well construction activities that generates the workflow according to constraints.', 'In such an example, the constraints can include at least one time-based constraint, at least one depth-based constraint, at least one equipment operation-based constraint and at least one formation-based constraint.', 'As an example, a constraint can be a fused constraint that is logically derived from at least two constraints.', 'As an example, a method can include, responsive to receiving information via an interface of a control system, formulating at least one constraint and, for example, generating a workflow that includes at least a series of tiered well construction activities according to the at least one constraint.', 'For example, a constraint can be for an activity that is to be interspersed between other activities.', 'As mentioned, a flow check constraint can be a constraint that demands stopping drilling, which can thereby affect a series of tiered well construction activities.', 'As mentioned, such a constraint may be one or more of time-based, depth-based, etc.', 'As an example, a constraint may be a logical formulation that operates dynamically responsive to circumstances.', 'As mentioned, a constraint may arise in a dynamic manner depending on circumstances.', 'As mentioned, constraints may be fused such that multiple constraints can be formulated as a single constraint.', 'For example, consider a flow check constraint that includes time and depth criteria that is formulated by a time-based constraint and a depth-based constraint.', 'As an example, a fusion process may fuse constraints in a logical manner that can be utilized for purposes of control of one or more pieces of equipment, rendering of information to a display, etc., for example, to promote compliance with a policy, policies, a standard, standards, a procedure, procedures, a guideline, guidelines, etc.', 'As an example, a method can include, via a control system, provisioning field equipment.', 'For example, such a method can include provisioning a plurality of pieces of the field equipment.', 'In such an example, one or more protocols may be implemented to generate relationships between resources and equipment.', 'Such relationships can include interfaces, data stores, entries in databases, security protocols (e.g., encryption, keys, etc.), etc.', 'As an example, a piece of equipment may be associated with one or more resources in a cloud environment as part of a provisioning process.', 'As an example, one or more instances of an object or objects may be instantiated in a cloud environment and/or a local environment as part of a provisioning process.', 'As an example, a method can include transmitting a control signal where such transmitting includes implementing an Advanced Message Queuing Protocol (AMQP).', 'As an example, a method can include receiving information where such information can be associated with an application programming interface (API) call and/or an API response.', 'As an example, in a client-cloud or client-server architecture, a client machine can include local resources that can generate an API call to cloud resources or server resources.', 'In such an example, the cloud resources or server resources can respond to the API call, optionally by processing information that may accompany the API call.', 'As an example, such a call may include information germane to performance of one or more actions in a field (e.g., drilling a trajectory for a well, etc.).', 'In such an example, the cloud resources or server resources can be part of a control system that can issue a control signal to one or more pieces of equipment to perform an action in a field.', 'In such an example, a piece of equipment may be provisioned such that the control system has an established relationship with the piece of equipment for purposes of one or more of data acquisition, control, etc.', 'As an example, a method can include utilizing a control system that can control one or more pieces of equipment according to tiered well construction activities, which may include a process level, a sub-process level and an activity level.', 'In such an example, the process level can include a well section construction process, the sub-process level can include a drill section sub-process and a case section sub-process and the activity level can include a drilling run activity and a run casing activity.', 'As an example, a control system can include a domain bounded assessor that includes trajectory information for a well where, for example, at least one of a series of tiered well construction activities constructs the well according to the trajectory information.', 'In such an example, the control system can include receiving information that adjusts a trajectory specified by the trajectory information.', 'In such an example, the information may be received by the control system via an API call.', 'For example, a client machine can generate an API call that is transmitted via a network to the control system where the control system processes the API call for information, which may be utilized to effectuate control of a field action (e.g., directional drilling, etc.).', 'As an example, field equipment can include at least one sensor.', 'In such an example, a control system can receive information that includes data acquired by at least one of the at least one sensor.', 'For example, a control system can be implemented with one or more control loops that include one or more sensors.', 'As an example, a control system may operate in part via information received via a client (e.g., an individual using a client machine) and in part via information received via a sensor (e.g., a piece of field equipment).', 'As an example, a series of tiered well construction activities can be associated with corresponding pieces of field equipment.', 'As an example, a series of tiered well construction activities can be associated with corresponding pieces of field equipment and corresponding resources at a rigsite.', 'In such an example, a resource may be a human resource.', 'As an example, a piece of field equipment may be a dedicated piece of field equipment that is to remain at a rigsite (e.g., or in a well, etc.) or may be a mobile piece of equipment that is amenable to use at a plurality of rigsites.', 'As an example, a workflow can include at least two well construction activities at a common tier.', 'As an example, a workflow can include at least two well construction activities that are parallel activities.', 'As an example, at least one of a series of well construction activities can include a movement activity for moving at least one piece of field equipment to a different site.', 'For example, consider moving drilling equipment (e.g., a BHA, a rig, a portion of a rig, mud-pump equipment, etc.).', 'As an example, a system can include a processor; memory accessible by the processor; processor-executable instructions stored in the memory and executable to instruct the system to: receive information via an interface of a control system; perform an analysis of the information by the control system with respect to tiered well construction activities; based on the analysis, generate a workflow that includes at least a series of tiered well construction activities; and transmit a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'As an example, one or more computer-readable storage media can include processor-executable instructions to instruct a computing system to: receive information via an interface of a control system; perform an analysis of the information by the control system with respect to tiered well construction activities; based on the analysis, generate a workflow that includes at least a series of tiered well construction activities; and transmit a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'As an example, a method may be implemented in part using computer-readable media (CRM), for example, as a module, a block, etc. that include information such as instructions suitable for execution by one or more processors (or processor cores) to instruct a computing device or system to perform one or more actions.', 'As an example, a single medium may be configured with instructions to allow for, at least in part, performance of various actions of a method.', 'As an example, a computer-readable medium (CRM) may be a computer-readable storage medium (e.g., a non-transitory medium) that is not a carrier wave.', 'According to an embodiment, one or more computer-readable media may include computer-executable instructions to instruct a computing system to output information for controlling a process.', 'For example, such instructions may provide for output to sensing process, an injection process, drilling process, an extraction process, an extrusion process, a pumping process, a heating process, etc.', 'In some embodiments, a method or methods may be executed by a computing system.', 'FIG.', '34\n shows an example of a system \n3400\n that can include one or more computing systems \n3401\n-\n1\n, \n3401\n-\n2\n, \n3401\n-\n3\n and \n3401\n-\n4\n, which may be operatively coupled via one or more networks \n3409\n, which may include wired and/or wireless networks.', 'As an example, a system can include an individual computer system or an arrangement of distributed computer systems.', 'In the example of \nFIG.', '34\n, the computer system \n3401\n-\n1\n can include one or more modules \n3402\n, which may be or include processor-executable instructions, for example, executable to perform various tasks (e.g., receiving information, requesting information, processing information, simulation, outputting information, etc.).', 'As an example, a module may be executed independently, or in coordination with, one or more processors \n3404\n, which is (or are) operatively coupled to one or more storage media \n3406\n (e.g., via wire, wirelessly, etc.).', 'As an example, one or more of the one or more processors \n3404\n can be operatively coupled to at least one of one or more network interface \n3407\n.', 'In such an example, the computer system \n3401\n-\n1\n can transmit and/or receive information, for example, via the one or more networks \n3409\n (e.g., consider one or more of the Internet, a private network, a cellular network, a satellite network, etc.).', 'As an example, the computer system \n3401\n-\n1\n may receive from and/or transmit information to one or more other devices, which may be or include, for example, one or more of the computer systems \n3401\n-\n2\n, etc.', 'A device may be located in a physical location that differs from that of the computer system \n3401\n-\n1\n.', 'As an example, a location may be, for example, a processing facility location, a data center location (e.g., server farm, etc.), a rig location, a wellsite location, a downhole location, etc.', 'As an example, a processor may be or include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.', 'As an example, the storage media \n3406\n may be implemented as one or more computer-readable or machine-readable storage media.', 'As an example, storage may be distributed within and/or across multiple internal and/or external enclosures of a computing system and/or additional computing systems.', 'As an example, a storage medium or storage media may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLUERAY disks, or other types of optical storage, or other types of storage devices.', 'As an example, a storage medium or media may be located in a machine running machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.', 'As an example, various components of a system such as, for example, a computer system, may be implemented in hardware, software, or a combination of both hardware and software (e.g., including firmware), including one or more signal processing and/or application specific integrated circuits.', 'As an example, a system may include a processing apparatus that may be or include a general purpose processors or application specific chips (e.g., or chipsets), such as ASICs, FPGAs, PLDs, or other appropriate devices.\n \nFIG.', '35\n shows components of a computing system \n3500\n and a networked system \n3510\n.', 'The system \n3500\n includes one or more processors \n3502\n, memory and/or storage components \n3504\n, one or more input and/or output devices \n3506\n and a bus \n3508\n.', 'According to an embodiment, instructions may be stored in one or more computer-readable media (e.g., memory/storage components \n3504\n).', 'Such instructions may be read by one or more processors (e.g., the processor(s) \n3502\n) via a communication bus (e.g., the bus \n3508\n), which may be wired or wireless.', 'The one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g., as part of a method).', 'A user may view output from and interact with a process via an I/O device (e.g., the device \n3506\n).', 'According to an embodiment, a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc.', 'According to an embodiment, components may be distributed, such as in the network system \n3510\n.', 'The network system \n3510\n includes components \n3522\n-\n1\n, \n3522\n-\n2\n, \n3522\n-\n3\n, . . .', '3522\n-N.', 'For example, the components \n3522\n-\n1\n may include the processor(s) \n3502\n while the component(s) \n3522\n-\n3\n may include memory accessible by the processor(s) \n3502\n.', 'Further, the component(s) \n3522\n-\n2\n may include an I/O device for display and optionally interaction with a method.', 'The network may be or include the Internet, an intranet, a cellular network, a satellite network, etc.', 'As an example, a device may be a mobile device that includes one or more network interfaces for communication of information.', 'For example, a mobile device may include a wireless network interface (e.g., operable via IEEE 802.11, ETSI GSM, BLUETOOTH, satellite, etc.).', 'As an example, a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio/video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery.', 'As an example, a mobile device may be configured as a cell phone, a tablet, etc.', 'As an example, a method may be implemented (e.g., wholly or in part) using a mobile device.', 'As an example, a system may include one or more mobile devices.', 'As an example, a system may be a distributed environment, for example, a so-called “cloud” environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc.', 'As an example, a device or a system may include one or more components for communication of information via one or more of the Internet (e.g., where communication occurs via one or more Internet protocols), a cellular network, a satellite network, etc.', 'As an example, a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).', 'As an example, information may be input from a display (e.g., consider a touchscreen), output to a display or both.', 'As an example, information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed.', 'As an example, information may be output stereographically or holographically.', 'As to a printer, consider a 2D or a 3D printer.', 'As an example, a 3D printer may include one or more substances that can be output to construct a 3D object.', 'For example, data may be provided to a 3D printer to construct a 3D representation of a subterranean formation.', 'As an example, layers may be constructed in 3D (e.g., horizons, etc.), geobodies constructed in 3D, etc.', 'As an example, holes, fractures, etc., may be constructed in 3D (e.g., as positive structures, as negative structures, etc.).', 'Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” together with an associated function.'] | ['1.', 'A method comprising:\ngenerating, via a domain planner, a prescriptive plan for a well construction process that comprises a series of well construction sub-processes, wherein each of the sub-processes comprises activities;\ngenerating, via a tactical planner, a dynamic plan for one of the activities, wherein the dynamic plan comprises an activity workflow and associated sub-activity workflows for the one of the activities, wherein each of the sub-activity workflows comprises one or more prescriptive tasks;\nduring execution of the dynamic plan, as part of execution of the prescriptive plan, and performance of at least one of the one or more prescriptive tasks, receiving sensor data;\nautomatically interpreting the sensor data to detect an event;\nautomatically generating an inference as to an impact of the event;\nbased at least in part on the inference, automatically deciding to revise the dynamic plan via issuance of a call to the tactical planner or to revise the prescriptive plan via issuance of a call to the domain planner;\nresponsive to deciding to revise the dynamic plan, automatically generating, via the tactical planner, a revised dynamic plan; and\nautomatically executing the revised dynamic plan to progress the execution of the prescriptive plan for the well construction process.', '2.', 'The method of claim 1, wherein the prescriptive plan, the dynamic plan and the prescriptive tasks define a series of tiered well construction activities.', '3.', 'The method of claim 2 wherein at least one of the series of tiered well construction activities comprises a drilling operation.', '4.', 'The method of claim 1, wherein, based at least in part on the inference, the automatically deciding comprises determining that the impact of the event does not require revision of the prescriptive plan.', '5.', 'The method of claim 1, wherein, based at least in part on the inference, the automatically deciding comprises deciding not to revise the prescriptive plan.', '6.', 'The method of claim 1, comprising, responsive to deciding to revise the prescriptive plan, generating, via the domain planner, a revised prescriptive plan.', '7.', 'The method of claim 1, comprising, prior to automatically executing the revised dynamic plan, automatically assessing viability of the revised dynamic plan.', '8.', 'The method of claim 1, wherein the generating, via the tactical planner, the revised dynamic plan comprises determining that the revised dynamic plan meets constraints.', '9.', 'The method of claim 8, wherein the constraints comprise at least one time-based constraint, at least one depth-based constraint, at least one equipment operation-based constraint and at least one formation-based constraint.', '10.', 'The method of claim 1, wherein the automatically interpreting the sensor data to detect the event comprises executing a computational framework that performs at least one simulation of physical phenomena using at least one model to generate simulation results indicative of the event.', '11.', 'The method of claim 1, wherein the automatically generating an inference as to an impact of the event, comprises executing a computational framework that generates an inference based on predicate information stored in a database.\n\n\n\n\n\n\n12.', 'The method of claim 11, comprising receiving at least a portion of the sensor data by the computational framework, wherein the inference is based at least in part on the at least a portion of the sensor data.', '13.', 'The method of claim 11, comprising transmitting the inference to at least one of the tactical planner and the domain planner.', '14.', 'The method of claim 1, comprising implementing a computational system that comprises a domain planner framework for execution of the domain planner, a tactical planner framework for execution of the tactical planner, an interpretation framework for generation of the event, and an inference framework for generation of the inference.', '15.', 'The method of claim 1, comprising executing a tactical planner computational framework, wherein the tactical planner computational framework comprises an actions dispatcher component and an actions execution component, wherein the actions execution component is operatively coupled to at least one piece of equipment implemented for performance of the well construction process.', '16.', 'A system comprising:\na processor;\nmemory accessible by the processor;\nprocessor-executable instructions stored in the memory and executable to instruct the system to: generate, via a domain planner, a prescriptive plan for a well construction process that comprises a series of well construction sub-processes, wherein each of the sub-processes comprises activities; generate, via a tactical planner, a dynamic plan for one of the activities, wherein the dynamic plan comprises an activity workflow and associated sub-activity workflows for the one of the activities, wherein each of the sub-activity workflows comprises one or more prescriptive tasks; during execution of the dynamic plan, as part of execution of the prescriptive plan, and performance of at least one of the one or more prescriptive tasks, receive sensor data; automatically interpret the sensor data to detect an event; automatically generate an inference as to an impact of the event; based at least in part on the inference, automatically make a decision to revise the dynamic plan via issuance of a call to the tactical planner or to revise the prescriptive plan via issuance of a call to the domain planner; responsive to the decision to revise the dynamic plan, automatically generate, via the tactical planner, a revised dynamic plan; and automatically execute the revised dynamic plan to progress the execution of the prescriptive plan for the well construction process.', '17.', 'One or more non-transitory computer-readable storage media comprising processor-executable instructions to instruct a computing system to:\ngenerate, via a domain planner, a prescriptive plan for a well construction process that comprises a series of well construction sub-processes, wherein each of the sub-processes comprises activities;\ngenerate, via a tactical planner, a dynamic plan for one of the activities, wherein the dynamic plan comprises an activity workflow and associated sub-activity workflows for the one of the activities, wherein each of the sub-activity workflows comprises one or more prescriptive tasks;\nduring execution of the dynamic plan, as part of execution of the prescriptive plan, and performance of at least one of the one or more prescriptive tasks, receive sensor data;\nautomatically interpret the sensor data to detect an event;\nautomatically generate an inference as to an impact of the event;\nbased at least in part on the inference, automatically make a decision to revise the dynamic plan via issuance of a call to the tactical planner or to revise the prescriptive plan via issuance of a call to the domain planner;\nresponsive to the decision to revise the dynamic plan, automatically generate, via the tactical planner, a revised dynamic plan; and\nautomatically execute the revised dynamic plan to progress the execution of the prescriptive plan for the well construction process.'] | ['FIG. 1 illustrates examples of equipment in a geologic environment;; FIG. 2 illustrates examples of equipment and examples of hole types;; FIG.', '3 illustrates an example of a system;; FIG.', '4 illustrates an example of a wellsite system and an example of a computing system;; FIG.', '5 illustrates an example of a graphical user interface;; FIG.', '6 illustrates an example of a graphical user interface;; FIG.', '7 illustrates an example of a method and an example of a system;; FIG. 8 illustrates an example of a system;; FIG. 9 illustrates an example of a system;; FIG.', '10 illustrates an example of a system;; FIG.', '11 illustrates an example of a system;; FIG.', '12 illustrates an example of a system;; FIG.', '13 illustrates an example of the system of FIG. 12;; FIG.', '14 illustrates an example of a system;; FIG.', '15 illustrates an example of a method;; FIG.', '16 illustrates an example of a method and an example of a graphical user interface;; FIG.', '17 illustrates an example of a method;; FIG.', '18 illustrates an example of a method;; FIG.', '19 illustrates an example of a method;; FIG.', '20 illustrates an example of a method;; FIG.', '21 illustrates an example of a method;; FIG.', '22 illustrates an example of a method and an example of a graphical user interface;; FIG.', '23 illustrates an example of a graphical user interface;; FIG.', '24 illustrates an example of a graphical user interface;; FIG.', '25 illustrates an example of a graphical user interface;; FIG.', '26 illustrates an example of a graphical user interface;; FIG.', '27 illustrates an example of a graphical user interface;; FIG.', '28 illustrates an example of a graphical user interface;; FIG.', '29 illustrates an example of a graphical user interface;; FIG.', '30 illustrates an example of a graphical user interface;; FIG.', '31 illustrates an example of a graphical user interface;; FIG.', '32 illustrates an example of a graphical user interface;; FIG.', '33 illustrates an example of a method;; FIG.', '34 illustrates an example of computing system; and; FIG.', '35 illustrates example components of a system and a networked system.; FIG.', '1 shows an example of a geologic environment 120.', 'In FIG.', '1, the geologic environment 120 may be a sedimentary basin that includes layers (e.g., stratification) that include a reservoir 121 and that may be, for example, intersected by a fault 123 (e.g., or faults).', 'As an example, the geologic environment 120 may be outfitted with any of a variety of sensors, detectors, actuators, etc.', 'For example, equipment 122 may include communication circuitry to receive and to transmit information with respect to one or more networks 125.', 'Such information may include information associated with downhole equipment 124, which may be equipment to acquire information, to assist with resource recovery, etc.', 'Other equipment 126 may be located remote from a well site and include sensing, detecting, emitting or other circuitry.', 'Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.', 'As an example, one or more pieces of equipment may provide for measurement, collection, communication, storage, analysis, etc. of data (e.g., for one or more produced resources, etc.).', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.', 'For example, FIG. 1 shows a satellite in communication with the network 125 that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).', '; FIG. 1 also shows the geologic environment 120 as optionally including equipment 127 and 128 associated with a well that includes a substantially horizontal portion (e.g., a lateral portion) that may intersect with one or more fractures 129.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop the reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment 127 and/or 128 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, injection, production, etc.', 'As an example, the equipment 127 and/or 128 may provide for measurement, collection, communication, storage, analysis, etc. of data such as, for example, production data (e.g., for one or more produced resources).', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.; FIG. 1 also shows an example of equipment 170 and an example of equipment 180.', 'Such equipment, which may be systems of components, may be suitable for use in the geologic environment 120.', 'While the equipment 170 and 180 are illustrated as land-based, various components may be suitable for use in an offshore system (e.g., an offshore rig, etc.).', '; FIG.', '2 shows an example of a wellsite system 200 (e.g., at a wellsite that may be onshore or offshore).', 'As shown, the wellsite system 200 can include a mud tank 201 for holding mud and other material (e.g., where mud can be a drilling fluid), a suction line 203 that serves as an inlet to a mud pump 204 for pumping mud from the mud tank 201 such that mud flows to a vibrating hose 206, a drawworks 207 for winching drill line or drill lines 212, a standpipe 208 that receives mud from the vibrating hose 206, a kelly hose 209 that receives mud from the standpipe 208, a gooseneck or goosenecks 210, a traveling block 211, a crown block 213 for carrying the traveling block 211 via the drill line or drill lines 212 (see, e.g., the crown block 173 of FIG. 1), a derrick 214 (see, e.g., the derrick 172 of FIG. 1), a kelly 218 or a top drive 240, a kelly drive bushing 219, a rotary table 220, a drill floor 221, a bell nipple 222, one or more blowout preventors (BOPs) 223, a drillstring 225, a drill bit 226, a casing head 227 and a flow pipe 228 that carries mud and other material to, for example, the mud tank 201.; FIG.', '2 also shows some examples of types of holes that may be drilled.', 'For example, consider a slant hole 272, an S-shaped hole 274, a deep inclined hole 276 and a horizontal hole 278.; FIG.', '3 shows an example of a system 300 that includes various equipment for evaluation 310, planning 320, engineering 330 and operations 340.', 'For example, a drilling workflow framework 301, a seismic-to-simulation framework 302, a technical data framework 303 and a drilling framework 304 may be implemented to perform one or more processes such as a evaluating a formation 314, evaluating a process 318, generating a trajectory 324, validating a trajectory 328, formulating constraints 334, designing equipment and/or processes based at least in part on constraints 338, performing drilling 344 and evaluating drilling and/or formation 348.; FIG.', '4 shows an example of a wellsite system 400, specifically, FIG.', '4 shows the wellsite system 400 in an approximate side view and an approximate plan view along with a block diagram of a system 470.; FIG.', '4 also shows a battery 480 that may be operatively coupled to the system 470, for example, to power the system 470.', 'As an example, the battery 480 may be a back-up battery that operates when another power supply is unavailable for powering the system 470.', 'As an example, the battery 480 may be operatively coupled to a network, which may be a cloud network.', 'As an example, the battery 480 can include smart battery circuitry and may be operatively coupled to one or more pieces of equipment via a SMBus or other type of bus.; FIG.', '5 shows an example of a graphical user interface (GUI) 500 that includes information associated with a well plan.', 'Specifically, the GUI 500 includes a panel 510 where surfaces representations 512 and 514 are rendered along with well trajectories where a location 516 can represent a position of a drillstring 517 along a well trajectory.', 'The GUI 500 may include one or more editing features such as an edit well plan set of features 530.', 'The GUI 500 may include information as to individuals of a team 540 that are involved, have been involved and/or are to be involved with one or more operations.', 'The GUI 500 may include information as to one or more activities 550.', 'As shown in the example of FIG.', '5, the GUI 500 can include a graphical control of a drillstring 560 where, for example, various portions of the drillstring 560 may be selected to expose one or more associated parameters (e.g., type of equipment, equipment specifications, operational history, etc.).', 'FIG. 5 also shows an example of a table 570 as a point spreadsheet that specifies information for a plurality of wells.', 'As shown in the example table 570, coordinates such as “x” and “y” and “depth” can be specified for various features of the wells, which can include pad parameters, spacings, toe heights, step outs, initial inclinations, kick offs, etc.; FIG.', '6 shows an example of a graphical user interface 600 that includes a schedule organized with respect to time (days, dates, etc.)', 'and with respect to various types of operations.', 'The GUI 600 can be part of a well planning system, which may be part of a field development framework.', 'For example, the various operations in the GUI 600 can be implemented to drill at least a portion of a well in a geologic environment (e.g., an oil field or oilfield) where the well may be completed for one or more purposes (e.g., production of hydrocarbons, injection of fluid(s), fracturing of rock, etc.).', '; FIG.', '7 shows an example of a method 700 and an example of a system 790.', 'The method 710 includes a selection block 710 for selecting an operational context (e.g., well construction, etc.), a provision block 720 for provisioning equipment and/or interfaces for purposes of data acquisition and control, a performance block 730 for performing operations based at least in part on a digital plan, and a control block 740 for controlling performance of operations based at least in part on feedback (e.g., based at least in part on acquired data, etc.).', '; FIG.', '8 shows an example of a system 800 that can be a well construction ecosystem.', 'As shown, the system 800 includes rig infrastructure 810 and a drill plan component 820 that can generation or otherwise transmit information associated with a plan to be executed utilizing the rig infrastructure 810, for example, via the drilling operations layer 840, which includes a wellsite component 842 and an offsite component 844.', 'As shown, data acquired and/or generated by the drilling operations layer 840 can be transmitted to a data archiving component 850, which may be utilized, for example, for purposes of planning one or more operations (e.g., per the drilling plan component 820.; FIG.', '9 shows an example of a system 900 that includes data 910 that can be received by a project management component 920 via a project portal where the component 920 includes workflow management features, which can include features that operate on the data 910 to generate a digital plan such as a drilling digital plan, which may include executable instructions to control one or more pieces of equipment at a rigsite.', 'As shown, the digital plan may be transmitted to a drilling operations component 930 (see, e.g., the layer 840 of FIG.', '8).;', 'FIG.', '10 shows an example of a system 1000 that includes various layers and operational blocks, including an applications layer 1010 that can include a remote access and interface block 1020 (e.g., for access to interfaces of rigsite equipment from one or more remote locations, etc.), an intelligence and inferencing block 1030 (e.g., resources optionally remote from a rigsite, etc.), an applications delivery and/or GUIs block 1040 (e.g., optionally including one or more application programming interfaces, etc.), and a framework layer 1050 that includes a core services and/or resources block 1060.; FIG.', '11 shows an example of a system 1100 that may be implemented, at least in part, via cloud resources 1101.', 'In the example of FIG.', '11, locations are indicated such as by a rig 1120 and an office 1130 where the rig 1120 can be a rigsite location or locations of rigsites and where the office 1130 can be an office location or locations of offices where an office may be at a rigsite or at another site, which may be remote from the rigsite.; FIG.', '12 shows an example of a system 1200 that includes various blocks including a digital drill plan (DDP) block 1205, a domain planner block 1210, an operation orchestration block 1220, a domain tactical planning block 1230, an actions dispatcher block 1240, an actions execution and monitoring block 1250, an inference engine block 1260, a drilling interpretation block 1270, and a core services block 1280.; FIG.', '13 shows an example of an implementation of the system 1200 of FIG.', '12, with various examples of components and features.', 'The example of FIG.', '13 shows the various blocks 1210, 1220, 1230, 1240, 1250, 1260, 1270 and 1280 with respect to the digital drill plan block 1205.', 'The blocks can be components of a computational system.; FIG.', '14 shows an example of a system 1400 that includes various layers of organization including equipment operations 1402, well centric operations and rig equipment management 1404, offsite operations management 1406 and cold data storage 1408.; FIG.', '15 shows an example of a method 1500 that may implement a system such as, for example, the system 1200 of FIG.', '12, the system of 1000 of FIG.', '10 and/or the system 1100 of FIG.', '11.; FIG.', '16 shows an example of a method 1600 and an example of a graphical user interface (GUI) 1690.', 'As shown, the method 1600 includes prescriptive blocks 1610 and 1630 and a dynamic block 1620.', 'Such blocks may be associated with various blocks of the method 1500 of FIG.', '15.', 'For example, the process block 1510, the sub-process block 1530 and the activity block 1540 may be associated with the prescriptive block 1610 and the activity workflow block 1570 may be associated with the dynamic block 1620, while operational tasks as part of an activity workflow may be associated with the prescriptive block 1630.; FIG.', '17 shows an example of a method 1700 that is directed to a particular sub-process in the context of well construction, as illustrated in the example of FIG.', '15.', 'As shown, at a sub-process tier or level, the method 1700 can include a movement block 1710 for moving a rig (e.g., to a rigsite), a construction block 1720 for constructing a section X of a well at the rigsite utilizing the rig, and a construction block 1730 for constructing another section Y of the well at the rigsite utilizing the rig.', 'The blocks 1710, 1720 and 1730 may be performed according to one or more constraints, which may pertain to one or more goals.', 'For example, consider a human safety goal and/or an equipment safety goal.', 'Such goals may be based at least in part on information received from one or more entities as, for example, one or more of policies, standards, procedures or guidelines.', 'As an example, to achieve a goal, a constraint may be to limit the ground speed of a portion of the rig equipment to being less than X kph while another goal may be a time-based goal where a minimum ground speed is to be at least Y kph where X is greater than Y. As explained with respect to the example of FIG.', '13, monitoring may occur where ground speed can be determined and compared to a constraint where a result of a comparison may be utilized for one or more purposes (e.g., notifications, replanning, etc.).', '; FIG.', '18 shows an example of a method 1800 that is directed to a particular activity in the context of well construction, as illustrated in the example of FIG.', '15.', 'As shown, at an activity tier or level, the method 1800 can include a drill block 1810 for drilling a section of a well (e.g., section X, section Y, etc.), a case block 1820 for casing a section of a well that has been drilled, a cement block 1830 for cementing a section of a well (e.g., a cased section of a well), and a secure block 1840 for securing a section of a well.', 'As an example, the method 1800 may be implemented a plurality of times for a plurality of sections (e.g., section X, section Y, etc.).', 'As an example, the method 1800 may be performed using information received from one or more entities where such information may be translatable into one or more goals, one or more constraints, etc.; FIG.', '19 shows an example of a method 1900 as associated with sub-activities in the context of well construction.', 'As shown, the method 1900 can include a drilling run block 1910, a wireline run block 1920 and a clean out run block 1930.', 'With respect to the method 1500 of FIG.', '15', ', note that sub-activities may be generated via the planning block 1520, for example, one or more sub-activities may be dynamic in that operations are performed at a rigsite where data may be acquired during such activities, which may provide feedback, which can be utilized in a dynamic manner such that one or more aspects of the method 1900 may be updated in real-time.', 'As an example, the method 1900 may be performed using information received from one or more entities where such information may be translatable into one or more goals, one or more constraints, etc.; FIG.', '20 shows an example of a method 2000 as associated with an activity workflow in the context of well construction.', 'As shown, the method 2000 can include a make up BHA block 2010 for making up a bottom hole assembly (BHA) for drilling at least a portion of a well, a trip in to depth block 2020 for tripping the made up BHA to a depth, a drill to depth block 2030 for utilizing the BHA for drilling to a depth (e.g., as may be specified by a digital drill plan for a particular section of a well), a circulate to condition hole block 2040 for circulating material (e.g., fluid, etc.) to condition a bore hole, a conduct flow check block 2050 for conducting a flow check as to flow of fluid (e.g., liquid, gas, slurry, etc.)', 'in at least a portion of a bore hole, a trip out to depth block 2060 for tripping out at least a portion of the BHA to a depth (e.g., surface, sea bottom, etc.), and a lay down BHA block 2070 for laying down a BHA (e.g., or portion thereof).', 'As an example, the method 2000 may be performed using information received from one or more entities where such information may be translatable into one or more goals, one or more constraints, etc.; FIG.', '21 shows an example of a method 2100 as various operational tasks that may be associated with the make up BHA block 2010 of the method 2000 of FIG.', '20.', 'As shown, the operational tasks can be specified in a logical manner where various tasks are assigned to particular resources (e.g., individuals, machines, teams, etc.).', 'In the example of FIG.', '21', ', the resources include a logistics coordination resource, a toolpusher resource, a directional driller resource, a roust about resource, a driller resource and a measurement while drilling (MWD) resource.', 'As shown, various tasks can be depended on other tasks.', '; FIG.', '22 specifically shows an example of a method 2200 and an example of a graphical user interface (GUI) 2201 that can be an interactive interface that renders information as to the method 2200 and/or a system such as the system 1000 of FIG.', '10.; FIG.', '23 shows an example of a graphical user interface 2300 that includes a multi-dimensional system, which may be referred to as an operational space or a field development space for visualizing various operations that may be part of a well plan.', 'For example, the GUI 2300 includes: a physical well structure dimension with location, surface section, intermediate section and production section labels that demarcate physical structures of a well that may be drilled into a geologic environment; a well plan engineering dimension that includes development activities such as, for example, one or more of rig selection, trajectory design, casing design, bit design, drilling fluids design, cementing design, and logging design, which may be organized along the well plan engineering dimension in an order that can correspond to an approximate order based on dependencies (e.g., a BHA design being dependent on a bit design, a trajectory design, etc.); an activity plan dimension that can correspond to a linear progression in time as to field development operations; and one or more scenario dimensions that can highlight one or more regions within the foregoing three dimensions where one or more development operations can benefit from one or more adjustments.', 'As an example, a scenario dimension may be a risk dimension that highlights a risk in a multidimensional space.; FIG.', '23 also shows a graphical representation of a portion of a geological environment into which the physical well is being drilled or to be drilled.', 'The graphical representation can be a graphical user interface and/or part of the GUI 2200.', 'The graphical representation, as a GUI, can include control graphics that can be selected (e.g., actuated), which may, for example, cause rendering of one or more other GUIs to a display.', 'For example, along a right side column, icons are shown that can correspond to framework tools that can be instantiated and utilized.', 'Such tools may be highlighted to correspond to one or more features highlighted in the multidimensional system.', 'For example, where a risk exists with respect to a BHA, a BHA control graphic may be highlighted that upon actuation switches a user to a BHA GUI that can adjust one or more parameters associated with a BHA (see, e.g., the drillstring 560 of the GUI 500 of FIG.', '5).;', 'FIG.', '24 shows an example of a graphical user interface 2400 that includes the well plan engineering dimension along with some examples such as rig selection, trajectory design, casing design, bit design, drilling fluids design, cementing design, and logging design.', 'Such designs can be present for one or more positions along the physical well structure dimension.', 'As an example, “bit design” may be present along the subsurface sections of the physical well structure dimension and may change depending on section (e.g., where tripping out and tripping in may be performed as part of a bit change according to a bit design).', '; FIG.', '25 shows an example of a graphical user interface 2500 that includes the activity plan dimension along with some examples of markers for location and sections: construct location, construct 12% inch section, construct 8½ inch section, and construct 6% inch section.', 'Such sections can correspond to sections of the physical well structure; noting that the activity plan dimension can be a time dimension, which may be linear, non-linear, continuous, non-continuous, continuous and non-continuous, etc.; FIG.', '26 shows an example of a graphical user interface 2600 as including graphical controls associated with digital documents (e.g., digital files).', 'For example, an operations procedure document (OP), a checklist document, a work instructions document (WI), or other document may be linked with one or more points within the multidimensional system.', 'The example of FIG.', '26 includes two highlighted scenarios that can correspond to risk or level of risk for one or more activities along the activity plan dimension.', 'As an example, a highlighted region can correspond to a single point in the physical well structure dimension and the plan activity dimension plane or a highlighted region can correspond to multiple points in the physical well structure dimension and the plan activity dimension plane.', 'As an example, a user may navigate a cursor to a highlighted region (e.g., or touch a highlighted region on a touchscreen) to activate a menu that can list menu options that are associated with conditions, specifications, etc., that underlie a reason as to why the region was highlighted (e.g., increased level of risk, conflicting parameters in design, etc.).', '; FIG.', '26 also shows an example graphic of a bore drilling issue that can be due to bore geometry (e.g., well trajectory geometry) and another graphic of a bore drilling issue that can be due to an accumulation of debris (“junk”) in the bore, which may interfere with drilling operations.', 'As indicated in FIG.', '26, the notification as to the issue is associated with a position in the multi-dimensional space defined by dimensions for physical well structure, well plan engineering and activity plan.', 'The issue is shown as being associated with a particular BHA and a fluid.', 'As an example, a method can include rendering an issue in a multi-dimensional environment where the rendering can occur prior to performing one or more activities along the activity plan dimension.', '; FIG.', '27 shows an example of a graphical user interface 2700 that illustrates a workflow that can fuse various types of policies, standards, procedures, and guidelines.', 'For example, various entities can specify logic that can include technical logic for performing one or more field operations.', 'Such logic can be particular to an entity, for example, based on expertise, risk, etc., of the entity and what that entity may be providing as a service, as a product, etc.', 'For example, a particular downhole tool may be supplied by an entity to perform a field operation where the entity has expertise as to how the downhole tool is to be utilized, under what conditions it is to be utilized, etc.', 'As illustrated in the GUI 2700, a workflow can fuse logic from a plurality of different entities such that a tiered output can be generated, which is shown as including a plurality of levels: L2 to L7.', 'Further, the GUI 2700 provides guidance as to levels and sequences of activities that describe well construction and tasks and operational steps, which can include work instructions, checklists, etc.', 'The tiered output can be utilized to construct a well and may include executable commands, instructions, etc., that may be consumed by one or more pieces of equipment, which may, in response to receipt thereof, perform one or more actions, be configured for performance of one or more actions, etc.', 'For example, consider a programmable downhole tool being programmed per a work instruction associated with the level L6 Tasks.', 'As an example, a programmable downhole tool may be programmed to acquire sensor data at an instructed resolution, frequency, acquisition algorithm, etc.; FIGS.', '28, 29, 30 and 31 show examples of graphical user interfaces 2800, 2900, 3000, and 3100 that include information as to logic of policies, standards, goals and constraints.', 'One or more of the GUIs 2800, 2900, 3000 and 3100 may be part of a workflow or workflows of a computational framework such as one associated with the GUI 2700 of FIG.', '27.', 'For example, the policy and/or standard information may represent types of information that can be received by an interface of a computational framework, which may generate logic based thereon to fuse such information into output for construction of a well.; FIG.', '32 shows an example of a graphical user interface 3200 that includes various types of information for construction of a well where times are rendered for corresponding actions.', 'In the example of FIG.', '32, the information may be part of a work breakdown structure (WBS); noting that the information of the GUI 1690 of FIG.', '16 may be part of a WBS.; FIG.', '33 shows an example of a method 3300 for controlling field equipment where the method 3300 includes a reception block 3310 for receiving information via an interface of a control system; an analysis block 3320 for analyzing the information by the control system with respect to tiered well construction activities; a generation block 3330 for, based on the analyzing, generating a workflow that includes at least a series of tiered well construction activities; and a transmission block 3340 for transmitting a signal from the control system to the field equipment to control the field equipment to perform at least one of the series of tiered well construction activities.', 'As mentioned, a method can include utilizing constraints for generating a workflow that includes at least a series of tiered well construction activities.', 'As an example, a method can be dynamic and generate a workflow responsive to a change in circumstances, for example, a change with respect to circumstances considered during planning.', 'As an example, a method may generate a revised workflow.; FIG.', '35 shows components of a computing system 3500 and a networked system 3510.', 'The system 3500 includes one or more processors 3502, memory and/or storage components 3504, one or more input and/or output devices 3506 and a bus 3508.', 'According to an embodiment, instructions may be stored in one or more computer-readable media (e.g., memory/storage components 3504).', 'Such instructions may be read by one or more processors (e.g., the processor(s) 3502) via a communication bus (e.g., the bus 3508), which may be wired or wireless.', 'The one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g., as part of a method).', 'A user may view output from and interact with a process via an I/O device (e.g., the device 3506).', 'According to an embodiment, a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc.'] |
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US11142986 | Isolation assembly | May 31, 2016 | Mariano Sanchez, Isaac Aviles Cadena, Afou Keshishian | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion for corresponding PCT Application No. PCT/US2016/034972, dated Jan. 6, 2017, 16 pages. | 7424909; September 16, 2008; Roberts et al.; 7775279; August 17, 2010; Marya et al.; 7810558; October 12, 2010; Shkurti et al.; 7980300; July 19, 2011; Roberts et al.; 8047280; November 1, 2011; Tran et al.; 8211247; July 3, 2012; Marya et al.; 8211248; July 3, 2012; Marya; 9752407; September 5, 2017; Jacob et al.; 20020060078; May 23, 2002; Cook; 20130186616; July 25, 2013; Xu et al.; 20140054047; February 27, 2014; Zhou; 20140060837; March 6, 2014; Love; 20160186511; June 30, 2016; Coronado; 20160230498; August 11, 2016; Walton | WO2007015766; February 2007; WO; WO2016065291; April 2016; WO | ['An apparatus that is usable with a well includes a tubular assembly and an expansion tool.', 'The tubular assembly has a radially contracted state and includes a restriction.', 'The restriction is adapted to catch an object that is deployed into the well to form a fluid barrier when caught by the restriction.', 'The expansion tool is deployed downhole with the tubular assembly inside a tubing string.', 'The expansion tool is adapted to deform the tubular assembly to anchor the tubular assembly to the tubing string.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nWell stimulation operations may be conducted downhole in a well that extends through a hydrocarbon bearing formation for purposes of enhancing hydraulic communication between the formation and the well.', 'As an example, a jetting operation may be performed to remove debris that was introduced during the drilling of the well or during downhole perforating operations.', "In this manner, a jetting tool may be run, or deployed, downhole on a coiled tubing string, and an acidic jetting fluid may be communicated via the coiled tubing string through nozzles of the tool to remove the debris from the near wellbore to increase the well's permeability.", 'Hydraulic fracturing is another example of a well stimulation operation.', 'In hydraulic fracturing, fluid in the well is pressurized to fracture the surrounding formation rock and introduce a fracture pack (proppant, for example) into the resulting fractures for purposes of holding the fractures open when the pressure is released.', 'Well stimulation operations may be performed sequentially in multiple isolated segments, or stages, of the well and may involve the deployment and use of various downhole tools, such as fracturing plugs, sleeve valves, and so forth.', 'SUMMARY', 'The summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'In accordance with an example implementation, a technique includes deploying an isolation assembly into a tubing string that was previously installed in a well; deforming the isolation assembly at a downhole location in the well to secure the assembly to the tubing string; receiving an object in a restriction of the isolation assembly; and using the received object in the isolation assembly to perform a downhole operation in the well.', 'In accordance with another example implementation, an apparatus that is usable with a well includes a tubular assembly and an expansion tool.', 'The tubular assembly has a radially contracted state and includes a restriction.', 'The restriction is adapted to catch an object that is deployed into the well to form a fluid barrier when caught by the restriction.', 'The expansion tool is deployed downhole with the tubular assembly inside a tubing string.', 'The expansion tool is adapted to deform the tubular assembly to anchor the tubular assembly to the tubing string.', 'In accordance with yet another example implementation, a system that is usable with a well includes a tubing string and an isolation assembly.', 'The tubing string supports a wellbore, and the wellbore has multiple stages.', 'The isolation assembly is deployed in the central passageway of the tubing string to form an isolation barrier for a given stage of the multiple stages.', 'The isolation assembly includes a tubular assembly and an expansion tool.', 'The tubular assembly has a radially contracted state and includes a seat.', 'The seat is adapted to catch an untethered object that is deployed into the central passageway of the tubing string to form a fluid barrier due to the untethered object being caught by the seat.', 'The expansion tool is deployed downhole with the tubular member as a unit inside the tubing string.', 'The expansion tool is adapted to deform the tubular assembly to anchor the tubular assembly to the tubing string.', 'Advantages and other features will become apparent from the following drawings, description and claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1A\n a schematic diagram of a well according to an example implementation.', 'FIG.', '1B\n is a schematic diagram of the well of \nFIG.', '1A\n illustrating the formation of a fluid barrier downhole in a tubing string of the well and the use of the fluid barrier in a stimulation operation conducted in an isolated stage of the well according to an example implementation.', 'FIG.', '2A\n is a schematic diagram illustrating an isolation assembly in its radially contracted state according to an example implementation.', 'FIG.', '2B\n is a schematic diagram illustrating the isolation assembly of \nFIG.', '2A\n during the radial expansion of the assembly according to an example implementation.', 'FIG.', '2C\n is a schematic diagram of the isolation assembly of \nFIG.', '2A\n illustrating the isolation assembly in its radially expanded state according to an example implementation.', 'FIGS.', '3A, 3B, 8A and 8B\n are flow diagrams depicting techniques to form and use a fluid barrier constructed from a deformable isolation assembly according to example implementations.', 'FIGS.', '4A, 4B, 4C and 4D\n depict sleeves and anchoring members for an isolation assembly according to example implementations.\n \nFIG.', '5\n depicts a cross-sectional view of a setting tool mandrel and a sleeve of an isolation assembly according to a further example implementation.', 'FIG.', '6A\n is a schematic diagram illustrating an isolation assembly in its radially contracted state according to a further example implementation.', 'FIG.', '6B\n is a schematic diagram illustrating the isolation assembly of \nFIG.', '6A\n during the radial expansion of the assembly according to an example implementation.', 'FIG.', '6C\n is a schematic diagram of the isolation assembly of \nFIG.', '6A\n illustrating the isolation assembly in its radially expanded state according to an example implementation.', 'FIG.', '7A\n is a schematic diagram illustrating an isolation assembly in its radially contracted state according to a further example implementation.', 'FIG.', '7B\n is a schematic diagram illustrating the isolation assembly of \nFIG.', '7A\n during the radial expansion of the assembly according to an example implementation.', 'FIG.', '7C\n is a schematic diagram of the isolation assembly of \nFIG.', '7A\n illustrating the isolation assembly in its radially expanded state according to an example implementation.', 'DETAILED DESCRIPTION', 'In general, systems and techniques are disclosed herein to deploy and use a deformable isolation assembly in a well for purposes of performing a downhole operation.', 'In this regard, the isolation assembly that is disclosed herein has a radially contracted state, which allows the assembly to be run downhole in the well inside the central passageway of a tubing string (a casing string, for example) that was previously installed in the well.', 'When at the appropriate downhole location, the isolation assembly may be radially expanded and secured, or anchored, to the tubing string to form a downhole obstruction, or fluid barrier, inside the central passageway of the tubing string; and this fluid barrier may then be used in connection with a downhole operation.', 'The downhole operation may be any of a number of operations (a stimulation operation, perforating operation, a jetting operation and so forth) that rely on a fluid barrier inside a tubing string.', 'In accordance with example implementations that are disclosed herein, the isolation assembly has a central passageway and a restriction that is formed in its central passageway for purposes of allowing an object to be landed in the restriction to form the fluid barrier after the assembly had been anchored in place and radially expanded.', 'As a more specific example, the isolation assembly may be a fracturing plug assembly, and the restriction may be an inner, object catching seat.', 'In this context, “object catching seat” refers to the seat being constructed to catch an object that is deployed through the tubing string, such as a ball, a dart, a barrel, a rod, or any other object that is constructed to land in the seat to form the fluid barrier.', 'In general, the isolation assembly is run downhole in a collapsed, or unexpanded state (also referred to as the “radially contracted state” herein), which allows the isolation assembly to have a smaller overall cross-section.', 'This smaller cross-section allows the isolation assembly to be freely run downhole inside the central passageway of a tubing string without being impeded by features of the string.', 'As further described herein, after being placed in the appropriate downhole location, the isolation assembly may be transitioned to its expanded state (also called the “radially expanded state” herein) in which the isolation assembly is secured, or anchored, to the tubing string wall.', 'In this radially expanded stage, the isolation assembly may be used to catch an object that is deployed in the central passageway of the string for purposes of forming a fluid barrier.', 'In accordance with example implementations, in its expanded state, the isolation assembly is constructed to receive, or catch, an object, which is deployed in the passageway of the tubing string.', "In accordance with example implementations, the object may be a solid object that is constructed to be caught by the isolation assembly's restriction so that the landed object in conjunction with the assembly substantially closes off fluid communication through the assembly to form a downhole fluid barrier.", '“Substantially closes off” fluid communication refers to fluid communication through the isolation assembly being inhibited to the extent that a fluid column above the assembly may be pressurized to perform a downhole operation (pressurized to conduct a hydraulic fracturing operation, for example).', 'Fluid leakage between the landed object and the restriction may or may not occur, depending on the particular implementation.', 'The object that lands in the restriction may be an “untethered object,” in accordance with example implementations.', 'In this context, an “untethered object” refers to an object that is communicated downhole through the passageway of the string along at least part of its path without the use of a conveyance line (a slickline, a wireline, a coiled tubing string and so forth).', 'As an example, the untethered object may be deployed from the Earth surface of the well.', "In accordance with further example implementations, the untethered object may be run downhole into the well by a conveyance mechanism, such as a wireline, slickline, coiled tubing string or jointed tubing string and then released to travel into the tubing string containing the isolation assembly to land in the assembly's restriction.", "In accordance with further example implementations, the object may be tethered to the end of a conveyance mechanism or tool, which is run downhole to position the object in the isolation assembly's restriction.", 'Thus many implementations are contemplated, which are within the scope of the appended claims.', 'In accordance with example implementations described herein, the isolation assembly includes a sleeve that is constructed to be deformably expanded downhole in the well to anchor the isolation assembly to the tubing string.', 'For example, in accordance with some implementations, the isolation assembly may be run downhole with a setting tool on a conveyance mechanism, such as a tubular string, coiled tubing, a wireline, and so forth.', 'After being placed in the proper position, the setting tool may be actuated using actions initiated from the Earth surface of the well for purposes of exerting a force to deform the sleeve to cause the sleeve to radially expand and become anchored to the surrounding wall of the tubing string.', 'In accordance with example implementations, the sleeve of the isolation assembly may be radially expanded to anchor the sleeve to the tubing string, and the sleeve may contain a restriction to form a seat to catch an untethered object to form a fluid barrier in the tubing string.', "More specifically, in accordance with example implementations that are described herein, the setting tool may have an expansion member that, for the assembly's radially contracted state, has an overall outer dimension that is greater than the overall inner dimension of the isolation assembly; and when the isolation assembly has been run downhole and placed at the appropriate target downhole location, the conveyance mechanism may be pulled uphole to draw the expansion tool member through the interior of the isolation assembly to deform and radially expand isolation assembly.", 'After the isolation assembly has been radially expanded and anchored in place, the setting tool and conveyance mechanism may then be pulled out of the well; and then an object may be deployed to land in the restriction of the isolation assembly to form a fluid barrier.', 'In accordance with further example implementations, the seat of the isolation assembly may be separate from the sleeve of the isolation assembly.', 'In this manner, the isolation assembly may include a seat member (containing the seat) and a deformable sleeve.', 'A setting tool on which the isolation assembly is mounted may be run downhole in the central passageway of the tubing string to a target downhole location.', 'The setting tool may then be actuated to radially expand the sleeve member and force the sleeve member between the seat member and the tubing string wall for purposes of forming a wedge, or friction, fit between the seat member and the tubing string.', 'As described herein, in accordance with some implementations, the sleeve member may be run into the well mounted uphole of the seat member on the setting tool.', 'A tension mandrel of the setting tool may be secured to the seat member so that the setting tool may be actuated to engage a sleeve member of the isolation assembly to exert a force on the sleeve member and axially translate the sleeve member to force the sleeve member into a seat member of the isolation assembly.', 'In this manner, the force that is applied by the setting tool and the axial translation of the sleeve member caused by this force causes the sleeve member to radially expand to form a wedge between the seat member and the tubing string wall.', 'In accordance with further example implementations that are described herein, the isolation assembly may include a sleeve member and a seat member, with the seat member being mounted on the setting tool uphole of the sleeve member.', 'A tension mandrel of the setting tool may be secured to the sleeve member so that the setting tool may be actuated to apply a force to the seat member to axially translate the seat member into the sleeve member to cause the sleeve member to deform and radially expand to form a wedge between the seat and the tubing string wall.', 'Referring to \nFIG.', '1A\n as a more specific example, in accordance with some implementations, a well \n100\n includes a wellbore \n115\n, which traverses one or more hydrocarbon-bearing formations.', 'As an example, the wellbore \n115\n may be lined, or supported, by a tubing string \n120\n, as depicted in \nFIG.', '1A\n.', 'The tubing string \n120\n may be a liner string or a casing string that is cemented to and supports the wellbore \n115\n (such wellbores are typically referred to as “cased hole” wellbores); or the tubing string \n120\n may be secured to the surrounding formation(s) by packers (such wellbores typically are referred to as “open hole” wellbores).', 'In general, the wellbore \n115\n may extend through multiple segments, or stages \n130\n (four example stages \n130\n-\n1\n, \n130\n-\n2\n, \n130\n-\n3\n, and \n130\n-\n4\n, being depicted in \nFIG.', '1A\n), of the well \n100\n.', 'It is noted that although \nFIG.', '1A\n and other figures disclosed herein depict a lateral wellbore, the techniques and systems that are disclosed herein may likewise be applied to vertical wellbores.', 'Moreover, in accordance with some implementations, the well \n100\n may contain multiple wellbores, which contain tubing strings that are similar to the illustrated tubing string \n120\n of \nFIG.', '1A\n.', 'The well \n100\n may be a subsea well or may be a terrestrial well, depending on the particular implementation.', 'Additionally, the well \n100\n may be an injection well or may be a production well.', 'Thus, many implementations are contemplated, which are within the scope of the appended claims.', 'Multiple stage operations (fracturing or other stimulation operations) may be performed along the wellbore \n115\n, one stage \n130\n at a time.', 'In this manner, a given stage \n130\n may be hydraulically isolated from the other stages \n130\n, a given operation may be performed in the isolated stage, the isolation may be removed, and then these same steps may be performed for the next stage.', 'The downhole operations may be performed in the stages \n130\n in a particular directional order, in accordance with example implementations.', 'For example, in accordance with some implementations, downhole operations may be conducted in a direction from a toe end of the wellbore to a heel end of the wellbore \n115\n.', 'In further implementations, the multiple stage downhole operations may be connected from the heel end to the toe end of the wellbore \n115\n.', 'In accordance with further example implementations, the multiple stage operations may be performed in no particular order, or sequence.', 'FIG.', '1A\n depicts that fluid communication with the surrounding hydrocarbon formation(s) has been enhanced through sets \n140\n of perforation tunnels that, for this example, are formed in each stage \n130\n and extend through the tubing string \n120\n.', 'It is noted that each stage \n130\n may have multiple sets of such perforation tunnels \n140\n.', 'Although perforation tunnels \n140\n are depicted in \nFIG.', '1A\n, it is understood that other techniques other than perforating may be used to establish/enhance fluid communication with the surrounding formation (s).', 'For example, the fluid communication may be alternatively established/enhanced by jetting an abrasive fluid using a jetting tool; opening sleeve valves of the tubing string \n120\n; and so forth.', 'One or more multiple stage stimulation operations may be performed after such operations.', 'In accordance with further example implementations, the multiple stage stimulation operation(s) may be performed without first perforating or jetting.', 'Referring to \nFIG.', '1B\n in conjunction with \nFIG.', '1A\n, as an example, a stimulation operation may be performed in the stage \n130\n-\n1\n by deploying an isolation assembly \n175\n into the tubing string \n120\n on a setting tool (not depicted in \nFIGS.', '1A and 1B\n) in a radially contracted state of the assembly \n175\n and running the assembly \n175\n to a target downhole location in a given stage \n130\n of the well.', 'As described herein, the setting tool may then be used to radially expand the isolation assembly \n175\n and anchor the isolation assembly \n175\n to the tubing string \n120\n.', 'For the example of limitation that is depicted in \nFIG.', '1B\n, the isolation assembly \n175\n has been radially expanded and anchored to the tubing string \n120\n in the stage \n130\n-\n1\n.', 'After the isolation assembly \n175\n has been installed, a solid object (here, an activation ball \n150\n) may be deployed so that the object lands in a restriction of the assembly \n175\n to form a fluid barrier, as shown in \nFIG.', '1B\n.', 'As depicted in \nFIG.', '1B\n, the fluid barrier may be used to divert a stimulation fluid (fracturing fluid pumped into the tubing string \n120\n from the Earth surface, for example) into the formation in the stage \n130\n-\n1\n.', 'The radially contracted state, or run-in-hole state, of the isolation assembly \n175\n, in accordance with an example implementation, is depicted in \nFIG.', '2A\n.', 'Referring to \nFIG.', '2A\n in conjunction with \nFIG.', '1B\n, in accordance with example implementations, the isolation assembly \n175\n includes a tubular body, or sleeve \n207\n, which is coaxial with a longitudinal axis \n201\n of isolation assembly \n175\n.', 'The longitudinal axis \n201\n, in turn, is generally coaxial with the outer tubing string \n120\n.', 'The sleeve \n207\n has a restriction \n200\n, which circumscribes the longitudinal axis \n201\n and is sized to catch a solid object, such as activation ball \n150\n (\nFIG.', '1B\n), to form a fluid barrier.', 'The restriction \n205\n may be symmetrical about the longitudinal axis to form a seat, as depicted in \nFIG.', '2A\n.', 'However, in accordance with further example implementations, the restriction \n205\n may be asymmetric with respect to the longitudinal axis \n200\n.', 'In accordance with example implementations, the restriction \n205\n may have a profile that complements the profile of the object to be landed in the restriction \n205\n.', 'For example, the restriction \n205\n may have a curved surface that corresponds to the spherical outer surface of a ball, such as activation ball \n150\n (see \nFIG.', '1B\n).', 'As depicted in \nFIG.', '2A\n, for the radially contracted state of the isolation assembly \n175\n, the sleeve \n207\n generally has two axial segments that are associated with different outer cross-sections: an expanded section \n258\n, which contains an expansion member \n252\n of an expansion tool \n250\n; and a contracted section \n260\n, which is the part of the assembly \n175\n that is radially expanded by the expansion tool \n252\n to anchor the assembly \n175\n to the wall of the tubing string \n120\n.', 'The overall outer dimension (outer diameter, for example) of the expanded section \n258\n is sufficiently small enough to pass through the tubing string \n120\n to allow the isolation assembly \n175\n to be run downhole.', 'The isolation assembly \n175\n includes one or multiple anchor members \n230\n (multiple anchor members \n130\n for the example implementations depicted in the figures) and a seal element \n240\n.', 'The anchor members \n230\n and the seal element \n240\n circumscribe the section \n260\n of the sleeve \n207\n and circumscribe the longitudinal axis \n201\n.', 'The overall outer dimension (outer diameter, for example) of the isolation assembly \n175\n at the anchor members \n230\n and at the seal element \n240\n is sufficiently small enough to allow the isolation assembly \n175\n to pass through the tubing string \n120\n when the assembly \n175\n is run downhole.', 'The contracted segment of the sleeve \n207\n, in accordance with example implementations, is radially expanded by the expansion member \n252\n of the expansion tool \n250\n for purposes of enlarging the inner passageway of the isolation assembly \n175\n, radially extending the anchor members \n230\n to secure the assembly \n175\n to the tubing string wall and radially expanding the seal element \n240\n to form a seal (fluid seal, for example) between the sleeve \n207\n and the tubing string wall.', 'In accordance with example implementations, the anchor member \n230\n may have a profile or surface that is constructed to grip the inner surface of the tubing string \n120\n to secure the isolation assembly \n175\n to the tubing string \n120\n.', 'For example, in accordance with some implementations, the anchor member \n230\n may have a relatively high coefficient of friction (as compared to the inner wall of the tubing string \n120\n, for example) to allow the member \n230\n to secure the isolation assembly \n175\n to the tubing string \n120\n when the member \n230\n is radially pushed against the wall of the string \n120\n.', 'In accordance with some implementations, the anchor member \n230\n may contain pointed surfaces, or “teeth.”', 'The teeth may be constructed of a metal that is relatively harder than the metal of the tubing string \n120\n so that the teeth “bite” into the tubing string wall to anchor the isolation assembly \n175\n to the tubing string \n120\n.', 'In accordance with further example implementations, the anchor member \n230\n may be a slip, similar to a slip used in a packer.', 'In this manner, for these example implementations, the isolation assembly \n175\n may contain thimbles, or collars, which are moved closely axially together due to the expansion of the sleeve \n207\n (or due to actuation by a setting tool, as another example) to cause the anchor members \n230\n (disposed between the thimbles) to radially extend into and engage the tubing string wall.', 'In accordance with example implementations, the seal element \n240\n may be an elastomer ring that radially expands with the sleeve \n207\n to form a fluid tight or near fluid tight seal between the isolation assembly \n175\n and the tubing string \n120\n.', 'Materials other than an elastomer may be used for the seal element \n240\n, in accordance with further example implementations.', 'For example, in accordance with some implementations, the seal element \n240\n may be formed from metal to form a metal-to-metal seal between the isolation assembly \n175\n and the tubing string \n120\n.', 'In accordance with further example implementations, the isolation assembly \n175\n may not have a seal element.', 'As depicted in \nFIG.', '2A\n, in accordance with example implementations, the expansion member \n252\n may be a solid member (a solid right circular cylindrical metal piece, for example) and has an outer diameter that corresponds to the inner diameter of the expanded section \n258\n of the sleeve \n207\n when the isolation assembly \n175\n is run downhole.', 'Moreover, as also shown in \nFIG.', '2A\n, the expansion member \n252\n may be attached to a conveyance mechanism \n254\n (a coiled tubing string, for example) that is used to draw the expansion member \n252\n uphole to radially expand the section \n260\n.', 'In this manner, in accordance with example implementations, the isolation assembly \n175\n may be run downhole on a conveyance mechanism, such as a tubing string \n255\n (\nFIG.', '2B\n), that is attached to the sleeve \n207\n to a target location inside the outer tubing string \n120\n.', 'The conveyance mechanism \n254\n extends inside the tubing string \n255\n.', 'When the isolation assembly \n175\n is in the appropriate position, the conveyance mechanism \n254\n may be pulled uphole to move the expansion member \n252\n through the sleeve \n207\n to deform and radially expand the section \n260\n.', 'In accordance with example implementations, the conveyance mechanism \n254\n may be run downhole with the tubing string \n255\n and may be initially attached (via one or more shear pins, for example) to the string \n255\n during the running of the isolation assembly \n175\n downhole.', 'FIG.', '2B\n depicts the isolation assembly \n175\n in an intermediate state during the radial expansion of the assembly \n175\n.', 'More specifically, \nFIG.', '2B\n depicts the expansion tool \n250\n being moved uphole in a direction \n260\n to cause the corresponding expansion of the sleeve \n207\n.', 'For the state depicted in \nFIG.', '2B\n, the contracted section \n260\n has shortened, and the anchor members \n230\n are extended to grip the wall of the tubing string \n120\n to anchor the isolation assembly \n175\n to the tubing string \n120\n.', 'FIG.', '2C\n depicts the isolation assembly \n175\n in its radially expanded state, after the expansion tool \n250\n has been pulled out of the well, and an activation ball \n150\n has been deployed and landed in the restriction \n205\n.', 'In accordance with example implementations, in its radially expanded state, the seal element \n240\n has been radially expanded to energize the element \n240\n to form a fluid seal between the isolation assembly \n175\n and the tubing string \n120\n.', 'Moreover, as depicted in \nFIG.', '2A\n, in its radially expanded state, the isolation assembly \n175\n has a generally uniform inner cross section, except for the restriction \n205\n at its lower end.', 'In accordance with example implementations, the sleeve \n207\n may be formed from a metal, such as stainless steel or a metal that has less chromium content per mass than stainless steel, such as SAE grade \n4140\n metal.', 'The sleeve \n207\n may be made from other metals or from materials other than metal, in accordance with further example implementations.', 'Although example implementations are described above in which an expansion tool is drawn through the isolation assembly to deform and radially expand the assembly, other tools and techniques may be used to deform and expand the assembly, in accordance with further example implementations.', 'For example, an expansion tool may be pushed through the isolation assembly to deform and expand the assembly.', 'The expansion tool may have an expansion member that is asymmetrical with respect to the longitudinal axis \n201\n of the isolation assembly.', 'Moreover, the isolation assembly may be deformed and expanded using a tool or technique that does not involved mechanically contacting the sleeve \n207\n with an expansion member.', 'For example, in accordance with further example implementations, a setting tool may be used to run the isolation assembly \n175\n downhole and may be constructed to form a temporary and removable seal inside the expanded section \n258\n (see \nFIG.', '2A\n) so that the interior of the sleeve \n207\n may be pressurized (via fluid pumped in from the Earth surface, for example) to cause the contracted section \n260\n to deform and radially expand; and after this expansion, the setting tool may be actuated to remove the temporary seal so that setting tool may be pulled out of the well.', 'As another example, a setting tool may be used to run the isolation assembly \n175\n downhole, may be constructed to form one or multiple temporary and removable seal(s) inside the sleeve \n207\n, and the setting tool may contain a chemical agent (a gas producing agent, for example) that is activated (via an activating agent communicated from the Earth surface of the well or released from the tool in response to the tool being actuated from the Earth surface of the well, as examples), which causes sufficient pressure to build up inside the sleeve \n207\n to deform and radially expand the sleeve \n207\n.', 'The setting tool may then be actuated to remove the temporary seal(s) so that the setting tool may be removed from the well.', 'In accordance with example implementations, the object (such as activation ball \n150\n of \nFIG.', '2C\n) may be removed from the restriction \n205\n of the isolation assembly \n175\n after completion of the downhole operation that uses the corresponding fluid barrier.', 'The removal of the object permits well access downhole of the isolation assembly \n175\n.', 'In accordance with example implementations, the isolation assembly \n175\n may remain in place, secured to the tubing string \n120\n, after the object is removed.', 'In this manner, in accordance with example implementations, the sleeve \n207\n, in the radially expanded state of assembly \n175\n, has a relatively large inner diameter that is close in size to the inner diameter of the tubing string \n120\n, and the restriction \n205\n is sufficiently large enough to allow equipment to pass through.', 'In accordance with some implementations, the sleeve \n207\n and/or the untethered object that is ultimately seated in the sleeve \n207\n may be constructed from a milling material so that a milling tool may be run into the well to mill out the object and/sleeve when the fluid barrier is no longer needed, in accordance with example implementations.', 'In accordance with further example implementations, the object and/or one or more components of the isolation seat assembly \n175\n may be constructed from dissolvable or degradable materials.', 'As an example, dissolvable, or degradable, alloys may be used similar to the alloys that are disclosed in the following patents, which have an assignee in common with the present application and are hereby incorporated by reference: U.S. Pat.', 'No. 7,775,279, entitled, “DEBRIS-FREE PERFORATING APPARATUS AND TECHNIQUE,” which issued on Aug. 17, 2010; and U.S. Pat.', 'No. 8,211,247, entitled, “DEGRADABLE COMPOSITIONS, APPARATUS COMPOSITIONS COMPRISING SAME, AND METHOD OF USE,” which issued on Jul. 3, 2012.', 'In accordance with an example implementation, the object may be constructed from a dissolvable or degradable material that is constructed to sufficiently dissolve/degrade after a certain time (a week, several weeks, a month, several months, and so forth) to purposefully compromise the structural integrity of the object so that the object collapses or otherwise loses its ability to be retained in the restriction \n205\n so that the object falls out of the restriction \n205\n.', 'In accordance with an example implementation, one or more of the anchor members \n230\n may be constructed from a dissolvable or degradable material that is constructed to sufficiently dissolve/degrade after a certain time to compromise the ability of the anchor members \n230\n to secure the isolation assembly \n175\n to the wall of the tubing string \n120\n so that the assembly \n175\n releases from the string \n120\n.', 'Although implementations are discussed herein in which the isolation assembly \n175\n may be used as a fracturing plug assembly to form a fluid barrier for a well stimulation operation, the isolation assembly \n175\n may be used to form a fluid barrier for downhole operations, other than well stimulation operations.', 'For example, the isolation assembly \n175\n may be used to form a fluid barrier to pressurize a fluid column for such purposes as firing a tubing conveyed pressure (TCP) perforating gun; actuating a downhole tool; shifting a sleeve valve; and so forth.', 'Therefore, in general, the isolation assembly \n175\n may be used for a wide variety of downhole operations, such as shifting a downhole operator; diverting fluid; forming a downhole obstruction; operating a tool; and so forth.', 'Although implementations are discussed herein in which the expansion tool and isolation assembly \n175\n are run, or deployed, downhole as a unit, in accordance with further example implementations, the setting tool and isolation assembly may be run downhole separately.', 'Referring to \nFIG.', '3A\n, to summarize, in accordance with example implementations, a technique \n300\n includes deploying (block \n304\n) an isolation assembly into a tubing string that has been previously installed in a well.', 'The isolation assembly is deformed (block \n306\n) at a downhole location in the well to secure the assembly to the tubing string.', 'Pursuant to the technique \n300\n, an object may be received (block \n308\n) in a restriction of the isolation assembly; and the received object may then be used (block \n312\n) in the isolation assembly to perform a downhole operation in the well.', 'In this context of this application, “deforming the isolation assembly” refers to distorting at least one component of the isolation assembly.', 'Depending on the particular implementation, this distortion may involve radially expanding the component(s), radially contracting the component(s), and as well as other distortions of the component(s).', 'As described above, in accordance with some implementations, a sleeve of the isolation assembly is deformed, and a restriction of the sleeve is used to catch an object to form a fluid barrier.', 'More specifically, referring to \nFIG.', '3B\n, in accordance with example implementations, a technique \n330\n includes deploying (block \n334\n) an isolation assembly into a tubing string that has been previously installed in a well.', 'The technique \n330\n includes radially expanding (block \n336\n) a sleeve of the isolation assembly at a target downhole location in the well to cause the isolation assembly to engage the tubing string.', 'An object is received (block \n338\n) in a restriction of the sleeve, and the received object may then be used (block \n340\n) to form a fluid barrier in the tubing string.', 'In accordance with further example implementations, the sleeve of the isolation assembly may contain features that enhance the anchoring of the assembly to the tubing string wall.', 'These anchoring features may be used in lieu of a separate anchoring member of the isolation assembly (i.e., an anchoring member separate from the sleeve) or in conjunction with a separate anchoring member, depending on the particular implementation.', 'Referring to \nFIG.', '4A\n, as a more specific example, in accordance with further example implementations, an isolation assembly may include a sleeve and “bumps,” or protuberances \n402\n, that are distributed about the outside of the sleeve \n400\n.', 'The protuberances \n402\n serve as anchoring members to enhance the gripping of the sleeve \n400\n to the tubing member \n120\n when the sleeve \n400\n is expanded.', 'Referring to \nFIG.', '4B\n, in accordance with further example implementations, an isolation assembly may include a sleeve \n410\n and slip rings \n414\n that circumscribe the sleeve \n410\n.', 'The slip ring \n414\n has teeth that penetrate into the tubing string \n120\n to anchor the isolation assembly to the string \n120\n when the sleeve \n410\n is expanded.', 'Referring to \nFIG.', '4C\n, in accordance with further example implementations, the sleeve \n420\n may be a slotted tubing.', "In this manner, slots \n422\n of the sleeve \n420\n enhance the sleeve's \n420\n deformation such that the sleeve \n420\n, when expanded, conforms to the tubing string \n120\n to anchor the isolation assembly in place.", 'Referring to \nFIG.', '4D\n, in accordance with further example implementations, an isolation assembly may include a sleeve \n430\n that has protuberances \n434\n that are distributed about the outside of the sleeve \n430\n.', 'As depicted in \nFIG.', '4D\n, the protuberance \n434\n may have teeth \n436\n to enhance the anchoring of isolation to the tubing string \n120\n.', 'Referring to \nFIG.', '5\n, in accordance with further example implementations, a sleeve \n506\n of an isolation assembly may have a frustoconical surface \n507\n, which circumscribes a longitudinal axis \n501\n of the sleeve \n506\n.', 'As depicted in \nFIG.', '5\n, the frustoconical surface \n507\n is directed uphole so that a slightly larger frustoconical surface \n505\n of a lower member \n504\n of a setting tool \n500\n may be forced inside the sleeve \n506\n to expand the sleeve \n506\n.', 'In accordance with further example implementations, a sleeve may have a frustoconical surface similar to the frustoconical surface \n507\n, except that the frustoconical surface of this sleeve is facing downhole.', 'In this manner, a setting tool having a frustoconical surface that faces uphole may be run downhole with the sleeve so that the setting tool may be pulled into the sleeve to expand the sleeve.', 'In accordance with further example implementations, instead of forming an object catching restriction in the sleeve, the isolation assembly may include a seat and a sleeve; and a setting tool assembly may be constructed to wedge the sleeve between the seat and the tubing string for purposes of anchoring the seat in place inside the tubing string.', 'In this manner, the seat and sleeve may be mounted to the setting tool and run into the well as a unit with the setting tool.', 'When at the target downhole location, the setting tool may be constructed to hold one of the seat and sleeve components in place while the setting tool applies a force to axially translate the other component to push the seat and sleeve together to wedge the sleeve between the seat and tubing string wall for purposes of anchoring the isolation assembly in place.', 'As a more specific example, \nFIG.', '6A\n depicts an isolation assembly \n600\n that is run downhole on a setting tool \n630\n in accordance some implementations.', 'The isolation assembly \n600\n includes a tubular seat member \n610\n and a sleeve member \n614\n, which both circumscribe the longitudinal axis \n201\n of the tubing string \n120\n.', 'FIG.', '6A\n depicts the isolation assembly \n600\n in its run-in-hole state, a state in which the sleeve member \n614\n is mounted on the setting tool \n630\n uphole of the seat member \n610\n.', 'The setting tool \n630\n contains components to push the seat component \n610\n and the sleeve component \n614\n together when the isolation assembly \n600\n is at the target downhole location for forming the fluid barrier: a tension mandrel \n631\n that extends along the longitudinal axis \n201\n; and a sleeve member \n650\n that circumscribes the tension mandrel \n631\n.', 'As depicted in \nFIG.', '6A\n, in accordance with some implementations, the setting tool tension mandrel \n631\n may include an enlarged lower, or downhole, end \n632\n, which extends into an opening \n611\n of the seat member \n610\n for purposes of engaging the seat member \n610\n so that an axial force may be applied to the sleeve member \n614\n to translate the sleeve member \n614\n along the longitudinal axis \n201\n toward the seat member \n610\n to force the sleeve member \n614\n over and radially outside of the seat member \n610\n.', 'More specifically, referring to \nFIG.', '6B\n, the setting tool \n630\n may be actuated to cause the setting tool sleeve member \n650\n to contact an upper, or uphole end \n619\n of the sleeve member \n614\n to exert an axially-directed force \n654\n against the sleeve member \n614\n to axially translate the sleeve member \n614\n.', 'This axial translation causes a lower, or downhole, end \n615\n of the sleeve member \n614\n to radially expand and be forced, or wedged, inside the annular space between the seat member \n610\n and the tubing string wall.', 'As an example, the setting tool \n630\n may contain a downhole actuator (not shown) that is constructed to be actuated from the Earth surface to pull the tension mandrel \n631\n in an uphole direction, relative to the sleeve member \n650\n of the tool \n630\n.', 'In accordance with some implementations, an upper end \n609\n of the seat member \n610\n may have an inclined, or beveled, surface for purposes of facilitating the radial expansion of the sleeve member \n614\n.', 'In accordance with some implementations, the lower end \n632\n of the setting tool \n630\n may be engaged to the seat member \n610\n using one or more shear pins (not shown) so that after sufficient force to wedge the sleeve member \n614\n between the seat member \n610\n and the tubing string wall is exerted, the shear pins shear to release the setting tool tension mandrel \n631\n from the seat member \n610\n.', 'This allows the setting tool \n630\n to be removed from the well.\n \nFIG.', '6C\n depicts the isolation assembly \n600\n in its fully set state and further depicts an untethered object, such as an activation ball \n670\n, being seated in the seat \n613\n of the seat member \n610\n.', 'As depicted in \nFIG.', '6C\n, the sleeve member \n614\n is wedged between the seat member \n610\n and the wall of the tubing string \n120\n.', 'In accordance with example implementations, the sleeve member \n614\n creates a fluid seal between the seat member \n610\n and the tubing string wall; and the wedge formed from the sleeve member \n614\n anchors the seat member \n610\n to the tubing string \n120\n to prevent the isolation assembly \n600\n from moving.', 'In accordance with further example implementations, an isolation assembly may include a seat and a sleeve, which are run downhole on a setting tool, with the seat being mounted to the setting tool uphole of the sleeve.', 'As a more specific example, \nFIG.', '7A\n depicts an isolation assembly \n700\n that includes a seat member \n714\n that is run downhole on a setting tool \n730\n uphole of a sleeve member \n710\n of the isolation assembly \n700\n.', 'In this manner, as depicted in \nFIG.', '7A\n, the sleeve member \n710\n is secured to a setting tension mandrel \n731\n of a setting tool \n730\n.', 'The sleeve member \n710\n includes an opening \n711\n that receives a downhole end \n732\n of the setting tool tension mandrel \n731\n.', 'In the run-in-hole state of the isolation assembly \n700\n, which is depicted in \nFIG.', '7A\n, the seat member \n714\n has not been pushed into the sleeve member \n710\n to facilitate running of the isolation assembly \n700\n into the well.', 'As also shown in \nFIG.', '7A\n, the setting tool \n730\n includes a sleeve member \n750\n for purposes exerting an axial force on the sleeve member \n714\n to axially translate the sleeve member \n714\n and force the sleeve member \n714\n into an interior space \n709\n of the sleeve member \n710\n.\n \nFIG.', '7B\n depicts actuation of the setting tool \n730\n in which the setting tool \n730\n moves the sleeve member \n750\n in a downhole direction relative to the tension mandrel \n731\n to exert an axial force \n754\n on the seat member \n714\n of the isolation assembly \n700\n.', 'The axial force \n734\n pushes the seat member \n714\n toward the sleeve member \n710\n to force a lower, or downhole end \n717\n of the seat member \n714\n into the interior space \n709\n of the sleeve member \n710\n.', 'During the application of the force \n754\n, the setting tool tension mandrel \n731\n holds, or secures, the sleeve member \n710\n, as shown in \nFIG.', '7B\n.', 'Similar to the isolation assembly \n600\n and setting tool \n630\n depicted in connection with \nFIGS.', '6A, 6B and 6C\n, the setting tool tension mandrel \n731\n may be secured to the sleeve member \n710\n via one or more shear pins.', 'By forcing the seat member \n714\n inside the sleeve member \n710\n, an upper, or uphole end \n713\n of the sleeve member \n710\n extends in the annular space between the seat member \n714\n and tubing string wall to form a wedge to secure, or anchor, the seat member \n714\n in place.\n \nFIG.', '7C\n depicts the isolation assembly \n700\n in its fully set state and further depicts a seat \n715\n of the seat member \n714\n receiving an untethered object, such as an actuation ball \n770\n, to form a fluid barrier inside the tubing string \n120\n.', 'Similar to the isolation assemblies described above, one or multiple components of the isolation assemblies \n600\n and \n700\n depicted in \nFIGS.', '6A-7C\n may be formed from degradable or dissolvable materials.', 'Moreover, one or more components of these assemblies \n600\n and \n700\n may be formed from millable materials.', 'Thus, referring to \nFIG.', '8A\n, in accordance with example implementations, a technique \n800\n includes deploying (block \n804\n) an isolation assembly and a setting tool into a tubing string that was previously installed in a well.', 'At a target downhole location, a sleeve of the isolation assembly, which is mounted to the setting tool uphole of a seat of the isolation assembly is pushed (block \n806\n) into the seat to radially expand the sleeve and wedge the sleeve between the seat and the tubing string to secure the assembly to the tubing string.', 'Pursuant to block \n808\n, an object may then be received in the seat, and the received object may be used in the isolation assembly to form a fluid barrier in the tubing string, pursuant to block \n812\n.', 'Referring to \nFIG.', '8B\n, in accordance with further example implementations, a technique \n840\n may include deploying (block \n844\n) an isolation assembly and a setting tool into a tubing string that was previously installed in a well.', 'At a target downhole location, a seat of the isolation assembly, which is mounted to the setting tool uphole of a sleeve of the isolation assembly is pushed (block \n846\n) into the sleeve to radially expand the sleeve and wedge the sleeve between the seat and the tubing string.', 'An object may then be received in the seat, pursuant to block \n848\n; and the received object may be used (block \n852\n) to form a fluid barrier in the tubing string.', 'While the present invention has been described with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom.', 'It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of this present invention.'] | ['1.', 'A method comprising:\ndeploying an isolation assembly into a tubing string previously installed in a well, wherein the isolation assembly comprises a sleeve that is coaxial with a longitudinal axis of the isolation assembly, and wherein the sleeve comprises: an expanded section; a contraction section; and a restriction;\ndeforming the contraction section of the sleeve at a downhole location in the well to secure the isolation assembly to the tubing string, wherein deforming the contraction section of the sleeve comprises radially expanding the contraction section of the sleeve of the isolation assembly in an uphole direction to cause an anchor member of the isolation assembly to radially extend to engage the tubing string, and wherein, prior to deforming the contraction section of the sleeve, the anchor member of the isolation assembly does not engage the tubing string;\nreceiving an object in the restriction of the sleeve after radially expanding the contraction section of the sleeve; and\nusing the received object to perform a downhole operation as the sleeve remains in the well.', '2.', 'The method of claim 1, wherein using the received object in the isolation assembly to perform the downhole operation comprises performing an operation selected from the group consisting essentially of shifting a downhole operator; diverting fluid; forming a downhole obstruction; and operating a tool.', '3.', 'The method of claim 1, wherein deforming the contraction section of the sleeve further comprises:\ndrawing an expander through the sleeve of the isolation assembly to radially expand the contraction section of the sleeve.', '4.', 'The method of claim 1, wherein the object comprises an untethered object, the method further comprising:\ndeploying the untethered object through a passageway of the string to cause the untethered object to travel through the passageway and land in the restriction of the isolation assembly.', '5.', 'The method of claim 1, further comprising:\nexpanding a seal element of the isolation assembly in response to deforming the contraction section of the sleeve to form a fluid seal between the isolation assembly and the tubing string.', '6.', 'The method of claim 1, wherein deforming the contraction section of the sleeve of the isolation assembly further comprises:\nmechanically deforming the contraction section of the sleeve, deforming the contraction section of the sleeve using a chemical reaction, or applying pressure to deform the contraction section of the sleeve.', '7.', 'The method of claim 1, wherein deforming the contraction section of the sleeve further comprises:\nradially expanding the contraction section of the sleeve to form a wedge between a seat member of the isolation assembly and a wall of the tubing string.', '8.', 'The method of claim 7, wherein:\nthe isolation assembly is deployed into the tubing string on a setting tool such that the sleeve and the seat member are mounted on the setting tool, and the sleeve is mounted to the setting tool uphole of the seat member; and\nradially expanding the contraction section of the sleeve comprises actuating the setting tool to push the sleeve and the seat member together.', '9.', 'The method of claim 7, wherein:\nthe isolation assembly is deployed into the tubing string on a setting tool such that the sleeve and the seat member are mounted on the setting tool, and the seat member is mounted to the setting tool uphole of the sleeve; and\nradially expanding the contraction section of the sleeve comprises actuating the setting tool to push the sleeve and the seat member together.', '10.', 'An apparatus usable with a well, comprising:\na tubular assembly having a radially contracted state, the tubular assembly comprising: a sleeve; and a restriction adapted to catch an object deployed into the well to form a fluid barrier when caught by the restriction; and\nan expansion tool to be deployed downhole with the tubular assembly inside a tubing string, the expansion tool being adapted to radially expand the sleeve of the tubular assembly inside the tubing string in an uphole direction to anchor the expanded sleeve to the tubing string via at least one anchoring member disposed on an exterior of the sleeve,\nwherein the at least one anchoring member does not engage the tubing string prior to radial expansion of the sleeve of the tubular assembly, and\nwherein the restriction is adapted to catch the object deployed into the well after radial expansion of the sleeve and removal of the expansion tool.', '11.', 'The apparatus of claim 10, wherein the at least one anchor member comprises a slip.\n\n\n\n\n\n\n12.', 'The apparatus of claim 10, wherein the at least one anchor member comprises teeth to engage the wall of the tubing string, and wherein the sleeve of the tubular assembly comprises a first section that is contracted for a run-in-hole state of the apparatus and a second section that is expanded for the run-in-hole state of the apparatus.', '13.', 'The apparatus of claim 10, further comprising a conveyance mechanism to deploy the expansion tool and tubular assembly downhole.', '14.', 'The apparatus of claim 13, wherein the expansion tool is adapted to be drawn through the tubular assembly using the conveyance mechanism to deform the sleeve to radially expand the sleeve.', '15.', 'The apparatus of claim 10, further comprising:\na seal element to form a fluid seal between the tubular assembly and the tubing string in response to the radial expansion of the tubular assembly.\n\n\n\n\n\n\n16.', 'The apparatus of claim 10, wherein the restriction comprises a seat having a contoured surface to complement a contoured surface of the object.', '17.', 'The apparatus of claim 16, wherein the seat is adapted to catch a ball, dart, or barrel.', '18.', 'The apparatus of claim 10, wherein the tubular assembly further comprises a seat member, wherein the expansion tool is adapted to exert a force to wedge the sleeve between the seat member and the tubing string to anchor the seat member to the tubing string, and wherein the seat member comprises the restriction.', '19.', 'A system usable with a well, comprising:\na casing string to support a wellbore, wherein the casing string has a central passageway and the wellbore has multiple stages;\nan isolation assembly to be deployed in the central passageway of the casing string to form an isolation barrier for a given stage of the multiple stages, the isolation assembly comprising: a tubular assembly having a radially contracted state, the tubular assembly comprising a restriction adapted to catch an object deployed into the well to form a fluid barrier when caught by the restriction, wherein, in the radially contracted state, the tubular assembly comprises an expanded section and a contracted section; and at least one anchor member;\nan expansion tool to be deployed downhole with the tubular assembly inside a tubing string; and\na conveyance mechanism to deploy the expansion tool and the tubular assembly downhole,\nwherein the expansion tool is adapted to be drawn through the tubular assembly using the conveyance mechanism to deform the contracted section of the tubular assembly to radially expand the tubular assembly in an uphole direction inside the tubing string to anchor the expanded tubular assembly to the tubing string via the at least one anchor member,\nwherein the at least one anchor member of the isolation assembly does not engage the tubing string prior to usage of the conveyance mechanism and the expansion tool, and\nwherein the restriction is adapted to catch the object deployed into the well after radial expansion of the tubular assembly and removal of the expansion tool.', '20.', 'The system of claim 19, wherein:\nthe isolation assembly comprises a fracturing plug assembly.', '21.', 'The system of claim 19, further comprising:\nwherein the tubular assembly comprises: a sleeve having the contracted section, which is contracted for running the tubular assembly downhole in the central passageway of the casing string, and the expanded section, which is expanded for running the tubular assembly downhole in the central passageway of the casing string; and\nthe at least one anchor member is disposed on the sleeve on the contracted section to anchor the expanded tubular assembly to the tubing string.'] | ['FIG.', '1A a schematic diagram of a well according to an example implementation.', ';', 'FIG.', '1B is a schematic diagram of the well of FIG.', '1A illustrating the formation of a fluid barrier downhole in a tubing string of the well and the use of the fluid barrier in a stimulation operation conducted in an isolated stage of the well according to an example implementation.', '; FIG.', '2A is a schematic diagram illustrating an isolation assembly in its radially contracted state according to an example implementation.', ';', 'FIG.', '2B is a schematic diagram illustrating the isolation assembly of FIG.', '2A during the radial expansion of the assembly according to an example implementation.; FIG.', '2C is a schematic diagram of the isolation assembly of FIG.', '2A illustrating the isolation assembly in its radially expanded state according to an example implementation.;', 'FIGS.', '3A, 3B, 8A and 8B are flow diagrams depicting techniques to form and use a fluid barrier constructed from a deformable isolation assembly according to example implementations.;', 'FIGS.', '4A, 4B, 4C and 4D depict sleeves and anchoring members for an isolation assembly according to example implementations.; FIG. 5 depicts a cross-sectional view of a setting tool mandrel and a sleeve of an isolation assembly according to a further example implementation.', '; FIG.', '6A is a schematic diagram illustrating an isolation assembly in its radially contracted state according to a further example implementation.', '; FIG.', '6B is a schematic diagram illustrating the isolation assembly of FIG.', '6A during the radial expansion of the assembly according to an example implementation.;', 'FIG.', '6C is a schematic diagram of the isolation assembly of FIG.', '6A illustrating the isolation assembly in its radially expanded state according to an example implementation.', ';', 'FIG.', '7A is a schematic diagram illustrating an isolation assembly in its radially contracted state according to a further example implementation.', '; FIG.', '7B is a schematic diagram illustrating the isolation assembly of FIG.', '7A during the radial expansion of the assembly according to an example implementation.; FIG.', '7C is a schematic diagram of the isolation assembly of FIG.', '7A illustrating the isolation assembly in its radially expanded state according to an example implementation.; FIG.', '1A depicts that fluid communication with the surrounding hydrocarbon formation(s) has been enhanced through sets 140 of perforation tunnels that, for this example, are formed in each stage 130 and extend through the tubing string 120.', 'It is noted that each stage 130 may have multiple sets of such perforation tunnels 140.', 'Although perforation tunnels 140 are depicted in FIG.', '1A, it is understood that other techniques other than perforating may be used to establish/enhance fluid communication with the surrounding formation (s).', 'For example, the fluid communication may be alternatively established/enhanced by jetting an abrasive fluid using a jetting tool; opening sleeve valves of the tubing string 120; and so forth.', 'One or more multiple stage stimulation operations may be performed after such operations.', 'In accordance with further example implementations, the multiple stage stimulation operation(s) may be performed without first perforating or jetting.; FIG.', '2B depicts the isolation assembly 175 in an intermediate state during the radial expansion of the assembly 175.', 'More specifically, FIG.', '2B depicts the expansion tool 250 being moved uphole in a direction 260 to cause the corresponding expansion of the sleeve 207.', 'For the state depicted in FIG.', '2B, the contracted section 260 has shortened, and the anchor members 230 are extended to grip the wall of the tubing string 120 to anchor the isolation assembly 175 to the tubing string 120.; FIG.', '2C depicts the isolation assembly 175 in its radially expanded state, after the expansion tool 250 has been pulled out of the well, and an activation ball 150 has been deployed and landed in the restriction 205.', 'In accordance with example implementations, in its radially expanded state, the seal element 240 has been radially expanded to energize the element 240 to form a fluid seal between the isolation assembly 175 and the tubing string 120.', 'Moreover, as depicted in FIG.', '2A, in its radially expanded state, the isolation assembly 175 has a generally uniform inner cross section, except for the restriction 205 at its lower end.', '; FIG.', '6C depicts the isolation assembly 600 in its fully set state and further depicts an untethered object, such as an activation ball 670, being seated in the seat 613 of the seat member 610.', 'As depicted in FIG.', '6C, the sleeve member 614 is wedged between the seat member 610 and the wall of the tubing string 120.', 'In accordance with example implementations, the sleeve member 614 creates a fluid seal between the seat member 610 and the tubing string wall; and the wedge formed from the sleeve member 614 anchors the seat member 610 to the tubing string 120 to prevent the isolation assembly 600 from moving.; FIG.', '7B depicts actuation of the setting tool 730 in which the setting tool 730 moves the sleeve member 750 in a downhole direction relative to the tension mandrel 731 to exert an axial force 754 on the seat member 714 of the isolation assembly 700.', 'The axial force 734 pushes the seat member 714 toward the sleeve member 710 to force a lower, or downhole end 717 of the seat member 714 into the interior space 709 of the sleeve member 710.', 'During the application of the force 754, the setting tool tension mandrel 731 holds, or secures, the sleeve member 710, as shown in FIG.', '7B.', 'Similar to the isolation assembly 600 and setting tool 630 depicted in connection with FIGS.', '6A, 6B and 6C, the setting tool tension mandrel 731 may be secured to the sleeve member 710 via one or more shear pins.', 'By forcing the seat member 714 inside the sleeve member 710, an upper, or uphole end 713 of the sleeve member 710 extends in the annular space between the seat member 714 and tubing string wall to form a wedge to secure, or anchor, the seat member 714 in place.', '; FIG.', '7C depicts the isolation assembly 700 in its fully set state and further depicts a seat 715 of the seat member 714 receiving an untethered object, such as an actuation ball 770, to form a fluid barrier inside the tubing string 120.'] |
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US11144567 | Dynamic schema transformation | Nov 30, 2018 | Lucas Natraj, Hrvoje Markovic | Schlumberger Technology Corporation | International Search Report and Written Opinion for the counterpart International patent appliction PCT/US2019/063265 dated Mar. 20, 2020.; International Preliminary Report on Patentability for the counterpart International patent appliction PCT/US2019/063265 dated Jun. 10, 2021. | 7225411; May 29, 2007; Stoner et al.; 10120913; November 6, 2018; Mullins; 20020069192; June 6, 2002; Aegerter; 20020180755; December 5, 2002; Krueger; 20030217069; November 20, 2003; Fagin et al.; 20040034615; February 19, 2004; Thomson; 20040093344; May 13, 2004; Berger et al.; 20040181543; September 16, 2004; Wu; 20050060647; March 17, 2005; Doan; 20080021912; January 24, 2008; Seligman et al.; 20080046491; February 21, 2008; Gupta; 20090106285; April 23, 2009; Cheung et al.; 20090235185; September 17, 2009; Gill; 20110246415; October 6, 2011; Li; 20150012553; January 8, 2015; Hazelwood et al.; 20160092527; March 31, 2016; Kang et al.; 20170031958; February 2, 2017; Miller; 20180246912; August 30, 2018; Arning | Foreign Citations not found. | ['Dynamic schema transformation that involves a target schema that is determined from a request.', 'A set of transformations is identified between a set of source schemas and the target schema.', 'A set of source entities that correspond to the set of source schemas is received.', 'The set of source entities is converted to a set of target entities by applying the sets of transformations to the set of source entities.', 'A reply is presented that comprises target data from the set of target entities.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThere are several stages within the lifespan of the Exploration & Production (E&P) process for acquiring subsurface minerals.', 'The several stages may span several years and involve several companies, people, and software.', 'The various companies, people, and software may use different terminology for the same concepts, such as ‘wells’, ‘logs’, ‘faults’, ‘horizons’, etc.', 'The multiple ways of describing the semantically similar terminology introduces a significant problem when data from disparate sources are ingested into a common data storage or space.', 'Specifically, queries and calculations may be incomplete when data is discarded because the data did not match the expected format or schema.', 'A challenge exists in acquiring data from multiple data sources that use multiple schemas.', 'SUMMARY\n \nIn general, in one or more aspects, the disclosure relates to dynamic schema transformation.', 'A target schema is determined from a request.', 'A set of transformations is identified between a set of source schemas and the target schema.', 'A set of source entities that correspond to the set of source schemas is received.', 'The set of source entities is converted to a set of target entities by applying the sets of transformations to the set of source entities.', 'A reply is presented that comprises target data from the set of target entities.', 'Other aspects of the disclosure will be apparent from the following description and the appended claims.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nFIG.', '1\n shows a diagram of a system in accordance with disclosed embodiments.\n \nFIGS.', '2.1, 2.2, 2.3, 2.4, and 2.5\n show diagrams of a system in accordance with disclosed embodiments.', 'FIGS.', '3, 4, and 5\n, show flowcharts in accordance with disclosed embodiments.', 'FIGS.', '6.1, 6.2, 6.3, 6.4, and 6.5\n show an example in accordance with disclosed embodiments.', 'FIGS.', '7.1 and 7.2\n show computing systems in accordance with disclosed embodiments.', 'DETAILED DESCRIPTION\n \nSpecific embodiments of the disclosure will now be described in detail with reference to the accompanying figures.', 'Like elements in the various figures are denoted by like reference numerals for consistency.', 'In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure.', 'However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details.', 'In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.', 'Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application).', 'The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as by the use of the terms “before”, “after”, “single”, and other such terminology.', 'Rather, the use of ordinal numbers is to distinguish between the elements.', 'By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.', 'In general, embodiments are directed to analyzing data using dynamic schema transformation.', 'The system maintains data in entities that are defined according to multiple different schemas.', 'Transformations are defined between different schemas that allow for converting entities stored according to one schema to be processed according to another schema.', 'After converting the entities to a common schema, the data can be filtered, searched, and processed.\n \nFIG.', '1\n depicts a schematic view, partially in cross section, of an onshore field (\n101\n) and an offshore field (\n102\n) in which one or more embodiments may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in \nFIG.', '1\n may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments should not be considered limited to the specific arrangement of modules shown in \nFIG.', '1\n.', 'As shown in \nFIG.', '1\n, the fields (\n101\n), (\n102\n) include a geologic sedimentary basin (\n106\n), wellsite systems (\n192\n), (\n193\n), (\n195\n), (\n197\n), wellbores (\n112\n), (\n113\n), (\n115\n), (\n117\n), data acquisition tools (\n121\n), (\n123\n), (\n125\n), (\n127\n), surface units (\n141\n), (\n145\n), (\n147\n), well rigs (\n132\n), (\n133\n), (\n135\n), production equipment (\n137\n), surface storage tanks (\n150\n), production pipelines (\n153\n), and an exploration and production (E&P) computer system (\n180\n) connected to the data acquisition tools (\n121\n), (\n123\n), (\n125\n), (\n127\n), through communication links (\n171\n) managed by a communication relay (\n170\n).', 'The geologic sedimentary basin (\n106\n) contains subterranean formations.', 'As shown in \nFIG.', '1\n, the subterranean formations may include several geological layers (\n106\n-\n1\n through \n106\n-\n6\n).', 'As shown, the formation may include a basement layer (\n106\n-\n1\n), one or more shale layers (\n106\n-\n2\n, \n106\n-\n4\n, \n106\n-\n6\n), a limestone layer (\n106\n-\n3\n), a sandstone layer (\n106\n-\n5\n), and any other geological layer.', 'A fault plane (\n107\n) may extend through the formations.', 'In particular, the geologic sedimentary basin includes rock formations and may include at least one reservoir including fluids, for example the sandstone layer (\n106\n-\n5\n).', 'In one or more embodiments, the rock formations include at least one seal rock, for example, the shale layer (\n106\n-\n6\n), which may act as a top seal.', 'In one or more embodiments, the rock formations may include at least one source rock, for example the shale layer (\n106\n-\n4\n), which may act as a hydrocarbon generation source.', 'The geologic sedimentary basin (\n106\n) may further contain hydrocarbon or other fluids accumulations associated with certain features of the subsurface formations.', 'For example, accumulations (\n108\n-\n2\n), (\n108\n-\n5\n), and (\n108\n-\n7\n) associated with structural high areas of the reservoir layer (\n106\n-\n5\n) and containing gas, oil, water or any combination of these fluids.', 'In one or more embodiments, data acquisition tools (\n121\n), (\n123\n), (\n125\n), and (\n127\n), are positioned at various locations along the field (\n101\n) or field (\n102\n) for collecting data from the subterranean formations of the geologic sedimentary basin (\n106\n), referred to as survey or logging operations.', 'In particular, various data acquisition tools are adapted to measure the formation and detect the physical properties of the rocks, subsurface formations, fluids contained within the rock matrix and the geological structures of the formation.', 'For example, data plots (\n161\n), (\n162\n), (\n165\n), and (\n167\n) are depicted along the fields (\n101\n) and (\n102\n) to demonstrate the data generated by the data acquisition tools.', 'Specifically, the static data plot (\n161\n) is a seismic two-way response time.', 'Static data plot (\n162\n) is core sample data measured from a core sample of any of subterranean formations (\n106\n-\n1\n to \n106\n-\n6\n).', 'Static data plot (\n165\n) is a logging trace, referred to as a well log.', 'Production decline curve or graph (\n167\n) is a dynamic data plot of the fluid flow rate over time.', 'Other data may also be collected, such as historical data, analyst user inputs, economic information, and/or other measurement data and other parameters of interest.', 'The acquisition of data shown in \nFIG.', '1\n may be performed at various stages of planning a well.', 'For example, during early exploration stages, seismic data (\n161\n) may be gathered from the surface to identify possible locations of hydrocarbons.', 'The seismic data may be gathered using a seismic source that generates a controlled amount of seismic energy.', 'In other words, the seismic source and corresponding sensors (\n121\n) are an example of a data acquisition tool.', 'An example of seismic data acquisition tool is a seismic acquisition vessel (\n141\n) that generates and sends seismic waves below the surface of the earth.', 'Sensors (\n121\n) and other equipment located at the field may include functionality to detect the resulting raw seismic signal and transmit raw seismic data to a surface unit (\n141\n).', 'The resulting raw seismic data may include effects of seismic wave reflecting from the subterranean formations (\n106\n-\n1\n to \n106\n-\n6\n).', 'After gathering the seismic data and analyzing the seismic data, additional data acquisition tools may be employed to gather additional data.', 'Data acquisition may be performed at various stages in the process.', 'The data acquisition and corresponding analysis may be used to determine where and how to perform drilling, production, and completion operations to gather downhole hydrocarbons from the field.', 'Generally, survey operations, wellbore operations and production operations are referred to as field operations of the field (\n101\n) or (\n102\n).', 'These field operations may be performed as directed by the surface units (\n141\n), (\n145\n), (\n147\n).', 'For example, the field operation equipment may be controlled by a field operation control signal that is sent from the surface unit.', 'Further as shown in \nFIG.', '1\n, the fields (\n101\n) and (\n102\n) include one or more wellsite systems (\n192\n), (\n193\n), (\n195\n), and (\n197\n).', 'A wellsite system is associated with a rig or a production equipment, a wellbore, and other wellsite equipment configured to perform wellbore operations, such as logging, drilling, fracturing, production, or other applicable operations.', 'For example, the wellsite system (\n192\n) is associated with a rig (\n132\n), a wellbore (\n112\n), and drilling equipment to perform drilling operation (\n122\n).', 'In one or more embodiments, a wellsite system may be connected to a production equipment.', 'For example, the well system (\n197\n) is connected to the surface storage tank (\n150\n) through the fluids transport pipeline (\n153\n).', 'In one or more embodiments, the surface units (\n141\n), (\n145\n), and (\n147\n), are operatively coupled to the data acquisition tools (\n121\n), (\n123\n), (\n125\n), (\n127\n), and/or the wellsite systems (\n192\n), (\n193\n), (\n195\n), and (\n197\n).', 'In particular, the surface unit is configured to send commands to the data acquisition tools and/or the wellsite systems and to receive data therefrom.', 'In one or more embodiments, the surface units may be located at the wellsite system and/or remote locations.', 'The surface units may be provided with computer facilities (e.g., an E&P computer system) for receiving, storing, processing, and/or analyzing data from the data acquisition tools, the wellsite systems, and/or other parts of the field (\n101\n) or (\n102\n).', 'The surface unit may also be provided with, or have functionality for actuating, mechanisms of the wellsite system components.', 'The surface unit may then send command signals to the wellsite system components in response to data received, stored, processed, and/or analyzed, for example, to control and/or optimize various field operations described above.', 'In one or more embodiments, the surface units (\n141\n), (\n145\n), and (\n147\n) are communicatively coupled to the E&P computer system (\n180\n) via the communication links (\n171\n).', 'In one or more embodiments, the communication between the surface units and the E&P computer system may be managed through a communication relay (\n170\n).', 'For example, a satellite, tower antenna or any other type of communication relay may be used to gather data from multiple surface units and transfer the data to a remote E&P computer system for further analysis.', 'Generally, the E&P computer system is configured to analyze, model, control, optimize, or perform management tasks of the aforementioned field operations based on the data provided from the surface unit.', 'In one or more embodiments, the E&P computer system (\n180\n) is provided with functionality for manipulating and analyzing the data, such as analyzing seismic data to determine locations of hydrocarbons in the geologic sedimentary basin (\n106\n) or performing simulation, planning, and optimization of exploration and production operations of the wellsite system.', 'In one or more embodiments, the results generated by the E&P computer system may be displayed for user to view the results in a two-dimensional (2D) display, three-dimensional (3D) display, or other suitable displays.', 'Although the surface units are shown as separate from the E&P computer system in \nFIG.', '1\n, in other examples, the surface unit and the E&P computer system may also be combined.', 'The E&P computer system and/or surface unit may correspond to a computing system, such as the computing system shown in \nFIGS.', '7.1 and 7.2\n and described below.', 'FIGS.', '2.1 through 2.5\n show diagrams of one or more embodiments that are in accordance with the disclosure.', 'The various elements, systems, and components shown in \nFIGS.', '2.1 through 2.5\n may be omitted, repeated, combined, and/or altered as shown from \nFIGS.', '2.1 through 2.5\n.', 'Accordingly, the scope of the present disclosure should not be considered limited to the specific arrangements shown in \nFIGS.', '2.1 through 2.5\n.', 'Referring to \nFIG.', '2.1\n, the application (\n202\n) is in communication with the client devices (\n228\n) and the repository (\n212\n).', 'The client devices (\n228\n) interact with the application (\n202\n), which interacts with the repository (\n212\n).', 'The application (\n202\n) is a set of programs that process requests from the client devices (\n228\n).', 'In one or more embodiments, the application (\n202\n) is a web service that is available to the client devices (\n228\n) over the interne or private networks and uses standardized messaging systems and protocols for receiving and transmitting requests.', 'In one or more embodiments, extensible markup language (XML) is used with the simple object access protocol (SOAP) and representational state transfer application programming interfaces (RESTful APIs).', 'In one or more embodiments, JavaScript object notation (JSON) is used to format messages and requests.', 'In one or more embodiments, the application (\n202\n) is a web service that provides searchable access to the data stored in the entities (\n214\n) of the repository (\n212\n).', 'In one or more embodiments, the application (\n202\n) is a distributed application that executes on the application servers (\n204\n).', 'The application servers (\n204\n) include the application server (\n206\n), which is a virtual machine instance that executes one or more of the programs that make up the application (\n202\n).', 'The application server (\n206\n) operates on a physical computing device with processors and memory, such as the computing system (\n600\n) and nodes (\n722\n, \n724\n) described in \nFIGS.', '7.1 and 7.2\n.', 'As another example, the application server may be dedicated hardware and software for executing an application.', 'For example, an application server may be a physical machine.', "By way of another example, the application server may be any computing system, such as a user's local computing system.", 'The application server (\n206\n) hosts programs that include the analyzer engine (\n208\n) and the transformation engine (\n210\n).', 'The analyzer engine (\n208\n) is a program executing on the application server (\n206\n).', 'The analyzer engine (\n208\n) analyzes the data stored in the repository (\n212\n).', 'In one or more embodiments, the analyzer engine (\n208\n) analyzes data (\n240\n) and metadata (\n242\n) in of the entities (\n214\n) and presents results to the client devices (\n228\n).', 'The transformation engine (\n210\n) is a program running on the application server (\n206\n).', 'The transformation engine (\n210\n) executes the transformations (\n224\n) that convert the entities (\n214\n) between the different schemas (\n218\n), which is described further below.', 'The repository (\n212\n) is any type of storage unit and/or device (e.g., a file system, database, collection of tables, or any other storage mechanism) for storing data.', 'Further, the repository (\n212\n) may include multiple different storage units and/or devices.', 'The multiple different storage units and/or devices may or may not be of the same type or located at the same physical site.', 'The repository (\n212\n) stores the entities (\n214\n), the schemas (\n218\n), the graph (\n222\n), the transformations (\n224\n), which are described below in \nFIGS.', '2.2 through 2.5\n.', 'In one or more embodiments, the repository includes multiple graphs.', 'The client devices (\n228\n) include the client device (\n230\n), which is an embodiment of the computer system (\n180\n) of \nFIG.', '1\n and the computing system (\n600\n) of the \nFIG.', '6.1\n.', 'The client devices (\n228\n) communicate with the application (\n202\n) to engage and operate the analyzer engine (\n208\n) and display analyzed information from the entities (\n214\n).', 'The client devices (\n228\n) can display data from the repository (\n212\n), including the entities (\n214\n), the schemas (\n218\n), the graph (\n222\n), the transformations (\n226\n), etc.', 'The client devices (\n228\n) can display the progress of the analyzer engine (\n208\n) and the transformation engine (\n210\n).', 'Referring to \nFIG.', '2.2\n, the entities (\n214\n) include the entity (\n216\n), which includes the entity identifier (\n232\n), the schema identifier (\n234\n), the data (\n240\n), and the metadata (\n242\n).', 'The entities (\n214\n) are collections of data stored in the repository (\n212\n).', 'In one or more embodiments, the entity (\n216\n) stores exploration and production data in the data (\n240\n), and the metadata (\n242\n).', 'In one or more embodiments, an entity is a specific unit of data that may be the target of a search and can include multiple named values.', 'For example, an entity can include one or more pressure values along the length of a particular well.', 'By way of another example, an entity may be the porosity at a specific subsurface location.', 'By way of another example, the entity may be a reservoir model.', 'The entity identifier (\n232\n) identifies the entity (\n216\n).', 'The entity identifier (\n232\n) can include a sequence of numbers and characters that is unique to the entity (\n216\n).', 'In one or more embodiments, the entity is explicitly or implicitly related to the entity identifier.', 'For example, the entity identifier may be defined based on position of the entity within the set of entities.', 'By way of another example, the entity identifier may be an alphanumeric value that is a link in the repository to the entity.', 'The schema identifier (\n234\n) identifies a schema for the entity (\n216\n).', 'In one or more embodiments, the schema identifier (\n234\n) identifies the schema (\n220\n) as the schema that defines the entity (\n216\n).', 'The data (\n240\n) is the values of the entity (\n216\n) and the metadata (\n242\n) describes the values in the data (\n240\n), such as by providing the units of measure.', 'For example, when the data (\n240\n) includes a value for the depth of a well measured in feet, the depth is stored in the data (\n240\n) as a floating point number and the units of measure (meters/feet) can be stored in the metadata (\n242\n) as a string.', 'In one or more embodiments, the data (\n240\n) is structured according to the properties (\n236\n) defined by the syntax (\n252\n) of the schema (\n220\n).', 'In one or more embodiments, the metadata (\n242\n) is also defined in the syntax (\n252\n) of the schema (\n220\n) and uses a name value pair where the name identifies the property (\n238\n) defined in the schema (\n220\n) and the value is associated with the property (\n238\n).', 'Referring to \nFIG.', '2.3\n, the schemas (\n218\n) define how the data in the entities (\n214\n) is stored.', 'The schemas (\n218\n) include the schema (\n220\n).', 'Each schema defines, for one or more entities, how the one or more entities are stored.', 'For example, each individual schema may be for a corresponding individual repository of entities.', 'The schema (\n220\n) includes the type (\n244\n) and the syntax (\n252\n).', 'The type (\n244\n) of the schema (\n220\n) uniquely identifies the schema (\n220\n) within the schemas (\n218\n).', 'In one or more embodiments, the type (\n244\n) is a string that includes the namespace (\n246\n), the class (\n248\n), and the version (\n250\n).', 'The type (\n244\n) can be used as a schema identifier.', 'In one or more embodiments, the schema identifier (\n234\n) of the entity (\n216\n) of \nFIG.', '2.2\n is a string that includes the namespace (\n246\n), the class (\n248\n), and the version (\n250\n).', 'For example, the type “A:Well:1.0” can be used as a schema identifier that identifies a schema having the namespace “A”, the class “Well”, and the version “1.0”.', 'In one or more embodiments, the syntax (\n252\n) is the set of rules that defines the combinations of symbols, values, names, strings, numbers, etc. required for correctly structuring an entity as defined by the schema (\n220\n) and identified with the type (\n244\n).', 'The syntax includes the properties (\n236\n).', 'The properties (\n236\n) include the property (\n238\n).', 'In one or more embodiments, the properties (\n236\n) define the property names and data types for the data (\n240\n) and the metadata (\n242\n).', 'A property includes a property name and a data type.', 'The property name is an identifier of data within an entity.', 'The property name, for example, may be porosity, horizontal stress, permeability, valve position, etc.', 'The data type identifies the type of data structure used to store the value for the property.', 'By way of example, the property (\n238\n) can be a depth property with a property name of “Depth” and data type that indicates that the value is stored as a floating point number (e.g., 2384.0).', 'Referring to \nFIG.', '2.4\n, the graph (\n222\n) relates schemas and transformations.', 'Specifically, each node in the graph corresponds to a unique schema.', 'The node has the schema identifier (\n256\n) that corresponds to the node.', 'Each edge in the graph corresponds to a transformation between two schemas.', 'Thus, the edges have corresponding transformation identifiers (\n262\n).', 'An edge connects two nodes (e.g., first node, second node) when a transformation corresponding to the edge exists that transforms an entity matching a schema represented by a first node to an entity having the schema represented by the second node.', 'In one or more embodiments, the graph (\n222\n) is a directed graph in that each edge is directional.', 'As shown, the graph (\n222\n) includes the schema identifiers (\n256\n) and the transformation identifiers (\n262\n).', 'The graph (\n222\n) identifies the transformations (\n224\n) that can be made between the entities (\n214\n).', 'The schema identifiers (\n256\n) identify the schemas that form the nodes of the graph (\n222\n).', 'The schema identifiers (\n256\n) include the schema identifier (\n258\n).', 'In one or more embodiments, the schema identifier (\n258\n) identifies the schema (\n220\n).', 'The transformation identifiers (\n262\n) form the edges and connections between the schemas that represent the nodes of the graph (\n222\n).', 'The transformation identifiers (\n262\n) include the transformation identifier (\n264\n), which includes the weights (\n272\n).', 'In one or more embodiments, the graph (\n222\n) is a weighted graph having weights related to each edge.', 'The weights (\n272\n) define a cost for converting source entities to target entities that are defined by source schemas and target schemas in transformations and can be used to determine which transformations to use.', 'The weights (\n272\n) include the weight (\n273\n) and the weight (\n274\n).', 'In one or more embodiments, the weight (\n273\n) is a function of the amount of time to execute the transformation (\n225\n) on a source entity and generate a target entity.', 'In one or more embodiments, the weight (\n274\n) may be a function of the number of operations (\n282\n) required to perform the transformation (\n226\n).', 'Thus, the transformation corresponding to an edge having the greater weight may be less desirable than the transformation(s) having less weight.', 'Referring to \nFIG.', '2.5\n, the transformations (\n224\n) define how to convert entities between different schemas (\n218\n).', 'The transformations (\n224\n) include the transformation (\n226\n).', 'The transformations (\n224\n) can be direct or indirect.', 'Direct transformations convert a start entity (valid under a start schema) directly to an end entity (valid under an end schema) without intermediate transformations to intermediate entities (valid under intermediate schemas).', 'Indirect transformations include the use of intermediate transformations to convert start entities to end entities.', 'The transformation (\n226\n) includes the transformation identifier (\n270\n), the start schema identifier (\n276\n), the end schema identifier (\n278\n), and the operations (\n280\n).', 'A set of one or more transformations from a start schema to an end schema corresponds to a path in the graph (\n222\n) from a node matching the start schema through one or more intermediate nodes via edges to a node matching the end schema.', 'Each edge along the path corresponds to an individual transformation in the set of transformations.', 'The transformation identifier (\n270\n) identifies the transformation (\n226\n).', 'In one or more embodiments, the transformation identifier (\n270\n) is a string of alphanumeric characters that is unique to the transformation (\n226\n) and identifies the transformation (\n226\n) within the set of transformations (\n272\n).', 'The source schema identifier (\n276\n) identifies one of the schemas (\n218\n) as being the schema that defines the source entity being converted by the transformation (\n226\n).', 'The target schema identifier (\n278\n) identifies one of the schemas (\n218\n) as being the schema that defines the target entity that results from the transformation (\n226\n).', 'The operations (\n280\n) convert source entities that are valid under source schemas directly to target entities that are valid under target schemas without intermediate conversions.', 'For example, the transformation (\n226\n) can include two operations where the first operation converts a start entity to an intermediate entity and the second operation converts the intermediate entity to an end entity.', 'The operations (\n280\n) include the operation (\n282\n).', 'The operation (\n282\n) includes the start schema identifier (\n284\n), the end schema identifier (\n286\n), the map (\n288\n).', 'The start schema identifier (\n284\n) that identifies a start schema under which a start entity is valid.', 'The end schema identifier (\n286\n) that identifies an end schema under which an end entity will be valid after execution of the operation (\n282\n).', 'The map (\n288\n) specifies the properties that are converted with the operation (\n282\n).', 'In one or more embodiments, the map (\n288\n) identifies a start property defined in the start schema and links the start property to an end property defined in the end schema.', 'In one or more embodiments, the values related to the start property of a start entity are converted to the end property of the end entity.', 'In one or more embodiments, the map (\n288\n) can also include additional instructions to facilitate converting a start entity to an end entity.', 'In one or more embodiments, map (\n288\n) includes the service call (\n290\n).', 'The service call (\n290\n) specifies a function that can perform a conversion required by the operation (\n282\n).', 'In one or more embodiments, the service call (\n290\n) is a call to a web service that takes start entity property values as inputs and returns data for the end entity property.', 'For example, consider the scenario in which the start entity property is for a street address and the datatype of the start entity property is a set of strings.', 'In the example, the input to the service call is a set of strings that specify a particular street address defined in the start entity property.', 'Continuing with the example, the web service of the service call converts street address to geographic coordinates (longitude, latitude, elevation, etc.).', 'The geographic coordinates are loaded into the end entity property.', 'In other words, in the example, the service call is used convert a street address to the geographic coordinates.', 'In general, one or more embodiments receive a request that identifies a target schema.', 'The target schema defines the target properties of data that the user or requesting system may want to receive.', 'The request does not identify data repositories, particular entities, or specific sources of the data in accordance with one or more embodiments.', 'Using the graph, one or more embodiments determine the one or more source schemas in which at least one path exists to the target schema.', 'In other words, based on the graphs, the paths to the target schema are determined.', 'From the source schemas, the entities having a schema identifier matching one or more of the source schemas are identified.', 'Thus, the entities and data sources which are not known prior to determining the paths to the target may be determined.', 'The series of transformations, defined by the respective paths, are performed on the entities to obtain corresponding transformed entities in the target schema.', 'The corresponding transformed entities may then be returned in response to the original request.', 'FIG.', '3\n, \nFIG.', '4\n, and \nFIG.', '5\n show flowcharts in accordance with one or more embodiments of the disclosure.', 'While the various blocks in these flowcharts are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'Furthermore, the blocks may be performed actively or passively.', 'For example, some blocks may be performed using polling or be interrupt driven in accordance with one or more embodiments.', 'By way of an example, determination blocks may not require a processor to process an instruction unless an interrupt is received to signify that condition exists in accordance with one or more embodiments.', 'As another example, determination blocks may be performed by performing a test, such as checking a data value to test whether the value is consistent with the tested condition in accordance with one or more embodiments.', 'Turning to \nFIG.', '3\n, \nFIG.', '3\n shows a flowchart in accordance with one or more embodiments of the disclosure.', 'In Block \n302\n, a target schema is determined from a request.', 'In one or more embodiments, the request identifies the target schema from which a set of target entities can be identified and retrieved but does not identify the source schemas and source entities, which are derived later.', 'In one or more embodiments, the request can be part of a search query and identify one or more of the target schemas, the type of the target schema, the namespace of the target schema, the class of the target schema, the version of the target schema, and a property defined by the syntax of the target schema.', 'In one or more embodiments, incomplete information can be filled in using contextual information or default values.', 'For example, with the query:\n \ngeo:Location.', 'Latitude>40\n \nthe target schema is identified from “geo:Location.', 'Latitude”, which identifies a class “geo” and a property “Location.', 'Latitude”, but does not identify the namespace or the version of the target schema.', 'The namespace “I” can be determined from the context (e.g., a previous or query that identified the namespace) or a default namespace can be used.', 'The version “1.10” can default to the latest version of the schema.', 'The query above also includes a filter, which is discussed below in \nFIG.', '5\n.', 'In Block \n304\n, transformations are identified that can convert between source schemas and the target schema.', 'In one or more embodiments, after determining the target schema a set of transformations is identified from a list of available transformations.', 'The set of transformations include transformations that have target schema identifiers that match the target schema that was previously determined.', 'From the set of transformations, a set of source schemas is identified from the source schema identifiers within the transformations.', 'In one or more embodiments, the transformations are determined from the graph.', 'Specifically, a source node corresponding to the source schema is identified.', 'The target node corresponding to the target schema is identified.', 'Paths from the source node to the target node are determined through analyzing the graph.', 'If multiple paths exist, the path having optimal set of weights may be selected.', 'For example, the path having the least total weight may be selected.', 'In Block \n306\n, source entities are received that correspond to the source schemas.', 'After identifying the set of source schemas, the system identifies a set of source entities that are defined according to at least one of the source schemas.', 'As an example, the analyzer engine can send the source schema identifiers to databases that respond by providing entities that are compatible with the source schemas identified with the source schema identifiers.', 'In Block \n308\n, source entities are converted to target entities by applying transformations.', 'In one or more embodiments, the analyzer engine applies the set of transformations identified from the available transformations to the source entities that were received.', 'In one or more embodiments, individual transformations can include multiple operations that convert a source entity through a sequence of one or more intermediate entities before generating the target entity.', 'A process for converting entities is further described in \nFIG.', '4\n.', 'In one or more embodiments, when multiple paths are available for converting from a source schema to a target schema, the weights associated with the transformations in the paths are used to determine the path (having the least cumulative weight) to use for performing the transformation.', 'In one or more embodiments, entities that are transformed are stored in a cache to expedite repeated executions by reducing the number of transformations needing to be performed, which is useful when a transformation involves a remote service invocation.', 'In one or more embodiments, transformations are versioned with a version number that increases when updated to enable cashing and reuse of previously transform entities in subsequent queries that use the same transformations.', 'In one or more embodiments, a given transformation is re-executed on an entity when a cached entity is not available or when a newer version of the transformation is available.', 'In Block \n310\n, a reply is presented in response to the request that includes target data from the target entities.', 'In one or more embodiments, the target data in the target entities was converted from the source data in the source entities by the analyzer engine.', 'In one or more embodiments, the application presents the target data by transferring the target data using extensible markup language (XML) to the client device.', 'The client device displays the target data using hypertext markup language (HTML) with a web browser on the client device in response to the request that was initially sent from the client device and received by the application.', 'Turning to \nFIG.', '4\n, \nFIG.', '4\n shows a flowchart for converting source data to target data in accordance with one or more embodiments of the disclosure.', 'In Block \n402\n, a property is identified from a request.', 'In one or more embodiments, a property is a target property of a target entity for which data is being requested.', 'For example, with the query:\n \ngeo:Location.', 'Latitude>40\n \nthe property “Location.', 'Latitude” is identified as the target property.', 'In Block \n404\n, a map is used to transform source data to target data.', 'In one or more embodiments, the analyzer engine uses a map from an operation of a transformation to transform the source data to the target data.', 'The map is used to copy data and metadata from the source entity to the target entity.', 'In one or more embodiments, the maps include instructions to adjust the data being copied from the source entities to the target entities.', 'For example, a map can include instructions to convert between units (e.g., feet to meters), types (e.g., float to string), and presentation (e.g., fixed point display to floating point display).', 'In Block \n406\n, a web service is invoked with the source data.', 'In one or more embodiments, the analyzer engine transforms the source data to the target data by using a web service.', 'For example, a source entity property can include the street address:\n \n500 Fifth Avenue\n \nNew York, N.Y.\n \nwhich is reconstructed into a web service call:\n \n \n \n \n \nhttps://webservice.tld/search?q=500+Fifth+Avenue+New+York+NY \n that is passed to the web service by the analyzer engine.', 'In Block \n408\n, a response is received from the web service that includes the target data.', 'In one or more embodiments, the analyzer engine receives the target data from the web service in a JavaScript object notation (JSON) formatted string.', 'For example, a response to the web service call from above may include the JSON formatted string:\n \n{“Latitude”:“40.7539143”,“Longitude”:“−73.9810162”}\n \nfrom which the target data that includes the latitude and longitude can be incorporated into the target property of the target entity.', 'Turning to \nFIG.', '5\n, \nFIG.', '5\n shows a flowchart for filtering data in accordance with one or more embodiments of the disclosure.', 'In Block \n502\n, a filter is identified from a request.', 'The filter can specify a type of data, a range of values, a minimum value, maximum value, specific values, etc.', 'For example, the query:\n \ngeo:Location.Latitude>40\n \nincludes a filter “Location.Latitude>40”, which specifies that only entities with the latitudes property that is greater than 40 degrees should be presented.', 'In Block \n504\n, the target entities are filtered prior to responding to the request.', 'In one or more embodiments, the analyzer engine filters the target entities based on the property identified in the filter.', 'For example, with the filter “Location.Latitude>40”, which specifies the “Location.Latitude” property, the target entities that do not have the property specified by the filter are removed from the results.', 'In Block \n506\n, target data is filtered prior to responding to the request.', 'In one or more embodiments, the analyzer engine filters the target data based on the filter.', 'For example, with the filter “Location.Latitude>40”, which specifies that the property value must be greater than 40, the target entities with target data that do not have the value specified by the filter are removed from the results.\n \nFIGS.', '6.1 through 6.5\n show diagrams of one or more embodiments that are in accordance with the disclosure.', 'The various elements, features, systems, components, and interfaces shown in \nFIGS.', '6.1 through 6.5\n may be omitted, repeated, combined, and/or altered as shown from \nFIGS.', '6.1 through 6.5\n.', 'Accordingly, the scope of the present disclosure should not be considered limited to the specific arrangements shown in \nFIGS.', '6.1 through 6.5\n.', 'Referring to \nFIG.', '6.1\n, the user interface (\n616\n) can be used to display and edit the schemas (\n601\n, \n602\n) and the transformation (\n603\n).', 'In one or more embodiments, the user interface (\n616\n) is displayed on a client device to edit one or more graphs, transformations, schemas, and entities from the repository.', 'Definitions are provided for the source schema (\n601\n), the target schema (\n602\n), and the transformation (\n603\n).', 'The transformation (\n603\n) can be used to transform an entity defined in accordance with the source schema (\n601\n) to an entity that accords with the target schema (\n602\n).', 'The source schema (\n601\n) is the type “A:Well:1.0”, which includes the namespace “A”, the class “Well”, and the version “1.0”.', 'Six properties are defined as part of the syntax of the source schema (\n601\n).', 'The “Name”, “UWI”, and “Basin” properties store the name of the well, a universal well identifier (UWI), and the name of the basin where the well is located.', 'The “Name”, “UWI”, and “Basin” properties are stored as strings.', 'The SpudDate property is stored as a “datetime” object and indicates when the main drill bit began drilling into the ground.', 'The “Depth” property is stored as a 64 bit double precision floating point number (“double”) and indicates the maximum depth of the well.', 'The “Location” property is stored as a “geopoint” object that includes floating point values for latitude and longitude.', 'The target schema (\n602\n) is the type “My:Well:1.0”, which includes the namespace “My” that is different from the namespace of the source schema (\n601\n).', 'Four properties are defined as part of the syntax of the target schema (\n602\n).', 'The “Name”, “WellId”, and “field” properties store the name of the well, a well identifier, and the name of the field where the well is located.', 'The “Name”, “WellID”, and “Field” properties are stored as strings.', 'The “MaxDepth” property is stored as a 64 bit double precision floating point number (“double”) and identifies the maximum depth to which the well has been drilled.', 'The transformation (\n603\n) includes a transformation identifier “192A5” to distinguish the transformation (\n603\n) from other transformations in the system.', 'The transformation (\n603\n) includes a single operation to convert an entity directly from the source schema (\n601\n) to the target schema (\n602\n).', 'The string “A:Well:1.0→My:Well:1.0” includes a source schema identifier “A:Well:1.0” for the source schema (\n601\n) and a target schema identifier “My:Well:1.0” for the target schema (\n602\n).', 'The transformation (\n603\n) includes a map that identifies three properties from the source schema (\n601\n) (“Name”, “UWI”, “Depth”) that can be converted to properties of the target schema (\n602\n) (“Name”, “WellId”, “MaxDepth”).', 'Referring to \nFIG.', '6.2\n, the user interface (\n616\n) is updated to display and edit the entities (\n604\n, \n605\n).', 'The source entity (\n604\n) and the target entity (\n605\n) are shown with the transformation button (\n617\n).', 'Selecting the transformation button \n617\n transforms the source data from the source entity \n604\n to the target data in the target entity \n605\n using the transformation (\n603\n) from \nFIG.', '6.1\n.', 'The source entity (\n604\n) includes an entity identifier (“95AFCDE5”) and a schema identifier (“A:Well:1.0”) with data and metadata.', 'The data includes values for the properties defined in the source schema (\n601\n).', 'The metadata includes metadata values for three of the properties (“SpudDate”, “Location”, and “Depth”).', 'Resource entity (\n604\n) includes the property named “Depth” with a value of (2384), which is measured in meters.', 'The target entity (\n605\n) includes the same entity identifier (“95AFCDE5”) and a different schema identifier (“My:Well:1.0”) as compared to the source entity (\n604\n).', 'The target entity (\n605\n) includes data converted from the source entity (\n604\n).', 'The data includes values for the properties “Name”, “WellId”, and “MaxDepth”.', 'The metadata includes metadata a value for one property (“MaxDepth”).', 'The values for the “Name” and “WellId” properties are copied from the source entity (\n604\n).', 'The value for the “MaxDepth” property is converted from 2384 meters in the source entity (\n604\n) to 7822 feet in the target entity (\n605\n).', 'To perform the conversion, the analyzer engine identifies the metadata for the property in the source entity (\n604\n) and the target entity (\n605\n).', 'The analyzer engine and compares the source metadata to the target metadata to determine whether a conversion is needed.', 'When a conversion is needed, the conversion can be performed by identifying a formula from a lookup table and applying the formula to the data from the source entity (\n604\n) to generate the data for the target entity (\n605\n).', 'Referring to \nFIG.', '6.3\n, the user interface (\n616\n) is updated to show a screen for editing the graph (\n606\n).', 'The graph (\n606\n) includes the schemas (\n607\n, \n609\n, \n611\n, and \n612\n) and the tranformations (\n608\n, \n610\n, \n613\n) that are used to identify and convert entities.', 'The tranformations (\n608\n, \n610\n, \n613\n) include a single operation to directly convert source entities to target entities.', 'In one or more embodiments, the analyzer engine can generate additional transformations that include the operations from other transformations.', 'For example, an additional transformation can be generated that includes the operations from the transformations (\n608\n, \n610\n).', 'With the transformations available to the analyzer engine, entities defined by the schemas (\n607\n, \n609\n, and \n612\n) can be converted to target entities defined by the schema (\n611\n).', 'The schema (\n607\n) is of the type “N:Borehole” and includes the properties “Name”, “UWI”, and “LatLong”.', 'The type “N:Borehole” represents a hole in the ground drilled for geological investigation, assessment or to bring hydrocarbons/natural gas to the surface.', 'In one or more embodiments, the schema (\n607\n) also includes a “trajectory” property, which correlates to the path of the borehole with a series of (x, y, z) values that can be used to plot a line or curve in 3D space that represents the trajectory of the borehole.', 'There can be several boreholes that belong to a specific well.', 'The schema (\n609\n) is of the type “A:Well”, which includes the properties “Name”, “UWI”, “SpudDate”, “Depth”, “Location”, and “Basin”, which are described above in \nFIG.', '6.1\n.', 'The schema (\n609\n) generally defines entities for an oil well designed to bring petroleum to the surface via boreholes.', 'Oil wells have globally unique identifiers that are tracked on various oilfield directories like the Norwegian Petroleum Directorate (NPD) and the American Petroleum Institute (API), which can be stored in the UWI property.', 'The schema (\n611\n) is of the type “I:Geo” and includes the property “Location”.', 'As used here, “Geo” is not a specific geoscientific term, but a software abstraction for any entity that has a ‘Geographical Location’.', 'The “I:Geo” type is used to map disparate types of source entities to a single type of entity (“I:Geo” target entities) to enable the comparison/sorting/grouping of the source data in the source entities.', 'Most oilfield entities have a physical geographical location (e.g. the location of a well on the surface of the earth, the location of a specific rock formation, the location of a fluid pump, etc.)', 'and by projecting these source types and entities as ‘Geo’ target entities, spatial operations can be performed across the different source entities.', 'The schema (\n612\n) is of the type “X:Company”.', 'The “X:Company” type includes the properties “Name”, “Address”, and “Website” that identify the name of the company, the address of the company, and a website for the company.', 'The transformation (\n608\n) can transform entities from the “N:Borehole” schema (\n607\n) to the “A:Well” schema (\n609\n).', 'The map of the transformation (\n608\n) indicates that the “LatLong” property of an entity defined by the schema (\n607\n) is converted to the “Location” property of an entity defined by the schema (\n609\n).', 'In one or more embodiments, the value for the “LatLong” property from a source “N:Borehole” entity is copied to the “Location” property of the target “A: Well” entity.', 'The transformation (\n610\n) can transform entities from the “A:Well” schema (\n609\n) to the “I:Geo” schema (\n611\n).', 'The map of the transformation (\n610\n) indicates that the “Location” property of an entity defined by the schema (\n609\n) is converted to the “Location” property of an entity defined by the schema (\n611\n).', 'In one or more embodiments, the value for the “Location” property from a source “A:Well” entity is copied to the “Location” property of the target “I:Geo” entity.', 'The transformation (\n613\n) can transform entities from the “X:Company” schema (\n612\n) to the “I:Geo” schema (\n611\n).', 'The map of the transformation (\n613\n) indicates that a call to a web service is invoked to perform the transformation.', 'For example, the “Address” property of a source “X:Company” entity is included in a call to the web service (\n615\n) that is routed through the network (\n614\n).', 'The web service (\n615\n) respond with latitude and longitude coordinates that are put into the “Location” property of the target “I:Geo” entity.', 'Referring to \nFIG.', '6.4\n, the user interface (\n616\n) is updated to show edits to the graph (\n606\n).', 'The schemas are shown without properties and represented by a box with the type of the schema.', 'The transformations are displayed without the maps and service calls and are represented as arrows between the schemas with a shortened numbering system.', 'The shortened numbering system uniquely identifies each transformation displayed on user interface (\n616\n).', 'In one or more embodiments, selecting a schema or transformation can bring up and edit window to edit the selected schema or transformation.', 'In one or more embodiments, options were selected to present the schemas (\n607\n, \n609\n, \n611\n, \n621\n, \n623\n, \n625\n, \n627\n, \n629\n, \n632\n) and transformations (\n608\n, \n610\n, \n622\n, \n624\n, \n626\n, \n628\n, \n630\n, \n631\n, \n633\n) in a condensed view.', 'The graph (\n606\n) is updated in \nFIG.', '6.4\n to remove the schema (\n612\n) and to remove the transformation (\n613\n), the network (\n614\n) and the web service (\n615\n) shown in \nFIG.', '6.3\n.', 'The graph is updated to include the schemas (\n621\n, \n623\n, \n625\n, \n627\n, \n629\n, \n632\n) and to include the transformations (\n622\n, \n624\n, \n626\n, \n628\n, \n630\n, \n631\n, \n633\n).', 'The transformations (\n608\n, \n610\n, \n622\n, \n624\n, \n626\n, \n628\n, \n630\n, \n631\n, \n633\n) include a single operation to directly convert source entities to target entities.', 'With the changes to the available schemas and transformations, the analyzer engine can generate new additional transformations to incorporate the operations from the available transformations (\n608\n, \n610\n, \n622\n, \n624\n, \n626\n, \n628\n, \n630\n, \n631\n, \n633\n).', 'With the updates to the graph (\n606\n), the “I:Geo” schema (\n611\n) can be reached from entities defined with the schemas (\n607\n, \n609\n, \n611\n, \n621\n, \n623\n, \n625\n, \n627\n, \n629\n), but not with the schema (\n632\n).', 'The “N:ImageLog” schema (\n621\n) and the “T:SonicLog” schema (\n625\n) are used for entities that represent specific types of logs that measure more complex properties of the rock formations.', 'Image logs usually measure a two dimensional (2D) set of values at a specific depth along a borehole.', 'Sonic logs measure a formations capacity to transmit seismic waves.', 'The “X:Log” schema (\n623\n) is used for entities that represent collections of continuous data points that record details of the rock formation usually along the path of a borehole penetrating the earth.', 'Logs commonly are a series of values (depending on what is being measured like porosity, temperature, permeability, etc.) indexed against the measured depth from the top of the borehole.', 'The “N:Horizon” schema (\n627\n) is used for entities that represent marker horizons.', 'The marker horizons correspond to stratigraphic elements that share common properties (including age and composition) despite their presence in separate geographic locations.', 'The “I:3DPlane” schema (\n629\n) is for entities that represent a flat surface in three dimensional (3D) space.', 'The “N:Surface” schema (\n632\n) is for entities that represent a 3-dimensional plane comprising some geological formation.', 'For example, “N: Surface” entities can represent various layers of the subsurface, including the sea bed.', 'Referring to \nFIG.', '6.5\n, the client device (\n641\n) displays the user interface (\n642\n).', 'In one or more embodiments, the user interface (\n642\n) is a command line interface (CLI) displayed in a shell or browser window on the client device (\n641\n).', 'The user interface displays a query (\n643\n) and the results (\n644\n) that are presented in response to the query (\n643\n).', 'The user of the client device (\n641\n) entered the the query “geo:Location.Latitude>40”.', 'The query includes the class name of the schema as “geo”, a property as “Location.Latitude”, and a filter of “Location.Latitude>40”.', 'The analyzer engine determines that the target schema is “I:Geo” with the namespace “I” being determined from a previous query or a default value.', 'The analyzer engine uses the graph to determine the source schemas that are reachable to the target schema and to determine the transformations needed to convert entities from the source schemas to the target schema.', 'After retrieving target data from entities converted to target entities, the filter is applied to generate the results (\n644\n) that are presented in the user interface (\n642\n).', 'Embodiments may be implemented on a computing system.', 'Any combination of mobile, desktop, server, router, switch, embedded device, or other types of hardware may be used.', 'For example, as shown in \nFIG.', '7.1\n, the computing system (\n700\n) may include one or more computer processors (\n702\n), non-persistent storage (\n704\n) (e.g., volatile memory, such as random access memory (RAM), cache memory), persistent storage (\n706\n) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory, etc.), a communication interface (\n712\n) (e.g., Bluetooth interface, infrared interface, network interface, optical interface, etc.), and numerous other elements and functionalities.', 'The computer processor(s) (\n702\n) may be an integrated circuit for processing instructions.', 'For example, the computer processor(s) may be one or more cores or micro-cores of a processor.', 'The computing system (\n700\n) may also include one or more input devices (\n710\n), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.', 'The communication interface (\n712\n) may include an integrated circuit for connecting the computing system (\n700\n) to a network (not shown) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) and/or to another device, such as another computing device.', 'Further, the computing system (\n700\n) may include one or more output devices (\n708\n), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device.', 'One or more of the output devices may be the same or different from the input device(s).', 'The input and output device(s) may be locally or remotely connected to the computer processor(s) (\n702\n), non-persistent storage (\n704\n), and persistent storage (\n706\n).', 'Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.', 'Software instructions in the form of computer readable program code to perform embodiments of the disclosure may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium.', 'Specifically, the software instructions may correspond to computer readable program code that, when executed by a processor(s), is configured to perform one or more embodiments of the disclosure.', 'The computing system (\n700\n) in \nFIG.', '7.1\n may be connected to or be a part of a network.', 'For example, as shown in \nFIG.', '7.2\n, the network (\n720\n) may include multiple nodes (e.g., node X (\n722\n), node Y (\n724\n)).', 'Nodes may correspond to a computing system, such as the computing system shown in \nFIG.', '7.1\n, or a group of nodes combined may correspond to the computing system shown in \nFIG.', '7.1\n.', 'By way of an example, embodiments of the disclosure may be implemented on a node of a distributed system that is connected to other nodes.', 'By way of another example, embodiments of the disclosure may be implemented on a distributed computing system having multiple nodes, where portions of the disclosure may be located on a different node within the distributed computing system.', 'Further, one or more elements of the aforementioned computing system (\n700\n) may be located at a remote location and connected to the other elements over a network.', 'Although not shown in \nFIG.', '7.2\n, the node may correspond to a blade in a server chassis that is connected to other nodes via a backplane.', 'By way of another example, the node may correspond to a server in a data center.', 'By way of another example, the node may correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.', 'The nodes (e.g., node X (\n722\n), node Y (\n724\n)) in the network (\n720\n) may be configured to provide services for a client device (\n726\n).', 'For example, the nodes may be part of a cloud computing system.', 'The nodes may include functionality to receive requests from the client device (\n726\n) and transmit responses to the client device (\n726\n).', 'The client device (\n726\n) may be a computing system, such as the computing system shown in \nFIG.', '7.1\n.', 'Further, the client device (\n726\n) may include and/or perform at least a portion of one or more embodiments of the disclosure.', 'The computing system or group of computing systems described in \nFIGS.', '7.1 and 7.2\n may include functionality to perform a variety of operations disclosed herein.', 'For example, the computing system(s) may perform communication between processes on the same or different system.', 'A variety of mechanisms, employing some form of active or passive communication, may facilitate the exchange of data between processes on the same device.', 'Examples representative of these inter-process communications include, but are not limited to, the implementation of a file, a signal, a socket, a message queue, a pipeline, a semaphore, shared memory, message passing, and a memory-mapped file.', 'Further details pertaining to a couple of these non-limiting examples are provided below.', 'Based on the client-server networking model, sockets may serve as interfaces or communication channel end-points enabling bidirectional data transfer between processes on the same device.', 'Foremost, following the client-server networking model, a server process (e.g., a process that provides data) may create a first socket object.', 'Next, the server process binds the first socket object, thereby associating the first socket object with a unique name and/or address.', 'After creating and binding the first socket object, the server process then waits and listens for incoming connection requests from one or more client processes (e.g., processes that seek data).', 'At this point, when a client process wishes to obtain data from a server process, the client process starts by creating a second socket object.', 'The client process then proceeds to generate a connection request that includes at least the second socket object and the unique name and/or address associated with the first socket object.', 'The client process then transmits the connection request to the server process.', 'Depending on availability, the server process may accept the connection request, establishing a communication channel with the client process, or the server process, busy in handling other operations, may queue the connection request in a buffer until server process is ready.', 'An established connection informs the client process that communications may commence.', 'In response, the client process may generate a data request specifying the data that the client process wishes to obtain.', 'The data request is subsequently transmitted to the server process.', 'Upon receiving the data request, the server process analyzes the request and gathers the requested data.', 'Finally, the server process then generates a reply including at least the requested data and transmits the reply to the client process.', 'The data may be transferred, more commonly, as datagrams or a stream of characters (e.g., bytes).', 'Shared memory refers to the allocation of virtual memory space in order to substantiate a mechanism for which data may be communicated and/or accessed by multiple processes.', 'In implementing shared memory, an initializing process first creates a shareable segment in persistent or non-persistent storage.', 'Post creation, the initializing process then mounts the shareable segment, subsequently mapping the shareable segment into the address space associated with the initializing process.', 'Following the mounting, the initializing process proceeds to identify and grant access permission to one or more authorized processes that may also write and read data to and from the shareable segment.', 'Changes made to the data in the shareable segment by one process may immediately affect other processes, which are also linked to the shareable segment.', 'Further, when one of the authorized processes accesses the shareable segment, the shareable segment maps to the address space of that authorized process.', 'Often, only one authorized process may mount the shareable segment, other than the initializing process, at any given time.', 'Other techniques may be used to share data, such as the various data described in the present application, between processes without departing from the scope of the disclosure.', 'The processes may be part of the same or different application and may execute on the same or different computing system.', 'Rather than or in addition to sharing data between processes, the computing system performing one or more embodiments of the disclosure may include functionality to receive data from a user.', 'For example, in one or more embodiments, a user may submit data via a graphical user interface (GUI) on the user device.', 'Data may be submitted via the graphical user interface by a user selecting one or more graphical user interface widgets or inserting text and other data into graphical user interface widgets using a touchpad, a keyboard, a mouse, or any other input device.', 'In response to selecting a particular item, information regarding the particular item may be obtained from persistent or non-persistent storage by the computer processor.', "Upon selection of the item by the user, the contents of the obtained data regarding the particular item may be displayed on the user device in response to the user's selection.", 'By way of another example, a request to obtain data regarding the particular item may be sent to a server operatively connected to the user device through a network.', 'For example, the user may select a uniform resource locator (URL) link within a web client of the user device, thereby initiating a Hypertext Transfer Protocol (HTTP) or other protocol request being sent to the network host associated with the URL.', 'In response to the request, the server may extract the data regarding the particular selected item and send the data to the device that initiated the request.', "Once the user device has received the data regarding the particular item, the contents of the received data regarding the particular item may be displayed on the user device in response to the user's selection.", 'Further to the above example, the data received from the server after selecting the URL link may provide a web page in Hyper Text Markup Language (HTML) that may be rendered by the web client and displayed on the user device.', 'Once data is obtained, such as by using techniques described above or from storage, the computing system, in performing one or more embodiments of the disclosure, may extract one or more data items from the obtained data.', 'For example, the extraction may be performed as follows by the computing system in \nFIG.', '7.1\n.', 'First, the organizing pattern (e.g., grammar, schema, layout) of the data is determined, which may be based on one or more of the following: position (e.g., bit or column position, Nth token in a data stream, etc.), attribute (where the attribute is associated with one or more values), or a hierarchical/tree structure (consisting of layers of nodes at different levels of detail-such as in nested packet headers or nested document sections).', 'Then, the raw, unprocessed stream of data symbols is parsed, in the context of the organizing pattern, into a stream (or layered structure) of tokens (where tokens may have an associated token “type”).', 'Next, extraction criteria are used to extract one or more data items from the token stream or structure, where the extraction criteria are processed according to the organizing pattern to extract one or more tokens (or nodes from a layered structure).', 'For position-based data, the token(s) at the position(s) identified by the extraction criteria are extracted.', 'For attribute/value-based data, the token(s) and/or node(s) associated with the attribute(s) satisfying the extraction criteria are extracted.', 'For hierarchical/layered data, the token(s) associated with the node(s) matching the extraction criteria are extracted.', 'The extraction criteria may be as simple as an identifier string or may be a query presented to a structured data repository (where the data repository may be organized according to a database schema or data format, such as XML).', 'The extracted data may be used for further processing by the computing system.', 'For example, the computing system of \nFIG.', '7.1\n, while performing one or more embodiments of the disclosure, may perform data comparison.', 'Data comparison may be used to compare two or more data values (e.g., A, B).', 'For example, one or more embodiments may determine whether A>B, A=B, A !=B, A B, B may be subtracted from A (i.e., A−B), and the status flags may be read to determine if the result is positive (i.e., if A>B, then A−B>0).', 'In one or more embodiments, B may be considered a threshold, and A is deemed to satisfy the threshold if A=B or if A>B, as determined using the ALU.', 'In one or more embodiments of the disclosure, A and B may be vectors, and comparing A with B requires comparing the first element of vector A with the first element of vector B, the second element of vector A with the second element of vector B, etc.', 'In one or more embodiments, if A and B are strings, the binary values of the strings may be compared.', 'The computing system in \nFIG.', '7.1\n may implement and/or be connected to a data repository.', 'For example, one type of data repository is a database.', 'A database is a collection of information configured for ease of data retrieval, modification, re-organization, and deletion.', 'Database Management System (DBMS) is a software application that provides an interface for users to define, create, query, update, or administer databases.', 'The user, or software application, may submit a statement or query into the DBMS.', 'Then the DBMS interprets the statement.', 'The statement may be a select statement to request information, update statement, create statement, delete statement, etc.', 'Moreover, the statement may include parameters that specify data, or data container (database, table, record, column, view, etc.), identifier(s), conditions (comparison operators), functions (e.g. join, full join, count, average, etc.), sort (e.g. ascending, descending), or others.', 'The DBMS may execute the statement.', 'For example, the DBMS may access a memory buffer, a reference or index a file for read, write, deletion, or any combination thereof, for responding to the statement.', 'The DBMS may load the data from persistent or non-persistent storage and perform computations to respond to the query.', 'The DBMS may return the result(s) to the user or software application.', 'The computing system of \nFIG.', '7.1\n may include functionality to present raw and/or processed data, such as results of comparisons and other processing.', 'For example, presenting data may be accomplished through various presenting methods.', 'Specifically, data may be presented through a user interface provided by a computing device.', 'The user interface may include a GUI that displays information on a display device, such as a computer monitor or a touchscreen on a handheld computer device.', 'The GUI may include various GUI widgets that organize what data is shown as well as how data is presented to a user.', 'Furthermore, the GUI may present data directly to the user, e.g., data presented as actual data values through text, or rendered by the computing device into a visual representation of the data, such as through visualizing a data model.', 'For example, a GUI may first obtain a notification from a software application requesting that a particular data object be presented within the GUI.', 'Next, the GUI may determine a data object type associated with the particular data object, e.g., by obtaining data from a data attribute within the data object that identifies the data object type.', 'Then, the GUI may determine any rules designated for displaying that data object type, e.g., rules specified by a software framework for a data object class or according to any local parameters defined by the GUI for presenting that data object type.', 'Finally, the GUI may obtain data values from the particular data object and render a visual representation of the data values within a display device according to the designated rules for that data object type.', 'Data may also be presented through various audio methods.', 'In particular, data may be rendered into an audio format and presented as sound through one or more speakers operably connected to a computing device.', 'Data may also be presented to a user through haptic methods.', 'For example, haptic methods may include vibrations or other physical signals generated by the computing system.', 'For example, data may be presented to a user using a vibration generated by a handheld computer device with a predefined duration and intensity of the vibration to communicate the data.', 'The above description of functions presents only a few examples of functions performed by the computing system of \nFIG.', '7.1\n and the nodes and/or client device in \nFIG.', '7.2\n.', 'Other functions may be performed using one or more embodiments of the disclosure.', 'While the disclosure has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the disclosure.', 'Accordingly, the scope of the disclosure should be limited only by the attached claims.'] | ['1.', 'A method comprising:\ndetermining, from a request, a target schema;\nidentifying a plurality of paths between a set of source schemas and the target schema, each path of the plurality of paths comprising a corresponding set of transformations between a source schema, of the set of source schemas, and the target schema, and each path of the plurality of paths having a corresponding cumulative weight based on the corresponding set of transformations;\nreceiving a set of source entities that correspond to the set of source schemas;\nconverting the set of source entities to a set of target entities by applying the corresponding set of transformations to the set of source entities based on the corresponding cumulative weight; and\npresenting, in response to the request, a reply that comprises target data from the set of target entities.', '2.', 'The method of claim 1, further comprising:\nidentifying a target property from the request,\nwherein the set of target entities generated from the set of source entities include the target property.', '3.', 'The method of claim 2,\nwherein the set of source entities includes a source entity with source data of a source property with source metadata, and\nwherein the set of target entities includes a target entity with target data of the target property with target metadata.', '4.', 'The method of claim 3, further comprising:\ntransforming the source data to the target data by: using a map from a transformation from the corresponding set of transformations.', '5.', 'The method of claim 3, further comprising:\ntransforming the source data to the target data by: invoking a web service with a web service request that includes the source data.', '6.', 'The method of claim 5, further comprising:\ntransforming the source data to the target data by: receiving a web service response that includes the target data.', '7.', 'The method of claim 1,\nwherein the request is a query that includes a filter.', '8.', 'The method of claim 7, further comprising:\nfiltering the set of target entities based on the filter prior to responding to the request.', '9.', 'The method of claim 7, further comprising:\nfiltering the target data based on the filter prior to responding to the request.', '10.', 'The method of claim 1,\nwherein the source schema includes a source type that includes a source namespace, and\nwherein least one of the source namespace and the source type are different from a target namespace and a target type of the target schema.', '11.', 'A system comprising:\na memory coupled to a processor;\na graph that includes a set of schemas and a set of transformations, wherein the set of schemas includes a target schema and a set of source schemas;\nan analyzer engine from figure that executes on the processor, uses the memory, and is configured for: determining, from a request, the target schema; identifying the a plurality of paths between the set of source schemas and the target schema from the graph, each path of the plurality of paths comprising a corresponding set of transformations between a source schema, of the set of source schemas, and the target schema, and each path of the plurality of paths having a corresponding cumulative weight based on the corresponding set of transformations; receiving a set of source entities that correspond to the set of source schemas; converting the set of source entities to a set of target entities by applying the corresponding set of transformations to the set of source entities based on the corresponding cumulative weight; and presenting, in response to the request, a reply that includes target data from the set of target entities.\n\n\n\n\n\n\n12.', 'The system of claim 11, wherein the analyzer engine is further configured for:\nidentifying a target property from the request,\nwherein the set of target entities generated from the set of source entities include the target property.', '13.', 'The system of claim 12,\nwherein the set of source entities includes a source entity with source data of a source property with source metadata, and\nwherein the set of target entities includes a target entity with target data of the target property with target metadata.', '14.', 'The system of claim 13, wherein the analyzer engine is further configured for:\ntransforming the source data to the target data by: using a map from a transformation from the corresponding set of transformations.', '15.', 'The system of claim 13, wherein the analyzer engine is further configured for:\ntransforming the source data to the target data by: invoking a web service with a web service request that includes the source data.', '16.', 'The system of claim 15, wherein the analyzer engine is further configured for:\ntransforming the source data to the target data by: receiving a web service response that includes the target data.', '17.', 'The system of claim 8, wherein the analyzer engine is further configured for:\nwherein the request is a query that includes a filter.', '18.', 'The system of claim 17, wherein the analyzer engine is further configured for:\nfiltering the set of target entities based on the filter prior to responding to the request.', '19.', 'The system of claim 17, wherein the analyzer engine is further configured for:\nfiltering the target data based on the filter prior to responding to the request.', '20.', 'A non-transitory computer readable medium comprising computer readable program code for:\ndetermining, from a request, a target schema;\nidentifying a plurality of paths between a set of source schemas and the target schema, each path of the plurality of paths comprising a corresponding set of transformations between a source schema, of the set of source schemas, and the target schema, and each path of the plurality of paths having a corresponding cumulative weight based on the corresponding set of transformations;\nreceiving a set of source entities that correspond to the set of source schemas;\nconverting the set of source entities to a set of target entities by applying the corresponding set of transformations to the set of source entities based on the corresponding cumulative weight; and\npresenting, in response to the request, a reply that includes target data from the set of target entities.'] | ['FIG.', '1 shows a diagram of a system in accordance with disclosed embodiments.; FIGS. 2.1, 2.2, 2.3, 2.4, and 2.5 show diagrams of a system in accordance with disclosed embodiments.; FIGS. 3, 4, and 5, show flowcharts in accordance with disclosed embodiments.; FIGS.', '6.1, 6.2, 6.3, 6.4, and 6.5 show an example in accordance with disclosed embodiments.; FIGS.', '7.1 and 7.2 show computing systems in accordance with disclosed embodiments.;', 'FIG. 1 depicts a schematic view, partially in cross section, of an onshore field (101) and an offshore field (102) in which one or more embodiments may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in FIG.', '1 may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments should not be considered limited to the specific arrangement of modules shown in FIG.', '1.; FIGS. 2.1 through 2.5 show diagrams of one or more embodiments that are in accordance with the disclosure.', 'The various elements, systems, and components shown in FIGS.', '2.1 through 2.5 may be omitted, repeated, combined, and/or altered as shown from FIGS.', '2.1 through 2.5.', 'Accordingly, the scope of the present disclosure should not be considered limited to the specific arrangements shown in FIGS.', '2.1 through 2.5.;', 'FIG. 3, FIG. 4, and FIG.', '5 show flowcharts in accordance with one or more embodiments of the disclosure.', 'While the various blocks in these flowcharts are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'Furthermore, the blocks may be performed actively or passively.', 'For example, some blocks may be performed using polling or be interrupt driven in accordance with one or more embodiments.', 'By way of an example, determination blocks may not require a processor to process an instruction unless an interrupt is received to signify that condition exists in accordance with one or more embodiments.', 'As another example, determination blocks may be performed by performing a test, such as checking a data value to test whether the value is consistent with the tested condition in accordance with one or more embodiments.; FIGS.', '6.1 through 6.5 show diagrams of one or more embodiments that are in accordance with the disclosure.', 'The various elements, features, systems, components, and interfaces shown in FIGS.', '6.1 through 6.5 may be omitted, repeated, combined, and/or altered as shown from FIGS.', '6.1 through 6.5.', 'Accordingly, the scope of the present disclosure should not be considered limited to the specific arrangements shown in FIGS.', '6.1 through 6.5.'] |
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US11141787 | Concurrent, layer-by-layer powder and mold fabrication for multi-functional parts | Oct 10, 2018 | Srinand Karuppoor, Manuel Marya | SCHLUMBERGER TECHNOLOGY CORPORATION | Smart Material from Wikipedia, https://en.wikipedia.org/wiki/Smart_material, downloaded on May 6, 2021 (3 pages).; Wen et al., 2002, Piezoelectric cement-based materials with large coupling and voltage coefficients, Cement and Concrete Research 32, pp. 335-359 http://citeseerx.ist.psu.edu/viewdoc/download?doi=10.1.1.496.2883&rep=rep1&type=pdf.; Dong et al., Cement-based piezoelectric ceramic smart composites, Composites Science and Technology. vol. 65, Issue 9, Jul. 2005, pp. 1363-1371. | 5204055; April 20, 1993; Sachs et al.; 6353771; March 5, 2002; Southland; 7461684; December 9, 2008; Liu et al.; 7832457; November 16, 2010; Calnan et al.; 8374835; February 12, 2013; Lind et al.; 20030094730; May 22, 2003; Dourfaye et al.; 20070181224; August 9, 2007; Marya; 20130310961; November 21, 2013; Intriago Velez; 20200269320; August 27, 2020; Ben-Zur; 20200338818; October 29, 2020; Teng | 2490087; October 2012; GB; 2490299; October 2012; GB; 2006049619; May 2006; WO; 2009017648; February 2009; WO; WO2012073089; June 2012; WO | ['The present disclosure provides for a method of making a part using powder metallurgy and material extrusion.', 'The method includes forming a mold of a first material using material extrusion.', 'The method includes depositing a second material within the mold.', 'The second material is deposited as a powder.', 'The method includes compacting the second material within the mold, and heating the mold and the second material within the mold.', 'During the heating, the mold is separated from the material by melting, evaporating, or burning of the first material, and the second material is sintered.', 'Also provided for are parts made by the method and a system for making such parts.', 'The system includes a material extrusion head and a powder deposition head.', 'Each head is articulable along three axes.'] | ['Description\n\n\n\n\n\n\nFIELD\n \nThe present disclosure relates to the use of powder metallurgy methods in conjunction with additive manufacturing methods, as well as to parts, including multi-functional parts, made thereby, apparatus and systems including such parts, and methods of using such parts, apparatus and systems.', 'BACKGROUND\n \nOilfield tools are subjected to relatively harsh operating conditions.', 'Such tool components are typically required to fulfill multiple functionalities and/or exhibit multiple properties that provide suitability for operation in such harsh conditions, such as corrosion resistance, wear resistance, and the ability to bear relatively heavy loads and impacts.', 'Typically, such tool components are composed of a base material that provides the tool components with the primary load-bearing functionality, as well as supplemental coatings (claddings) that provide the tool components with desired physical properties, such as wear-resistance (e.g., wear bands on drill collars).', 'Powder metallurgy is one of the most important and established manufacturing processes.', 'Powder metallurgy typically includes the followings steps: (1) powder production; (2) powder compaction; (3) sintering of the compact; and (4) secondary and other finishing steps.', 'As one skilled in the art would know, the details of the powder metallurgy processes and its uses are available in literature and books.', 'See, e.g., Angelo, P. C. and Subramanian, R., Powder Metallurgy: Science, Technology, and Applications, PHI Learning Pvt. Ltd., 2008.', 'Traditionally, compaction of the powder is performed in many different ways to provide the required shape to the resultant product.', 'Typically, this involves pressing the powder with dies, isostatic compaction, centrifugal casting, cold isostatic pressing, or other methods known to those skilled in the art.', 'In isostatic pressing, containers (i.e., molds) for the powders are typically made of a sheet metal having a relatively high ductility to account for the deformation of the container during the pressing process.', 'Such sheet metal containers (metal shells) stay engaged on the surface of the pressed part (i.e., the part formed by compaction and sintering), requiring machining for removal of the sheet metal containers after formation of the part.', 'Material extrusion, in the additive manufacturing context, is a process in which a material is selectively dispensed through a nozzle or orifice head onto a build platform that is capable of moving in the x-y plane relative to the nozzle or orifice head.', 'After formation of a layer is completed using the material extrusion process, either the nozzle or orifice head or the build platform is moved in the z-plane so that an additional layer can be formed over the first layer.', 'This process is continued until the part is completely formed.', 'The raw material in material extrusion is typically a filament of thermoplastic that is coiled onto a spool and is melted as the material is extruded through the nozzle or orifice head.', 'Fusion between layers of the part occurs due to the overlay of the melt material of one layer upon the previous layer(s), which subsequently hardens to form a bond between the layers.', 'Support structures or material are typically required to support the bottom or overhanging features of the part.', 'The material extrusion process is commonly referred to as “3D printing”.', 'Recently, there has been a proliferation of 3D printing systems using material extrusion process technology in part because, in comparison to other additive manufacturing processes, such 3D printing systems are relatively inexpensive.', 'BRIEF SUMMARY\n \nOne embodiment of the present disclosure includes a method of making a part using powder metallurgy and material extrusion.', 'The method includes forming a mold of a first material using material extrusion, and depositing a second material within the mold.', 'The second material is deposited as a powder.', 'The method includes compacting the second material within the mold, and heating the mold and the second material within the mold.', 'During the heating, the mold is separated from the material by melting, evaporating, burning, or combinations thereof of the first material, and the second material is sintered.', 'The method includes obtaining a part.', 'Also provided for is a part made by the method.', 'Another embodiment of the present disclosure includes a system for making a part using powder metallurgy and material extrusion.', 'The system includes a material extrusion head and a powder deposition head.', 'The heads are each articulable along three axes.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nSo that the manner in which the features of the compositions, articles, systems and methods of the present disclosure may be understood in more detail, a more particular description briefly summarized above may be had by reference to the embodiments thereof which are illustrated in the appended drawings that form a part of this specification.', 'It is to be noted, however, that the drawings illustrate only various exemplary embodiments and are therefore not to be considered limiting of the disclosed concepts as it may include other effective embodiments as well.\n \nFIG.', '1A\n is a simplified flow chart showing steps of a powder metallurgy process.', 'FIG.', '1B\n is side view depicting powder being deposited into a mold.\n \nFIG.', '1C\n is a top view of the mold of \nFIG.', '1B\n showing compacted powder.\n \nFIG.', '1D\n is a top view of a part formed after sintering the compacted powder of \nFIG.', '1C\n.', 'FIG.', '1E\n is a simplified schematic of a material extrusion or fused deposition modelling system.', 'FIG.', '1F\n is a simplified flow chart of a material extrusion or fused deposition modelling process.', 'FIG.', '2A\n is a simplified schematic of a system, including both powder metallurgy and material extrusion apparatus, during concurrent manufacture of a mold and a part.', 'FIG.', '2B\n depicts a mold including holes formed through a body thereof.\n \nFIG.', '2C\n depicts a part formed in accordance with certain aspects of the present disclosure.\n \nFIG.', '3\n is a simplified schematic of a process and system of forming parts in accordance with certain aspects of the present disclosure.', 'FIG.', '4\n is a simplified flow chart of a process of forming parts in accordance with certain aspects of the present disclosure.', 'FIG.', '5A\n is a part having a gradient compositional profile.', 'FIG.', '5B\n is a part having a layered compositional profile with abrupt compositional changes.\n \nFIG.', '6A\n is a layered degradable part.', 'FIG.', '6B\n is a part including a smart material.', 'FIGS.', '7A-7D\n depict an axial pulse generator used in drilling tools during and after manufacture thereof in accordance with embodiments of the present method.\n \nFIG.', '8\n is a sintered part formed in accordance with embodiments of the present method.', 'Compositions, articles, systems, and methods according to present disclosure will now be described more fully with reference to the accompanying drawings, which illustrate various exemplary embodiments.', 'Concepts according to the present disclosure may, however, be embodied in many different forms and should not be construed as being limited by the illustrated embodiments set forth herein.', 'Rather, these embodiments are provided so that this disclosure will be thorough as well as complete and will fully convey the scope of the various concepts to those skilled in the art and the best and preferred modes of practice.', 'DETAILED DESCRIPTION', 'Certain aspects of the present disclosure include methods and systems of using powder metallurgy in conjunction with additive manufacturing (AM) to form parts, including multi-functional parts.', 'Additionally, the present disclosure includes parts made by these methods, apparatus and systems including such parts, and methods of using such parts, apparatus and systems.', 'Powder Metallurgy\n \nThe methods disclosed herein use powder metallurgy and associated apparatus to form parts.', 'With reference to \nFIG.', '1A\n, powder metallurgy includes powder production, box \n11\n.', 'Powder production may include selection of powder for use in construction of the parts.', 'The selected powder be a single constituent powder, such as a powder that is 100 percent by weight (wt. %) tungsten carbide.', 'In other aspects, the powder is a mixture of multiple, different powders.', 'Powders suitable for use in the present disclosure for powder metallurgy include, but are not limited to, metal powder, metal alloy powders, ceramic powders (e.g., tungsten carbide), or combinations thereof.', 'When the powder is a mixture of multiple, different powders, powder production may include blending or otherwise mixing the multiple, different powders together.', 'In certain aspects, the methods disclosed herein may be used to build a hybrid part that includes portions that are wholly or predominately metallic, such as greater than 50 wt. % metallic, and portions that are wholly or predominately ceramic, such as greater than 50 wt. % ceramic.', 'After powder production, powder metallurgy includes powder compaction, box \n13\n.', 'For example, the powder may be deposited into a mold and then subjected to compaction.', 'Powder compaction can include, but is not limited to, pressing the powder with dies, isostatic compaction of the powder, cold isostatic pressing, or other methods known to those skilled in the art.', 'After compaction, powder metallurgy includes sintering of the compact, box \n15\n.', 'Sintering may include, but is not limited to, liquid phase sintering, electric current assisted sintering, spark plasma sintering, and electro sinter forging.', 'Compaction and sintering results in a consolidation and/or fusing of the particles that make up the powder.', 'Thus, after compaction and sintering, the material is no longer in particulate or powder form, but is a bulk, solid part.', 'In some aspects, formation of the part via powder metallurgy include subjecting the powder material to hot isotactic pressing.', 'While described herein as separate steps, in some aspects compaction and sintering occur and/or are performed concurrently (e.g., simultaneously).', 'Powder metallurgy may then include any of numerous possible secondary and other finishing steps, box \n17\n, as would be understood by one skilled in the art.\n \nFIGS.', '1B-1D\n are schematics illustrating powder metallurgy.', 'Powder material \n32\n is dispensed from hopper \n30\n into mold \n34\n.', 'Within mold \n34\n, powder material \n32\n is subjected compaction processing, forming compacted powder \n38\n.', 'Compacted powder \n38\n is then subjected to sintering to form sintered part \n42\n.', 'One skilled in the art would understand that the above discussion of the powder metallurgy process is for exemplary and explanatory purposes, and that the methods disclosed herein are not limited to performing these particular steps in this particular order.', 'Rather, one skilled in the art would understand that certain steps combined or eliminated and other steps may be added without departing from the scope of this disclosure.', 'Material Extrusion\n \nThe methods disclosed herein use material extrusion and associated apparatus to form molds used in making parts.', 'A simplified representation of a material extrusion process is depicted in \nFIG.', '1E\n.', 'With reference to \nFIG.', '1E\n, filament \n10\na \nof raw material (e.g., a polymer resin) is dispensed from material spool \n12\n in a solid state, and is guided by guide \n14\n to heated extrusion head \n16\n.', 'Within heated extrusion head \n16\n, the raw material is brought from the solid state to a molten state such that the material exits heated extrusion head \n16\n as molten filament \n10\nb\n.', 'Heated extrusion head \n16\n is moved in the x- and y-directions to extrude and deposit molten filament \n10\nb \nonto platform \n18\n to successively build part \n22\n on layer-by-layer basis.', 'As shown, part \n22\n is supported by support material \n24\n.', 'After a layer is completed, the heated extrusion head \n16\n or the build platform \n18\n is moved in the z-direction.', 'One skilled in the art would understand that it is not critical which of the heated extrusion head \n16\n or build platform \n18\n moves, and that the process may be implemented by moving any combination of the heated extrusion head \n16\n or the build platform \n18\n in any combination of the x-, y-, and z-directions such that the heated extrusion head \n16\n or the build platform \n18\n are moved relative to one another.', 'The materials suitable for use in building the molds by material extrusion, as disclosed herein include polymer resins.', 'In some aspects, the polymer resins include relatively low melting temperature polymers.', 'In some embodiments, the polymer resin is nylon, acrylonitrile butadiene styrene (ABS), polytetrafluoroethylene (PTFE), polyether ether ketone (PEEK), polyetherketoneketon (PEKK), polyphenylene sulfide (PPS), polyamide, polylactic acid (PLA), polyvinyl alcohol (PVA), polycarbonate, a reinforced thermoplastic (e.g., a thermoplastic reinforced with a ceramic, such as sand, carbon, or another component), or another polymer resin.', 'Extrusion is enabled by thermal reduction of the viscosity of the material and, thus, the extrusion temperature will vary depending upon the particular material being extruded.', 'However, some exemplary temperatures include extrusion temperatures of: from about 240° C. to about 270° C. (e.g., for nylon); from about 240° C. to about 300° C. or about 275° C. (e.g., for PTFR); at least about 340° C. (e.g., for PEEK or PEKK); at least about 280° C. (e.g., for PPS), at least about 350° C. (e.g., for polyamide), about 230° C. (e.g., ABS), or below about 230° C. (e.g., for PLA, PVA, and polycarbonate.', 'In some aspects, the extrusion temperature ranges from about 150° C. to 450° C., or from about 200° C. to about 400° C., or from about 250° C. to about 350° C., or anywhere therebetween.', 'In some aspects, the melting temperature of the extruded material (e.g., thermoplastic) will be less than 500° C., or less than 450° C., or less than 400° C., or less than 350° C., or less than 300° C., or less than 250° C.\n \nFIG.', '1F\n is a simplified schematic of a material extrusion process, including dispensing filament, box \n41\n; melting filament, box \n43\n; extruding melted filament, box \n45\n; and depositing extruded filament, box \n47\n.', 'One skilled in the art would understand that the above discussion of the material extrusion process is for exemplary and explanatory purposes, and that the methods disclosed herein are not limited to performing these particular steps in this particular order.', 'Rather, one skilled in the art would understand that certain steps combined or eliminated and other steps may be added without departing from the scope of this disclosure.', 'Combining Powder Metallurgy with Material Extrusion\n \nThe present disclosure provides for a method and system for forming parts using both powder metallurgy and additive manufacturing processes and apparatus.', 'FIG.', '2A\n depicts one exemplary schematic of a system that includes both powder metallurgy apparatus and additive manufacturing apparatus.', 'System \n200\n may be used to build a “green part”, that is, a part that is formed and compacted to have the same shape and size, or at least substantially the same shape and size, as the final, deployable part, but is not yet processed to a final state (e.g., a final density and/or strength) that is typically suitable for deployment and service of the part.', 'System \n200\n includes least two heads, including at least one head for the 3D printing (i.e., extrusion head \n206\n) a mold and at least one other head (i.e., deposition head \n216\n) for powder deposition in a powder metallurgy process of forming a final part.', 'Each such head of system \n200\n may be capable of and programmed to articulate along three axes (i.e., the x-, y- and z-axis).', 'As discussed in more detail below, the position of each such head along the three axes and the usage of each head (e.g., when and where material is extruded or deposited) may be controlled and coordinated using computer software and electronics.', 'The powder metallurgy and material extrusion system, system \n200\n, includes material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n.', 'Material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n are arranged in positional relationship with one another such that the apparatus may be used to form mold portions \n208\na\n-\n208\nc \nand to form part portions \n209\na\n-\n209\nc \nor layers \n212\nb \nand \n214\nb \nthereof, respectively, as is described in more detail below.', 'Material extrusion apparatus \n201\n includes material spool \n205\n having filament \n202\na \n(e.g., polymer filament) of a material spooled thereon.', 'Material extrusion apparatus \n201\n includes extrusion head \n206\n.', 'Extrusion head \n206\n is positioned to receive filament \n202\na\n, which is fed into extrusion head \n206\n from guide \n241\n.', 'Extrusion head \n206\n is heated, such that the material of filament \n202\na \nbecomes molten within extrusion head \n206\n or at least upon exit from nozzle \n207\n of extrusion head \n206\n.', 'Thus, the material of filament \n202\na \nexits nozzle \n207\n as molten filament \n202\nb\n.', 'Extrusion head \n206\n is capable of moving in the x-, y-, and z-directions.', 'In operation, while extruding molten filament \n202\nb\n, extrusion head \n206\n moves in the x- and y-directions to deposit a layer of the material of molten filament \n202\nb \nwithin a plane defined in the x- and y-directions.', 'After deposition of a layer of the material of molten filament \n202\nb \nwithin a plane defined in the x- and y-directions, extrusion head \n206\n moves in the z-direction to deposit another layer of the material of molten filament \n202\nb \nwithin a plane defined in the x- and y-directions.', 'This subsequent layer is deposited on top of the former layer.', 'Extrusion head \n206\n may be programmed (as discussed in more detail below) to deposit extruded molten filament \n202\nb \nat only the positions along the x-, y-, and z-directions that correspond with a portion of the mold to be formed.', 'As such, material extrusion apparatus \n201\n is used to build mold portions \n208\na\n-\n208\nc \non a layer-by-layer basis on build platform \n218\n.', 'As shown in \nFIG.', '2A\n, mold portions \n208\na \nare completely formed mold portions that surround built part portions \n209\na \nand \n209\nb \nof the part, and mold portion \n208\nb \nis in the process of being formed by deposition of extruded molten filament \n202\nb\n.', 'Mold portion \n208\nb \nsurrounds the deposited portions of material of unbuilt portion \n209\nb \nof the part.', 'Also shown, in hidden lines, is mold portion \n208\nc\n, which has not been formed yet.', 'Powder metallurgy apparatus \n203\n includes first hopper \n210\na \ncontaining first powder (or powder mixture) \n212\na\n, and second hopper \n210\nb \ncontaining second powder (or powder mixture) \n214\na\n.', 'Powder metallurgy apparatus \n203\n includes deposition head \n216\n, including deposition nozzle \n217\n.', 'First hopper \n210\na \nand second hopper \n210\nb \nare arranged in positional relationship with one another and with deposition head \n216\n such that first hopper \n210\na \nand second hopper \n210\nb \ndispense first powder \n212\na \nand second powder \n212\nb\n, respectively, into deposition head \n216\n.', 'Deposition head \n216\n is capable of moving in the x-, y-, and z-directions.', 'In operation, while depositing powder \n223\n, deposition head \n216\n moves in the x- and y-directions to deposit a layer or zone of the powder \n223\n.', 'After deposition of powder \n223\n, deposition head \n216\n may move in the z-direction to deposit another layer or zone of powder \n223\n, which may be deposited on top of the previously deposited powder.', 'For example, formed portion \n209\na \nof the part is depicted as including at least two layers.', 'A first layer of formed portion \n209\na \nof the part includes second material \n214\nb\n, and a second layer of formed portion \n209\na \nof the part includes first material \n212\nb\n.', 'First and second layers of formed portion \n209\na \nof the part may be bonded together.', 'Formed parts may also be formed of the same material throughout.', 'For example, formed portion \n209\nb \nof the part is depicted as a single layer part including first material \n212\nb\n.', 'Deposition head \n216\n may also operate to deposit different powders or mixtures at different positions within the same x-y plane, such that deposition head \n216\n deposits powder \n223\n in one zone in an x-y plane, and then deposition head \n216\n moves in the x- and y-direction within that same x-y plane and deposits another powder or mixture in a different zone within that same x-y plane.', 'For example, \nFIG.', '2C\n depicts a top view of a part \n209\nd \ncomposed of different compositions \n215\na \nand \n215\nb \nlocated in different zones within part \n209\nd \nwithin the x-y plane.', 'Thus, the composition and properties of a formed part, from layer to layer and within each layer, may be varied using the powder metallurgy process disclosed herein.', 'Deposited powder \n223\n may be first powder \n212\na\n, second powder \n214\na\n, or a mixture thereof.', 'Deposition head \n216\n may be programmed (as discussed in more detail below) to deposit powder \n223\n at only the positions along the x-, y-, and z-directions that correspond with a portion of the part to be formed.', 'As such, powder metallurgy apparatus \n203\n is used to build parts (e.g., portions of part \n209\na\n, \n209\nb\n, and \n209\nc\n) on a layer-by-layer basis.', 'As shown in \nFIG.', '2A\n, mold portions \n208\na \nare completely formed mold portions that surround built part portions \n209\na \nand \n209\nb\n, and mold portion \n208\nb \nis in the process of being formed by deposition of the material of extruded molten filament \n202\nb\n.', 'Mold portion \n208\na \nsurrounds the built part portion \n209\na\n, and mold portion \n208\nb \nsurrounds built part portion \n209\nb\n.', 'The formed portions of mold \n208\nc \nsurround the deposited portions of powder of unbuilt part portion \n209\nc\n.', 'Also shown, in hidden lines, is mold portion \n208\nc\n, which has not been formed yet.', 'In certain aspects, material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n operate concurrently to form mold portions \n208\na\n-\n208\nc \nand part portions \n209\na\n-\n209\nc \n(or layers thereof), respectively.', 'In some such aspects, the concurrent operation of material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n includes simultaneously building the mold using material extrusion apparatus \n201\n and the part using powder metallurgy apparatus \n203\n.', 'That is, the extrusion head \n206\n and deposition head \n216\n simultaneously extrude and deposit, respectively, the extruded filament \n202\nb \nand powder \n223\n, respectively.', 'Thus, as a layer of mold is formed by material extrusion, a layer of powder material is concurrently deposited therein.', 'In other such aspects, the concurrent operation of material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n includes sequential cycles of operation of the material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n.', 'That is, the extrusion head \n206\n extrudes the extruded filament \n202\nb \nto form a portion (e.g., layer) of the mold, followed by the deposition head \n216\n depositing powder to form a portion (e.g., layer) of the part, subsequently followed by the extrusion head \n206\n extruding the extruded filament \n202\nb \nto form another portion (e.g., layer) of the mold, and so forth until the part and mold are fully built.', 'Thus, in at least some aspects, the mold is not full built upon the beginning of powder deposition by deposition head \n216\n.', 'In other aspects, the mold may be built via 3D printing prior to building the part within the mold via powder metallurgy.', 'FIG.', '2B\n depicts a top view of an exemplary mold, including built mold portion \n208\nd \nand unbuilt mold portion \n208\ne\n.', 'Using the material extrusion process disclosed herein, the mold may be constructed to have various features, including features of complex geometry.', 'The molds disclosed herein may, thus, be used to build parts having various features, including features of complex geometry.', 'As shown in \nFIG.', '2B\n, mold \n208\nd \nincludes mold body \n222\n having holes \n220\n defining space where powder is not deposited when forming a part.', 'In some aspects, material extrusion apparatus \n201\n includes controller \n211\n in electronic and/or data communication with one or more portions of material extrusion apparatus \n201\n, such as with material spool \n205\n and/or extruder head \n206\n and/or build platform \n218\n.', 'Controller \n211\n may control operation and movement of material spool \n205\n, extruder head \n206\n and build platform \n218\n through the use of software with control algorithms and data and/or control signals transmitted to material spool \n205\n, extruder head \n206\n, and build platform \n218\n.', 'For example, controller \n211\n may have a CAD design file (STL file) that defines the size, shape and position of molds, such that controller \n211\n controls the dispensing of material from spool \n205\n, the extrusion of material from head \n206\n, and the position of head \n206\n and build platform \n218\n based on the CAD design file of the mold.', 'In some aspects, powder metallurgy apparatus \n203\n includes controller \n231\n in electronic and/or data communication with one or more portions of powder metallurgy apparatus \n203\n, such as with material hoppers \n210\na \nand \n210\nb \nand/or head \n216\n.', 'Controller \n231\n may control operation and movement of hoppers \n210\na \nand \n210\nb \nand head \n216\n through the use of software with control algorithms and data and/or control signals transmitted to hoppers \n210\na \nand \n210\nb \nand head \n216\n.', 'For example, controller \n231\n may have a CAD design file (STL file) that defines the size, shape, composition of, and position of part, such that controller \n231\n controls the dispensing of powder from hoppers \n210\na \nand \n210\nb\n, the deposition of powder from head \n216\n, and the position of head \n216\n based on the CAD design file of the part.', 'While material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n are shown as including separate controllers, controllers \n211\n and \n231\n, one skilled in the art would understand that the same controller may be used to control both material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n and to coordinate the operations thereof.', 'Furthermore, in embodiments with two controllers, as shown in \nFIG.', '2A\n, the two controllers may be in communication (e.g., data communication) such that operations controlled by the two controllers may be coordinated, or the two controllers may be programmed such that operations of material extrusion apparatus \n201\n and powder metallurgy apparatus \n203\n are coordinated.', 'One skilled in the art would understand that the powder metallurgy and material extrusion system and method of use described with reference to \nFIG.', '2A\n is for exemplary and explanatory purposes, and that the systems and methods disclosed herein are not limited to inclusion of these particular parts, steps, or arrangement of parts and steps.', 'Rather, one skilled in the art would understand that certain parts or steps may be combined or eliminated and other parts or steps may be added without departing from the scope of this disclosure.', 'For example, the powder metallurgy and material extrusion system may include more than one material extrusion head, more than one powder deposition head, and more or less than two hoppers (or any other powder dispensing apparatus).', 'Furthermore, other particular equipment may be used to concurrently form the mold and part therein.', 'Sintering\n \nAfter forming the “green parts”, as shown in \nFIG.', '2A\n, the molded green part is subjected to conditions (e.g., temperature and/or pressure conditions) that result in the fusing of the particles of the compacted power material, such that a consolidated, bulk, solid part is formed.', 'For example, in some such aspects, the molded green part is subjected to sintering to fuse the particles of the compacted power material and form the solid part.', 'The sintering may include subjecting the molded green part to hot isostatic pressing (HIP), where the molded green part is heated, such as in an oven, at a suitable process temperature that facilitates the fusion of the powder material.', 'One skilled in the art would understand that the particular temperature or temperature range suitable for fusing the powder material may vary depending on, for example, the composition of the powder.', 'The conditions (e.g., temperature and/or pressure) suitable for fusing the particles of the compacted power material together are also suitable for separating the mold from the green part.', 'For example, the conditions (e.g., temperature and/or pressure) suitable for fusing the particles of the compacted power material together may also be suitable for melting and/or evaporating and/or burning the mold from the green part.', 'As such, during subjection of the molded green part to conditions that result in the fusing of the particles of the compacted power material, the material of which the mold is composed (e.g., polymer resin) is removed (e.g., melted and/or evaporated and/or burned) from the green part.', 'The material of which the mold is composed may be selected to be a material that melts and/or evaporates and/or burns at a relatively lower temperature in comparison to the temperature at which the powder material would melt and/or evaporate and/or burn.', 'The material of which the mold is composed may melt and/or evaporate and/or burn at a lower temperature than the sintering temperature of the powder material.', 'Thus, while heating the molded green part to sinter the green part, but prior to the sintering of the powder material occurring, the mold melts and/or evaporates and/or burns away from the part.', 'As such, in some aspects, the material of which the mold is composed does not fuse, or at least does not substantially fuse, with the powder material during such fusion (e.g., sintering) processing.', 'In some aspects, after the outside shell material (mold) melts or at least begins melting, pressure may be increased to hold and fuse the powder material at a temperature that is higher than that at which the mold begins to melt.', 'As would be understood by one skilled in the art, the temperature and pressure conditions at which a part is sintered varies depending upon the material being sintered.', 'For example, to sinter a part from certain nickel alloys, temperatures of about 2150° F. and pressures of about 10,000 psi may be used to sinter the material into a part.', 'During HIP processing, the molded green part is subjected to hydrostatic pressures via addition of an inert gas, which facilitates proper fusion of the powder materials and reduces or eliminates porosity in the final, formed part.', 'Using these methods, a final, formed part is thus produced, and may be subjected to one or more standard post-processing steps.', 'While HIP processing has been specifically described, one skilled in the art would understand that sintering may include liquid phase sintering, electric current assisted sintering, spark plasma sintering, electro sinter forging, or other suitable sintering processes.', 'As the mold is removed via melting and/or evaporation and/or burning, the present methods reduce or eliminate the use of machining for removal of the mold from the part.', 'As would be understood by one skilled in the art, the temperature at which the mold material is decomposed will vary depending upon the pressure and the particular material.', 'Decomposition (e.g., melting, evaporation, burning) of the mold material is facilitated at low pressures, including vacuum.', 'For example, a mold of PTFE will degrade at temperatures above about 360° C., such as 500° C.\n \nWith reference to \nFIG.', '3\n, an exemplary sintering process is shown and described.', 'First, molded green part \n317\n, including part \n309\n and mold \n308\n, is placed into sintering apparatus \n399\n (e.g., an oven).', 'Within sintering apparatus \n399\n, molded green part \n317\n is subjected to temperature and/or pressure conditions \n397\n that result in the fusing of the particles of the compacted power material, such that a consolidated, bulk, solid part \n319\n is formed and mold \n308\n is degraded to melted and/or evaporated and/or burned material \n318\n.', 'Consolidated, bulk, solid part \n319\n may then be removed from sintering apparatus \n399\n and optionally subjected to standard post-processing steps \n395\n to form final, finished part \n321\n suitable for deployment and service in the field, such as in a downhole environment.', 'As would be understood by one skilled in the art, the temperature at which a part sinters will vary depending on the particular material being sintered.', 'For example, sintering tungsten carbide with at least 6 to 40 wt. % of a metal binder will vary depending upon the particular metal binder.', 'Temperatures above about 1400° F. will sinter tungsten carbide with 6 to 40 wt. % of a copper binder, temperatures above about 2000°', 'F. (e.g., 2000 to 3000° F.) will sinter tungsten carbide with 6 to 40 wt. % of a nickel and cobalt binder.', 'The sintering may occur in an inert atmosphere, including at vacuum conditions.', 'In HIP processing, pressurizing results in a reduced porosity, promotes flow, and results in better material properties, including transverse rupture strength of the resulting part.', 'Sintering pressures during HIP processing may be as high as 30,000 psi for carbides.', 'In other aspects, the pressures during HIP processing may be from about 10,000 to about 15,000 psi.', 'One skilled in the art would understand that the pressured used during HIP processing may vary depending upon the particular materials and desired results.', 'One skilled in the art would understand that the above discussion of the sintering process is for exemplary and explanatory purposes, and that the methods disclosed herein are not limited to performing these particular steps in this particular order.', 'Rather, one skilled in the art would understand that certain steps combined or eliminated and other steps may be added without departing from the scope of this disclosure.', 'Designing and Building Parts and Molds\n \nFIG.', '4\n is a flow chart of steps of the present method.', 'Method \n400\n of building a part includes “part model and software coordination”, box \n410\n.', 'For example, a model of a part (part model), including the necessary material content thereof, may be identified, designed, and developed using computer aided design (CAD) software.', 'The features of a mold necessary to form the part may be extracted from the thus designed CAD model of the part to form a corresponding CAD model of the mold that has an internal contour that matches the external contour of the part.', 'The CAD model of the mold may be transmitted to, formed within, or otherwise input into 3D printer equipment including 3D printer software (e.g., transmitted to computer/controller \n211\n that controls the extruder head \n206\n).', 'The material composition identified as suitable for forming the part may be fed into the powder metallurgy apparatus (e.g., into hoppers \n210\na \nand \n210\nb \nof apparatus \n203\n).', 'Method \n400\n includes, equipment layering and green part build, box \n420\n.', 'The powder materials are fed by the powder nozzle (e.g., nozzle \n217\n) from the hoppers into the formed portions of the mold.', 'The outside wall features, that is the mold, is 3D printed by operation of the filament nozzle (e.g., nozzle \n207\n) depositing molten material (e.g., molten polymer) to form the walls of the mold, which contains the deposited powder.', 'The building of the part and mold is performed on a layer-by-layer basis.', 'For example, in some such aspects, each successive layer built has a thickness ranging from 20 to 100 microns.', 'One skilled in the art would understand that the layers may have thickness outside of this range, including thickness less than 20 microns and thickness greater than 100 microns, depending on the particular application.', 'In operation, the 3D printing software of the controller(s) of the material extrusion apparatus and powder metallurgy apparatus defines and controls, via controlling the heads \n206\n and \n216\n and associated equipment, the successive layering of the mold and successive deposition of the powder material required per layer of the mold.', 'Such 3D printing software may function to sequence the coordination of the heads \n206\n and \n216\n, as required.', 'The method \n400\n includes powder sintering/HIP, box \n430\n.', 'The molded, green part is subjected to sintering or HIP processing for fusion of the powder materials.', 'During sintering or HIP processing, the temperature is at the sintering/melting temperature of the powder or infiltrate to cause fusion thereof.', 'Pressure may also be applied during sintering or HIP processing to enable fusion of the powders and remove porosities in the part.', 'During the sintering process, the relatively low-temperature mold material melts and/or evaporates and/or burns; thereby, exposing the powder material and enabling and/or facilitating fusion of the powder material to obtain the final sintered part, box \n440\n.', 'Thus, the entire molded part (i.e., the mold and the part, together) may be post-processed by sintering, including hot isostatic pressing, such that the mold is burned off, melted of, and/or evaporated off of the consolidated powder to form the solid part.', 'The method disclosed herein provides for the concurrent, layer-by-layer powder metallurgy and material extrusion for concurrent fabrication of molds and molded parts.', 'With 3D printing of the mold, the method provides for the formation of parts, such as tools, of relatively complicated shapes, nested shapes, and lattice structures.', 'With the powder deposition controlled separately from control of the material extrusion, different powder materials can be deposited in different layers and distributed across different positions within a part.', 'Changes in the composition of the powder deposited, if used, can be gradient changes, such that the part formed thereby has a gradient compositional profile.', 'For example, \nFIG.', '5A\n depicts part \n509\na \nhaving a gradient compositional profile, where the composition of part \n509\na \ngradually changes along the part \n509\na \nin at least one direction, from material \n571\n to material \n573\n.', 'Also, changes in the composition of the powder deposited, if used, can be abrupt, step changes, such that the part formed thereby can has abrupt changes in composition.', 'For example, \nFIG.', '5B\n depicts part \n509\nb \nhaving a compositional profile with abrupt changes, where the composition of part \n509\nb \nabruptly changes along the part \n509\nb \nin at least one direction, from material \n571\n to material \n573\n, forming layers or zones composed of material \n571\n that are discrete from layers or zones composed of material \n573\n.', 'One skilled in the art would understand that the compositional profile may be varied in many different ways to produce parts of homogenous composition, inhomogeneous composition, continuous phase/discontinuous phase composition, or other variations in compositional make up and constituency.', 'Thus, the present disclosure provides for systems and methods for building, layer-by-layer, a mold contour using 3D printing and concurrently filling the mold with powder, such that the composition of each layer is customizable.', 'The method may be implemented, in some aspects, to construct tailored, precise parts, such as oilfield parts, relatively quickly and at a relatively low costs in comparison to at least some other additive manufacturing processes.', 'One skilled in the art would understand that the above discussion of the method is for exemplary and explanatory purposes, and that the methods disclosed herein are not limited to performing these particular steps in this particular order.', 'Rather, one skilled in the art would understand that certain steps combined or eliminated and other steps may be added without departing from the scope of this disclosure.', 'Parts\n \nThe methods disclosed herein may be used to form any number of different types of parts of varying compositions, shapes, sizes, and properties.', 'The methods disclosed herein may be used to form cutting bits, piezoelectric sensing parts, composite parts, graded material parts, axial pulse generators, drill bits, bearings, impellers/diffusers, turbines, flow diverters, or other oilfield tools and components.', 'In some embodiments, the part may be a multi-functional part formed to exhibit wear and/or corrosion resistant.', 'While discussed primarily with respect to oilfield parts and oilfield-related applications, one skilled in the art would understand that the present methods and systems are not limited to being used in the formation of such oilfield-related parts, and may be used to other parts for other applications.', 'In some aspects, the parts formed in accordance with the present disclosure include rotating parts, such as bits, bearing, bushings, thrusts washers, turbines, cutters (i.e., bits included for coring), rotors, stators, blenders, mixers, gears, cams, pump stages, shafts, and sleeves.', 'The parts formed in accordance with the present disclosure may include non-rotating parts, such as wear bands, pads, stabilizers, centralizers, collars (e.g., drill collars), fasteners (e.g., nuts and bolts), threaded rings, valve seats, inserts, seals (e.g., face seals), sucker rods, collets, anchors, mandrels, housings, tubulars, protectors, connectors, ferrules, pins, nozzles, screens and filters, and heat exchangers.', 'Exemplary Parts—Degradable\n \nThe methods disclosed herein may be used to form degradable parts for use in downhole environments.', 'For example, the powder material may be a degradable material, such as a degradable metal, degradable ceramic, or degradable composite.', 'In some such aspects, layered structures of materials with different electrical potentials are built using the methods disclosed herein.', 'Such methods may include formation of the mold via 3D printing and, concurrently with the formation of the mold, depositing a layer of a first material followed by depositing a layer of a second material, with the first and second materials characterized as having different electrochemical potentials, such that the part made therefrom degrades galvanically in water-based environments.', 'Thus, the methods disclosed herein may be used to produce graded materials that are degradable in water-based environments, including a layer of an anode material, followed by a layer of a cathode material and/or a layer of blended of powers that contain both anodes and cathodes.', 'FIG.', '6A\n shows such a part \n602\n, formed of first material \n601\n and second material \n603\n having different electrochemical potentials.', 'One skilled in the art would understand that the selection and number of materials, and the shape of the part may be modified depending on the particular application.', 'Part \n602\n, as shown in \nFIG.', '6A\n, is depicted for exemplary purposes.', 'Exemplary Parts—Smart\n \nIn some aspects, the methods disclosed herein may be used to form “smart parts”.', 'As used herein, a “smart part” is a part composed at least partially or fully of at least one “smart material.”', 'One skilled in the art would understand that a smart material is a material that exhibits at least one property that is responsive, in a controlled manner, to external conditions, including stress, temperature, moisture, pH, electric fields, or magnetic fields, light, or chemical compounds.', 'To form a smart part, a powder of a smart material may be deposited and processed via powder metallurgy methods in accordance with the present discourse.', 'Such smart parts may include, but are not limited to, pressure sensitive smart parts, such as valves that open and close, leading to changes in pressure and resulting in the formation of electrical signals via piezoelectric signals.', 'In some aspects, the smart materials include piezoelectric cement-based materials, or polymeric materials.', 'In certain aspects, piezoelectric ceramic powders may be deposited within a matrix material to form a smart part that is sensitive to pressure.', 'FIG.', '6B\n shows such a part \n612\n, formed of non-smart material \n611\n and smart material \n613\n.', 'One skilled in the art would understand part \n612\n, as shown in \nFIG.', '6B\n, is depicted for exemplary purposes.', 'Parts—Exemplary Parts\n \nFIGS.', '7A-7D\n illustrate the successive buildup of one exemplary part, an axial pulse generator \n700\nd \nfor use in drilling tools, via powder metallurgy methods concurrently with the successive buildup of the associated mold \n701\n via 3D printing.', 'In \nFIGS.', '7A-7D\n, the part and mold are shown in isolation from the systems used to build the part and mold.', 'One skilled in the art would understand that the present methods are not limited to construction of axial pulse generators, and may be used to form other parts for other applications.', 'With reference to \nFIGS.', '7A-7D\n, axial pulse generator \n700\na \nis shown partially constructed in \nFIG.', '7A\n with mold \n701\n partially constructed and a first material \n702\n deposited to fill the void defined by the, thus far, constructed portions of mold \n701\n.', 'FIG.', '7B\n depicts axial pulse generator \n700\nb \nand associated mold \n701\n further constructed relative to \nFIG.', '7A\n, and \nFIG.', '7C\n is a cross-sectional view of \nFIG.', '7B\n.', 'Portions of mold \n701\n have first material \n702\n deposited therein to fill the void defined by those portions of mold \n701\n, and other portions of mold have second material \n704\n deposited therein to fill the void defined by those portions of mold \n701\n not filed by first material \n702\n.', 'FIG.', '7C\n also indicates the remaining portions \n706\n (hidden lines) of the axial pulse generator \n700\nc \nand mold \n701\n that need to be built to compete construction of the part.', 'FIG.', '7D\n depicts the completed part, axial pulse generator \n700\nd \nafter completion of construction and removal of the mold \n701\n.', 'Also indicated are the fluid flow lines \n710\n and \n712\n through axial pulse generator \n700\nd \nand the axial movement \n714\n of the axial pulse generator \n700\nd\n.', 'First material \n702\n and second material \n704\n may be selected to have desired properties, depending on the particular application.', 'Furthermore, the position of each material within axial pulse generator \n700\nd \nmay be selected depending on the particular application, such as the expected conditions for which the part or that portion of the part will be subjected to in a downhole environment.', 'For example, and without limitation, first material \n702\n may be a relatively tough material selected to provide impact resistance to the portions of axial pulse generator \n700\nd \ncomposed of first material \n702\n, and second material \n704\n may be a relatively hard material selected to provide erosion and/or wear resistance to the portions of axial pulse generator \n700\nd \ncomposed of second material \n704\n.', 'Thus, in this exemplary scenario, it is required or desired that axial pulse generator \n700\nd \nbe composed of a relativize hard material for wear/erosion resistance on the fluid flow side, and of a relatively tough material capable of withstanding impacts due to the flow pulsations at other locations.', 'As such, each portion of a part may be designed and built to exhibit a different property and/or to provide a different functionality to the part.', 'Each portion of a part may be designed and built to exhibit thermal, electrical, mechanical, chemical, and any other physical property that is the same as or different than other portions of the part.', 'For example, some portions of a part may include a smart material while other portions do not include a smart material, some portions of a part may include a degradable material while other portions do not include a degradable material, some portions of a part may include a thermal insulator while other portions include a thermal conductor, and some portions of a part may include an electrical insulator while other portions include an electrical conductor.', 'One skilled in the art would understand that the number and type of such property variations within a part may depend on the particular application of the part.\n \nFIG.', '8\n depicts another, final, sintered part \n800\n in accordance with some aspects of the present disclosure.', 'Part \n800\n includes through-hole \n802\n, blind hole \n804\n, through-hole \n806\n, and through-hole \n808\n, each positioned through body \n810\n of part \n800\n.', 'FIG.', '8\n illustrates some of the complex features that can be integrally built into the parts in accordance with the present disclosure.', 'FIG.', '8\n is representative of the final form of the part shown being manufactured in \nFIG.', '2A\n.', 'Applications', 'The method disclosed herein may be used to design and produce parts having improved functionality at a cost and rate of production that is, in at least some aspects, superior to that attainable by conventional additive manufacturing techniques.', 'In some aspects, the methods disclosed herein are used to manufacture oilfield tools capable of being subjected to relatively harsh operating conditions while fulfilling multiple functionalities without failure of the oilfield tool, such as corrosion resistance, wear resistance, the ability to bear relatively heavy loads, the ability to bear relatively heavy/high impacts, or combinations thereof.', 'The manufacturing methods disclosed herein may be used to form parts that are composed of multiple, different materials at desired locations to meet the desired functional requirements of the part.', 'The methods and systems disclosed herein may also be applied to other, non-oilfield related applications.', 'Equipment\n \nCertain aspects of the present disclosure relate to equipment, including systems and/or apparatus suitable for forming parts in accordance with the methods disclosed herein.', 'The system may include at least one material extrusion head that moves on a 3-axis, enabling the building of a mold wall by controlled extrusion of heated polymer through a nozzle.', 'The system may include at least one powder deposition head that moves on a 3-axis that dispenses a powder material or desired combination of powders from at least one or multiple powder dispensers (e.g., hoppers).', 'The system may include software and control electronics that facilitate the building of the final green part, such as by slicing the CAD model of the part suitably, layer-by-layer, and creating the mold and powder location features.', 'As used herein, ‘slicing the CAD model” refers to apportioning a 3D CAD model of the part and/or the mold into sections or layers that correspond with the layers of the part and mold to be built using the system disclosed herein (e.g., CAD model sections that correspond with a 20-100 micron layers of the mold and part to be built).', 'As such, the system builds a first layer of the mold and part in accordance with a first slice of the 3D CAD model of the mold and part, and subsequently builds a second layer of the mold and part in accordance with a second slice of the 3D CAD model of the mold and part, as so forth until the mold and part are fully built in accordance with the full 3D CAD model of the mold and part.', 'The software and control electronics control the movement and position of the nozzle heads, control the extrusion of the material to build the mold wall, and control the powder deposition, all based on the CAD model(s) and on a layer-by-layer (and CAD model slice-by-CAD model slice) basis.', 'One skilled in the art would understand that the system disclosed herein may include additional features, apparatus, and parts, and is not limited to these particular components.', 'Method of Using Parts\n \nCertain aspects of the present disclosure provide for a method of using a part formed in accordance with the present disclosure.', 'The method includes providing a part formed in accordance the methods disclosed herein, and deploying the part, such as in a downhole environment.', 'Green Molded Part\n \nSome aspects of the present disclosure provide for a molded green part.', 'The molded green part includes a powder material (e.g., a compacted powder material) molded by a polymeric mold.', 'The polymeric mold is formed via 3D printing, and the powder material is deposited therein via powder metallurgy techniques.', 'Although the present embodiments and advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure.', 'Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification.', 'As one of ordinary skill in the art will readily appreciate from the disclosure, processes, machines, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized according to the present disclosure.', 'Accordingly, the appended claims are intended to include within their scope such processes, machines, manufacture, compositions of matter, means, methods, or steps.'] | ['1.', 'A method of making a part using powder metallurgy and material extrusion, the method comprising:\nforming a mold of a first material using material extrusion;\ndepositing a second material within the mold, wherein the second material is deposited into the mold in powder form;\ncompacting the second material within the mold;\nheating the mold and the second material within the mold, wherein, during the heating the mold is separated from the second material by melting, evaporating, burning, or combinations thereof of the first material, and wherein during the heating the second material is sintered; and\nobtaining a part.', '2.', 'The method of claim 1, the sintering includes hot isostatic pressing.', '3.', 'The method of claim 1, wherein the first material melts, evaporates, burns, or combinations thereof at a lower temperature than the temperature at which the second material sinters.', '4.', 'The method of claim 1, wherein the first material is a polymer resin, and wherein second material is a metal powder, a metal alloy powder, a ceramic powder, or combinations thereof.', '5.', 'The method of claim 1, wherein the method includes extruding the first material from at least one extrusion head to form the mold, and depositing the second material from at least one deposition head into the mold.', '6.', 'The method of claim 5, wherein the method includes articulating the at least one extrusion head along three axes during extrusion of the first material, and articulating the at least one deposition head along three axes during deposition of the second material.', '7.', 'The method of claim 1, wherein the forming of the mold and the deposition of the second material are performed concurrently.', '8.', 'The method of claim 7, wherein the method includes concurrent extrusion of the first material and deposition of the second material, including extruding the first material to form the mold while simultaneously depositing the second material into formed portions of the mold.', '9.', 'The method of claim 7, wherein the method includes concurrent extrusion of the first material and deposition of the second material, including sequential cycles of extrusion of the first material to form a portion of the mold and deposition of the second material into the formed portion of the mold.', '10.', 'The method of claim 1, wherein the mold is formed layer-by-layer and the second material is deposited layer-by-layer, including:\nextruding first layer of the first material to form a first portion of the mold;\ndepositing a first portion of the second material within the first portion of the mold;\nextruding second layer of the first material to form a second portion of the mold; and\ndepositing a second portion of the second material within the second portion of the mold.', '11.', 'The method of claim 1, wherein the part is at least partially degradable, and wherein the second material is a degradable material.\n\n\n\n\n\n\n12.', 'The method of claim 1, the part is a smart part, and wherein the second material is a smart material.', '13.', 'The method of claim 1, wherein the part is a cutting bit, a piezoelectric sensing pars, a composite part, a graded material part, an axial pulse generator, a drill bit, a bearing, an impeller/diffuser, a turbine, a flow diverter, a bushing, a thrust washer, a rotor, a stator, a blender, a mixer, a gear, a cam, a pump stage, a shaft, a sleeve, a wear band, a pad, a stabilizer, a centralizer, a collar, a fastener, a threaded ring, a valve seat, an insert, a seal, a sucker rod, a collet, an anchor, a mandrel, a housing, a tubular, a protector, a connector, a ferrule, a pin, a nozzle, a screen, a filter, or a heat exchanger.', '14.', 'The method of claim 1, wherein a third material is deposited into the mold, and wherein the second material and the third material exhibit different properties.', '15.', 'The method of claim 14, wherein the third material is deposited in a different position within the mold than the second material.', '16.', 'A method of making a part using powder metallurgy and material extrusion, the method comprising:\nforming a mold of a first material by extruding the first material;\ndepositing a second material into the mold, wherein multiple layers of the second material are deposited in the form of a powder;\nheating the mold and the second material within the mold, wherein, during the heating the mold is separated from the second material by melting, evaporating, burning, or combinations thereof of the first material;\nafter the mold is separated from the second material, increasing pressure and temperature on the second material, wherein during the heating the second material is sintered; and\nobtaining a part, the part comprising the second material.\n\n\n\n\n\n\n17.', 'The method of claim 16, wherein depositing the second material into the mold comprises:\ndepositing a first layer of the second material in powder form into the mold; and\ndepositing a second layer of the second material in powder form into the mold, wherein the second layer is deposited onto the first layer.', '18.', 'The method of claim 1, wherein the second material is deposited from a hopper into the mold.\n\n\n\n\n\n\n19.', 'The method of claim 1, wherein, after the mold is separated from the second material, pressure and temperature on the second material are increased.', '20.', 'A method of making a part using powder metallurgy and material extrusion, the method comprising:\nextruding a first material into the form of a mold;\ndepositing a particulate, in powder form, into the mold, wherein the particulate is a metal or ceramic powder;\ncompacting the metal or ceramic powder within the mold;\nheating the mold and the metal or ceramic powder within the mold, wherein, during the heating the mold is separated from the metal or ceramic powder by melting, evaporating, burning, or combinations thereof of the first material, and wherein during the heating the metal or ceramic powder is sintered; and\nobtaining a part, the part comprising the sintered metal or ceramic powder.'] | ['FIG.', '1A is a simplified flow chart showing steps of a powder metallurgy process.', ';', 'FIG.', '1B is side view depicting powder being deposited into a mold.; FIG.', '1C is a top view of the mold of FIG.', '1B showing compacted powder.; FIG.', '1D is a top view of a part formed after sintering the compacted powder of FIG.', '1C.; FIG.', '1E is a simplified schematic of a material extrusion or fused deposition modelling system.; FIG.', '1F is a simplified flow chart of a material extrusion or fused deposition modelling process.', '; FIG.', '2A is a simplified schematic of a system, including both powder metallurgy and material extrusion apparatus, during concurrent manufacture of a mold and a part.;', 'FIG.', '2B depicts a mold including holes formed through a body thereof.', '; FIG.', '2C depicts a part formed in accordance with certain aspects of the present disclosure.', '; FIG. 3 is a simplified schematic of a process and system of forming parts in accordance with certain aspects of the present disclosure.; FIG. 4 is a simplified flow chart of a process of forming parts in accordance with certain aspects of the present disclosure.', '; FIG.', '5A is a part having a gradient compositional profile.', ';', 'FIG.', '5B is a part having a layered compositional profile with abrupt compositional changes.; FIG.', '6A is a layered degradable part.;', 'FIG.', '6B is a part including a smart material.; FIGS.', '7A-7D', 'depict an axial pulse generator used in drilling tools during and after manufacture thereof in accordance with embodiments of the present method.;', 'FIG. 8 is a sintered part formed in accordance with embodiments of the present method.; FIGS.', '1B-1D are schematics illustrating powder metallurgy.', 'Powder material 32 is dispensed from hopper 30 into mold 34.', 'Within mold 34, powder material 32 is subjected compaction processing, forming compacted powder 38.', 'Compacted powder 38 is then subjected to sintering to form sintered part 42.; FIG.', '1F is a simplified schematic of a material extrusion process, including dispensing filament, box 41; melting filament, box 43; extruding melted filament, box 45; and depositing extruded filament, box 47.; FIG.', '2B depicts a top view of an exemplary mold, including built mold portion 208d and unbuilt mold portion 208e.', 'Using the material extrusion process disclosed herein, the mold may be constructed to have various features, including features of complex geometry.', 'The molds disclosed herein may, thus, be used to build parts having various features, including features of complex geometry.', 'As shown in FIG.', '2B, mold 208d includes mold body 222 having holes 220 defining space where powder is not deposited when forming a part.;', 'FIG. 4 is a flow chart of steps of the present method.', 'Method 400 of building a part includes “part model and software coordination”, box 410.', 'For example, a model of a part (part model), including the necessary material content thereof, may be identified, designed, and developed using computer aided design (CAD) software.', 'The features of a mold necessary to form the part may be extracted from the thus designed CAD model of the part to form a corresponding CAD model of the mold that has an internal contour that matches the external contour of the part.', 'The CAD model of the mold may be transmitted to, formed within, or otherwise input into 3D printer equipment including 3D printer software (e.g., transmitted to computer/controller 211 that controls the extruder head 206).', 'The material composition identified as suitable for forming the part may be fed into the powder metallurgy apparatus (e.g., into hoppers 210a and 210b of apparatus 203).; FIGS.', '7A-7D illustrate the successive buildup of one exemplary part, an axial pulse generator 700d for use in drilling tools, via powder metallurgy methods concurrently with the successive buildup of the associated mold 701 via 3D printing.', 'In FIGS.', '7A-7D, the part and mold are shown in isolation from the systems used to build the part and mold.', 'One skilled in the art would understand that the present methods are not limited to construction of axial pulse generators, and may be used to form other parts for other applications.; FIG.', '8 depicts another, final, sintered part 800 in accordance with some aspects of the present disclosure.', 'Part 800 includes through-hole 802, blind hole 804, through-hole 806, and through-hole 808, each positioned through body 810 of part 800.', 'FIG.', '8 illustrates some of the complex features that can be integrally built into the parts in accordance with the present disclosure.', 'FIG.', '8 is representative of the final form of the part shown being manufactured in FIG.', '2A.'] |
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US11142954 | Pad in bit articulated rotary steerable system | Jan 28, 2019 | Martin Thomas Bayliss | SCHLUMBERGER TECHNOLOGY CORPORATION | Panchal, N. et al.; Robust Linear Feedback Control of Attitude for Directional Drilling Tools; Aug. 2010; All (Year: 2010).; International Search Report and Written Opinion issued in International Patent application PCT/US2015/055079 dated Jan. 22, 2016, 14 pages.; International Preliminary Report on Patentability issued in International Patent application PCT/US2015/055079 dated Apr. 18, 2017, 10 pages. | 6438495; August 20, 2002; Chau; 7228918; June 12, 2007; Evans et al.; 8302705; November 6, 2012; Downton; 8672056; March 18, 2014; Clark et al.; 8875806; November 4, 2014; Williams; 8967296; March 3, 2015; Downton et al.; 9022141; May 5, 2015; Panchal et al.; 9371696; June 21, 2016; Oppelaar; 9835020; December 5, 2017; Bayliss et al.; 10472893; November 12, 2019; Benson; 20030010534; January 16, 2003; Chen; 20030121702; July 3, 2003; Downton et al.; 20070029113; February 8, 2007; Chen; 20070251726; November 1, 2007; Menger; 20080083567; April 10, 2008; Downton et al.; 20090000823; January 1, 2009; Pirovolou; 20090065258; March 12, 2009; Hamilton; 20090266610; October 29, 2009; Farley; 20130000980; January 3, 2013; Dolgin; 20130199844; August 8, 2013; Bayliss et al.; 20140291024; October 2, 2014; Sugiura et al.; 20150330209; November 19, 2015; Panchai; 20160108679; April 21, 2016; Bayliss; 20160186551; June 30, 2016; Dykstra; 20170306702; October 26, 2017; Summers; 20180003026; January 4, 2018; Boone | 2014011463; January 2014; WO; 2014160567; October 2014; WO | ['A rotary steerable system (RSS) including an upper stabilizer connected to a collar of a drill string, an articulated section connected by a flexible joint to the collar, a drill bit connected to the articulated section opposite from the flexible joint, a lower stabilizer located proximate to the flexible joint and an actuator located with the articulated section and selectively operable to tilt an axis of the drill bit and the articulated section relative to the collar.', 'A method includes drilling with the RSS a bias phase of a drilling cycle on a demand tool face and drilling a neutral phase of the drilling cycle on a 180 degree offset tool face from the demand tool face.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a divisional application of U.S. patent application Ser.', 'No. 14/875,770, filed on Oct. 6, 2015, which claims priority to and the benefit of US Provisional Application No. 62/064,408, filed on Oct. 15, 2014, the entire contents of both of which are hereby incorporated by reference herein.', 'BACKGROUND\n \nThis section provides background information to facilitate a better understanding of the various aspects of the disclosure.', 'It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.', 'An oil or gas well often has a subsurface section that is drilled directionally, i.e., inclined at an angle with respect to the vertical and with an inclination having a particular compass heading or azimuth.', 'A typical procedure for drilling a directional wellbore is to remove the drill string and drill bit by which the initial, vertical section of the well was drilled using conventional rotary drilling techniques, and run in a mud motor having a bent housing at the lower end of the drill string which drives the bit in response to circulation of drilling fluid.', 'The bent housing provides a bend angle such that the axis below the bend point, which corresponds to the rotation axis of the bit, has an inclination with respect to the vertical.', 'A “toolface” angle with respect to a reference, as viewed from above, is established by slowly rotating the drill string and observing the output of various orientation devices until the desired azimuth or compass heading is reached.', 'The mud motor and drill bit are then lowered (i.e., the weight of the drill string is loaded onto the drill bit) with the drill string non-rotatable to maintain the selected toolface, and the drilling fluid pumps are energized to develop fluid flow through the drill string and mud motor.', 'The mud motor converts the hydraulic energy of the drilling fluid into rotary motion of a mud motor output shaft that drives the drill bit.', 'The presence of the bend angle causes the bit to drill on a curve until a desired borehole inclination has been established.', 'Once the desired inclination is achieved at the desired azimuth, the drill string is then rotated so that its rotation is superimposed over that of the mud motor output shaft, which causes the bend section to merely orbit around the axis of the borehole so that the drill bit drills straight ahead at whatever inclination and azimuth have been established.', 'Various problems can arise when sections of the wellbore are being drilled with a mud motor and the drill string is not rotating.', 'The reactive torque caused by operation of a mud motor can cause the toolface to gradually change so that the borehole is not being deepened at the desired azimuth.', 'If not corrected, the wellbore may extend to a point that is too close to another wellbore, the wellbore may miss the desired subsurface target, or the wellbore may simply be of excessive length due to “wandering.”', 'These undesirable factors can cause the drilling costs of the wellbore to be excessive and can decrease the drainage efficiency of fluid production from a subsurface formation of interest.', 'Moreover, a non-rotating drill string will cause increased frictional drag so that there is less control over the “weight on bit” and the rate of drill bit penetration can decrease, which can also result in substantially increased drilling costs.', 'Of course, a non-rotating drill string is also more likely to get stuck in the wellbore than a rotating one, particularly where the drill string extends through a permeable zone that causes significant buildup of mud cake on the borehole wall.', "Rotary steerable drilling systems minimize these risks by steering the drill string while it's being rotated.", 'Rotary steerable systems, also known as “RSS,” may be generally classified as either “push-the-bit” systems or “point-the-bit” systems.', 'SUMMARY', 'In accordance to an aspect of the disclosure a rotary steerable system includes an upper stabilizer connected to a collar of a drill string, an articulated section connected by a flexible joint to the collar, a drill bit connected to the articulated section opposite from the flexible joint, a lower stabilizer located proximate to the flexible joint and an actuator located with the articulated section and selectively operable to tilt the axis of the drill bit and the articulated section relative to the axis of the collar.', 'A method in accordance to an embodiment includes drilling a borehole with the rotary steerable system including drilling a bias phase of a drilling cycle on a demand tool face and drilling a neutral phase of the drilling cycle on a 180 degree offset tool face from the demand tool face.', 'In accordance to an embodiment a method includes estimating an optimum drilling cycle time and performing a drilling cycle using the estimated optimum drilling time with the rotary steerable system.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The disclosure is best understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n illustrates a well system incorporating a rotary steerable system (“RSS”) having a pad-in-bit articulated section bias unit in accordance to one or more aspects of the disclosure.', 'FIG.', '1A\n is a pictorial diagram of attitude and steering parameters depicted in a global coordinate reference in accordance to one or more aspects of the disclosure.', 'FIGS.', '2 and 3\n schematically illustrate an RSS in accordance to one or more aspects of the disclosure.', 'FIG.', '4\n illustrates a geometric relationship steady state curvature of a wellbore.\n \nFIG.', '5\n illustrates model parameters for a simulation of a tool in accordance to one or more aspects of the disclosure.\n \nFIG.', '6\n is a geometric illustration for estimating an optimum drilling cycle time in accordance to one or more aspects of the disclosure.', 'FIG.', '7\n is a geometric illustration for an instantaneous and net curvature over one drilling cycle.\n \nFIG.', '8\n is a graphically illustration of a variation of the instantaneous to net curve deviation for a drilling cycle in accordance to one or more aspects of the disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements.', 'Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements.', 'Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element are may be utilized to more clearly describe some elements.', 'Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.\n \nFIG.', '1\n illustrates borehole \n4\n, or wellbore, being directionally drilled into earthen formations \n6\n utilizing a bottom hole assembly (“BHA”), generally denoted by the numeral \n10\n.', 'The bottom hole assembly is depicted connected to the end of the tubular drill string \n12\n which is may be rotatably driven by a drilling rig \n14\n from the surface.', 'In addition to providing motive force for rotating the drill string \n12\n, the drilling rig \n14\n also supplies a drilling fluid \n8\n, under pressure, through the tubular drill string \n12\n.', 'In order to achieve directional control while drilling, components of the BHA \n10\n may include one or more drill collars \n16\n, one or more stabilizers, generally denoted by the numeral \n18\n, and a rotary steerable system (“RSS”) \n20\n.', 'The rotary steerable system \n20\n is the lowest component of the BHA and in accordance to one or more embodiments includes a control unit \n22\n, bias unit \n40\n and a steering section \n24\n.', 'Steering section \n24\n includes an upper collar or section \n23\n connected to a lower articulated section or member \n25\n by a flexible joint \n32\n.', 'The lower articulated section \n25\n is referred to from time to time herein as an articulated section, articulated member or other similar terms.', 'Although the steering section \n24\n is described in terms of two sections, the sections may be integrally combined in one component.', 'In accordance to embodiments disclosed herein, the BHA may be referred to as a pad-in-bit articulated BHA \n10\n and the RSS may be referred to as a pad-in-bit articulated RSS \n20\n.', 'The upper collar or section \n23\n is connected to the last of the drill collars \n16\n or to any other suitable downhole component.', 'Other components suited for attachment of the rotary steerable system \n20\n include a drilling motor \n19\n (e.g., mud motor), measuring while drilling tools, tubular segments, data communication and control tools, cross-over subs, etc.', 'An upper stabilizer \n26\n is attached to one of the collars \n16\n, for example above and adjacent to the rotary steerable system \n20\n.', 'A lower stabilizer \n30\n is located adjacent to the flexible joint \n32\n and in some embodiments it is located coincident with the flexible joint.', 'In an embodiment, a lower stabilizer \n30\n is attached to the lower articulated section \n25\n of steering section \n24\n.', 'The steering section \n24\n also includes drill bit \n28\n.', 'A surface control system \n21\n, e.g., directional driller, may be utilized to communicate steering commands to the electronics in control unit \n22\n, e.g. attitude hold controller, either directly in a manner that is well known in the art (e.g., mud-pulse telemetry) or indirectly via a measuring while drilling (“MWD”) module \n29\n included among the drill collars \n16\n.', 'The lower articulated section \n25\n including the bit shaft and drill bit \n28\n are pivoted, as represented by a bit axis \n34\n, relative to the axis \n38\n (e.g., drill attitude) of the bottom hole assembly \n10\n (e.g., the collar axis) by way of a flexible section or joint \n32\n within the steering section \n24\n.', 'The flexible section or joint \n32\n may be provided for example by a universal joint.', 'The flexible section or joint \n32\n itself may transmit the torque from the drill string \n12\n to the drill bit \n28\n, or the torque may be transmitted via other arrangements.', 'Suitable torque transmitting arrangements include many well-known devices such as splined couplings, gearing arrangements, universal joints, and recirculating ball arrangements.', 'In accordance to aspects of the disclosure the flexible joint \n32\n may include for example a universal joint with a flex tube, a universal joint without a flex tube, or a flex sub with effectively zero moment transmission across it, such that the flexible joint has the functionality of a universal joint with two angular degrees of freedom whilst allowing for transmission of axial torque to the drill bit and transmitting a negligible bending moment across itself.', 'The lower articulated section \n25\n is intermittently actuated by one or more actuators \n36\n, about the flexible section or joint \n32\n with respect to the upper collar or section \n23\n (collar or BHA axis \n38\n) to actively maintain the bit axis \n34\n pointing in a particular direction while the whole assembly is rotated with the drill string.', 'The term “actively tilted” is meant to differentiate how the rotary steerable system \n20\n is dynamically oriented as compared to the known fixed displacement units.', '“Actively tilted” means that the rotary steerable system \n20\n has no set fixed angular or offset linear displacement.', 'Rather, both angular and offset displacements vary dynamically as the rotary steerable system \n20\n is operated.', 'The use of a universal joint as a flexible joint \n32\n swivel is desirable in that it may be fitted in a relatively small space and still allow the drill bit axis \n34\n to be tilted with respect to the axis \n38\n such that the direction of drill bit \n28\n defines the direction of the borehole \n4\n.', 'That is, the direction of the drill bit \n28\n leads the direction of the borehole \n4\n.', 'This allows for the rotary steerable system \n20\n to drill with little or no side force once a curve is established and minimizes the amount of active control necessary for steering the borehole \n4\n.', 'Further, the collar \n16\n can be used to transfer torque to the drill bit \n28\n.', 'This allows a dynamic point-the-bit rotary steerable system \n20\n to have a higher torque capacity than a static point-the-bit type tool of the same size that relies on a smaller inner structural member for transferring torque to the bit.', 'Although the illustrated embodiments utilize a torque transmitting device) such as a universal joint as the flexible joint \n32\n in the steering section, other devices such as flex connections, splined couplings, ball and socket joints, gearing arrangements, etc. may also be used as a flexible joint \n32\n.', 'Refer now to \nFIGS.', '2 and 3\n which schematically illustrate a pad-in-bit articulated rotary steerable system \n20\n of a BHA \n10\n in accordance to one or more embodiments.', 'The illustrated pad-in-bit RSS \n20\n includes a steering section \n24\n having an upper collar or section \n23\n connected by a flexible joint \n32\n to a lower articulated section \n25\n carrying a drill bit \n28\n.', 'For example, lower articulated section \n25\n includes the drill bit shaft \n27\n which is connected to the flexible joint \n32\n and an outer sleeve \n31\n.', 'In accordance to one or more aspects of the disclosure a lower stabilizer \n30\n is located on the upper section or collar \n23\n or the lower articulated section \n25\n proximate to and or below the flexible joint \n32\n.', 'Stabilizer \n30\n is illustrated located on the articulated section \n25\n for example in \nFIGS.', '2 and 3\n.', 'In accordance to embodiments, stabilizer \n30\n is located coincident or substantially coincident with the flexible joint \n32\n; for example, within an inch or two inches of the flexible joint \n32\n, e.g., universal joint.', 'Locating the stabilizer \n30\n coincident with the flexible joint \n32\n stabilizes the flexible joint.', 'The drill bit shaft \n27\n may be connected for example to the rotor of a mud motor \n19\n for example through a flexible drive shaft.', 'The control unit \n22\n may be for example a roll stabilized or strap down variety.', 'Illustrated in \nFIGS.', '2 and 3\n, the control unit \n22\n and the bias unit \n40\n are disposed directly behind and adjacent to drill bit \n28\n in the lower articulated section \n25\n.', 'The control unit \n22\n includes for example and without limitation self-powered electronics \n42\n, an electrical source \n44\n, sensor or sensors \n46\n (e.g., direction and azimuth sensors or sensor package, direction and inclination (D&I) sensors), and control valves \n48\n.', 'The bias unit \n40\n includes an actuator \n36\n to apply a radial force against the wall of the borehole.', 'For example, the illustrated actuator \n36\n includes piston face or pad \n50\n disposed on moveable pistons \n52\n.', 'The pistons \n52\n may be moved from a retracted position toward an extended position by supplying drilling fluid to the piston cylinders.', 'It will be recognized by those skilled in the art that the pistons may be oriented parallel to the bit axis and hinged to move pads \n50\n radially outward.', 'The supply of the drilling fluid to the pistons is controlled by the control unit \n22\n.', 'To achieve a drilling direction, the control unit can actuate one or more of the pistons \n52\n to an extended position such that the pad \n50\n engages the wall of the borehole \n4\n and articulates the lower articulated section \n25\n and drill bit \n28\n at the flexible joint \n32\n relative to the axis \n38\n of the upper collar or section \n23\n and the drill string.', 'In accordance to some embodiments, the control unit \n22\n for the bias unit may be located above the motor and the flexible joint \n32\n and the fluid under pressure flowing for example through a flexible drive shaft across the flexible joint \n32\n (e.g., universal joint) to the actuators \n36\n.', 'The steering section \n24\n illustrated in \nFIG.', '3\n includes a strike ring \n54\n positioned to limit the angle or extent that the lower articulated section \n25\n can be articulated relative to the upper collar or section \n23\n.', 'The drill bit \n28\n has a bit gauge \n56\n, for example active and/or passive gauge rings.', 'The gauge is associated with the amount of formation that is removed from the borehole wall.', 'A pad-in-bit articulated RSS \n20\n in accordance to one or more aspects of the disclosure combines a bias unit \n40\n having a high dog-leg severity (“DLS”) capability, for example of a point-the-bit tool, with the excellent attitude hold performance of conventional push-the-bit low DLS tools.', 'In accordance to methods of the disclosure, the disclosed pad-in-bit articulated RSS can drill a build section and a lateral section, for example while geo-steering, without having to trip out of the wellbore to change steering tools, e.g., from a point-the-bit tool to a push-the-bit tool.', 'In accordance to some embodiments the pad-in-bit articulated RSS \n20\n does not need extra sleeve sensors or closed loop sleeve tool face control and can be steered very accurately with the basic 100 percent steering ratio virtual tool face (“VTF”) with no attitude measurement feedback delay compensation algorithms.', 'In accordance to some embodiments, the pad-in-bit articulated RSS \n20\n can perform high DLS parameters, e.g. greater than 15 degrees/100 ft., without sleeve “flipping” or large tool face offset issues.', 'In accordance to some embodiments the pad-in-bit articulated RSS \n20\n is a low power tool with and fast tool face actuation.', 'Utilizing a strike ring \n54\n may provide more predictable steady state DLS at 100 percent steering ratio, however, in some embodiments a strike ring is not used.', 'In accordance to aspects, the pad-in-bit articulated RSS effectively becomes a push-the-bit tool when in the lateral, whilst having the benefits of a point-the-bit tool in a soft formation.', 'Non-limiting examples of directional drilling control are described with reference to U.S. Pat.', 'No. 9,022,141, which is incorporated by reference herein.', 'In accordance to one or more embodiments, the control unit \n22\n is positioned between the bend (flexible joint \n32\n) and the drill bit \n28\n with the steering forces (actuator \n36\n) applied as close to the bit \n28\n as possible with the reaction on the active gauge \n56\n of the drill bit \n28\n seeing as much of the steering (pad) forces as possible, i.e. a large or no under gauge bit.', 'In accordance to an embodiment, the pad-in-bit articulated RSS \n20\n may have a drill bit \n28\n to flexible joint \n32\n dimension of about five feet to thirty feet.', 'In accordance to an embodiment, the pad-in-bit articulated RSS may have a drill bit \n28\n to flexible joint \n32\n dimension of about ten feet to twenty feet.', 'In accordance to at least one embodiment, the pad-in-bit articulated RSS may have a drill bit \n28\n to flexible joint \n32\n dimension of about fifteen feet.', 'In accordance to an embodiment, the pad-in-bit articulated RSS \n20\n may have a drill bit to \n28\n to flexible joint \n32\n up to about four feet and a flexible joint \n32\n to stabilizer \n26\n dimension of up to about fifteen feet in accordance to the implied assumption of Equation 3 below.', 'The D&I sensors \n46\n are placed as close to the drill bit \n28\n as possible, for example in the lower articulated section \n25\n, or the D&I sensors may be located above the flexible joint \n32\n for example in the upper collar or section \n23\n and connected to the control unit \n22\n in the articulated section \n25\n via wiring going through the flexible joint \n32\n, e.g., universal joint, or by telemetry.', 'D&I sensors, denoted as D&I sensors \n47\n or on-collar sensors, are illustrated in \nFIG.', '3\n located above the flex joint \n32\n relative to the drill bit.', 'For the application of virtual tool face it may be desired to have the D&I sensors \n46\n in the articulated section \n25\n (\nFIG.', '3\n) close to the drill bit.', 'For example, in accordance to a simulation described below, the D&I sensor \n46\n were placed eight feet from the drill bit \n28\n in the articulated section \n25\n so as to mimic a PowerDrive (trademark of Schlumberger) RSS tool (see, e.g., Table 1 and \nFIG.', '5\n).', 'Operationally, a roll stabilized control unit \n22\n once downlinked, e.g., using mud telemetry, to hold an attitude will stay in attitude hold with no electrical connection required to the rest of the pad-in-bit articulated BHA \n10\n.', 'This configuration can be useful as electrical connectivity past the flexible joint may be problematic and or complex and expensive.', 'In accordance to aspects of the disclosure, the pad-in-bit articulated BHA \n10\n and RSS \n20\n has the advantages of a push-the-bit tool (low power fast tool face actuation) and it also has the advantages of a point-the-bit bias unit, implying a higher DLS capability (particularly in soft formations) but also an easier to predict steady state DLS capability using the following geometric relationship described with reference to \nFIG.', '4\n.', 'With reference to \nFIG.', '4\n the steady state curvature prediction of Eq. 3 is valid when the flexure of the bottom hole assembly between the drill bit \n28\n to flexible joint \n32\n section and the flexible joint \n32\n to stabilizer \n26\n section is negligible such the RSS \n20\n over these two dimensions can be treated as two rigid bodies linked by the flexible joint \n32\n.', 'θ\n \n1\n \n \n=\n \n \n \nα\n \n-\n \n \nθ\n \n2\n \n \n \n=\n \nθ\n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n1\n \n \n)\n \n \n \n \n \n \n \n \n \n \ns\n \n1\n \n \n\u2062\n \nρ\n \n \n2\n \n \n=\n \n \n \nα\n \n-\n \n \n \n \ns\n \n2\n \n \n\u2062\n \nρ\n \n \n2\n \n \n \n=\n \nθ\n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n2\n \n \n)\n \n \n \n \n \n \n \nρ\n \n=\n \n \n \n2\n \n\u2062\n \n \n \n \n\u2062\n \nα\n \n \n \n(\n \n \n \ns\n \n1\n \n \n+\n \n \ns\n \n2\n \n \n \n)\n \n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n3\n \n \n)\n \n \n \n \n \n \n \n \nWhere: \n \n \n \nS\n1\n, S\n2 \nare the paths of the constant curvature between the contact points (can be taken as the chords between the contact points as a first approximation, i.e. the stabilizer position dimensions),\n \nα is the angle of limit for articulation of the articulated section \n25\n (e.g., the a strike ring angle), and\n \nρ is the steady state curvature of the wellbore between the first three contact points (the drill bit \n28\n, the lower stabilizer \n30\n, and the upper stabilizer \n26\n).', 'Simulation Case Studies\n \nModel parameters for a simulation of a pad-in-bit articulated BHA \n10\n and RSS \n20\n are illustrated in \nFIG.', '5\n (dimensions in feet) and Table 1 below.', 'A model pad-in-bit articulated BHA \n10\n was made to drill due East with a gravity tool (“GTF”) of 90 degrees.', 'The model BHA proceeded to drill with a steady state DLS of 17 degrees/100 ft. or more with very little propagated hole tool face offset.', 'It is noted that the analytical equation, Equation 3, stated above for predicting the steady state DLS of a point-the-bit tool predicted 16.4 degree/100 ft. curvature which is similar to the numerical simulation results.', 'The response tool face of the propagated borehole had a consistent and small tool face offset that the directional driller could easily compensate for if manual steering were being used.', 'TABLE 1\n \n \n \n \n \n \n \n \n \n \nActuator Force\n \n10\n \nkN\n \n \n \n \n \n \n \n \n \n \n \nNominal RPM\n \n60\n \n \n \n \n \n \n \n \n \n \n \n \nEffective rate of penetration (ROP)\n \n100\n \nft/hr\n \n \n \n \n \n \n \n \n \n \n \nTool Size\n \n675\n \n \n \n \n \n \n \n \n \n \n \nBit Model\n \nDetourney plus passive\n \n \n \n \n \ngauge stabilizer\n \n \n \n \nTool to Formation CoF\n \n0.35\n \n \n \n \n \n \n \n \n \n \n \n \nActuation tool face update interval\n \n0.5\n \nseconds', 'D&I 46 to bit offset (D&I on lower\n \n8\n \nft\n \n \n \n \narticulated section 25)\n \n \n \n \nD&I 47 to bit offset (MWD on upper\n \n14\n \nft\n \n \n \n \ncollar or section 23)\n \n \n \n \nStrike ring angle\n \n2\n \ndegrees\n \n \n \n \n \n \n \n \n \n \n \nInitial azimuth and inclination\n \n90 degrees for both\n \n \n \n \n \n \n \n \n \n \n \nIn the simulation the lower articulated section \n25\n was fully articulated at 2 degrees throughout the run and the magnitude of the contact force on the strike ring \n54\n was around 110 kN.', 'The contact force on the strike ring will be higher on the steering section \n24\n of the pad-in-bit articulated RSS \n20\n of this disclosure compared to prior rotary steerable systems due to the greater moment arm of the longer articulated steering section \n25\n due to positioning of the bias unit \n40\n below the flexible joint \n32\n.', 'Attitude Hold Study\n \nIn an attitude hold simulation the pad-in-bit articulated BHA \n10\n and RSS \n20\n was started from the same initial conditions as the above simulation, but put into VTF attitude hold immediately.', 'The simulation tool was able to hold the demand attitude with a tolerance of 0.25 degrees throughout the simulation run.', 'This demonstrates that the pad-in-bit articulated BHA \n10\n and RSS \n20\n can be predicted to have the high DLS capability of a point-the-bit tool but with the excellent VTF attitude hold capability demonstrated by lower dogleg severity tools using the same VTF algorithm.', 'The simulated pad-in-bit articulated BHA \n10\n demonstrated excellent attitude hold response when drilling in VTF and was also capable of greater than 17 degrees/100 ft. in pure bias (100 percent steering ratio) as described above.', 'In the simulation, the tool face response was determined for attitude measurements of both the on tool D&I sensors \n46\n located on the articulated section \n25\n and the on-collar D&I sensor \n47\n, e.g., MWD, located on the upper section \n23\n (i.e., collar).', 'Also of interest is that the on tool D&I sensor \n46\n, i.e. the D&I sensor \n46\n on the articulated section \n25\n, picked up on the ±2 degrees of articulation.', 'Despite the VTF algorithm using the attitude measurements from the articulated effected lower section \n25\n, the attitude response of the resulting borehole, as measured by the on-collar D&I sensor \n47\n that is fourteen feet further back on the collar from the drill bit, demonstrated an excellent attitude tracking response with a small attitude tolerance.', 'This was achieved while filtering the on tool D&I \n46\n attitude measurement with an equivalent of a 1 Hz band width analogue low pass filter, other D&I and signal conditioning architectures are possible.', 'Attitude Hold with a Nudge Study\n \nThis case study is the same as above but instead of maintaining the same demand attitude throughout a nudge of +2 degrees inclination was downlinked at 80 feet of measured depth.', 'The modeled pad-in-bit articulated BHA \n10\n and RSS \n20\n accurately followed the demand attitude whilst clearly uncoupling the inclination from the azimuth response as would be expected in VTF for a tool with fast tool face actuation.', 'This kind of precision and control is unexpected in particular with such a simple attitude hold algorithm.', 'In this simulation the strike ring \n54\n was mostly not in contact during the attitude hold and only came into contact briefly during the nudge transient.', 'Vertical Drilling Case Study\n \nThis case study covers a special case of attitude hold, vertical drilling.', 'Vertical drilling is a more demanding form of attitude control and in this simulation was implemented simply using VTF but with the demand attitude set to have a zero inclination (with arbitrary demand azimuth).', 'It is a demanding form of attitude drilling mainly because of the noisier inclination measurement.', 'However, the simulation demonstrated that the bias unit \n40\n was able to hold vertical to within ±1.0 degrees.', 'Less than 100 Percent Steering Ratio (“SW”)', 'Case Study\n \nIn accordance to aspects the disclosure, the pad-in-bit articulated BHA \n10\n and RSS \n20\n can steer with steering ratios less than 100 percent and in modes other than virtual tool face (“VTF”) or vertical.', 'This permits the directional drillers to downlink curved sections which are drilled at DLS values less than the maximum the tool can achieve.', 'This could be a problem for some embodiments of the RSS tool because of the longer dimension from the drill bit to the universal joint to fit in the bias unit, the control unit and possibly a separate D&I sensor to the one on the control unit.', 'This may mean the tool will have a greater tendency to stay at the attitude it had in the bias phase of the drilling cycle whilst in the neutral phase.', 'Conventionally the neutral phase of the drilling cycle is achieved by spinning the actuation tool face open loop at a constant rate as the tool propagates.', 'However, in accordance with aspects of the disclosure, the pad-in-bit articulated RSS \n20\n tool presents an additional possibility for the neutral phase of the drilling cycle due to the pad in bit nature of the actuation on the end of the articulated section \n25\n.', 'Rather than spinning the tool face of actuation at a constant open loop rate, the tool phase of actuation can simply be inverted by 180 degrees relative to the tool face in the bias phase whilst in the neutral phase of the drilling cycle.', 'Because of the far better tool face actuation dynamics, the pad-in-bit articulated RSS \n20\n will approximate well to drilling on tool face in the bias phase, and 180 degree offset from the demand tool face in the neutral phase.', 'This will mean the in plane curvature of the curved section will approximate well to the difference between the bias and neutral percentages as a percentage of the maximum DLS of the tool.', 'So for example, if the pad-in-bit articulated RSS \n20\n is capable of 16 degrees/100 ft.', 'then with a 70 percent steering ratio it will respond with a 40 percent (70 percent −30 percent) of maximum DLS (6.4 degrees/100 ft.) for the in plane curved section.', 'Table 2 provides a theoretical range of response percentage of maximum DLS verses percentage steering ratio for an in plane curved section.', 'TABLE 2\n \n \n \n \n \n \n \n \nSR % (percent)', 'Response % of max DLS (net curvature)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n50\n \n0\n \n \n \n \n60\n \n20\n \n \n \n \n70\n \n40\n \n \n \n \n80\n \n60\n \n \n \n \n90\n \n80\n \n \n \n \n100\n \n100\n \n \n \n \n \n \n \n \n \n \n \nHence with this modification to existing drilling practice the pad-in-bit articulated RSS \n20\n will be able to drill curved sections using the drilling cycle concept with curvatures less than the maximum DLS capability of the tool.', 'Using a 180 degree tool face inversion on the demand tool face, as described above, for the neutral phase of the drilling cycle is original to the pad-in-bit articulated RSS \n20\n in accordance to this disclosure.', 'This neutral cycle implementation is only possible for the pad-in-bit articulated RSS \n20\n concept and is not anticipated to work well or be applicable to standard RSS tools.', 'A simulation was run of a pad-in-bit articulated RSS \n20\n drilling at 90 degree GTF at 70 percent SR for the first 80 feet (therefore expected to respond with a 40 percent of maximum tool DLS) and after 80 feet the tool continued to drill with a 100 percent SR until the end of the simulation.', 'The simulation demonstrated that the 70 percent SR section had a DLS approximately 40 percent of the 100 percent SR section, as expected.', 'Choice of Optimum Drilling Cycle Time for In Plane Curve\n \nThe less than 100 percent DLS plane section curve approach previously detailed also lends itself to a simple geometrical analysis such that the drilling cycle time can be chosen for a given set of operating point conditions to give a specified nominal maximum deviation of the instantaneous in plane curve from the ideal in plane curve as if drilled continuously with a drilling cycle of 100 percent steering ratio.', 'The starting point for the geometrically based analysis is described with reference to \nFIG.', '6\n which finds the lateral deviation of the curve “A” from its starting tangent over a specified path length “s” for a defined dog leg severity (DLS) curvature p.', 'Hence, it can be deduced that:\n \n \n \n \n \n \n \n \nA\n \n=\n \n \n \n1\n \n-\n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \ns\n \n\u2062\n \n \n \n \n\u2062\n \nρ\n \n \n \nρ\n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n4\n \n \n)\n \n \n \n \n \n \n \n \nTherefore the schematic in \nFIG.', '7\n can be sketched for the instantaneous and net curvature over one drilling cycle with “bias” curvature +ρ\n1 \nand “neutral” curvature −ρ\n1 \nfor the instantaneous curve (i.e., ρ\n1\n) and curvature ρ\n2 \nfor the net curvature path.', 'It can be deduced that the deviation Δ of the instantaneous curve ρ\n1 \nfrom the ideal net curvature curve ρ\n2 \nover the drilling cycle, is given by:\n \n \n \n \n \n \n \n \nΔ\n \n=\n \n \n \n[\n \n \n \n1\n \n-\n \n \ncos\n \n\u2061\n \n \n(\n \n \nα\n \n\u2062\n \n \n \n \n\u2062\n \ns\n \n\u2062\n \n \n \n \n\u2062\n \n \nρ\n \n1\n \n \n \n)\n \n \n \n \n \nρ\n \n1\n \n \n \n]\n \n \n-\n \n \n[\n \n \n \n1\n \n-\n \n \ncos\n \n\u2061\n \n \n(\n \n \nα\n \n\u2062\n \n \n \n \n\u2062\n \ns\n \n\u2062\n \n \n \n \n\u2062\n \n \nρ\n \n2\n \n \n \n)\n \n \n \n \n \nρ\n \n2\n \n \n \n]\n \n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n5\n \n \n)\n \n \n \n \n \n \n \nΔ\n \n=\n \n \n \n \nρ\n \n2\n \n \n-\n \n \nρ\n \n1\n \n \n-\n \n \n \nρ\n \n2\n \n \n\u2062\n \n \ncos\n \n\u2061\n \n \n(\n \n \nα\n \n\u2062\n \n \n \n \n\u2062\n \ns\n \n\u2062\n \n \n \n \n\u2062\n \n \nρ\n \n1\n \n \n \n)\n \n \n \n \n+\n \n \n \nρ\n \n1\n \n \n\u2062\n \n \ncos\n \n\u2061\n \n \n(\n \n \nα\n \n\u2062\n \n \n \n \n\u2062\n \ns\n \n\u2062\n \n \n \n \n\u2062\n \n \nρ\n \n2\n \n \n \n)\n \n \n \n \n \n \n \nρ\n \n1\n \n \n\u2062\n \n \nρ\n \n2\n \n \n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n6\n \n \n)\n \n \n \n \n \n \n \n \nWhere α is the steering ratio (“SR”) and s is the measured depth drilled over the drilling cycle at a nominal rate of penetration Vrop,', 'such that if Δt is the drilling cycle period then the measured depth s is given by Vrop·Δt, and the drilling time is\n \n \n \n \n \n \nΔ\n \n\u2062\n \n \n \n \n\u2062\n \nt\n \n \n=\n \n \n \ns\n \nVrop\n \n \n.', 'Therefore, with this expression for a given range of steering ratio α values, nominal Vrop and ρ\n1 \nfor an assumed Δt it is possible to estimate the deviation Δ of the instantaneous in plane curve ρ\n1 \nfrom the equivalent net curvature curve ρ\n2\n.', 'Therefore, for an assumed Vrop and ρ\n1\n, and α steering ratios, a look up table of drilling cycle Δt times can be derived to ensure the instantaneous to net curve deviation Δ can be kept below a desired nominal value.', 'For example the \nFIG.', '8\n graph shows the variation of the instantaneous to net curve deviation Δ for a 180 second drilling cycle, a pad-in-bit articulated RSS \n20\n tool with a maximum DLS of 16 degree/100 ft. and assumed nominal Vrop of 200 ft./hr.', 'It can be seen that for this operating point the worst case Δ is just less than 13 mm at a net percentage of maximum DLS of 40 percent, which corresponds to a steering ratio of 70 percent.', 'If this is too much deviation for this operating point then the drilling cycle time can be reduced accordingly, and so on.', 'The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure.', 'Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the disclosure.', 'The scope of the invention should be determined only by the language of the claims that follow.', 'The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group.', 'The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.'] | ['1.', 'A method for drilling a subterranean wellbore, the method comprising:\n(a) generating a net drilling curvature over a single drilling cycle of one bias phase and one neutral phase for drilling the wellbore with a rotary steerable system;\n(b) computing an instantaneous curvature of the wellbore, during the single drilling cycle, from a bias curvature of the rotary steerable system deployed in the wellbore and a neutral curvature of the rotary steerable system deployed in the wellbore;\n(c) processing the bias curvature, a steering ratio, and a rate of penetration of drilling with the rotary steerable system and computing a deviation of the instantaneous curvature from the net drilling curvature over the single drilling cycle;\n(d) choosing a drilling cycle time for cycling between the bias and neutral phases of the rotary steerable system, and by determining the deviation of the instantaneous curvature from the net drilling curvature computed in (c) is less than a maximum deviation for the single drilling cycle; and\n(e) cycling back and forth between the bias phase and the neutral phase of the rotary steerable system at the drilling cycle time chosen in (d) while rotating the rotary steerable system in the wellbore to drill.', '2.', 'The method of claim 1, wherein cycling back and forth between the bias phase and the neutral phase comprises cycling back and forth between drilling the bias phase on a demand tool face and drilling the neutral phase on a 180 degree offset tool face from the demand tool face.', '3.', 'The method of claim 1, wherein the rotary steerable system comprises:\nan upper stabilizer connected to a collar of a drill string;\nan articulated section connected by a flexible joint to the collar;\na drill bit connected to the articulated section opposite from the flexible joint;\na lower stabilizer located proximate to the flexible joint; and\nan actuator located with the articulated section and selectively operable while drilling to tilt an axis of the drill bit and the articulated section relative to a collar axis.', '4.', 'The method of claim 3, wherein cycling back and forth between the bias phase and the neutral phase comprises cycling back and forth between drilling the bias phase on a demand tool face and drilling the neutral phase on a 180 degree offset tool face from the demand tool face.', '5.', 'The method of claim 4, wherein the actuator is located adjacent to the drill bit and the flexible joint permits two angular degrees of freedom whilst allowing for transmission of axial torque to the drill bit and transmitting a negligible bending moment across itself.', '6.', 'The method of claim 1, wherein the deviation of the instantaneous curvature from the net drilling curvature is computed in (c) according to the following mathematical equation: Δ = ρ 2 - ρ 1 - ρ 2 \u2062 cos \u2061 ( α · s · ρ 1 ) - ρ 1 \u2062 cos \u2061 ( α · s · ρ 2 ) ρ 1 · ρ 2\nwherein Δ represents the deviation of the instantaneous curvature from the net drilling curvature over the single drilling cycle, ρ1 represents the bias curvature of the rotary steerable system, ρ2 represents the net drilling curvature, α represents the steering ratio, and s represents a measured depth drilled during the single drilling cycle of the bias phase and the neutral phase, wherein s is given by the rate of penetration of drilling times the drilling cycle time.', '7.', 'The method of claim 1, wherein:\n(d) further comprises: computing a lookup table of the deviations of the instantaneous curvature from the net drilling curvature and corresponding drilling cycle times from the bias curvature of the rotary steerable system, assumed rates of penetration, and a plurality of the steering ratios over the single drilling cycle; and (ii) choosing the drilling cycle time from the lookup table.', '8.', 'The method of claim 7, wherein computing the lookup table includes generating at least one graph of the deviation of instantaneous curvature from the net drilling curvature as a percentage of maximum dog leg severity, each graph of the at least one graph being specific to a particular drilling cycle time.'] | ['FIG. 1 illustrates a well system incorporating a rotary steerable system (“RSS”) having a pad-in-bit articulated section bias unit in accordance to one or more aspects of the disclosure.', '; FIG.', '1A is a pictorial diagram of attitude and steering parameters depicted in a global coordinate reference in accordance to one or more aspects of the disclosure.', '; FIGS.', '2 and 3 schematically illustrate an RSS in accordance to one or more aspects of the disclosure.', '; FIG.', '4 illustrates a geometric relationship steady state curvature of a wellbore.; FIG.', '5 illustrates model parameters for a simulation of a tool in accordance to one or more aspects of the disclosure.', '; FIG.', '6 is a geometric illustration for estimating an optimum drilling cycle time in accordance to one or more aspects of the disclosure.', '; FIG. 7 is a geometric illustration for an instantaneous and net curvature over one drilling cycle.; FIG. 8 is a graphically illustration of a variation of the instantaneous to net curve deviation for a drilling cycle in accordance to one or more aspects of the disclosure.', '; FIG. 1 illustrates borehole 4, or wellbore, being directionally drilled into earthen formations 6 utilizing a bottom hole assembly (“BHA”), generally denoted by the numeral 10.', 'The bottom hole assembly is depicted connected to the end of the tubular drill string 12 which is may be rotatably driven by a drilling rig 14 from the surface.', 'In addition to providing motive force for rotating the drill string 12, the drilling rig 14 also supplies a drilling fluid 8, under pressure, through the tubular drill string 12.', 'In order to achieve directional control while drilling, components of the BHA 10 may include one or more drill collars 16, one or more stabilizers, generally denoted by the numeral 18, and a rotary steerable system (“RSS”) 20.', 'The rotary steerable system 20 is the lowest component of the BHA and in accordance to one or more embodiments includes a control unit 22, bias unit 40 and a steering section 24.', 'Steering section 24 includes an upper collar or section 23 connected to a lower articulated section or member 25 by a flexible joint 32.', 'The lower articulated section 25 is referred to from time to time herein as an articulated section, articulated member or other similar terms.', 'Although the steering section 24 is described in terms of two sections, the sections may be integrally combined in one component.', 'In accordance to embodiments disclosed herein, the BHA may be referred to as a pad-in-bit articulated BHA 10 and the RSS may be referred to as a pad-in-bit articulated RSS 20.'] |
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July 25, 2019; Vehra et al. | 03053025; June 2003; WO; 2015190934; December 2015; WO; 2016102381; December 2015; WO; WO-2016102381; June 2016; WO; 2016168596; October 2016; WO; 2017011585; January 2017; WO | ['Apparatus and methods regarding a first processing system operable to receive a job plan developed by a second processing system, and implement the job plan, including generating commands for an equipment controller based on the job plan.', 'The first processing system is operable to transmit, through a network, the commands to the controller for execution by the controller.', 'The first processing system is operable to iteratively (i) monitor, through the network, current conditions of the well construction system during execution of commands by the controller; (ii) update the implementation of the job plan, including generating updated commands for the controller based on the job plan and the current well construction system conditions when the current well construction system conditions indicate a deviation from the implementation; and (iii) transmit, through the network, the updated commands to the controller for execution by the controller.'] | ['Description\n\n\n\n\n\n\nBACKGROUND OF THE DISCLOSURE', 'In the drilling of oil and gas wells, drilling rigs are used to create a well by drilling a wellbore into a formation to reach oil and gas deposits (e.g., hydrocarbon deposits).', 'During the drilling process, as the depth of the wellbore increases, so does the length and weight of the drillstring.', 'A drillstring may include sections of drill pipe, a bottom hole assembly, and other tools for creating a well.', 'The length of the drillstring may be increased by adding additional sections of drill pipe as the depth of the wellbore increases.', 'Various components of a drilling rig can be used to advance the drillstring into the formation.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus including a first processing system having a processor and a memory including computer program code.', 'The first processing system is operable to receive a job plan developed by a second processing system, and implement the job plan, including generating commands for one or more equipment controllers based on the job plan.', 'The one or more equipment controllers are operable to control equipment of a well construction system.', 'The first processing system is also operable to transmit, through a network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers.', 'The first processing system is also operable to iteratively: (i) monitor, through the network, current conditions of the well construction system during execution of commands by the one or more equipment controllers; (ii) update the implementation of the job plan, including generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and (iii) transmit, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', 'The present disclosure also introduces an apparatus including a network, one or more equipment controllers communicatively coupled to the network and operable to control equipment of a well construction system, and a first processing system communicatively coupled to the network and having a processor and a memory including computer program code.', 'The first processing system is operable to develop a job plan based on current conditions of the well construction system, and to transmit the job plan through the network.', 'The apparatus also includes a second processing system communicatively coupled to the network and having a processor and a memory including computer program code.', 'The second processing system is operable to receive the job plan through the network, implement the job plan including generating commands for the one or more equipment controllers based on the job plan, and transmit, through the network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers.', 'The second processing system is also operable to iteratively: (a) monitor, through the network, the current conditions of the well construction system during execution of commands by the one or more equipment controllers; (b) update the implementation of the job plan, including generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and (c) transmit, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', 'The present disclosure also introduces a method including operating a first processing system comprising a processor and a memory including computer program code.', 'Operating the first processing system includes receiving a job plan developed by a second processing system, implementing the job plan including generating commands for one or more equipment controllers based on the job plan.', 'The one or more equipment controllers are operable to control equipment of a well construction system.', 'Operating the first processing also includes transmitting, through a network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers.', 'Operating the first processing also includes iteratively: (i) monitoring, through the network, current conditions of the well construction system during execution of commands by the one or more equipment controllers; (ii) updating the implementation of the job plan, including generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and (iii) transmitting, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '4\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.\n \nFIG.', '5\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.', 'FIG.', '6\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.\n \nFIG.', '7\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '8\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Systems and methods and/or processes according to one or more aspects of the present disclosure may be used or performed in connection with well construction at a wellsite, such as construction of a wellbore to obtain hydrocarbons (e.g., oil and/or gas) from a formation, including drilling the wellbore.', 'For example, some aspects of the present disclosure may be described in the context of drilling a wellbore in the oil and gas industry, although one or more aspects of the present disclosure may also or instead be used in other systems.', 'Various subsystems used in constructing the wellsite may have sensors and/or controllable components that are communicatively coupled to one or more equipment controllers (ECs).', 'An EC can include a programmable logic controller (PLC), an industrial computer, a personal computer based controller, a soft PLC, the like, and/or an example controller configured and operable to (1) perform sensing of an environmental status and/or (2) control equipment.', 'Sensors and various other components may transmit sensor data and/or status data to an EC, and controllable components may receive commands from an EC to control operations of the controllable components.', 'One or more aspects disclosed herein may permit communication between ECs of different subsystems through virtual networks and/or a common data bus.', 'Sensor data and/or status data may be communicated between ECs of different subsystems through virtual networks and a common data bus.', 'Additionally, a coordinated controller can implement control logic to issue commands to various ones of the ECs through the virtual networks and common data bus to thereby control operations of one or more controllable components.', 'Additional details of example implementations are described below.', 'A person having ordinary skill in the art will readily understand that one or more aspects of systems and methods and/or processes disclosed herein may be used in other contexts, including other systems.\n \nFIG.', '1\n is a schematic view of at least a portion of an example implementation of a well construction system \n100\n operable to drill a wellbore \n104\n into a subsurface formation \n102\n at a wellsite in accordance with one or more aspects of the present disclosure.', 'A drillstring \n106\n penetrates the wellbore \n104\n and includes a bottom hole assembly (BHA) \n108\n that comprises or is mechanically and hydraulically coupled to a drill bit \n110\n.', 'The well construction system \n100\n includes a mast \n114\n (a portion of which is depicted in \nFIG.', '1\n) extending from a rig floor \n112\n that is erected over the wellbore \n104\n.', 'A top drive \n116\n is suspended from the mast \n114\n and is detachably, mechanically, and hydraulically coupled to the drillstring \n106\n.', 'The top drive \n116\n provides a rotational force (e.g., torque) to drive rotational movement of the drillstring \n106\n when advancing the drillstring \n106\n into the formation \n102\n to form the wellbore \n104\n.', 'The top drive \n116\n is suspended from the mast \n114\n via hoisting equipment.', 'The hoisting equipment includes a traveling block \n118\n with a hook or other means \n120\n for mechanically coupling the traveling block \n118\n to the top drive \n116\n.', 'The hoisting equipment also includes a crown block \n122\n attached to the mast \n114\n, a drawworks \n124\n anchored to the rig floor \n112\n and comprising a drum \n125\n, a deadline anchor \n126\n attached to the rig floor \n112\n, and a drill line \n128\n extending from the deadline anchor \n126\n, around the crown block \n122\n and the traveling block \n118\n, and to the drawworks \n124\n where the excess length is spooled around the drum \n125\n.', 'The portion of the drill line \n128\n extending from the deadline anchor \n126\n to the crown block \n122\n is referred to as the deadline \n130\n (a portion of which being depicted in \nFIG.', '1\n in phantom).', 'The crown block \n122\n and the traveling block \n118\n collectively comprise a system of pulleys or sheaves around which the drill line \n128\n is reeved.', 'The drawworks \n124\n comprises the drum \n125\n and an engine, motor, or other prime mover (not shown).', 'The drawworks \n124\n may also comprise a control system and/or one or more brakes, such as a mechanical brake (e.g., a disk brake), an electrodynamic brake, and/or the like, although the prime mover and/or control system may instead provide the braking function.', 'The prime mover of the drawworks \n124\n drives the drum \n125\n to rotate and reel in the drill line \n128\n, which causes the traveling block \n118\n and the top drive \n116\n to move upward away from the rig floor \n112\n.', 'The drawworks \n124\n can reel out the drill line \n128\n by a controlled rotation of the drum \n125\n using the prime mover and control system, and/or by disengaging the prime mover (such as with a clutch) and disengaging and/or operating one or more brakes to control the release of the drill line \n128\n.', 'Unreeling the drill line \n128\n from the drawworks \n124\n causes the traveling block \n118\n and the top drive \n116\n to move downward toward the rig floor \n112\n.', 'Implementations within the scope of the present disclosure include land-based rigs, as depicted in \nFIG.', '1\n, as well as offshore implementations.', 'In offshore implementations, the hoisting equipment may also include a motion or heave compensator between the mast \n114\n and the crown block \n122\n and/or between the traveling block \n118\n and the hook \n120\n, among other possible additional components.', 'The top drive \n116\n includes a drive shaft \n132\n, a pipe handling assembly \n134\n with an elevator \n136\n, and various other components not shown in \nFIG.', '1\n, such as a prime mover and a grabber.', 'The drillstring \n106\n is mechanically coupled to the drive shaft \n132\n (e.g., with or without a sub saver between the drillstring \n106\n and the drive shaft \n132\n).', 'The prime mover drives the drive shaft \n132\n, such as through a gearbox or transmission, to rotate the drive shaft \n132\n and, therefore, the drillstring \n106\n.', 'The pipe handling assembly \n134\n and the elevator \n136\n permit the top drive \n116\n to handle tubulars (e.g., single, double, or triple stands of drill pipe and/or casing) that are not mechanically coupled to the drive shaft \n132\n.', 'The grabber includes a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft \n132\n.', 'A guide system (e.g., rollers, rack-and-pinion elements, and/or other mechanisms) may include a guide \n140\n affixed or integral to the mast \n114\n, and a dolly \n138\n integral to or otherwise carried with the top drive \n116\n up and down the guide \n140\n.', 'The guide system may provide torque reaction, such as to prevent rotation of the top drive \n116\n while the prime mover is rotating the drive shaft \n132\n.', 'The guide system may also or instead aid in maintaining alignment of the top drive \n116\n with an opening \n113\n in the rig floor \n112\n through which the drillstring \n106\n extends.', 'A drilling fluid circulation system circulates oil-based mud (OBM), water-based mud (WBM), and/or other drilling fluid to the drill bit \n110\n.', 'A pump \n142\n delivers drilling fluid through, for example, a discharge line \n144\n, a standpipe \n146\n, and a hose \n148\n to a port \n150\n of the top drive \n116\n.', 'The drilling fluid is then conducted through the drillstring \n106\n to the drill bit \n110\n, exiting into the wellbore \n104\n via ports in the drill bit \n110\n.', 'The drilling fluid then circulates upward through an annulus \n152\n defined between the outside of the drillstring \n106\n and the wall of the wellbore \n104\n (or the wall of casing installed in the wellbore \n104\n, if applicable).', 'In this manner, the drilling fluid lubricates the drill bit \n110\n and carries formation cuttings up to the surface as the drilling fluid is circulated.', 'At the surface, the drilling fluid may be processed for recirculation.', 'For example, the drilling fluid may flow through a blowout preventer \n154\n and a bell nipple \n156\n that diverts the drilling fluid to a return flowline \n158\n.', 'The return flowline \n158\n may direct the drilling fluid to a shale shaker \n160\n that removes at least large formation cuttings from the drilling fluid.', 'The drilling fluid may then be directed to reconditioning equipment \n162\n, such as may remove gas and/or finer formation cuttings from the drilling fluid.', 'The reconditioning equipment \n162\n can include a desilter, a desander, a degasser, and/or other components.', 'After treatment by the reconditioning equipment \n162\n, the drilling fluid may be conveyed to one or more mud tanks \n164\n.', 'Intermediate mud tanks may also be used to hold drilling fluid before and/or after the shale shaker \n160\n and/or various ones of the reconditioning equipment \n162\n.', 'The mud tank(s) \n164\n can include an agitator to assist in maintaining uniformity (e.g., homogeneity) of the drilling fluid contained therein.', 'A hopper (not depicted) may be disposed in a flowline between the mud tank(s) \n164\n and the pump \n142\n to disperse an additive, such as caustic soda, in the drilling fluid.', 'A catwalk \n166\n can be used to convey tubulars from a ground level to the rig floor \n112\n.', 'The catwalk \n166\n has a horizontal portion \n167\n and an inclined portion \n168\n that extends between the horizontal portion \n167\n and the rig floor \n112\n.', 'A skate \n169\n may be positioned in a groove and/or other alignment means in the horizontal and inclined portions of the catwalk \n166\n.', 'The skate \n169\n can be driven along the groove by a rope, chain, belt, and/or other pulley system (not depicted), thereby pushing tubulars up the inclined portion \n168\n of the catwalk \n166\n to a position at or near the rig floor \n112\n for subsequent engagement by the elevator \n136\n of the top drive \n116\n and/or other pipe handling means.', 'However, other means for transporting tubulars from the ground to the rig floor \n112\n are also within the scope of the present disclosure.', 'One or more pipe racks (not shown) may also adjoin the horizontal portion \n167\n of the catwalk \n166\n, and may include or operate in conjunction with a tubular delivery unit and/or other means for transferring tubulars to the horizontal portion \n167\n of the catwalk \n166\n in a mechanized and/or automated manner.', 'An iron roughneck \n170\n is also disposed on the rig floor \n112\n.', 'The iron roughneck \n170\n comprises a spinning system \n172\n and a torque wrench comprising a lower gripper \n174\n and an upper gripper \n176\n.', 'The iron roughneck \n170\n is moveable (e.g., in a translation movement \n178\n) to approach the drillstring \n106\n (e.g., for making up and/or breaking out a connection of the drillstring \n106\n) and to move clear of the drillstring \n106\n.', 'The spinning system \n172\n applies low-torque spinning to threadedly engage or disengage a threaded connection between tubulars of the drillstring \n106\n, and the torque wrench applies a higher torque to ultimately make up or initially break out the threaded connection.', 'Manual, mechanized, and/or automated slips \n180\n are also disposed on and/or in the rig floor \n112\n.', 'The drillstring \n106\n extends through the slips \n180\n.', 'In mechanized and/or automated implementations of the slips \n180\n, the slips \n180\n can be actuated between open and closed positions.', 'In the open position, the slips \n180\n permit advancement of the drillstring \n106\n through the slips \n180\n.', 'In the closed position, the slips \n180\n clamp the drillstring \n106\n to prevent advancement of the drillstring \n106\n, including with sufficient force to support the weight of the drillstring \n106\n suspended in the wellbore \n104\n.', 'To form the wellbore \n104\n (e.g., “make hole”), the hoisting equipment lowers the top drive \n116\n, and thus the drillstring \n106\n suspended from the top drive \n116\n, while the top drive \n116\n rotates the drillstring \n106\n.', 'During this advancement of the drillstring \n106\n, the slips \n180\n are in the open position, and the iron roughneck \n170\n is clear of the drillstring \n106\n.', 'When the upper end of the tubular in the drillstring \n106\n that is made up to the top drive \n116\n nears the slips \n180\n, the hoisting equipment ceases downward movement of the top drive \n116\n, the top drive \n116\n ceases rotating the drillstring \n106\n, and the slips \n180\n close to clamp the drillstring \n106\n.', 'The grabber of the top drive \n116\n clamps the upper portion of the tubular made up to the drive shaft \n132\n.', 'The drive shaft \n132\n is driven via operation of the prime mover of the top drive \n116\n to break out the connection between the drive shaft \n132\n and the drillstring \n106\n.', 'The grabber of the top drive \n116\n then releases the tubular of the drillstring \n106\n, and the hoisting equipment raises the top drive \n116\n clear of the “stump” of the drillstring \n106\n extending upward from the slips \n180\n.', 'The elevator \n136\n of the top drive \n116\n is then pivoted away from the drillstring \n106\n towards another tubular extending up through the rig floor \n112\n via operation of the catwalk \n166\n.', 'The elevator \n136\n and the hoisting equipment are then operated to grasp the additional tubular with the elevator \n136\n.', 'The hoisting equipment then raises the additional tubular, and the elevator \n136\n and the hoisting equipment are then operated to align and lower the bottom end of the additional tubular to proximate the upper end of the stump.', 'The iron roughneck \n170\n is moved \n178\n toward the drillstring \n106\n, and the lower gripper \n174\n clamps onto the stump of the drillstring \n106\n.', 'The spinning system \n172\n then rotates the suspended tubular to engage a threaded (e.g., male) connector with a threaded (e.g., female) connector at the top end of the stump.', 'Such spinning continues until achieving a predetermined torque, number of spins, vertical displacement of the additional tubular relative to the stump, and/or other operational parameters.', 'The upper gripper \n176\n then clamps onto and rotates the additional tubular with a higher torque sufficient to complete making up the connection with the stump.', 'In this manner, the additional tubular becomes part of the drillstring \n106\n.', 'The iron roughneck \n170\n then releases the drillstring \n106\n and is moved \n178\n clear of the drillstring \n106\n.', 'The grabber of the top drive \n116\n then grasps the drillstring \n106\n proximate the upper end of the drillstring \n106\n.', 'The drive shaft \n132\n is moved into contact with the upper end of the drillstring \n106\n and is rotated via operation of the prime mover to make up a connection between the drillstring \n106\n and the drive shaft \n132\n.', 'The grabber then releases the drillstring \n106\n, and the slips \n180\n are moved into the open position.', 'Drilling may then resume.\n \nFIG.', '1\n also depicts a pipe handling manipulator (PHM) \n182\n and a fingerboard \n184\n disposed on the rig floor \n112\n, although other implementations within the scope of the present disclosure may include one or both of the PHM \n182\n and the fingerboard \n184\n located elsewhere or excluded.', 'The fingerboard \n184\n provides storage (e.g., temporary storage) of tubulars \n194\n, such that the PHM \n182\n can be operated to transfer the tubulars \n194\n from the fingerboard \n184\n for inclusion in the drillstring \n106\n during drilling or tripping-in operations, instead of (or in addition to) from the catwalk \n166\n, and similarly for transferring tubulars \n194\n removed from the drillstring \n106\n to the fingerboard \n184\n during tripping-out operations.', 'The PHM \n182\n includes arms and clamps \n186\n collectively operable for grasping and clamping onto a tubular \n194\n while the PHM \n182\n transfers the tubular \n194\n to and from the drillstring \n106\n, the fingerboard \n184\n, and the catwalk \n166\n.', 'The PHM \n182\n is movable in at least one translation direction \n188\n and/or a rotational direction \n190\n around an axis of the PHM \n182\n.', 'The arms of the PHM \n182\n can extend and retract along direction \n192\n.', 'The tubulars \n194\n conveyed to the rig floor \n112\n via the catwalk \n166\n (such as for subsequent transfer by the elevator \n136\n and/or the PHM \n182\n to the drillstring \n106\n and/or the fingerboard \n184\n) may be single joints and/or double- or triple-joint stands, such as may be assembled prior to being fed onto the catwalk \n166\n.', 'In other implementations, the catwalk \n166\n may include means for making/breaking the multi-joint stands.', 'The multi joint stands may also be made up and/or broken out via cooperative operation of two or more of the top drive \n116\n, the drawworks \n124\n, the elevator \n136\n, the catwalk \n166\n, the iron roughneck \n170\n, the slips \n180\n, and the PHM \n182\n.', 'For example, the catwalk \n166\n may position a first joint (drill pipe, casing, etc.) to extend above the rig floor \n112\n or another orientation where the joint can be grasped by the elevator \n136\n.', 'The top drive \n116\n, the drawworks \n124\n, and the elevator \n136\n may then cooperatively transfer the first joint into the wellbore \n104\n, where the slips \n180\n may retain the first joint.', 'The catwalk \n166\n may then position a second joint that will be made up with the first joint.', 'The top drive \n116\n, the drawworks \n124\n, and the elevator \n136\n may then cooperatively transfer the second joint to proximate the upper end of the first joint extending up from the slips \n180\n.', 'The iron roughneck \n170\n may then make up the first and second joints to form a double stand.', 'The top drive \n116\n, the drawworks \n124\n, the elevator \n136\n, and the slips \n180\n may then cooperatively move the double stand deeper into the wellbore \n104\n, and the slips \n180\n may retain the double stand such that an upper end of the second joint extends upward.', 'If the contemplated drilling, casing, or other operations are to utilize triple stands, the catwalk \n166\n may then position a third joint to extend above the rig floor \n112\n, and the top drive \n116\n, the drawworks \n124\n, and the elevator \n136\n may then cooperatively transfer the third joint to proximate the upper end of the second joint extending up from the slips \n180\n.', 'The iron roughneck \n170\n may then make up the second and third joints to form a triple stand.', 'The top drive \n116\n (or the elevator \n136\n) and the drawworks \n124\n may then cooperatively lift the double or triple stand out of the wellbore \n104\n.', 'The PHM \n182\n may then transfer the stand from the top drive \n116\n (or the elevator \n136\n) to the fingerboard \n184\n, where the stand may be stored until retrieved by the PHM \n182\n for the drilling, casing, and/or other operations.', 'This process of assembling stands may generally be performed in reverse to disassemble the stands.', 'A power distribution center \n196\n is also at the wellsite.', 'The power distribution center \n196\n includes one or more generators, one or more AC-to-DC power converters, one or more DC-to-AC power inverters, one or more hydraulic systems, one or more pneumatic systems, the like, or a combination thereof.', 'The power distribution center \n196\n can distribute AC and/or DC electrical power to various motors, pumps, and other components of the well construction system \n100\n.', 'Similarly, the power distribution center \n196\n can distribute pneumatic and/or hydraulic power to various components of the well construction system \n100\n.', 'Components of the power distribution center \n196\n can be centralized in the well construction system \n100\n or can be distributed among several locations within the well construction system \n100\n.', 'A control center \n198\n is also at the wellsite.', 'The control center \n198\n houses one or more processing systems of a network of the well construction system \n100\n.', 'Details of the network of the well construction system \n100\n are described below.', 'Generally, various equipment of the well construction system \n100\n, such as the drilling fluid circulation system, the hoisting equipment, the top drive \n116\n, the PHM \n182\n, the catwalk \n166\n, etc., can have various sensors and controllers to monitor and control the operations of that equipment.', 'Additionally, the control center \n198\n can receive information regarding the formation and/or downhole conditions from modules and/or components of the BHA \n108\n.', 'The BHA \n108\n can comprise various components with various capabilities, such as measuring, processing, and storing information.', 'The BHA \n108\n may include a telemetry device \n109\n for communications with the control center \n198\n.', 'The BHA \n108\n shown in \nFIG.', '1\n is depicted as having a modular construction with specific components in certain modules.', 'However, the BHA \n108\n may be unitary, or select portions thereof may be modular.', 'The modules and/or components therein may be positioned in a variety of configurations within the BHA \n108\n.', 'For example, the BHA \n108\n may comprise one or more measurement-while-drilling (MWD) modules \n200\n that may include tools operable to measure wellbore trajectory, wellbore temperature, wellbore pressure, and/or other example properties.', 'The BHA \n108\n may comprise one or more logging-while-drilling (LWD) modules \n202\n that may include tools operable to measure formation parameters and/or fluid properties, such as resistivity, porosity, permeability, sonic velocity, optical density, pressure, temperature, and/or other example properties.', 'The BHA \n108\n may comprise one or more sampling-while-drilling (SWD) modules \n204\n for communicating a formation fluid through the BHA \n108\n and obtaining a sample of the formation fluid.', 'The SWD module(s) \n204\n may comprise gauges, sensor, monitors and/or other devices that may also be utilized for downhole sampling and/or testing of a formation fluid.', 'A person having ordinary skill in the art will readily understand that well construction systems other than the example depicted in \nFIG.', '1\n may include more, less, and/or different equipment than as described herein and/or depicted in the figures, but may still be within the scope of the present disclosure.', 'Additionally, various equipment and/or systems of the well construction systems within the scope of the present disclosure may include more, less, and/or different equipment than as described herein and/or depicted in the figures.', 'For example, various engines, motors, hydraulics, actuators, valves, or the like that are not described herein and/or depicted in the figures may be included in other implementations of equipment and/or systems also within the scope of the present disclosure.', 'The well construction systems within the scope of the present disclosure may also be implemented as land-based rigs or offshore rigs.', 'The equipment and/or systems of well construction systems within the scope of the present disclosure may be transferrable via land-based movable vehicles, such as trucks and/or trailers.', 'For example, the mast \n114\n, the PHM \n182\n (and associated frame), the drawworks \n124\n, the fingerboard \n184\n, the power distribution center \n196\n, the control center \n198\n, the mud tanks \n164\n (and associated pump \n142\n, shale shaker \n160\n, and reconditioning equipment \n162\n), and the catwalk \n166\n, among other examples, may each be transferrable by a separate truck and trailer combination.', 'Some of the equipment and/or systems may be collapsible to accommodate transfer on a trailer.', 'For example, the mast \n114\n, the fingerboard \n184\n, the catwalk \n166\n, and/or other equipment and/or systems may be telescopic, folding, and/or otherwise collapsible.', 'Other equipment and/or systems may be collapsible by other techniques, or may be separable into subcomponents for transportation purposes.', 'FIG.', '2\n is a schematic view of at least a portion of another example implementation of a well construction system \n250\n operable to drill a wellbore \n104\n into a subsurface formation \n102\n at a wellsite in accordance with one or more aspects of the present disclosure.', 'Some of the components and operation of those components are common (as indicated by usage of common reference numerals) between the well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively.', 'Hence, description of the common components may be omitted here for brevity, although a person of ordinary skill in the art will readily understand the components and their operation in the well construction system \n250\n of \nFIG.', '2\n.', 'A swivel \n256\n and kelly \n254\n are suspended from the mast \n114\n via the hoisting equipment.', 'The hook \n120\n mechanically couples with the swivel \n256\n, although other means for coupling the traveling block \n118\n with the swivel \n256\n are also within the scope of the present disclosure.', 'The kelly \n254\n is detachably mechanically coupled to the drillstring \n106\n.', 'A kelly spinner is between the kelly \n254\n and the swivel \n256\n, although not specifically illustrated.', 'The kelly \n254\n extends through an opening \n253\n through a master bushing (not specifically depicted) in the rig floor \n112\n and a kelly bushing \n258\n that engages the master bushing and the kelly \n254\n.', 'The rig floor \n112\n includes a rotary table that includes the master bushing and a prime mover.', 'The prime mover of the rotary table, through the master bushing and the kelly bushing \n258\n, provides a rotational force to drive rotational movement of the drillstring \n106\n to form the wellbore \n104\n.', 'Similar to as described above with respect to \nFIG.', '1\n, the pump \n142\n delivers drilling fluid through, for example, the discharge line \n144\n, the standpipe \n146\n, and the hose \n148\n to a port \n257\n of the swivel \n256\n.', 'The drilling fluid is then conducted through the kelly \n254\n and the drillstring \n106\n to the drill bit \n110\n.', 'Although not illustrated, tongs, a cathead, and/or a spinning wrench or winch spinning system may be used for making up and/or breaking out connections of tubulars.', 'A winch spinning system may include a chain, rope, or the like that is driven by a winch.', 'The spinning wrench or winch spinning system may be operable for applying low-torque spinning to make up and/or break out a threaded connection between tubulars of the drillstring \n106\n.', 'For example, with a winch spinning system, a human roughneck can wrap a chain around a tubular, and the chain is pulled by the winch to spin the tubular to make up and/or break out a connection.', 'The tongs and cathead can be used to apply higher torque to make up and/or break out the threaded connection.', 'For example, a human roughneck can manually apply tongs to tubulars, and the cathead mechanically coupled to the tongs (such as by chains) can apply a high torque to make up and/or break out the threaded connection.', 'Removable slips may be used in securing the drillstring \n106\n when making up and/or breaking out a connection.', 'For example, a human operator may place the slips between the drillstring \n106\n and the rig floor \n112\n and/or the master bushing of the rotary table to suspend the drillstring \n106\n in the wellbore \n104\n during make up and/or break out.', 'To form the wellbore \n104\n (e.g., “make hole”), the hoisting equipment lowers the drillstring \n106\n while the prime mover of the rotary table rotates the drillstring \n106\n via the master bushing and kelly bushing \n258\n.', 'During this advancement of the drillstring \n106\n, removable slips are removed from the opening \n253\n, and the tongs are clear of the drillstring \n106\n.', 'When the upper end of the kelly \n254\n nears the kelly bushing \n258\n and/or rig floor \n112\n, the hoisting equipment ceases downward movement of the kelly \n254\n, and the rotary table ceases rotating the drillstring \n106\n.', 'The hoisting equipment raises the kelly \n254\n until the upper end of the drillstring \n106\n protrudes from the master bushing and/or rig floor \n112\n, and the slips are placed in the opening \n253\n between the drillstring \n106\n and the master bushing and/or rig floor \n112\n to clamp the drillstring \n106\n.', 'When the kelly \n254\n is raised, a flange at the bottom of the kelly \n254\n can grasp the kelly bushing \n258\n to clear the kelly bushing \n258\n from the master bushing.', 'Human operators can then break out the connection between the kelly \n254\n and the drillstring \n106\n using the tongs and cathead for applying a high torque, and the prime mover of the rotary table can cause the drillstring \n106\n to rotate to spin out of the connection to the kelly \n254\n, for example.', 'A tubular may be positioned in preparation to being made up to the kelly \n254\n and the drillstring \n106\n.', 'For example, a tubular may be manually transferred to a mouse hole in the rig floor \n112\n.', 'Other methods and systems for transferring a tubular may be used.', 'With the connection between the drillstring \n106\n and the kelly \n254\n broken out, the hoisting equipment maneuvers the kelly \n254\n into a position such that a connection between the kelly \n254\n and the tubular projecting through the mouse hole can be made up.', 'Operators can then make up the connection between the kelly \n254\n and the tubular by spinning the kelly \n254\n with the kelly spinner and by using the tongs and cathead.', 'The hoisting equipment then raises and maneuvers the kelly \n254\n and attached tubular into a position such that a connection between the attached tubular and drillstring \n106\n can be made up.', 'Operators can then make up the connection between the tubular and the drillstring \n106\n by clamping one of the tongs to the tubular and spinning the kelly \n254\n with the kelly spinner and by using the tongs and cathead.', 'The slips are then removed from the opening \n253\n, and the drillstring \n106\n and kelly \n254\n are lowered by the hoisting equipment until the drill bit \n110\n engages the one or more subsurface formations \n102\n.', 'The kelly bushing \n258\n engages the master bushing and the kelly \n254\n.', 'Drilling may then resume.', 'A power distribution center \n196\n and control center \n198\n are also at the wellsite as described above.', 'The control center \n198\n houses one or more processing systems of a network of the well construction system \n250\n.', 'Details of the network of the well construction system \n250\n are described below.', 'Generally, various equipment of the well construction system \n250\n, such as the drilling fluid circulation system, the hoisting equipment, the rotary table, etc., can have various sensors and controllers to monitor and control the operations of that equipment.', 'Additionally, the control center \n198\n can receive information regarding the formation and/or downhole conditions from modules and/or components of the BHA \n108\n.', 'The BHA \n108\n can comprise various components with various capabilities, such as measuring, processing, and storing information, as described above.', 'A person having ordinary skill in the art will readily understand that a well construction system may include more or fewer equipment than as described herein and/or depicted in the figures.', 'Additionally, various equipment and/or systems of the example implementation of the well construction system \n250\n depicted in \nFIG.', '2\n may include more or fewer equipment.', 'For example, various engines, motors, hydraulics, actuators, valves, or the like that were not described above and/or depicted in \nFIG.', '2\n may be included in other implementations of equipment and/or systems also within the scope of the present disclosure.', 'Additionally, the well construction system \n250\n of \nFIG.', '2\n may be implemented as a land-based rig or on an offshore rig.', 'One or more aspects of the well construction system \n250\n of \nFIG.', '2\n may be incorporated in and/or omitted from a land-based rig or an offshore rig.', 'Such modifications are within the scope of the present disclosure.', 'One or more equipment and/or systems of the well construction system \n250\n of \nFIG.', '2\n may be transferrable via a land-based movable vessel, such as a truck and/or trailer.', 'For example, the mast \n114\n, the drawworks \n124\n, the fingerboard \n184\n, the power distribution center \n196\n, the control center \n198\n, mud tanks \n164\n (and associated pump \n142\n, shale shaker \n160\n, and reconditioning equipment \n162\n), and/or other examples may each be transferrable by a separate truck and trailer combination.', 'Some of the equipment and/or systems may be collapsible to accommodate transfer on a trailer.', 'For example, the mast \n114\n, the fingerboard \n184\n, and/or other equipment and/or systems may be telescopic, folding, and/or otherwise collapsible.', 'Other equipment and/or systems may be collapsible by other techniques, or may be separable into subcomponents for transportation purposes.', 'The well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively, illustrate various example equipment and systems that may be incorporated in a well construction system.', 'Various other example well construction systems may include another combination of equipment and systems described with respect to the well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively, and may omit some equipment and/or systems and/or include additional equipment and/or systems not specifically described herein.', 'Such well construction systems are within the scope of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of an operations network \n300\n according to one or more aspects of the present disclosure.', 'The physical network used to implement the operations network \n300\n of \nFIG.', '3\n can have a network topology, such as a bus topology, a ring topology, a star topology, and/or mesh topology, among other examples also within the scope of the present disclosure.', 'The operations network \n300\n can include one or more processing systems, such as one or more network appliances (like a switch or other processing system), that are configured to implement various virtual networks, such as virtual local area networks (VLANs).', 'Additionally, the operations network \n300\n can include one or more processing systems, such as one or more network appliances (like a switch or other processing system), that are configured with an intrusion detection system (IDS) to monitor traffic across the operations network \n300\n, such as may be in respective virtual networks.', 'The IDS can alert personnel to potential cyber security breaches that may occur on the operations network \n300\n.', 'The operations network \n300\n includes a configuration manager \n302\n, which may be a software program instantiated and operable on one or more processing systems, such as one or more network appliances.', 'The configuration manager \n302\n may be a software program written in and compiled from a high-level programming language, such as C/C++ or the like.', 'As described in further detail below, the configuration manager \n302\n is operable to translate communications from various communications protocols to a common communication protocol and make the communications translated to the common communication protocol available through a common data bus, and vice versa.', 'The common data bus may include an application program interface (API) of the configuration manager \n302\n and/or a common data virtual network (VN-DATA) implemented on one or more processing systems, such as network appliances like switches.', 'The configuration manager \n302\n can have predefined classes for objects to implement the translations of communication.', 'Instantiated objects in the configuration manager \n302\n for subsystems can be used to receive communications from the subsystems according to respective (and possibly different) communication protocols implemented by the subsystems, and to translate the communications to a common protocol, which is made available on the common data bus, and vice versa.', 'The classes can define objects at the subsystem level (e.g., drilling control system, drilling fluid circulation system, cementing system, etc.), the equipment level (e.g., top drive, drawworks, drilling fluid pump, etc.), and/or the data level (e.g., type of commands, sensor data, and/or status data).', 'Hence, an object can be instantiated for each instance of a subsystem, equipment, and/or data type depending on how the class of the object was defined.', 'Further, the classes can define objects based on the communication protocols to be implemented by the subsystems.', 'Hypothetically, assuming two subsystems that are identical except that each implements a different communication protocol, the configuration manager \n302\n may instantiate objects for the subsystems from different classes that were defined based on the different communication protocols.', 'Objects can be instantiated at set-up of the operations network \n300\n and/or by dynamically detecting ECs and/or subsystems.', 'As will become apparent from description below, using a configuration manager, such as the configuration manager \n302\n in \nFIG.', '3\n, may permit simpler deployment of subsystems in a well construction system and associated communications equipment, for example.', 'The use of a software program compiled from a high-level language may permit deployment of an updated version of a configuration manager when an additional, previously undefined subsystem is deployed, which may alleviate deployment of physical components associated with the configuration manager (e.g., when adding equipment/subsystems to the well construction system).', 'Further, applications that access data from the configuration manager (e.g., through the common data bus) can be updated through a software update when new data becomes available by the addition of a new subsystem, such that the updated application can consume data generated by the new subsystem.', 'One or more processing systems of the operations network \n300\n, such as one or more switches and/or other network appliances, are configured to implement one or more subsystem virtual networks (e.g., VLANs), such as a first subsystem virtual network (VN-S1) \n304\n, a second subsystem virtual network (VN-S2) \n306\n, and an Nth subsystem virtual network (VN-SN) \n308\n as illustrated in \nFIG.', '3\n.', 'More or fewer subsystem virtual networks may be implemented.', 'The subsystem virtual networks (e.g., VN-S1 \n304\n, VN-S2 \n306\n, and VN-SN \n312\n) are logically separate from each other.', 'The subsystem virtual networks can be implemented according to the IEEE 802.1Q standard, another standard, or a proprietary implementation.', 'Each subsystem virtual network can implement communications with the EC(s) of the respective subsystem based on various protocols, such as an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication, or the like), a proprietary communication protocol, and/or another communication protocol.', 'Further, the subsystem virtual networks can implement publish-subscribe communications.', 'The subsystem virtual networks can implement the same protocol, each subsystem virtual network can implement a different protocol, or a combination therebetween.', 'In the example depicted in \nFIG.', '3\n, a first control subsystem (S1) \n310\n, a second control subsystem (S2) \n312\n, and an N\nth \ncontrol subsystem (SN) \n314\n are various control subsystems of a well construction system.', 'Example subsystems include a drilling fluid circulation system (which may include mud pumps, valves, fluid reconditioning equipment, etc.), a rig control system (which may include hoisting equipment, drillstring rotary mover equipment (such as a top drive and/or rotary table), a PHM, a catwalk, etc.), a managed pressure drilling system, a cementing system, a rig walk system, etc.', 'A subsystem may include a single piece of equipment, or may include multiple pieces of equipment that, for example, that are jointly used to perform one or more functions.', 'Each subsystem includes one or more ECs, which may control equipment of the subsystem and/or receive sensor and/or status data from sensors and/or equipment of the subsystem.', 'In the example depicted in \nFIG.', '3\n, the S1 \n310\n includes a first S1 EC (EC-S1-1) \n318\n, a second S1 EC (EC-S1-2) \n320\n, a third S1 EC (EC-S1-3) \n322\n, and a fourth S1 EC (EC-S1-4) \n324\n.', 'The S2 \n312\n includes a first S2 EC (EC-S2-1) \n326\n and a second S2 EC (EC-S2-2) \n328\n.', 'The SN \n314\n includes a first SN EC (EC-SN-1) \n330\n, a second SN EC (EC-SN-2) \n332\n, and a third SN EC (EC-SN-3) \n334\n.', 'Other numbers of control subsystems may be implemented, and other numbers of ECs may be used in each control subsystem.', 'Some example control subsystems are described below following description of various aspects of \nFIG.', '3\n.', 'Each EC can implement logic to monitor and/or control one or more sensors and/or one or more controllable components of the respective subsystem.', 'Each EC can include logic to interpret a command and/or other data, such as from one or more sensors or controllable components, and to communicate a signal to one or more controllable components of the subsystem to control the one or more controllable components in response to the command and/or other data.', 'Each EC can also receive a signal from one or more sensors, and can reformat the signal (e.g., from an analog signal to a digital signal) into interpretable data.', 'The logic for each EC can be programmable, such as compiled from a low-level programming language, such as described in IEC 61131 programming languages for PLCs, structured text, ladder diagram, functional block diagrams, functional charts, or the like.', 'As also illustrated in the example depicted in \nFIG.', '3\n, a downhole system (DH) \n316\n is an example sensor system of the well construction system.', 'The DH \n316\n includes surface equipment \n336\n that is communicatively coupled to a bottom hole assembly (BHA) on a drillstring (e.g., the BHA \n108\n of the drillstring \n106\n in \nFIGS.', '1 and 2\n).', 'The surface equipment \n336\n receives (e.g., via telemetry equipment) data from the BHA, such as data relating to conditions in the wellbore, conditions of the subterranean formation \n102\n, and/or conditions/parameters of components of the BHA, among other examples.', 'The surface equipment \n336\n in this example does not control operations of equipment.', 'Other sensor subsystems may also or instead be included in the operations network \n300\n.', 'The operations network \n300\n includes a coordinated controller \n338\n, which may be a software program instantiated and operable on one or more processing systems, such as one or more network appliances.', 'The coordinated controller \n338\n may be a software program written in and compiled from a high-level programming language, such as C/C++ or the like.', 'The coordinated controller \n338\n can control operations of subsystems and communications as described in further detail below.', 'The operations network \n300\n also includes one or more human-machine interfaces (HMIs), such as the HMI \n340\n in the example implementation depicted in \nFIG.', '3\n.', 'The HMI \n340\n may be, comprise, or be implemented by one or more processing systems with a keyboard, a mouse, a touchscreen, a joystick, one or more control switches or toggles, one or more buttons, a track-pad, a trackball, an image/code scanner, a voice recognition system, a display device (such as a liquid crystal display (LCD), a light-emitting diode (LED) display, and/or a cathode ray tube (CRT) display), a printer, speaker, and/or other examples.', 'A human operator may use the HMI \n340\n for entry of commands to the coordinated controller \n338\n, and the HMI \n340\n may permit visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data.', 'The HMI may be a part of a control subsystem, and may issue commands through a subsystem virtual network to one or more of the ECs of that subsystem virtual network without using the coordinated controller \n338\n.', 'Each HMI can be associated with and control a single or multiple subsystems.', 'An HMI may also or instead control an entirety of the system that includes each subsystem.', 'The operations network \n300\n also includes a historian \n342\n, which may be a database maintained and operated on one or more processing systems, such as database devices, for example.', 'The historian \n342\n may be distributed across multiple processing systems and/or may be maintained in memory, which can include external storage, such as a hard disk or drive.', 'The historian \n342\n may access sensor data and/or status data, which is stored and maintained in the historian \n342\n.', 'The operations network \n300\n further includes one or more process applications \n344\n, which may each or collectively be a software program instantiated and operable on one or more processing systems, such as one or more server devices and/or other network appliances.', 'The process applications \n344\n may each be a software program written in and compiled from a high-level programming language, such as C/C++ or the like.', 'The process applications \n344\n may analyze data and output one or more job plans to the coordinated controller \n338\n, and/or may monitor data that is accessible and/or consumed from the common data bus.', 'An example of the process applications \n344\n can include a drilling operation plan, and another example can include a cementing operation plan.', 'Various job plans can be self-contained, or can refer to one or more other plans.', 'Processing systems that process data for control of various subsystems can have resources dedicated for such processing.', 'For example, the one or more processing systems on which the coordinated controller \n338\n operates, the one or more processing systems on which the configuration manager \n302\n operates, the one or more processing systems that are configured to implement the virtual networks, and/or other processing systems may have resources dedicated to processing and communicating commands and/or sensor and/or status data used to determine appropriate commands to issue.', 'By dedicating resources in this manner, control of processes in the well construction system may be real-time.', 'Other communications and processing may be may be handled in a non-real-time manner without using dedicated resources.', 'Referring to communications within the operations network \n300\n, each EC within a control subsystem can communicate with other ECs in that control subsystem through the subsystem virtual network for that control subsystem (e.g., through processing systems configured to implement the subsystem virtual network).', 'Sensor data, status data, and/or commands from an EC in a subsystem can be communicated to another EC within that subsystem through the subsystem virtual network for that subsystem, for example, which may occur without intervention of the coordinated controller \n338\n.', 'As an example from the example operations network \n300\n depicted in \nFIG.', '3\n, EC-S1-1 \n318\n can communicate sensor data, status data, and/or commands to EC-S1-3 \n322\n via VN-S1 \n304\n, and vice versa, without intervention of the coordinated controller \n338\n.', 'Other ECs within a subsystem can similarly communicate through their respective subsystem virtual network.', 'Communications from a subsystem virtual network to another processing system outside of that subsystem and respective subsystem virtual network can be translated from the communications protocol used for that subsystem virtual network to a common protocol (e.g., data distribution service (DDS) protocol or other examples) by the configuration manager \n302\n.', 'The communications that are translated to a common protocol may also be available to other processing systems via the common data bus, for example.', 'Sensor data and/or status data from the control subsystems (e.g., S1 \n310\n, S2 \n312\n, and SN \n314\n) may be available (e.g., directly available) for consumption by ECs of different subsystems, the coordinated controller \n338\n, the HMI \n340\n, the historian \n342\n, and/or the process applications \n344\n via the common data bus.', 'ECs may also communicate sensor data and/or status data to another EC in another subsystem via the common data bus.', 'For example, if a sensor in the S1 \n310\n communicates a signal to the EC-S1-1 \n318\n, and the data generated from that sensor is also used by the EC-S2-1 \n326\n in the S2 \n312\n to control one or more controllable components of the S2 \n312\n, the sensor data can be communicated from the EC-S1-1 \n318\n via the VN-S1 \n304\n, the common data bus, and the VN-S2 \n306\n to the EC-S2-1 \n326\n.', 'Other ECs within various subsystems can similarly communicate sensor data and/or status data through the common data bus to one or more other ECs in different subsystems.', 'Similarly, for example, if one or more of the process applications \n344\n consume data generated by a sensor coupled to the EC-S1-1 \n318\n in the S1 \n310\n, the sensor data can be communicated from the EC-S1-1 \n318\n via the VN-S1 \n304\n and the common data bus, where the one or more process applications \n344\n can access and consume the sensor data.', 'Similarly, communications from a sensor subsystem (e.g., the DH \n316\n) can be translated from the communications protocol used for that sensor subsystem to the common protocol by the configuration manager \n302\n.', 'The communications that are translated to a common protocol can be made available to other processing systems via the common data bus, for example.', 'Similar to above, sensor data and/or status data from the sensor subsystem may be available (e.g., directly available) for consumption by ECs of control subsystems, the coordinated controller \n338\n, the HMI \n340\n, the historian \n342\n, and/or the process applications \n344\n via the common data bus.', 'The coordinated controller \n338\n can also implement logic to control operations of the well construction system.', 'The coordinated controller \n338\n can monitor various statuses of components and/or sensors and can issue commands to various ECs to control the operation of the controllable components within one or more subsystems.', 'Sensor data and/or status data can be monitored by the coordinated controller \n338\n via the common data bus, and the coordinated controller \n338\n can issue commands to one or more ECs via the respective subsystem virtual network of the EC.', 'The coordinated controller \n338\n can implement logic to generate commands based on a job plan from one or more process applications \n344\n, and to issue those commands to one or more ECs in one or more subsystems.', 'The one or more process applications \n344\n may communicate a generalized command to the coordinated controller \n338\n, such as through the common data bus.', 'The generalized command may include an intended general operation (e.g., drilling into a formation) and defined constraints of parameters that can affect the operation.', 'For example, the defined constraints for a drilling operation may include a desired function of rate of penetration (ROP) of the drilling related to a top drive revolutions per minute (RPM) and weight on bit (WOB).', 'The coordinated controller \n338\n may interpret the generalized command and translate it to specified commands (that are interpretable by appropriate ECs) that are then issued to ECs to control various controllable components.', 'The coordinated controller \n338\n can further monitor the status of various equipment and/or sensor data to optimize operations of equipment of subsystems based on the status and/or sensor data that is fed back.', 'By feeding back and monitoring data of the environment of the well construction, the coordinated controller \n338\n can continuously update commands to account for a changing environment.', 'For example, if the ROP is greater or less than anticipated by the plan, the coordinated controller \n338\n can calculate and issue commands to increase or decrease one or both of top drive RPM and WOB.', 'Similarly, one or more of the process applications \n344\n can monitor status and/or sensor data available through the common data bus to monitor a progression of an operation, and/or to update a job plan based on a changing environment.', 'If the operation progresses as planned within the various constraints, for example, the process applications \n344\n may not update the job plan and can permit operations to continue based on the job plan that is being implemented.', 'If the operation progresses differently from what was planned, which may be indicated by the status and/or sensor data, the process applications \n344\n may alter the job plan and communicate the altered job plan to the coordinated controller \n338\n for implementation.\n \nFIG.', '4\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n400\n) for controlling operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (\n400\n) may be performed by, utilizing, or otherwise in association with one or more features depicted in one or more of \nFIGS.', '1-3\n described above, one or more features depicted in \nFIGS.', '7 and/or 9\n described below, and/or one or more features otherwise within the scope of the present disclosure.', 'However, for the sake of simplicity, the method (\n400\n) is described below in the context of the example implementation depicted in \nFIG.', '3\n and/or otherwise described above, and a person having ordinary skill in the art will recognize that the following description of the method (\n400\n) is also applicable or readily adaptable for operations networks other than the example operations network \n300\n depicted in \nFIG.', '3\n.', 'The method (\n400\n) may include developing (\n402\n) a job plan, such as by one or more of the process applications \n344\n.', 'The job plan may be developed (\n402\n) based on geological and/or geophysical data measured or otherwise believed to be descriptive of the target formation(s) of the well being constructed, and/or one or more geological, geophysical, and/or engineering databases.', 'The developed (\n402\n) job plan may include details pertaining to the trajectory of the well, the mud to be used during drilling, casing design, drill bits, BHA components, and the like.', 'The method (\n400\n) includes implementing (\n404\n) the job plan, such as by the coordinated controller \n338\n as described above.', 'Implementing (\n404\n) the job plan may comprise operating (and/or causing the operation of) the well construction system to form the well according to the developed (\n402\n) job plan.', 'The operation details (e.g., WOB, top drive RPM, mud flow rate, etc.) may be determined during the development (\n402\n) and/or implementation (\n404\n) of the job plan.', 'The method (\n400\n) also includes monitoring (\n406\n) status and/or sensor data, such as by one or more of the process applications \n344\n and the coordinated controller \n338\n, as the job operations continue.', 'The method (\n400\n) also includes determining (\n408\n) whether the implementation of the job plan should be updated based on the monitored (\n406\n) status and/or sensor data.', 'The coordinated controller \n338\n may perform the determination (\n408\n).', 'The determination (\n410\n) may be based on one or more indications in (or derived from) the monitored (\n406\n) status and/or sensor data that the operations are deviating from an intended progression of the job plan implementation (\n404\n), and/or that the initial job plan implementation (\n404\n) was faulty in light of new data.', 'If the determination (\n408\n) is that the implementation will not be updated, operations continue while monitoring (\n406\n) the status and/or sensor data, such as by the coordinated controller \n338\n.', 'If the determination (\n408\n) is that the implementation will be updated, the existing job plan implementation (\n404\n) is updated (\n409\n) based on the monitored (\n406\n) status and/or sensor data, such as by the coordinated controller \n338\n.', 'The status and/or sensor data monitoring (\n406\n) and job operations then continue.', 'The method (\n400\n) also comprises determining (\n410\n) whether the job plan should be updated based on the monitored (\n406\n) status and/or sensor data.', 'One or more of the process applications \n344\n may perform the determination (\n410\n).', 'The determination (\n410\n) may be based on one or more indications in (or derived from) the monitored (\n406\n) status and/or sensor data that the operations are deviating from an anticipated progression of the job plan, and/or that the initially developed (\n402\n) job plan was faulty in light of new data.', 'If the determination (\n410\n) is that the job plan will not be updated, operations continue while monitoring (\n406\n) the status and/or sensor data, such as by one or more of the process applications \n344\n.', 'If the determination (\n410\n) is that the job plan will be updated, the job plan is updated (based on the monitored (\n406\n) status and/or sensor data) and implemented (\n411\n), such as by one or more of the process applications \n344\n.', 'The status and/or sensor data monitoring (\n406\n) and job operations then continue.', 'The method (\n400\n) may continue until the initially developed (\n402\n) or updated (\n411\n) job plan is completed.', 'Developing a job plan may be calculation intensive, and may thus be developed over a longer period of time, which may not be real-time to the operations.', 'The coordinated controller \n338\n (e.g., the one or more processing systems on which the coordinated controller \n338\n operates) may have resources (e.g., processing resources) dedicated to control of various systems, which permit such control to be real-time (e.g., within a known, determinable period of time).', 'Further, the implementation may be updated by simpler processes, which may permit real-time updates to the implementation.', 'The real-time updates may permit optimized control of operations being implemented by a job plan.', "The coordinated controller \n338\n can control issuance of commands to ECs generated in response to an actor outside of the ECs' respective subsystem virtual networks.", 'Thus, for example, the HMI \n340\n can issue a command to one or more ECs in a subsystem through the common data bus under the control of the coordinated controller \n338\n and through the subsystem virtual network of that subsystem.', 'For example, a user may input commands through the HMI \n340\n to control an operation of a subsystem.', 'Commands to an EC of a subsystem from an actor outside of that subsystem may be prohibited in the operations network \n300\n without the coordinated controller \n338\n processing the command.', 'The coordinated controller \n338\n can implement logic to determine whether a given actor (e.g., the HMI \n340\n and/or process applications \n344\n) can cause a command to be issued to a given EC in a subsystem.', 'The coordinated controller \n338\n can implement logic to arbitrate commands that would control the operation of a particular equipment or subsystem, such as when there are multiple actors (e.g., job plans and/or HMIs) attempting to cause commands to be issued to the same equipment or subsystem at the same time.', 'The coordinated controller \n338\n can implement an arbiter (e.g., logic) to determine which of conflicting commands from HMIs and/or job plans to issue to an EC.', 'For example, if a first job plan attempts to have a command issued to the EC-SN-1 \n330\n to increase a pumping rate of a pump, and a second job plan simultaneously attempts to have a command issued to the EC-SN-1 \n330\n to decrease the pumping rate of the same pump, the arbiter of the coordinated controller \n338\n can resolve the conflict and determine which command is permitted to be issued.', 'Additionally, as an example, if two HMIs issue conflicting commands simultaneously, the coordinated controller \n338\n can determine which command to prohibit and which command to issue.', 'The arbiter of the coordinated controller \n338\n may operate using a hybrid first in, first served and prioritization scheme.', 'For example, the first command that is issued is permitted to operate to completion or until the actor that caused the command to be issued terminates the execution of that command.', 'In some examples, a single, self-contained job plan that is to be executed alone without the execution of another job plan can generally be implemented without generating conflicting commands.', 'However, a job plan may refer to another job plan, which may result in conflicting commands being generated.', 'For example, a job plan for a cementing process can refer to a job plan for a drilling process in order to operate a pump, and by executing the job plan for the cementing process that refers to the job plan for the drilling process, multiple conflicting commands may be generated for the pump by operation of the two job plans.', 'The arbiter handles these commands by permitting the first command that is generated by one of the job plans to be completed or until the generating job plan terminates the first command, even though a second subsequent and conflicting command is generated by the other of the job plans.', 'The second command is placed in a queue until the first command is completed or terminated by its generating job plan, and then the arbiter permits the second command to be issued and executed.', 'Some actors within the operations network \n300\n may be assigned a priority that permits those actors to interrupt operations and/or commands regardless of the current state of the process.', 'For example, an HMI can be assigned a high priority that permits a command from the HMI to interrupt an operation and/or command that is being executed.', 'The command from the HMI may be executed, despite the current state of the process, until the command is completed or terminated by the sending HMI.', 'After the command from the HMI has been executed, the process may return to its previous state or restart based on new conditions on which the job plan and/or implementation of the job plan is based.\n \nFIG.', '5\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n500\n) for controlling operations of a well construction system, including implementing an arbiter, according to one or more aspects of the present disclosure.', 'The method (\n500\n) may be performed by, utilizing, or otherwise in association with one or more features depicted in one or more of \nFIGS.', '1-3\n described above, one or more features depicted in \nFIGS.', '7 and/or 9\n described below, and/or one or more features otherwise within the scope of the present disclosure.', 'However, for the sake of simplicity, the method (\n500\n) is described below in the context of the example implementation depicted in \nFIG.', '3\n and/or otherwise described above, and a person having ordinary skill in the art will recognize that the following description of the method (\n500\n) is also applicable or readily adaptable for operations networks other than the example operations network \n300\n depicted in \nFIG.', '3\n.', 'Also, as described in more detail below, the method (\n500\n) may not flow linearly as illustrated in \nFIG.', '5\n.', 'The method (\n500\n) includes receiving (\n502\n) one or more commands generated from one or more non-prioritized actors.', 'For example, an arbiter can receive one or more commands that have been generated from one or more job plans, which may be non-prioritized.', 'The method (\n500\n) includes issuing (\n504\n) the earliest received, non-issued command.', 'For example, the arbiter can effectively queue commands from non-prioritized actors, and the first command received from a non-prioritized actor is the first command that is issued by the arbiter.', 'The method (\n500\n) comprises executing (\n506\n) the issued command until the command is completed or terminated by the sending actor.', 'The execution (\n506\n) of the issued command may be a discrete, instantaneous function by equipment, a function performed by equipment over a defined duration, a function performed by equipment until defined conditions are met (which may be indicated by the sending actor), and/or other example means of execution.', 'The method (\n500\n) then loops back to issuing (\n504\n) the earliest received, non-issued command.', 'During the issuance (\n504\n) and the execution (\n506\n), commands can continue to be received (\n502\n) from one or more non-prioritized actors, which commands are queued for issuance.', 'Hence, the receiving (\n502\n), issuing (\n504\n), and executing (\n506\n) may implement a first in, first served type of queue.', 'During the receiving (\n502\n), issuing (\n504\n), and executing (\n506\n), the method (\n500\n) includes receiving (\n508\n) a command from a prioritized actor.', 'The receipt (\n508\n) of a command from a prioritized actor interrupts the flow of the receiving (\n502\n), issuing (\n504\n), and executing (\n506\n) commands from non-prioritized actors, and hence, the command from the prioritized actor has priority over commands from non-prioritized actors.', 'Example prioritized actors can include HMIs or others.', 'The method (\n500\n) includes issuing (\n510\n) the command received from the prioritized actor, and executing (\n512\n) the issued command until the command is completed or terminated by the sending actor.', 'The execution (\n512\n) of the issued command may be a discrete, instantaneous function by equipment, a function performed by equipment over a defined duration, a function performed by equipment until defined conditions are met (which may be indicated by the sending actor), and/or other example means of execution.', 'After the execution (\n512\n) of the command received (\n508\n) from the prioritized actor, the method (\n500\n) may resume at various instances.', 'For example, after the execution (\n512\n), the method (\n500\n) may resume at the instance where the receipt (\n508\n) of the command from the prioritized actor interrupted the flow of the receiving (\n502\n), issuing (\n504\n), and executing (\n506\n) one or more commands received from one or more non-prioritized actors.', 'Additionally, the execution (\n512\n) of the command received (\n508\n) from the prioritized actor can change conditions at the wellsite to an extent that non-prioritized actors withdraw previously sent commands and begin sending commands that are updated in response to the conditions that changed as a result of the execution (\n512\n) of the command from the prioritized actor.', 'Thus, the method (\n500\n) may resume at receiving (\n502\n) one or more commands from one or more non-prioritized actors regardless of the instance when the receipt (\n508\n) of the command from the prioritized actor occurred.', 'In some examples of the implementation of the example method (\n500\n) of \nFIG.', '5\n, the arbiter receives (\n502\n, \n508\n) and issues (\n504\n, \n510\n) the commands, which commands may be received from other logic of the coordinated controller \n338\n that implements one or more job plans received from one or more process applications \n344\n.', 'The arbiter can determine which commands the coordinated controller \n338\n is to issue to one or more ECs, and the ECs may execute (\n506\n, \n512\n) the commands by controlling various equipment of the well construction system at the wellsite, for example.', 'Other components and/or processing systems can implement various operations in other examples.', 'By permitting different subsystems to communicate as described above, a single clock may be used to synchronize multiple clocks of the processing systems of the operations network \n300\n.', 'For example, the coordinated controller \n338\n may periodically synchronize the clock of its one or more processing systems with a clock of a Global Positioning System (GPS) or other system.', 'The coordinated controller \n338\n may then cause clocks of other processing systems of the operations network \n300\n to be synchronized with the clock of the coordinated controller \n338\n.', 'This synchronization process permits time stamps of, e.g., commands and sensor and/or status data to be synchronized to a single clock.', 'This may permit improved control, in that conversion between clocks may be obviated for issuance of commands, for example.', 'Further, data stored and maintained on the historian \n342\n, for example, may be interpreted more easily by personnel.', 'When an additional subsystem is added to the operations network \n300\n, and/or when an additional EC is added to an existing subsystem of the operations network \n300\n, such that the new subsystem and/or EC is connected to the physical network, the configuration manager \n302\n may automatically instantiate one or more respective objects of the predefined classes corresponding to the new subsystem and/or EC to permit communications to and from the new subsystem and/or EC to be communicated through the common data bus.', 'For example, after the operations network \n300\n is initiated and begins operation, a new (albeit predefined in the configuration manager \n302\n) EC may subsequently be connected to the physical network of the operations network \n300\n.', 'The new EC may be for new equipment that is to become part of an existing subsystem, for equipment of a new subsystem, and/or for other situations.', 'For example, a new EC for a new pump may be added to an existing drilling fluid circulation system, or a new EC for equipment may be added to create a new cementing system, among other examples.', 'When the EC becomes connected to the physical network, the EC can communicate its presence through the physical network, such as by a multicast or broadcast message.', 'The configuration manager \n302\n can receive the communication and, based on this communication (and possibly subsequent communications with the EC), the configuration manager \n302\n can instantiate a new object based on the type of equipment and/or subsystem with which the EC is used.', 'After this object is instantiated, the EC can communicate through the common data bus to communicate sensor and/or status data to the common data bus and/or to receive commands through the common data bus.', 'The new subsystem and/or EC can be segmented into an existing virtual network or in a newly created virtual network.', 'For example, during the set-up of the operations network \n300\n, various unused ports of switches and/or other network appliances may be mapped to various virtual networks (e.g., VLANs), some of which virtual networks may be used upon initiating the operations network \n300\n, and some of which may be allocated for future use upon initiating the operations network \n300\n.', 'The new EC can be connected to a previously unused port that is mapped to a virtual network that is in use for an existing subsystem for the EC to become part of that subsystem, or the new EC can be connected to a previously unused port that is mapped to a virtual network that was allocated for future use to create a new subsystem.', 'In other example implementations, other segmentation techniques may be used, such as dynamic domain segmentation.', 'FIG.', '6\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n600\n) for connecting an EC (and/or similarly for connecting a subsystem) to an existing network of a well construction system according to one or more aspects of the present disclosure.', 'The method (\n600\n) includes connecting (\n602\n) the EC to the physical network of the operations network \n300\n.', 'As described above, connecting (\n602\n) the EC can include connecting the EC to an existing port of a network appliance of the operations network \n300\n, which may be configured to implement a virtual network.', 'The method (\n600\n) then includes announcing (\n604\n), by the EC (or another data processing system, such as one implementing a gateway when used in a different network), its presence on the physical network.', 'The EC can announce (\n604\n) its presence by transmitting a multicast message, broadcast message, and/or other communication through the physical network.', 'The configuration manager \n302\n receives the communication from the EC announcing (\n604\n) its presence, and then, the method (\n600\n) includes handshaking (\n606\n) between the EC and the configuration manager \n302\n.', 'The handshaking (\n606\n) can establish a communication channel between the EC and the configuration manager \n302\n and can further permit the EC to identify itself, such as including a type of equipment and/or subsystem with which the EC is associated.', 'For example, the EC may establish that it is associated with a new pump that is to be a part of the existing drilling fluid circulation system.', 'The method (\n600\n) includes determining (\n608\n) whether the EC is authorized to be on the operations network \n300\n.', 'This may be part of the handshaking (\n606\n) between the EC and the configuration manager \n302\n.', 'The determination (\n608\n) may be based on one or more conditions.', 'Example conditions that may cause the EC to be unauthorized can include that the EC and/or its associated equipment may not be recognizable by the configuration manager \n302\n; addition of the EC and/or its associated equipment may exceed a specified number of ECs and/or associated equipment permitted for a subsystem; operating conditions of the well construction system may prohibit addition of the EC and/or its associated equipment; failure by the EC to transmit an authorization certificate accepted by the configuration manager; and/or other example conditions.', 'If the determination (\n608\n) is that the EC is not authorized, the method (\n600\n) includes sending (\n610\n) an alert from the configuration manager \n302\n.', 'The alert can be to personnel devices to alert the personnel of an unauthorized device being connected to the operations network \n300\n and/or to one or more processing systems, such as one or more network appliances, to lock the EC out of the operations network \n300\n.', 'Other actions can also or instead be taken in response to the EC not being authorized.', 'If the determination (\n608\n) is that the EC is authorized, the method (\n600\n) includes instantiating (\n612\n) an object for the EC by the configuration manager \n302\n.', 'The object can correspond to a type of subsystem, control data, and/or sensor and/or status data with which the EC is associated, for example.', 'The object can be in various forms, and can contain various information.', 'Further, the object can be instantiated based on the protocol that the EC implements for communications.', 'For example, translations of communications may differ depending on the protocol implemented between the configuration manager \n302\n and the EC.', 'The configuration manager \n302\n may include predefined classes for instantiating various objects depending on the protocol used to communicate with the EC.', 'With the object instantiated (\n612\n), the method (\n600\n) includes communicating (\n614\n) with the EC via the common data bus using the object to translate communications between the common data bus and the EC.', 'For example, the EC can communicate sensor and/or status data to the common data bus using the object, which data can be consumed by, e.g., the coordinated controller \n318\n, process applications \n320\n, etc., and can receive commands from, e.g., the coordinated controller \n318\n through the common data bus using the object.', 'By dynamically detecting ECs and/or subsystems, various ECs and/or subsystems may be added to the well construction system more easily and transparent to job plan(s) and/or the coordinated controller.', 'This may permit simpler deployment of the well construction system while being able to maintain robust communications and rich data throughout the network.', 'Other configurations of an operations network are also within the scope of the present disclosure.', 'Different numbers of ECs, different numbers of subsystems and subsystem virtual networks, and different physical topologies and connections are also within the scope of the present disclosure.', 'Additionally, other example implementations may include or omit an HMI and/or a historian, for example.', 'As an example subsystem, a drilling fluid circulation system can incorporate one or more ECs that control one or more controllable components.', 'Controllable components in the drilling fluid circulation system may include one or more pumps (e.g., pump \n142\n in \nFIGS.', '1 and 2\n), a shale shaker (e.g., shale shaker \n160\n), a desilter, a desander, a degasser (e.g., reconditioning equipment \n162\n), a hopper, various valves that may be on pipes and/or lines, and other components.', 'For example, a pump may be controllable by an EC to increase/decrease a pump rate by increasing/decreasing revolutions of a prime mover driving the pump, and/or to turn the pump on/off.', 'Similarly, a shale shaker may be controllable by an EC to increase/decrease vibrations of a grating, and/or to turn on/off the shale shaker.', 'A degasser may be controllable by an EC to increase/decrease a pressure in the degasser by increasing/decreasing revolutions of a prime mover of a vacuum pump of the degasser, and/or to turn on/off the degasser.', 'A hopper may be controllable by an EC to open/close a valve of the hopper to control the release of an additive (e.g., caustic soda) into a pipe and/or line through which drilling fluid flows.', 'Further, various relief valves, such as a relief discharge value on a discharge line of a drilling fluid pump, a relief suction valve on an intake or suction line of a drilling fluid pump, or the like, may be controllable by an EC to be opened/closed (such as to relieve pressure).', 'The controllable components may be controlled by a digital signal and/or analog signal from an EC.', 'A person of ordinary skill in the art will readily envisage other example controllable components in a drilling fluid circulation system and how such components would be controllable by an EC, which are also within the scope of the present disclosure.', 'The drilling fluid circulation system may also incorporate one or more ECs that receive one or more signals from one or more sensors that are indicative of conditions in the drilling fluid circulation system.', 'The one or more ECs that control one or more controllable components may be the same as, different from, or a combination therebetween of the one or more ECs that receive signals from sensors.', 'Example sensors may include various flow meters and/or pressure gauges that may be fluidly coupled to various lines and/or pipes through which drilling fluid flows, such as the discharge line of a drilling fluid pump, the standpipe, the return line, the intake line of the drilling fluid pump, around various equipment, and/or the like.', 'Using flow meters and/or pressure gauges, flow rates and/or pressure differentials may be determined that can indicate a leak in equipment, that a clog in equipment has occurred, that the formation has kicked, that drilling fluid is being lost to the formation, or the like.', 'Various tachometers can be on various pumps and/or prime movers to measure speed and/or revolutions, such as of a drilling fluid pump, a vacuum pump of a degasser, a motor of an agitator of a mud tank, or the like.', 'The tachometers can be used to measure the health of the respective equipment.', 'A pressure gauge can be on the degasser to measure a pressure within the degasser.', 'The degasser may operate at a predetermined pressure level to adequately remove gas from drilling fluid, and a pressure reading from a pressure gauge can be fed back to control the pressure within the degasser.', 'A pit volume totalizer can be in one or more mud tanks to determine an amount of drilling fluid held by the mud tanks, which can indicate a leak in equipment, that a clog in equipment has occurred, that the formation has kicked, that drilling fluid is being lost to the formation, or the like.', 'A viscometer can be along the circulation to measure viscosity of the drilling fluid, which can be used to determine remedial action, such as adding an additive to the drilling fluid at a hopper.', 'Signals from such sensors can be sent to and received by one or more ECs, which can then transmit the sensor data to the common data bus and/or use the data to responsively control controllable components, for example.', 'The signals from the sensor that are received by an EC may be a digital signal and/or analog signal.', 'A person of ordinary skill in the art will readily envisage other example sensors in a drilling fluid circulation system and how such components would be coupled to an EC, which are also within the scope of the present disclosure.', 'As another example, a rig control system may incorporate one or more ECs that control one or more controllable components.', 'Controllable components of the hoisting equipment may include a prime mover of the drawworks, one or more brakes, and others.', 'For example, a prime mover of the drawworks may be controllable by an EC to increase/decrease a revolution rate of the prime mover of the drawworks, and/or to turn the prime mover on/off.', 'A mechanical (and/or electronic) brake may be controllable by an EC to actuate the brake (e.g., a caliper and pad assembly) to clamp/release a brake disk of the drawworks, for example.', 'Controllable components in the drillstring rotary mover equipment may include a prime mover (e.g., including the top drive \n116\n in \nFIG.', '1\n and/or the rotary table depicted in \nFIG.', '2\n), a gearbox and/or transmission, a pipe handler assembly and/or grabber, a kelly spinner, a torque wrench, mechanized and/or automated slips, and/or others.', 'For example, the prime mover may be controllable by an EC to increase/decrease a revolution rate of the prime mover, and/or to turn the prime mover on/off.', 'The gearbox and/or transmission may be controllable by an EC to set and/or change a gear ratio between the prime mover and the drive shaft or master bushing.', 'The pipe handler assembly and/or grabber can be controllable by an EC to move the pipe handler assembly and/or grabber for receiving, setting, clasping, and/or releasing a tubular.', 'The kelly spinner can be controllable by an EC to rotate a kelly when making up or breaking out a connection between the kelly and the drillstring.', 'The torque wrench can be controllable by an EC to clamp and twist a tubular to make up a connection between the drive shaft and the tubular.', 'The mechanized and/or automated slips can be controllable by an EC to open/close the slips.', 'The controllable components may be controlled by a digital signal and/or analog signal from an EC.', 'A person of ordinary skill in the art will readily envisage other example controllable components in a rig control system and how such components would be controllable by an EC, which are also within the scope of the present disclosure.', 'The rig control system may also incorporate one or more ECs that receive one or more signals from one or more sensors that are indicative of conditions in the rig control system.', 'The one or more ECs that control one or more controllable components may be the same as, different from, or a combination therebetween of the one or more ECs that receive signals from sensors.', 'As some examples of sensors, a crown saver can be in a drawworks to determine and indicate when an excessive amount of drilling line has been taken in by the drawworks.', 'An excessive amount of drilling line being taken in can damage hoisting equipment, such as by a traveling block impacting a crown block, and the signal from the crown saver can be fed back to indicate when the drawworks should cease taking in drilling line.', 'A WOB sensor can be included on the traveling block, drawworks, deadline, other components/lines, and/or combinations thereof.', 'The signal from the WOB sensor can be fed back to determine if too much or too little weight is on the bit of the drillstring, and in response, to determine whether to take in or reel out, respectively, drilling line.', 'Further, a tachometer can be on a prime mover of the drawworks to measure speed and/or revolutions.', 'The tachometer can be used to measure the health of the prime mover.', 'As further examples of sensors, various tachometers can be on the prime mover and/or drive shaft or master bushing of drillstring rotary mover equipment, and can be used to determine a rate of rotation of the respective prime mover and/or drive shaft or master bushing.', 'A torque-on-bit sensor can be in a BHA.', 'Various pressure gauges can be coupled to hydraulic systems used for the pipe handler assembly and/or grabber, the torque wrench, the slips, and/or other components.', 'Signals from such sensors can be sent to and received by one or more ECs, which can then transmit the sensor data to the common data bus and/or use the data to responsively control controllable components, for example.', 'The signals from the sensor that are received by an EC may be a digital signal and/or analog signal.', 'A person of ordinary skill in the art will readily envisage other example sensors in a rig control system and how such components would be coupled to an EC, which are also within the scope of the present disclosure.', 'A person of ordinary skill in the art will readily understand other example subsystems that may be in a well construction system, and that such other subsystems are also within the scope of the present disclosure.', 'Such other subsystems may include a managed pressure drilling system, a cementing system, and/or a rig walk system, among other examples.', 'A person of ordinary skill in the art will readily understand example EC(s), controllable component(s), and/or sensor(s) that can be used in these additional example systems.', 'Additionally, a person of ordinary skill in the art will readily understand other example equipment and components that may be included in or omitted from example subsystems described herein.\n \nFIG.', '7\n is a schematic view of at least a portion of an example implementation of a first processing system \n700\n according to one or more aspects of the present disclosure.', 'The first processing system \n700\n may execute example machine-readable instructions to implement at least a portion of the configuration manager, coordinated controller, virtual networks, HMI, and/or historian described herein.', 'The first processing system \n700\n may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, industrial computers, servers, personal computers, internet appliances, PLCs, and/or other types of computing devices.', 'Moreover, while it is possible that the entirety of the first processing system \n700\n shown in \nFIG.', '7\n is implemented within one device, e.g., in the control center \n198\n of \nFIGS.', '1 and 2\n, it is also contemplated that one or more components or functions of the first processing system \n700\n may be implemented across multiple devices, some or an entirety of which may be at the wellsite and/or remote from the wellsite of the well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively.', 'The first processing system \n700\n comprises a processor \n712\n such as, for example, a general-purpose programmable processor.', 'The processor \n712\n may comprise a local memory \n714\n, and may execute program code instructions \n732\n present in the local memory \n714\n and/or in another memory device.', 'The processor \n712\n may execute, among other things, machine-readable instructions or programs to implement the configuration manager, coordinated controller, process applications, and/or virtual networks described herein, for example.', 'The programs stored in the local memory \n714\n may include program instructions or computer program code that, when executed by an associated processor, permit, cause, and/or embody implementation of the configuration manager, the coordinated controller, the virtual networks, an HMI, the process applications, and/or the historian as described herein.', 'The processor \n712\n may be, comprise, or be implemented by one or more processors of various types operable in the local application environment, and may include one or more general-purpose processors, special-purpose processors, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), processors based on a multi-core processor architecture, and/or other processors.', 'Examples of the processor \n712\n may include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, and/or embedded soft/hard processors in one or more FPGAs, among other examples.', 'The processor \n712\n may be in communication with a main memory \n717\n, such as via a bus \n722\n and/or other communication means.', 'The main memory \n717\n may comprise a volatile memory \n718\n and a non-volatile memory \n720\n.', 'The volatile memory \n718\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices.', 'The non-volatile memory \n720\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as read-only memory (ROM), flash memory, and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n718\n and/or the non-volatile memory \n720\n.', 'The first processing system \n700\n may also comprise an interface circuit \n724\n in communication with the processor \n712\n, such as via the bus \n722\n.', 'The interface circuit \n724\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB) interface, a third generation input/output (3GIO) interface, a wireless interface, a BLUETOOTH interface, and/or a cellular interface, among other examples.', 'One or more ECs (e.g., EC \n740\n through EC \n742\n as depicted) are communicatively coupled to the interface circuit \n724\n, such as when the first processing system \n700\n is implemented as a network appliance, such as a switch, in the operations network.', 'The interface circuit \n724\n may permit communications between the first processing system \n700\n and one or more ECs by one or more communication protocols, such as an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication, and/or others), a proprietary communication protocol, and/or another communication protocol.', 'The interface circuit \n724\n may also comprise a communication device such as a modem or network interface card to facilitate exchange of data with external computing devices via a network, such as via Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, and/or satellite, among other examples.', 'One or more input devices \n726\n may be connected to the interface circuit \n724\n and permit a user to enter data and/or commands for utilization by the processor \n712\n.', 'Each input device \n726\n may be, comprise, or be implemented by one or more instances of a keyboard, a mouse, a touchscreen, a joystick, a control switch or toggle, a button, a track-pad, a trackball, an image/code scanner, and/or a voice recognition system, among other examples.', 'One or more output devices \n728\n may also be connected to the interface circuit \n724\n.', 'The output device \n728\n may be, comprise, or be implemented by a display device, such as an LCD, an LED display, and/or a CRT display, among other examples.', 'The interface circuit \n724\n may also comprise a graphics driver card to permit use of a display device as one or more of the output devices \n728\n.', 'One or more of the output devices \n728\n may also or instead be, comprise, or be implemented by one or more instances of an LED, a printer, a speaker, and/or other examples.', 'The one or more input devices \n726\n and the one or more output devices \n728\n connected to the interface circuit \n724\n may, at least in part, enable the HMI described above with respect to \nFIG.', '3\n.', 'The input device(s) \n726\n may permit entry of commands to the coordinated controller, and the output device(s) \n728\n may permit visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data.', 'The first processing system \n700\n may also comprise a mass storage device \n730\n for storing machine-readable instructions and data.', 'The mass storage device \n730\n may be connected to the processor \n712\n, such as via the bus \n722\n.', 'The mass storage device \n730\n may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples.', 'The program code instructions \n732\n may be stored in the mass storage device \n730\n, the volatile memory \n718\n, the non-volatile memory \n720\n, the local memory \n714\n, a removable storage medium (such as a CD, a DVD, and/or another external storage medium \n734\n connected to the interface circuit \n724\n), and/or another storage medium.', 'The modules and/or other components of the first processing system \n700\n may be implemented in accordance with hardware (such as in one or more integrated circuit chips, such as an ASIC), or may be implemented as software or firmware for execution by a processor.', 'In the case of software or firmware, the implementation can be provided as a computer program product including a computer readable medium or storage structure containing computer program code (i.e., software or firmware) for execution by the processor.\n \nFIG.', '8\n is a schematic view of at least a portion of an example implementation of a second processing system \n800\n according to one or more aspects of the present disclosure.', 'The second processing system \n800\n may execute example machine-readable instructions to implement at least a portion of an EC as described herein.', 'The second processing system \n800\n may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, servers, personal computers, internet appliances, and/or other types of computing devices.', 'Moreover, while it is possible that the entirety of the second processing system \n800\n shown in \nFIG.', '8\n is implemented within one device, it is also contemplated that one or more components or functions of the second processing system \n800\n may be implemented across multiple devices, some or an entirety of which may be at the wellsite and/or remote from the wellsite of the well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively.', 'The second processing system \n800\n comprises a processor \n810\n such as, for example, a general-purpose programmable processor.', 'The processor \n810\n may comprise a local memory \n812\n, and may execute program code instructions \n840\n present in the local memory \n812\n and/or in another memory device.', 'The processor \n810\n may execute, among other things, machine-readable instructions or programs to implement logic for monitoring and/or controlling one or more components of a well construction system.', 'The programs stored in the local memory \n812\n may include program instructions or computer program code that, when executed by an associated processor, enable monitoring and/or controlling one or more components of a well construction system.', 'The processor \n810\n may be, comprise, or be implemented by one or more processors of various types operable in the local application environment, and may include one or more general-purpose processors, special-purpose processors, microprocessors, DSPs, FPGAs, ASICs, processors based on a multi-core processor architecture, and/or other processors.', 'The processor \n810\n may be in communication with a main memory \n814\n, such as via a bus \n822\n and/or other communication means.', 'The main memory \n814\n may comprise a volatile memory \n816\n and a non-volatile memory \n818\n.', 'The volatile memory \n816\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as RAM, SRAM, SDRAM, DRAM, RDRAM, and/or other types of random access memory devices.', 'The non-volatile memory \n818\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as ROM, flash memory, and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n816\n and/or the non-volatile memory \n818\n.', 'The second processing system \n800\n may also comprise an interface circuit \n824\n in communication with the processor \n810\n, such as via the bus \n822\n.', 'The interface circuit \n824\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a USB interface, a peripheral component interconnect (PCI) interface, and a 3GIO interface, among other examples.', 'One or more other processing system \n850\n (e.g., the first processing system \n700\n of \nFIG.', '7\n) are communicatively coupled to the interface circuit \n824\n.', 'The interface circuit \n824\n can enable communications between the second processing system \n800\n and one or more other processing system (e.g., a network appliance, the processing system of the configuration manager \n302\n, or another processing system in \nFIG.', '3\n) by enabling one or more communication protocols, such as an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication, and/or others), a proprietary communication protocol, and/or another communication protocol.', 'One or more input devices \n826\n may be connected to the interface circuit \n824\n and permit a user to enter data and/or commands for utilization by the processor \n810\n.', 'Each input device \n826\n may be, comprise, or be implemented by one or more instances of a keyboard, a mouse, a touchscreen, a joystick, a control switch or toggle, a button, a track-pad, a trackball, an image/code scanner, and/or a voice recognition system, among other examples.', 'One or more output devices \n828\n may also be connected to the interface circuit \n824\n.', 'The output device \n828\n may be, comprise, or be implemented by a display device, such as an LCD and/or an LED display, among other examples.', 'The interface circuit \n824\n may also comprise a graphics driver card to enable use of a display device as one or more of the output devices \n828\n.', 'One or more of the output devices \n828\n may also or instead be, comprise, or be implemented by one or more instances of an LED, a printer, a speaker, and/or other examples.', 'The second processing system \n800\n may comprise a shared memory \n830\n in communication with the processor \n810\n, such as via the bus \n822\n.', 'The shared memory \n830\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as RAM, SRAM, SDRAM, DRAM, RDRAM, and/or other types of random access memory devices.', 'The second processing system \n800\n may comprise one or more analog input (AI) interface circuits \n832\n, one or more digital input (DI) interface circuits \n834\n, one or more analog output (AO) interface circuits \n836\n, and/or one or more digital output (DO) interface circuits \n838\n, each of which may be in communication with the shared memory \n830\n.', 'The AI interface circuit \n832\n may include one or multiple inputs, and may convert an analog signal received on an input into digital data useable by the processor \n810\n, for example.', 'The DI interface circuit \n834\n may include one or multiple inputs, and may receive a discrete signal (e.g., on/off signal), which may be useable by the processor \n810\n.', 'The AI interface circuit \n832\n and the DI interface circuit \n834\n are communicatively coupled to the shared memory \n830\n, where the AI interface circuit \n832\n and DI interface circuit \n834\n can cache and/or queue input data and from which the processor \n810\n can access the data.', 'The inputs of the AI interface circuit \n832\n and the DI interface circuit \n834\n are communicatively coupled to outputs of various sensors (e.g., analog output sensor \n852\n and digital output sensor \n854\n), devices, components, etc., in a well construction system.', 'The AI interface circuit \n832\n and the DI interface circuit \n834\n can be used to receive, interpret, and/or reformat sensor data and monitor the status of one or more components, such as by receiving analog signals and discrete signals, respectively, of the various sensors, devices, components, etc., in the well construction system.', 'The AO interface circuit \n836\n may include one or multiple outputs to output analog signals, which may be converted from digital data provided by the processor \n810\n and temporarily stored in the shared memory \n830\n, for example.', 'The DO interface circuit \n838\n may include one or multiple outputs, and can output a discrete signal (e.g., on/off signal), which may be provided by the processor \n810\n and temporarily stored in the shared memory \n830\n, for example.', 'The AO interface circuit \n836\n and the DO interface circuit \n838\n are communicatively coupled to the shared memory \n830\n.', 'The outputs of the AO interface circuit \n836\n and the DO interface circuit \n838\n are communicatively coupled to inputs of various devices, components, etc., such as one or more analog input controllable components \n856\n and/or one or more digital input controllable components \n858\n, in a well construction system.', 'The AO interface circuit \n836\n and the DO interface circuit \n838\n can be used to control the operation of one or more components, such as by providing analog signals and discrete signals, respectively, to the various devices, components, etc., in the well construction system.', 'The second processing system \n800\n may also comprise a mass storage device \n839\n for storing machine-readable instructions and data.', 'The mass storage device \n839\n may be connected to the processor \n810\n, such as via the bus \n822\n.', 'The mass storage device \n839\n may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a CD drive, and/or DVD drive, among other examples.', 'The program code instructions \n840\n may be stored in the mass storage device \n839\n, the volatile memory \n816\n, the non-volatile memory \n818\n, the local memory \n812\n, a removable storage medium, such as a CD or DVD, and/or another storage medium.', 'The modules and/or other components of the second processing system \n800\n may be implemented in accordance with hardware (such as in one or more integrated circuit chips, such as an ASIC), or may be implemented as software or firmware for execution by a processor.', 'In the case of software or firmware, the implementation can be provided as a computer program product including a computer readable medium or storage structure containing computer program code (i.e., software or firmware) for execution by the processor.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising a first processing system comprising a processor and a memory including computer program code, wherein the first processing system is operable to: (A) receive a job plan developed by a second processing system; (B) implement the job plan comprising generating commands for one or more equipment controllers based on the job plan, wherein the one or more equipment controllers are operable to control equipment of a well construction system; (C) transmit, through a network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers; and (D) iteratively: (i) monitor, through the network, current conditions of the well construction system during execution of commands by the one or more equipment controllers; (ii) update the implementation of the job plan comprising generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and (iii) transmit, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', 'The first processing system may comprise dedicated resources comprising at least a portion of the processor and at least a portion of the memory, and the dedicated resources may be dedicated to monitoring the current conditions of the well construction system, updating the implementation, and transmitting the updated commands.', 'The job plan may include a generalized operation with defined constraints of parameters of the generalized operation.', 'The apparatus may comprise the second processing system comprising a processor and a memory including computer program code, and the second processing system may be operable to: (A) develop the job plan based on the current conditions of the well construction system; (B) transmit the job plan to the first processing system; and (C) iteratively: (i) monitor, through the network, the current conditions of the well construction system during execution of the commands by the one or more equipment controllers; (ii) update the job plan when the current conditions of the well construction system indicate a deviation from the job plan; and (iii) transmit the updated job plan to the first processing system.', 'The apparatus may comprise the network, the network may comprise a common data bus, the current conditions of the well construction system may be made available via the common data bus, and the first processing system may be operable to monitor the current conditions of the well construction system via the common data bus.', 'The apparatus may further comprise a third processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein the third processing system is operable to translate communications between the common data bus and the one or more equipment controllers, and wherein the communications include commands and the current conditions of the well construction system.', 'The third processing system may be operable to translate the communications between one or more of a plurality of predetermined protocols and a common protocol used on the common data bus.', 'The predetermined protocols may include two or more selected from the group consisting of ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, and Siemens S7 communication, and the common protocol may be a DDS protocol.', 'The current conditions of the well construction system may include or be indicated by sensor data, status data, or a combination thereof communicated from the one or more equipment controllers.', 'The equipment of the well construction system may be selected from the group consisting of equipment of a drilling rig control system, equipment of a drilling fluid circulation system, equipment of a managed pressure drilling system, equipment of a cementing system, and equipment of a rig walk system.', 'The present disclosure also introduces an apparatus comprising: (A) a network; (B) one or more equipment controllers communicatively coupled to the network and operable to control equipment of a well construction system; (C) a first processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein the first processing system is operable to: (i) develop a job plan based on current conditions of the well construction system; and (ii) transmit the job plan through the network; and (D) a second processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein the second processing system is operable to: (i) receive the job plan through the network; (ii) implement the job plan comprising generating commands for the one or more equipment controllers based on the job plan; (iii) transmit, through the network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers; and (iv) iteratively: (a) monitor, through the network, the current conditions of the well construction system during execution of commands by the one or more equipment controllers; (b) update the implementation of the job plan comprising generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and (c) transmit, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', 'The second processing system may comprise dedicated resources comprising at least a portion of the processor and at least a portion of the memory, wherein the dedicated resources may be dedicated to monitoring the current conditions of the well construction system, updating the implementation, and transmitting the updated commands.', 'The job plan may include a generalized operation with defined constraints of parameters of the generalized operation.', 'The first processing system may be operable to iteratively: monitor, through the network, the current conditions of the well construction system during execution of the commands by the one or more equipment controllers; update the job plan when the current conditions of the well construction system indicate a deviation from the job plan; and transmit the updated job plan through the network.', 'The network may comprise a common data bus, the current conditions of the well construction system may be made available via the common data bus, and the second processing system may be operable to monitor the current conditions of the well construction system via the common data bus.', 'The apparatus may further comprise a third processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, the third processing system may be operable to translate communications between the common data bus and the one or more equipment controllers, and the communications may include commands and the current conditions of the well construction system.', 'The third processing system may be operable to translate the communications between one or more of a plurality of predetermined protocols and a common protocol used on the common data bus.', 'The predetermined protocols may include two or more selected from the group consisting of ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, and Siemens S7 communication, and the common protocol may be a DDS protocol.', 'The current conditions of the well construction system may include or be indicated by sensor data, status data, or a combination thereof communicated from the one or more equipment controllers.', 'The equipment of the well construction system may be selected from the group consisting of equipment of a drilling rig control system, equipment of a drilling fluid circulation system, equipment of a managed pressure drilling system, equipment of a cementing system, and equipment of a rig walk system.', 'The present disclosure also introduces a method comprising operating a first processing system comprising a processor and a memory including computer program code, wherein operating the first processing system comprises: (A) receiving a job plan developed by a second processing system; (B) implementing the job plan comprising generating commands for one or more equipment controllers based on the job plan, wherein the one or more equipment controllers are operable to control equipment of a well construction system; (C) transmitting, through a network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers; and (D) iteratively: (i) monitoring, through the network, current conditions of the well construction system during execution of commands by the one or more equipment controllers; (ii) updating the implementation of the job plan comprising generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and (iii) transmitting, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', 'The first processing system may comprise dedicated resources comprising at least a portion of the processor and at least a portion of the memory, wherein the dedicated resources may be dedicated to monitoring the current conditions of the well construction system, updating the implementation, and transmitting the updated commands.', 'The job plan may include a generalized operation with defined constraints of parameters of the generalized operation.', 'The method may comprise operating the second processing system, which comprises a processor and a memory including computer program code, wherein operating the second processing system may comprise: (A) developing the job plan based on the current conditions of the well construction system; (B) transmitting the job plan to the first processing system; and (C) iteratively: (i) monitoring, through the network, the current conditions of the well construction system during execution of the commands by the one or more equipment controllers; (ii) updating the job plan when the current conditions of the well construction system indicate a deviation from the job plan; and (iii) transmitting the updated job plan to the first processing system.', 'The network may comprise a common data bus, the current conditions of the well construction system may be made available via the common data bus, and monitoring the current conditions of the well construction system by the first processing system may be via the common data bus.', 'The method may further comprise operating a third processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein operating the third processing system may comprise translating communications between the common data bus and the one or more equipment controllers, and wherein the communications may include commands and the current conditions of the well construction system.', 'The third processing system may be operable to translate the communications between one or more of a plurality of predetermined protocols and a common protocol used on the common data bus.', 'The predetermined protocols may include two or more selected from the group consisting of ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, and Siemens S7 communication, and the common protocol may be a DDS protocol.', 'The current conditions of the well construction system may include or be indicated by sensor data, status data, or a combination thereof communicated from the one or more equipment controllers.', 'The equipment of the well construction system may be selected from the group consisting of equipment of a drilling rig control system, equipment of a drilling fluid circulation system, equipment of a managed pressure drilling system, equipment of a cementing system, and equipment of a rig walk system.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'An apparatus comprising:\na first processing system comprising a processor and a memory including computer program code, wherein the first processing system is operable to: receive a job plan developed by a second processing system, wherein the job plan: is based on geological and/or geophysical data descriptive of a target formation of a well to be constructed by a well construction system; and includes details pertaining to trajectory of the well and mud, casing, drill bits, and bottom hole assembly components to be used during the construction; and implement the job plan comprising generating commands for one or more equipment controllers based on the job plan, wherein the one or more equipment controllers are operable to control equipment of the well construction system; transmit, through a network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers; and iteratively: monitor, through the network, current conditions of the well construction system during execution of commands by the one or more equipment controllers; update the implementation of the job plan comprising generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and transmit, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', '2.', 'The apparatus of claim 1 wherein the first processing system comprises dedicated resources comprising at least a portion of the processor and at least a portion of the memory, and wherein the dedicated resources are dedicated to monitoring the current conditions of the well construction system, updating the implementation, and transmitting the updated commands.', '3.', 'The apparatus of claim 1 wherein the job plan includes a generalized operation with defined constraints of parameters of the generalized operation.', '4.', 'The apparatus of claim 1 further comprising the second processing system, wherein the second processing system comprises a processor and a memory including computer program code, and wherein the second processing system is operable to:\ndevelop the job plan based further on the current conditions of the well construction system;\ntransmit the job plan to the first processing system; and\niteratively: monitor, through the network, the current conditions of the well construction system during execution of the commands by the one or more equipment controllers; update the job plan when the current conditions of the well construction system indicate a deviation from the job plan; and transmit the updated job plan to the first processing system.', '5.', 'The apparatus of claim 1 further comprising the network, wherein:\nthe network comprises a common data bus;\nthe current conditions of the well construction system are made available via the common data bus; and\nthe first processing system is operable to monitor the current conditions of the well construction system via the common data bus.', '6.', 'The apparatus of claim 5 further comprising a third processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein the third processing system is operable to translate communications between the common data bus and the one or more equipment controllers, and wherein the communications include commands and the current conditions of the well construction system.', '7.', 'The apparatus of claim 6 wherein the third processing system is operable to translate the communications between one or more of a plurality of predetermined protocols and a common protocol used on the common data bus.', '8.', 'The apparatus of claim 1 wherein the current conditions of the well construction system include or are indicated by sensor data, status data, or a combination thereof communicated from the one or more equipment controllers.', '9.', 'The apparatus of claim 1 wherein the equipment of the well construction system is selected from the group consisting of equipment of a drilling rig control system, equipment of a drilling fluid circulation system, equipment of a managed pressure drilling system, equipment of a cementing system, and equipment of a rig walk system.', '10.', 'An apparatus comprising:\na network;\none or more equipment controller communicatively coupled to the network and operable to control equipment of a well construction system;\na first processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein the first processing system is operable to: develop a job plan based on current conditions of the well construction system and geological and/or geophysical data descriptive of a target formation of a well to be constructed by the well construction system, wherein the job plan includes details pertaining to trajectory of the well and mud, casing, drill bits, and bottom hole assembly components to be used during the constructions; and transmit the job plan through the network; and\na second processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein the second processing system is operable to: receive the job plan through the network; implement the job plan comprising generating commands for the one or more equipment controllers based on the job plan; transmit, through the network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers; and iteratively: monitor, through the network, the current conditions of the well construction system during execution of commands by the one or more equipment controllers; update the implementation of the job plan comprising generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and transmit, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', '11.', 'The apparatus of claim 10 wherein the second processing system comprises dedicated resources comprising at least a portion of the processor and at least a portion of the memory, and wherein the dedicated resources are dedicated to monitoring the current conditions of the well construction system, updating the implementation, and transmitting the updated commands.\n\n\n\n\n\n\n12.', 'The apparatus of claim 10 wherein the first processing system is operable to iteratively:\nmonitor, through the network, the current conditions of the well construction system during execution of the commands by the one or more equipment controllers;\nupdate the job plan when the current conditions of the well construction system indicate a deviation from the job plan; and\ntransmit the updated job plan through the network.', '13.', 'The apparatus of claim 10 wherein\nthe network comprises a common data bus;\nthe current conditions of the well construction system are made available via the common data bus; and\nthe second processing system is operable to monitor the current conditions of the well construction system via the common data bus.', '14.', 'The apparatus of claim 13 further comprising a third processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein the third processing system is operable to translate communications between the common data bus and the one or more equipment controllers, and wherein the communications include commands and the current conditions of the well construction system.\n\n\n\n\n\n\n15.', 'The apparatus of claim 14 wherein the third processing system is operable to translate the communications between one or more of a plurality of predetermined protocols and a common protocol used on the common data bus.', '16.', 'A method comprising:\noperating a first processing system comprising a processor and a memory including computer program code, wherein operating the first processing system comprises: receiving a job plan developed by a second processing system, wherein the job plan: is based on geological and/or geophysical data descriptive of a target formation of a well to be constructed by a well construction system; and includes details pertaining to trajectory of the well and mud, casing, drill bits, and bottom hole assembly components to be used during the constructions; and implementing the job plan comprising generating commands for one or more equipment controllers based on the job plan, wherein the one or more equipment controllers are operable to control equipment of the well construction system; transmitting, through a network, the commands to the one or more equipment controllers for execution of the commands by the one or more equipment controllers; and iteratively: monitoring, through the network, current conditions of the well construction system during execution of commands by the one or more equipment controllers; updating the implementation of the job plan comprising generating updated commands for the one or more equipment controllers based on the job plan and on the current conditions of the well construction system when the current conditions of the well construction system indicate a deviation from the implementation; and transmitting, through the network, the updated commands to the one or more equipment controllers for execution of the updated commands by the one or more equipment controllers.', '17.', 'The method of claim 16 wherein the first processing system comprises dedicated resources comprising at least a portion of the processor and at least a portion of the memory, and wherein the dedicated resources are dedicated to monitoring the current conditions of the well construction system, updating the implementation, and transmitting the updated commands.', '18.', 'The method of claim 16 further comprising operating the second processing system comprising a processor and a memory including computer program code, wherein operating the second processing system comprises:\ndeveloping the job plan based further on the current conditions of the well construction system;\ntransmitting the job plan to the first processing system; and\niteratively: monitoring, through the network, the current conditions of the well construction system during execution of the commands by the one or more equipment controllers; updating the job plan when the current conditions of the well construction system indicate a deviation from the job plan; and transmitting the updated job plan to the first processing system.', '19.', 'The method of claim 16 wherein:\nthe network comprises a common data bus;\nthe current conditions of the well construction system are made available via the common data bus; and\nmonitoring the current conditions of the well construction system by the first processing system is via the common data bus.', '20.', 'The method of claim 19 further comprising operating a third processing system communicatively coupled to the network and comprising a processor and a memory including computer program code, wherein operating the third processing system comprises translating communications between the common data bus and the one or more equipment controllers, and wherein the communications include commands and the current conditions of the well construction system.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '4 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG.', '5 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG.', '6 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG. 7 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG. 8 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG. 1 is a schematic view of at least a portion of an example implementation of a well construction system 100 operable to drill a wellbore 104 into a subsurface formation 102 at a wellsite in accordance with one or more aspects of the present disclosure.', 'A drillstring 106 penetrates the wellbore 104 and includes a bottom hole assembly (BHA) 108 that comprises or is mechanically and hydraulically coupled to a drill bit 110.', 'The well construction system 100 includes a mast 114 (a portion of which is depicted in FIG.', '1) extending from a rig floor 112 that is erected over the wellbore 104.', 'A top drive 116 is suspended from the mast 114 and is detachably, mechanically, and hydraulically coupled to the drillstring 106.', 'The top drive 116 provides a rotational force (e.g., torque) to drive rotational movement of the drillstring 106 when advancing the drillstring 106 into the formation 102 to form the wellbore 104.; FIG. 1 also depicts a pipe handling manipulator (PHM) 182 and a fingerboard 184 disposed on the rig floor 112, although other implementations within the scope of the present disclosure may include one or both of the PHM 182 and the fingerboard 184 located elsewhere or excluded.', 'The fingerboard 184 provides storage (e.g., temporary storage) of tubulars 194, such that the PHM 182 can be operated to transfer the tubulars 194 from the fingerboard 184 for inclusion in the drillstring 106 during drilling or tripping-in operations, instead of (or in addition to) from the catwalk 166, and similarly for transferring tubulars 194 removed from the drillstring 106 to the fingerboard 184 during tripping-out operations.', '; FIG.', '2 is a schematic view of at least a portion of another example implementation of a well construction system 250 operable to drill a wellbore 104 into a subsurface formation 102 at a wellsite in accordance with one or more aspects of the present disclosure.', 'Some of the components and operation of those components are common (as indicated by usage of common reference numerals) between the well construction systems 100 and 250 of FIGS.', '1 and 2, respectively.', 'Hence, description of the common components may be omitted here for brevity, although a person of ordinary skill in the art will readily understand the components and their operation in the well construction system 250 of FIG.', '2.; FIG.', '3 is a schematic view of at least a portion of an example implementation of an operations network 300 according to one or more aspects of the present disclosure.', 'The physical network used to implement the operations network 300 of FIG. 3 can have a network topology, such as a bus topology, a ring topology, a star topology, and/or mesh topology, among other examples also within the scope of the present disclosure.', 'The operations network 300 can include one or more processing systems, such as one or more network appliances (like a switch or other processing system), that are configured to implement various virtual networks, such as virtual local area networks (VLANs).', 'Additionally, the operations network 300 can include one or more processing systems, such as one or more network appliances (like a switch or other processing system), that are configured with an intrusion detection system (IDS) to monitor traffic across the operations network 300, such as may be in respective virtual networks.', 'The IDS can alert personnel to potential cyber security breaches that may occur on the operations network 300.; FIG.', '4 is a flow-chart diagram of at least a portion of an example implementation of a method (400) for controlling operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (400) may be performed by, utilizing, or otherwise in association with one or more features depicted in one or more of FIGS.', '1-3 described above, one or more features depicted in FIGS.', '7 and/or 9 described below, and/or one or more features otherwise within the scope of the present disclosure.', 'However, for the sake of simplicity, the method (400) is described below in the context of the example implementation depicted in FIG.', '3 and/or otherwise described above, and a person having ordinary skill in the art will recognize that the following description of the method (400) is also applicable or readily adaptable for operations networks other than the example operations network 300 depicted in FIG.', '3.; FIG.', '5 is a flow-chart diagram of at least a portion of an example implementation of a method (500) for controlling operations of a well construction system, including implementing an arbiter, according to one or more aspects of the present disclosure.', 'The method (500) may be performed by, utilizing, or otherwise in association with one or more features depicted in one or more of FIGS.', '1-3 described above, one or more features depicted in FIGS.', '7 and/or 9 described below, and/or one or more features otherwise within the scope of the present disclosure.', 'However, for the sake of simplicity, the method (500) is described below in the context of the example implementation depicted in FIG.', '3 and/or otherwise described above, and a person having ordinary skill in the art will recognize that the following description of the method (500) is also applicable or readily adaptable for operations networks other than the example operations network 300 depicted in FIG.', '3.', 'Also, as described in more detail below, the method (500) may not flow linearly as illustrated in FIG.', '5.; FIG. 6 is a flow-chart diagram of at least a portion of an example implementation of a method (600) for connecting an EC (and/or similarly for connecting a subsystem) to an existing network of a well construction system according to one or more aspects of the present disclosure.', 'The method (600) includes connecting (602) the EC to the physical network of the operations network 300.', 'As described above, connecting (602) the EC can include connecting the EC to an existing port of a network appliance of the operations network 300, which may be configured to implement a virtual network.', '; FIG. 7 is a schematic view of at least a portion of an example implementation of a first processing system 700 according to one or more aspects of the present disclosure.', 'The first processing system 700 may execute example machine-readable instructions to implement at least a portion of the configuration manager, coordinated controller, virtual networks, HMI, and/or historian described herein.; FIG. 8 is a schematic view of at least a portion of an example implementation of a second processing system 800 according to one or more aspects of the present disclosure.', 'The second processing system 800 may execute example machine-readable instructions to implement at least a portion of an EC as described herein.'] |
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US11136461 | Degradable composite structures | Dec 18, 2015 | Philip Kokel, Shitong S. Zhu, Matthew Godfrey, Meng Qu, Jahir A. Pabon, Yucun Lou, Francois M. Auzerais, John David Rowatt, Roman Kats, Gauri Joshi, Miranda Amarante | SCHLUMBERGER TECHNOLOGY CORPORATION | Schnabelrauch et al. “Degradable phosphate glass fiber reinforced polymer matrices: mechanical properties and cell response”, J Mater Sci Mater Med. Jan. 2008;19(1):121-7.; Ensanya et al. “Bioactive functional materials: a perspective on phosphate-based glasses.” (2009) J. Mater. Chem., 19: 690-701.; Ahmed et al. “Retention of Mechanical Properties and Cytocompatibility of a Phosphate-Based Glass Fiber/Polylactic Acid Composite.” Journal of Biomedical Materials Research Part B: Applied Biomaterials 89: 18-27.; Bennett et al., “Ultrafast chemical reactions between nickel and aluminum powders during shock loading”, Applied Physics Letters, 61 (5), 1992, 520-521.; C. W. S Marchi, “Processing of aluminum-nickel intermetallics by reactive infiltration”, 1997, Ph.D. Thesis (111 pages).; D.E. Eakins, Role of heterogeneity in the chemical and mechanical shock-response of nickel and aluminum powder mixtures, 2007, Ph.D. Thesis, School of materials and science engineering, Georgia Institue of Technology (424 pages).; S. Cozien-Cazuc, A.J.P., G.S. Walker, I.A. Jones, C.D. Rudd (2009), “Real-Time Dissolution of P40Na20Ca16Mg24 posphate glass fibers.” Journal of Non-Crystalline Solids 355: 2514-2521.; International Search Report and Written Opinion issued in the related PCT application PCT/US2015/066738, dated Apr. 21, 2016 (9 pages).; International Preliminary Report on Patentability issued in the related PCT application PCT/US2015/066738, dated Jul. 6, 2017 (8 pages). | 6380138; April 30, 2002; Ischy et al.; 7093664; August 22, 2006; Todd et al.; 8342094; January 1, 2013; Marya et al.; 20040034121; February 19, 2004; Nozaki; 20080093073; April 24, 2008; Bustos et al.; 20080196896; August 21, 2008; Bustos; 20080202764; August 28, 2008; Clayton et al.; 20090000786; January 1, 2009; Daniels; 20110226479; September 22, 2011; Tippel et al.; 20110250626; October 13, 2011; Williams; 20120067581; March 22, 2012; Auzerais et al.; 20130292123; November 7, 2013; Murphree et al.; 20140360728; December 11, 2014; Tashiro; 20160076326; March 17, 2016; Van Petegem et al.; 20170121568; May 4, 2017; Strebl | 2873986; February 2014; CA | ['Embodiments may generally take the form of a degradable composite structure and a method for controlling the rate of degradation of a degradable composite structure.', 'An example embodiment may take the form of a degradable polymer matrix composite (PMC) including a matrix having: a degradable polymer, a fiber reinforcement, and particulate fillers.', 'The fiber loading is between approximately 10% to 70% by weight and the particulate loading is between approximately 5% to 60%.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThe present application is related to and claims the benefit of U.S. Provisional Patent Application No. 62/095,144 filed Dec. 22, 2014, which is incorporated by reference herein in its entirety.', 'FIELD\n \nThe subject disclosure generally relates to degradable composite structures.', 'BACKGROUND\n \nDegradable materials can change their mechanical, physical and responsive properties upon thermal, hygroscopic, and/or chemical interaction with their environment, or upon interaction with mechanical, physical or chemical triggers.', 'Degradable materials provide acceptable performance for a certain period of time and after fulfilling their intended applications, the materials degrade or dissolve away in the downhole environment, which saves both time and cost which is associated with drilling out or retrieving non-degradable materials.', 'Degradable materials are of particular interest to the oil field industry especially because of this time-and cost-saving potential.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to limit the scope of the claimed subject matter.', 'Embodiments may generally take the form of a degradable composite structure and a method for controlling the rate of degradation of a degradable composite structure.', 'An example embodiment may take the form of a degradable polymer matrix composite (PMC) including a matrix having: a degradable polymer, a fiber reinforcement, and particulate fillers.', 'The fiber loading is between approximately 10% to 70% by weight and the particulate loading is between approximately 5% to 60%.', 'Further features and advantages of the subject disclosure will become more readily apparent from the following detailed description when taken in conjunction with the accompanying drawings.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThe subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein:\n \nFIG.', '1A\n depicts catalysts as solid particles compounded into the polymer matrix and \nFIG.', '1B\n depicts reinforcing short fibers and solid catalyst particles compounded with a degradable polymer matrix to form a tube, the composite tube degradable in water over time.\n \nFIG.', '2\n depicts a nylon prepreg layered alternately with a film of catalyst.\n \nFIG.', '3\n depicts a nylon composite tape sandwiched between multiple layers of solid catalysts.\n \nFIG.', '4\n depicts degradable PMCs with reactive pressed NI—Al powered mixture (grey).\n \nFIG.', '5\n illustrates methods for initiating the chemical reaction of the Ni—Al powder mixture.\n \nFIG.', '6\n illustrates superparamagnetic MagSilica® nanoparticles which are incorporated into the composite to generate induction heating under an electromagnetic field.\n \nFIG.', '7\n illustrates a heterogeneous structure of a fast degradable composite or degradable metal core covered with a slow/non degradable outer layer of composite.\n \nFIG.', '8\n illustrates cross-sections of the PMC parts coated with protective coating.\n \nFIG.', '9\n depicts a degradable composite/metallic hybrid structure.\n \nFIG.', '10\n depicts an example of a composite/metallic structure with interlocking metal pieces as the core.\n \nFIGS.', '11A and 11B\n illustrates examples of composite/metallic structures with interlocking metal pieces as the core and cavities in the core.\n \nFIG.', '12\n illustrates compression molding chopped nylon prepreg with a catalyst.\n \nFIG.', '13\n illustrates examples of composite/metallic structures, in non-limiting examples.\n \nFIG.', '14\n illustrates an example wellbore with completion tools and a perforating gun disposed therein.\n \nFIG.', '15\n illustrates loading tube made of degradable material in different stages of degradation.\n \nFIG.', '16\n illustrates an example tubular formed of PMC.\n \nFIG.', '17\n illustrates plots of degradable PLA with glass fiber and without glass fiber.\n \nFIG.', '18\n shows images of a degradable polymer member as it degrades over a 24 hour period and in different solutions.\n \nFIG.', '19\n illustrates a plot showing degradation trends of nylon \n6\n with different additives.', 'DETAILED DESCRIPTION', 'The particulars shown herein are by way of example and for purposes of illustrative discussion of the examples of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure.', 'In this regard, no attempt is made to show structural details in more detail than is necessary, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice.', 'Furthermore, like reference numbers and designations in the various drawings indicate like elements.', 'Degradable materials can be used in various different applications and tools in the oil field.', 'For example, degradable materials may be used as materials for zonal isolation, bridging, plugging or as degradable parts/components in downhole devices.', 'In some applications, the degradable materials have certain mechanical properties in to fulfill the intended functions before degradation starts.', 'Polymers are good candidates as degradable materials due to the variety of available chemistry to trigger the degradation, and the available technologies to reinforce polymers with particulates and/or fibers to form degradable polymer matrix composites (PMC) for improved mechanical properties and controllable degradation.', 'PMC include polymer as the continuous phase and particulates (aspect ratio between approximately 2-50) or fibers (aspect ratio greater than approximately 45-55) as the reinforcement.', 'The matrix (continuous phase) performs several functions, including maintaining the fibers in the proper orientation and spacing and protecting them from abrasion and the environment.', 'In polymer composites that form a strong bond between the fiber and the matrix, the matrix transmits loads from the matrix to the fibers through shear loading at the interface.', 'In the degradable PMC, the continuous polymer matrix also functions as the degradable phase.', 'The reinforcing phase which is harder, stronger, and stiffer than the matrix provides the strength and stiffness of the composite.', 'Continuous fibers have long aspect ratios, while discontinuous fibers (chopped sections of continuous fibers) have short aspect ratios.', 'Continuous-fiber composites normally have a preferred orientation, while discontinuous fibers generally have a random orientation.', 'Typical fibers include glass, polymer (aramid), carbon, boron, ceramics and metal which may be continuous or discontinuous.', 'The type and quantity of the reinforcement determine the final properties.', 'Soluble glass fibers are rarely used in fiber reinforced composites.', 'For the purpose of complete degradation, soluble and degradable fibers including water soluble glass fibers (p-glass), biodegradable fibers such as cellulose fibers, acid soluble metal fibers, and glass fibers may be desirable in d-PMC.', 'For practical applications in the oil and gas industry, the mechanical properties and the rate of composite degradation may be balanced.', 'The subject disclosure relates to the design of materials to control the rate of degradation at different temperature ranges, processes to bring heat sources to a downhole environment to accelerate the degradation, and the design of materials to balance both the mechanical properties and degradability.', 'Example embodiments may take the form of designs of degradable PMC in which degradable polymers are used as the matrix.', 'The degradable polymers for the matrix in PMC may include aliphatic polyesters, poly(lactic acid) (PLA), poly(ε-caprolactone), poly(glycolic acid) (PGA), poly(lactic-co-glycolic acid), poly(hydroxyl ester ether), polyhydroxyalkanoate (PHA), poly(hydroxybutyrate), poly(anhydride), polycarbonate, poly(amino acid), poly(ethylene oxide), poly(phosphazene), polyether ester, polyester amide, polyamides, sulfonated polyesters, poly(ethylene adipate), polyhydroxyalkanoate, poly(ethylene terephtalate), aliphatic polyethers, poly(butylene terephthalate), poly(trimethylene terephthalate), poly(ethylene naphthalate), polyamide (nylon), polyurethane and copolymers, blends, derivatives or a combination of any of these degradable polymers.', 'PLA, PGA, PA, PET, PBT, and PHA, and their breakdown products, are non-toxic.', 'These are readily available in a variety of molecular weights and degrees of crystallinity and are easily prepared.', 'In some example embodiments, the fiber reinforcement may include continuous fibers.', 'In some example embodiments, the fiber reinforcements may include discontinuous fibers.', 'In some example embodiments, the fiber reinforcement may include continuous and discontinuous fibers.', 'Examples of reinforcing fibers may include glass fibers, carbon fibers, polymer fibers (aramid fibers, nylon fibers, etc), boron, ceramics, metal fibers as well as water soluble, acid soluble, and biodegradable fibers.', 'An example embodiment may include one or more types of reinforcing fibers.', 'The fiber loading is in the range of about 10% to 70% by weight.', 'For example, the fiber loading may be in the range of about 10% to 60%, 20%-70%, 20%-60%, 30%-50%, or any suitable range.', 'For the purpose of reducing the residual materials after degradation, discontinuous fibers may be implemented for strength and stiffness in the degradable PMC.', 'In other cases, water soluble glass fibers (for example, discontinuous or continuous phosphate-glass fibers), acid soluble metal fibers, and biodegradable nature fibers such as cellulose fibers can be used as the reinforcement.', 'The resultant PMC may completely degrade in aqueous fluids, leaving little residual material in a downhole environment.', 'One or more other particulate fillers can be used to improve strength and stiffness.', 'Particulate fillers may include, for example: clay, talc, aluminum trihydrate (Al(OH)\n3\n), calcium carbonate, magnesium carbonate, glass beads, silica, silicate minerals, microspheres, ceramic particles, metals powders, mica, and Al\n2\nO\n3\n.', 'The particulate loading is in the range of about 5% to 60% by weight.', 'For example, the particulate loading may be in the range of 5% to 50%, 15% to 60%, 5% to 50%, 15% to 50%, or any suitable range.', 'One or more of: flame retardants, impact modifiers, coupling agents, plasticizers, pigments, UV stabilizers, antioxidants, anti-fouling agents, and other functional additives can be included in the PMC to introduce other performance properties such as thermal or electrical conductivity, UV stability, and fire resistance, for example.', 'These fillers may include by way of example: carbon black, carbon nanotubes, graphite and graphite nano-platelets (GNP), impact modifiers such as DuPont™ Biomax TH300, core-shell polymers, rubber particles, and PHA (Metabolix), plasticizers, coupling agents/or adhesive promoting agents such as silane, 2-hydroxyethylmethacrylate acid phosphate, 2-hydroxyethyl methacrylate phosphates, long chain fatty acids, and their ester derivatives.', 'The rate of matrix degradation is dictated by the formation temperatures, pH of the fluids and the inherent property of the polymer (type of chemical bonds, crystallinity, etc) and any catalysts used in the composite.', 'As the formation temperatures and the pH of the fluids are limited by the environments and the particular requirement of the operations, the choice of the polymer and the use of catalysts/functional fillers are the preferred method for controlling the rate of degradation, especially when the catalysts are incorporated into the composites.', 'Catalysts to control the rate of matrix degradation may include, for example: Ca(OH)\n2\n, Mg(OH)\n2\n, CaCO\n3\n, Al(OH)\n3\n, Borax, MgO, CaO, ZnO, CuO, Al\n2\nO\n3\n, ZrO\n2\n, oxides of titania, zirconia, magnesia, a base or a base precursor in the form of particles, films, sheets, foams or combination of these shapes.', 'Solid acids include polymers, for example polyesters such as PLA, PGA, PHA, PET, PBT etc.', 'that can degrade to release acids, anhydrides, long-chain fatty acids, silica, alumina, zeolites, solid acid sulfates and selenates, aluminium chloride, tungsten oxide, ferric chloride, antimony fluoride, titanium chloride and tin chloride.', 'Other water soluble and phase changing fillers could also be used.', 'These include salt (NaCl), KCl, ZnCl\n2\n, CaCl\n2\n, MgCl\n2\n, NaCO\n3\n, KCO\n3\n, potassium phosphate (KH\n2\nPO\n4\n, K\n2\nHPO\n4\n, K\n3\nPO\n4\n), sulfonate salts such as sodium benzenesulfonate (NaBS) and sodium dodecylbenzenesulfonate (NaDBS), water soluble/hydrophilic polymers, poly(ethylene-co-vinyl alcohol) and poly(vinyl alcohols) (PVOH), modified PVOH, and a mixture of these additives in the form of particles, films, sheets, foams, and a combination of these shapes.', 'The loading of the catalysts is in the range of 5% to 50% by weight.', 'In an embodiment, the catalysts \n101\n as solid particles are compounded into the polymer matrix \n102\n as shown in \nFIG.', '1A\n.', 'Conventional extrusion processes can be used to incorporate the catalysts \n101\n and the chopped fibers \n103\n into the polymer matrix \n102\n, and the final parts can be made into a desirable shape using any suitable process such as an extrusion or molding process, for example, using injection molding or profile extrusion.', 'The resultant part \n100\n will degrade in water to leave fibers \n103\n as residuals.', 'If soluble fibers are used in the part, the fibers will eventually dissolve in the downhole fluids to leave few residuals (\nFIG.', '1B\n).', 'FIG.', '1B\n illustrates the degradation process of the part \n100\n from a structural shape to remaining fibers after the polymer matrix dissolves and finally no remaining constituent parts upon full degradation.', 'In other embodiments, the d-PMC comprises a layered structure of composite tapes or prepreg (degradable polymers pre-impregnated on fibers or woven) and films, sheets of foams or a composite tape/prepreg of a solid catalyst.', 'Tape may also be pre-treated and rendered porous/permeable to facilitate imbibition of acids or bases inside its matrix or allow insertion of heating agents.', 'FIGS.', '2 and 4\n depict two examples.', 'In \nFIG.', '2\n, the composite tape \n200\n (e.g., nylon tape \n202\n from TENCATE®) may be layered alternately with a film of solid acid \n204\n (for example, a film of PLA).', 'The hydration of the solid acid or base produces acids or bases that catalyze the hydrolytic degradation of nylon at high temperatures (>120° C.) in a downhole environment.', 'In \nFIG.', '3\n, the layers of nylon tape \n202\n are sandwiched with several layers or a thick sheet of solid catalyst \n206\n.', 'These layered designs may produce a structure in the form of a cylinder, a tube, a block, a sphere or any combination of these shapes.', 'Heating of the polymer matrix locally is another way to accelerate the degradation.', 'One way to achieve this is to embed a reactive metal powder (such as Ni—Al metal powder) mixture \n300\n into the composite \n302\n (\nFIG.', '4\n); the chemical reaction of the metal powders \n300\n will generate a large amount of heat, and this elevated temperature will help accelerate the degradation of the PMC.', 'The Ni—Al powder mixture can be added to the surface or inserted in the PMC, in non-limiting examples, as isolated pellets, strips, coatings etc.', 'It can also be sandwiched in the PMC parts (e.g., \nFIG.', '4\n at b and d) or added into the core of PMC (e.g., \nFIG.', '4\n at e).', 'The reaction of Ni—Al powder mixture can be initiated by either heat or shock loading.', 'The heat to initiate the reaction can be generated by a local laser beam \n304\n, or a local electrical heat source etc.', '(\nFIG.', '5\n at a).', 'The shock loading can be generated by dropping a small ball/dart \n306\n or with any mechanical trigger attached on the degradable PMC parts (\nFIG.', '5\n at b).', 'Other heat sources can be mounted either on a slick line, coiled tubing or wireline cable and brought to the proximity of the downhole structure to accelerate its degradation once the heat starts being released.', 'Such sources can be activated from the surface using electric power when there is a cable or can be a chemical source inserted in a canister.', 'Deployment on a wire or coiled tubing of a downhole heat source could become a substitute to drilling out those fixed structures provided that we are able to achieve degradation in a shorter time than using a drilling method.', 'In an embodiment, the pressed metal powder or 3-D print metal core may have degradable tape around it.', 'Powder or pieces of the 3-D core will disperse after the tape degrades and it is possible to accelerate this or to compromise plastic layer integrity by using an external magnetic field (electromagnetic field).', 'The easy degradable metal can be 3-D printed and impregnated by nylon and after metal degradation small particles of the plastic will float out.', 'It is possible to use different porosity and cavities for the 3-D print for delay or acceleration of the degradation.', 'The local heating in the composite can be inductive as well.', 'When ferromagnetic, paramagnetic or superparamagnetic particles or nanoparticles \n602\n are exposed to a constantly changing magnetic field \n604\n, magnetically induced hyperthermia takes place, which can be used to heat up the media \n600\n (e.g., a degradable polymer matrix) that carries the particles.', 'These particles \n602\n can be used as functional fillers in the matrix \n600\n of the composite materials.', 'When an external magnetic field (electromagnetic field) \n604\n is applied in a downhole environment, the magnetic particles \n602\n heat up the polymer matrix \n600\n by inductive heating and accelerate the degradation (\nFIG.', '6\n).', 'Examples of ferromagnetic, paramagnetic or superparamagnetic particles include iron powders, steel powders, coated superparamagnetic FeO particles (Magsilica), nickel zinc ferrite particles (FP95, FP110, etc).', 'Since water is a reactant which causes degradation of the composite, for the situations that the PMC parts need to sit in the downhole environment (i.e. high temperatures) for a period of time in aqueous fluids before they degrade, different types of matrix composites can be designed into the same structure with the outer layers \n610\n of the structure \n608\n made from a more hydrophobic/less degradable composite.', 'In this way, the structure \n608\n will have very slow degradation initially so that its mechanical strength is intact during its applications at high temperature in fluids.', 'After water slowly penetrates the outer layers \n610\n and contacts with the more degradable inner structures \n612\n, the degradation accelerates.', 'This design ensures that the structure will have a window of working/functioning time before its degradation speeds up (delayed degradation, \nFIG.', '7\n).', 'The thickness of the outer layer \n610\n depends on the application conditions (the operating window, temperatures, fluid types) and the choice of the polymers.', 'The thickness of the outer layer \n610\n could be in the range of about 1% to 95% of total weight.', 'For example, the thickness of the outer layer \n610\n may be in the range of about 1% to 51%, 49% to 95%, 10% to 85%, 20% to 75%, 30% to 65%, and so forth.', 'Relatively more hydrolysis-resistant polymers can be used as the matrix for the outer layer.', 'The examples include epoxy, polyamide, polyurethane, polypropylene, polyethylene, polycarbonate, cyanate ester, vinyl ester, polyphenylene sulfide, bis-maleimides, phenolic formaldehyde, unsaturated polyester, polyester, polyimide, PEEK, fluoropolymer, polystyrene, silicon, etc. and combinations of these polymers.', 'Coating is another option to have a delayed or timed degradation.', 'A layer of coating \n700\n can be applied to delay water penetration into the parts \n702\n.', 'The material of the coating \n700\n can be either polymer or metal.', 'The coating \n700\n can be deposited using in non-limiting examples, a thermal spray technique.', 'Different coating thicknesses can be obtained by controlling the spray time.', 'The parts \n702\n can also be fully or partially coated, depending on the requirements of the application (\nFIG.', '8\n).', 'For example, a coating \n704\n may include various gaps \n706\n as illustrated in \nFIG.', '8\n at b and c.', 'The use of polymer films is that it may be sprayed without flames to form the polymer coating, so the degradation of the parts is limited.', 'The material can be any protective polymer, such as epoxy, polypropylene, polyethylene, polycarbonate, cyanate ester, polyphenylene sulfide, bis-maleimides, phenolic formaldehyde, unsaturated polyester, polyimide, PEEK, fluoropolymer, polystyrene, polyamide, polyurethane, silicon, etc and combinations of these polymers.', 'Metal coatings can also be applied to the PMC surface; the advantage of using metal coatings is that they not only delay water penetration, but also add more mechanical strength to the PMC parts.', 'Other additives could also be used in the polymer matrix to slow down the degradation.', 'Example additives include, for example, hydrolysis inhibitors (fly ash, baking soda, carbodiimide, etc. weak base) and low surface energy additives to slow down water diffusion (fluoropolymer particles).', 'The degradable PMC can be customized to have mechanical properties that can meet the requirement of the desired applications.', 'In some example embodiments, the properties of the degradable PMC may include: a tensile strength approximately equal to or grater than 20 MPa, a tensile modulus approximately equal to or greater than 1 GPa, and a heat deflection temperature (HDT) approximately equal to or greater than 60° C. With these mechanical properties, the degradable PMC can be used to fabricate many one-time use downhole tools that are currently made of metal.', 'Examples include the loading tube in the perforating gun, darts and balls.', 'Numerical simulation results show that for the loading tube made of degradable PMC, the maximum internal stress due to the weight of the charge (between approximately 0.3˜0.6 kg) is less than approximately 0.9 MPa, two orders of magnitude smaller than its tensile strength.', 'In addition, such a tool with typical geometries can sustain an external load on the order of approximately 1000 N without significant deformation (i.e., less than 0.1%).', 'Additionally, composite/metallic hybrid structures could be designed.', 'FIG.', '9\n shows an example of a high strength metal core \n800\n wrapped with degradable composites \n802\n.', 'The metal core \n800\n could even be replaced with a water soluble metal alloy so that the whole structure is degradable/soluble in some embodiments.', 'The degradable metal/composite hybrid materials could be produced into forms of cylinders, tubes, blocks or spheres or any other desired shapes or structures.', 'The composite/metallic hybrid structures \n810\n could have interlocking metal pieces \n812\n, \n814\n as the core and the degradable materials such as the degradable composite tapes as the outer layer.', 'This could also be an overmolded part \n822\n having an interlocking metal pieces \n820\n with a degradable composite layer as the outer layer that allows for the movement of part (\nFIG.', '13\n at b and b′).', 'The degradable composite material may be molded around the interlocking metal core or otherwise applied to the metal core in any suitable manner.', 'FIG.', '10\n shows an example of the core \n830\n made of interlocking metal pieces \n832\n and wrapped with degradable fiber tape \n834\n.', 'In some embodiments, the interlocking metal pieces may include alignment members so that adjacent members are aligned with each other.', 'In some embodiments, adjacent members may couple together through a tight fit or other suitable mechanism.', 'In some embodiments, adjacent members may not have a tight fit.', 'The outer layer \n834\n makes the inner core \n832\n behave as a solid structure under compression in some embodiments.', 'Upon degradation of the outer layer \n834\n, the metallic core pieces \n832\n fall apart and are small enough that they either may flow back or fall to a rat hole.', 'Cavities \n840\n can be included between interlocking pieces \n842\n or the interlocking pieces \n842\n′ may form a cavity \n840\n′. The interlocking pieces \n842\n and \n842\n′may be covered with degradable composite tapes \n844\n and \n844\n′. These cavities \n840\n and \n840\n′ can be left empty so that under downhole conditions the outer pressure keeps the device under compression, providing structural stability (\nFIGS.', '11A and 11B\n).', 'In \nFIG.', '11B\n, the inner layer \n842\n′ may be made o fsmall interlocking metallic pieces forming a continuous spherical of similarly closed surface with an inner cavity.', 'The cavities \n840\n and \n840\n′ can also be used to hold other additives, chemicals or materials for other functions.', 'For example, the cavities can contain chemicals (solid acid, for example) to control the degradation/corrosion of the outer layers, the metal pieces, or even other supporting structures (such as ball seats and/or plug seats used in multi-stage fracturing operations) for the composite/metallic hybrid structures.', 'The cavities could also contain chemicals to modify the properties of local fluids such as the pH, viscosity, conductivity, salinity, density etc. of the fluid, or to initiate other functions such as crosslinking, oxidization, reduction, anti-bacteria (biocide), etc.', 'The cavities could also contain reactive Ni—Al metal powder mixture to generate an even larger amount of heat to accelerate the degradation of the structure.', 'A high speed thermal process is developed to consolidate the prepreg/tape in-situ to form composite cylindrical and complex structures with continuous fiber reinforcement (Automated Dynamics).', 'Conventional compression molding processes can also be used to mold chopped prepreg \n900\n with degradation catalysts \n902\n for complex structures \n904\n (\nFIG.', '12\n).', 'The mold \n906\n may take any appropriate form, such as asphere for example, and chopped nylon tapes with catalyst \n900\n may be placed in the mold to form the shape.', 'The degradable composite with or without reactive fillers may be implemented in a variety of oil field and other tools.', 'For example, the degradable composite may be used for zonal isolation in multi-zone stimulation using sliding sleeves, bridge plugs, isolation plugs or downhole devices which can be inserted in a casing or tubing with degradable parts/components such that a specific reservoir formation can be targeted and accessed in a downhole environment.', 'In the case of sliding sleeves, one current method for actuating the sliding sleeves for multi-zone fracturing operations is to drop untethered balls or darts of graduating sizes to land on target sleeves.', 'The balls form a seal with the sleeve and create a restriction to build fluid pressure against.', 'At a certain pressure, the sleeve shifts and expose fracture ports or slots that allow hydraulic communication between the internal diameter of the casing or tubing and the formation in the current target zone.', 'This hydraulic communication allows the operator to fracture the target zone.', 'The target sleeves are run as part of the completion and can either be cemented in place, or external casing packers may be used to isolate the zones.', 'Once the fracturing operations are complete, removal of the untethered objects and/or seats establishes fluid circulation within the well.', 'The most common method for removal of these objects is to mill out the objects using coiled tubing operations.', 'Since a milling operation can be very time consuming and costly, it is desirable to eliminate this step.', 'Using degradable composites with or without reactive fillers to manufacture the balls, darts, and/or seats is one of the applications for the materials as disclosed.', 'Current technology for passive degradable balls or shaped plugging devices which can be dropped from the surface in a multi-zone stimulation application exists and has been used in the oilfield as described above.', 'The ball functions to provide a seal and hold fracture pressure for a period of hours and degrade over a period of days.', 'However, due to geometry constraints with the rapidly decreasing diameter of the seats which creates an increasing flow restriction, the ball drop system may only be used to target 20-30 zones.', 'In addition, the passive degradation of the ball material in the downhole environment does not allow for the seats to be made of a similar material.', 'This is due to the fact that the seats are run in hole with the completion and may be exposed to the downhole environment for many days before performing their intended function.', 'Therefore, on many occasions, despite using a passively degradable material for the ball drop systems, coiled tubing milling operations must occur to clear out the restrictions due to the seats.\n \nUsing a degradable composite material with or without reactive fillers can enable the sleeves to be made of the same material.', 'The material can be placed downhole on the completions string for an extended period of time, allowing the sleeves to perform their intended interaction with the untethered object or shifting tool.', 'Once the sleeves have been shifted and fracturing operations completed, the sleeves and objects left in the wellbore can be triggered to degrade by sending down either another object to initiate the degradation process through impact or a localized heat source.', 'This process may be much quicker and more efficient at removing the seats and/or untethered objects than coiled tubing milling operations.', 'Embodiments may take the form of a degradable of disappearing perforating gun, for example.', 'The disappearing perforating gun may be directed to eliminating/reducing the rat hole below the perforating gun, among other possible motivating factors.', 'Conventionally, rat holes receive a gun (or other tools) at the bottom of a well after an operation, such as a perforating operation, has been performed.', 'In some embodiments, a disappearing chamber gun may be implemented with a degradable loading tube or a foam tray to support the shaped charges, as shown in \nFIG.', '14\n.', 'Using a loading tube or tray that is degradable, is one method and component that may be used to generate a carrier tubular that is free of debris and able to produce fluids from the reservoir, unimpeded.\n \nFIG.', '14\n illustrates an example oilfield with a well \n1180\n accommodating completions hardware which may be dual purposed as production tubing and completions hardware.', 'In the embodiment shown, the lower completions hardware \n1101\n of the system includes a perforating gun \n1105\n that is integrally incorporated thereinto.', 'Specifically, the gun \n1105\n is also in direct tubular communication with upper completions production tubing \n1125\n and includes a dissolvable internal support system as detailed further below.', 'Thus, while initially serving as a perforating gun \n1105\n, this portion of the hardware may later serve as a conduit for fluid flow.', 'Utilizing completions hardware for the dual purposes of perforating and subsequent fluid flow as noted above may be of significant benefit to offshore operations as depicted in the embodiment of \nFIG.', '14\n.', 'For example, the oilfield of \nFIG.', '14\n is in an offshore environment with a well head \n150\n and pressure control equipment \n1110\n mounted at a seabed.', 'In addition to being located several hundred feet or more below water \n1190\n, completing the well \n1180\n may require drilling several thousand feet further, past a variety of formation layers \n1191\n, \n1193\n, \n1195\n before reaching a targeted production layer \n1197\n.', 'Thus, even setting aside the added amount of time and expense dedicated to properly drilling, placing cement \n1120\n, installing casing \n1185\n, or delivering completions hardware, even the most time-efficient trip into or out of the well \n1180\n may require a day or more of otherwise non-producing time.', 'However, a dual purpose perforating gun \n1105\n, for perforating and subsequently accommodating fluid flow, may minimize time and expense in terms of both drilling and trips into the well \n1180\n.', 'The perforating gun \n1105\n of \nFIG.', '14\n is shown installed as part of permanent completions hardware.', 'That is, as opposed to installing lower completions hardware \n1101\n without a gun \n1105\n and later delivering a gun \n1105\n on another trip into the well \n1180\n, the time dedicated to such a trip is saved and the perforating gun \n1105\n is supplied at the same time the lower completions hardware \n1101\n is installed.', 'However, in addition to saving trip time dedicated to perforating, time and expense are also saved in terms of drilling.', 'That is, as shown in \nFIG.', '14\n, a terminal space \n1175\n at the tail end of the well \n1180\n extends beyond the terminal end \n1130\n of the gun \n1105\n by only a short distance.', 'As opposed to a more conventional “rat hole” extending 50-100 feet or more and taking two days or more to drill, the terminal space \n1175\n of \nFIG.', '14\n may extend no more than 5-25 feet in depth beyond the terminal end \n1130\n of the gun \n1105\n.', 'Because the all or part of the gun may be degradable, there is no need for additional space for debris to accumulate.', "Internal modeling of the materials' strength based on the dimension and weight of the shaped charges indicates that the loading tube should have a tensile strength of approximately 10-30 MPa (e.g., approximately 15-25 MPa, or approximately 20 MPa) at the operating temperatures, a modulus of approximately 0.5-1.5 GPa (e.g., approximately 1 GPa), and heat distortion temperature (HDT) up to approximately 90-100° C. (e.g., approximately 100° C.) before perforating.", 'A loading tube \n1000\n will break down to debris \n1002\n after the gun fires \n1001\n, and the debris \n1004\n should degrade in light brines at the defined temperatures in one (1003) to two (1005) days, as shown in \nFIG.', '15\n, to allow for flow back of the gun particles or allow for the particles to fall to the bottom of the well to completely degrade without impeding flow of fluids.', 'The operating/downhole temperature varies depending on the formation in which the gun is to be used and ranges from approximately 50-90° C. (Marcellus) to above approximately 150° C. (Haynesville).', 'Degradable polymer matrix composites may be used in some embodiments to make the degradable/dissolvable loading tube.', 'In this example, aliphatic polyester based composites may be chosen as the examples for fabricating the degradable loading tube for applications in the temperature range of approximately 60-100° C.', 'The composites may be reinforced with chopped/short glass or carbon fibers for desired mechanical properties (e.g., stiffness, strength, etc.).', 'Internal or external additives/catalysts may be used to control the rate of degradation at the defined temperatures.', 'Other functional additives such as impact modifiers may be incorporated into the composites for better performance properties.', 'For operations at lower temperature ranges (e.g., approximately 60-100° C.), poly(aliphatic acid) based composites, such as polylactic acid, reinforced with chopped carbon or glass fibers may be useful for making the loading tube, as shown in \nFIG.', '16\n.', 'Solid base or base precursors, such as Ca(OH)2, Mg(OH)2, CaCO3, Al(OH)3, Borax, MgO, CaO, ZnO, CuO, Al2O3, ZrO2, oxides of titania, zirconia, magnesia, are used to control/accelerate the degradation.', 'Different grades of PLA resins with various molecular weights and degrees of crystallinity, different grades of MgO with various surface areas and reactivity, and different volume fractions of glass fibers or carbon fibers and impact modifiers may be implemented in some embodiments.', 'An example formula of a polylactic acid (PLA) composite is shown in Table 1 as an example formulation for compression molding or extrusion of the loading tube.', 'Noting that various type of PLA blends or grades of MgO could be used in the formulation to fine tune the melt viscosity, mechanical properties and the rates of degradation.', 'Table 2 listed some other grades of PLA and MgO that could be used in certain embodiments.', 'The loading of the impact modifier is in the range of approximately 0-5%; the loading of MgO or other base or base precursors is in the range of approximately 0-20%; and the loading of chopped glass or carbon fibers is in the range of approximately 10-40%.', 'Chopped fibers, impact modifiers, nucleation agents and MgO were melt-compounded into PLA resin \n1602\n at approximately 170-200° C. using a single screw extruder.', 'The MgO and PLA were dried in an oven overnight before compounding.', 'ASTM standard D638-10 type I dog bones were injection molded and used to evaluate the tensile strength of the composite.', 'A large tube \n1600\n shown in \nFIG.', '16\n was also compression-molded to demonstrate the practicality of manufacturing the formulation.', 'The tensile strength of the PLA composites tested at room temperature is in the range of approximately 25 to 90 MPa, varying due to the loading and grades of PLA, impact modifiers, fibers and MgO.', 'The tensile strength at approximately 70° C. (above the glass transition temperature of PLA) is in the range of approximately 15-40 MPa.', 'The storage modules measured by DMA is above 2 GPa at either room temperature or 70° C.\n \n \n \n \n \n \n \n \nTABLE 1\n \n \n \n \n \n \n \n \nAn example formula of PLA composite for making a loading tube \n \n \n \n \n \n \n \n \n \n \nIngredients\n \nGrade\n \nweight %\n \n \n \n \n \n \nPLA resin \n \n2500HP\n \n54.5%', 'Impact modifier\n \nBiomax Strong 120/or impact MB\n \n\u2009\u20035%\n \n \n \nMineral filler\n \nElastomag MgO 100\n \n\u2009\u200210%\n \n \n \nchopped glass fibers\n \nE-glas (ave.', '2 mm)\n \n\u2009\u200230%\n \n \n \nNucleation agent\n \nEBS, Ethylene bis(stearamide)\n \n\u20020.5%\n \n \n \nTotal\n \n \n\u2009100%\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nTABLE 2\n \n \n \n \n \n \n \n \nChoices of raw materials and their grade \n \n \n \n \n \n \n \n \n \n \n \nResins\n \nGrade\n \n \n \n \n \n \n \n \nPLA 2500HP\n \nExtrusion\n \n \n \n \nPLA 3260HP\n \nMolding\n \n \n \n \nPLA 6302D\n \nMolding\n \n \n \n \nPLA 6060\n \nFiber grade\n \n \n \n \nPHA 4300\n \nImpact modifier\n \n \n \n \nMgO\n \nElastomg 100 or 170\n \n \n \n \nMgO\n \nNalcon D176\n \n \n \n \nZnO\n \n99%\n \n \n \n \nE-glass fibers\n \nChopped\n \n \n \n \nCarbon fibers\n \nChopped\n \n \n \n \n \n \n \n \n \n \n \nAs the degradable PLA-based loading tube may withstand a certain amount of constant load from the shaped charges, creep tests were conducted on these PLA-based composites to understand whether there is any creep induced by a constant load.', 'The creep tests were conducted using TMA with a load of 1 N using a spherical tip.', 'This load/pressure is higher than the load that the shaped charges would apply on the composites.', 'The results show that there is not much creep under the applied load for all samples tested at room temperature.', 'At 75° C., there is no creep for all samples with crystallinity (>20%), as shown in \nFIG.', '17\n.', 'Creep test at longer times (up to 2 days) was also conducted on selected samples; no creep was observed at 75° C.\n \nSmall blocks of the solid PLA composite samples \n1800\n were immersed in 20 ml of aqueous fluids in a bottle \n1802\n.', 'The bottles were placed in an oven at a defined temperature for a defined degradation time (a few days).', 'Then, the samples were filtered, rinsed with DI water several times and dried in vacuum oven at 38° C. to remove any residual water.', 'The weight of the residual sample was recorded and the weight loss % of fibers was calculated using the following equation: \n Weight loss %(wl %)=(\nW\n0−Wt)/\nW\n0, \n \nW0 is the original sample weight and Wt is the weight of the dried residual fibers at the degradation time of t.', 'The typical weight loss % of these composites at approximately 60-70° C. in the fluid sequences of 3 hours of approximately 15% HCl (the structure \n1800\n′ is shown after 3 hrs in approximately 15% HCl) and approximately 20-24 hours of approximately 1% NaCl solution (the structure \n1800\n′ is shown after 20-24 hours in approximately 1% NaCl solution) is in the range of approximately 20-50% depending on the formulation.', 'The samples broke into small pieces after approximately 24 hours in the fluid sequence, as shown in \nFIG.', '18\n.', 'After stirring, the structure \n1800\n′″ was unrecognizable.', 'At higher temperatures, hydrolysis inhibitor, such as Stabaxol® P, a carbodiimide, can be used to delay the rate of degradation of poly(aliphatic acid).', 'Although this present embodiments are focused on the degradable PLA composites for the application in the temperature ranges of approximately 60-100° C., other polymers, such as polyamides or PET based composites could be used at temperatures above approximately 100° C.', 'The typical tensile strength of nylon composites with chopped glass or carbon fibers is above 100 MPa tested even at 98° C. in wet environment.', 'Lewis acids, such as AlF3, ZnCl2 or AlCl3 could be used as internal or external additives to control the rate of degradation.', 'FIG.', '19\n shows the accelerated degradation of nylon \n6\n (PA\n6\n) at 150° C. with internal catalysts ZnCl2 or AlF3.', 'The composites become brittle at around 15-20% of weight loss (within 1-2 days).', 'Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples without materially departing from this subject disclosure.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A perforating gun, comprising a degradable polymer matrix composite (PMC) with a controlled degradation, the PMC comprising:\na matrix comprising: a degradable polymer; a fiber reinforcement, wherein the fiber loading is between approximately 10% to 70% of the total weight of the composite; particulate fillers, wherein the particulate loading is between approximately 5% to 60% of the total weight of the composite; and a catalyst, wherein the catalyst is between approximately 5% to 50% of total weight of the composite, wherein the degradable polymer, the fillers, the catalyst, or any combination of the three control the rate of degradation.', '2.', 'The perforating gun of claim 1, wherein the degradable polymer comprises at least one component selected from the group consisting of: aliphatic polyesters, poly(lactic acid) (PLA), poly(c-caprolactone), poly(glycolic acid) (PGA), poly(lactic-co-glycolic acid), poly(hydroxyl ester ether), polyhydroxyalkanoate (PHA), poly(hydroxybutyrate), poly(anhydride), polycarbonate, poly(amino acid), polyethylene oxide), poly(phosphazene), polyether ester, polyester amide, polyamides, sulfonated polyesters, polyethylene adipate), poly(ethylene terephtalate), aliphatic polyethers, poly(butylene terephthalate), poly(trirnethylene terephthalate), poly(ethylene naphthalate), and polyurethane.\n\n\n\n\n\n\n3.', 'The perforating gun of claim 2, wherein the degradable polymer comprises copolymers, blends, derivatives or combinations of the degradable polymers.', '4.', 'The perforating gun of claim 1, wherein the fiber reinforcement comprises continuous fibers.', '5.', 'The perforating gun of claim 1, wherein the fiber reinforcement comprises discontinuous fibers.', '6.', 'The perforating gun of claim 1, wherein the fiber reinforcement comprises continuous and discontinuous fibers.', '7.', 'The perforating gun of claim 1, wherein the fiber reinforcement comprises one or more of: glass fiber, carbon fiber, polymer fiber, boron, ceramic, or metal fiber.', '8.', 'The perforating gun of claim 1, wherein the fiber reinforcement comprises at least one of: water soluble fibers, acid soluble fibers, or biodegradable fibers.', '9.', 'The perforating gun of claim 1, wherein the particulate filler comprises at least one of: clay, talc, aluminum trihydrate (Al(OH)3), calcium carbonate, magnesium carbonate, glass beads, silica, silicate minerals, microspheres, ceramic particles, metals powders, mica, or Al2O3.\n\n\n\n\n\n\n10.', 'The perforating gun of claim 1, wherein the PMC further comprises at least one of: a flame retardant, an impact modifier, a coupling agent, a plasticizer, a pigment, a UV stabilizer, an antioxidant, or an anti-fouling agent.', '11.', 'The perforating gun of claim 10, wherein the PMC has one or more of: thermal conductivity, electrical conductivity, UV stability, or fire resistance.\n\n\n\n\n\n\n12.', 'The perforating gun of claim 1, wherein the PMC further comprises at least one of: carbon black, carbon nanotubes, graphite, and graphite nano-platelets (GNP), core-shell polymers, rubber particles, and polyhydroxyalkanoate, plasticizers, silane, 2-hydroxyethylmethacrylate acid phosphate, 2-hydroxyethyl methacrylate phosphate, long chain fatty acids, or the ester derivatives of long chain fatty acids.', '13.', 'The perforating gun of claim 1, wherein the catalyst comprises at least one of: Ca(OH)2; Mg(OH)2; CaCO3; Al(OH)3; Borax; MgO; CaO; ZnO; CuO; Al2O3; ZrO2; oxides of titania, zirconia, magnesia, a base or a base precursor in the form of particles, films, sheets, foams or combination of these shapes.', '14.', 'The perforating gun of claim 1, wherein the catalyst comprises water soluble and phase changing additives.', '15.', 'The perforating gun of claim 14, wherein the water soluble and phase changing additives comprises at least one of: NaCl, KCl, ZnCl2, CaCl2, MgCl2, NaCO3, KCO3, potassium phosphates, sulfonate salts, water soluble/hydrophilic polymers, poly(ethylene-co-vinyl alcohol), poly(vinyl alcohols) (PVOH), or modified PVOH, wherein the sulfonate salts include sodium benzenesulfonate (NaBS) and sodium dodecylbenzenesulfonate (NaDBS), and the potassium phosphates include KH2PO4, K2HPO4, K3PO4.\n\n\n\n\n\n\n16.', 'The perforating gun of claim 1, wherein the PMC further comprises heating materials that generate heat.', '17.', 'The perforating gun of claim 1, wherein the PMC further comprises a hydrolysis inhibitor.', '18.', 'A method comprising manufacturing the perforating gun of claim 1.\n\n\n\n\n\n\n19.', 'A method comprising using the perforating gun of claim 1 to perforate a well.'] | ['FIG.', '1A depicts catalysts as solid particles compounded into the polymer matrix and FIG.', '1B depicts reinforcing short fibers and solid catalyst particles compounded with a degradable polymer matrix to form a tube, the composite tube degradable in water over time.', '; FIG.', '2 depicts a nylon prepreg layered alternately with a film of catalyst.; FIG.', '3 depicts a nylon composite tape sandwiched between multiple layers of solid catalysts.; FIG.', '4 depicts degradable PMCs with reactive pressed NI—Al powered mixture (grey).', '; FIG.', '5 illustrates methods for initiating the chemical reaction of the Ni—Al powder mixture.;', 'FIG. 6 illustrates superparamagnetic MagSilica® nanoparticles which are incorporated into the composite to generate induction heating under an electromagnetic field.; FIG.', '7 illustrates a heterogeneous structure of a fast degradable composite or degradable metal core covered with a slow/non degradable outer layer of composite.; FIG.', '8 illustrates cross-sections of the PMC parts coated with protective coating.; FIG.', '9 depicts a degradable composite/metallic hybrid structure.; FIG.', '10 depicts an example of a composite/metallic structure with interlocking metal pieces as the core.; FIGS.', '11A and 11B illustrates examples of composite/metallic structures with interlocking metal pieces as the core and cavities in the core.;', 'FIG. 12 illustrates compression molding chopped nylon prepreg with a catalyst.; FIG.', '13 illustrates examples of composite/metallic structures, in non-limiting examples.; FIG.', '14 illustrates an example wellbore with completion tools and a perforating gun disposed therein.; FIG.', '15 illustrates loading tube made of degradable material in different stages of degradation.; FIG.', '16 illustrates an example tubular formed of PMC.; FIG.', '17 illustrates plots of degradable PLA with glass fiber and without glass fiber.; FIG.', '18 shows images of a degradable polymer member as it degrades over a 24 hour period and in different solutions.;', 'FIG. 19 illustrates a plot showing degradation trends of nylon 6 with different additives.; FIG.', '14 illustrates an example oilfield with a well 1180 accommodating completions hardware which may be dual purposed as production tubing and completions hardware.', 'In the embodiment shown, the lower completions hardware 1101 of the system includes a perforating gun 1105 that is integrally incorporated thereinto.', 'Specifically, the gun 1105 is also in direct tubular communication with upper completions production tubing 1125 and includes a dissolvable internal support system as detailed further below.', 'Thus, while initially serving as a perforating gun 1105, this portion of the hardware may later serve as a conduit for fluid flow.'] |
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US11136869 | Method for detecting a fracture position in a well (variants) | Jul 1, 2016 | Sergey Vladimirovich Semenov, Anatoly Vladimirovich Medvedev, Fedor Nikolaevich Litvinets | Schlumberger Technology Corporation | International Preliminary Report on Patentability issued in International Patent Appl. No. PCT/RU2016/000408 dated Jan. 10, 2019; 11 pages. | 4141843; February 27, 1979; Watson; 4530402; July 23, 1985; Smith; 6148917; November 21, 2000; Brookey; 8369183; February 5, 2013; Savary-Sismondini et al.; 9121272; September 1, 2015; Potapenko et al.; 20040103376; May 27, 2004; Pandey; 20120193092; August 2, 2012; Qu; 20130062066; March 14, 2013; Broussard | 2670949; August 2015; EP; 2439310; January 2012; RU; 2531775; October 2014; RU; 133022; November 1959; SU; 2012087796; June 2012; WO; 2014055931; April 2014; WO; 2014193577; December 2014; WO | ['The positions of hydraulic fractures may be detected during multistage reservoir stimulation operations.', 'Fracturing fluid is injected into a well at a pressure above the fracturing pressure to produce at least one hydraulic fracture.', 'Then, a marker slug is injected into the well.', 'Next, additional fracturing fluid is injected into the well.', 'When the marker slug enters at least one of the hydraulic fractures, a detectable pressure response is observed, and the position of a hydraulic fracture may be detected from the volume of fracturing fluid injected after injection of the marker slug.', 'The marker slug is a fluid that has a viscosity and/or density that is different from the fracturing fluids injected before and after the marker slug.', 'This technique may be combined with other well operations, such as plugging at least one hydraulic fracture or creating at least one new hydraulic fracture.'] | ['Description\n\n\n\n\n\n\nFIELD OF THE INVENTION', 'The invention relates to stimulation of an underground reservoir using hydraulic fracturing operation, particularly, to methods for detecting hydraulic fractures positions during multizone reservoir stimulation.', 'PRIOR ART\n \nPrior art solutions describe microseismics for characterization of hydraulic fractures, for example, U.S. Pat.', 'No. 8,369,183 (Schlumberger Technology Corporation), WO2014055931 (Halliburton Energy Services), etc.', 'There are known solutions describing the use of acoustic tools and computer models for description of hydraulic fractures geometry, for example, WO2012087796 (Schlumberger Canada limited).', 'Also, known solutions employ temperature measurements for characterization of hydraulic fractures, for example, WO2014193577 (CONOCOPHILLIPS COMPANY).', 'Accordingly, there is a need in prior art for a simple method for detecting an open hydraulic fracture position during multizone reservoir stimulation with the use of simple and available measuring instruments.', 'SUMMARY OF THE INVENTION', 'The present disclosure describes a new approach to detecting hydraulic fractures positions during multizone reservoir stimulation.', 'The method is based on local changes in the viscosity and/or density of fluid injected into a well.', 'In certain embodiments, this disclosure relates to a method for detecting a hydraulic fracture positions in a well.', 'According to the claimed method, fracturing fluid is injected into a well at a pressure above the fracturing pressure to produce at least one hydraulic fracture.', 'After this, a marker slug is injected into the well.', 'Further, the fracturing fluid is re-injected into the well.', 'When the marker slug enters at least one of the hydraulic fractures, a detectable pressure response is observed, and the position of hydraulic fracture is determined from the volume of fracturing fluid injected after the marker slug.', 'The marker slug is a slug (portion) of fluid differing in the viscosity and/or density from the fracturing fluids injected before and after the marker slug.', 'In other embodiments, this disclosure relates to a method for detecting a hydraulic fracture position in a well in conjunction with operations of plugging (colmatage) of at least one hydraulic fracture out of already existing hydraulic fractures.', 'In yet another embodiments, this disclosure relates to a method for detecting a hydraulic fracture position in a well in conjunction with operations of placement of at least one additional (new) hydraulic fracture within a new reservoir stimulation zone.', 'Other aspects of this invention will become evident from the following description and appended claims.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nFIG.', '1\n schematically illustrates passage of fluid flow into a perforation or a frac sleeve opening through a restriction.\n \nFIG.', '2\n depicts a diagram of exemplary embodiment of the method.\n \n \nDESCRIPTION OF EMBODIMENTS\n \nWhen carrying out multistage hydraulic fracturing operations at oil and gas wells, it is required to understand where exactly fluid is injected.', 'This disclosure describes a method for detecting a hydraulic fracture in a well having one or several hydraulic fractures that have been initiated in a productive reservoir and determining which of the existing hydraulic fractures is receiving fluid at a specific point in time.', 'This disclosure is based upon basic laws of fluid flow through objects of different geometry (a pipe, a rectangular slot, etc.).', 'The main idea described in the above basic laws is that the pressure drop during liquid flow through a pipe or rectangular slot depends on the fluid viscosity and density.', 'The Darcy-Weisbach formula for pressure difference during flow of viscous fluid through a pipe of diameter Dr is known from hydrodynamics\n \n \n \n \n \n \n \n \n \n \nΔ\n \n\u2062\n \n \n \n \n\u2062\n \n \np\n \nfric\n \n \n \n=\n \n \nλ\n \n\u2062\n \n \nl\n \n \nD\n \nr\n \n \n \n\u2062\n \n \n \nρ\n \n\u2062\n \n \n \n \n\u2062\n \n \nw\n \n0\n \n2\n \n \n \n2\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nΔ\n \n\u2062\n \n \n \n \n\u2062\n \n \np\n \nrp\n \n \n \n=\n \n \nλ\n \n\u2062\n \n \n \nl\n \n \nD\n \nr\n \n \n \n·\n \n \n \nρ\n \n\u2062\n \n \n \n \n\u2062\n \n \nw\n \n0\n \n2\n \n \n \n2\n \n \n \n \n \n \n \n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n \nThe Darcy-Weisbach formula (1) describes the relation among the friction pressure (p\nfric\n) of fluid flowing in a fracture, the fluid viscosity (accounted for by the hydrodynamic coefficient λ), the fluid density (ρ) and the linear velocity (ω\n0\n).', 'When fluid flows through a pipe of constant diameter (a casing), the flow through a local restriction (for example, through the perforation openings in a casing or the fracturing sleeve openings) passes into the volume of hydraulic fracture.', 'If we select two points on different sides of the restriction location, the pressure difference between these two points is described by formula (1).', 'As is obvious, a drastic change in either of the formula coefficients (the fluid density and/or viscosity) causes a change in upstream pressure at constant linear velocity.', 'As this takes place, a decrease in the pressure difference according to formula (1) causes a negative pressure response, while an increase in the pressure difference according to formula (1) (density increase in a slug (pulse)) reveals itself in the form of a positive pressure response in the well.', 'As applied to stimulation of oil and gas wells, the fluid flow through a fracture is a process being technologically identical to fluid flow through a narrow rectangular slot (\nFIG.', '1\n).', 'The fluid flow through a perforation or a frac sleeve (port) opening is identical to the flow through a local restriction.', 'In general, the embodiments of the method for detecting a hydraulic fracture position in a well can be presented by the following sequence of operations:\n \n1.', 'Injecting a fracturing fluid into a well that has several open fracturing sleeves (ports) or perforation intervals, where a hydraulic fracture can be initiated.', '2.', 'Exceeding the initiation pressure and, thus, producing a hydraulic fracture.\n \n3.', 'Injecting a marker slug with viscosity and/or density differing from those of fracturing fluid.', '4.', 'Injecting the fracturing fluid to displace the marker slug up to perforations or fracturing sleeves.\n \n5.', 'Detecting a pressure response.\n \n6.', 'Comparing the time point of observed pressure response with the volume of injected fracturing fluid after the marker slug.\n \n7.', 'Based on the volume of injected fracturing fluid, detecting the location of perforation interval or the position of respective fracturing sleeve, where the fracture, to which the marker slug was delivered, was initiated (item \n4\n).', 'An essential stage of this disclosure is injection of a “marker slug” into a well.', 'In the oil and gas industry practice, a slug being stably distinguishable from other fluid in its physical properties is referred to as the fluid slug.', 'A characteristic feature of the “fluid slug” can be fluid density, fluid viscosity, concentration of additives, etc.', 'A fluid slug in a well or pipe can be created with the use of standard equipment by combining fluid flows with substantially different properties in the same pipe.', 'For example, when using the flow-channel hydraulic fracturing technique, “clean slugs” and “dirty slugs” that are maintained during transportation to the perforation openings are alternately injected into the casing.', '“Dirty slugs” are the proppant-laden viscous fluid slugs, while “clean slugs” are the proppant-free fluid slugs.', 'The use of “fluid slugs” for reservoir treatment and injection of fluid slugs (portions) with different pH are also known.', 'In the context of the disclosed method, the “marker slug” concept means a fluid slug to be injected into a wellbore showing physical properties different from those of the remaining fracturing fluid.', 'The “marker” feature means that the composition and size of a slug are such that slug delivery into a well causes no substantial changes in the geometry and positions of hydraulic fractures.', 'Such “marker slug” is a source of information when detecting hydraulic fractures position.', 'In other words, injection of “marker slug” cannot affect the positions and geometry of hydraulic fractures produced before this slug.', 'A person of ordinary skill in the oil and gas industry will appreciate the limitations to be applied when a “marker slug” is injected into a well so that it does not cause substantial changes in the hydraulic fracture geometry or fracture conductivity.', 'In particular, effective viscosity and/or density of fluid are physical properties that distinguish the marker slug from fracturing fluid slugs.', 'According to the embodiments of this disclosure, the marker slug fluid has a viscosity that is substantially different from the fracturing fluid viscosity.', 'For the Newtonian fluids (water, saline solutions), the fluid viscosity is independent on the flow shear rate; it depends on temperature to a greater extent.', 'The non-Newtonian fluids demonstrate different behavior.', 'If a non-Newtonian fluid (where viscosity varies with flow shear rate) is injected, this leads to a decrease in the effective viscosity of fluid.', 'Such fluids are characterized by a dependency graph of viscosity (cP) versus shear rate (units of s\n−1\n).', 'Many well-working fluids are based on viscosified water-soluble polymers solutions referred to the class of non-Newtonian fluids (in particular, shear-thinning fluids).', 'This characteristic of fluid rheology should be taken into account in consideration of the substantial feature of “fluid viscosity”.', 'By viscosity we mean kinematic (or dynamic) viscosity measured just in the “bottleneck” or “high shear rate” conditions.', 'In some embodiments of this disclosure, the viscosity of marker slug fluid is 10 (or more) times as great as the viscosity of fracturing fluid.', 'Such difference in viscosities is achieved when the low-viscous (standard) fracturing fluid is selected as a fracturing fluid, while the fluid thickened by a high polymer concentration is selected for a marker slug.', 'Generally, a polymer-viscosified fluid pertains to the class of non-Newtonian fluids.', 'As a variant of viscous fluid, a water-soluble polymer solution is additionally crosslinked by a crosslinker.', 'In the oil industry practice, thickened fluids with viscosity of hundreds and thousands of centipoises can be produced.', 'In some embodiments of this disclosure, a fluid for marker slug is a viscosified oil-based fluid.', 'Therewith, the oil-based fluid is poorly miscible with aqueous fracturing fluid, which allows maintaining a high viscosity difference between fracturing fluid and an oil-based marker slug.', 'In some embodiments of this disclosure, the viscosity of marker slug fluid is 10 (or more) times as small as viscosity of fracturing fluid.', 'Such combination of fluids will be produced if water viscosified with a water-soluble polymer (water-swellable polysaccharides, polyacrylamide polymers, carboxymethyl cellulose and other thickeners) is used as a fracturing fluid, while, by contrast, a marker slug is an aqueous fluid without thickening additives (“non-viscous slug”).', 'According to embodiments of this disclosure, the marker slug fluid has a higher density as compared to the fracturing fluid.', 'An intended increase in fluid density is known from the drilling or hydraulic fracturing practice (to ensure the desired pressure of hydrostatic fluid column, which is directly proportional to the height of fluid column and fluid density).', 'To increase fluid density, high-density particles are added.', 'For example, weighting agents are presented by such minerals as barite, hematite and other weighting materials.', 'In practice, density of fluids can be increased by 1.1-2 times.', 'In some embodiments of this disclosure, the density of marker slug is considerably lower than the density of fracturing fluid slug.', 'This is achieved by introducing a lightweight material.', 'For example, a lightweight material is an additive for reducing the density of marker slug, such as cenospheres or polymeric hollow spheres.', 'In some embodiments of this disclosure, the marker slug fluid differs from the fracturing fluid to the higher side both in the density and viscosity (due to the additives of weighting or lightweight agents).', 'For example, the marker slug will have an increased viscosity (by 10 times and more) and an increased density (by 1.1 times and more).', 'In some embodiments of this disclosure, fibers at concentration above 0.5% are added into the marker slug fluid.', 'It is known that the addition of fibers into one or both interfacial fluids increases stability of the interface between two interfacial fluids (the marker slug fluid and the fracturing fluid).', 'This maintains the viscosity contrast of the marker slug flowing through the pipe to the fracture entry.', 'After formation of the marker slug, generation of pressure response may be conceived of as reaction to passage of the marker slug through the bottlenecks of fluid flow.', 'When the marker slug passes through an open hydraulic fracture zone, a pressure response occurs.', 'The pressure response propagates upwards the fluid filling the well.', 'The pressure response (a positive or negative pressure gain) is recorded by pressure transmitters located in the well or on the surface (at the wellhead).', 'Different positions in the well can be selected as the locations of one or more recording pressure transmitters: for example, at the wellhead, or in the wellbore.', 'Since the pressure response (a pressure peak) occurs as the fluid marker slug passes through the hydraulic fracture, such response is easily recorded in the pressure record diagram, if no other events having influence on the downhole pressure (such as fracture closure, pump shutdown, packer setting, etc.) take place.', 'Therefore, an embodiment of the method provides for sequential injection of fracturing fluid and a marker slug at a constant fluid flow rate (m\n3\n/s).', 'It is the constant fluid flow rate (continuous operation of hydraulic fracturing pumps) in the pressure record diagram that enables detecting the pressure response related to passage of the marker slug.', 'The pressure response amplitude depends on the location of pressure transmitter, the level of noise in the well and a method for recording and processing the pressure signals.', 'In most cases, a useful signal identifying the event of marker slug passage into a hydraulic fracture can be above 0.1 bar, and its value is reliably recorded by pressure transmitters.', 'At the instant when the pressure response caused by the marker slug passage is identified, the volume of fracturing fluid injected after the marker slug is measured by means of a flow meter.', 'When the diameter (section area) of pipes and the constant injection rate of fracturing fluid are known, this volume of fracturing fluid indicates the coordinate of marker slug location near the hydraulic fracture being detected and, respectively, the fracture coordinate with reference to the wellhead (\nFIG.', '2\n).', 'The embodiments of the method are distinguished for different well completion options (i.e. options for producing and maintaining a hydraulic fracture).', 'According to one completion option, perforation clusters (zones) corresponding to reservoir zones that need stimulation are produced in an inclined or horizontal well using perforation tools.', 'Then, using surface pumps, fracturing fluid is injected into the well at a pressure exceeding the hydraulic fracturing pressure of the reservoir, which results in opening of one or more hydraulic fractures.', 'Since the mechanical stresses in the reservoir stimulation zone differ for different perforation clusters, the hydraulic fractures are initiated and propagate into the reservoir with varying efficiency.', 'According to another completion option, one or more fracturing sleeves are arranged on the pipe in an inclined or horizontal well.', 'Fluid injection through the fracturing sleeves (or fracturing ports) is different from injection through conventional perforation openings made in a casing.', 'The fracturing sleeves render unnecessary the operation of forming perforation openings using a system of perforation charges.', 'Instead of this, a fracturing sleeve has ready-made openings.', 'Furthermore, the industry employs more suitable versions of sleeves, wherein a set of openings can be not only opened, but also closed at a desired depth to restrict flow communication between the reservoir and the tubing.', 'As the fracturing fluid pressure increases (the injection stage), the hydraulic fracturing of the rocks (formation of fractures) proceeds near the fracturing sleeve.', 'However, as this takes place, newly-formed fractures are produced at the soft rock places, and these places may be not coincident with the positions of fracturing sleeve openings (the hydraulic fracture is shifted with respect to the fracturing sleeve).', 'With such configuration, it is also expedient to detect the actual position of the hydraulic fracture.', 'In the above described well completion options comprising formation of hydraulic fractures, the bottlenecks (restrictions) for fracturing fluid communication appear.', 'These can be perforation openings of perforation clusters or a hydraulic fracture zone near the wellbore.', 'An increased flow shear rate is indicative of such a bottleneck.', 'Therewith, perforation openings in pipes can be made with different modifications.', 'Perforation openings for fluid inlet can be produced by the methods known in the industry.', 'In some embodiments of this disclosure, the method for detecting a hydraulic fracture position in a well is combined with other well operations such as, for instance, the placement of a new fracture (refract), for example, in the following sequence in accordance with the selected injection schedule: or plugging of the existing hydraulic fractures.', '(a) injecting a fracturing fluid into a well having at least one hydraulic fracture and an initiation zone of new hydraulic fracture;\n \n(b) increasing pressure above the fracturing pressure and producing at least one new hydraulic fracture;\n \n(c) injecting a marker slug into the well;\n \n(d) injecting a fracturing fluid into the well.', 'In so doing, when the marker slug enters at least one of the hydraulic fractures, a detectable pressure response is observed, and the position of a hydraulic fracture is detected from the volume of fracturing fluid injected at stage (d).', 'In the multizone reservoir stimulation practice, need arises for redirection of working fluid flows from one hydraulic fracture to another.', 'To accomplish this, the required well section is isolated by injecting an “isolation pill” or “blocking pill” or “diversion material”.', 'Therefore, in some embodiments of this disclosure, the method for detecting a hydraulic fracture position in a well is combined with other well operations such as, for instance, plugging of already existing fractures, for example, in the following sequence in accordance with the selected injection schedule:\n \n(a) injecting a fracturing fluid into a well at a pressure above the fracturing pressure and producing at least one hydraulic fracture;\n \n(b) providing plugging of at least one hydraulic fracture in the well;\n \n(c) injecting a fracturing fluid into the well at a pressure above the fracturing pressure and producing at least one new hydraulic fracture;\n \n(d) injecting a marker slug into the well;\n \n(e) injecting a fracturing fluid into the well.', 'When the marker slug enters at least one of the hydraulic fractures, a detectable pressure response is observed, and the position of a hydraulic fracture is detected from the volume of fracturing fluid injected at stage (e).', 'Rather long time intervals can be provided between stages (a) and (b) for execution of well operations.', 'Plugging of hydraulic fracture(s) at (b) stage is performed by any known method, for example, using degradable materials.', 'The embodiments of this disclosure allow detecting hydraulic fractures positions that receive fracturing fluid without engagement of complex downhole equipment, distributed pressure transmitters, load, temperature, etc.', 'The pressure response is measured using a standard pressure transmitter available in the well.', 'EXAMPLES\n \nExample 1', 'The example demonstrate injection of a marker slug, occurrence of pressure response recorded at the wellhead when the marker slug enters a hydraulic fracture, and then, the hydraulic fracture position detection in the well from the volume of injected fluid.\n \nFIG.', '2\n shows passage of a viscous marker slug through a section of horizontal well with several fracturing sleeves (ports).', 'The well has a constant pipe diameter.', 'Surface-based pumps (not shown) create a constant flow rate of fracturing fluid that enters the well and is consumed through one or more open hydraulic fractures.', 'The locations of three fracturing sleeves (the 1st, 2nd and 3rd sleeves) are designated.', 'At a certain point of time, a device for supplying fracturing fluid into the well is switched to a tank containing viscous fluid (the formed “marker slug”).', 'In each particular case, the viscosity of marker slug is within the range of values that exceeds the viscosity of fracturing fluid by 10 to 100 times.', 'Once the marker slug is introduced, the fluid supply valve is switched to supply of the previous fracturing fluid.', 'During transportation of viscous marker slug along the wellbore, the marker slug remains in the form of a single slug between two low-viscous fracturing fluids.', 'Since injection of fluids proceeds at a pressure above the hydraulic fracturing pressure (P>Pfrac) and at a constant fluid flow rate, then the instant (time) of marker slug passage near one of the fracturing sleeves is proportional to the volume of injected fracturing fluid after injection of marker slug.', 'Passage of marker slug through a bottleneck near the fracturing sleeve causes a local change in the pressure difference due to flow restriction, and this change in the fluid flow regime reveals itself in the form of a positive pressure response, which is registered by means of a pressure transmitter located at the wellhead.', 'Example 2\n \nIn the course of multistage hydraulic fracturing at one of the wells in Russia, a sequence of operations was carried out for detecting a hydraulic fracture position in the well.', 'To execute the stage (inject a marker slug), a fluid in the volume of 2 m\n3 \n(a crosslinked gel with a gelling agent concentration of 7.2 kg/m\n3\n) with the viscosity 460 times exceeding that of the fracturing fluid at other stages was used.', 'The marker slug was displaced by displacement fracturing fluid (a linear gel with the gelling agent concentration of 3.6 kg/m\n3\n) at a constant fluid flow rate.', 'The volume of displacement fracturing fluid up to receiving a pressure response of 60 bars was 16 m\n3\n, which corresponded to the volume up to fracturing sleeve No. 5.', 'Example 3\n \nWhen carrying out multistage hydraulic fracturing according to Example 2, a marker slug with the viscosity 460 times exceeding that of the fracturing fluid at other stages was injected.', "To execute the stage (inject a marker slug), a fluid in the volume of 2 m\n3 \n(a crosslinked gel with a gelling agent concentration of 7.2 kg/m\n3 \nand weighting agent (barite) added to achieve the marker slug's effective density of 1,250 kg/m\n3\n) with the viscosity 460 times exceeding that of the fracturing fluid at other stages was used.", 'The marker slug was displaced by displacement fracturing fluid (a linear gel with the gelling agent concentration of 3.6 kg/m\n3\n) at a constant fluid flow rate.', 'The volume of displacement fracturing fluid up to receiving a pressure response of 80 bars was 15.4 m\n3\n, which corresponded to the volume up to fracturing sleeve No. 6.', 'It is apparent that the above embodiments shall not be regarded as a limitation of the patent claims scope.', 'It is clear for a person skilled in the art that it is possible to introduce many changes to the technique described above without departing from the principles of the claimed invention.'] | ['1.', 'A method for detecting a hydraulic fracture position in a well, comprising: (a) injecting a fracturing fluid into a well at a pressure above a fracturing pressure and producing at least one hydraulic fracture; (b) injecting a liquid marker slug into the well; (c) injecting the fracturing fluid into the well behind the marker slug; (d) when the liquid marker slug flows through a perforation or a frac sleeve, detecting a pressure response and measuring a volume of the fracturing fluid injected at stage (c); and (e) determining the position of the at least one hydraulic fracture.', '2.', 'The method of claim 1, wherein the marker slug has a different viscosity and/or density than the fracturing fluid at stages (a) and (c).', '3.', 'The method of claim 1, wherein the marker slug viscosity is at least ten times higher than the fracturing fluid viscosity.', '4.', 'The method of claim 1, wherein the marker slug viscosity is at least ten times lower than the fracturing fluid viscosity.', '5.', 'The method of claim 1, wherein the marker slug further comprises solid particles or fibers.', '6.', 'The method of claim 1, wherein the marker slug further comprises a weighting material that increases marker slug density or a lightweight material that decreases marker slug density.', '7.', 'The method of claim 6, wherein the weighting material comprises barite or hematite.\n\n\n\n\n\n\n8.', 'The method of claim 6, wherein the lightweight material comprises cenospheres or hollow polymer spheres.', '9.', 'The method of claim 1, wherein a fluid-injection rate at stages (a), (b) and (c) is kept constant.', '10.', 'The method of claim 1, wherein the fluid injection at stages (a)-(c) is performed through perforation clusters in casing.', '11.', 'The method of claim 1, wherein the fluid injection at stages (a)-(c) is performed through fracturing sleeve openings.', '12.', 'The method of claim 1, wherein one or more stages (a), (b), (c) are performed several times in accordance with an injection schedule.', '13.', 'A method for detecting a hydraulic fracture position in a well, comprising: (a) injecting a fracturing fluid into a well having at least one hydraulic fracture and an initiation zone of at least one new hydraulic fracture; (b) increasing pressure above a fracturing pressure and producing at least one new hydraulic fracture; (c) injecting a liquid marker slug into the well; (d) injecting the fracturing fluid into the well behind the marker slug; (e) detecting a pressure response when the liquid marker slug flows through a perforation or a frac sleeve and measuring a volume of the fracturing fluid injected at stage (d); and (f) determining the position of the at least one new hydraulic fracture.\n\n\n\n\n\n\n14.', 'The method of claim 13, wherein the marker slug has a different viscosity and/or density than the fracturing fluid at stages (a) and (d).', '15.', 'The method of claim 13, wherein the marker slug viscosity is at least ten times higher than the fracturing fluid viscosity at stage (a).', '16.', 'The method of claim 13, wherein the marker slug viscosity is at least ten times lower than the fracturing fluid viscosity stage (a).', '17.', 'The method of claim 13, wherein the marker slug further comprises solid particles or fibers.', '18.', 'The method of claim 13, wherein the marker slug further comprises a weighting material that increases the marker slug density or a lightweight material that lowers the marker slug density.', '19.', 'The method of claim 18, wherein the weighting material comprises barite or hematite.\n\n\n\n\n\n\n20.', 'The method of claim 13, wherein the lightweight material comprises cenospheres or hollow polymer spheres.', '21.', 'The method of claim 13, wherein a fluid injection rate at stages (a), (b), (c) and (d) is kept constant.', '22.', 'The method of claim 13, wherein fluid injection at stages (a)-(d) is performed through perforation clusters in casing.', '23.', 'The method of claim 13, wherein fluid injection-at stages (a)-(d) is performed through fracturing sleeve openings.', '24.', 'The method of claim 13, wherein one or more stages of (a), (b), (c) and (d) are performed several times in accordance with an injection schedule.'] | ['FIG.', '1 schematically illustrates passage of fluid flow into a perforation or a frac sleeve opening through a restriction.;', 'FIG. 2 depicts a diagram of exemplary embodiment of the method.; FIG.', '2 shows passage of a viscous marker slug through a section of horizontal well with several fracturing sleeves (ports).', 'The well has a constant pipe diameter.', 'Surface-based pumps (not shown) create a constant flow rate of fracturing fluid that enters the well and is consumed through one or more open hydraulic fractures.', 'The locations of three fracturing sleeves (the 1st, 2nd and 3rd sleeves) are designated.'] |
|
US11136830 | Downhole tools with variable cutting element arrays | Feb 11, 2019 | Scott D. McDonough, Craig A. Raisanen | Schlumberger Technology Corporation | NPL References not found. | 4940099; July 10, 1990; Deane et al.; 6942045; September 13, 2005; Dennis; 7370711; May 13, 2008; Singh; 7686104; March 30, 2010; Singh et al.; 9074431; July 7, 2015; Portwood et al.; 9856701; January 2, 2018; Portwood et al.; 20090188724; July 30, 2009; Portwood; 20180106113; April 19, 2018; McDonough et al. | Foreign Citations not found. | ['A downhole tool includes a cone with an outer surface, a cone axis, and a set on the outer surface thereof.', 'The set includes first and second cutting elements.', 'The first and second cutting elements have respective first and second grips that are different.', 'Another downhole tool includes a body and a cone is connected to, and rotatable relative to, the body.', 'Cutting elements on the cone are arranged in a set to vary in radial position relative to a cone axis, with a first position nearest to, and a last position farthest from, the cone axis.', 'A first cutting element in the first position has a different cutting element geometry type than a second cutting element in the last position.', 'First and second cutting elements may have the same cutting element geometry type and one or more cutting elements therebetween may have different cutting element geometry types.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application claims the benefit of, and priority to, U.S. Patent Application No. 62/628,530, filed Feb. 9, 2018, which application is expressly incorporated herein by this reference.', 'BACKGROUND\n \nWellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes.', 'For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations.', 'Wellbores used to produce or extract fluids may be lined with casing around the walls of the wellbore.', 'A variety of drilling methods may be utilized depending partly on the characteristics of the formation through which the wellbore is drilled.', 'During drilling of a wellbore, cutting tools including cutting elements are used to remove material from the earth to extend the wellbore or from previous casing or lining of the wellbore to change the wellbore.', 'The cutting tools experience wear during the cutting operations and cutting elements may loosen in the cutting tool.', 'Lost cutting elements can damage the cutting tool and slow or stop work on the wellbore.', 'Roller cone bits include cutting elements connected to a rotating cone on the cutting tool.', 'Uniform cutting elements on the roller cone experience different amounts of wear related to the relative position of the cutting elements on the cone.', 'Some cutting elements experience more wear and/or damage than other cutting elements, leading those elements to fail prematurely.', 'A cutting tool with increased lifetime and improved reparability may reduce drilling system downtime.', 'SUMMARY\n \nIn some embodiments, a downhole tool includes a cone with an outer surface and a cone axis and a set positioned on the outer surface of the cone.', 'The set includes a first cutting element and a second cutting element.', 'The first cutting element has a first grip.', 'The second cutting element has a second grip, where the second grip is different from the first grip.', 'In some embodiments, a downhole tool includes a body, a cone, and a plurality of cutting elements.', 'The body has a bottom end and a longitudinal axis about which the body is configured to rotate.', 'The cone is connected to the bottom end of the body and is rotatable relative to the body about a cone axis.', 'The plurality of cutting elements is positioned on the cone and arranged in a set.', 'The plurality of cutting elements varies in radial position relative to the cone axis and the set has a first position nearest the cone axis and a last position furthest the cone axis.', 'A first cutting element is in the first position and a second cutting element is in the last position where the first cutting element and the second cutting element have a first cutting element geometry type.', 'One or more cutting elements between the first cutting element and second cutting element have a second cutting element geometry type that is different from the first cutting element geometry type.', 'In some embodiments, a downhole tool includes a body, a cone, a first plurality of cutting elements, and a second plurality of cutting elements.', 'The body has a bottom end and a longitudinal axis about which the body is configured to rotate.', 'The cone is connected to the body at the bottom end and is rotatable relative to the body about a cone axis.', 'The first plurality of cutting elements is positioned on the cone and arranged in a first set of an array and second plurality of cutting elements is positioned on the cone and arranged in a second set of the array.', 'At least one of the cutting elements of the first plurality of cutting elements is positioned at a first longitudinal position relative to the cone axis and has a first cutting element geometry type.', 'At least one of the cutting elements of the second plurality of cutting elements is positioned at the first longitudinal position relative to the cone axis and has a second cutting element geometry type that is different from the first cutting element geometry type.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'Additional features and advantages of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments.', 'The features and advantages of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims.', 'These and other features will become more fully apparent from the following description and appended claims, or may be learned by the practice of such embodiments as set forth hereinafter.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings.', 'For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures.', 'While some of the drawings may be schematic or exaggerated representations of concepts, non-schematic drawings should be considered as being to scale for some embodiments of the present disclosure.', 'Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:\n \nFIG.', '1\n is a side schematic view of a drilling system, according to some embodiments of the present disclosure;\n \nFIG.', '2\n is a bottom end view of a drill bit;\n \nFIG.', '3-1\n is a perspective view of a roller cone for a drill bit, according to some embodiments of the present disclosure;\n \nFIG.', '3-2\n is a detail view of the roller cone of \nFIG.', '3-1\n, according to some embodiments of the present disclosure;\n \nFIG.', '4\n is an example of a conventional composite cutting profile of a roller cone;\n \nFIG.', '5\n is a composite cutting profile of a roller cone with a plurality of cutting elements in sets, according to some embodiments of the present disclosure;\n \nFIG.', '6-1\n is a composite cutting profile of a roller cone, according to some embodiments of the present disclosure;\n \nFIG.', '6-2\n is another composite cutting profile of a roller cone, according to some embodiments of the present disclosure;\n \nFIG.', '7\n is a schematic representation of the composite cutting profile of \nFIG.', '6-1\n removing material from an earth formation, according to some embodiments of the present disclosure; and\n \nFIG.', '8\n is a perspective view of another roller cone, according to some embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'This disclosure generally relates to devices, systems, and methods for increasing operational lifetime and decreasing downtime in a drill bit.', 'More particularly, some embodiments of the present disclosure relate to devices, systems, and methods for positioning a set of cutting elements on a rotatable cone of a cutting tool, where the set includes a plurality of cutting elements with variable dimensions, properties, or geometry within the set.', 'In some embodiments, a cutting tool may have one or more cutting elements to remove material in a downhole environment.', 'During cutting operations, the area at or near the radially outward gauge surface of a roller cone may experience high abrasion and/or erosion forces.', 'A cutting tool according to some embodiments of the present disclosure may include one or more sets of cutting element within a spiral array of cutting elements on the roller cone.', 'The spiral set may include cutting elements that vary in one or more of an extension, a diameter of the cutting element, a cutting element grip, a cutting element geometry type of the cutting element, a working material of the cutting element, or combinations thereof.', 'For example, a roller cone may include a set of cutting elements within an array where the cutting elements vary with greater extension near a bottommost portion of the cutting profile and lesser extension near a gauge surface of the cutting profile.', 'In other examples, a roller cone may include a set with cutting elements that vary with greater diameter near a bottommost portion of the cutting profile and lesser extension near a gauge surface of the cutting profile.', 'In yet other examples, a roller cone may include a set with cutting elements that vary with greater diameter near a bottommost portion of the cutting profile and lesser extension near a gauge surface of the cutting profile.\n \nFIG.', '1\n shows one example of a drilling system \n100\n for drilling an earth formation \n101\n to form a wellbore \n102\n.', 'The drilling system \n100\n includes a drill rig \n103\n used to turn a drilling tool assembly \n104\n which extends downward into the wellbore \n102\n.', 'The drilling tool assembly \n104\n may include a drill string \n105\n, a bottomhole assembly (“BHA”) \n106\n, and a bit \n110\n, attached to the downhole end of drill string \n105\n.', 'The drill string \n105\n may include several joints of drill pipe \n108\n a connected end-to-end through tool joints \n109\n.', 'The drill string \n105\n transmits drilling fluid through a central bore and transmits rotational power from the drill rig \n103\n to the BHA \n106\n.', 'In some embodiments, the drill string \n105\n may further include additional components such as subs, pup joints, etc.', 'The drill pipe \n108\n provides a hydraulic passage through which drilling fluid is pumped from the surface.', 'The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit \n110\n for the purposes of cooling the bit \n110\n and cutting structures thereon, and for lifting cuttings out of the wellbore \n102\n as it is being drilled.', 'The BHA \n106\n may include the bit \n110\n or other components.', 'An example BHA \n106\n may include additional or other components (e.g., coupled between to the drill string \n105\n and the bit \n110\n).', 'Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.', 'In general, the drilling system \n100\n may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves).', 'Additional components included in the drilling system \n100\n may be considered a part of the drilling tool assembly \n104\n, the drill string \n105\n, or a part of the BHA \n106\n depending on their locations in the drilling system \n100\n.', 'The bit \n110\n in the BHA \n106\n may be any type of bit suitable for degrading downhole materials.', 'For instance, the bit \n110\n may be a drill bit suitable for drilling the earth formation \n101\n.', 'Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits.', 'In other embodiments, the bit \n110\n may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof.', 'For instance, the bit \n110\n may be used with a whipstock to mill into casing \n107\n lining the wellbore \n102\n.', 'The bit \n110\n may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore \n102\n, or combinations thereof.', 'Swarf or other cuttings formed by use of a mill may be lifted to surface, or may be allowed to fall downhole.', 'FIG.', '2\n is bottom end view of a conventional roller cone bit \n210\n.', 'A roller cone bit \n210\n may, generally, include one or more roller cones \n212\n connected to a body \n214\n.', 'The roller cones \n212\n are rotatably connected to the bottom end of the body \n214\n such that each roller cone \n212\n is rotatable about a cone axis \n216\n.', 'For instance, a journal or bearing may be used to rotatable connect the roller cones \n212\n to the body \n214\n, or to a leg extending from the body \n214\n.', 'As the body \n214\n rotates about a longitudinal axis \n218\n, contact between the roller cones \n212\n and a formation (such as formation \n101\n described in relation to \nFIG.', '1\n) rotates the roller cones \n212\n about the cone axes \n216\n.', 'The roller cones \n212\n may include a plurality of cutting elements \n220\n.', 'The cutting elements \n220\n continually strike the formation as the roller cones \n212\n rotate to fracture, break, degrade, or otherwise remove material from the formation to create a wellbore.', 'In a conventional roller cone \n212\n, the plurality of cutting elements \n220\n are arranged in rows \n222\n.', 'Each row \n222\n is positioned at a constant radial position relative to the cone axis \n216\n and around a circumference of the roller cone \n212\n.', 'The cutting elements \n220\n of each row \n222\n impact the formation sequentially to repeatedly strike the same area of the formation to remove material.', 'The rows \n222\n, however, can lead to the creation of ridges on either side of the eventual grooves formed in the formation that can reduce or limit the rate of penetration of the bit \n210\n.\n \nFIG.', '3-1\n is a perspective view of a roller cone \n312\n, according to some embodiments of the present disclosure.', 'The roller cone \n312\n may include a plurality of cutting elements \n320\n positioned in sets \n324\n-\n1\n, \n324\n-\n2\n around a cone axis \n316\n where each set is oriented at a non-perpendicular angle to the cone axis \n316\n.', 'A sequence of sets \n324\n-\n1\n, \n324\n-\n2\n may be contained in an array within a circumferential band about the cone axis \n316\n.', 'In some embodiments, a set \n324\n-\n1\n, \n324\n-\n2\n may be positioned around the entire circumference of the roller cone \n312\n and/or may continue beyond a single full circumference.', 'For example, a single set \n324\n-\n1\n, \n324\n-\n2\n may spiral around the circumference of the roller cone \n312\n one or more times (e.g., greater than 360° around the cone axis \n316\n).', 'In other embodiments, a set \n324\n-\n1\n, \n324\n-\n2\n may be positioned around a portion of the circumference of the roller cone \n312\n, but less than a full circumference.', 'For example, the set \n324\n-\n1\n, \n324\n-\n2\n illustrated in \nFIG.', '3-1\n may be positioned around less than half, or approximately 120° of, the circumference of the roller cone \n312\n relative to the cone axis \n316\n.', 'In some embodiments, a set \n324\n-\n1\n, \n324\n-\n2\n may extend around a portion of the circumference in a range having an upper value, a lower value, or upper and lower values including any of 30°, 40°, 50°, 60°, 70°, 80°, 90°, 100°, 120°, 140°, 160°, 180°, 200°, 220°, 240°, 280°, 320°, 360°, or any values therebetween.', 'In some examples, the set \n324\n-\n1\n, \n324\n-\n2\n may be positioned around greater than 30° of the circumference of the roller cone \n312\n.', 'In other examples, the set \n324\n-\n1\n, \n324\n-\n2\n may be positioned around less than 360° of the circumference of the roller cone \n312\n.', 'In yet other examples, the set \n324\n-\n1\n, \n324\n-\n2\n may be positioned around between 30° and 360° of the circumference of the roller cone \n312\n.', 'In further examples, the set \n324\n-\n1\n, \n324\n-\n2\n may be positioned around between 60° and 240° of the circumference of the roller cone \n312\n.', 'In yet further examples, the set \n324\n-\n1\n, \n324\n-\n2\n may be positioned around between 90° and 180° of the circumference of the roller cone \n312\n.', 'In some embodiments, a roller cone \n312\n may include rotationally overlapping sets \n324\n-\n1\n, \n324\n-\n2\n.', 'For example, a first set \n324\n-\n1\n may spiral around a portion of the roller cone \n312\n in both an axial direction (i.e., in the direction of the cone axis \n316\n) and a rotational direction (i.e., in the direction around the cone axis \n316\n).', 'A second set \n324\n-\n2\n may spiral around a portion of the roller cone \n312\n in both the axial direction and the rotational direction.', 'A portion of the first set \n324\n-\n1\n and a portion of the second set \n324\n-\n2\n may rotationally overlap one another in the rotational direction relative to the cone axis \n316\n in an overlapping section \n326\n.', 'In some embodiments, the overlapping section \n326\n may include a percentage of the set \n324\n-\n1\n, \n324\n-\n2\n relative to a rotational length \n328\n of the set \n324\n-\n1\n, \n324\n-\n2\n.', 'For example, in \nFIG.', '3-1\n, the rotational length \n328\n of the second set \n324\n-\n2\n may be approximately 120° and the overlapping section \n326\n may be approximately 10° around the cone axis \n316\n.', 'The overlapping section \n326\n may be about 8% of the rotational length \n328\n of the second set \n324\n-\n2\n.', 'In some embodiments, the overlapping section \n326\n may be a percentage of the rotational length \n328\n of a set \n324\n-\n1\n, \n324\n-\n2\n in a range having an upper value, a lower value, or an upper and lower value including any of 1%, 5%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or any values therebetween.', 'In some examples, the overlapping section \n326\n may be greater than 1% of the rotational length \n328\n of a set \n324\n-\n1\n, \n324\n-\n2\n.', 'In other examples, the overlapping section \n326\n may be less than 90% of the rotational length \n328\n of a set \n324\n-\n1\n, \n324\n-\n2\n.', 'In yet other examples, the overlapping section \n326\n may be between 1% and 90% of the rotational length \n328\n of a set \n324\n-\n1\n, \n324\n-\n2\n.', 'In further examples, the overlapping section \n326\n may be between 5% and 75% of the rotational length \n328\n of a set \n324\n-\n1\n, \n324\n-\n2\n.', 'In yet further examples, the overlapping section \n326\n may be between 10% and 50% of the rotational length \n328\n of a set \n324\n-\n1\n, \n324\n-\n2\n.', 'In some embodiments, a set \n324\n-\n1\n, \n324\n-\n2\n may include a series of cutting elements \n320\n that are substantially aligned in a spiral about the cone axis \n316\n.', 'It should be understood that one or more other cutting elements on the roller cone \n312\n may be aligned with a set, and not be considered part of the set.', 'For example, the first set \n324\n-\n1\n includes a series of cutting elements \n320\n positioned in a spiral path in a rotational direction and longitudinal direction of the cone axis \n316\n.', 'The roller cone \n312\n may include a row of gauge cutting elements \n341\n positioned at or near a gauge surface \n340\n of the roller cone \n312\n.', 'In some embodiments, at least one gauge cutting element \n341\n in the row may be positioned in line with the spiral path of the first set \n324\n-\n1\n.', 'In such an example, the gauge cutting element \n341\n should be understood to be part of the row of gauge cutting elements adjacent the gauge surface \n340\n, and should be understood to not be part of the first set \n324\n-\n1\n.\n \nFIG.', '3-2\n is a detail view of the first set \n324\n-\n1\n of the roller cone \n312\n of \nFIG.', '3-1\n.', 'In some embodiments, a set \n324\n-\n1\n may include a plurality of cutting elements \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n.', 'In at least one embodiment, one or more ridge cutting elements \n320\n-\n4\n may be positioned adjacent the set \n324\n-\n1\n.', 'The ridge cutting elements \n320\n-\n4\n may assist in breaking up any residual rock which was not cut by the cutting elements \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n of the set \n324\n-\n1\n.', 'In some embodiments, a set \n324\n-\n1\n may prevent such build-up of residual rock, and a roller cone \n312\n may include sets \n324\n-\n1\n without ridge cutting elements \n320\n-\n4\n adjacent the sets \n324\n-\n1\n.', 'Similar to the gauge cutting elements described in relation to \nFIG.', '3-1\n, any ridge cutting elements \n320\n-\n4\n positioned on the roller cone \n312\n near or adjacent a set \n324\n-\n1\n, should be understood to not be part of the set \n324\n-\n1\n.', 'For example, the ridge cutting elements \n320\n-\n4\n include cutting elements that are not part of the bottomhole composite cutting profile otherwise established by the cutting elements of the set \n324\n-\n1\n.', 'In other words, the ridge cutting elements \n320\n-\n4\n that are recessed from the composite cutting profile (such as shown in \nFIG.', '5\n) are to be understood to not be part of the set \n324\n-\n1\n.', 'In other examples, the ridge cutting elements \n320\n-\n4\n may include cutting elements that are at least 15% recessed from the composite cutting profile relative to the extension of the immediately adjacent cutting element.', 'The cutting elements \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n, may vary within the set \n324\n-\n1\n.', 'In an example, the first cutting element \n320\n-\n1\n and the second cutting element \n320\n-\n2\n may have different extensions above an outer surface \n330\n.', 'In other examples, a third cutting element \n320\n-\n3\n and a second cutting element \n320\n-\n2\n may have a different diameter to each other cutting element \n320\n-\n1\n.', 'The changes in cutting element diameter, cutting element extension, a working material of the cutting element, other changes to the geometry and/or cutting element geometry type of the cutting elements, or combinations thereof may allow for a cutting profile of the roller cone \n312\n that has a greater rate of penetration and lower risk of damage to the cutting elements \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n.', 'In some embodiments, a portion of the working surface of the cutting element \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n may be recessed from the outer surface \n330\n.', 'For example, the embodiment of a first set \n324\n-\n1\n illustrated in \nFIG.', '3-2\n includes the first cutting element \n320\n-\n1\n, the second cutting element \n320\n-\n2\n, and the third cutting element \n320\n-\n3\n positioned in recesses \n332\n.', 'The recesses \n332\n may be located on the outer surface \n330\n of the roller cone \n312\n.', 'The extension of the cutting elements \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n positioned in the recess \n332\n may be relative to the surface of the recess \n332\n of the roller cone \n312\n as the recess \n322\n is part of the outer surface \n330\n of the roller cone \n312\n.', 'In some embodiments, varying recesses \n332\n may allow an extension of the cutting elements \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n to vary along the first set \n324\n-\n1\n.', 'In other embodiments, the recesses \n332\n may provide clearance around the cutting elements \n320\n-\n1\n, \n320\n-\n2\n, \n320\n-\n3\n during removal of material in operation of the roller cone bit.\n \nFIG.', '4\n illustrates an example of a composite cutting profile \n434\n of a conventional roller cone bit with conventional roller cones \n412\n.', 'The composite cutting profile \n434\n overlays the position of the cutting elements \n420\n-\n1\n, \n420\n-\n2\n as the roller cones \n412\n rotate with the rotation of the roller cone bit.', 'The composite cutting profile \n434\n therefore may illustrate the outline of the cutting elements \n420\n-\n1\n, \n420\n-\n2\n positioned on the outer surface \n430\n of the roller cones \n412\n as experienced by the formation during rotation of the bit.', 'In a conventional composite cutting profile \n434\n, the cutting elements \n420\n-\n1\n, \n420\n-\n2\n may be substantially identical throughout the sets \n424\n and/or rows of the roller cone \n412\n.', 'For example, a first cutting element \n420\n-\n1\n of a set \n424\n may have a first diameter \n436\n-\n1\n and a first extension \n438\n-\n1\n beyond the outer surface \n430\n of the roller cones \n412\n, and a second cutting element \n420\n-\n2\n of the set \n424\n may have a second diameter \n436\n-\n2\n and a second extension \n438\n-\n2\n beyond the outer surface \n430\n of the roller cones \n412\n.', 'The extension of a cutting element is the height along a longitudinal axis of the cutting element that protrudes above the surface of the roller cone immediately adjacent the cutting element.', 'In a conventional composite cutting profile \n434\n, the first diameter \n436\n-\n1\n and the second diameter \n436\n-\n2\n may be approximately identical.', 'In a conventional composite cutting profile \n434\n, the first extension \n438\n-\n1\n and the second extension \n438\n-\n2\n may be approximately identical.', 'Each of the cutting elements \n420\n-\n1\n, \n420\n-\n2\n of the set \n424\n may be approximately identical with equal extensions, equal diameters, and the same working material composition throughout the composite cutting profile \n434\n toward the gauge surface \n440\n.', 'In some embodiments, the different forces experienced by the cutting elements \n420\n-\n1\n, \n420\n-\n2\n may result in greater damage to those nearer the gauge surface \n440\n.\n \nFIG.', '5\n is a composite cutting profile \n534\n of roller cones \n512\n of a roller cone bit, according to some embodiments of the present disclosure.', 'In some embodiments, the composite cutting profile \n534\n may include a plurality of arrays that each include one or more sets \n524\n-\n1\n, \n524\n-\n2\n.', 'In some embodiment, at least the first sets \n524\n-\n1\n of the first array may include a variety of different cutting elements \n520\n-\n1\n, \n520\n-\n2\n, \n520\n-\n3\n.', 'For example, the first sets \n524\n-\n1\n may include a first cutting element \n520\n-\n1\n with a first diameter \n536\n-\n1\n and a second cutting element \n520\n-\n2\n with a second diameter \n536\n-\n2\n.', 'In some embodiments, the first diameter \n536\n-\n1\n may be greater than the second diameter \n536\n-\n2\n.', 'In other embodiments, the first diameter \n536\n-\n1\n may be less than the second diameter \n536\n-\n2\n.', 'In some embodiments, at least one cutting element in the first sets \n524\n-\n1\n may have a diameter that is different from the diameter of another cutting element.', 'For example, at least one cutting element may have a diameter that is a percentage of a diameter of another cutting element of the array in a range having an upper value, a lower value, or upper and lower values including any of 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 95%, or any values therebetween.', 'For example, at least one cutting element may have a diameter that is greater than 10% of a diameter of another cutting element of the array.', 'In other examples, at least one cutting element may have a diameter that is less than 95% of a diameter of another cutting element of the array.', 'In yet other examples, at least one cutting element may have a diameter that is between 10% and 95% of a diameter of another cutting element of the array.', 'In further examples, at least one cutting element may have a diameter that is between 20% and 90% of a diameter of another cutting element of the array.', 'In yet further examples, at least one cutting element may have a diameter that is between 50% and 85% of a diameter of another cutting element of the array.', 'In the embodiment of a composite cutting profile illustrated in \nFIG.', '5\n, the second diameter \n536\n-\n2\n may be approximately 70% of the first diameter \n536\n-\n1\n.', 'In some embodiments, the first set \n524\n-\n1\n may include a first cutting element \n520\n-\n1\n with a first extension \n538\n-\n1\n and a third cutting element \n520\n-\n3\n with a third extension \n538\n-\n3\n.', 'In some embodiments, the first extension \n538\n-\n1\n may be greater than the third extension \n538\n-\n3\n.', 'In other embodiments, the first extension \n538\n-\n1\n may be less than the third extension \n538\n-\n3\n.', 'In some embodiments, at least one cutting element in the first sets \n524\n-\n1\n of the first array may have an extension that is different from an extension of another cutting element.', 'For example, at least one cutting element may have an extension that is a percentage of an extension of another cutting element of the array in a range having an upper value, a lower value, or upper and lower values including any of 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 95%, or any values therebetween.', 'For example, at least one cutting element may have an extension that is greater than 10% of an extension of another cutting element of the set.', 'In other examples, at least one cutting element may have an extension that is less than 95% of an extension of another cutting element of the set.', 'In yet other examples, at least one cutting element may have an extension that is between 10% and 95% of an extension of another cutting element of the set.', 'In further examples, at least one cutting element may have an extension that is between 20% and 90% of an extension of another cutting element of the set.', 'In yet further examples, at least one cutting element may have an extension that is between 30% and 85% of an extension of another cutting element of the set.', 'In the embodiment of a composite cutting profile illustrated in \nFIG.', '5\n, the third extension \n538\n-\n3\n may be approximately 75% of the first extension \n538\n-\n1\n.\n \nFIG.', '5\n illustrates a first array \n524\n-\n1\n with a plurality of cutting elements.', 'In some embodiments, the cutting elements of a set of an array may have different cutting element geometry types.', 'For example, the cutting elements may be non-planar cutting elements (i.e., apexed cutting elements).', 'Apexed cutting element geometry types may include chisel cutting elements, such as cutting elements with an elongated axe-like leading edge or cutting tip; conical cutting elements, such as rotationally symmetrical cutting elements with at least a portion of the cutting element profile being angled and linear towards a center apex (such as the cutting elements \n520\n-\n1\n, \n520\n-\n2\n, \n520\n-\n3\n illustrated in \nFIG.', '5\n); or curved cutting elements, such as a rotationally symmetrical “bullet” cutting element with a continuously curved working surface toward the center apex.', 'An array according to some embodiments of the present disclosure (such as array \n524\n-\n1\n), may include a plurality of cutting elements with the same cutting element geometry type.', 'For example, the set may include all non-planar cutting elements.', 'In other examples, the set may include all conical cutting elements.', 'In other embodiments, an array may include a plurality of cutting elements with different cutting element geometry types.', 'For example, a set may include at least one conical cutting element and at least one bullet cutting element, at least one conical cutting element and at least one chisel cutting element, or at least one chisel cutting element and at least one bullet cutting element.', 'In some embodiments, a set of an array may include different cutting element geometries with the same cutting element geometry type.', 'For example, a set of an array may include all conical cutting elements, where at least two of the conical cutting elements have differing radii of curvature at the apex, differing cone angles, differing diameters, or some combination of the foregoing.', 'In other examples, a set of an array may include all chisel cutting elements, where at least two of the chisel cutting elements have differing radii of curvature at the apex, differing diameters, differing chamfer features, or the like.', 'In yet other examples, a set of an array may include all chisel cutting elements, with at least two of the chisel cutting elements having differing widths of the cutting edge along the apex, differing diameters, or the like.', 'In some embodiments, a cutting element \n520\n may include a working material.', 'For example, the working material may include a ceramic, carbide, diamond, or ultrahard material.', 'An ultrahard material is understood to refer to those materials known in the art to have a grain hardness of about 1,500 HV (Vickers hardness in kg/mm2) or greater.', 'Such ultra-hard materials can include those capable of demonstrating physical stability at temperatures above about 750° C., and for certain applications above about 1,000° C., that are formed from consolidated materials.', 'Such ultrahard materials can include but are not limited to diamond or polycrystalline diamond (PCD), nanopolycrystalline diamond (NPD), or hexagonal diamond (Lonsdaleite); cubic boron nitride (cBN); polycrystalline cBN (PcBN); Q-carbon; binderless PcBN; diamond-like carbon; boron suboxide; aluminum manganese boride; metal borides; boron carbon nitride; and other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, as well as combinations of the above materials.', 'In at least one embodiment, a portion of the cutting element \n520\n may be a monolithic carbonate PCD.', 'For example, a portion of the cutting element \n520\n may consist of a PCD without an attached substrate or metal catalyst phase.', 'In some embodiments, the ultrahard material may have a hardness values above 3,000 HV.', 'In other embodiments, the ultrahard material may have a hardness value above 4,000 HV.', 'In yet other embodiments, the ultrahard material may have a hardness value greater than 80 HRa (Rockwell hardness A).', 'In some embodiments, at least one set \n524\n-\n1\n of the first array may have cutting elements \n520\n-\n1\n, \n520\n-\n2\n, \n520\n-\n3\n with the same working materials.', 'For example, all of the cutting elements of at least one set \n524\n-\n1\n of the first array may include the same working material.', 'In at least one example, all of the cutting elements of at least one set \n524\n-\n1\n of the first array may include a PCD working material.', 'In other embodiments, at least one set \n524\n-\n1\n of the first array may have cutting elements \n520\n-\n1\n, \n520\n-\n2\n, \n520\n-\n3\n with different working materials.', 'For example, the first cutting element \n520\n-\n1\n may include a tungsten carbide working material and the second cutting element \n520\n-\n2\n may include a PcBN working material.', 'In other examples, the first cutting element \n520\n-\n1\n may include a PcBN working material and the third cutting element \n520\n-\n3\n may include a PCD working material.', 'In yet other examples, the first cutting element \n520\n-\n1\n, second cutting element \n520\n-\n2\n, and third cutting element \n520\n-\n3\n may each include different working materials from one another.', 'In some embodiments, roller cones \n512\n may include a plurality sets \n524\n-\n1\n, \n524\n-\n2\n that form a plurality of arrays thereon.', 'In some embodiments, each of the arrays may have cutting elements that vary in extension, diameter, working material, or combinations thereof.', 'In other embodiments, at least one array, such as the second array \n524\n-\n2\n illustrated in \nFIG.', '5\n, may include cutting elements that are identical in extension, diameter, and working material.', 'In some embodiments, at least one set \n524\n-\n1\n of an array may include a bottommost point \n542\n of the composite cutting profile \n534\n or bit, and the cutting elements of the set \n524\n-\n1\n may change relative to a proximity to the gauge surface \n540\n.', 'For example, \nFIG.', '6-1\n illustrates a first array composite cutting profile \n544\n of the cutting element sets \n524\n of the first array between the bottommost point \n542\n of the bit through a staggered zone \n546\n toward the gauge surface \n540\n.', 'The staggered zone \n546\n may be the area of the roller cone and/or composite cutting profile between the bottommost point \n542\n and the gauge surface \n540\n.', 'In some embodiments, at least one cutting element in the sets \n524\n of the first array may have a cutting element grip that is different from a grip of another cutting element.', 'Varying the grip may displace the bottom of each cutting element pocket, spacing stress risers from the cutting elements and/or cutting element pockets from one another.', 'Varying the grip of different cutting elements in a set may allow for greater durability and impact resistance of the cutting element and/or cone body.', 'In some embodiments, at least one cutting element may have a grip that is a percentage of a grip of another cutting element of the set in a range having an upper value, a lower value, or upper and lower values including any of 50%, 60%, 70%, 80%, 90%, 95%, or any values therebetween.', 'For example, at least one cutting element may have a grip that is greater than 50% of a grip of another cutting element of the set.', 'In other examples, at least one cutting element may have a grip that is less than 95% of a grip of another cutting element of the set.', 'In yet other examples, at least one cutting element may have a grip that is between 50% and 95% of a grip of another cutting element of the set.', 'In further examples, at least one cutting element may have a grip that is between 60% and 90% of a grip of another cutting element of the set.', 'In yet further examples, at least one cutting element may have a grip that is between 70% and 85% of a grip of another cutting element of the set.', 'In the embodiment of a composite cutting profile illustrated in \nFIG.', '6-1\n, the first grip \n548\n-\n1\n of the first cutting element \n520\n-\n1\n may be approximately 75% of the third grip \n548\n-\n3\n of the third cutting element \n520\n-\n3\n.', 'In some embodiments, the grip may vary between cutting elements independently of the extension, diameter, cutting element geometry type, working material, or other property.', 'For example, the grip may vary while the extensions are the same between the cutting elements.', 'In other examples, the diameter may remain constant between cutting elements in a set while the grip varies.', 'In yet other examples, a working material may be constant across cutting elements, while the grip of cutting elements may vary.', 'In some embodiments, extension, diameter, grip, working material, or combinations thereof of the cutting elements may change from the bottommost point \n542\n toward the gauge surface \n540\n.', 'For example, the first cutting element \n520\n-\n1\n may be positioned at or near the bottommost point \n542\n and the third cutting element \n520\n-\n3\n may be the cutting element of the sets \n524\n of the array closest to the gauge surface \n540\n.', 'In some embodiments, a cutting element diameter may decrease from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n.', 'For example, a diameter of the first cutting element \n520\n-\n1\n may be greater than a diameter of the third cutting element \n520\n-\n3\n.', 'In other embodiments, a cutting element diameter may increase from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n.', 'For example, a diameter of the first cutting element \n520\n-\n1\n may be less than a diameter of the third cutting element \n520\n-\n3\n.', 'In some embodiments, the change in cutting element diameter from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be continuous, with each cutting element from the cutting element at or nearest the bottommost point \n542\n toward the cutting element at or nearest the gauge surface \n540\n having a progressively smaller cutting element diameter.', 'In other embodiments, the change in cutting element diameter from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be discrete, with at least two of the cutting elements between the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n having the same cutting element diameters.', 'For example, the first cutting element \n520\n-\n1\n and the cutting element immediately adjacent in the direction of the gauge surface \n540\n may have the same cutting element diameter, while the third cutting element \n520\n-\n3\n may have a smaller cutting element diameter.', 'In some embodiments, the change in cutting element diameter from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be continuous, with each cutting element from the cutting element at or nearest the bottommost point \n542\n toward the cutting element at or nearest the gauge surface \n540\n having a progressively larger cutting element diameter.', 'In other embodiments, the change in cutting element diameter from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be discrete, with at least two of the cutting elements between the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n having the same cutting element diameters.', 'For example, the first cutting element \n520\n-\n1\n and the cutting element immediately adjacent in the direction of the gauge surface \n540\n may have the same cutting element diameter, while the third cutting element \n520\n-\n3\n may have a larger cutting element diameter.', 'In some embodiments, a cutting element extension may decrease from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n.', 'For example, an extension of the first cutting element \n520\n-\n1\n may be greater than an extension of the third cutting element \n520\n-\n3\n.', 'In other embodiments, a cutting element extension may increase from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n.', 'For example, an extension of the first cutting element \n520\n-\n1\n may be less than an extension of the third cutting element \n520\n-\n3\n.', 'In some embodiments, the change in cutting element extension from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be continuous, with each cutting element from the cutting element at or nearest the bottommost point \n542\n toward the cutting element at or nearest the gauge surface \n540\n having a progressively smaller cutting element extension.', 'In other embodiments, the change in cutting element extension from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be discrete, with at least two of the cutting elements between the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n having the same cutting element extensions.', 'For example, the first cutting element \n520\n-\n1\n and the cutting element immediately adjacent in the direction of the gauge surface \n540\n may have the same cutting element extension, while the third cutting element \n520\n-\n3\n may have a smaller cutting element extension.', 'In some embodiments, the change in cutting element extension from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be continuous, with each cutting element from the cutting element at or nearest the bottommost point \n542\n toward the cutting element at or nearest the gauge surface \n540\n having a progressively larger cutting element extension.', 'In other embodiments, the change in cutting element extension from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be discrete, with at least two of the cutting elements between the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n having the same cutting element extensions.', 'For example, the first cutting element \n520\n-\n1\n and the cutting element immediately adjacent in the direction of the gauge surface \n540\n may have the same cutting element extension, while the third cutting element \n520\n-\n3\n may have a larger cutting element extension.', 'In some embodiments, a working material hardness of each cutting element may decrease from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n.', 'For example, a working material hardness of the first cutting element \n520\n-\n1\n may be greater than a working material hardness of the third cutting element \n520\n-\n3\n.', 'In other embodiments, a working material hardness may increase from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n.', 'For example, a working material hardness of the first cutting element \n520\n-\n1\n may be less than a working material hardness of the third cutting element \n520\n-\n3\n.', 'In some embodiments, the change in working material hardness from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be continuous, with each cutting element from the cutting element at or nearest the bottommost point \n542\n toward the cutting element at or nearest the gauge surface \n540\n having a progressively lesser working material hardness.', 'In other embodiments, the change in working material hardness from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be discrete, with at least two of the cutting elements between the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n having the same working material hardness.', 'For example, the first cutting element \n520\n-\n1\n and the cutting element immediately adjacent in the direction of the gauge surface \n540\n may have the same working material hardness, while the third cutting element \n520\n-\n3\n may have a lesser working material hardness.', 'In some embodiments, the change in working material hardness from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be continuous, with each cutting element from the cutting element at or nearest the bottommost point \n542\n toward the cutting element at or nearest the gauge surface \n540\n having a progressively greater working material hardness.', 'In other embodiments, the change in working material hardness from the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n may be discrete, with at least two of the cutting elements between the cutting element at or nearest the bottommost point \n542\n to the cutting element at or nearest the gauge surface \n540\n having the same working material hardness.', 'For example, the first cutting element \n520\n-\n1\n and the cutting element immediately adjacent in the direction of the gauge surface \n540\n may have the same working material hardness, while the third cutting element \n520\n-\n3\n may have a greater working material hardness.\n \nFIG.', '6-2\n illustrates another composite cutting profile \n644\n of sets \n624\n comprising an array, according to some embodiments of the present disclosure.', 'In some embodiments, the cutting elements at either end of the sets \n624\n of the array may have a different property and/or dimension that the cutting elements positioned between the ends of the sets \n624\n.', 'For example, the first cutting element \n624\n-\n1\n may be located in a first position of the set \n624\n nearest the cone axis and furthest from a gauge surface \n640\n.', 'At an opposite end of the set \n624\n-\n1\n, the last position of the set \n624\n may have a cutting element with at least one property in common with the first cutting element and that is different from the one or more cutting elements positioned between.', 'For example, the third cutting element \n620\n-\n3\n may be located in the last position and the second cutting element \n620\n-\n2\n may be positioned between the first cutting element \n620\n-\n1\n in the first position and the third cutting element \n620\n-\n3\n in the last position.', 'In some embodiments, the first cutting element \n620\n-\n1\n in the first position may have the same cutting element geometry type as the third cutting element \n620\n-\n3\n in the last position, while the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n) may have a different cutting element geometry type.', 'For example, the first cutting element \n620\n-\n1\n in the first position and the third cutting element \n620\n-\n3\n in the last position may be chisel cutting elements, while the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n) may be conical cutting elements.', 'In other embodiments, the first cutting element \n620\n-\n1\n in the first position may have the same grip as the third cutting element \n620\n-\n3\n in the last position, while the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n) may have a different grip.', 'For example, the first grip \n648\n-\n1\n in the first position and the third grip \n648\n-\n3\n in the last position may be the same, while the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n) may have a longer grip.', 'For example, the third grip \n648\n-\n3\n being lesser than other grips in the set \n624\n may provide additional clearance and/or spacing of stress risers from the row of gauge cutting elements \n649\n positioned at the gauge surface \n640\n.', 'In yet other embodiments, the first grip \n648\n-\n1\n in the first position and the third grip \n648\n-\n3\n in the last position may be greater than the grip of the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n).', 'In some embodiments, a grip ratio of the first grip \n648\n-\n1\n and third grip \n648\n-\n3\n to a grip of one or more cutting elements located therebetween may be in a range having an upper value, a lower value, or upper and lower values including any of 50%, 60%, 70%, 80%, 90%, 95%, or any values therebetween.', 'For example, the first grip \n648\n-\n1\n and third grip \n648\n-\n3\n may be 0.5 inches (12.7 millimeters) and the grip of one or more cutting elements therebetween may be 1.0 inches (25.4 millimeters).', 'In other examples, the grip ratio may be greater than 50%.', 'In yet other examples, the grip ratio may be less than 95%.', 'In some embodiments, other dimensions and/or properties of the cutting elements in the first position and last position may be the same and may “bookend” a set with cutting elements having different dimensions and/or properties therebetween.', 'For example, the first cutting element \n620\n-\n1\n in the first position may have the same extension as the third cutting element \n620\n-\n3\n in the last position, while the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n) may have a different extension.', 'For example, the first cutting element \n620\n-\n1\n in the first position and the third cutting element \n620\n-\n3\n in the last position may have an extension that is less than that of the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n).', 'Such a reduction in extension at ends of the set \n624\n may allow for a more gradual start to the set \n624\n contacting the material of the formation and may increase operational lifetime of the tool.', 'In other examples, the first cutting element \n620\n-\n1\n in the first position may have the same diameter as the third cutting element \n620\n-\n3\n in the last position, while the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n) may have a different diameter.', 'For example, the first cutting element \n620\n-\n1\n in the first position and the third cutting element \n620\n-\n3\n in the last position may have a diameter that is less than that of the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n).', 'Such as reduction in diameter at the ends of the set \n624\n may allow for closer packing of the cutting elements to adjacent features of the roller cone.', 'In yet other examples, the first cutting element \n620\n-\n1\n in the first position may have the same working material as the third cutting element \n620\n-\n3\n in the last position, while the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n) may have a different working material.', 'For example, the first cutting element \n620\n-\n1\n in the first position and the third cutting element \n620\n-\n3\n in the last position may have a working material that is harder than that of the one or more cutting elements located therebetween (e.g., the second cutting element \n620\n-\n2\n).', 'The harder working material may allow the set \n624\n to resist erosion at the ends of the set \n624\n, while enabling the use of cheaper and/or easier to manufacture working materials in the interior of the set \n624\n.\n \nFIG.', '7\n is a schematic representation of the roller cone \n512\n removing material from a formation \n501\n, according to embodiments of the present disclosure.', 'In some embodiments, a roller cone \n512\n may incur less damage and/or increase a rate of penetration with a set with different cutting elements.', 'For example, cutting elements \n520\n-\n1\n, \n520\n-\n3\n between the bottommost point \n542\n and gauge surface \n540\n of the roller cone \n512\n (i.e., in the staggered zone \n546\n) may be different from one another to increase a rate of penetration of the first cutting element \n520\n-\n1\n at or near the bottommost point \n542\n while reducing damage to the third cutting element \n520\n-\n3\n at or near the gauge surface \n540\n.', 'In some embodiments, a first cutting element \n520\n-\n1\n may be oriented more axially downhole (e.g., in the longitudinal direction of the roller cone bit) relative to the radially tilted third cutting element \n520\n-\n3\n.', 'The third cutting element \n520\n-\n3\n may experience greater forces and greater exposure to wear nearer the gauge surface \n540\n than the first cutting element \n520\n-\n1\n.', 'The third cutting element \n520\n-\n3\n may have a third extension \n538\n-\n3\n that is shorter than the first extension \n538\n-\n1\n of the first cutting element \n520\n-\n1\n to support the third cutting element \n520\n-\n3\n.', 'The first cutting element \n520\n-\n1\n may have a larger first extension \n538\n-\n1\n, relative to third extension \n538\n-\n3\n of the third cutting element \n520\n-\n3\n, that provides a greater rate of penetration of the roller cone \n512\n.', 'In some embodiments, the first extension \n538\n-\n1\n may be the largest extension of the set.', 'The first extension \n538\n-\n1\n may be relatively larger to provide a greater rate of penetration by creating unsupported formation \n501\n.', 'After contact with the first cutting element \n520\n-\n1\n, the formation \n501\n may have a recess therein.', 'The area of the formation \n501\n around the recess is unsupported (e.g., it may collapse toward the recess under force), and the cutting elements positioned in the staggered zone \n546\n may subsequently and in series, remove and propagate the unsupported material of the formation to remove material.', 'The aggressive first cutting element \n520\n-\n1\n may allow for a deeper unsupported material, enabling a greater rate of penetration.', 'The subsequent cutting elements after the first cutting element \n520\n-\n1\n (sequentially toward the gauge surface \n540\n) may have less extension and/or may be less aggressive to reduce wear on the cutting elements while still removing the unsupported material.', 'In some embodiments, the first cutting element \n520\n-\n1\n may further have a larger diameter than subsequent cutting elements (toward the gauge surface \n540\n).', 'A greater extension may provide an increased rate of penetration relative to a lesser extension, and a larger diameter may further support a cutting element with a greater extension.', 'Further, the cutting elements at or near the gauge surface \n540\n may have a smaller diameter to facilitate closer packing of cutting elements to increase wear and/or erosion resistance.\n \nFIG.', '8\n is a perspective view of another roller cone, according to embodiments of the present disclosure.', 'In some embodiments, a roller cone \n712\n may include a plurality of sets in an array.', 'For example, the roller cone \n712\n may include at least a first set \n724\n-\n1\n and a second set \n724\n-\n2\n.', 'The first set \n724\n-\n1\n and second set \n724\n-\n2\n may be located at the same longitudinal position relative to the cone axis \n716\n and displaced around the cone axis \n716\n.', 'In some embodiments, at least one of the cutting elements of the first set \n724\n-\n1\n may be longitudinally aligned (e.g., at the same longitudinal position relative to the cone axis \n716\n) with a cutting element of the second set \n724\n-\n2\n.', 'For example, a first cutting element \n720\n-\n1\n located at a leading end of the first set \n724\n-\n1\n may be positioned at the same longitudinal position along the cone axis \n716\n as a second cutting element \n720\n-\n2\n cutting element located at a leading end of the second set \n724\n-\n2\n.', 'While the roller cone \n712\n rotates about the cone axis \n716\n, the first cutting element \n720\n-\n1\n of the first set \n724\n-\n1\n and second cutting element \n720\n-\n2\n of the second set \n724\n-\n2\n may contact the same location in the composite cutting profile (similar to those described in relation to \nFIGS.', '5 and 6-1\n) of the roller cone \n712\n.', 'In some embodiments, the cutting element geometry and/or type may change between the first set \n724\n-\n1\n and second set \n724\n-\n2\n, such that the first cutting element \n720\n-\n1\n and second cutting element \n720\n-\n2\n, while overlapping in longitudinal position, contact the formation differently.', 'For example, the first cutting element \n720\n-\n1\n may be a conical cutting element and the second cutting element \n720\n-\n2\n may be a chisel cutting element.', 'In other examples, the first cutting element \n720\n-\n1\n may be a chisel cutting element and the second cutting element \n720\n-\n2\n may be a bullet cutting element.', 'In yet other examples, the first cutting element \n720\n-\n1\n may be a frustoconical cutting element and the second cutting element \n720\n-\n2\n may be a conical cutting element.', 'In at least one example, the first cutting element \n720\n-\n1\n may be a conical cutting element and the second cutting element \n720\n-\n2\n may be a conical cutting element with a different radius of curvature at the tip.', 'In some embodiments, a roller cone bit may include at least one set of cutting elements that vary in extension, type, working material, or radius and may allow increased rate of penetration and/or decreased rate of wear of the cutting elements.', 'In at least one embodiment, the set may be most aggressive at the bottommost point of the composite cutting profile and may be most durable (i.e., most wear-resistant) adjacent the gauge surface.', 'The embodiments of cutting tools have been primarily described with reference to wellbore cutting operations; the cutting tools described herein may be used in applications other than the drilling of a wellbore.', 'In other embodiments, cutting tools of the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources.', 'For instance, cutting tools of the present disclosure may be used in a borehole used for placement of utility lines.', 'Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.', 'One or more specific embodiments of the present disclosure are described herein.', 'These described embodiments are examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” in the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein, to the extent such features are not described as being mutually exclusive.', 'Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure.', 'A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result.', 'The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.', 'The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result.', 'For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount.', 'Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements.', 'For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.', 'A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure.', 'Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function.', 'It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function.', 'Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.', 'The described embodiments are therefore to be considered as illustrative and not restrictive, and the scope of the disclosure is indicated by the appended claims rather than by the foregoing description.'] | ['1.', 'A downhole tool, comprising:\na cone, the cone having an outer surface and a cone axis about which the cone is configured to rotate; and\nan array positioned on the outer surface of the cone, the array including at least one set of cutting elements within a circumferential band about the cone axis, the at least one set of cutting elements oriented at a non-perpendicular angle to the cone axis, the at least one set including: a first cutting element positioned at a first longitudinal position and having a first grip; and a second cutting element positioned at a second longitudinal position different from the first longitudinal position and having a second grip, the second grip being different from the first grip.', '2.', 'The downhole tool of claim 1, the first cutting element having a first extension and the second cutting element having a second extension, the first extension and the second extension being the same.', '3.', 'The downhole tool of claim 1, the array further comprising a third cutting element at a third longitudinal position different from the first longitudinal position and the second longitudinal position, the third cutting element having a third grip that is different from the first grip and the second grip.', '4.', 'The downhole tool of claim 3, the third cutting element having a third extension that is the same as at least one of the first extension or the second extension.', '5.', 'The downhole tool of claim 1, the first cutting element being at least one of an apexed cutting element or a chisel cutting element.', '6.', 'The downhole tool of claim 5, the first cutting element and the second cutting element having different types of cutting element geometry.', '7.', 'The downhole tool of claim 1, the first cutting element having a first diameter and the second cutting element having a second diameter, the first diameter and the second diameter being the same.\n\n\n\n\n\n\n8.', 'The downhole tool of claim 1, the first cutting element being positioned longitudinally adjacent a gage row, the first grip being less than the second grip.', '9.', 'The downhole tool of claim 1, further comprising a third cutting element, the first cutting element being at a first position nearer the cone axis than the second or third cutting elements, the third cutting element being in a last position farther from the cone axis than the second cutting element, and the second cutting element at an intermediate position between the first cutting element and the second cutting element, the first cutting element and the third cutting element having a first cutting element geometry type and the second cutting element having a second cutting element geometry type that is different from the first cutting element geometry type.', '10.', 'A downhole tool, comprising:\na body, the body having a bottom end and being rotatable about a longitudinal axis;\na cone connected to the body proximate the bottom end and rotatable relative to the body about a cone axis; and\na plurality of cutting elements on the cone, the plurality of cutting elements arranged in a set within a circumferential band about the cone axis, the set of cutting elements oriented at a non-perpendicular angle to the cone axis in which the plurality of cutting elements vary in radial position relative to the cone axis, the set having a first position nearest the cone axis and a last position farthest from the cone axis, a first cutting element being in the first position and a second cutting element being in the last position, where the first cutting element and the second cutting element have a first cutting element geometry type and one or more cutting elements between the first cutting element and the second cutting element have a second cutting element geometry type that is different from the first cutting element geometry type.', '11.', 'The downhole tool of claim 10, at least part of the set being positioned at a bottommost portion of the cone or in a staggered zone of the cone adjacent a gauge surface of the cone.\n\n\n\n\n\n\n12.', 'The downhole tool of claim 11, each of the plurality of cutting elements of the set decreasing in extension from the bottommost portion toward the gauge surface.', '13.', 'The downhole tool of claim 10, the first cutting element and the second cutting element having a cutting tip of a first diameter and each of the one or more cutting elements between the first cutting element and second cutting element having a cutting tip of a second diameter that is less than the first diameter.', '14.', 'The downhole tool of claim 10, the first cutting element and the second cutting element having a first extension and at least some of the one or more cutting elements between the first cutting element and second cutting element having a second extension that is different from the first extension.', '15.', 'The downhole tool of claim 10, the first cutting element and the second cutting element including a first working material and at least some of the one or more cutting elements between the first cutting element and second cutting element including a second working material that is different from the first working material.', '16.', 'The downhole tool of claim 15, the first working material being harder than the second working material.', '17.', 'The downhole tool of claim 10, the first cutting element geometry type being a chisel cutting element and the second cutting element geometry type being a conical cutting element.', '18.', 'A downhole tool, comprising:\na body having a bottom end and a longitudinal axis about which the body is configured to rotate;\na cone connected to the body proximate the bottom end and rotatable relative to the body about a cone axis of the cone;\na first set of an array positioned on an outer surface of the cone, the first set including a first plurality of cutting elements, at least one of the cutting elements of the first plurality of cutting elements being positioned at a first longitudinal position relative to the cone axis and having a first cutting element geometry type; and\na second set of the same array positioned on the outer surface of the cone, the second set including a second plurality of cutting elements, at least one of the cutting elements of the second plurality of cutting elements being positioned at the first longitudinal position relative to the cone axis and having a second cutting element geometry type that is different from the first cutting element geometry type.\n\n\n\n\n\n\n19.', 'The downhole tool of claim 18, the first plurality of cutting elements varying in radial position relative to the cone axis and at least one of cutting element extension relative to the outer surface of the cone, cutting element diameter, cutting element grip, or working material of the plurality of first cutting elements, and the second plurality of cutting elements varying in radial position relative to the cone axis and at least one of cutting element extension relative to the outer surface of the cone, cutting element diameter, cutting element grip, or working material of the plurality of second cutting elements.', '20.', 'The downhole tool of claim 18, the first cutting element geometry type being at least one of a conical cutting element, a chisel cutting element, or a bullet cutting element, and the second cutting element geometry type being a conical cutting element.'] | ['FIG.', '1 is a side schematic view of a drilling system, according to some embodiments of the present disclosure;; FIG.', '2 is a bottom end view of a drill bit;; FIG.', '3-1 is a perspective view of a roller cone for a drill bit, according to some embodiments of the present disclosure;; FIG.', '3-2 is a detail view of the roller cone of FIG.', '3-1, according to some embodiments of the present disclosure;; FIG. 4 is an example of a conventional composite cutting profile of a roller cone;; FIG.', '5 is a composite cutting profile of a roller cone with a plurality of cutting elements in sets, according to some embodiments of the present disclosure;; FIG.', '6-1 is a composite cutting profile of a roller cone, according to some embodiments of the present disclosure;; FIG.', '6-2 is another composite cutting profile of a roller cone, according to some embodiments of the present disclosure;; FIG.', '7 is a schematic representation of the composite cutting profile of FIG.', '6-1 removing material from an earth formation, according to some embodiments of the present disclosure; and; FIG.', '8 is a perspective view of another roller cone, according to some embodiments of the present disclosure.', '; FIG.', '1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102.', 'The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102.', 'The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of drill string 105.; FIG.', '2 is bottom end view of a conventional roller cone bit 210.', 'A roller cone bit 210 may, generally, include one or more roller cones 212 connected to a body 214.', 'The roller cones 212 are rotatably connected to the bottom end of the body 214 such that each roller cone 212 is rotatable about a cone axis 216.', 'For instance, a journal or bearing may be used to rotatable connect the roller cones 212 to the body 214, or to a leg extending from the body 214.', 'As the body 214 rotates about a longitudinal axis 218, contact between the roller cones 212 and a formation (such as formation 101 described in relation to FIG.', '1) rotates the roller cones 212 about the cone axes 216.; FIG.', '3-1 is a perspective view of a roller cone 312, according to some embodiments of the present disclosure.', 'The roller cone 312 may include a plurality of cutting elements 320 positioned in sets 324-1, 324-2 around a cone axis 316 where each set is oriented at a non-perpendicular angle to the cone axis 316.', 'A sequence of sets 324-1, 324-2 may be contained in an array within a circumferential band about the cone axis 316.', 'In some embodiments, a set 324-1, 324-2 may be positioned around the entire circumference of the roller cone 312 and/or may continue beyond a single full circumference.', 'For example, a single set 324-1, 324-2 may spiral around the circumference of the roller cone 312 one or more times (e.g., greater than 360° around the cone axis 316).', 'In other embodiments, a set 324-1, 324-2 may be positioned around a portion of the circumference of the roller cone 312, but less than a full circumference.', 'For example, the set 324-1, 324-2 illustrated in FIG.', '3-1 may be positioned around less than half, or approximately 120° of, the circumference of the roller cone 312 relative to the cone axis 316.; FIG.', '3-2 is a detail view of the first set 324-1 of the roller cone 312 of FIG.', '3-1.', 'In some embodiments, a set 324-1 may include a plurality of cutting elements 320-1, 320-2, 320-3.', 'In at least one embodiment, one or more ridge cutting elements 320-4 may be positioned adjacent the set 324-1.', 'The ridge cutting elements 320-4 may assist in breaking up any residual rock which was not cut by the cutting elements 320-1, 320-2, 320-3 of the set 324-1.', 'In some embodiments, a set 324-1 may prevent such build-up of residual rock, and a roller cone 312 may include sets 324-1 without ridge cutting elements 320-4 adjacent the sets 324-1.', 'Similar to the gauge cutting elements described in relation to FIG.', '3-1, any ridge cutting elements 320-4 positioned on the roller cone 312 near or adjacent a set 324-1, should be understood to not be part of the set 324-1.', 'For example, the ridge cutting elements 320-4 include cutting elements that are not part of the bottomhole composite cutting profile otherwise established by the cutting elements of the set 324-1.', 'In other words, the ridge cutting elements 320-4 that are recessed from the composite cutting profile (such as shown in FIG. 5) are to be understood to not be part of the set 324-1.', 'In other examples, the ridge cutting elements 320-4 may include cutting elements that are at least 15% recessed from the composite cutting profile relative to the extension of the immediately adjacent cutting element.', '; FIG.', '4 illustrates an example of a composite cutting profile 434 of a conventional roller cone bit with conventional roller cones 412.', 'The composite cutting profile 434 overlays the position of the cutting elements 420-1, 420-2 as the roller cones 412 rotate with the rotation of the roller cone bit.', 'The composite cutting profile 434 therefore may illustrate the outline of the cutting elements 420-1, 420-2 positioned on the outer surface 430 of the roller cones 412 as experienced by the formation during rotation of the bit.; FIG.', '5 is a composite cutting profile 534 of roller cones 512 of a roller cone bit, according to some embodiments of the present disclosure.', 'In some embodiments, the composite cutting profile 534 may include a plurality of arrays that each include one or more sets 524-1, 524-2.', 'In some embodiment, at least the first sets 524-1 of the first array may include a variety of different cutting elements 520-1, 520-2, 520-3.', 'For example, the first sets 524-1 may include a first cutting element 520-1 with a first diameter 536-1 and a second cutting element 520-2 with a second diameter 536-2.', 'In some embodiments, the first diameter 536-1 may be greater than the second diameter 536-2.', 'In other embodiments, the first diameter 536-1 may be less than the second diameter 536-2.; FIG.', '5 illustrates a first array 524-1 with a plurality of cutting elements.', 'In some embodiments, the cutting elements of a set of an array may have different cutting element geometry types.', 'For example, the cutting elements may be non-planar cutting elements (i.e., apexed cutting elements).', 'Apexed cutting element geometry types may include chisel cutting elements, such as cutting elements with an elongated axe-like leading edge or cutting tip; conical cutting elements, such as rotationally symmetrical cutting elements with at least a portion of the cutting element profile being angled and linear towards a center apex (such as the cutting elements 520-1, 520-2, 520-3 illustrated in FIG. 5); or curved cutting elements, such as a rotationally symmetrical “bullet” cutting element with a continuously curved working surface toward the center apex.; FIG.', '6-2 illustrates another composite cutting profile 644 of sets 624 comprising an array, according to some embodiments of the present disclosure.', 'In some embodiments, the cutting elements at either end of the sets 624 of the array may have a different property and/or dimension that the cutting elements positioned between the ends of the sets 624.', 'For example, the first cutting element 624-1 may be located in a first position of the set 624 nearest the cone axis and furthest from a gauge surface 640.', 'At an opposite end of the set 624-1, the last position of the set 624 may have a cutting element with at least one property in common with the first cutting element and that is different from the one or more cutting elements positioned between.', 'For example, the third cutting element 620-3 may be located in the last position and the second cutting element 620-2 may be positioned between the first cutting element 620-1 in the first position and the third cutting element 620-3 in the last position.; FIG. 7 is a schematic representation of the roller cone 512 removing material from a formation 501, according to embodiments of the present disclosure.', 'In some embodiments, a roller cone 512 may incur less damage and/or increase a rate of penetration with a set with different cutting elements.', 'For example, cutting elements 520-1, 520-3 between the bottommost point 542 and gauge surface 540 of the roller cone 512 (i.e., in the staggered zone 546) may be different from one another to increase a rate of penetration of the first cutting element 520-1 at or near the bottommost point 542 while reducing damage to the third cutting element 520-3 at or near the gauge surface 540.; FIG.', '8 is a perspective view of another roller cone, according to embodiments of the present disclosure.', 'In some embodiments, a roller cone 712 may include a plurality of sets in an array.', 'For example, the roller cone 712 may include at least a first set 724-1 and a second set 724-2.', 'The first set 724-1 and second set 724-2 may be located at the same longitudinal position relative to the cone axis 716 and displaced around the cone axis 716.', 'In some embodiments, at least one of the cutting elements of the first set 724-1 may be longitudinally aligned (e.g., at the same longitudinal position relative to the cone axis 716) with a cutting element of the second set 724-2.', 'For example, a first cutting element 720-1 located at a leading end of the first set 724-1 may be positioned at the same longitudinal position along the cone axis 716 as a second cutting element 720-2 cutting element located at a leading end of the second set 724-2.', 'While the roller cone 712 rotates about the cone axis 716, the first cutting element 720-1 of the first set 724-1 and second cutting element 720-2 of the second set 724-2 may contact the same location in the composite cutting profile (similar to those described in relation to FIGS.', '5 and 6-1) of the roller cone 712.'] |
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US11125081 | Terminal modules for downhole formation testing tools | Oct 23, 2017 | Miroslav Slapal, Christopher Albert Babin, Daniel Palmer, Kai Hsu, Anthony Robert Holmes Goodwin, Julian Pop, Nathan Mathew Landsiedel, Adriaan Gisolf | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 7178591; February 20, 2007; Del Campo et al.; 7305306; December 4, 2007; Venkataramanan et al.; 7398159; July 8, 2008; Venkataramanan et al.; 7614294; November 10, 2009; Hegeman et al.; 7805988; October 5, 2010; Kasperski et al.; 9416657; August 16, 2016; Tao et al.; 9845673; December 19, 2017; Gisolf; 20090025926; January 29, 2009; Briquet; 20100307769; December 9, 2010; Briquet; 20120132419; May 31, 2012; Zazovsky; 20130293891; November 7, 2013; Zazovsky | Foreign Citations not found. | ['A method includes positioning a downhole acquisition tool in a wellbore in a geological formation.', 'The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore.', 'Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module.', 'Operating the pump module includes controlling a valve assembly to a second valve configuration that enables the fluid to flow into the downhole tool via the second flowline fluidly coupled to a second pump module, and selectively using a turnaround module or a crossover portion disposed between the first flowline and the second flowline to permit discharging the fluid from one flowline to the other flowline by actuating a valve associated with the turnaround module when the first pump module or the second pump module is not in use.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCES TO RELATED APPLICATIONS', 'This application claims priority to U.S. Provisional Patent Application No. 62/415,008, filed on Oct. 31, 2016, which is incorporated in its entirety by reference herein.', 'BACKGROUND\n \nThis disclosure relates to systems and methods to reduce the number of independent modules and other equipment (e.g., valves) used in the downhole acquisition tools.', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.', 'A variety of systems are used in geophysical exploration and production operations to determine chemical and physical parameters of materials drawn in through a wellbore.', 'Fluid analyses typically include, but are not limited to, the determination of oil, water and gas constituents of the fluid.', 'It may be desirable to obtain multiple fluid analyses or samples as a function of depth within the wellbore.', 'Operationally, it may be desirable to obtain these multiple analyses or samples during a single trip of the tool within the wellbore.', 'Formation testing tools can be conveyed through the wellbore by variety of means including, but not limited to, a drill string, a permanent completion string, or a string of coiled tubing.', 'Formation testing tools may be designed for wireline usage or as part of a drill string.', 'Conventional formation testing tools may utilize several modules and may utilize several flow control devices (e.g., valves), thereby increasing the overall size of the tool.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the subject matter described herein, nor is it intended to be used as an aid in limiting the scope of the subject matter described herein.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'In one example, a method includes positioning a downhole acquisition tool in a wellbore in a geological formation.', 'The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore.', 'Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module.', 'Operating the pump module includes controlling a valve assembly to a second valve configuration that enables the fluid to flow into the downhole tool via the second flowline fluidly coupled to a second pump module, and selectively using a turnaround module or a crossover portion disposed between the first flowline and the second flowline to permit discharging the fluid from one flowline to the other flowline by actuating a valve associated with the turnaround module when the first pump module or the second pump module is not in use.', 'In another example, a system includes a downhole acquisition tool housing configured to receive a fluid that enters the downhole acquisition tool from a first flowline, a second flowline, or both.', 'A flow control assembly includes a turnaround module, a first flowline fluidly coupled to a first pump module, a second flowline fluidly coupled to a second pump module, and a crossover portion disposed between the first pump module and the second pump module, where the flow control assembly permits discharging the fluid from the first flowline to the second flowline, where the flow control system includes one or more tangible, non-transitory, machine-readable media comprising instructions.', 'The instructions control a valve assembly of a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline toward a first pump module, control a valve assembly of a second valve configuration that enables the fluid to flow into the downhole tool via the second flowline toward a second pump module, and selectively use the turnaround module or the crossover portion to direct the fluid flow between the first flowline and the second flowline by actuating a valve associated with the turnaround module when the first pump module or the second pump module is not in use.', 'In another example, a system includes a downhole acquisition tool housing configured to receive a fluid that enters the downhole acquisition tool from a first flowline, a second flowline, or both and a turnaround module.', 'The system includes a first flowline fluidly coupled to a first pump module, and a second flowline fluidly coupled to the first pump module, where the turnaround module permits discharging the fluid from the first flowline to the second flowline.', 'The system includes one or more tangible, non-transitory, machine-readable media comprising instructions to control a valve assembly of a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline toward the first pump module.', 'The instructions control a valve assembly of a second valve configuration that enables the fluid to flow into the downhole tool via the second flowline toward the first pump module.', 'The instructions selectively use the turnaround module to direct the fluid flow along the first or the second flowlines to inflate a packer assembly by actuating a valve associated with the turnaround module.', 'Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:\n \nFIG.', '1\n is a schematic diagram of a logging-while-drilling wellsite system that may be used to identify properties of formation fluids in the wellbore, in accordance with an embodiment;\n \nFIG.', '2\n is a schematic diagram of another example of a wireline wellsite system that may be used to identify properties of the formation fluids in the wellbore, in accordance with an embodiment;\n \nFIG.', '3\n illustrates a flowchart of a method for operating the downhole acquisition tool using a bottom pump module and a top pump module, in accordance with an embodiment;\n \nFIG.', '4\n is a schematic diagram of another example of a wireline wellsite system illustrating a sample line and a guard line used to draw in formation fluids in the wellbore, where a turnaround module is fluidly coupled to the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '5\n illustrates a flowchart of method for operating the downhole acquisition tool using a top pump module, in accordance with an embodiment;\n \nFIG.', '6\n is a schematic diagram of another example of a wireline wellsite system illustrating the sample line and the guard line used to draw in formation fluids in the wellbore, where the top pump module is used to direct fluid through the sample line and the guard line using a turnaround module, in accordance with an embodiment;\n \nFIG.', '7\n illustrates a flowchart of a method for operating the downhole acquisition tool using the bottom pump module and the top pump module, in accordance with an embodiment;\n \nFIG.', '8\n is a schematic diagram of another example of a wireline wellsite system illustrating the sample line and the guard line used to draw in formation fluids in the wellbore, where the bottom pump module is used to direct fluid through the sample line and the guard line using the turnaround module, in accordance with an embodiment;\n \nFIG.', '9\n illustrates a flowchart of a method for operating the downhole acquisition tool using the bottom pump module, in accordance with an embodiment\n \nFIG.', '10\n is a schematic diagram of another example of a wireline wellsite system illustrating the sample line and the guard line used to draw in formation fluids in the wellbore, where the bottom pump module is used to direct fluid through the sample line and the guard line using the turnaround module, in accordance with an embodiment;\n \nFIG.', '11\n illustrates a flowchart of a method for using the single pump module and a plurality of packers used to draw in formation fluids in the wellbore, in accordance with an embodiment;\n \nFIG.', '12\n is a schematic diagram of another example of a wireline wellsite system illustrating the plurality of packers used to draw in formation fluids in the wellbore through the sample line and the guard line, where the single pump module is used to direct fluid through the sample line and the guard line using the turnaround modules, in accordance with an embodiment;\n \nFIG.', '13\n illustrates a flowchart of a method for collecting a plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '14\n is a schematic diagram of another example of a wireline wellsite system illustrating the plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '15\n illustrates a flowchart of a method for collecting a plurality of larger fluid slugs within the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '16\n is a schematic diagram of another example of a wireline wellsite system illustrating the plurality of larger fluid slugs within the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '17\n illustrates a flowchart of a method for mixing a plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '18\n is a schematic diagram of another example of a wireline wellsite system illustrating the mixed plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '19\n illustrates a flowchart of a method for performing a phase separation within the sample line and the guard line, in accordance with an embodiment;\n \nFIG.', '20\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;\n \nFIG.', '21\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;\n \nFIG.', '22\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;\n \nFIG.', '23\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;\n \nFIG.', '24\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;\n \nFIG.', '25\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;\n \nFIG.', '26\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system; and\n \nFIG.', '27\n illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions may be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would still be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'The present disclosure relates to systems and methods of a formation evaluation system including a downhole tool positionable in a wellbore penetrating a subterranean formation having a formation fluid therein.', 'The system is provided with a first and a second inlet for receiving the fluids from the formation, a first and a second evaluation flowline (e.g., the sample line and the guard line) fluidly coupled to at the first and the second inlets for passage of the formation fluid into the downhole tool, and at least one turnaround module coupled to at least one first or the second evaluation flowlines for passage of the formation fluid into the downhole tool.', 'In another aspect, the disclosure relates to a method of drawing fluid into a downhole tool positionable in a wellbore penetrating a formation having a formation fluid therein.', 'The method involves establishing fluid communication between a first and a second inlet and the formation, establishing fluid communication between a first and a second inlet and a first and a second evaluation flowline, pumping fluid into the first evaluation flowline via a first pump module, pumping fluid into the second evaluation flowline via a second pump module, and using the at least one turnaround module for routing fluid in the first evaluation flowline with the second pump module or routing fluid in the second evaluation flowline with the first pump module.', 'The disclosed embodiments may reduce the number of independent modules and other equipment (e.g., valves) used in the downhole acquisition tool when compared to conventional tools.\n \nFIGS.', '1 and 2\n depict examples of wellsite systems that may employ such fluid analysis systems and methods.', 'In \nFIG.', '1\n, a rig \n10\n suspends a downhole acquisition tool \n12\n into a wellbore \n14\n via a drill string \n16\n.', 'A drill bit \n18\n drills into a geological formation \n20\n to form the wellbore \n14\n.', 'The drill string \n16\n is rotated by a rotary table \n24\n, which engages a kelly \n26\n at the upper end of the drill string \n16\n.', 'The drill string \n16\n is suspended from a hook \n28\n, attached to a traveling block, through the kelly \n26\n and a rotary swivel \n30\n that permits rotation of the drill string \n16\n relative to the hook \n28\n.', 'The rig \n10\n is depicted as a land-based platform and derrick assembly used to form the wellbore \n14\n by rotary drilling.', 'However, in other embodiments, the rig \n10\n may be an offshore platform.', 'Drilling fluid referred to as drilling mud \n32\n, is stored in a pit \n34\n formed at the wellsite.', 'A pump \n36\n delivers the drilling mud \n32\n to the interior of the drill string \n16\n via a port in the swivel \n30\n, inducing the drilling mud \n32\n to flow downwardly through the drill string \n16\n as indicated by a directional arrow \n38\n.', 'The drilling mud \n32\n exits the drill string \n16\n via ports in the drill bit \n18\n, and then circulates upwardly through the region between the outside of the drill string \n16\n and the wall of the wellbore \n14\n, called the annulus, as indicated by directional arrows \n40\n.', 'The drilling mud \n32\n lubricates the drill bit \n18\n and carries formation cuttings up to the surface as it is returned to the pit \n34\n for recirculation.', 'The downhole acquisition tool \n12\n, sometimes referred to as a component of a bottom hole assembly (“BHA”), may be positioned near the drill bit \n18\n and may include various components with capabilities such as measuring, processing, and storing information, as well as communicating with the surface.', 'Additionally or alternatively, the downhole acquisition tool \n12\n may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or other suitable types of conveyance.', 'The downhole acquisition tool \n12\n may further include a fluid communication module \n46\n, a sampling module \n48\n, and a sample bottle module.', 'In a logging-while-drilling (LWD) configuration, the modules may be housed in a drill collar for performing various formation evaluation functions, such as pressure testing and fluid sampling, among others, and collecting representative samples of native formation fluid \n50\n.', 'As shown in \nFIG.', '1\n, the fluid communication module \n46\n is positioned adjacent the sampling module \n48\n; however the position of the fluid communication module \n46\n, as well as other modules, may vary in other embodiments.', 'Additional devices, such as pumps, gauges, sensors, monitors or other devices usable in downhole sampling and/or testing also may be provided.', 'The additional devices may be incorporated into modules \n46\n or \n48\n or disposed within separate modules.', 'The downhole acquisition tool \n12\n may evaluate fluid properties of an obtained fluid \n52\n.', 'Generally, when the obtained fluid \n52\n is initially taken in by the downhole acquisition tool \n12\n, the obtained fluid \n52\n may include some drilling mud \n32\n, some mud filtrate \n54\n that has entered the formation \n20\n, and the native formation fluid \n50\n.', 'The downhole acquisition tool \n12\n may store a sample of the native formation fluid \n50\n or perform a variety of in-situ testing to identify properties of the native formation fluid \n50\n.', 'The fluid communication module \n46\n includes a probe \n60\n, which may be positioned in a rib \n62\n.', 'The probe \n60\n includes one or more inlets for receiving the obtained fluid \n52\n and one or more flowlines (not shown) extending into the downhole tool \n12\n for passing fluids (e.g., the obtained fluid \n52\n) through the tool.', 'The probe \n60\n may include a radial focused probe or a probe with multiple inlets (e.g., a sampling probe and a guard probe) that may, for example, be used for focused sampling.', 'In these embodiments, the probe \n60\n may be connected to the sampling flowline, as well as to guard flowlines.', 'The probe \n60\n may be movable between extended and retracted positions for selectively engaging the wellbore wall \n58\n of the wellbore \n14\n and acquiring fluid samples from the geological formation \n20\n.', 'One or more setting pistons \n64\n may be provided to assist in positioning the fluid communication device against the wellbore wall \n58\n.', 'Sensors may collect and transmit data \n70\n from the measurement of the fluid properties and the composition of the obtained fluid \n52\n to a control and data acquisition system \n72\n at surface \n74\n, where the data \n70\n may be stored and processed in a data processing system \n76\n of the control and data acquisition system \n72\n.', 'The data processing system \n76\n may include a processor \n78\n, memory \n80\n, storage \n82\n, and/or display \n84\n.', 'The memory \n80\n may include one or more tangible, non-transitory, machine readable media collectively storing one or more sets of instructions for operating the downhole acquisition tool \n12\n and estimating a mobility of the obtained fluid \n52\n.', 'The memory \n80\n may store algorithms associated with properties of the native formation fluid \n50\n (e.g., uncontaminated formation fluid) to compare to properties of the obtained fluid \n52\n.', 'The data processing system \n76\n may use the fluid property and composition information of the data \n70\n to estimate a mobility of the obtained fluid \n52\n in the guard line, the sample line, or both.', 'These estimates may be used to adjust operation of the downhole tool or other equipment.', 'To process the data \n70\n, the processor \n78\n may execute instructions stored in the memory \n80\n and/or storage \n82\n.', 'It may be appreciated that the processing may occur downhole in described embodiments.', 'The instructions may cause the processor \n78\n to estimate fluid and compositional parameters of the native formation fluid \n50\n of the obtained fluid \n52\n, and control flow rates of the sample and guard probes, and so forth.', 'As such, the memory \n80\n and/or storage \n82\n of the data processing system \n76\n may be any suitable article of manufacture that can store the instructions.', 'By way of example, the memory \n80\n and/or the storage \n82\n may be ROM memory, random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive.', 'The display \n84\n may be any suitable electronic display that can display information (e.g., logs, tables, cross-plots, etc.) relating to properties of the well as measured by the downhole acquisition tool \n12\n.', 'It should be appreciated that, although the data processing system \n76\n is shown by way of example as being located at the surface \n74\n, the data processing system \n76\n may be located in the downhole acquisition tool \n12\n.', 'In such embodiments, some of the data \n70\n may be processed and stored downhole (e.g., within the wellbore \n14\n), while some of the data \n70\n may be sent to the surface \n74\n (e.g., in real time or near real time).', 'FIG.', '2\n depicts an example of a wireline downhole tool \n100\n that may employ the systems and methods of this disclosure.', 'The downhole tool \n100\n is suspended in the wellbore \n14\n from the lower end of a multi-conductor cable \n104\n that is spooled on a winch at the surface \n74\n.', 'Like the downhole acquisition tool \n12\n, the wireline downhole tool \n100\n may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or any other suitable conveyance.', 'The cable \n104\n is communicatively coupled to an electronics and processing system \n106\n.', 'The downhole tool \n100\n includes an elongated body \n108\n that houses modules \n110\n, \n112\n, \n114\n, \n122\n, and \n124\n, that provide various functionalities including fluid sampling, sample bottle filling, fluid testing, operational control, and communication, among others.', 'For example, the modules \n110\n and \n112\n may provide additional functionality such as fluid analysis, resistivity measurements, operational control, communications, coring, and/or imaging, among others.', 'As shown in \nFIG.', '2\n, the module \n114\n is a fluid communication module \n114\n that has a selectively extendable probe \n116\n and backup pistons \n118\n that are arranged on opposite sides of the elongated body \n108\n.', 'The extendable probe \n116\n selectively seals off or isolates selected portions of the wall \n58\n of the wellbore \n14\n to fluidly couple to the adjacent geological formation \n20\n and/or to draw fluid samples from the geological formation \n20\n.', 'The probe \n116\n may include a single inlet or multiple inlets designed for guarded or focused sampling.', 'The native formation fluid \n50\n may be expelled to the wellbore \n14\n through a port in the body \n108\n or the obtained fluid \n52\n, including the native formation fluid \n50\n, may be sent to one or more fluid sampling modules \n122\n and \n124\n.', 'The fluid sampling modules \n122\n and \n124\n may include sample chambers that store the obtained fluid \n52\n.', 'In the illustrated example, the electronics and processing system \n106\n and/or a downhole control system are configured to control the extendable probe assembly \n116\n and/or the drawing of a fluid sample from the geological formation \n20\n to enable analysis of the obtained fluid \n52\n.', 'Using these or any other suitable downhole acquisition tools, samples of formation fluids \n50\n may be obtained at the guard line, the sample line, or both.', 'For example, as shown by a flowchart of \nFIG.', '3\n, a method \n130\n for performing a steady state operation using the bottom pump module and the top pump module, in accordance with an embodiment.', 'The method \n130\n includes drawing in (block \n132\n) the sample line fluid and the guard line fluid.', 'The method \n130\n includes cleaning (block \n134\n) a sample of fluid (e.g., formation fluid) from the sample line.', 'After the sample of fluid is cleaned to a suitable level, the method \n130\n includes capturing (block \n136\n) a first sample of fluid in the sample bottles.', 'The method \n130\n may include allowing an amount of time to pass before collecting a second sample of fluid.', 'As such, the method \n130\n may include pumping (block \n138\n) the sample line fluid and the guard line fluid during steady state operation of the downhole acquisition tool.', 'In some embodiments, the method \n130\n may include continuously pumping the sample line fluid and the guard line fluid.', 'The method \n130\n may then include capturing (block \n140\n) a second sample using the sample bottles.', 'The second sample may be captured at a different location from the first sample or at the same location as the first sample.', 'FIG.', '4\n is a schematic diagram of another example of a wireline wellsite system \n142\n illustrating a sample line \n144\n and a guard line \n146\n used to draw in formation fluids in the wellbore, where a turnaround module \n148\n is fluidly coupled to the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'The wireline wellsite system \n142\n may flow fluid (e.g., through the sample line \n144\n and/or through the guard line \n146\n) during steady state operation of the downhole acquisition tool \n12\n.', 'In the illustrated embodiment, the sample line fluid is drawn in through the sample line \n144\n.', 'The sample line \n144\n includes an isolation valve \n154\n to control the flow of the sample line fluid into the sample line \n144\n.', 'When the isolation valve \n154\n is open, the downhole acquisition tool \n12\n uses a bottom pump module \n150\n associated with the sample line \n144\n to draw in fluid with the bottom pump module \n150\n.', 'The flow path of the sample line fluid \n144\n is illustrated by arrows \n151\n.', 'A comingle valve \n158\n may be used when the isolation valve \n154\n is not being used.', 'The guard line fluid is drawn in through the guard line \n146\n.', 'The guard line \n146\n includes an isolation valve \n156\n to control the flow of the guard line fluid into the guard line \n146\n.', 'When the isolation valve \n156\n is open, the downhole acquisition tool \n12\n uses a top pump module \n152\n associated with the guard line \n146\n to draw in fluid with the top pump module \n152\n.', 'The flow path of the guard line fluid \n146\n is illustrated by arrows \n153\n.', 'A flow of the downhole fluid and/or water generated during sample capture is shown by arrows \n155\n.', 'The sample line fluid and the guard line fluid follow the flow paths as shown by the sample line \n144\n and the guard line \n146\n, respectively.', 'As illustrated, the fluid may flow through a crossover portion \n157\n.', 'When the turnaround module \n148\n is open (e.g., in a first position), the sample line fluid and the guard line fluid may pass through the turnaround module.', 'When the turnaround module \n148\n is open (e.g., when the valve \n160\n is opened and the port associate with the turnaround module \n148\n is open), the sample line fluid and the guard line fluid flow out of the downhole acquisition tool \n12\n and into a wellbore annulus.', 'The turnaround module \n148\n includes a valve \n160\n that may be open when the turnaround module \n148\n is open.', 'When the valve \n160\n is closed (e.g., in a second position), the turnaround module \n148\n may be used to turn the flow of the sample line \n144\n and/or the guard line \n146\n so that the sample line fluid, the guard line fluid, or both may be directed along a different flowline as explained in further detail below.', 'One or more sensors \n159\n may be disposed along the flowlines \n144\n, \n146\n or associated the flow control valves (e.g., the valve \n160\n, the valve \n184\n, the comingle valve \n158\n, the isolation valve \n154\n, \n156\n, etc.)', 'to output data that may be used to control the actuation of the valves and the fluid flow.', 'It may be appreciated that exit ports \n162\n, \n164\n may be associated with the flowlines.', 'In the illustrated embodiment, the exit ports \n162\n, \n164\n are associated with the guard line \n146\n and the sample line \n144\n, respectively.', 'The exit ports \n162\n, \n164\n may be selectively opened and closed to may be used to pump fluid (e.g., sample line fluid, guard line fluid) out of the flowlines.', 'The exit ports \n162\n, \n164\n may be used to direct the flow of the fluid in varying directions, depending on the configuration of hardware associated with the exit ports \n162\n, \n164\n.', 'In some embodiments, one or more of the exit ports \n162\n, \n164\n may utilize a check valve to control the fluid flow.', 'The exit ports \n162\n, \n164\n may be used when the both the bottom pump module \n150\n and the top pump module \n152\n are used to draw in the fluid, or when one of the bottom pump module \n150\n or the top pump module \n152\n are used as explained in further detail below.', 'FIG.', '5\n illustrates a flowchart of a method \n170\n of the operating the downhole acquisition tool \n12\n using the top pump module \n152\n, in accordance with an embodiment.', 'The method \n170\n may be used when the bottom pump module \n150\n is unable to be used (e.g., to maintenance, equipment failure, etc.) or when it is not desirable to use the bottom pump module \n150\n.', 'The method \n170\n includes drawing in (block \n172\n) the sample line fluid and the guard line fluid.', 'While the fluid is drawn in, the exit ports \n162\n, \n164\n may be closed and the fluid may flow out of the downhole acquisition tool \n12\n when the valve \n160\n is open.', 'The method \n170\n includes cleaning the fluid or capturing a sample (block \n174\n).', 'The method \n170\n includes closing (block \n176\n) a bypass valve \n184\n of the bottom pump module \n150\n.', 'The method \n170\n includes opening (block \n178\n) the exit port \n162\n so that the fluid exits through the exit port.', 'The method \n170\n includes closing (block \n180\n) a wellbore port associated with the turnaround module \n148\n in the turnaround module (e.g. by closing a valve \n160\n associated with the turnaround module \n148\n) to turn the fluid flow.', 'The method \n170\n may include reversing (block \n182\n) the pumping direction of the top pump module \n152\n.', 'The method includes capturing samples (block \n183\n) in a sample chamber that is in fluid communication with the flowline \n146\n.', 'The sample may be captured with the pump that is connected to flowline \n144\n (e.g., when the fluid is pumped by the top pump module \n152\n through flowline \n144\n and is U-turned into flowline \n146\n).', 'FIG.', '6\n is a schematic diagram of another example of a wireline wellsite system \n142\n illustrating the sample line \n144\n and the guard line \n146\n used to draw in formation fluids in the wellbore, where the top pump module \n152\n is used to direct fluid through the sample line \n144\n and the guard line \n146\n using a turnaround module \n148\n, in accordance with an embodiment.', 'In the illustrated embodiment, the sample line fluid is drawn in through the sample line \n144\n.', 'The sample line \n144\n uses the isolation valve \n154\n to control the flow of the sample line fluid into the sample line \n144\n.', 'In the illustrated embodiment, the downhole acquisition tool \n12\n bypasses the bottom pump module \n150\n associated with the sample line \n144\n.', 'The bypass valve \n184\n of the bottom pump module is closed and the exit port \n162\n is opened.', 'The fluid follows the flow path indicated by the arrows \n186\n shown.', 'As illustrated, the fluid is turned via the turnaround module \n148\n at the top of the downhole acquisition tool \n12\n.', 'FIG.', '7\n illustrates a flowchart of a method of operating the downhole acquisition tool using a bottom pump module and a top pump module, in accordance with an embodiment.', 'A method \n230\n for performing a steady state operation using a bottom pump module and a top pump module, in accordance with an embodiment.', 'The method \n230\n may be similar to the method \n130\n described above with reference to \nFIG.', '3\n.', 'In the method \n230\n, the flow of the downhole fluid and/or water that the bottom pump module \n150\n generates during sample capture may be different compared to the method \n130\n.', 'The method \n230\n includes drawing in (block \n232\n) the sample line fluid and the guard line fluid.', 'The method \n230\n includes cleaning (block \n234\n) a sample of fluid (e.g., formation fluid) from the sample line and the guard line.', 'After the sample of fluid is cleaned to a suitable level, the method \n230\n includes capturing (block \n236\n) a first sample of fluid in the sample bottles.', 'The method \n230\n may include allowing an amount of time to pass before collecting a second sample of fluid.', 'As such, the method \n230\n may include pumping (block \n238\n) the sample line fluid and the guard line fluid during steady state operation of the downhole acquisition tool.', 'The method \n230\n may then include capturing (block \n240\n) a second sample from the sample bottles.', 'The second sample may be captured at a different location from the first sample or at the same location as the first sample.', 'FIG.', '8\n is a schematic diagram of another example of a wireline wellsite system \n142\n illustrating the sample line \n144\n and the guard line \n146\n used to draw in formation fluids in the wellbore, where the turnaround module \n148\n is fluidly coupled to the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'As described above, the flow of the downhole fluid and/or water that the bottom pump module \n150\n generates during sample capture may be different compared to the embodiment illustrated in \nFIG.', '4\n.', 'The flow of the downhole fluid and/or water generated during sample capture is shown by arrows \n250\n.', 'As described above, the sample line fluid is drawn in through the sample line \n144\n.', 'The sample line \n144\n includes an isolation valve \n154\n to control the flow of the sample line fluid into the sample line \n144\n.', 'In the illustrated embodiment, the downhole acquisition tool \n12\n uses the bottom pump module \n150\n associated with the sample line \n144\n to draw in fluid with the bottom pump module \n150\n.', 'A comingle valve \n158\n may be used when the isolation valve \n154\n is not being used (e.g., when the isolation valve \n154\n is closed).', 'The guard line fluid is drawn in through the guard line \n146\n.', 'The guard line \n146\n includes an isolation valve \n156\n to control the flow of the guard line fluid into the guard line \n146\n.', 'When the isolation valve \n156\n is open, the downhole acquisition tool \n12\n uses the top pump module \n152\n associated with the guard line \n146\n to draw in fluid with the top pump module \n152\n.', 'As described above, the one or more sensors \n159\n may be disposed along the flowlines \n144\n, \n146\n or associated the flow control valves (e.g., the valve \n160\n, the valve \n184\n, the comingle valve \n158\n, the isolation valve \n154\n, \n156\n, etc.)', 'to output data that may be used to control the actuation of the valves and the fluid flow.', 'It may be appreciated that both the bottom pump module \n150\n and the top pump module \n152\n are used to draw in the fluid, or when one of the bottom pump module \n150\n or the top pump module \n152\n are used as explained in further detail below.', 'FIG.', '9\n illustrates a flowchart of a method \n280\n of operating the downhole acquisition tool \n12\n using the bottom pump module \n150\n, in accordance with an embodiment.', 'The method \n280\n may be used when the top pump module \n152\n is not able to be used or it is not desired to use the top pump module.', 'The method \n280\n includes drawing in (block \n282\n) the sample line fluid and the guard line fluid.', 'The method \n280\n includes cleaning sample line fluid and/or capture the sample (block \n284\n).', 'The method \n280\n includes closing (block \n286\n) the valve \n160\n and the port associated with the top turnaround module \n148\n.', 'The method \n280\n includes opening (block \n288\n) the exit port \n164\n and opening the bypass valve associated with flowline in the top pump module \n152\n.', 'The method \n280\n may include reversing (block \n290\n) the direction of the bottom pump module \n150\n.', 'The method \n280\n includes capturing samples (block \n292\n) in a sample chamber that is in fluid communication with the flowline \n144\n.', 'The sample may be captured with the pump that is connected to flowline \n146\n (e.g., when the fluid pumped by the bottom pump module \n150\n through flowline \n146\n and is U-turned into flowline \n144\n).', 'FIG.', '10\n is a schematic diagram of another example of a wireline wellsite system \n142\n illustrating the sample line \n144\n and the guard line \n146\n used to draw in formation fluids in the wellbore, where the bottom pump module \n150\n is used to direct fluid through the sample line \n144\n and the guard line \n146\n using the turnaround modules \n148\n, in accordance with an embodiment.', 'In the illustrated embodiment, the sample line fluid is drawn in through the sample line \n144\n.', 'The guard line \n146\n uses the isolation valve \n158\n to control the flow of the guard line fluid into the guard line \n146\n.', 'As described above, the fluid may flow through the crossover portion \n157\n.', 'In the illustrated embodiment, the downhole acquisition tool \n12\n bypasses the top pump module \n152\n associated with the guard line \n146\n.', 'The turnaround modules \n148\n are opened and the exit port \n162\n is closed.', 'The flowline to top pump module \n152\n is closed.', 'The direction of the top pump module \n152\n is reversed.', 'The guard line fluid follows the flow path indicated by the arrows \n300\n shown.\n \nFIG.', '11\n illustrates a flowchart of a method \n302\n of using a single pump module and a plurality of packers used to draw in formation fluids in the wellbore, in accordance with an embodiment.', 'The method \n302\n includes closing (block \n304\n) a flowline in pump module.', 'The method \n302\n includes closing (block \n306\n)', 'the wellbore port and opening the turnaround module in the bottom terminal module.', 'The method \n302\n includes opening (block \n308\n) the wellbore port and closing the turnaround in the top terminal module.', 'When the packers are filled with fluid from a volume chamber \n326\n, the valve \n160\n associated with the turnaround module \n148\n may be closed.', 'When the packers are filled with fluid from the borehole, the valve \n160\n associated with the turnaround module \n148\n may be opened.', 'It may be appreciated that the valves associated with the sample chamber are closed when the packers are filled.', 'The method \n302\n includes reversing (block \n310\n) the direction of the pump module.', 'The method \n302\n includes filling (block \n312\n) the packers or inflating the packers with clean fluid.', 'The method \n302\n includes cleaning (block \n314\n) the sample line fluid and/or capturing the sample.\n \nFIG.', '12\n is a schematic diagram of another example of a wireline wellsite system illustrating a plurality of packers \n320\n used to draw in formation fluids in the wellbore through the sample line \n144\n and the guard line \n146\n, where a single pump module \n322\n is used to direct fluid through the sample line \n144\n and the guard line \n146\n using the turnaround modules \n148\n, in accordance with an embodiment.', 'Instead of opening the exit port and closing the turnaround module \n148\n in the top terminal module, the inflation fluid may be drawn from the sample chamber \n326\n.', 'The inflation of the packers \n320\n may be performed with the single pump module \n322\n as shown by arrows \n324\n.', 'As described above, the one or more sensors \n159\n may be disposed along the flowlines \n144\n, \n146\n or associated the flow control valves (e.g., the valve \n160\n, the valve \n184\n, the comingle valve \n158\n, the isolation valve \n154\n, \n156\n, etc.)', 'to output data that may be used to control the actuation of the valves and the fluid flow.\n \nFIG.', '13\n illustrates a flowchart of a method \n330\n for collecting a plurality of fluid slugs within the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'The method \n330\n includes opening (block \n332\n) the valve \n160\n associated with the turnaround flowline of the top termination module, opening the exit port, and starting to pump the fluid so that the fluid is pumped out of the tool \n12\n.', 'The method \n330\n includes closing (block \n334\n) the valve \n160\n associated with the turnaround flowline of the top termination module and closing the exit port to turn the fluid.', 'The method \n330\n includes capturing (block \n336\n) a first fluid slug in the flowline \n146\n between the check valves in the top termination module and the top pump module \n152\n.', 'The method \n330\n includes continuing (block \n338\n)', 'the pumping operations using the top pump module \n152\n, flowing fluid through the flowline \n144\n, and out of the turnaround module \n148\n through the open valve \n160\n.', 'The method \n330\n includes capturing (block \n340\n) a second fluid slug in flowline \n144\n between the check valves in the top termination module and the top pump module \n152\n.', 'The method \n330\n includes opening (block \n342\n) the turnaround flowline of the top termination module, closing the exit port in the top module, and closing the isolation valves to create a loop across the modules of the downhole acquisition tool.\n \nFIG.', '14\n is a schematic diagram of another example of a wireline wellsite system \n142\n illustrating the plurality of fluid slugs \n350\n within the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'A first fluid slug \n354\n is formed in the flowline \n146\n between the check valves in the top termination module and the lower pump module \n150\n as shown.', 'A second fluid slug \n352\n is formed between the top termination module (e.g., a check valve associated with the top termination module) and the top pump module \n152\n, as shown.', 'As shown, the downhole fluid originates from the sample inlet.', 'Either of the pump modules or both may be used to circulate one or both of the fluid slugs \n352\n, \n354\n between the fluid analyzers.', 'Fluid analysis of the fluid slugs \n352\n, \n354\n may be used to measure fluid properties of the slugs.\n \nFIG.', '15\n illustrates a flowchart of a method \n360\n for collecting a plurality of larger fluid slugs within the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'The method \n360\n includes opening (block \n362\n) the valve \n160\n associated with the turnaround flowline of the top termination module, opening the exit port, and starting to pump the fluid so that the fluid is pumped out of the tool \n12\n.', 'The method \n360\n includes closing (block \n364\n)', 'the valve \n160\n associated with the turnaround flowline of the top termination module and closing the exit port to turn the fluid.', 'The method \n360\n includes capturing (block \n366\n) a first fluid slug between the top termination module and the bottom termination module (e.g., between check valves associated with the top termination module and the bottom termination module).', 'The method \n360\n includes continuing (block \n368\n) pumping operations using the top pump module \n152\n.', 'The method \n360\n includes capturing (block \n370\n) a second fluid slug between check valves in the top termination module and the bottom pump module.\n \nFIG.', '16\n is a schematic diagram of another example of a wireline wellsite system \n142\n illustrating the plurality of larger fluid slugs \n350\n within the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'A first fluid slug \n356\n is formed between the check valves in the top termination module and the top pump module \n152\n as shown.', 'A second fluid slug \n358\n is formed between the check valves in the top termination module and the bottom pump module as shown.', 'Arrows illustrate the fluid flow from the sample flowline and may be used to clean the flowline loop \n356\n.', 'Arrows show the flow path of the second fluid slug \n358\n.', 'Either of the pump modules or both may be used to circulate one or both of the fluid slugs \n352\n, \n354\n between the fluid analyzers.', 'Fluid analysis of the fluid slugs \n356\n, \n358\n may be used to measure fluid properties of the slugs.\n \nFIG.', '17\n illustrates a flowchart of a method \n380\n for mixing a plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment.', 'The method \n380\n includes bypassing (block \n382\n)', 'the bottom pump module \n150\n that contains the same fluid as the second slug.', 'The method \n380\n include driving (block \n384\n) the top pump module \n152\n to reverse circulate the first fluid slug.', 'The method \n380\n includes driving (block \n386\n) the bottom pump module \n150\n to inject the second slug into the flow loop.', 'It may be appreciated that the pump modules may be run at different speeds relative to one another to facilitate mixing of the fluids.', 'The method \n380\n includes mixing (block \n388\n) the first and second fluid slugs above the bypass valve of the bottom pump module \n150\n.', 'The method \n380\n includes flowing (block \n390\n) the mixture through the bypass valve of the bottom pump module \n150\n and splitting the flow between the flow loop and the previously empty chamber of the bottom pump module \n150\n.', 'The method \n380\n includes closing (block \n392\n) the bypass valve of the bottom pump module \n150\n, bypassing the top pump module \n152\n, and reversing the stroke of the bottom pump module.', 'Mixing the fluid slugs may be useful to analyze the mixed fluids by directing the mixed fluid slug to a fluid analyzer, study fluid compatibility, perform chemical experiments, and so forth.', 'FIG.', '18\n is a schematic diagram of another example of a wireline wellsite system \n142\n illustrating the mixed plurality of fluid slugs \n400\n, \n402\n within the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'The first fluid slug \n400\n is circulated by the top pump module \n150\n and the second fluid slug \n402\n is driven to inject the second slug into the flow loop as shown by the arrows.', 'FIG.', '19\n illustrates a flowchart of a method \n410\n for performing a phase separation within the sample line \n144\n and the guard line \n146\n, in accordance with an embodiment.', 'The method \n410\n includes opening (block \n412\n) the exit port of the top pump module \n152\n.', 'The method \n410\n includes driving (block \n414\n) the pump in the same module.', 'The method \n410\n includes depressurizing (block \n416\n) the upper part of the flow loop to promote phase separation of the fluid.', 'It may be appreciated either of the pump modules may be used to circulated the separated phases to fluid analyzers.', 'When the method \n410\n is combined with the control, other benefits may be seen, such as determining the phase border at the temperature of the flowline fluid.', 'It may be appreciated that any of the above referenced systems and methods for operating the wireline well site system \n142\n, drawing in fluids through the sample line \n144\n and/or the guard line \n146\n may be accomplished in part by using a plurality of flow routing plug modules \n450\n.', 'Each of the flow routing plug modules \n450\n may include one or more flow routing plugs \n452\n and a motor-driven valve \n454\n.', 'The flow routing modules \n450\n may enable the sample line \n144\n and the guard line \n146\n to be connected in any number of different ways, as explained in detail below with reference to \nFIGS.', '20-27\n.', 'It may be appreciated that the flow routing modules \n450\n may be used when the downhole acquisition tool \n12\n uses the turnaround module \n148\n or when the downhole acquisition tool \n12\n remains unconnected near the top of the tool \n12\n (e.g., near the surface).', 'The flow routing modules \n450\n reduce the amount of hardware and different hardware versions necessary to connect the sample line \n144\n and the guard line \n146\n to each other, or to the borehole, or to block the flow through the sample line \n144\n or the guard line \n146\n.', 'The flow routing plugs \n452\n may be removably coupled to a sample line \n144\n, the guard line \n146\n, or both.', 'The flow routing modules \n450\n enable the connection between the sample line \n144\n and the guard line \n146\n to changed relatively quickly.', 'For example, the flow routing plugs \n452\n may be uncoupled from the flowlines (e.g., the sample line \n144\n, the guard line \n146\n, or both) at the surface.', 'Once the initial flow routing plug \n452\n is uncoupled from the flowline, another flow routing plug \n452\n can be removably coupled using a suitable fastener (e.g., a bolt assembly).', 'In the illustrated embodiments, the flow routing modules \n450\n include three flow routing plugs \n452\n and the motor-driven valve \n454\n.', 'A first and a second plug of the plurality of the flow routing plugs \n452\n may be coupled to the sample line \n144\n and the guard line \n146\n, respectively.', 'A third plug of the plurality of flow routing plugs \n452\n may be disposed between the sample line \n144\n and the guard line \n146\n.', 'The single motor-driven valve \n454\n may be used control the flow through the valve along a line disposed between the sample line \n144\n and the guard line \n146\n.', 'In other words, when the motor-driven valve \n454\n is opened, fluid is allowed to flow through the valve \n454\n.', 'When the motor-driven valve \n454\n is closed, fluid is not allowed to flow through the valve \n454\n.', 'Each of the flow routing plugs \n452\n may utilize a plurality of fluidic connections \n456\n to route the fluid.', 'In some embodiments, the flow routing plugs \n452\n may use as many as four fluidic connections \n456\n to direct the fluid flow.', 'Various embodiments of the flow routing modules \n450\n may be further understood with reference to \nFIGS.', '20-27\n.', 'FIG.', '20\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the top most flow routing plug \n452\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n are oriented to turn the fluid from the motor-driven valve \n454\n through the flow routing plug \n452\n such that the fluid can exit the flow routing plug \n452\n via the sample line exit port \n162\n.', 'The flow routing plug \n452\n disposed on the sample line \n144\n utilizes three fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the sample line fluid to enter the motor-driven valve \n454\n to pass through to the exit port \n162\n and, in addition, enable the sample line fluid to flow through the sample line \n144\n, thereby bypassing the motor-driven valve \n454\n.', 'The flow routing plug \n452\n disposed on the guard line \n146\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the guard line fluid to flow through the guard line \n146\n, thereby bypassing the motor-driven valve \n454\n.', 'When the motor-driven valve \n454\n is open, the routing module \n450\n acts as an exit port for the sample line \n144\n.', 'When the motor-driven valve \n454\n is closed, the module \n450\n allows continuous flow of the sample line \n144\n flow and guard line \n146\n.\n \nFIG.', '21\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the top most flow routing plug \n452\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n are oriented to turn the fluid from the motor-driven valve \n454\n through the flow routing plug \n452\n such that the fluid can exit the flow routing plug \n452\n via the exit port \n162\n.', 'The flow routing plug \n452\n disposed on the sample line \n144\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the sample line fluid to flow through the sample line \n144\n, thereby bypassing the motor-driven valve \n454\n.', 'The flow routing plug \n452\n disposed on the guard line \n146\n utilizes three fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the guard line fluid to flow through the guard line \n146\n, thereby bypassing the motor-driven valve \n454\n.', 'The fluidic connections \n456\n enable the guard line fluid to flow through the motor-driven valve \n454\n to pass through to the exit port \n162\n.', 'When the motor-driven valve \n454\n is open, the routing module \n450\n acts as an exit port for the guard line \n146\n.', 'When the motor-driven valve \n454\n is closed, the module \n450\n allows continuous flow of the sample line \n144\n flow and guard line \n146\n.\n \nFIG.', '22\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the top most flow routing plug \n452\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n are oriented to turn the fluid from the motor-driven valve \n454\n through the flow routing plug \n452\n such that the fluid exit via the exit port \n162\n.', 'The flow routing plug \n452\n disposed on the sample line \n144\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the sample line fluid to flow from the sample line \n144\n to the motor-driven valve \n454\n.', 'The flow routing plug \n452\n disposed on the guard line \n146\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the guard line fluid to flow from the guard line \n146\n to the motor-driven valve \n454\n.', 'As such, the fluid flow from both the sample line \n144\n and the guard line \n146\n flow through the motor-driven valve \n454\n.', 'When the motor-driven valve \n454\n is closed, the module \n450\n acts as a turnaround (e.g., U-turn) connecting the fluid flow of the sample and guard lines \n144\n, \n146\n.', 'When the motor-driven valve \n454\n is open, the module \n450\n acts as a common exit for sample line \n144\n and guard line \n146\n.\n \nFIG.', '23\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the top most flow routing plug \n452\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n are oriented to pass the fluid through the flow routing plug \n452\n such that the fluid flows from the motor-driven valve \n454\n to the sample line \n144\n.', 'The flow routing plug \n452\n disposed on the sample line \n144\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the sample line fluid to flow through the sample line \n144\n, thereby bypassing the motor-driven valve \n454\n.', 'The flow routing plug \n452\n disposed on the guard line \n146\n utilizes three fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the guard line fluid to flow from the guard line \n146\n to the motor-driven valve \n454\n and also enable the guard line fluid to flow through the guard line \n146\n, thereby bypassing the motor-driven valve \n454\n.', 'As such, the module \n450\n connects the sample line \n144\n and to the guard line \n146\n.', 'This allows, for example, fluid flow from both the sample line \n144\n and the guard line \n146\n flow through the motor-driven valve \n454\n to mix with the sample line fluid so that a comingled fluid can be formed.\n \nFIG.', '24\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the top most flow routing plug \n452\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n are oriented to flow the fluid from the motor-driven valve \n454\n to the sample line \n144\n.', 'The flow routing plug \n452\n disposed on the sample line \n144\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the sample line fluid to flow from the sample line \n144\n to the motor-driven valve \n454\n.', 'The motor-driven valve \n454\n can thereby act as a sealing valve for the sample line \n144\n when the fluid flow from the sample line \n144\n is directed from the sample line \n144\n to the motor-driven valve \n454\n.', 'In other words, the valve \n454\n may control the quantity and timing of the fluid flow from the sample line \n144\n.', 'The flow routing plug \n452\n disposed on the guard line \n146\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the guard line fluid to bypass the motor-driven valve \n454\n.\n \nFIG.', '25\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the top most flow routing plug \n452\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n are oriented to flow from the motor-driven valve \n454\n to the guard line \n146\n.', 'The flow routing plug \n452\n disposed on the sample line \n144\n utilize two fluidic connections \n456\n.', 'The flow routing plug \n452\n passes through the sample line \n144\n, thereby bypassing the motor-driven valve \n454\n.', 'The flow routing plug \n452\n disposed on the guard line \n146\n utilizes two fluidic connections \n456\n.', 'The fluidic connections \n456\n enable the guard line fluid to flow from the guard line \n146\n to the motor-driven valve \n454\n.', 'The motor-driven valve \n454\n can thereby act as a sealing valve for the guard line \n144\n when the fluid flow from the guard line \n146\n is directed from the guard line \n146\n to the motor-driven valve \n454\n.', 'In other words, the valve \n454\n may control the quantity and timing of the fluid flow from the guard line \n146\n.\n \nFIG.', '26\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the flow routing module \n450\n is utilized in a single flowline downhole acquisition tool \n12\n.', 'The flow routing module \n450\n utilizes one flow routing plug \n452\n and the motor-driven valve \n454\n.', 'The routing plug \n452\n utilizes two fluidic connections \n456\n.', 'The motor-driven valve \n454\n can thereby act as a sealing valve for the flowline when the fluid flow from the flowline is directed from the flowline to the motor-driven valve \n454\n.', 'In other words, the valve \n454\n may control the quantity and timing of the fluid flow from the flowline.\n \nFIG.', '27\n illustrates a schematic diagram of an embodiment of the flow routing module \n450\n within the wireline wellsite system \n142\n.', 'In the illustrated embodiment, the flow routing module \n450\n is utilized in a single flowline downhole acquisition tool \n12\n.', 'The flow routing module \n450\n utilizes one flow routing plug \n452\n and the motor-driven valve \n454\n.', 'The routing plug \n452\n utilizes four fluidic connections \n456\n.', 'The fluidic connections \n456\n are oriented to direct a portion of the fluid through the flow routing plug \n452\n such that the fluid can exit the flow routing plug \n452\n via the line exit port.', 'The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure.', 'Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.'] | ['1.', 'A system, comprising:\na downhole acquisition tool housing configured to receive a fluid that enters a downhole acquisition tool from a first flowline, a second flowline, or both; and\na flow control assembly comprising: a first pump module fluidly coupled to first flowline; a second pump module fluidly coupled to the second flowline; a crossover portion disposed between the first pump module and the second pump module, wherein a turnaround module is connected with the crossover portion, wherein the crossover portion is disposed between the turnaround module and an inlet of the first flowline and second flowline, wherein the turnaround module has a valve associated therewith that is selectively adjusted to open an exit port or close an exit port, and wherein when the exit port is opened fluid flows out of the downhole acquisition tool housing and when the exit port is closed fluid is allowed to flow from one of the flow lines to the other flow line, and wherein the flow control assembly is configured to permit discharging the fluid from the first flowline to the second flowline, wherein the flow control assembly comprises one or more tangible, non-transitory, machine-readable media comprising instructions to: control a valve assembly of a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline toward a first pump module; control a valve assembly of a second valve configuration that enables the fluid to flow into the downhole tool via the second flowline toward a second pump module; and\nselectively use the turnaround module or the crossover portion to direct the fluid flow between the first flowline and the second flowline by actuating the valve associated with the turnaround module, the valve associated with the crossover portion, or both, to adjust operation of the downhole acquisition tool.', '2.', 'The system of claim 1, wherein selective use of the turnaround module comprises closing a port and a valve associated with the turnaround module, wherein closing the port and the valve associated with the turnaround module enables the fluid flow from the first flowline and the second flowline to be turned in the turnaround module within the downhole acquisition tool by closing the valve.', '3.', 'The system of claim 2, wherein the fluid flow is turned in the turnaround module and is rerouted in the downhole tool along the first flowline or the second flowline.', '4.', 'The system of claim 1, wherein the selective use of the turnaround module comprises using the first pump module, bypassing the second pump module, and opening a comingle valve when the second pump module is unavailable, wherein the first pump module is configured to pump fluid from the first flowline to collect a sample in a sample chamber.', '5.', 'The system of claim 4, wherein the selective use of the turnaround module comprises using the second pump module, bypassing the first pump module, and opening a comingle valve when the first pump module is unavailable, wherein the second pump module is configured to pump fluid from the second flowline to collect a sample in a sample chamber.', '6.', 'The system of claim 1, wherein the selective use of the turnaround module comprises closing the valve associated with the turnaround module and closing an exit port associated with the turnaround module to capture a first fluid slug and continuing to operate the pump module to capture a second fluid slug to enable the first fluid slug and the second fluid slug to mix to form a mixed fluid.', '7.', 'The system of claim 6, wherein the selective use of the turnaround module comprises measuring one or more fluid properties of the mixed fluid.'] | ['FIG.', '1 is a schematic diagram of a logging-while-drilling wellsite system that may be used to identify properties of formation fluids in the wellbore, in accordance with an embodiment;; FIG.', '2 is a schematic diagram of another example of a wireline wellsite system that may be used to identify properties of the formation fluids in the wellbore, in accordance with an embodiment;; FIG.', '3 illustrates a flowchart of a method for operating the downhole acquisition tool using a bottom pump module and a top pump module, in accordance with an embodiment;; FIG.', '4 is a schematic diagram of another example of a wireline wellsite system illustrating a sample line and a guard line used to draw in formation fluids in the wellbore, where a turnaround module is fluidly coupled to the sample line and the guard line, in accordance with an embodiment;; FIG.', '5 illustrates a flowchart of method for operating the downhole acquisition tool using a top pump module, in accordance with an embodiment;; FIG.', '6 is a schematic diagram of another example of a wireline wellsite system illustrating the sample line and the guard line used to draw in formation fluids in the wellbore, where the top pump module is used to direct fluid through the sample line and the guard line using a turnaround module, in accordance with an embodiment;; FIG.', '7 illustrates a flowchart of a method for operating the downhole acquisition tool using the bottom pump module and the top pump module, in accordance with an embodiment;; FIG. 8 is a schematic diagram of another example of a wireline wellsite system illustrating the sample line and the guard line used to draw in formation fluids in the wellbore, where the bottom pump module is used to direct fluid through the sample line and the guard line using the turnaround module, in accordance with an embodiment;; FIG.', '9 illustrates a flowchart of a method for operating the downhole acquisition tool using the bottom pump module, in accordance with an embodiment; FIG.', '10 is a schematic diagram of another example of a wireline wellsite system illustrating the sample line and the guard line used to draw in formation fluids in the wellbore, where the bottom pump module is used to direct fluid through the sample line and the guard line using the turnaround module, in accordance with an embodiment;; FIG.', '11 illustrates a flowchart of a method for using the single pump module and a plurality of packers used to draw in formation fluids in the wellbore, in accordance with an embodiment;; FIG.', '12 is a schematic diagram of another example of a wireline wellsite system illustrating the plurality of packers used to draw in formation fluids in the wellbore through the sample line and the guard line, where the single pump module is used to direct fluid through the sample line and the guard line using the turnaround modules, in accordance with an embodiment;; FIG.', '13 illustrates a flowchart of a method for collecting a plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;; FIG.', '14 is a schematic diagram of another example of a wireline wellsite system illustrating the plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;; FIG.', '15 illustrates a flowchart of a method for collecting a plurality of larger fluid slugs within the sample line and the guard line, in accordance with an embodiment;; FIG.', '16 is a schematic diagram of another example of a wireline wellsite system illustrating the plurality of larger fluid slugs within the sample line and the guard line, in accordance with an embodiment;; FIG.', '17 illustrates a flowchart of a method for mixing a plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;; FIG.', '18 is a schematic diagram of another example of a wireline wellsite system illustrating the mixed plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment;; FIG.', '19 illustrates a flowchart of a method for performing a phase separation within the sample line and the guard line, in accordance with an embodiment;; FIG.', '20 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;; FIG.', '21 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;; FIG.', '22 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;; FIG.', '23 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;; FIG.', '24 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;; FIG.', '25 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system;; FIG.', '26 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system; and; FIG.', '27 illustrates a schematic diagram of an embodiment of the flow routing module within the wireline wellsite system.; FIGS. 1 and 2 depict examples of wellsite systems that may employ such fluid analysis systems and methods.', 'In FIG.', '1, a rig 10 suspends a downhole acquisition tool 12 into a wellbore 14 via a drill string 16.', 'A drill bit 18 drills into a geological formation 20 to form the wellbore 14.', 'The drill string 16 is rotated by a rotary table 24, which engages a kelly 26 at the upper end of the drill string 16.', 'The drill string 16 is suspended from a hook 28, attached to a traveling block, through the kelly 26 and a rotary swivel 30 that permits rotation of the drill string 16 relative to the hook 28.', 'The rig 10 is depicted as a land-based platform and derrick assembly used to form the wellbore 14 by rotary drilling.', 'However, in other embodiments, the rig 10 may be an offshore platform.', '; FIG.', '2 depicts an example of a wireline downhole tool 100 that may employ the systems and methods of this disclosure.', 'The downhole tool 100 is suspended in the wellbore 14 from the lower end of a multi-conductor cable 104 that is spooled on a winch at the surface 74.', 'Like the downhole acquisition tool 12, the wireline downhole tool 100 may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or any other suitable conveyance.', 'The cable 104 is communicatively coupled to an electronics and processing system 106.', 'The downhole tool 100 includes an elongated body 108 that houses modules 110, 112, 114, 122, and 124, that provide various functionalities including fluid sampling, sample bottle filling, fluid testing, operational control, and communication, among others.', 'For example, the modules 110 and 112 may provide additional functionality such as fluid analysis, resistivity measurements, operational control, communications, coring, and/or imaging, among others.; FIG.', '4 is a schematic diagram of another example of a wireline wellsite system 142 illustrating a sample line 144 and a guard line 146 used to draw in formation fluids in the wellbore, where a turnaround module 148 is fluidly coupled to the sample line 144 and the guard line 146, in accordance with an embodiment.', 'The wireline wellsite system 142 may flow fluid (e.g., through the sample line 144 and/or through the guard line 146) during steady state operation of the downhole acquisition tool 12.', 'In the illustrated embodiment, the sample line fluid is drawn in through the sample line 144.', 'The sample line 144 includes an isolation valve 154 to control the flow of the sample line fluid into the sample line 144.', 'When the isolation valve 154 is open, the downhole acquisition tool 12 uses a bottom pump module 150 associated with the sample line 144 to draw in fluid with the bottom pump module 150.', 'The flow path of the sample line fluid 144 is illustrated by arrows 151.', 'A comingle valve 158 may be used when the isolation valve 154 is not being used.', '; FIG.', '5 illustrates a flowchart of a method 170 of the operating the downhole acquisition tool 12 using the top pump module 152, in accordance with an embodiment.', 'The method 170 may be used when the bottom pump module 150 is unable to be used (e.g., to maintenance, equipment failure, etc.)', 'or when it is not desirable to use the bottom pump module 150.', 'The method 170 includes drawing in (block 172) the sample line fluid and the guard line fluid.', 'While the fluid is drawn in, the exit ports 162, 164 may be closed and the fluid may flow out of the downhole acquisition tool 12 when the valve 160 is open.', 'The method 170 includes cleaning the fluid or capturing a sample (block 174).', 'The method 170 includes closing (block 176) a bypass valve 184 of the bottom pump module 150.', 'The method 170 includes opening (block 178) the exit port 162 so that the fluid exits through the exit port.', 'The method 170 includes closing (block 180) a wellbore port associated with the turnaround module 148 in the turnaround module (e.g. by closing a valve 160 associated with the turnaround module 148) to turn the fluid flow.', 'The method 170 may include reversing (block 182) the pumping direction of the top pump module 152.', 'The method includes capturing samples (block 183) in a sample chamber that is in fluid communication with the flowline 146.', 'The sample may be captured with the pump that is connected to flowline 144 (e.g., when the fluid is pumped by the top pump module 152 through flowline 144 and is U-turned into flowline 146).; FIG.', '6 is a schematic diagram of another example of a wireline wellsite system 142 illustrating the sample line 144 and the guard line 146 used to draw in formation fluids in the wellbore, where the top pump module 152 is used to direct fluid through the sample line 144 and the guard line 146 using a turnaround module 148, in accordance with an embodiment.', 'In the illustrated embodiment, the sample line fluid is drawn in through the sample line 144.', 'The sample line 144 uses the isolation valve 154 to control the flow of the sample line fluid into the sample line 144.', 'In the illustrated embodiment, the downhole acquisition tool 12 bypasses the bottom pump module 150 associated with the sample line 144.', 'The bypass valve 184 of the bottom pump module is closed and the exit port 162 is opened.', 'The fluid follows the flow path indicated by the arrows 186 shown.', 'As illustrated, the fluid is turned via the turnaround module 148 at the top of the downhole acquisition tool 12.; FIG.', '7 illustrates a flowchart of a method of operating the downhole acquisition tool using a bottom pump module and a top pump module, in accordance with an embodiment.', 'A method 230 for performing a steady state operation using a bottom pump module and a top pump module, in accordance with an embodiment.', 'The method 230 may be similar to the method 130 described above with reference to FIG.', '3.', 'In the method 230, the flow of the downhole fluid and/or water that the bottom pump module 150 generates during sample capture may be different compared to the method 130.', 'The method 230 includes drawing in (block 232) the sample line fluid and the guard line fluid.', 'The method 230 includes cleaning (block 234) a sample of fluid (e.g., formation fluid) from the sample line and the guard line.', 'After the sample of fluid is cleaned to a suitable level, the method 230 includes capturing (block 236) a first sample of fluid in the sample bottles.', 'The method 230 may include allowing an amount of time to pass before collecting a second sample of fluid.', 'As such, the method 230 may include pumping (block 238) the sample line fluid and the guard line fluid during steady state operation of the downhole acquisition tool.', 'The method 230 may then include capturing (block 240) a second sample from the sample bottles.', 'The second sample may be captured at a different location from the first sample or at the same location as the first sample.; FIG. 8 is a schematic diagram of another example of a wireline wellsite system 142 illustrating the sample line 144 and the guard line 146 used to draw in formation fluids in the wellbore, where the turnaround module 148 is fluidly coupled to the sample line 144 and the guard line 146, in accordance with an embodiment.', 'As described above, the flow of the downhole fluid and/or water that the bottom pump module 150 generates during sample capture may be different compared to the embodiment illustrated in FIG.', '4.', 'The flow of the downhole fluid and/or water generated during sample capture is shown by arrows 250.; FIG.', '9 illustrates a flowchart of a method 280 of operating the downhole acquisition tool 12 using the bottom pump module 150, in accordance with an embodiment.', 'The method 280 may be used when the top pump module 152 is not able to be used or it is not desired to use the top pump module.', 'The method 280 includes drawing in (block 282) the sample line fluid and the guard line fluid.', 'The method 280 includes cleaning sample line fluid and/or capture the sample (block 284).', 'The method 280 includes closing (block 286) the valve 160 and the port associated with the top turnaround module 148.', 'The method 280 includes opening (block 288) the exit port 164 and opening the bypass valve associated with flowline in the top pump module 152.', 'The method 280 may include reversing (block 290) the direction of the bottom pump module 150.', 'The method 280 includes capturing samples (block 292) in a sample chamber that is in fluid communication with the flowline 144.', 'The sample may be captured with the pump that is connected to flowline 146 (e.g., when the fluid pumped by the bottom pump module 150 through flowline 146 and is U-turned into flowline 144).; FIG.', '10 is a schematic diagram of another example of a wireline wellsite system 142 illustrating the sample line 144 and the guard line 146 used to draw in formation fluids in the wellbore, where the bottom pump module 150 is used to direct fluid through the sample line 144 and the guard line 146 using the turnaround modules 148, in accordance with an embodiment.; FIG.', '11 illustrates a flowchart of a method 302 of using a single pump module and a plurality of packers used to draw in formation fluids in the wellbore, in accordance with an embodiment.', 'The method 302 includes closing (block 304) a flowline in pump module.', 'The method 302 includes closing (block 306) the wellbore port and opening the turnaround module in the bottom terminal module.', 'The method 302 includes opening (block 308) the wellbore port and closing the turnaround in the top terminal module.', 'When the packers are filled with fluid from a volume chamber 326, the valve 160 associated with the turnaround module 148 may be closed.', 'When the packers are filled with fluid from the borehole, the valve 160 associated with the turnaround module 148 may be opened.', 'It may be appreciated that the valves associated with the sample chamber are closed when the packers are filled.', 'The method 302 includes reversing (block 310) the direction of the pump module.', 'The method 302 includes filling (block 312) the packers or inflating the packers with clean fluid.', 'The method 302 includes cleaning (block 314) the sample line fluid and/or capturing the sample.;', 'FIG. 12 is a schematic diagram of another example of a wireline wellsite system illustrating a plurality of packers 320 used to draw in formation fluids in the wellbore through the sample line 144 and the guard line 146, where a single pump module 322 is used to direct fluid through the sample line 144 and the guard line 146 using the turnaround modules 148, in accordance with an embodiment.', 'Instead of opening the exit port and closing the turnaround module 148 in the top terminal module, the inflation fluid may be drawn from the sample chamber 326.', 'The inflation of the packers 320 may be performed with the single pump module 322 as shown by arrows 324.', 'As described above, the one or more sensors 159 may be disposed along the flowlines 144, 146 or associated the flow control valves (e.g., the valve 160, the valve 184, the comingle valve 158, the isolation valve 154, 156, etc.)', 'to output data that may be used to control the actuation of the valves and the fluid flow.', '; FIG.', '13 illustrates a flowchart of a method 330 for collecting a plurality of fluid slugs within the sample line 144 and the guard line 146, in accordance with an embodiment.', 'The method 330 includes opening (block 332) the valve 160 associated with the turnaround flowline of the top termination module, opening the exit port, and starting to pump the fluid so that the fluid is pumped out of the tool 12.', 'The method 330 includes closing (block 334) the valve 160 associated with the turnaround flowline of the top termination module and closing the exit port to turn the fluid.', 'The method 330 includes capturing (block 336) a first fluid slug in the flowline 146 between the check valves in the top termination module and the top pump module 152.', 'The method 330 includes continuing (block 338) the pumping operations using the top pump module 152, flowing fluid through the flowline 144, and out of the turnaround module 148 through the open valve 160.', 'The method 330 includes capturing (block 340) a second fluid slug in flowline 144 between the check valves in the top termination module and the top pump module 152.', 'The method 330 includes opening (block 342) the turnaround flowline of the top termination module, closing the exit port in the top module, and closing the isolation valves to create a loop across the modules of the downhole acquisition tool.; FIG.', '14 is a schematic diagram of another example of a wireline wellsite system 142 illustrating the plurality of fluid slugs 350 within the sample line 144 and the guard line 146, in accordance with an embodiment.', 'A first fluid slug 354 is formed in the flowline 146 between the check valves in the top termination module and the lower pump module 150 as shown.', 'A second fluid slug 352 is formed between the top termination module (e.g., a check valve associated with the top termination module) and the top pump module 152, as shown.', 'As shown, the downhole fluid originates from the sample inlet.', 'Either of the pump modules or both may be used to circulate one or both of the fluid slugs 352, 354 between the fluid analyzers.', 'Fluid analysis of the fluid slugs 352, 354 may be used to measure fluid properties of the slugs.; FIG.', '15 illustrates a flowchart of a method 360 for collecting a plurality of larger fluid slugs within the sample line 144 and the guard line 146, in accordance with an embodiment.', 'The method 360 includes opening (block 362) the valve 160 associated with the turnaround flowline of the top termination module, opening the exit port, and starting to pump the fluid so that the fluid is pumped out of the tool 12.', 'The method 360 includes closing (block 364)', 'the valve 160 associated with the turnaround flowline of the top termination module and closing the exit port to turn the fluid.', 'The method 360 includes capturing (block 366) a first fluid slug between the top termination module and the bottom termination module (e.g., between check valves associated with the top termination module and the bottom termination module).', 'The method 360 includes continuing (block 368) pumping operations using the top pump module 152.', 'The method 360 includes capturing (block 370) a second fluid slug between check valves in the top termination module and the bottom pump module.;', 'FIG.', '16 is a schematic diagram of another example of a wireline wellsite system 142 illustrating the plurality of larger fluid slugs 350 within the sample line 144 and the guard line 146, in accordance with an embodiment.', 'A first fluid slug 356 is formed between the check valves in the top termination module and the top pump module 152 as shown.', 'A second fluid slug 358 is formed between the check valves in the top termination module and the bottom pump module as shown.', 'Arrows illustrate the fluid flow from the sample flowline and may be used to clean the flowline loop 356.', 'Arrows show the flow path of the second fluid slug 358.', 'Either of the pump modules or both may be used to circulate one or both of the fluid slugs 352, 354 between the fluid analyzers.', 'Fluid analysis of the fluid slugs 356, 358 may be used to measure fluid properties of the slugs.; FIG.', '17 illustrates a flowchart of a method 380 for mixing a plurality of fluid slugs within the sample line and the guard line, in accordance with an embodiment.', 'The method 380 includes bypassing (block 382) the bottom pump module 150 that contains the same fluid as the second slug.', 'The method 380 include driving (block 384) the top pump module 152 to reverse circulate the first fluid slug.', 'The method 380 includes driving (block 386) the bottom pump module 150 to inject the second slug into the flow loop.', 'It may be appreciated that the pump modules may be run at different speeds relative to one another to facilitate mixing of the fluids.', 'The method 380 includes mixing (block 388) the first and second fluid slugs above the bypass valve of the bottom pump module 150.', 'The method 380 includes flowing (block 390) the mixture through the bypass valve of the bottom pump module 150 and splitting the flow between the flow loop and the previously empty chamber of the bottom pump module 150.', 'The method 380 includes closing (block 392) the bypass valve of the bottom pump module 150, bypassing the top pump module 152, and reversing the stroke of the bottom pump module.', 'Mixing the fluid slugs may be useful to analyze the mixed fluids by directing the mixed fluid slug to a fluid analyzer, study fluid compatibility, perform chemical experiments, and so forth.', '; FIG.', '18 is a schematic diagram of another example of a wireline wellsite system 142 illustrating the mixed plurality of fluid slugs 400, 402 within the sample line 144 and the guard line 146, in accordance with an embodiment.', 'The first fluid slug 400 is circulated by the top pump module 150 and the second fluid slug 402 is driven to inject the second slug into the flow loop as shown by the arrows.; FIG.', '19 illustrates a flowchart of a method 410 for performing a phase separation within the sample line 144 and the guard line 146, in accordance with an embodiment.', 'The method 410 includes opening (block 412) the exit port of the top pump module 152.', 'The method 410 includes driving (block 414) the pump in the same module.', 'The method 410 includes depressurizing (block 416) the upper part of the flow loop to promote phase separation of the fluid.', 'It may be appreciated either of the pump modules may be used to circulated the separated phases to fluid analyzers.', 'When the method 410 is combined with the control, other benefits may be seen, such as determining the phase border at the temperature of the flowline fluid.', '; FIG.', '20 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the top most flow routing plug 452 utilizes two fluidic connections 456.', 'The fluidic connections 456 are oriented to turn the fluid from the motor-driven valve 454 through the flow routing plug 452 such that the fluid can exit the flow routing plug 452 via the sample line exit port 162.', 'The flow routing plug 452 disposed on the sample line 144 utilizes three fluidic connections 456.', 'The fluidic connections 456 enable the sample line fluid to enter the motor-driven valve 454 to pass through to the exit port 162 and, in addition, enable the sample line fluid to flow through the sample line 144, thereby bypassing the motor-driven valve 454.', 'The flow routing plug 452 disposed on the guard line 146 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the guard line fluid to flow through the guard line 146, thereby bypassing the motor-driven valve 454.', 'When the motor-driven valve 454 is open, the routing module 450 acts as an exit port for the sample line 144.', 'When the motor-driven valve 454 is closed, the module 450 allows continuous flow of the sample line 144 flow and guard line 146.; FIG.', '21 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the top most flow routing plug 452 utilizes two fluidic connections 456.', 'The fluidic connections 456 are oriented to turn the fluid from the motor-driven valve 454 through the flow routing plug 452 such that the fluid can exit the flow routing plug 452 via the exit port 162.', 'The flow routing plug 452 disposed on the sample line 144 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the sample line fluid to flow through the sample line 144, thereby bypassing the motor-driven valve 454.', 'The flow routing plug 452 disposed on the guard line 146 utilizes three fluidic connections 456.', 'The fluidic connections 456 enable the guard line fluid to flow through the guard line 146, thereby bypassing the motor-driven valve 454.', 'The fluidic connections 456 enable the guard line fluid to flow through the motor-driven valve 454 to pass through to the exit port 162.', 'When the motor-driven valve 454 is open, the routing module 450 acts as an exit port for the guard line 146.', 'When the motor-driven valve 454 is closed, the module 450 allows continuous flow of the sample line 144 flow and guard line 146.; FIG.', '22 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the top most flow routing plug 452 utilizes two fluidic connections 456.', 'The fluidic connections 456 are oriented to turn the fluid from the motor-driven valve 454 through the flow routing plug 452 such that the fluid exit via the exit port 162.', 'The flow routing plug 452 disposed on the sample line 144 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the sample line fluid to flow from the sample line 144 to the motor-driven valve 454.', 'The flow routing plug 452 disposed on the guard line 146 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the guard line fluid to flow from the guard line 146 to the motor-driven valve 454.', 'As such, the fluid flow from both the sample line 144 and the guard line 146 flow through the motor-driven valve 454.', 'When the motor-driven valve 454 is closed, the module 450 acts as a turnaround (e.g., U-turn) connecting the fluid flow of the sample and guard lines 144, 146.', 'When the motor-driven valve 454 is open, the module 450 acts as a common exit for sample line 144 and guard line 146.; FIG.', '23 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the top most flow routing plug 452 utilizes two fluidic connections 456.', 'The fluidic connections 456 are oriented to pass the fluid through the flow routing plug 452 such that the fluid flows from the motor-driven valve 454 to the sample line 144.', 'The flow routing plug 452 disposed on the sample line 144 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the sample line fluid to flow through the sample line 144, thereby bypassing the motor-driven valve 454.', 'The flow routing plug 452 disposed on the guard line 146 utilizes three fluidic connections 456.', 'The fluidic connections 456 enable the guard line fluid to flow from the guard line 146 to the motor-driven valve 454 and also enable the guard line fluid to flow through the guard line 146, thereby bypassing the motor-driven valve 454.', 'As such, the module 450 connects the sample line 144 and to the guard line 146.', 'This allows, for example, fluid flow from both the sample line 144 and the guard line 146 flow through the motor-driven valve 454 to mix with the sample line fluid so that a comingled fluid can be formed.; FIG.', '24 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the top most flow routing plug 452 utilizes two fluidic connections 456.', 'The fluidic connections 456 are oriented to flow the fluid from the motor-driven valve 454 to the sample line 144.', 'The flow routing plug 452 disposed on the sample line 144 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the sample line fluid to flow from the sample line 144 to the motor-driven valve 454.', 'The motor-driven valve 454 can thereby act as a sealing valve for the sample line 144 when the fluid flow from the sample line 144 is directed from the sample line 144 to the motor-driven valve 454.', 'In other words, the valve 454 may control the quantity and timing of the fluid flow from the sample line 144.', 'The flow routing plug 452 disposed on the guard line 146 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the guard line fluid to bypass the motor-driven valve 454.; FIG.', '25 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the top most flow routing plug 452 utilizes two fluidic connections 456.', 'The fluidic connections 456 are oriented to flow from the motor-driven valve 454 to the guard line 146.', 'The flow routing plug 452 disposed on the sample line 144 utilize two fluidic connections 456.', 'The flow routing plug 452 passes through the sample line 144, thereby bypassing the motor-driven valve 454.', 'The flow routing plug 452 disposed on the guard line 146 utilizes two fluidic connections 456.', 'The fluidic connections 456 enable the guard line fluid to flow from the guard line 146 to the motor-driven valve 454.', 'The motor-driven valve 454 can thereby act as a sealing valve for the guard line 144 when the fluid flow from the guard line 146 is directed from the guard line 146 to the motor-driven valve 454.', 'In other words, the valve 454 may control the quantity and timing of the fluid flow from the guard line 146.; FIG.', '26 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the flow routing module 450 is utilized in a single flowline downhole acquisition tool 12.', 'The flow routing module 450 utilizes one flow routing plug 452 and the motor-driven valve 454.', 'The routing plug 452 utilizes two fluidic connections 456.', 'The motor-driven valve 454 can thereby act as a sealing valve for the flowline when the fluid flow from the flowline is directed from the flowline to the motor-driven valve 454.', 'In other words, the valve 454 may control the quantity and timing of the fluid flow from the flowline.', '; FIG.', '27 illustrates a schematic diagram of an embodiment of the flow routing module 450 within the wireline wellsite system 142.', 'In the illustrated embodiment, the flow routing module 450 is utilized in a single flowline downhole acquisition tool 12.', 'The flow routing module 450 utilizes one flow routing plug 452 and the motor-driven valve 454.', 'The routing plug 452 utilizes four fluidic connections 456.', 'The fluidic connections 456 are oriented to direct a portion of the fluid through the flow routing plug 452 such that the fluid can exit the flow routing plug 452 via the line exit port.'] |
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US11136836 | High trip rate drilling rig | Apr 25, 2018 | Joe Rodney Berry, Robert Metz, Melvin Alan Orr, Mark W. Trevithick | Schlumberger Technology Corporation | NPL References not found. | 2412020; December 1946; Walters; 3253995; May 1966; Antonsen et al.; 3874518; April 1975; Swoboda, Jr. et al.; 4042123; August 16, 1977; Sheldon et al.; 4274778; June 23, 1981; Putnam et al.; 4348920; September 14, 1982; Boyadjieff; 4421179; December 20, 1983; Boyadjieff; 4462733; July 31, 1984; Langowski et al.; 4501522; February 26, 1985; Causer et al.; 4610315; September 9, 1986; Koga et al.; 4621974; November 11, 1986; Krueger; 4715761; December 29, 1987; Berry et al.; 4738321; April 19, 1988; Olivier; 4850439; July 25, 1989; Lund; 5038871; August 13, 1991; Dinsdale; 5107940; April 28, 1992; Berry; 5211251; May 18, 1993; Woolslayer; 5423390; June 13, 1995; Donnally et al.; 5518076; May 21, 1996; Holz et al.; 6220807; April 24, 2001; Sorokan; 6513605; February 4, 2003; Lodden; 6557651; May 6, 2003; Norby et al.; 6591471; July 15, 2003; Hollingsworth et al.; 6591904; July 15, 2003; Cicognani; 6609565; 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2019; Alvaer et al. | 104563912; April 2015; CN; 0979924; February 2000; EP; 2100565; December 1997; RU; 2541972; February 2015; RU; 1730422; April 1992; SU; 9315303; August 1993; WO; 0111181; February 2001; WO; 0218742; March 2002; WO; 2006059910; June 2006; WO; 2010141231; December 2010; WO; 2011016719; February 2011; WO; 2011056711; May 2011; WO; 2012148286; November 2012; WO; 2014029812; February 2014; WO; 2016204608; December 2016; WO; 2017087200; May 2017; WO; 2017087349; May 2017; WO; 2017087350; May 2017; WO | ['A high trip rate drilling rig has first handling equipment to transport stands in/out of setback, second handling equipment to deliver stands to/from well center, and a hand-off position to set down stands for exchange between first/second equipment.', 'Second equipment can include a top drive and a delivery arm translatable along the mast past each other, and a clasp on the arm slidable on the stand for constraint below the upper end, which can allow the top drive to engage/disengage the constrained stand above the arm.', 'A high trip rate method transports stands in/out of setback, delivers stands to/from well center, and sets down and hands off stands at hand-off position between the setback transportation and well center delivery.', 'The delivery can include engaging/disengaging the top drive and a stand constrained by the clasp.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'This application is a divisional application of U.S. patent application Ser.', 'No. 15/770,854 filed on Apr. 25, 2018, which is a National Phase of Patent Cooperation Treaty Number PCT/US2017/030329 filed on May 1, 2017, which claims priority to U.S. Provisional Patent Application 62/330,016 filed on Apr. 29, 2016.', 'This application also claims priority to Patent Cooperation Treaty Numbers PCT/US2016/061952 and PCT/US2016/061956, both filed on Nov. 15, 2016, and Patent Cooperation Treaty Number PCT/US2016/062402 filed on Nov. 17, 2016.', 'This application claims priority to U.S. Provisional Patent Application Ser.', 'Nos.', '62/330,012 and 62/330,021 filed on Apr. 29, 2016 and U.S. Provisional Patent Application Ser.', 'Nos. 62/330,200 and 62/330,244 filed on May 1, 2016.', 'All 10 of these applications are incorporated by reference herein in their entirety.', 'BACKGROUND', 'In the exploration of oil, gas and geothermal energy, drilling operations are used to create boreholes, or wells, in the earth.', 'Conventional drilling involves having a drill bit on the bottom of the well.', 'A bottom-hole assembly is located immediately above the drill bit where directional sensors and communications equipment, batteries, mud motors, and stabilizing equipment are provided to help guide the drill bit to the desired subterranean target.', 'A set of drill collars are located above the bottom-hole assembly to provide a non-collapsible source of weight to help the drill bit crush the formation.', 'Heavy weight drill pipe is located immediately above the drill collars for safety.', 'The remainder of the drill string is mostly drill pipe, designed to operate under tension.', 'A conventional drill pipe section is about 30 feet long, but lengths vary based on style.', 'It is common to store lengths of drill pipe in “doubles” (2 connected lengths) or “triples” (3 connected lengths).', 'When the drill string (drill pipe, drill collars and other components) are removed from the wellbore to change-out the worn drill bit, the drill pipe and drill collars are set back in doubles or triples until the drill bit is retrieved and exchanged.', 'This process of pulling everything out of the hole and running it all back in is known as “tripping.”', 'Tripping is non-drilling time and, therefore, an expense.', 'Efforts have long been made to devise ways to avoid it or at least speed it up.', 'Running triples is faster than running doubles because it reduces the number of threaded connections to be disconnected and then reconnected.', 'Triples are longer and therefore more difficult to handle due to their length and weight and the natural waveforms that occur when moving them around.', 'Manually handling moving pipe can be dangerous.', 'It is desirable to have a drilling rig with the capability to reduce the trip time.', 'One option is to operate a pair of opposing masts, each equipped with a fully operational top drive that sequentially swings over the wellbore.', 'In this manner, tripping can be nearly continuous, pausing only to spin connections together or apart.', 'Problems with this drilling rig configuration include at least costs of equipment, operation and transportation.', 'Tripping is a notoriously dangerous activity.', 'Conventional drilling practice requires locating a derrickman high up on the racking module platform, where he is at risk of a serious fall and other injuries common to manually manipulating the heavy pipe stands when racking and unracking the pipe stands when tripping.', 'Personnel on the drill floor are also at risk, trying to manage the vibrating tail of the pipe stand, often covered in mud and grease of a slippery drill floor in inclement weather.', 'In addition, the faster desired trip rates increase risks.', 'It is desirable to have a drilling rig with the capability to reduce trip time and connection time.', 'It is also desirable to have a system that includes redundancies, such that if a component of the system fails or requires servicing, the task performed by that component can be taken-up by another component on the drilling rig.', 'It is also desirable to have a drilling rig that has these features and remains highly transportable between drilling locations.', 'SUMMARY\n \nA drilling rig system and method are disclosed for obtaining high trip rates, particularly on land based, transportable drilling rigs.', 'The drilling rig can reduce non-productive time by separating the transport of tubular stands in and out of their setback position into a first function, and delivery of a tubular stand into or out of well center as a second function.', 'The functions intersect at a stand hand-off position, where tubular stands are set down for exchange between tubular handling equipment.\n \nAlso disclosed are embodiments of an arrangement between a retractable top drive assembly and a tubular delivery arm that may allow the top drive to hoist or lower the drill string, while the tubular delivery arm simultaneously hoists only the stands in or out of well center.', 'In some embodiments, the tubular delivery arm is positioned below the upper end of the stand in well center position to stabilize the upper end and make room for the top drive over the stand, to facilitate engaging or disengaging the top drive and the stand, e.g., with the string held in the rotary table.', 'In some embodiments, the drilling rig comprises first function tubular handling equipment to transport tubular stands in and out of a setback position on a setback platform; second function tubular handling equipment to deliver the tubular stands to and from a well center over a well; and a stand hand-off position between the first and second function tubular handling equipment to set down tubular stands for exchange at an intersection between the first function tubular equipment and the second function tubular equipment.', 'In some embodiments, a method to insert tubulars in or remove tubulars from a drill string in a well below a drill floor of a drilling rig may comprise using first tubular handling equipment to transport tubular stands in and out of a setback position on a setback platform; using second tubular handling equipment to deliver the tubular stands to and from a well center position over the well; setting down the tubular stands in a stand hand-off position at an intersection between the first and second tubular handling equipment; and exchanging the tubular stands between the first and second functions at the stand hand-off position.', 'In some embodiments of the drilling rig and method, the first tubular handling equipment may comprise an upper racking arm over a racking module and the setback platform, and the second tubular handling equipment may comprise a tubular delivery arm.', 'In some embodiments, a method to insert tubulars in or remove tubulars from a drill string in a well below a drilling rig may comprise a first tubular handling function comprising guiding upper portions of the tubular stands to transport the tubular stands in or out of a setback position on a setback platform; a second tubular handling function comprising guiding the upper portions of the tubular stands to deliver the tubular stands to or from a well center position over the well; setting down the tubular stands in a stand hand-off position located at an intersection between the first and second functions; and exchanging the tubular stands between the first and second tubular handling functions at the stand hand-off position.', 'In some embodiments, a method to insert tubulars in or remove tubulars from a drill string in a well below a drilling rig may comprise moving tubular stands between a racked position in a fingerboard assembly and a set down position in a stand hand-off position, located between the fingerboard assembly and a drilling mast; and retrieving and delivering the tubular stands between the stand hand-off position and a well center position over well center.', 'The method in some embodiments may further comprise connecting or disconnecting the tubular stands and a drill string; engaging or disengaging the tubular stands and a top drive assembly; and lowering or hoisting the tubular stands connected to the drill string with the top drive assembly.', 'In some embodiments, a drilling rig may comprise a retractable top drive assembly vertically translatable along a mast; and a tubular delivery arm also vertically translatable along the mast and comprising a tubular clasp movable between well center and a position forward of the well center, e.g., a mousehole, a stand hand-off position, or a catwalk; where the tubular clasp is engageable with an upper end of a tubular stand and the tubular clasp is slidably engageable with the tubular stand below the upper end, e.g., to facilitate positioning an upper portion of the tubular stand in the well center position below the upper end.', 'In some embodiments, a method to insert tubulars in or remove tubulars from a drill string in a well below a drilling rig may comprise engaging a tubular clasp of a tubular delivery arm and an upper end of a tubular stand; moving the tubular clasp between a well center position over a well center and a position forward of the well center, e.g., a mousehole, a stand hand-off position, or a catwalk; positioning an upper portion of the tubular stand in the well center position with the clasp below the upper end; and engaging or disengaging a top drive and the constrained upper end of the tubular stand in the well center position.', 'In some embodiments, the stand hand-off position is a designated setdown position for transferring the next tubular stand to go into the well or to be racked, as handled between the tubular delivery arm and the upper racking arm.', 'In one embodiment, the lower end of the stand hand-off position is located on a setback platform, e.g., beneath the drill floor where a lower racking arm can work with the upper racking arm.', 'In some embodiments, an upper stand constraint may be provided to clasp an upper portion of one of the tubular stands, e.g., near its top, to secure it in vertical orientation when at the stand hand-off position.', 'The upper stand constraint may be mounted on the racking module.', 'By securing an upper portion of a tubular stand at the stand hand-off position, the upper racking arm is free to progress towards the next tubular stand to be retrieved.', 'The tubular delivery arm can lower along the mast to clasp the tubular stand held by the upper stand constraint above the upper stand constraint, e.g., at the upper end such as at the upset, without interfering with the path of the upper racking arm.', 'In some embodiments, a lower stand constraint may be provided to guide ascending and descending tubular stands to and away from the stand hand-off position and to secure the tubular stands vertically when at the stand hand-off position.', 'A stand hand-off station may be located at the stand hand-off position, e.g., to provide automatic washing and doping of the pin connection.', 'The terms “grease” and “dope” are used interchangeably herein.', 'A grease dispenser may also be provided on the tubular delivery arm for automatic doping of the box end of the tubular stands.', 'In some embodiments, an intermediate stand constraint may be provided and attached to the V-door side edge of the center section of the substructure of the drilling rig, e.g., at or below the drill floor.', 'The intermediate stand constraint may include a gripping assembly for gripping tubular stands to prevent their vertical movement while suspended over the mousehole to facilitate stand-building without the need for step positions in the mousehole assembly.', 'The intermediate stand constraint may also have a clasp, and the ability to extend between the stand hand-off position and the mousehole.', 'In some embodiments, an upper racking arm can be provided to move tubular stands of drilling tubulars between any racking position within the racking module and the stand hand-off position, located between the mast and a fingerboard of the racking module.', 'In some embodiments, a setback platform is provided beneath a racking module for supporting stored casing and tubular stands, e.g., near ground level.', 'A lower racking arm may be provided to control movement of the lower ends of tubular stands and/or casing while being moved between the stand hand-off position and their racked position on the platform.', 'In some embodiments, movements of the lower racking arm are controlled to match movements of the upper racking arm to maintain the tubular stands in a vertical orientation.', 'In some embodiments, a lower stabilizing arm may be provided at the drill floor level, e.g., for guiding the lower portion of casing, drilling tubulars, and stands of the drilling tubulars between the catwalk, mousehole, and stand hand-off and well center positions.', 'In some embodiments, a tubular delivery arm can travel vertically along the structure of the same drilling mast as the top drive, e.g., with lifting capability less than that of the top drive, e.g., sufficient to hoist a tubular stand of drill pipe or drill collars.', 'The tubular delivery arm can move tubular stands vertically and horizontally, e.g., in the drawworks to V-door direction, reaching positions that may include the centerline of the wellbore, a stand hand-off position, a mousehole, and a catwalk.', 'In some embodiments, a conventional non-retractable top drive may be used in conjunction with the tubular delivery arm and/or the stand hand-off position, with pauses to avoid conflict between the non-retractable top drive and the tubular delivery arm.', 'In some disclosed embodiments, tubular stand hoisting from the stand hand-off position and delivery to well center is accomplished by the tubular delivery arm, and drill string hoisting and lowering is accomplished by the retractable top drive.', 'The retractable top drive and tubular delivery arm can pass each other in relative vertical movement on the same mast.', 'Retraction capability of the retractable top drive, and tilt and/or rotation control of the tubular delivery arm, and compatible geometry of each may permit them to pass one another without conflict.', 'In some embodiments, either or both the top drive and the tubular delivery arm may be sufficiently retractable from the well center position, such that the top drive and the tubular delivery arm may, when one (or both) of them is retracted and the other is in the well center position, e.g., engaging a tubular in the well center position, be independently translated along the mast past one another.', 'In these embodiments, a tubular stand can be disconnected and hoisted away from the drill string suspended in the wellbore using the tubular delivery arm, while the retractable top drive is travelling downwards into position to grasp and lift the drill string for hoisting.', 'Similarly, a tubular stand can be positioned and stabbed over the wellbore with the tubular delivery arm, while the retractable top drive is travelling upwards into position above the stand for connection.', 'The simultaneous paths of the retractable top drive and tubular delivery arm may significantly reduce trip time.', 'In some embodiments, an iron roughneck (tubular connection machine) may be provided such as mounted to a rail on the drilling floor or attached to the end of a drill floor manipulating arm to move between a retracted position, the well center and the mousehole.', 'The iron roughneck can make-up and break-out tool joints, e.g., drill pipe, casing, and so on, over the well center and the mousehole.', 'A second iron roughneck may be provided to dedicate a first iron roughneck to connecting and disconnecting tubulars over the mousehole, and the second iron roughneck can be dedicated to connecting and disconnecting tubulars over the well center.', 'The disclosed embodiments provide a novel drilling rig system that may significantly reduce the time needed for tripping of drill pipe.', 'Some of the disclosed embodiments may further provide a system with one or more mechanically operative redundancies.', 'The following disclosure describes “tripping in” which means adding tubular stands on a racking module to the drill string to form the complete length of the drill string to the bottom of the well so that drilling may commence.', 'It will be appreciated by a person of ordinary skill that the procedure summarized below is generally reversed for tripping out of the well to remove tubular stands from the wellbore for orderly racking.', 'Although a configuration related to triples is being described herein, a person of ordinary skill in the art will understand that such description is by example only as the disclosed embodiments are not limited, and would apply equally to singles, doubles and fourables.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is an isometric view of an embodiment of the drilling rig system of the disclosed embodiments for a high trip rate drilling rig.\n \nFIG.', '2\n is a top view of the embodiment of \nFIG.', '1\n of the disclosed embodiments for a high trip rate drilling rig.\n \nFIG.', '3\n is an isometric cut-away view of the retractable top drive in a drilling mast as used in an embodiment of the high trip rate drilling rig.\n \nFIG.', '4\n is a side cut-away view of the retractable top drive, showing it positioned over the well center.\n \nFIG.', '5\n is a side cut-away view of the retractable top drive, showing it retracted from its position over the well center.\n \nFIG.', '6\n is an isometric simplified block diagram illustrating the transfer of reaction torque to the top drive, to the torque tube, to the travelling block to the dolly, and to the mast.\n \nFIG.', '7\n is a top view of the racking module, illustrating the operating envelope of the upper racking arm and the relationship of the stand hand-off position to the racking module, well center and mousehole, according to the embodiments disclosed.\n \nFIG.', '8\n is an isometric view of the racking module, illustrating the upper racking arm translating the alleyway and delivering the drill pipe to a stand hand-off position, according to the disclosed embodiments.\n \nFIG.', '9\n is an isometric view of an embodiment of an upper racking arm component of the racking module of the disclosed embodiments, illustrating rotation of the arm suspended from the bridge.\n \nFIG.', '10\n is an isometric break-out view of an embodiment of the racking module, illustrating the upper racking arm translating the alleyway and delivering the tubular stand to the stand hand-off position.\n \nFIG.', '11\n an isometric view of the racking module from the opposite side, illustrating the upper stand securing the tubular stand in position at the stand hand-off position, according to the embodiments disclosed.', 'FIG.', '11A\n is an isometric view of an embodiment of a tubular stand constraint, illustrating the carriage retracted and the clasp open.\n \nFIG.', '11B\n is an isometric view of an embodiment of a tubular stand constraint, illustrating the carriage extended and the clasp closed, as it would be to restrain a tubular stand.\n \nFIG.', '12\n is an isometric view of an embodiment of the tubular delivery arm component of the high trip rate drilling rig, shown having a free pivoting tubular clasp.\n \nFIG.', '12A\n is an isometric exploded view of the embodiment of the tubular delivery arm illustrated in \nFIG.', '12\n.\n \nFIG.', '13\n is an isometric view of another embodiment of the tubular delivery arm, having an incline controlled tubular clasp and an automatic box doping apparatus.', 'FIG.', '13A\n is an isometric exploded view of the tubular delivery arm of \nFIG.', '13\n.\n \nFIG.', '13B\n is a fully assembled isometric view of the tubular delivery arm illustrated in \nFIGS.', '13 and 13A\n.\n \nFIG.', '14\n is a side view of an embodiment of the tubular delivery arm, illustrating the range of the tubular delivery arm to position a tubular stand relative to positions of use on a drilling rig.\n \nFIG.', '14A\n is a side view of another embodiment of the tubular delivery arm illustrating the range of the tubular delivery arm to position a tubular stand relative to positions of use on a drilling rig.\n \nFIG.', '14B\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position to receive a section of drill pipe from the catwalk.\n \nFIG.', '14C\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '14B\n, illustrating the tubular delivery arm receiving a section of drill pipe from the catwalk.', 'FIG.', '14D\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned to receive a tubular stand from, or deliver a section of pipe to, the mousehole.\n \nFIG.', '14E\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position to receive (or deliver) a tubular stand at the stand hand-off position at the racking module.\n \nFIG.', '14F\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '7\n, illustrating the tubular delivery arm positioned over the stand hand-off position between the racking module and the mast, and having a tubular stand secured in the clasp.\n \nFIG.', '14G\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned over well center to deliver a tubular stand into a stump at the well center, and to release the tubular stand when secured by the top drive.\n \nFIG.', '15\n is an isometric view of the embodiment of the tubular delivery arm of FIG.', '13\n, in which a portion of the upper racking module is cut away to more clearly illustrate the tubular delivery arm articulated to the stand hand-off position clasping a tubular stand.', 'FIG.', '16\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '13\n, illustrating the tubular delivery arm articulated over the well center and handing a tubular stand to the top drive.\n \nFIG.', '16A\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '16\n, illustrating the tubular delivery arm articulated to reach a tubular stand held by an upper stand constraint component at the stand hand-off position.\n \nFIG.', '16B\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '16A\n, illustrating the upper stand constraint having released the tubular stand and the tubular delivery arm hoisting the tubular stand as the grease dispenser is lowered to spray grease into the box end of the tubular stand being lifted.\n \nFIG.', '16A\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '16\n, illustrating a closeup view of the tubular delivery arm connecting to a tubular stand at stand hand-off position.\n \nFIG.', '16B\n is an isometric view of the embodiment of tubular delivery arm of \nFIG.', '16A\n, illustrating the tubular delivery arm hoisting (or lowering) a tubular stand released (or to be constrained) by the upper stand constraint.', 'FIG.', '17\n is an isometric view of a lower stabilizing arm component according to the disclosed embodiments, illustrating the multiple extendable sections of the arm.\n \nFIG.', '18\n is a side view of the embodiment of \nFIG.', '16\n, illustrating positioning of the lower stabilizing arm to stabilize the lower portion of a tubular stand between a well center, mousehole, stand hand-off and catwalk position.\n \nFIG.', '19\n is an isometric view of the embodiment of \nFIG.', '18\n, illustrating the lower stabilizing arm capturing the lower end of a drill pipe section near the catwalk.', 'FIG.', '20\n is an isometric view of an embodiment of the lower stabilizing arm, illustrated secured to the lower end of a stand of drill pipe and stabbing it at the mousehole.\n \nFIG.', '21\n is an isometric view of an embodiment of an intermediate stand constraint, illustrated extended.\n \nFIG.', '22\n is an isometric view of the embodiment of the intermediate stand constraint of \nFIG.', '21\n, illustrating the intermediate stand constraint folded for transportation between drilling locations.', 'FIGS.', '23 through 32\n are isometric views that illustrate the high trip rate drilling rig of the disclosed embodiments in the process of moving tubular stands from a racked position and into the well, according to the disclosed embodiments.\n \nFIG.', '33\n is a top view of an embodiment of a setback platform of the tubular racking system of the disclosed embodiments.\n \nFIG.', '34\n is an isometric view of an embodiment of the setback platform of the tubular racking system of the disclosed embodiments.\n \nFIG.', '35\n is an isometric view of an upper racking module of the tubular racking system of the disclosed embodiments.\n \nFIG.', '36\n is an isometric view of the embodiment of \nFIG.', '35\n of the upper racking module of the tubular racking system of the disclosed embodiments.', 'FIG.', '37\n is an isometric view of an embodiment of a stand hand-off station of the disclosed embodiments.', 'The disclosed embodiments will become more readily understood from the following detailed description and appended claims when read in conjunction with the accompanying drawings in which like numerals represent like elements.', 'The drawings constitute a part of this specification and include embodiments that may be configured in various forms.', 'It is to be understood that in some instances various aspects of the disclosed embodiments may be shown exaggerated or enlarged to facilitate their understanding.', 'DETAILED DESCRIPTION', 'The following description is presented to enable any person skilled in the art to make and use the disclosed embodiments, and is provided in the context of an application and its requirements.', 'Various modifications to the disclosed embodiments will be apparent to those skilled in the art, and the general principles defined herein may be applied to other embodiments and applications without departing from the spirit and scope of the disclosed embodiments.', 'Thus, the disclosed embodiments are not intended to be limited to the embodiments shown, but is to be accorded the widest scope consistent with the principles and features disclosed herein.\n \nFIG.', '1\n is an isometric view of an embodiment of the drilling rig system of the disclosed embodiments for a high trip rate drilling rig \n1\n.', 'FIG.', '1\n illustrates drilling rig \n1\n having the conventional front portion of the drill floor removed, and placing well center \n30\n near to the edge of drill floor \n6\n.', 'In this configuration, a setback platform \n900\n is located beneath the level of drill floor \n6\n, and connected to base box sections of substructure \n2\n on the ground.', 'In this position, setback platform \n900\n is beneath racking module \n300\n such that tubular stands \n80\n (see \nFIG.', '33\n) located in racking module \n300\n will be resting on setback platform \n900\n.', 'Having setback platform \n900\n near ground level may reduce the required size of the side boxes of substructure \n2\n and thus the side box transport weight.', 'This configuration may also facilitate mitigation of the effects of wind against mast \n10\n.', 'In this configuration, racking module \n300\n is located lower on mast \n10\n of drilling rig \n1\n than on conventional land drilling rigs, since tubular stands \n80\n are not resting at the level of drill floor \n6\n.', 'As a result, a secondary hoisting means may elevate tubular stands \n80\n to reach the level of drill floor \n6\n, before they can be added to the drill string.', 'In some embodiments, a mousehole having a mousehole center \n40\n (see \nFIG.', '30\n) is located on the forward edge of drill floor \n6\n and extends downward beneath.', 'An intermediate stand constraint \n430\n may be located adjacent to drill floor \n6\n and centered over mousehole center \n40\n.', 'A stand hand-off position \n50\n is located on setback platform \n900\n, for example, and extends vertically upwards, unimpeded by another structure beneath racking module \n300\n.', 'A lower stand constraint \n440\n may be located on setback platform \n900\n and centerable over stand hand-off position \n50\n, which may be forward of, and in alignment with, well center \n30\n and mousehole center \n40\n.', 'FIG.', '2\n is a top view of the drilling rig \n1\n of \nFIG.', '1\n.', 'Racking module \n300\n has a frame \n302\n connected to a fingerboard assembly \n310\n (see \nFIG.', '7\n), which may, if desired, have columns of racking positions \n312\n aligned perpendicular to conventional alignment.', 'As so aligned, racking column positions \n312\n run in a V-door to drawworks direction.', 'Drilling masts generally have a mast front or V-door side, and an opposite mast rear or drawworks side.', "Perpendicular to these sides are the driller's side and opposite off-driller's side.", 'As seen in \nFIG.', '2\n, the racking positions for tubular stands \n80\n in racking module \n300\n align with space for racking tubular stands on setback platform \n900\n.', 'Racking module \n300\n and setback platform \n900\n can be size selected independent of the substructure \n2\n and mast \n10\n depending on the depth of the well to be drilled and the number of tubular stands \n80\n to be racked.', 'In some embodiments, drilling rig \n1\n is thus scalable.\n \nFIG.', '3\n is an isometric cut-away view of a retractable top drive assembly \n200\n in drilling mast \n10\n as used in an embodiment of drilling rig \n1\n.', 'Retractable top drive assembly \n200\n is generally comprised of a travelling block assembly (\n230\n, \n232\n), a top drive \n240\n, a pair of links \n252\n and an elevator \n250\n, along with other various components.', 'Retractable top drive assembly \n200\n may, for example, have a retractable dolly \n202\n that is mounted on guides \n17\n in mast \n10\n.', 'A first yoke \n210\n connects block assembly \n230\n, \n232\n to dolly \n202\n.', 'A second yoke \n212\n extends between dolly \n202\n and top drive \n240\n.', 'In the embodiment illustrated, guides \n17\n are proximate to the rear side \n14\n of mast \n10\n, and dolly \n202\n is vertically translatable on the length of guides \n17\n.', "In the embodiment illustrated, retractable top drive assembly \n200\n has a split block configuration including a driller's side block \n230\n and an off-driller's side block \n232\n.", 'This feature provides mast-well center path clearance additional to that obtained by the ability to retract dolly \n202\n.', 'The additional clearance may facilitate wire line access as well as facilitate avoiding conflict with a tubular delivery arm \n500\n (see \nFIG.', '12\n) when tilted for well center \n30\n alignment of a tubular stand \n80\n.', 'An actuator \n220\n extends between second yoke \n212\n and dolly \n202\n to facilitate controlled movement of top drive \n240\n between a well center \n30\n position and a retracted position.', 'Retractable top drive assembly \n200\n has a top drive \n240\n and a stabbing guide \n246\n.', 'Pivotal links \n252\n extend downward.', 'An automatic elevator \n250\n is attached to the ends of links \n252\n.', 'FIG.', '4\n is a side cut-away view of an embodiment of retractable top drive assembly \n200\n, showing it positioned over well center \n30\n.', 'Retractable top drive assembly \n200\n may optionally have a torque tube \n260\n that functions to transfer torque from retractable top drive assembly \n200\n to dolly \n202\n and there through to guides \n17\n and mast \n10\n.', '(See \nFIG.', '6\n).', 'FIG.', '5\n is a side cut-away view of the embodiment of retractable top drive assembly \n200\n in \nFIG.', '4\n, showing it retracted from its position over well center \n30\n to avoid contact with a tubular delivery arm \n500\n that vertically translates the same mast \n10\n as retractable top drive assembly \n200\n (see \nFIG.', '12\n).', 'FIG.', '6\n is an isometric cut-away view of an embodiment illustrating the force transmitted through torque tube \n260\n connected directly to the travel block assembly.', 'Torque tube \n260\n is solidly attached to the travelling block assembly, such as between block halves \n230\n and \n232\n, and thus connected to dolly \n202\n through yoke \n210\n and yoke \n212\n.', 'Torque may be encountered from make-up and break-out activity as well as drilling torque reacting from the drill bit and stabilizer engagement with the wellbore.', 'Torque tube \n260\n may be engaged to top drive \n240\n at torque tube bracket \n262\n in sliding relationship.', 'Top drive \n240\n is vertically separable from the travelling block assembly to accommodate different thread lengths in tubular couplings.', 'The sliding relationship of the connection at torque tube bracket \n262\n accommodates this movement.', "Slide pads \n208\n seen in the embodiment shown may be mounted on opposing ends of dolly \n202\n that extend outward in the driller's side and off-driller's side directions.", 'Each dolly end may have an adjustment pad between the end and slide pad \n208\n.', 'Slide pads \n208\n engage guides \n17\n to guide retractable top drive assembly \n200\n up and down the vertical length of mast \n10\n.', 'Optional adjustment pads may permit precise centering and alignment of dolly \n202\n on mast \n10\n, or a roller mechanism may be used.', 'In \nFIG.', '6\n, retractable top drive assembly \n200\n is positioned over well center \n30\n, and tubular stand \n80\n is right rotated by top drive \n240\n as shown by T\n1\n.', 'When drilling related friction at the drill bit, stabilizers and bottom hole assembly components, is overcome to drill ahead, reactive torque T\n2\n at top drive \n240\n may be transmitted to torque tube \n260\n through opposite forces F\n1\n and F\n2\n at bracket \n262\n.', 'Torque tube \n260\n transmits this torque to second yoke \n212\n, which transmits the force to connected dolly \n202\n, which in turn transmits the force to guides \n17\n of mast \n10\n through slide pads \n208\n.', 'By this configuration, torque tube \n260\n is extended and retracted with top drive \n240\n and the travelling block.', 'By firmly connecting torque tube \n260\n directly to the travelling block and using a single dolly at top drive \n240\n, retractable top drive assembly \n200\n can accommodate a tubular delivery arm \n500\n on common mast \n10\n without interference.\n \nFIG.', '7\n is a top view of racking module \n300\n, illustrating an operating envelope of upper racking arm \n350\n, and the relationship of stand hand-off position \n50\n to racking module \n300\n, in some embodiments.', 'Fingerboard assembly \n310\n may provide a rectangular grid of multiple tubular storage positions between its fingers.', 'Fingerboard assembly \n310\n has racking column positions \n312\n optionally aligned in the V-door to drawworks direction, opening in the direction of the mast \n10\n, facing the opening on the front side of the mast, and a transverse alleyway \n316\n connecting to the stand hand-off position \n50\n.', 'In some embodiments, an upper racking arm \n350\n can position its gripper \n382\n (see \nFIG.', '10\n) over the tubular racking column positions \n312\n in the grid to hoist or set down a tubular stand \n80\n and transport it along the column to or from the alleyway \n316\n.', 'In \nFIG.', '7\n, upper racking arm \n350\n is shown positioned to engage a stand to travel between the racking column position \n312\n toward alleyway \n316\n, or positioned to set down the stand in the racking column position in the case of tripping out, for example.', 'An optional second upper racking arm \n351\n, also having the capability of positioning its gripper \n382\n over the tubular racking column position \n312\n, may provide redundancy and/or speed up the process of moving tubular stands \n80\n between the racking positions \n312\n and the stand hand-off position \n50\n.\n \nFIG.', '8\n is an isometric view of racking module \n300\n component of the disclosed embodiments, illustrating upper racking arm \n350\n hoisting tubular stand \n80\n and traversing alleyway \n316\n towards stand hand-off position \n50\n, or away from the stand hand-off position \n50\n to be transported into racking column position \n312\n.\n \nFIG.', '9\n is an isometric view partially cut away to show an embodiment of racking module \n300\n in which upper racking arm \n350\n is hoisting tubular stand \n80\n in the stand hand-off position \n50\n, after retrieving it from racking column position \n312\n of fingerboard assembly \n310\n (see \nFIG.', '7\n) and carrying it along the alleyway \n316\n (see \nFIG.', '8\n) in preparation for setting down the tubular stand \n80\n in the stand hand-off position \n50\n (see \nFIG.', '11\n); or after retrieving tubular stand \n80\n from the stand hand-off position \n50\n (see \nFIG.', '11\n) in preparation for traversing alleyway \n316\n (see \nFIG.', '8\n)', 'to deliver the tubular stand to a racking column position \n312\n of fingerboard assembly \n310\n (see \nFIG.', '7\n).', 'After setting down a tubular stand \n80\n, either in the stand hand-off position \n50\n (\nFIG.', '9\n) or in the racking column position \n312\n (\nFIG.', '7\n), the upper racking arm \n350\n can traverse over the fingerboard to return to retrieve and hoist a next one of the tubular stands.', 'The retrieval and delivery of tubular stands \n80\n between the racking column position \n312\n and the stand hand-off position \n50\n is repeated as needed to rack or unrack the tubular stands.', 'FIG.', '10\n is an isometric view of an embodiment of upper racking arm \n350\n, illustrating the travel range and rotation of gripper \n382\n connected to sleeve \n380\n and arm \n370\n, as suspended from bridge \n358\n.', 'Upper racking arm \n350\n may have a bridge \n358\n spanning an inner runway \n304\n and an outer runway \n306\n supported on frame \n302\n.', 'Bridge \n358\n may have an outer roller assembly \n354\n and an inner roller assembly \n356\n for supporting movement of upper racking arm \n350\n along runways \n306\n and \n304\n, respectively (see \nFIG.', '11\n), on racking module \n300\n.', 'In some embodiments, an outer pinion drive \n366\n extends from an outer end of bridge \n358\n, and an inner pinion drive \n368\n extends proximate to the inner end (mast side) of bridge \n358\n.', 'Pinion drives \n366\n and \n368\n engage complementary geared racks on runways \n306\n and \n304\n, and these may be electronically synchronized to inhibit crabbing.', 'Actuation of pinion drives \n366\n and \n368\n permits upper racking arm \n350\n to horizontally translate the length of racking module \n300\n.', 'In some embodiments, a trolley \n360\n is translatably mounted to bridge \n358\n.', 'The position of trolley \n360\n may be controlled by a rack and pinion drive system, a capstan cable drive system, and so on.', 'In the embodiments illustrated, trolley pinion drive \n364\n engages a complementary geared rack on bridge \n358\n.', 'Actuation of the drive \n364\n permits trolley \n360\n to horizontally translate the length of bridge \n358\n.', 'In some embodiments, a rotary actuator \n362\n may be mounted to trolley \n360\n, and an arm \n370\n may be connected at an offset to the rotary actuator and thus trolley \n360\n.', 'Gripper \n382\n extends perpendicularly in relation to the lower end of arm \n370\n, and in the same plane as the offset.', 'Gripper \n382\n is attached to sleeve \n380\n for gripping tubular stands \n80\n (see \nFIG.', '9\n) racked in racking module \n300\n.', 'Sleeve \n380\n is mounted to arm \n370\n in vertically translatable relation, as further described below, and actuation of the rotary actuator \n362\n causes rotation of gripper \n382\n.', 'In some embodiments, a centerline of the rotary actuator \n362\n may extend downward from the center of rotation of as a common axis with the centerline of tubular stand \n80\n gripped by gripper \n382\n, such that rotation of gripper \n382\n results in centered rotation of tubular stands \n80\n without lateral movement.', 'The ghost lines of this view show arm \n370\n and gripper \n382\n rotated 90 degrees by rotary actuator \n362\n.', 'As shown, and as described above, the centerline of a stand of tubular stand \n80\n gripped by upper racking arm \n350\n is maintained in its lateral position, without lateral movement, when arm \n370\n is rotated.', 'As stated above, sleeve \n380\n may be mounted to arm \n370\n in vertically translatable relation, such as by slide bearings, rollers, or other method.', 'In the embodiment illustrated, a tandem cylinder assembly \n372\n is connected between arm \n370\n and sleeve \n380\n.', 'Tandem cylinder assembly \n372\n comprises a counterbalance cylinder and a lift cylinder.', 'Actuation of the lift cylinder is operator controllable with conventional hydraulic controls.', 'Tubular stand \n80\n is hoisted by retraction of the lift cylinder.', 'The counterbalance cylinder of the tandem cylinder assembly \n372\n is in the extended position when there is no load on gripper \n382\n, and when tubular stand \n80\n is set down, the counterbalance cylinder retracts to provide a positive indication of set down of tubular stand \n80\n.', 'Set down retraction of the counterbalance cylinder is measured by a transducer (not shown) such as a linear position transducer.', 'The transducer provides this feedback to prevent destructive lateral movement of tubular stand \n80\n before it has been lifted.\n \nFIG.', '11\n is an isometric view of an embodiment of the racking module \n300\n of \nFIG.', '7\n and the upper racking arm \n350\n of \nFIG.', '10\n, shown from the opposite side to illustrate clasp \n408\n of upper stand constraint \n420\n holding tubular stand \n80\n at stand hand-off position \n50\n.', 'Mast \n10\n is removed from this view for clarity.', 'With the tubular stand \n80\n constrained at stand hand-off position \n50\n, upper racking arm \n350\n is free to travel into position to hoist the next tubular stand \n80\n from the racking column position \n312\n, or to retrieve the tubular stand \n80\n from the stand hand-off position \n50\n in the case of tripping out, for example.', 'Upper stand constraint \n420\n can be used to secure tubular stand \n80\n in place at stand hand-off position \n50\n, e.g., restricting horizontal movement and optionally allowing vertical movement.', 'This facilitates delivery of tubular stand \n80\n and other tubular stands (such as drill collars) between the stand hand-off position \n50\n and upper racking arms \n350\n, \n351\n and also between the stand hand-off position \n50\n and tubular delivery arm \n500\n or retractable top drive assembly \n200\n.', 'In some embodiments, carriage \n404\n (\nFIG.', '11B\n) of upper stand constraint \n420\n can extend further towards well center \n30\n to tilt tubular stand \n80\n sufficiently to render it accessible to retractable top drive assembly \n200\n.', 'This allows upper stand constraint \n420\n to provide a redundant mechanism to tubular delivery arm \n500\n.', 'In some embodiments, upper stand constraint \n420\n may also be used to deliver certain drill collars and other heavy tubular stands \n80\n that may exceed the lifting capacity of tubular delivery arm \n500\n.\n \nFIG.', '11A\n is an isometric view of an embodiment of upper stand constraint \n420\n or lower stand constraint \n440\n, shown with carriage \n404\n (\nFIG.', '11\n) retracted.', 'Upper stand constraint \n420\n as shown in this embodiment can be positioned high above drill floor \n6\n, on racking module \n300\n (\nFIG.', '11\n).', 'The stand constraint \n440\n as shown in this embodiment can also be positioned below drill floor \n6\n, on setback platform \n900\n (see \nFIG.', '1\n).', 'In this configuration, the respective alleyway \n316\n, \n912\n (\nFIGS. 7, 33\n) is clear to allow a tubular stand \n80\n to be moved to or from the stand hand-off position \n50\n.\n \nFIG.', '11B\n is an isometric view of stand constraint \n420\n, \n440\n of \nFIG.', '11A\n, according to some embodiments, illustrating carriage \n404\n extended and clasp \n408\n closed, as it would be around a tubular stand \n80\n received in the stand hand-off position \n50\n.', 'Stand constraint \n420\n, \n440\n has a frame \n402\n.', 'A surface \n414\n forms the top of stand constraint \n420\n, \n440\n.', 'A carriage \n404\n is connected to frame \n402\n in an extendable relationship.', 'A carriage actuator \n406\n is connected between frame \n402\n and carriage \n404\n and is operable to extend and retract carriage \n404\n from frame \n402\n.', 'A clasp \n408\n is pivotally connected to the end of carriage \n404\n.', 'A clasp actuator is operable to open and close clasp \n408\n.', 'In some embodiments, clasp \n408\n can be self-centering to permit closure of clasp \n408\n around a full range of drilling tubulars \n80\n, including casing \n82\n, drill collars \n84\n and drill pipe \n86\n.', 'In some embodiments, clasp \n408\n slidably receives the tubular stand \n80\n and does not inhibit vertical movement, allowing the tubular stand \n80\n to be hoisted or set down while the clasp \n408\n is engaged.', 'In one embodiment, clasp \n408\n comprises opposing claws \n410\n.\n \nFIG.', '12\n is an isometric view of an embodiment of tubular delivery arm \n500\n of the disclosed embodiments, and \nFIG.', '12A\n is an isometric exploded view.', 'Retractable top drive assembly \n200\n provides a first tubular handling device that vertical translates mast \n10\n.', 'Tubular delivery arm \n500\n provides a second tubular handling functionality that may be, for example, vertically translatable along the same mast \n10\n of transportable land drilling rig \n1\n, without physically interfering with retractable top drive assembly \n200\n.', 'In some embodiments, tubular delivery arm \n500\n comprises a dolly \n510\n.', 'In one embodiment, adjustment pads \n514\n are attached to ends \n511\n and \n512\n of dolly \n510\n.', 'A slide pad \n516\n may be located on each adjustment pad \n514\n, and configured for sliding engagement with front side \n12\n of mast \n10\n of drilling rig \n1\n.', 'Adjustment pads \n514\n permit precise centering and alignment of dolly \n510\n on mast \n10\n.', 'In other embodiments, rollers, rack and pinion, or other arrangements may be incorporated in place of or in addition to slide pads \n516\n.', 'In some embodiments, an arm bracket \n520\n may extend outward from dolly \n510\n in the V-door direction.', 'An arm \n532\n or pair of arms \n532\n may be pivotally and rotationally connected to depend from arm bracket \n520\n.', 'An actuator bracket \n542\n is connected between arms \n532\n.', 'A tilt actuator \n540\n is pivotally connected between actuator bracket \n542\n and one of either dolly \n510\n or arm bracket \n520\n, e.g., drive plate \n530\n, to control the pivotal relationship between arm \n532\n and dolly \n510\n.', 'Rotary actuator \n522\n can be provided, according to some embodiments, for rotational control of arm \n532\n relative to dolly \n510\n.', 'A tubular clasp \n550\n is pivotally connected to the lower end of each arm \n532\n, to engage tubular stand \n80\n below the dolly \n510\n and provide a clear horizontal path between well center position \n30\n and stand hand-off position.', 'In an embodiment, rotary actuator \n522\n is mounted to arm bracket \n520\n and has a drive shaft extending through arm bracket \n520\n.', 'A drive plate \n530\n is rotatably connected to the underside of arm bracket \n520\n and connected to the drive shaft of rotary actuator \n522\n.', 'In this embodiment, clasp \n550\n may be optionally rotated to face tubular stand \n80\n at stand hand-off position \n50\n facing the V-door direction.', 'Flexibility in orientation of clasp \n550\n reduces manipulation of tubular delivery arm \n500\n to capture tubular stand \n80\n at stand hand-off position \n50\n by eliminating the need to further rise, tilt, pass, and clear tubular stand \n80\n.', 'A centerline of a tubular stand \n80\n secured in clasp \n550\n may be located between pivot connections \n534\n at the lower ends of each arm \n532\n.', 'In this manner, clasp \n550\n can be self-balancing to suspend a tubular stand \n80\n vertically, e.g., depending from the clasp \n550\n, without the need for additional angular controls or adjustments.', 'FIG.', '13\n is an isometric view of another embodiment of the tubular delivery arm \n500\n of the disclosed embodiments, and \nFIG.', '13A\n is an isometric exploded view.', 'In this embodiment, an incline actuator \n552\n is operative to control the angle of tubular clasp \n550\n relative to arm \n532\n. \nFIG.', '13\n illustrates arms \n532\n rotated and tilted to position clasp \n550\n over well center \n30\n as seen in \nFIGS.', '14 and 14A\n, and \nFIG.', '13B\n illustrates arms \n532\n rotated and tilted to position clasp \n550\n to receive a tubular stand \n80\n in the stand hand-off position \n50\n.', 'As also seen in \nFIG.', '14\n, extension of the incline actuator \n552\n inclines tubular clasp \n550\n to permit tilting of heavy tubular stands, such as large collars, and to position tubular clasp \n550\n properly for receiving a tubular section \n81\n or tubular stand \n80\n from catwalk \n600\n at catwalk position \n60\n.', 'Referring again to \nFIGS. 13, 13A, and 13B\n, in some embodiments, a grease dispenser \n560\n is extendably connected to a lower end of arm \n532\n above clasp \n550\n, and extendable to position grease dispenser \n560\n at least partially inside of a box connection of tubular stand \n80\n secured by clasp \n550\n.', 'A grease supply line may be connected between grease dispenser \n560\n and a grease reservoir \n570\n for this purpose.', 'In this embodiment, grease dispenser \n560\n may be actuated to deliver grease, such as by pressurized delivery to the interior of the box connection by either or both of spray nozzles or contact wipe application.', 'This embodiment permits grease to be stored in pressurized grease container \n570\n and strategically sprayed into a box connection of a tubular stand \n80\n held by clasp \n550\n prior to its movement over well center \n30\n for connection.', 'The automatic doping procedure improves safety by eliminating the manual application at the elevated position of tubular stand \n80\n.', 'FIGS.', '14 and 14A\n illustrate an exemplary lateral range of the motion of tubular delivery arm \n500\n to position a tubular stand \n80\n relative to positions of use on drilling rig \n1\n.', 'Tubular delivery arm \n500\n can retrieve and deliver a tubular stand \n80\n between well center \n30\n, mousehole position \n40\n, and stand hand-off position \n50\n, and optionally to catwalk position \n60\n, where clasp \n550\n can be inclined for retrieving or delivering tubular stand \n80\n from catwalk \n600\n.\n \nFIG.', '14B\n is a side view of one embodiment of tubular delivery arm \n500\n shown connected to drilling mast \n10\n of drilling rig \n1\n in catwalk position \n60\n (see \nFIG.', '3\n) to receive a tubular section \n2\n from catwalk \n600\n.', 'For this purpose, it is advantageous to have inclination control of clasp \n550\n, as disclosed in an embodiment shown in \nFIGS.', '11-14\n.\n \nFIG.', '14C\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '14B\n, receiving a tubular section \n2\n (drill pipe \n2\n) from catwalk \n600\n.', 'As seen in this view, tubular delivery arm \n500\n is articulated outwards by tilt actuator \n540\n to permit clasp \n550\n to attach to tubular section \n2\n.', 'From this position, tubular delivery arm \n500\n can be used to deliver tubular section \n2\n to the well center for make-up with the drill string in the well by an iron roughneck \n750\n shown positioned by a drill floor manipulating arm \n700\n.', 'In some embodiments, tubular delivery arm \n500\n can be used to build a stand with another drill pipe \n2\n secured in a mousehole \n40\n as shown in \nFIG.', '14D\n.', 'FIG.', '14E\n is a side view of an embodiment of tubular delivery arm \n500\n connected to a drilling mast \n10\n and in position to receive (or deliver) tubular stand \n80\n from stand hand-off position \n50\n at racking module \n300\n.\n \nFIG.', '14F\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '7\n, illustrating tubular delivery arm \n500\n articulated to stand hand-off position \n50\n between racking module \n300\n and mast \n10\n, and having tubular stand \n80\n secured in clasp \n550\n.', 'In one embodiment, slide pads \n516\n are slidably engageable with the front side \n12\n of drilling mast \n10\n to permit tubular delivery arm \n500\n to travel up and down along the front of mast \n10\n.', 'Rails may be attached to mast \n10\n for receiving slide pads \n516\n.', 'Tilt actuator \n540\n permits clasp \n550\n to swing over well center \n30\n, mousehole \n40\n, stand hand-off position \n50\n, and', 'if desired, catwalk \n60\n.\n \nFIG.', '14G\n is a side view of an embodiment of tubular delivery arm \n500\n connected to drilling mast \n10\n and in position to deliver tubular stand \n80\n to well center \n30\n to stab into a stump secured at well center \n30\n.', 'After stabbing, tubular delivery arm \n500\n can hand tubular stand \n80\n off to top drive assembly \n200\n.\n \nFIG.', '15\n is an isometric view of an embodiment of the tubular delivery arm \n500\n, in which a portion of the upper racking module is cut away to more clearly illustrate tubular delivery arm \n500\n articulated to stand hand-off position \n50\n between racking module \n300\n and mast \n10\n, and having a tubular stand \n80\n secured in clasp \n550\n.', 'Slide pads \n516\n are slidably engaged with the front side (V-door side) \n12\n of drilling mast \n10\n to permit tubular delivery arm \n500\n to vertically traverse front side \n12\n of mast \n10\n.', 'Tilt actuator \n540\n positions clasp \n550\n over stand hand-off position \n50\n.', 'Tubular delivery arm \n500\n may have a hoist connection \n580\n on dolly \n510\n for connection to a hoist at the crown block to facilitate movement of tubular delivery arm \n500\n vertically along mast \n10\n.\n \nFIG.', '16\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '14\n, illustrating tubular delivery arm \n500\n being articulated over well center \n30\n and handing tubular stand \n80\n off to retractable top drive assembly \n200\n.', 'Tubular delivery arm \n500\n is articulated by expansion of tilt actuator \n540\n, which inclines arms \n532\n into position such that the centerline of tubular stand \n80\n in clasp \n550\n is directly over well center \n30\n.', 'FIG.', '16A\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '16\n, illustrating tubular delivery arm \n500\n connected to tubular stand \n80\n at stand hand-off position \n50\n.', 'Tubular stand \n80\n is shown secured in the stand hand-off position by clasp \n408\n of upper stand constraint \n420\n beneath racking module \n300\n.', 'In this position, tubular delivery arm \n500\n may activate grease dispenser \n560\n to apply an appropriate amount of grease inside the box end of tubular stand \n80\n.\n \nFIG.', '16B\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '16A\n, illustrating tubular delivery arm \n500\n hoisting tubular stand \n80\n released by upper stand constraint \n420\n away from stand hand-off position \n50\n adjacent to racking module \n300\n.', 'In this manner, tubular delivery arm \n500\n is delivering and centering tubular stands \n80\n for top drive assembly \n200\n.', 'This design allows independent and simultaneous movement of tubular delivery arm \n500\n and top drive assembly \n200\n.', 'This combined capability provides accelerated trip speeds.', 'The limited capacity of tubular delivery arm \n500\n to lift tubular stands \n80\n of drill pipe drill collars allows the weight of tubular delivery arm \n500\n and mast \n10\n to be minimized.', 'Tubular delivery arm \n500\n can be raised [and lowered along the front \n12\n of mast \n10\n with an electric or hydraulic crown winch \n501\n (see \nFIG.', '14B\n).', 'If desired, tubular delivery arm \n500\n could be raised and lowered along mast \n10\n by means of a rack and pinion arrangement, with drive motors.', 'In this manner, tubular delivery arm \n500\n is delivering and stabbing tubular stands for retractable top drive assembly \n200\n.', 'This allows independent and simultaneous movement of retractable top drive assembly \n200\n to lower the drill string into the well (set slips), disengage the drill string, retract, and travel vertically up mast \n10\n while tubular delivery arm \n500\n is retrieving, centering, and stabbing the next tubular stand \n80\n.', 'This combined capability makes greatly accelerated trip speeds possible.', 'The limited capacity of tubular delivery arm \n500\n to lift only stands of drill pipe allows the weight of tubular delivery arm \n500\n to be minimized, if properly designed.', 'Tubular delivery arm \n500\n can be raised and lowered along mast \n10\n with only a relatively small electric or hydraulic crown winch \n501\n (see \nFIG.', '14B\n), e.g., having less lifting capacity than top drive \n200\n.', 'Winch \n500\n may be electronically controlled to position the delivery arm \n500\n along the mast \n10\n in the desired location in some embodiments.', 'FIG.', '17\n is an isometric view of an embodiment of a lower stabilizing arm \n800\n, that may be pivotally and/or rotatably mounted to the base for connection to a lower portion of a drilling mast, illustrating the rotation, pivot, and extension of an arm \n824\n.', 'In this embodiment, arm \n824\n is pivotally and rotationally connected to a mast bracket \n802\n.', 'An arm bracket \n806\n is rotationally connected to mast bracket \n802\n.', 'Arm \n824\n is pivotally connected to arm bracket \n806\n.', 'A pivot actuator \n864\n controls the pivotal movement of arm \n824\n relative to arm bracket \n806\n and thus mast bracket \n802\n.', 'A rotary table \n810\n controls the rotation of arm \n824\n relative to arm bracket \n806\n and thus mast bracket \n802\n.', 'Arm \n824\n is extendable as shown.', 'In this embodiment, a tubular guide \n870\n is rotational and pivotally connected to arm \n824\n.', 'A pivot actuator \n872\n controls the pivotal movement of tubular guide \n870\n relative to arm \n824\n.', 'A rotary actuator \n874\n controls the rotation of tubular guide \n870\n relative to arm \n824\n.', 'A pair of V-rollers \n862\n is provided to center a tubular stand \n80\n in guide \n870\n.', 'V-rollers \n862\n are operable by a roller actuator \n866\n.', 'The operation of the various rotational and pivot controls permits placement of tubular guide \n870\n over center of each of a wellbore \n30\n, a mousehole \n40\n, and a stand hand-off position \n50\n of drilling rig \n1\n as seen best in \nFIG.', '18\n.\n \nFIG.', '18\n is a top view of an embodiment of a lower stabilizing arm \n800\n, illustrating the change in positioning that occurs as lower stabilizing arm \n800\n relocates between the positions of well center \n30\n, mousehole \n40\n, stand hand-off position \n50\n, and catwalk \n60\n.\n \nFIG.', '19\n is an isometric view of an embodiment of lower stabilizing arm \n800\n connected to a leg \n20\n of drilling rig \n1\n, and illustrating lower stabilizing arm \n800\n capturing the lower end of tubular stand \n80\n and guiding tubular stand \n80\n to well center \n30\n for stabbing into drill string \n90\n.', 'Once stabbed, iron roughneck \n760\n will connect the tool joints.\n \nFIG.', '20\n illustrates an embodiment of lower stabilizing arm \n800\n secured to the lower end of tubular section \n81\n and preparing to stab it into the box connection of tubular section \n81\n located in mousehole \n40\n in a stand building procedure.', 'In \nFIG.', '20\n, tubular section \n81\n in mousehole \n40\n is secured to drill floor \n6\n by a tubular gripping \n409\n of intermediate stand constraint \n430\n.', 'As illustrated and described above, in some embodiments, lower stabilizing arm \n800\n can handle the lower end of tubular stand \n80\n and tubular sections \n81\n to safely permit the accelerated movement of tubular stands for reducing trip time and connection time, and to reduce exposure of workers on drill floor \n6\n.', 'Lower stabilizing arm \n800\n provides a means for locating the pin end of a hoisted tubular stand \n80\n into alignment with the box end of another for stabbing, or for other positional requirements such as catwalk retrieval, racking, mousehole insertion, and stand building.', 'Lower stabilizing arm \n800\n can facilitate accurately positioning tubular stand \n80\n at wellbore center \n30\n, mousehole \n40\n, and stand hand-off position \n50\n, etc.\n \nFIG.', '21\n is an isometric view of an embodiment of an intermediate stand constraint \n430\n.', 'Intermediate stand constraint \n430\n as shown can be connected at or immediately beneath drill floor \n6\n, as illustrated in \nFIG.', '1\n.', 'Intermediate stand constraint \n430\n has a frame \n433\n that may be configured as a single unit or as a pair, as illustrated.', 'A carriage \n435\n is extendably connected to frame \n433\n.', 'In the view illustrated, carriage \n435\n is extended from frame \n433\n.', 'A carriage actuator \n437\n is connected between frame \n433\n and carriage \n435\n and is operable to extend and retract carriage \n435\n from frame \n433\n.', 'In some embodiments, a clasp \n438\n is pivotally connected to the end of carriage \n435\n.', 'A clasp actuator is operable to open and close clasp \n438\n.', 'In some embodiments, clasp \n408\n can be self-centering to permit closure of clasp \n438\n around a full range of drilling tubulars \n80\n, including casing, drill collars and drill pipe.', 'Clasp \n438\n is not required to resist vertical movement of tubular stand \n80\n, which can be slidably received.', 'In one embodiment, clasp \n438\n comprises opposing claws.', 'In some embodiments, a tubular gripping assembly \n439\n is provided and can support the vertical load of tubular stand \n80\n to prevent downward vertical movement of tubular stand \n80\n.', 'In the embodiment shown, a transport bracket \n416\n is pivotally connected to carriage \n435\n.', 'An actuator \n418\n is provided to adjust the height of clasp \n438\n and gripper \n439\n.', 'If desired, the vertical actuator \n418\n may be used in the hand-off logic between the top drive assembly \n200\n and the intermediate stand constraint \n430\n over the mousehole \n40\n.', 'For example, actuator \n418\n can be hydraulically charged to hold it at an upper position; when the weight of a stand \n80\n is removed or applied, the actuator \n418\n may extend or retract, and with the integrated linear transducer in the cylinder \n418\n, signal a control system that the tubular weight is being taken by the top drive assembly and the gripper \n409\n can be opened to release the stand.', 'FIG.', '22\n is an isometric view of the embodiment of intermediate stand constraint \n430\n of \nFIG.', '21\n, illustrating carriage \n435\n retracted, and transport bracket pivoted into a transport position.', 'In operation, intermediate stand constraint \n430\n can facilitate stand building at mousehole \n40\n.', 'For example, intermediate stand constraint \n430\n may be used to vertically secure a first tubular section \n81\n.', 'A second tubular section \n81\n may then be positioned in series alignment by a hoisting mechanism such as the tubular delivery arm \n500\n.', 'With the use of an iron roughneck \n760\n (see \nFIG.', '19\n and \nFIG.', '20\n) movably mounted at drill floor \n6\n, the series connection between the first and second tubular sections \n81\n can be made to create a double tubular stand \n80\n.', 'Gripping assembly \n439\n can then be released to permit the double tubular stand \n80\n to be lowered into mousehole \n40\n.', 'Gripping assembly \n439\n can then be actuated to hold double tubular stand \n80\n in centered position, as a third tubular section \n81\n is hoisted above and stabbed into double tubular section \n81\n.', 'Once again, iron roughneck \n760\n on drill floor \n6\n can be used to connect the third tubular section \n81\n and form a triple tubular stand \n80\n.', 'FIGS.', '23-25\n illustrate an embodiment of high trip rate drilling rig \n1\n in the process of moving tubular stands \n80\n from racking module \n300\n to well center \n30\n for placement into the well.', 'To keep the drawings readable, some items mentioned below may not be numbered.', 'Please refer to \nFIGS.', '1-22\n for the additional detail.', 'It will be appreciated by a person of ordinary skill in the art that the procedure illustrated, although for “tripping in” in well, can be generally reversed to understand the procedure for “tripping out.”', 'FIG.', '23\n shows an embodiment of tubular delivery arm \n500\n on a front side \n12\n of mast \n10\n in an unarticulated position above racking module \n300\n on front side \n12\n of mast \n10\n.', 'In this position, tubular delivery arm \n500\n is above stand hand-off position \n50\n, and vertically above retractable top drive assembly \n200\n.', 'Tubular stand \n80\n has been connected to the drill string in the well (not visible) and is now a component of drill string \n90\n.', 'Tubular stand \n80\n and the rest of drill string \n90\n is held by retractable top drive assembly \n200\n, which is articulated into its well center \n30\n position, and is descending along mast \n10\n downward towards drill floor \n6\n.', 'In the embodiment of \nFIG.', '24\n, retractable top drive assembly \n200\n has descended further towards drill floor \n6\n as it lowers drill string \n90\n into the well.', 'Upper racking arm \n350\n is moving the next tubular stand \n80\n from its racked position towards stand hand-off position \n50\n.', 'In \nFIG.', '25\n, retractable top drive assembly \n200\n has neared the position where automatic slips will engage drill string \n90\n.', 'Tubular delivery arm \n500\n has moved lower down front side \n12\n of mast \n10\n near stand hand-off position \n50\n.', 'Upper racking arm \n350\n and lower racking arm \n950\n (see \nFIG.', '34\n) have delivered tubular stand \n80\n to stand hand-off position \n50\n.', 'Upper stand constraint \n420\n (see \nFIG.', '35\n) and lower stand constraint \n440\n have secured tubular stand \n80\n at stand hand-off position \n50\n.', 'In the embodiment of \nFIG.', '26\n, automatic slips have engaged drill string \n3\n and retractable top drive assembly \n200\n has released tubular stand \n80\n.', 'Retractable top drive assembly \n200\n has been moved into the retracted position of its return path behind well center \n30\n and proximate to the rear side \n14\n of mast \n10\n.', 'Tubular delivery arm \n500\n has articulated its arms \n532\n and its clasp \n550\n has latched onto tubular stand \n80\n.', 'Near drill floor \n6\n, lower stabilizing arm \n800\n has engaged the lower end of tubular stand \n80\n.', 'Upper stand constraint \n420\n (see \nFIG.', '35\n) has released tubular stand \n80\n.', 'In the embodiment of \nFIG.', '27\n, retractable top drive assembly \n200\n has begun a retracted ascent to the top of mast \n10\n.', 'Tubular delivery arm \n500\n has also risen along the front side \n12\n of mast \n10\n.', 'With this motion, clasp \n550\n of tubular delivery arm \n500\n has engaged the upset of tubular stand \n80\n and lifted tubular stand \n80\n vertically off setback platform \n900\n.', 'Lower stabilizing arm \n800\n is supporting the lower end of tubular stand \n80\n.', 'In the embodiment of \nFIG.', '28\n, retractable top drive assembly \n200\n continues its retracted ascent up mast \n10\n.', 'Tubular delivery arm \n500\n has elevated sufficiently to insure the bottom of tubular stand \n80\n will clear the stump of drill string \n90\n extending above drill floor \n6\n.', 'Since releasing tubular stand \n80\n at stand hand-off position \n50\n, upper racking arm \n350\n has been free to move to and secure the next drill stand in sequence.', 'In the embodiment of \nFIG.', '29\n, retractable top drive assembly \n200\n continues its retracted ascent up mast \n10\n.', 'Tubular delivery arm \n500\n has rotated 180 degrees, such that the opening on clasp \n550\n is facing well center \n30\n.', 'After rotation, tubular delivery arm \n500\n has been articulated to position tubular stand \n80\n over well center \n30\n.', 'In the embodiment of \nFIG.', '30\n, tubular delivery arm \n500\n has descended its path on the front side \n12\n of mast \n10\n until tubular stand \n80\n, with guidance from lower stabilizing arm \n800\n, has stabbed the pin connection of its lower tool joint into the box connection of the exposed tool joint of drill string \n90\n.', 'Tubular delivery arm \n500\n continues to descend such that clasp \n550\n moves lower on tubular stand \n80\n to make room for retractable top drive assembly \n200\n, while maintaining lateral positioning and stabilizing the upper end of the stand \n80\n.', 'Retractable top drive assembly \n200\n has risen to a position on mast \n10\n that is fully above tubular delivery arm \n500\n.', 'Having cleared tubular delivery arm \n500\n and tubular stand \n80\n in its ascent, retractable top drive assembly \n200\n has expanded actuator \n220\n to extend retractable top drive assembly \n200\n to its well center \n30\n position, directly over tubular stand \n80\n, and is now descending to engage the top of tubular stand \n80\n.', 'In the embodiment of \nFIG.', '31\n, retractable top drive assembly \n200\n has engaged tubular stand \n80\n as centered by tubular delivery arm \n500\n at the top and lower stabilizing arm \n800\n at the bottom.', 'Retractable top drive assembly \n200\n can now rotate to make-up and fully torque the connection.', 'An iron roughneck at drill floor \n6\n may be used to secure the connection.', 'In the embodiment of \nFIG.', '32\n, lower stabilizing arm \n800\n and tubular delivery arm \n500\n have released tubular stand \n80\n and retracted from well center \n30\n.', 'In the non-actuated position, tubular delivery arm \n500\n has rotated to allow clasp \n550\n to again face stand hand-off position \n50\n in anticipation of receiving the next tubular stand \n80\n.', 'Retractable top drive assembly \n200\n now supports the weight of the drill string as the automatic slips have also released, and retractable top drive assembly \n200\n is beginning its descent to lower drill string \n90\n into the wellbore.\n \nFIG.', '33\n is a top view of an embodiment of setback platform \n900\n on which the tubular stands \n80\n are stacked in accordance with their respective positions in the fingerboard assembly \n310\n.', 'Drilling rig \n1\n, catwalk \n600\n and tubular stands \n80\n are removed for clarity.', 'This embodiment illustrates the relationship between well center \n30\n, mousehole \n40\n, and stand hand-off position \n50\n.', 'As seen in this view, an alleyway \n912\n is provided on the front edge of setback platform \n900\n.', 'Stand hand-off position \n50\n is located in the platform alleyway \n912\n, in alignment with mousehole \n40\n and well center \n30\n.', 'A pair of lower racking arms \n950\n is also located in alleyway \n912\n.\n \nFIG.', '34\n is an isometric view of an embodiment of setback platform \n900\n of the tubular racking system of the disclosed embodiments.', 'Setback platform \n900\n comprises platform \n910\n for vertical storage of tubular stands \n80\n.', 'Platform \n910\n has a mast side and an opposite catwalk side.', 'Alleyway \n912\n extends along the mast side of platform \n910\n.', 'Alleyway \n912\n is offset below platform \n910\n.', 'Stand hand-off position \n50\n is located on alleyway \n912\n.', 'A geared rail \n914\n is affixed to alleyway \n912\n.', 'A lower racking arm \n950\n is provided, having a base \n952\n translatably connected to the rail \n914\n.', 'A lower racking frame \n970\n is connected to the base \n952\n in rotatable and pivotal relation.', 'A lower racking arm member \n980\n is pivotally connected to the frame \n970\n, and a clasp \n990\n is pivotally connected to the arm member \n980\n.', 'FIG.', '35\n is an isometric view of an embodiment of upper racking module \n300\n illustrating tubular stand \n80\n held at stand hand-off position \n50\n by upper stand constraint \n420\n, and engaged by upper racking arm \n350\n and by lower racking arm \n950\n.', 'Optional engagement with lower stand constraint \n440\n is not shown.', 'Lower racking arm \n950\n in some embodiments can allow the lower end of the stand \n80\n to rotate freely on the centerline of tubular stand \n80\n, e.g., and the arm \n950\n can thus follow upper racking arm \n350\n between stand hand-off position \n50\n and any racking position in racking module \n300\n, while keeping tubular stand \n80\n vertical.\n \nFIG.', '36\n is an isometric view illustrating an embodiment of tubular stand \n80\n supported vertically by upper racking arm \n350\n and held at its lower end by lower racking arm \n950\n, and extended to its designated racking position.\n \nFIG.', '37\n is an isometric view of an embodiment of a stand hand-off station \n450\n.', 'Referring to the embodiments illustrated in \nFIGS.', '34-36\n, stand hand-off station \n450\n is located at stand hand-off position \n50\n, in alleyway \n912\n.', 'Alleyway \n912\n is set vertically below surface \n910\n.', 'This permits positioning of stand hand-off station \n450\n below surface \n910\n so that tubular stand \n80\n need not be raised a significant distance by upper racking arm \n350\n to achieve access to stand hand-off station \n450\n.', 'As shown in the embodiment of \nFIG.', '37\n, stand hand-off station \n450\n has a base \n452\n.', 'An expandable chamber assembly \n470\n comprises a lower chamber \n472\n connected to base \n452\n, and an upper chamber \n474\n positioned in concentric relationship to lower chamber \n472\n.', 'A chamber actuator \n458\n is connected between lower chamber \n472\n and upper chamber \n474\n.', 'A stage \n454\n is located inside chamber assembly \n470\n.', 'Stage \n454\n is receivable of the threaded pin end of tubular stand \n80\n.', 'An elastomeric seal \n460\n is located over a top end of upper chamber \n474\n.', 'Seal \n460\n has an opening for receiving the threaded pin end of tubular stand \n80\n.', 'In one embodiment, a grease nozzle \n462\n is directed towards the interior of chamber assembly \n470\n.', 'A grease supply line \n464\n is connected to grease nozzle \n462\n for supplying pressurized grease to grease nozzle \n462\n.', 'In one embodiment, a wash nozzle \n466\n is directed towards the interior of chamber assembly \n470\n.', 'A wash supply line \n468\n is connected to wash nozzle \n466\n for supplying pressurized washing fluid to wash nozzle \n466\n.', 'A drain is connected to the interior of chamber assembly \n470\n for collection and removal of wash residue.', 'In operation, chamber actuator \n458\n is in the contracted position.', 'The threaded pin end of tubular stand \n80\n is lowered through the opening of seal \n460\n and onto stage \n454\n, which receives and supports the weight of tubular stand \n80\n.', 'Chamber actuator \n458\n is actuated to raise upper chamber \n474\n upwards to a proper height to cover the threads of the pin connection.', 'In this position, a wash cycle may be activated in which a washing fluid is provided through wash supply line \n468\n and is sprayed through wash nozzle \n466\n onto the threaded pin portion of tubular stand \n80\n.', 'Residual wash fluid passes through drain \n456\n for recycling or disposal.', 'Alternatively, or subsequently, a doping cycle may be activated in which grease is provided through grease supply line \n464\n and is sprayed through grease nozzle \n462\n onto the threaded pin portion of tubular stand \n80\n.', 'This step is intended to replace the manual doping of the threaded connection prior to threading the connection into the box end of another tubular stand \n80\n.', 'EMBODIMENTS LISTING\n \nAccordingly, the instant disclosure relates to the following embodiments: \n \n \n \n1.', 'A drilling rig [\n1\n] comprising: \n \na top drive assembly', '[\n200\n] vertically translatable along a mast [\n10\n] of the drilling rig [\n1\n];', 'a tubular delivery arm [\n500\n] vertically translatable along the mast', '[\n10\n]; and\n \nthe tubular delivery arm [\n500\n]', 'having a tubular clasp [\n550\n] that is movable between a well center position [\n30\n] over a well center and a second position [\n50\n] forward of the well center position.', '2.', 'The drilling rig of Embodiment 1, further comprising: the top drive assembly and tubular delivery arm having non-conflicting vertical paths.', '3.', 'The drilling rig of Embodiment 1, further comprising: \n \nthe tubular clasp of the tubular delivery arm movable between the well center position and a mousehole position forward of the well center position.\n \n \n \n4.', 'The drilling rig of Embodiment 1, further comprising: \n \nthe tubular clasp of the tubular delivery arm movable between the well center position and a stand hand-off position forward of the well center position.\n \n \n \n5.', 'The drilling rig of Embodiment 1, further comprising: \n \nthe tubular clasp of the tubular delivery arm movable between the well center position and a catwalk position forward of the well center position.', '6.', 'The drilling rig of Embodiment 1, further comprising: \n \nthe top drive assembly being vertically translatable along a first path over the well center and along a second path rearward to a drawworks side of well center.', '7.', 'The drilling rig of Embodiment 1, further comprising: the top drive assembly being horizontally movable between the well center position over the well center and a retracted position rearward to a drawworks side of the well center position.\n \n8.', 'The drilling rig of Embodiment 7, the top drive assembly further comprising: \n \na dolly translatably connected to the mast;\n \na travelling block assembly;\n \na top drive suspended from the travelling block assembly;\n \na yoke pivotally connecting the travelling block to the dolly;\n \nan extendable actuator connected between the dolly and the yoke;\n \na torque tube rigidly connected to the travelling block;\n \nthe torque tube connected to the top drive in vertically slidable relation;\n \nwherein extension of the actuator pivots the first yoke to extend the travelling block and top drive away from the dolly to a position over a well center; and\n \nwherein retraction of the actuator pivots the first yoke to retract the travelling block towards the dolly to a position away from the well center.', '9.', 'The drilling rig of Embodiment 8, further comprising: \n \nwherein torque reactions of a drill string responding to rotation by the top drive are transferred from the top drive to the torque tube, from the torque tube to the travelling block, from the travelling block to the dolly, and from the dolly to the mast.\n \n \n \n10.', 'The drilling rig of Embodiment 1, the tubular delivery arm further comprising: \n \na dolly translatably connected to the mast;\n \nan arm rotatably and pivotally connected to the dolly at its upper end; and\n \nthe tubular clasp pivotally connected to the arm at its lower end.\n \n \n \n11.', 'The drilling rig of Embodiment 10, further comprising: \n \nan inclination actuator pivotally connected between the arm and the clasp.\n \n \n \n12.', 'The drilling rig of Embodiment 1, further comprising: \n \na racking module connected to the drilling rig mast, the racking module comprising: \n \na frame;\n \na fingerboard assembly connected to the frame having columns receivable of tubular stands, optionally with the columns oriented in a direction towards the mast;\n \na fingerboard alleyway connecting the columns on a mast side of the columns; and\n \n \n \nan upper racking arm comprising: \n \na bridge translatably connected to the frame in translatable relation;\n \nan arm connected to the bridge in rotatable and translatable relation; and\n \na gripper connected to the arm in vertically translatable relation.', '13.', 'The drilling rig of Embodiment 12, further comprising: \n \na setback platform module comprising: \n \na platform positioned beneath the fingerboard assembly;\n \na platform alleyway', '[\n912\n] beneath the fingerboard alleyway of the racking module;\n \n \n \na lower racking arm comprising: \n \na base connected to the alleyway in translatable relation;\n \na frame connected to the base in rotatable and pivotal relation;\n \nan arm pivotally connected to the frame; and\n \na clasp pivotally connected to the arm.', '14.', 'The drilling rig of Embodiment 13, further comprising: a stand hand-off position located on a mast side of the platform and extending vertically upwards.', '15.', 'A method of moving tubular stands [\n80\n] from a racked position on a setback platform and in a racking module [\n300\n] to a drill string [\n90\n] at the drill floor', '[\n6\n] of a drilling rig [\n1\n], comprising the steps of: \n \nclasping a lower portion of a tubular stand [\n80\n] resting on the setback platform [\n900\n] with a lower racking arm [\n950\n];\n \nhoisting the tubular stand [\n80\n] with an upper racking arm [\n350\n] on a racking module connected to a mast', '[\n10\n] of the drilling rig [\n1\n];\n \nmoving the tubular stand [\n80\n] towards a stand hand-off position [\n50\n] with the upper racking arm [\n350\n];\n \nmoving the clasped lower end of the tubular stand [\n80\n] with the lower racking arm [\n950\n] along a path coincident to movement of the tubular stand [\n80\n] by the upper racking arm [\n350\n];\n \npositioning the tubular stand [\n80\n] above a stand hand-off position [\n50\n] located on the setback platform [\n900\n];\n \nlowering the tubular stand [\n80\n] to rest at the stand hand-off position [\n50\n];\n \nengaging an upper portion of the tubular stand [\n80\n] with an upper stand constraint [\n420\n];\n \ndisengaging the upper racking arm [\n350\n] and the lower racking arm [\n950\n] from the tubular stand [\n80\n];\n \nengaging the upper portion of the tubular stand [\n80\n] with a vertically translatable tubular delivery arm [\n500\n];\n \ndisengaging the tubular stand [\n80\n] from the upper stand constraint', '[\n420\n] and lower stand constraint', '[\n440\n];\n \nengaging a lower portion of the tubular stand [\n80\n] with a lower stabilizing arm [\n800\n]; hoisting the stand [\n80\n] with the tubular delivery arm [\n500\n]; and\n \nstabbing the tubular stand [\n80\n] into a drill string end extending above a rotary table on the drill floor [\n6\n].\n \n \n \n16.', 'The method of embodiment 15, further comprising: engaging a lower portion of the tubular stand with a lower stabilizing arm at the stand hand-off position.\n \n17.', 'The method of embodiment 15, further comprising: engaging a lower portion of the tubular stand with a lower stand constraint at the stand hand-off position.', '18.', 'The method of embodiment 15, further comprising: \n \nengaging the tubular stand with a tubular connection torqueing device located above the drill floor;\n \ndisengaging the lower stabilizing arm from the tubular stand;\n \ncoupling the stand to the drill string in the rotary table;\n \nlowering the position of engagement of the delivery arm on the stand;\n \nengaging the upper portion of the stand with an elevator of a top drive;\n \ndisengaging the delivery arm from the stand;\n \nhoisting the stand and connected drill string with the top drive assembly to release the drill string from its support at the drill floor; and\n \nlowering the stand and connected drill string into the wellbore with the top drive.\n \n \n \n19.', 'The method of embodiment 15, further comprising: \n \nclasping the tubular stand with an upper stand constraint when the tubular stand is at the stand hand-off position; and\n \nunclasping the tubular stand from the upper stand constraint when the tubular stand has been clasped by the tubular delivery arm.', '20.', 'A method of moving tubular stands [\n80\n] from a racked position to a drill string [\n90\n] at the drill floor', '[\n6\n] of a drilling rig [\n1\n], comprising the steps of: \n \ntransporting a tubular stand [\n80\n] from a racked position in a fingerboard [\n310\n] to a stand hand-off position [\n50\n] with an upper racking arm [\n350\n] on a racking module [\n300\n] connected to a mast [\n10\n] of the drilling rig [\n1\n];\n \nsetting the tubular stand [\n80\n] down at the stand hand-off position [\n50\n];\n \ntransporting a tubular stand [\n80\n] from the stand hand-off position [\n50\n] to a well center position [\n30\n] with a tubular delivery arm [\n500\n] translatably connected to the drilling mast', '[\n10\n];\n \nstabbing the tubular stand [\n80\n] into a stump of a drill string [\n90\n] at the well center [\n30\n];\n \nconnecting the tubular stand [\n80\n] to the drill string [\n90\n]; and\n \nlowering the drill string [\n90\n] with a top drive assembly [\n200\n] translatably connected to the drilling mast', '[\n10\n].\n \n \n \n21.', 'A drilling rig [\n1\n], comprising: \n \na substructure', '[\n2\n] comprising a pair of base boxes;\n \na drill floor', '[\n6\n] above the substructure [\n2\n];\n \na setback platform', '[\n900\n] below and forward of the drill floor [\n6\n];\n \na mast [\n10\n] extending vertically above the drill floor', '[\n6\n];\n \na top drive assembly [\n200\n] vertically translatable along the mast', '[\n10\n];\n \na tubular delivery arm [\n500\n] vertically translatable along the mast', '[\n10\n];\n \nthe tubular delivery arm [\n500\n] having a tubular clasp [\n550\n] movable between a well center position [\n30\n] over a well center and a stand hand-off position [\n50\n] forward of the well center position [\n30\n];\n \nthe top drive assembly', '[\n200\n] being vertically translatable along a first path over the well center and along a second path rearward of the first path;\n \na racking module [\n300\n] extending outward of the mast', '[\n10\n] above the set-back platform [\n900\n];\n \na stand hand-off position [\n50\n] located on the setback platform [\n900\n], and extending vertically upwards substantially between the mast [\n10\n] and the racking module [\n300\n]; and\n \nan upper stand constraint', '[\n420\n] connected beneath the racking module [\n300\n] and extendable rearward towards the mast', '[\n10\n].\n \n \n \n22.', 'The drilling rig of embodiment 21, further comprising: \n \nan intermediate stand constraint having a frame connected to the drilling rig at an edge of the V-door side of the drill floor;\n \na carriage connected to the frame in extendable relationship;\n \na carriage actuator connected between the frame and the carriage, and operable to extend or retract the carriage outward from the frame;\n \na tubular clasp attached to the extendable end of the carriage;\n \na clasp actuator connected to the tubular clasp, and operable to open or close the tubular clasp around a tubular stand;\n \na tubular gripper attached to the extendable end of the carriage; and\n \na gripper actuator connected to the tubular gripper, and operable to open or close the tubular gripper around a tubular stand.\n \n \n \nA1.', 'A drilling rig [\n1\n] comprising: \n \na top drive assembly', '[\n200\n] vertically translatable along a mast [\n10\n]; and\n \na tubular delivery arm [\n500\n] vertically translatable along the mast', '[\n10\n];\n \nthe tubular delivery arm [\n500\n] comprising a dolly [\n510\n] translatably connected to the mast, and an arm member', '[\n532\n] having an upper end rotatably and pivotally connected to the dolly, and a lower end pivotally connected to a tubular clasp [\n550\n] that is movable between a well center position [\n30\n] over a well center and a second position [\n50\n] forward of the well center position.\n \n \n \nA2.', 'The drilling rig of Embodiment A1, wherein the top drive assembly and tubular delivery arm have non-conflicting vertical paths.\n \nA3.', 'The drilling rig of Embodiment A1 or Embodiment A2, wherein the tubular clasp of the tubular delivery arm is movable between the well center position and a mousehole position forward of the well center position.\n \nA4.', 'The drilling rig of any of embodiments A1-A3, wherein the tubular clasp of the tubular delivery arm is movable between the well center position and a stand hand-off position forward of the well center position.\n \nA5.', 'The drilling rig of any of embodiments A1-A4, wherein the tubular clasp of the tubular delivery arm is movable between the well center position and a catwalk position forward of the well center position.', 'A6.', 'The drilling rig of any of embodiments A1-A5, wherein the top drive assembly having a top drive vertically translatable along a first path over the well center and along a second path rearward to a drawworks side of well center.', 'A7.', 'The drilling rig of any of embodiments A1-A6, wherein the top drive assembly has a top drive horizontally movable between the well center position over the well center and a retracted position rearward to a drawworks side of the well center position.', 'A8.', 'The drilling rig of any of embodiments A1-A7, the top drive assembly comprising: \n \na dolly translatably connected to the mast;\n \na travelling block assembly;\n \na top drive suspended from the travelling block assembly;\n \na yoke pivotally connecting the travelling block to the dolly;\n \nan extendable actuator connected between the dolly and the yoke;\n \na torque tube rigidly connected to the travelling block;\n \nthe torque tube connected to the top drive in vertically slidable relation;\n \nwherein extension of the actuator pivots the first yoke to extend the travelling block and top drive away from the dolly to a position over a well center; and\n \nwherein retraction of the actuator pivots the first yoke to retract the travelling block towards the dolly to a position away from the well center.\n \n \n \nA9.', 'The drilling rig of Embodiment A8, wherein torque reactions of a drill string responding to rotation by the top drive are transferred from the top drive to the torque tube, from the torque tube to the travelling block, from the travelling block to the dolly, and from the dolly to the mast.', 'A10.', 'The drilling rig of any of embodiments A1-A9, wherein the tubular clasp is engageable with an upset of a tubular stand [\n80\n] and moveable on the tubular stand below the upset.\n \nA11.', 'The drilling rig of any of embodiments A1-A10, the tubular delivery arm further comprising an arm bracket [\n520\n] extending outwardly from the dolly, and a drive plate', '[\n530\n] rotatably connected to the arm bracket, the upper end of the arm member pivotally connected to the drive plate.', 'A12.', 'The drilling rig of any of embodiments 1-10, the tubular delivery arm further comprising an arm bracket [\n520\n] extending outwardly from the dolly, a drive plate [\n530\n] rotatably connected to an underside of the arm bracket, and a rotary actuator [\n522\n] connected to the drive plate, the upper end of the arm member pivotally connected to the drive plate.', 'A13.', 'The drilling rig of embodiment A11 or embodiment A12, further comprising a tilt actuator [\n540\n] pivotally connected between the drive plate and the arm member.\n \nA14.', 'The drilling rig of any of embodiments A1-A13, further comprising: an incline actuator [\n552\n] pivotally connected between the arm and the clasp.\n \nA15.', 'The drilling rig of any of embodiments A1-A14, further comprising: \n \na racking module connected to the drilling rig mast, the racking module comprising: \n \na frame;\n \na fingerboard assembly connected to the frame having columns receivable of tubular stands, optionally with the columns oriented in a direction towards the mast;\n \na fingerboard alleyway connecting the columns on a mast side of the columns; and\n \n \n \nan upper racking arm comprising: \n \na bridge connected to the frame in translatable relation;\n \nan arm connected to the bridge in rotatable and translatable relation; and\n \na gripper connected to the arm in vertically translatable relation.\n \n \n \n \n \nA16.', 'The drilling rig of Embodiment A15, further comprising: \n \na setback platform module comprising: \n \na platform positioned beneath the fingerboard assembly;\n \na platform alleyway', '[\n912\n] beneath the fingerboard alleyway of the racking module;\n \n \n \na lower racking arm comprising: \n \na base connected to the alleyway in translatable relation;\n \na frame connected to the base in rotatable and pivotal relation;\n \nan arm pivotally connected to the frame; and\n \na clasp pivotally connected to the arm.', 'A17.', 'The drilling rig of any of embodiments A1-A16, further comprising: \n \na stand hand-off position [\n50\n] located on a mast side of a setback platform [\n900\n] and extending vertically upwards substantially between the mast and a racking module [\n300\n] extending outward of the mast above the setback platform.\n \n \n \nA18.', 'A drilling rig [\n1\n], comprising: \n \na substructure', '[\n2\n] comprising a pair of base boxes;\n \na drill floor', '[\n6\n] above the substructure [\n2\n];\n \na setback platform', '[\n900\n] below and forward of the drill floor [\n6\n];\n \na mast [\n10\n] extending vertically above the drill floor', '[\n6\n];\n \na top drive assembly [\n200\n] vertically translatable along the mast', '[\n10\n];\n \na tubular delivery arm [\n500\n] vertically translatable along the mast', '[\n10\n];\n \nthe tubular delivery arm [\n500\n] having a tubular clasp [\n550\n] movable between a well center position [\n30\n] over a well center and a stand hand-off position [\n50\n] forward of the well center position [\n30\n];\n \nthe top drive assembly', '[\n200\n] having a top drive vertically translatable along a first path over the well center and along a second path rearward of the first path;\n \na racking module [\n300\n] extending outward of the mast', '[\n10\n] above the set-back platform [\n900\n];\n \na stand hand-off position [\n50\n] located on the setback platform [\n900\n], and extending vertically upwards substantially between the mast [\n10\n] and the racking module [\n300\n]; and\n \nan upper stand constraint', '[\n420\n] connected beneath the racking module [\n300\n] and extendable rearward towards the mast', '[\n10\n].\n \n \n \nA19.', 'The drilling rig of embodiment A18, further comprising: \n \nan intermediate stand constraint having a frame connected to the drilling rig at an edge of the V-door side of the drill floor;\n \na carriage connected to the frame in extendable relationship;\n \na carriage actuator connected between the frame and the carriage, and operable to extend or retract the carriage outward from the frame;\n \na tubular clasp attached to the extendable end of the carriage;\n \na clasp actuator connected to the tubular clasp, and operable to open or close the tubular clasp around a tubular stand;\n \na tubular gripper attached to the extendable end of the carriage; and\n \na gripper actuator connected to the tubular gripper, and operable to open or close the tubular gripper around a tubular stand.\n \n \n \nA20.', 'A method for inserting tubulars in or removing tubulars from a drill string with the drilling rig [\n1\n] of any of embodiments A1-A17, comprising: \n \nvertically translating the top drive assembly [\n200\n] along mast', '[\n10\n];\n \nvertically translating the dolly of the tubular delivery arm [\n500\n] along the mast [\n10\n];\n \nrotating and pivoting the arm member [\n532\n] at the upper end with respect to the dolly to move the clasp between the well center position [\n30\n] and the second position [\n50\n];\n \nclasping a tubular stand with the tubular clasp; and\n \nunclasping the tubular stand to disengage the tubular clasp.\n \n \n \nA21.', 'The method of embodiment A20, further comprising: \n \nretracting a top drive of the top drive assembly from the well center position to pass the tubular delivery arm when the clasp is in the well center position.\n \n \n \nA22.', 'The method of embodiment A20 or embodiment A21, further comprising: \n \nretracting the clasp of the tubular delivery arm from the well center position to pass the top drive assembly when a top drive of the top drive assembly is in the well center position.\n \n \n \nA23.', 'The method of any of embodiments A20-A22, further comprising: \n \nengaging a tubular stand at an upset with the tubular clasp.\n \n \n \nA24.', 'The method of embodiment A23, further comprising: \n \nvertically translating the dolly of the tubular delivery arm to move the tubular clasp along the tubular stand below the upset.\n \n \n \nA25.', 'The method of embodiment A24, further comprising: \n \npositioning the top drive over the tubular stand in the well center position;\n \nclasping the tubular stand below the top drive with the tubular clasp; and\n \nengaging or disengaging the tubular stand and the top drive in the well center position.\n \n \n \nA26.', 'The method of embodiment A25, further comprising: \n \nlowering the tubular stand in the well center position with the tubular delivery arm to stab a pin connection of a lower tool joint of the tubular stand into a box connection of the drill string;\n \ncontinuing lowering of the tubular delivery arm to move the tubular clasp below the upset lower down on the tubular stand in the well center position;\n \nmoving the top drive over the tubular stand in the well center position;\n \nengaging the top drive and the tubular stand in the well center position; and\n \nunclasping the tubular stand engaged with the top drive from the tubular clasp.\n \n \n \nA27.', 'The method of embodiment A25, further comprising: \n \nclasping the tubular stand in the well center position with the tubular clasp below the top drive;\n \ndisengaging the top drive and the tubular stand in the well center position;\n \nretracting the top drive from the well center position; and\n \nmoving the tubular clasp up on the tubular stand in the well center position to engage the upset.\n \n \n \nA28.', 'The method of any of embodiments A20-A27, further comprising: \n \na first tubular handling function to transport the tubular stands in and out of a setback position on a setback platform;\n \na second tubular handling function to deliver the tubular stands to and from the well center position, wherein the second tubular handling function comprises: \n \nthe vertical translation of the top drive assembly [\n200\n] along the mast', '[\n10\n];\n \nthe vertical translation of the dolly of the tubular delivery arm [\n500\n] along the mast', '[\n10\n];\n \nthe rotation and pivoting of the arm member [\n532\n]; and\n \nthe clasping and unclasping of the tubular stands with the tubular clasp;\n \n \n \nsetting down the tubular stands in a stand hand-off position at an intersection between the first and second functions; and\n \nexchanging the tubular stands between the first and second functions at the stand hand-off position.', 'A29.', 'A method of moving tubular stands [\n80\n] from a racked position on a setback platform [\n900\n] and in a racking module [\n300\n] to a drill string [\n90\n] at the drill floor', '[\n6\n] of a drilling rig [\n1\n], comprising the steps of: \n \nclasping a lower portion of a tubular stand [\n80\n] resting on the setback platform [\n900\n] with a lower racking arm [\n950\n];\n \nhoisting the tubular stand [\n80\n] with an upper racking arm [\n350\n] on a racking module [\n300\n] connected to a mast [\n10\n] of the drilling rig [\n1\n];\n \nmoving the tubular stand [\n80\n] towards a stand hand-off position [\n50\n] with the upper racking arm [\n350\n];\n \nmoving the clasped lower end of the tubular stand [\n80\n] with the lower racking arm [\n950\n] along a path coincident to movement of the tubular stand [\n80\n] by the upper racking arm [\n350\n];\n \npositioning the tubular stand [\n80\n] above a stand hand-off position [\n50\n] located on the setback platform [\n900\n];\n \nlowering the tubular stand [\n80\n] to rest at the stand hand-off position [\n50\n];\n \nengaging an upper portion of the tubular stand [\n80\n] with an upper stand constraint [\n420\n];\n \ndisengaging the upper racking arm [\n350\n] and the lower racking arm [\n950\n] from the tubular stand [\n80\n];\n \nengaging the upper portion of the tubular stand [\n80\n] with a vertically translatable tubular delivery arm [\n500\n];\n \ndisengaging the tubular stand [\n80\n] from the upper stand constraint', '[\n420\n] and lower stand constraint', '[\n440\n];\n \nengaging a lower portion of the tubular stand [\n80\n] with a lower stabilizing arm [\n800\n];\n \nhoisting the stand [\n80\n] with the tubular delivery arm [\n500\n]; and\n \nstabbing the tubular stand [\n80\n] into a drill string end extending above a rotary table', '[\n810\n] on the drill floor [\n6\n].\n \n \n \nA30.', 'The method of embodiment A29, further comprising: \n \nengaging a lower portion of the tubular stand with a lower stabilizing arm at the stand hand-off position.\n \n \n \nA31.', 'The method of embodiment A29 or embodiment A30, further comprising: \n \nengaging a lower portion of the tubular stand with a lower stand constraint at the stand hand-off position.\n \n \n \nA32.', 'The method of any of embodiments A29-A31, further comprising: \n \nengaging the tubular stand with a tubular connection torqueing device located above the drill floor;\n \ndisengaging the lower stabilizing arm from the tubular stand;\n \ncoupling the stand to the drill string in the rotary table;\n \nlowering the position of engagement of the delivery arm on the stand;\n \nengaging the upper portion of the stand with an elevator of a top drive;\n \ndisengaging the delivery arm from the stand;\n \nhoisting the stand and connected drill string with the top drive assembly to release the drill string from its support at the drill floor; and\n \nlowering the stand and connected drill string into the wellbore with the top drive.\n \n \n \nA33.', 'The method of any of embodiments A29-A32, further comprising: \n \nclasping the tubular stand with an upper stand constraint when the tubular stand is at the stand hand-off position; and\n \nunclasping the tubular stand from the upper stand constraint when the tubular stand has been clasped by the tubular delivery arm.', 'A34.', 'A method of moving tubular stands [\n80\n] from a racked position to a drill string [\n90\n] at the drill floor', '[\n6\n] of a drilling rig [\n1\n], comprising the steps of: \n \ntransporting a tubular stand [\n80\n] from a racked position in a fingerboard assembly [\n310\n] to a stand hand-off position [\n50\n] with an upper racking arm [\n350\n] on a racking module [\n300\n] connected to a mast [\n10\n] of the drilling rig [\n1\n];\n \nsetting the tubular stand [\n80\n] down at the stand hand-off position [\n50\n];\n \ntransporting a tubular stand [\n80\n] from the stand hand-off position [\n50\n] to a well center position [\n30\n] with a tubular delivery arm [\n500\n] translatably connected to the drilling mast', '[\n10\n];\n \nstabbing the tubular stand [\n80\n] into a stump of a drill string [\n90\n] at the well center [\n30\n];\n \nconnecting the tubular stand [\n80\n] to the drill string [\n90\n]; and\n \nlowering the drill string [\n90\n] with a top drive assembly [\n200\n] translatably connected to the drilling mast', '[\n10\n].\n \n \n \nB1.', 'A drilling rig, comprising: \n \nfirst function tubular handling equipment to transport tubular stands', '[\n80\n] in and out of a setback position on a setback platform [\n900\n];\n \nsecond function tubular handling equipment to deliver the tubular stands to and from a well center', '[\n30\n] over a well; and\n \na stand hand-off position between the first and second function tubular handling equipment to set down tubular stands for exchange at an intersection between the first function tubular equipment and the second function tubular equipment.\n \n \n \nB2.', 'A drilling rig [\n1\n], comprising: \n \nfirst function tubular handling equipment comprising an upper racking arm [\n350\n] over a racking module [\n300\n] and a setback platform', '[\n900\n], to transport tubular stands', '[\n80\n] in and out of a setback position on the setback platform;\n \nsecond function tubular handling equipment comprising a tubular delivery arm [\n500\n] to deliver the tubular stands to and from a well center position [\n30\n] over a well; and\n \na stand hand-off position [\n50\n] to set down tubular stands for exchange at an intersection between the first function tubular handling equipment and the second function tubular handling equipment.\n \n \n \nB3.', 'The drilling rig of embodiment B1 or embodiment B2, further comprising: \n \na mast; and\n \na retractable top drive assembly', '[\n200\n] vertically translatable along the mast;\n \nwherein the tubular delivery arm is vertically translatable along the mast and comprises a tubular clasp [\n550\n] movable between the well center position and the stand hand-off position;\n \nwherein the tubular clasp is engageable with an upper end of a depending one of the tubular stands for the delivery of the tubular stands between the well center position and the stand hand-off position; and\n \nwherein the tubular clasp is slidably engageable with the tubular stand below the upper end to clasp an upper portion of the tubular stand in the well center position below the upper end.\n \n \n \nB4.', 'The drilling rig of any of embodiments B1-B3, wherein the stand hand-off position is located on the setback platform.', 'B5.', 'The drilling rig of any of embodiments B1-B4, wherein the stand hand-off position extends vertically upwards substantially between a mast and a fingerboard assembly [\n310\n] of the racking module.\n \nB6.', 'The drilling rig of any of embodiments B1-B5, wherein the setback platform is offset beneath a drill floor [\n6\n].\n \nB7.', 'The drilling rig of any of embodiments B1-B6, further comprising a mousehole having a mousehole center', '[\n40\n] in line between the well center and the stand hand-off position.', 'B8.', 'The drilling rig of embodiment 7, further comprising a catwalk [\n60\n] in line with the stand hand-off position and the mousehole center.\n \nB9.', 'The drilling rig of any of embodiments B1-B8, further comprising a stand constraint', '[\n420\n, \n440\n] to secure one of the tubular stands in the stand hand-off position.', 'B10.', 'The drilling rig of any of embodiment B9, wherein the stand constraint comprises an upper stand constraint [\n420\n] connected to the racking module and extendable to the stand hand-off position.', 'B11.', 'The drilling rig of embodiment B9 or B10, wherein the stand constraint comprises a lower stand constraint', '[\n440\n] on the setback platform and centerable over the stand hand-off position.', 'B12.', 'The drilling rig of any of embodiments B9-B11, wherein the stand constraint comprises: \n \nan upper stand constraint', '[\n420\n] connected to the racking module and extendable to the stand hand-off position; and\n \na lower stand constraint', '[\n440\n] on the setback platform and centerable over the stand hand-off position;\n \nwherein the upper and lower stand constraints are engageable with respective upper and lower portions of the one tubular stand set down in the stand hand-off position to vertically orient the one tubular stand.', 'B13.', 'The drilling rig of any of embodiments B9-B12, wherein the stand constraint comprises: \n \na frame;\n \na carriage connected to the frame in extendable relationship;\n \na carriage actuator connected between the frame and the carriage, and operable to extend or retract the carriage outward from the frame;\n \na clasp attached to an extendable end of the carriage; and\n \na clasp actuator connected to the clasp, and operable to open or close the clasp around one of the tubular stands.\n \n \n \nB14.', 'The drilling rig of embodiment B13, wherein: \n \nthe tubular stand constraint is affixed to the racking module;\n \nthe racking module extends from a mast and comprises a plurality of columns of tubular racking locations, and a transfer row connecting the columns to the stand hand-off position;\n \nthe stand hand-off position intersects with the transfer row;\n \nthe carriage is extendable towards the mast to allow a center of the clasp to be centered over the stand hand-off position; and\n \nthe carriage is retractable away from the mast to remove the clasp from intersection with the transfer row.', 'B15.', 'The drilling rig of embodiment B13 or B14, wherein the frame has a platform located on the racking module centrally between the columns.', 'B16.', 'The drilling rig of any of embodiments B13-B15, wherein the carriage is extendable towards the mast to position a center of the clasp beyond the center of the stand hand-off position.\n \nB17.', 'The drilling rig of any of embodiments B13-B16, wherein the carriage is extendable towards the mast to position one of the tubular stands within a horizontal range of a top drive unit translatable on the mast.', 'B18.', 'The drilling rig of any of embodiments B9-B17, wherein: \n \nthe tubular stand constraint is affixed to the setback platform;\n \nthe setback platform is offset beneath a drill floor [\n6\n] and connected to a substructure of the drilling rig;\n \nthe setback platform comprises a surface for placing tubular stands, and an alleyway that is accessible to the surface;\n \nthe stand hand-off position is located on the alleyway;\n \nthe carriage is extendable towards the substructure to allow the clasp to be centered over the stand hand-off position; and\n \nthe carriage is retractable away from the substructure to remove the clasp from intersection with the alleyway.', 'B19.', 'The drilling rig of embodiment B18, wherein the carriage is extendable towards the mast to position the clasp beyond the center of the stand hand-off position.\n \nB20.', 'The drilling rig of embodiment B18, wherein the carriage is extendable towards the mast to position the clasp over a mousehole.\n \nB21.', 'The drilling rig of any of embodiments B9-B20, wherein the stand constraint further comprises: \n \na gripper assembly attached to an extendable end of the carriage;\n \na gripper assembly actuator connected to the gripper assembly, and operable to open or close the gripper assembly around a tubular stand;\n \nwherein the tubular stand constraint is affixed to a center section of the drilling rig on a V-door side;\n \nwherein the stand hand-off position is located on the setback platform;\n \nwherein a mousehole is located between the well center and the stand hand-off position;\n \nwherein the carriage is extendable to allow the stand constraint clasp and gripper assembly to be centered over the setback position; and\n \nwherein the carriage is retractable to allow the stand constraint clasp and gripper assembly to be centered over the mousehole.', 'B22.', 'The drilling rig of embodiment B21, wherein the clasp is a gripping device that inhibits vertical movement of the gripped tubular.\n \nB23.', 'The drilling rig of any of embodiments B1-B22, further comprising: \n \na stand hand-off station located at the stand hand-off position;\n \nthe stand hand-off station comprising; \n \na chamber for receiving a pin connection of one of the tubular stands; and\n \na stage inside the chamber receivable of the weight of the one tubular stand.\n \n \n \n \n \nB24.', 'The drilling rig of any of embodiments B1-B23, further comprising: \n \na stand hand-off station located at the stand hand-off position;\n \nthe stand hand-off station comprising: \n \na base connecting the stand hand-off station to the setback platform;\n \nan expandable chamber assembly comprising an upper chamber and a lower chamber;\n \nwherein the lower chamber is attached to the base;\n \nwherein the upper chamber is positioned in concentric relationship to the lower chamber;\n \nan actuator connected between the lower chamber and the upper chamber;\n \na stage located in the chamber assembly, the stage receivable of the lower end of one of the tubular stands; and\n \nan elastomeric seal over a top end of the upper chamber, the seal having an opening receivable of the one tubular stand.\n \n \n \n \n \nB25.', 'The drilling rig of any of embodiments B1-B24, wherein the tubular delivery arm comprises a tubular clasp', '[\n550\n] movable between the stand hand-off position and the well center position.', 'B26.', 'The drilling rig of embodiment B25, wherein the tubular delivery arm comprises a dolly translatably connected to the mast.\n \nB27.', 'The drilling rig of embodiment B26, wherein the tubular delivery arm further comprises an arm member', '[\n532\n] having an upper end rotatably and pivotally connected to the dolly, and a lower end pivotally connected to the tubular clasp.\n \nB28.', 'The drilling rig of any of embodiments B25-B27, wherein the tubular clasp of the tubular delivery arm is movable to a mousehole position forward of the well center position.', 'B29.', 'The drilling rig of any of embodiments B25-B28, wherein the tubular clasp of the tubular delivery arm is movable to a catwalk position forward of the stand hand-off position.\n \nB30.', 'The drilling rig of any of embodiments B25-B29, wherein the tubular clasp of the tubular delivery arm is engageable with an upper end or upset of a tubular stand [\n80\n], and slidably engageable with the tubular stand below the upper end or upset.\n \nB31.', 'The drilling rig of any of embodiments B25-B30, wherein the tubular delivery arm further comprises an arm bracket [\n520\n] extending outwardly from the dolly, and a drive plate [\n530\n] rotatably connected to the arm bracket, the upper end of the arm member pivotally connected to the drive plate.', 'B32.', 'The drilling rig of embodiment B31, further comprising a tilt actuator [\n540\n] pivotally connected between the drive plate and the arm member.', 'B33.', 'The drilling rig of embodiment B31 or embodiment B32, further comprising an incline actuator [\n552\n] pivotally connected between the arm and the clasp.\n \nB34.', 'The drilling rig of any of embodiments B25-B33, wherein the tubular delivery arm further comprises an arm bracket [\n520\n] extending outwardly from the dolly, a drive plate [\n530\n] rotatably connected to the arm bracket, and a rotary actuator [\n522\n] connected to the drive plate, the upper end of the arm member pivotally connected to the drive plate.\n \nB35.', 'The drilling rig of any of embodiments B25-B34, further comprising a top drive assembly [\n200\n], wherein the top drive assembly and the tubular delivery arm are vertically translatable along a mast', '[\n10\n].\n \nB36.', 'The drilling rig of embodiment B35, wherein the tubular delivery arm and the top drive assembly have non-conflicting vertical paths along the mast.', 'B37.', 'The drilling rig of embodiment B35 or embodiment B36, wherein the top drive assembly has a top drive [\n240\n] vertically translatable along a first path over the well center and along a second path rearward to a drawworks side of well center.', 'B38.', 'The drilling rig of any of embodiments B35-B37, wherein the top drive assembly has a top drive [\n240\n] horizontally movable between the well center position and a retracted position rearward to a drawworks side of the well center position.', 'B39.', 'The drilling rig of any of embodiments B35-B38, wherein the top drive assembly comprises: \n \na dolly [\n202\n] translatably connected to the mast;\n \na travelling block assembly', '[\n230\n, \n232\n];\n \na top drive [\n240\n] suspended from the travelling block assembly;\n \na yoke', '[\n210\n, \n212\n] pivotally connecting the travelling block to the dolly;\n \nan extendable actuator [\n220\n] connected between the dolly and the yoke;\n \na torque tube', '[\n260\n] rigidly connected to the travelling block;\n \nthe torque tube connected to the top drive in vertically slidable relation;\n \nwherein extension of the actuator pivots the yoke to extend the travelling block and top drive away from the dolly to well center position; and\n \nwherein retraction of the actuator pivots the yoke to retract the travelling block towards the dolly to a position away from the well center.\n \n \n \nB40.', 'The drilling rig of embodiment B39, wherein torque reactions of a drill string responding to rotation by the top drive are transferred from the top drive to the torque tube, from the torque tube to the travelling block, from the travelling block to the dolly, and from the dolly to the mast.', 'B41.', 'The drilling rig of any of embodiments B25-B40, further comprising a leg [\n20\n], a lower stabilizing arm [\n800\n] pivotally and rotatably connected to the leg, and a tubular guide [\n870\n] connected to the lower stabilizing arm and movable between the stand hand-off position and the well center position.', 'B42.', 'The drilling rig of any of embodiments B1-B42, further comprising an upper racking arm [\n350\n] comprising a gripper', '[\n382\n] movable over a fingerboard assembly', '[\n310\n] and the stand hand-off position.', 'B43.', 'The drilling rig of embodiment B42, wherein the upper racking arm comprises: \n \na bridge [\n358\n] connected to a frame [\n302\n] in translatable relation;\n \na racking arm [\n370\n] connected to the bridge in rotatable and translatable relation; and\n \nthe gripper connected to the arm in vertically translatable relation.', 'B44.', 'The drilling rig of embodiment B42 or embodiment B43, wherein the racking module is connected to a mast', '[\n10\n], and the racking module further comprises: a frame', '[\n302\n]; \n \nwherein the fingerboard assembly is connected to the frame and has columns receivable of tubular stands, optionally with the columns oriented in a direction towards the mast;\n \na fingerboard alleyway', '[\n316\n] connecting the columns on a mast side of the columns.\n \n \n \nB45.', 'The drilling rig of embodiment B44, further comprising: \n \nwherein the setback platform is positioned beneath the fingerboard assembly;\n \na platform alleyway', '[\n912\n] beneath the fingerboard alleyway; and\n \na lower racking arm [\n950\n] positioned in the platform alleyway.\n \n \n \nB46.', 'The drilling rig of Embodiment B45, wherein the lower racking arm further comprises: \n \na lower racking base [\n952\n] connected to the platform alleyway in translatable relation;\n \na lower racking frame', '[\n972\n] connected to the base in rotatable and pivotal relation;\n \na lower racking arm member', '[\n980\n] pivotally connected to the frame; and\n \na lower racking clasp [\n990\n] pivotally connected to the arm.\n \n \n \nB47.', 'A drilling rig [\n1\n], comprising: \n \na substructure', '[\n2\n] comprising a pair of base boxes;\n \na drill floor', '[\n6\n] above the substructure [\n2\n];\n \na setback platform', '[\n900\n] below and forward of the drill floor [\n6\n];\n \na mast [\n10\n] extending vertically above the drill floor', '[\n6\n];\n \na top drive assembly [\n200\n] vertically translatable along the mast', '[\n10\n];\n \na tubular delivery arm [\n500\n] vertically translatable along the mast', '[\n10\n];\n \nthe tubular delivery arm [\n500\n] having a tubular clasp [\n550\n] movable between a well center position [\n30\n] over a well center and a stand hand-off position [\n50\n] forward of the well center position [\n30\n];\n \nthe top drive assembly', '[\n200\n] being vertically translatable along a first path over the well center and along a second path rearward of the first path;\n \na racking module [\n300\n] extending outward of the mast', '[\n10\n] above the set-back platform [\n900\n];\n \na stand hand-off position [\n50\n] located on the setback platform [\n900\n], and extending vertically upwards substantially between the mast [\n10\n] and a fingerboard assembly [\n310\n] of the racking module [\n300\n]; and\n \nan upper stand constraint', '[\n420\n] connected beneath the racking module [\n300\n] and extendable rearward towards the mast', '[\n10\n].\n \n \n \nB48.', 'The drilling rig of embodiment B47, further comprising: \n \nan intermediate stand constraint having a frame connected to the drilling rig at an edge of the V-door side of the drill floor;\n \na carriage connected to the frame in extendable relationship;\n \na carriage actuator connected between the frame and the carriage, and operable to extend or retract the carriage outward from the frame;\n \na tubular clasp attached to the extendable end of the carriage;\n \na clasp actuator connected to the tubular clasp, and operable to open or close the tubular clasp around a tubular stand;\n \na tubular gripper attached to the extendable end of the carriage; and\n \na gripper actuator connected to the tubular gripper, and operable to open or close the tubular gripper around a tubular stand.\n \n \n \nB49.', 'A method to insert tubulars in or remove tubulars from a drill string with the drilling rig of any of embodiments B1-B48, comprising: \n \ntransporting the tubular stands between the setback position and the stand hand-off position;\n \nsetting the tubular stands down in the stand hand-off position;\n \nclasping a tubular stand with a tubular clasp', '[\n550\n] connected to the tubular delivery arm;\n \nvertically translating the tubular delivery arm along a mast [\n10\n];\n \nmoving the tubular clasp between the stand hand-off position and the well center position; and\n \nunclasping the tubular stand to disengage the tubular clasp.\n \n \n \nB50.', 'A method to insert tubulars in or remove tubulars from a drill string in a well below a drill floor of a drilling rig, comprising: \n \nusing first tubular handling equipment to transport tubular stands in and out of a setback position on a setback platform;\n \nusing second tubular handling equipment to deliver the tubular stands to and from a well center position over the well;\n \nsetting down the tubular stands in a stand hand-off position at an intersection between the first and second tubular handling equipment; and\n \nexchanging the tubular stands between the first and second functions at the stand hand-off position.\n \n \n \nB51.', 'A method to insert tubulars in or remove tubulars from a drill string in a well below a drill floor of a drilling rig, comprising: \n \na first tubular handling function comprising guiding upper portions of the tubular stands to transport the tubular stands in or out of a setback position on a setback platform;\n \na second tubular handling function comprising guiding the upper portions of the tubular stands to deliver the tubular stands to or from a well center position over the well;\n \nsetting down the tubular stands in a stand hand-off position located at an intersection between the first and second functions; and\n \nexchanging the tubular stands between the first and second tubular handling functions at the stand hand-off position.\n \n \n \nB52.', 'The method of embodiment B50 or embodiment B51, further comprising: clasping the upper portion below an upper end of one of the tubular stands in the well center position; and \n \nengaging or disengaging a top drive assembly', '[\n200\n] with the upper portion of the one tubular stand constrained in the well center position.', 'B53.', 'The method of any of embodiments B50-B52, further comprising: \n \nvertically translating a top drive assembly along a mast [\n10\n];\n \nclasping the one tubular stand at an upper end with a tubular clasp connected to a tubular delivery arm [\n500\n];\n \nvertically translating the tubular delivery arm along the mast;\n \nmoving the clasp between the well center position and the stand hand-off position;\n \nsliding the clasp along the tubular stand in the stand hand-off position below the upper end; and\n \nunclasping the tubular stand to disengage the tubular clasp.\n \n \n \nB54.', 'The method of any of embodiments B50-B53, further comprising locating the stand hand-off position on the setback platform.', 'B55.', 'The method of embodiment B54, wherein the stand hand-off position extends vertically upwards substantially between a mast and a fingerboard assembly [\n310\n] of the racking module.\n \nB56.', 'The method of embodiment B54 or embodiment B55, further comprising offsetting the setback platform beneath a drill floor [\n6\n].\n \nB57.', 'The method of any of embodiments B50-B56, further comprising positioning a mousehole in line between the well center and the stand hand-off position.', 'B58.', 'The method of embodiment B57, further comprising positioning a catwalk [\n60\n] in line with the stand hand-off position and the mousehole.\n \nB59.', 'The method of any of embodiments B50-B58, further comprising securing one of the tubular stands in the stand hand-off position with a stand constraint [\n420\n, \n440\n].\n \nB60.', 'The method of embodiment B59, further comprising connecting the stand constraint', '[\n420\n] to the racking module, and extending the stand constraint to the stand hand-off position.', 'B61.', 'The method of embodiment B59 or embodiment B60, further comprising positioning the stand constraint', '[\n440\n] on the setback platform, and centering the stand constraint over the stand hand-off position.', 'B62.', 'The method of any of embodiments B59-B61, further comprising: \n \nconnecting an upper one of the stand constraint [\n420\n] to the racking module;\n \nextending the upper stand constraint to the stand hand-off position;\n \nconnecting a lower one of the stand constraint [\n440\n] on the setback platform;\n \ncentering the lower stand constraint over the stand hand-off position;\n \nengaging the upper and lower stand constraints with respective upper and lower portions of one of the tubular stands set down in the stand hand-off position to vertically orient the one tubular stand.\n \n \n \nB63.', 'The method of any of embodiments B59-B62, further comprising: \n \nwherein the stand constraint comprises a frame;\n \nconnecting a carriage to the frame in extendable relationship;\n \nconnecting a carriage actuator between the frame and the carriage;\n \noperating the carriage actuator to extend or retract the carriage outward from the frame;\n \nattaching a clasp to the extendable end of the carriage; and\n \nconnecting a clasp actuator to the clasp; and\n \noperating the clasp actuator to open or close the clasp around one of the tubular stands.\n \n \n \nB64.', 'The method of embodiment B63, further comprising: \n \naffixing the tubular stand constraint to the racking module;\n \nwherein the racking module comprises a plurality of columns of tubular racking locations, and a transfer row connecting the columns;\n \nconnecting the racking module to a mast to extend outwardly from the mast;\n \nlocating the stand hand-off position to project vertically to intersect with the transfer row;\n \nextending the carriage towards the mast to center the clasp over the stand hand-off position; and\n \nretracting the carriage away from the mast to remove the clasp from the intersection with the transfer row.\n \n \n \nB65.', 'The method of embodiment B64, further comprising locating a platform of the stand constraint frame on the racking module centrally between the columns.\n \nB66.', 'The method of embodiment B64 or embodiment B65, further comprising extending the carriage towards the mast to position a center of the clasp beyond the center of the stand hand-off position.', 'B67.', 'The method of embodiment B66, connecting a top drive unit operating on the mast to a tubular stand positioned by the extended carriage.', 'B68.', 'The method of any of embodiments B59-B67, further comprising: \n \naffixing the tubular stand constraint to the setback platform;\n \noffsetting the setback platform beneath a drill floor [\n6\n] and connecting the setback platform to a substructure of the drilling rig;\n \nsetting down tubular stands on a surface of the setback platform;\n \nlocating an alleyway on the setback platform that is accessible to the surface;\n \nlocating the stand hand-off position on the alleyway;\n \nextending the carriage towards the substructure to center the clasp over the stand hand-off position; and\n \nretracting the carriage away from the substructure to remove the clasp from intersection with the alleyway.\n \n \n \nB69.', 'The method of embodiment B68, further comprising extending the carriage towards the mast to position the clasp beyond the center of the stand hand-off position.\n \nB70.', 'The method of embodiment B68, further comprising extending the carriage towards the mast to position the clasp over a mousehole.\n \nB71.', 'The method of any of embodiments B59-B60, further comprising: \n \nattaching a gripper assembly to the extendable end of the carriage;\n \nconnecting a gripper assembly actuator to the gripper assembly;\n \noperating the gripper assembly actuator to open or close the gripper assembly around a tubular stand;\n \naffixing the tubular stand constraint to a center section of the drilling rig on a V-door side;\n \nlocating the stand hand-off position on the setback platform;\n \nlocating a mousehole between the well center and the stand hand-off position;\n \nextending the carriage to center the stand constraint clasp and gripper assembly over the setback position; and\n \nretracting the carriage to center the stand constraint clasp and gripper assembly over the mousehole.\n \n \n \nB72.', 'The method of embodiment B71, further comprising gripping a tubular with the constraint clasp to inhibit vertical movement of the gripped tubular.\n \nB73.', 'The method of any of embodiments B50-B72, further comprising: \n \nlocating a stand hand-off station at the stand hand-off position;\n \nreceiving a pin connection of a tubular stand in a chamber of the stand hand-off station; and\n \nreceiving the weight of the tubular stand on a stage inside the chamber.\n \n \n \nB74.', 'The method of any of embodiments B50-B73, further comprising: \n \nlocating a stand hand-off station at the stand hand-off position;\n \nconnecting a base of the stand hand-off station to the setback platform;\n \nattaching a lower chamber of an expandable chamber assembly to the base;\n \npositioning an upper chamber of the expandable chamber assembly in concentric relationship to the lower chamber;\n \nconnecting an actuator between the lower chamber and the upper chamber;\n \nreceiving a lower end of a tubular stand through an opening in an elastomeric seal over a top end of the upper chamber; and\n \nreceiving the lower end of the tubular on a stage in the chamber assembly.\n \n \n \nB75.', 'The method of any of embodiments B50-B74, wherein guiding the upper portion of one of the tubular stands for delivery to or from the well center position comprises clasping an upper end of the one tubular stand with a tubular clasp [\n550\n] of a tubular delivery arm, and moving the tubular clasp between the stand hand-off position and the well center position.\n \nB76.', 'The method of embodiment B75, further comprising translating the tubular delivery arm along a mast of the drilling rig to raise or lower the tubular clasp.\n \nB77.', 'The method of embodiment B75 or embodiment B76, further comprising translatably connecting a dolly of the tubular delivery arm to the mast.', 'B78.', 'The method of any of embodiments B75-B77, further comprising rotating and pivoting an upper end of an arm member [\n532\n] connected to the dolly, and pivotally connecting a lower end of the arm member to the tubular clasp.\n \nB79.', 'The method of any of embodiments B75-B78, further comprising moving the tubular clasp to a mousehole position forward of the well center position.\n \nB80.', 'The method of any of embodiments B75-B79, further comprising moving the tubular clasp to a catwalk position forward of the stand hand-off position.\n \nB81.', 'The method of any of embodiments B75-B80, further comprising engaging the tubular clasp and an upper end of the one tubular stand, and sliding the tubular clasp along the one tubular stand below the upper end.', 'B82.', 'The method of any of embodiments B75-B81, further comprising engaging the tubular clasp and an upset at an upper end of the one tubular stand, and sliding the tubular clasp along the one tubular stand below the upset.\n \nB83.', 'The method of any of embodiments B75-B82, further comprising extending an arm bracket [\n520\n] outwardly from a dolly of the tubular delivery arm, rotatably connecting a drive plate [\n530\n] to the arm bracket, and pivotally connecting an upper end of the arm member to the drive plate.', 'B84.', 'The method of embodiment B83, further comprising operating a tilt actuator [\n540\n] pivotally connected between the drive plate and the arm member to pivot the arm member.\n \nB85.', 'The method of embodiment B83 or embodiment B84, further comprising operating an incline actuator pivotally connected between the arm and the tubular clasp to pivot the tubular clasp.', 'B86.', 'The method of any of embodiments B75-B85, further comprising extending an arm bracket [\n520\n] outwardly from a dolly of the tubular delivery arm, rotatably connecting a drive plate [\n530\n] to the arm bracket, connecting a rotary actuator [\n522\n] to the drive plate, and pivotally connecting an upper end of the arm member to the drive plate.', 'B87.', 'The method of any of embodiments B75-B86, further comprising vertically translating a top drive assembly along a mast [\n10\n], and vertically translating the tubular delivery arm along the mast.', 'B88.', 'The method of embodiment B87, comprising vertically translating a top drive of the top drive assembly along a first path over the well center and along a second path rearward to a drawworks side of well center.', 'B89.', 'The method of embodiment B88, further comprising horizontally moving the top drive between the well center position and a retracted position rearward to a drawworks side of the well center position.\n \nB90.', 'The method of any of embodiments B87-B89, further comprising: \n \ntranslatably connecting a dolly of the top drive assembly to the mast;\n \nsuspending a top drive from a travelling block assembly of the top drive assembly;\n \npivotally connecting the travelling block to the dolly with a yoke;\n \nconnecting an extendable actuator between the dolly and the yoke;\n \nrigidly connecting a torque tube to the travelling block;\n \nconnecting the torque tube to the top drive in vertically slidable relation;\n \nextending the actuator to pivot the yoke to extend the travelling block and top drive away from the dolly to the well center position; and\n \nretracting the actuator to pivot the yoke to retract the travelling block towards the dolly to a position away from the well center.\n \n \n \nB91.', 'The method of embodiment B90, further comprising transferring torque reactions of a drill string responding to rotation by the top drive from the top drive to the torque tube, from the torque tube to the travelling block, from the travelling block to the dolly, and from the dolly to the mast.\n \nB92.', 'The method of any of embodiments B75-B91, further comprising pivotally and rotatably connecting a lower stabilizing arm [\n800\n] to a leg [\n20\n] of the drilling rig, connecting a tubular guide [\n870\n] to the lower stabilizing arm, and moving the tubular guide between the stand hand-off position and the well center position.\n \nB93.', 'The method of any of embodiments B50-B92, further comprising moving a gripper of an upper racking arm over a fingerboard assembly [\n310\n] and the stand hand-off position.\n \nB94.', 'The method of embodiment B93, further comprising: \n \nconnecting a bridge of the upper racking arm to a frame in translatable relation;\n \ntranslating the bridge along the frame;\n \nconnecting an arm to the bridge in rotatable and translatable relation;\n \ntranslating the arm along the bridge;\n \nconnecting the gripper connected to the arm in vertically translatable relation; and\n \nvertically translating the gripper.\n \n \n \nB95.', 'The method of embodiment B93, further comprising: \n \nconnecting the racking module to a mast, wherein the racking module comprises a frame;\n \nconnecting a fingerboard assembly [\n310\n] to the frame, wherein the fingerboard has columns receivable of tubular stands;\n \noptionally orienting the columns in a direction towards the mast;\n \nconnecting the columns to a fingerboard alleyway on a mast side of the columns.\n \n \n \nB96.', 'The method of embodiment B95, further comprising: \n \npositioning the setback platform beneath the fingerboard assembly;\n \nlocating a platform alleyway [\n312\n] beneath the fingerboard alleyway; and\n \npositioning a lower racking arm in the platform alleyway.\n \n \n \nB97.', 'The method of any of embodiments B50-B96, further comprising: \n \nconnecting or disconnecting the tubular stands and a drill string;\n \nengaging or disengaging the tubular stands and a top drive assembly', '[\n200\n]; and\n \nlowering or hoisting the tubular stands connected to the drill string with the top drive assembly.', 'B98.', 'A method to insert tubulars in or remove tubulars from a drill string [\n90\n] in a well below a drill rig, [\n1\n] comprising: \n \nmoving tubular stands [\n80\n] between a racked position in a fingerboard assembly [\n310\n] and a set down position in a stand hand-off position [\n50\n] located between the fingerboard assembly and a drilling mast', '[\n10\n];\n \nretrieving and delivering the tubular stands between the stand hand-off position and a well center position [\n30\n] over a center of a well;\n \nconnecting or disconnecting the tubular stands and a drill string;\n \nengaging or disengaging the tubular stands and a top drive assembly', '[\n200\n]; and\n \nlowering or hoisting the tubular stands connected to the drill string with the top drive assembly.\n \n \n \nB99.', 'The method of embodiment B98, further comprising locating a mousehole [\n40\n] in line between the stand hand-off position and the well center.', 'B100.', 'The method of embodiment B98 or embodiment B99, further comprising securing and releasing the tubular stands set down in the stand hand-off position.\n \nB101.', 'The method of embodiment B100, wherein securing the tubular stands in the stand hand-off position comprises constraining upper and lower portions of one of the tubular stands to secure the one tubular stand in vertical orientation.', 'B102.', 'The method of any of embodiments B98-B101, further comprising setting down the tubular stands in the stand hand-off and racked positions on a set-back platform [\n900\n].\n \nB103.', 'The method of embodiment B102, comprising offsetting the set-back platform with respect to a drill floor [\n6\n] of the drill rig, and positioning the set-back platform beneath a level of the drill floor.', 'B104.', 'The method of any of embodiments B98-B103, wherein the movement of the tubular stands between the racked position and the stand hand-off position comprises guiding upper portions of the tubular stands through columns of the fingerboard assembly optionally oriented toward the mast and through a transverse alleyway on a mast side of the fingerboard assembly connecting the columns to the stand hand-off position.', 'B105.', 'The method of embodiment B104, further comprising guiding lower portions of the tubular stands along a path coincident with the movement of upper portions of the tubular stands between the fingerboard assembly and the stand hand-off position.\n \nB106.', 'The method of any of embodiments B98-B105, wherein the movement of the tubular stands between the stand hand-off position and the well center position comprises guiding upper portions of the tubular stands between the stand hand-off position and the well center position.\n \nB107.', 'The method of embodiment B106, further comprising guiding lower portions of the tubular stands along a path coincident with the movement of upper portions of the tubular stands between the stand hand-off position and the well center position.', 'B108.', 'The method of any of embodiments B98-B107, further comprising: \n \noperating an upper racking arm [\n350\n] to guide upper portions of the tubular stands between the fingerboard assembly and the stand hand-off position;\n \noperating a tubular delivery arm [\n500\n] independently of the upper racking arm to guide the upper portions of the tubular stands between the stand hand-off position and the well center position; and\n \nusing the stand hand-off position as a designated set down position to hand off the upper portions of the tubular stands between the upper racking arm and the tubular delivery arm.\n \n \n \nB109.', 'The method of embodiment B108, further comprising: \n \nclasping an upper portion of one of the tubular stands with the tubular delivery arm below the top drive assembly in the well center position; and\n \nengaging or disengaging the constrained upper portion of the one tubular stand and the top drive assembly in the well center position.\n \n \n \nB110.', 'The method of embodiment B108 or embodiment B109, further comprising: \n \nconnecting or disconnecting a lower portion of one of the tubular stands and the drill string engaged in a rotary table', '[\n810\n];\n \ndisengaging the drill string and the rotary table for the hoisting or lowering of the drill string with the top drive assembly; and\n \nretracting one of the tubular delivery arm and the top drive assembly from the well center position to vertically translate the tubular delivery arm and the top drive assembly along the mast in non-conflicting paths.', 'B111.', 'The method of embodiment B110, wherein the top drive assembly comprises a retractable', 'dolly [\n202\n], and further comprising translatably connecting the top drive dolly to the mast.', 'B112.', 'The method of any of embodiments B108-B111, wherein the movement of the tubular stands between the fingerboard assembly [\n310\n] and the stand hand-off position comprises engaging the upper racking arm [\n350\n] with an upper portion of one of the tubular stands, hoisting the one tubular stand, moving the upper racking arm over the fingerboard assembly, setting down the one tubular stand, and disengaging the upper racking arm.\n \nB113.', 'The method of embodiment B112, further comprising moving the upper racking arm free of the one tubular stand into position for the engagement of a next one of the tubular stands.', 'B114.', 'The method of embodiment B112 or embodiment B113, wherein the upper racking arm comprises a bridge, a racking arm, and a gripper, and further comprising: \n \ntranslatably connecting the bridge to a frame over the fingerboard assembly, and translatably and rotatably connecting the racking arm to the bridge, to guide the upper racking arm over the finger board assembly; and\n \nconnecting the gripper to the racking arm in vertically translatable relation for the engagement, hoisting and setting down of the tubular stands.\n \n \n \nB115.', 'The method of any of embodiments B98-B116, wherein the retrieval and delivery of the tubular stands between the stand hand-off position and the well center position comprises extending, retracting, and rotating tubular delivery arm [\n500\n] with respect to a vertical axis.', 'B116.', 'The method of embodiment B115, further comprising returning the tubular delivery arm free of the delivered tubular stand into position for the retrieval of a next one of the tubular stands.\n \nB117.', 'The method of any of embodiments B108-B116, wherein the tubular delivery arm comprises a dolly [\n510\n], and further comprising translatably connecting the dolly of the tubular delivery arm to the mast.', 'B118.', 'The method of embodiment B117, wherein the tubular delivery arm comprises an arm member', '[\n532\n], and further comprising rotatably and pivotally connecting an upper end of the arm member to the dolly.\n \nB119.', 'The method of any of embodiments B98-B118, further comprising engaging and disengaging an upper portion of one of the tubular stands and a clasp [\n550\n] on a free end of the tubular delivery arm.\n \nB120.', 'The method of any of embodiments B98-B119, further comprising using a lower stabilizing arm to guide lower portions of the tubular stands between the stand hand-off position and the well center position.', 'B121.', 'The method of any of embodiments B98-B120 to insert tubulars in the drill string, comprising: \n \n(a) moving an upper racking arm over one of the tubular stands racked in the fingerboard assembly;\n \n(b) engaging and hoisting an upper portion of the one tubular stand with the upper racking arm;\n \n(c) moving the upper racking arm over the fingerboard assembly to position the one tubular stand in the stand hand-off position;\n \n(d) setting down the one tubular stand in the stand hand-off position;\n \n(e) securing the one tubular stand in the stand hand-off position;\n \n(f) disengaging and moving the upper racking arm over the fingerboard assembly away from the stand hand-off position; and\n \n(g) repeating (a) to (f) for a next one of the tubular stands.', 'B122.', 'The method of any of embodiments B98-B121 to insert tubulars in the drill string, further comprising: \n \n(1) engaging a clasp [\n550\n] of an extended tubular delivery arm [\n500\n] with an upper end of one of the tubular stands secured in the stand hand-off position;\n \n(2) releasing the one tubular secured in the stand hand-off position;\n \n(3) translating the tubular delivery arm along the mast to hoist the one tubular stand;\n \n(4) retracting the tubular delivery arm to move the one tubular stand away from the stand hand-off position;\n \n(5) rotating the tubular delivery arm to face the well center position;\n \n(6) extending the tubular delivery arm to move the one tubular stand into the well center position;\n \n(7) connecting the one tubular stand to the drill string engaged in a rotary table', '[\n810\n];\n \n(8) releasing the one tubular stand from the clasp and retracting, rotating, extending, and translating the tubular delivery arm along the mast to return the clasp to the upper portion of a next one of the tubular stands secured in the stand hand-off position; and\n \n(9) repeating (1) to (8) for the next one tubular stand.\n \n \n \nB123.', 'The method of embodiment B122, further comprising: \n \n(10) after the connection in (7), translating the tubular delivery arm downward along the mast to slide down the clasp engaging the upper portion of the one tubular stand;\n \n(11) translating retracted top drive [\n810\n] along the mast past the tubular delivery arm to the upper portion of the one tubular stand above the clasp;\n \n(12) engaging the top drive and the upper portion of the one tubular stand while clasping the upper portion of the one tubular stand with the clasp below the top drive assembly;\n \n(13) disengaging the rotary table and translating the top drive assembly along the mast to lower the one tubular stand and drill string into the well;\n \n(14) engaging the rotary table and disengaging the top drive assembly from the one tubular stand;\n \n(15) retracting the top drive assembly from the well center position; and\n \n(16) repeating (10) to (15) for the next one tubular stand.\n \n \n \nB124.', 'The method of any of embodiments B98-B120 to remove tubulars from the drill string, comprising: \n \n(1) engaging a clasp', '[\n550\n] of an extended tubular delivery arm [\n500\n] with an upper portion of one of the tubular stands connected to the drill string engaged in a rotary table', '[\n810\n];\n \n(2) disconnecting the one tubular stand from the drill string;\n \n(3) retracting the tubular delivery arm to move the one tubular stand away from the well center position;\n \n(4) translating the tubular delivery arm along the mast to lower the one tubular stand;\n \n(5) rotating the tubular delivery arm to face the stand hand-off position;\n \n(6) extending the tubular delivery arm to move the one tubular stand into the stand hand-off position;\n \n(7) securing the one tubular stand in the stand hand-off position;\n \n(8) releasing the one tubular stand from the tubular clasp and retracting, rotating, extending, and translating the tubular delivery arm along the mast to return the clasp to the upper portion of a next one of the tubular stands connected to the drill string engaged in the rotary table; and\n \n(9) repeating (1) to (8) for the next one tubular stand.', 'B125.', 'The method of embodiment B125, further comprising: \n \n(10) engaging the top drive assembly and the upper portion of the one tubular stand while engaging the one tubular stand connected to the drill string in the rotary table;\n \n(11) disengaging the rotary table and translating the top drive assembly along the mast to hoist the one tubular stand and connected drill string above the rotary table;\n \n(12) engaging the drill string in the rotary table below the lower portion of the one tubular stand;\n \n(13) while clasping the upper portion of the one tubular stand with the clasp of the tubular delivery arm below the top drive assembly, disengaging the top drive assembly from the one tubular stand;\n \n(14) translating the tubular delivery arm along the mast to raise the clasp at the upper portion of the one tubular stand in the well center position for the engagement in (1);\n \n(15) retracting and translating the top drive assembly along the mast past the tubular delivery arm; and\n \n(16) repeating (10) to (15) for the next one tubular stand.\n \n \n \nB126.', 'The method of any of embodiments B98-B120, B124, or B125 to remove tubulars from the drill string, comprising: \n \n(a) moving an upper racking arm over one of the tubular stands secured in the stand hand-off position;\n \n(b) engaging and hoisting an upper portion of the one tubular stand with the upper racking arm;\n \n(c) releasing the one tubular stand from the stand hand-off position;\n \n(d) moving the upper racking arm over the fingerboard assembly to position the one tubular stand in a racked position;\n \n(e) setting down the one tubular stand in the rack position;\n \n(f) disengaging and moving the upper racking arm over the fingerboard assembly away from the one tubular stand racked in the fingerboard assembly; and\n \n(g) repeating (a) to (f) for a next one of the tubular stands.', 'B127.', 'A drilling rig [\n1\n], comprising: \n \na retractable top drive assembly vertically translatable along a mast;\n \na tubular delivery arm vertically translatable along the mast and comprising a tubular clasp [\n550\n] movable between a well center position over a well center and a position forward of the well center;\n \nwherein the tubular clasp is engageable with an upper end of a tubular stand [\n80\n]; and\n \nwherein the tubular clasp is slidably engageable with the tubular stand below the upper end to clasp an upper portion of the tubular stand in the well center position below the upper end.', 'B128.', 'A method for inserting tubulars in or removing tubulars from a drill string, comprising: \n \nengaging a tubular clasp of a tubular delivery arm and an upper end of a tubular stand [\n80\n];\n \nmoving the tubular clasp between a well center position over a well center and a position forward of the well center;\n \nclasping an upper portion of the tubular stand in the well center position with the clasp below the upper end; and\n \nengaging or disengaging a top drive and the constrained upper end of the tubular stand in the well center position.\n \n \n \nB129.', 'The drilling rig of any of embodiments B2-B49 or B127, or the method of any of embodiments B49 or B53-B126, wherein the tubular delivery arm comprises an electric or hydraulically powered crown winch', '[\n501\n].', 'If used herein, the term “substantially” is intended for construction as meaning “more so than not.”', 'If used herein the term “and/or” is inclusive, e.g., an item comprising component A and/or component B, may comprise A alone, B alone, or A and B together.', 'Having thus described the disclosed embodiments by reference to certain of its preferred embodiments, it is noted that the embodiments disclosed are illustrative rather than limiting in nature and that a wide range of variations, modifications, changes, and substitutions are contemplated in the foregoing disclosure and, in some instances, some features of the disclosed embodiments may be employed without a corresponding use of the other features.', 'Many such variations and modifications may be considered desirable by those skilled in the art based upon a review of the foregoing description of preferred embodiments.', 'Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the disclosed embodiments.'] | ['1.', 'A method to insert tubulars in or remove tubulars from a drill string in a well below a drill floor of a drilling rig, comprising:\nconnecting together tubulars at least partially in a mousehole to form tubular stands, or disconnecting the tubulars from one another at least partially in the mousehole, or both;\nusing first tubular handling equipment to transport the tubular stands in and out of a setback position on a setback platform;\nusing second tubular handling equipment to deliver the tubular stands to and from a well center position over the well and to and from the mousehole;\nsetting down the tubular stands in a stand hand-off position reachable by both the first and second tubular handling equipment; and\nexchanging the tubular stands between the first and second tubular handling equipment at the stand hand-off position.', '2.', 'The method of claim 1, wherein the mousehole is positioned in line between the well center and the stand hand-off position.', '3.', 'The method of claim 2, further comprising positioning a catwalk in line with the stand hand-off position and the mousehole.', '4.', 'The method of claim 1, further comprising moving the second tubular handling equipment vertically relative to a mast of the drilling rig to deliver the tubular stands to and from the well center position over the well.', '5.', 'The method of claim 1, further comprising, for each one of the tubular stands, using a tubular clasp of the second tubular handling equipment to clasp a respective upper portion of the tubular stand as the second tubular handling equipment delivers the tubular stands to and from a well center position over the well and to and from the mousehole.', '6.', 'A method to insert tubulars in or remove tubulars from a drill string in a well below a drill floor of a drilling rig, comprising:\nguiding upper portions of tubular stands to transport the tubular stands in or out of a setback position on a setback platform using first tubular handling equipment, wherein the setback platform is lower than the drill floor;\nguiding the upper portions of the tubular stands to deliver the tubular stands to or from a well center position over the well using second tubular handling equipment;\nlocating a stand hand-off position on the setback platform;\nsetting down the tubular stands in the stand hand-off position; and\nexchanging the tubular stands between the first and second tubular handling equipment at the stand hand-off position.', '7.', 'The method of claim 6, further comprising:\nfor each one of the tubular stands, clasping a respective upper portion below an upper end of the tubular stand in the well center position using the second tubular handling equipment; and\nengaging or disengaging a top drive assembly with the upper portion of the tubular stand constrained in the well center position.', '8.', 'The method of claim 7, further comprising:\nvertically translating the top drive assembly along a mast;\nclasping the tubular stand at the upper end with a tubular clasp connected to a tubular delivery arm, wherein the second tubular handling equipment comprises the tubular clasp and the tubular delivery arm;\nvertically translating the tubular delivery arm along the mast;\nmoving the tubular clasp between the well center position and the stand hand-off position;\nsliding the tubular clasp along the tubular stand in the stand hand-off position below the upper end; and\nunclasping the tubular stand to disengage the tubular clasp.\n\n\n\n\n\n\n9.', 'The method of claim 6, wherein the stand hand-off position extends vertically upwards substantially between a mast and a fingerboard assembly of a racking module.', '10.', 'The method of claim 9, further comprising securing one of the tubular stands in the stand hand-off position with a stand constraint.', '11.', 'The method of claim 10, further comprising connecting the stand constraint to a racking module, and extending the stand constraint to the stand hand-off position.\n\n\n\n\n\n\n12.', 'The method of claim 10, further comprising positioning the stand constraint on the setback platform, and centering the stand constraint over the stand hand-off position.', '13.', 'The method of claim 10, further comprising:\nconnecting an upper one of the stand constraint to the racking module;\nextending the upper stand constraint to the stand hand-off position;\nconnecting a lower one of the stand constraint on the setback platform;\ncentering the lower stand constraint over the stand hand-off position;\nengaging the upper and lower stand constraints with respective upper and lower portions of one of the tubular stands set down in the stand hand-off position to vertically orient the one tubular stand.', '14.', 'The method of claim 10, further comprising:\nwherein the stand constraint comprises a frame;\nconnecting a carriage to the frame in extendable relationship;\nconnecting a carriage actuator between the frame and the carriage;\noperating the carriage actuator to extend or retract the carriage outward from the frame;\nattaching a clasp to the extendable end of the carriage; and\nconnecting a clasp actuator to the clasp; and\noperating the clasp actuator to open or close the clasp around one of the tubular stands.\n\n\n\n\n\n\n15.', 'The method of claim 14, further comprising:\naffixing the stand constraint to the racking module;\nwherein the racking module comprises a plurality of columns of tubular racking locations, and a transfer row connecting the columns;\nconnecting the racking module to a mast to extend outwardly from the mast;\nlocating the stand hand-off position to project vertically to intersect with the transfer row;\nextending the carriage towards the mast to center the clasp over the stand hand-off position; and\nretracting the carriage away from the mast to remove the clasp from the intersection with the transfer row.', '16.', 'The method of claim 15, further comprising locating a platform of the stand constraint frame on the racking module centrally between the columns.', '17.', 'The method of claim 15, further comprising extending the carriage towards the mast to position a center of the clasp beyond the center of the stand hand-off position, and connecting a top drive unit operating on the mast to the one of the tubular stands positioned by the extended carriage.', '18.', 'The method of claim 10, further comprising:\naffixing the stand constraint to the setback platform;\noffsetting the setback platform beneath a drill floor and connecting the setback platform to a substructure of the drilling rig;\nsetting down the one of the tubular stands on a surface of the setback platform;\nlocating an alleyway on the setback platform that is accessible to the surface;\nlocating the stand hand-off position on the alleyway;\nextending a carriage towards the substructure to center a clasp over the stand hand-off position; and\nretracting the carriage away from the substructure to remove the clasp from intersection with the alleyway.\n\n\n\n\n\n\n19.', 'The method of claim 18, further comprising extending the carriage towards the mast to position the clasp beyond the center of the stand hand-off position.', '20.', 'The method of claim 18, further comprising extending the carriage towards the mast to position the clasp over the mousehole.', '21.', 'The method of claim 10, further comprising:\nattaching a gripper assembly to an extendable end of a carriage;\nconnecting a gripper assembly actuator to the gripper assembly;\noperating the gripper assembly actuator to open or close the gripper assembly around the one of the tubular stands;\naffixing the stand constraint to a center section of the drilling rig on a V-door side;\nlocating the mousehole between the well center and the stand hand-off position;\nextending the carriage to center a clasp of the stand constraint and the gripper assembly over the setback position; and\nretracting the carriage to center the clasp of the stand constraint and the gripper assembly over the mousehole.\n\n\n\n\n\n\n22.', 'The method of claim 21, further comprising gripping one of the tubulars of the one of the tubular stands with the clasp of the stand constraint to inhibit vertical movement of the gripped tubular.\n\n\n\n\n\n\n23.', 'The method of claim 6, further comprising:\nlocating a stand hand-off station at the stand hand-off position;\nreceiving a pin connection of one of the tubular stands in a chamber of the stand hand-off station; and\nreceiving the weight of the one of the tubular stands on a stage inside the chamber.', '24.', 'The method of claim 6, further comprising:\nlocating a stand hand-off station at the stand hand-off position;\nconnecting a base of the stand hand-off station to the setback platform;\nattaching a lower chamber of an expandable chamber assembly to the base;\npositioning an upper chamber of the expandable chamber assembly in concentric relationship to the lower chamber;\nconnecting an actuator between the lower chamber and the upper chamber;\nreceiving a lower end of one of the tubular stands through an opening in an elastomeric seal over a top end of the upper chamber; and\nreceiving the lower end of the one of the tubular stands on a stage in the chamber assembly.', '25.', 'The method of claim 6, wherein, for each one of the tubular stands, guiding a respective upper portion of the tubular stand for delivery to or from the well center position comprises clasping the upper end portion of the tubular stand with a tubular clasp of a tubular delivery arm of the second tubular handling equipment, and moving the tubular clasp between the stand hand-off position and the well center position while the tubular clasp is clasping the upper end portion of the tubular stand.', '26.', 'The method of claim 25, further comprising moving the tubular clasp to a mousehole position forward of the well center position.', '27.', 'The method of claim 25, further comprising moving the tubular clasp to a catwalk position forward of the stand hand-off position.', '28.', 'The method of claim 25, further comprising engaging the tubular clasp and an upper end of the one tubular stand, and sliding the tubular clasp along the one tubular stand below the upper end.', '29.', 'The method of claim 25, further comprising engaging the tubular clasp and an upset at an upper end of the one tubular stand, and sliding the tubular clasp along the one tubular stand below the upset.', '30.', 'The method of claim 25, further comprising extending an arm bracket outwardly from a dolly of the tubular delivery arm, rotatably connecting a drive plate to the arm bracket, and pivotally connecting an upper end of the arm member to the drive plate.', '31.', 'The method of claim 30, further comprising operating a tilt actuator pivotally connected between the drive plate and the arm member to pivot the arm member.', '32.', 'The method of claim 30, further comprising operating an incline actuator pivotally connected between the arm and the tubular clasp to pivot the tubular clasp.\n\n\n\n\n\n\n33.', 'The method of claim 25, further comprising extending an arm bracket outwardly from a dolly of the tubular delivery arm, rotatably connecting a drive plate to the arm bracket, connecting a rotary actuator to the drive plate, and pivotally connecting an upper end of the arm member to the drive plate.', '34.', 'The method of claim 25, further comprising vertically translating a top drive assembly along a mast and vertically translating the tubular delivery arm along the mast.', '35.', 'The method of claim 34, comprising vertically translating a top drive of the top drive assembly along a first path over the well center and along a second path rearward to a drawworks side of well center.', '36.', 'The method of claim 35, further comprising horizontally moving the top drive between the well center position and a retracted position rearward to a drawworks side of the well center position.', '37.', 'The method of claim 34, further comprising:\ntranslatably connecting a dolly of the top drive assembly to the mast;\nsuspending a top drive from a travelling block assembly of the top drive assembly;\npivotally connecting the travelling block to the dolly with a yoke;\nconnecting an extendable actuator between the dolly and the yoke;\nrigidly connecting a torque tube to the travelling block;\nconnecting the torque tube to the top drive in vertically slidable relation;\nextending the actuator to pivot the yoke to extend the travelling block and top drive away from the dolly to the well center position; and\nretracting the actuator to pivot the yoke to retract the travelling block towards the dolly to a position away from the well center.\n\n\n\n\n\n\n38.', 'The method of claim 37, further comprising transferring torque reactions of a drill string responding to rotation by the top drive from the top drive to the torque tube, from the torque tube to the travelling block, from the travelling block to the dolly, and from the dolly to the mast.', '39.', 'The method of claim 25, further comprising pivotally and rotatably connecting a lower stabilizing arm to a leg of the drilling rig, connecting a tubular guide to the lower stabilizing arm, and moving the tubular guide between the stand handoff position and the well center position.', '40.', 'The method of claim 6, further comprising moving a gripper of an upper racking arm over a fingerboard assembly and the stand hand-off position.', '41.', 'The method of claim 40, further comprising:\nconnecting a bridge of the upper racking arm to a frame in translatable relation;\ntranslating the bridge along the frame;\nconnecting an arm to the bridge in rotatable and translatable relation;\ntranslating the arm along the bridge;\nconnecting the gripper connected to the arm in vertically translatable relation; and\nvertically translating the gripper.\n\n\n\n\n\n\n42.', 'The method of claim 40, further comprising:\nconnecting a racking module to a mast, wherein the racking module comprises a frame;\nconnecting the fingerboard assembly to the frame, wherein the fingerboard assembly has columns configured to receive the tubular stands;\norienting the columns in a direction towards the mast;\nconnecting the columns to a fingerboard alleyway on a mast side of the columns.\n\n\n\n\n\n\n43.', 'The method of claim 6, further comprising moving the second tubular handling equipment vertically relative to a mast of the drilling rig to deliver the tubular stands between the stand hand-off position and the well center position over the well.\n\n\n\n\n\n\n44.', 'A method to insert tubulars in or remove tubulars from a drill string in a well below a drill floor of a drilling rig, comprising:\nguiding upper portions of tubular stands to transport the tubular stands in or out of a setback position on a setback platform using first tubular handling equipment, wherein the setback platform is lower than the drill floor;\nguiding the upper portions of the tubular stands to deliver the tubular stands to or from a well center position over the well using second tubular handling equipment;\nsetting down the tubular stands in a stand hand-off position;\nexchanging the tubular stands between the first and second tubular handling equipment at the stand hand-off position,\nwherein guiding the upper portion of one of the tubular stands for delivery to or from the well center position comprises clasping an upper end of the one tubular stand using a tubular clasp of a tubular delivery arm of the second tubular handling equipment, and moving the tubular clasp between the stand hand-off position and the well center position; and\ntranslating the tubular delivery arm along a mast of the drilling rig to raise or lower the tubular clasp.', '45.', 'The method of claim 44, further comprising translatably connecting a dolly of the tubular delivery arm to the mast.', '46.', 'The method of claim 45, further comprising rotating and pivoting an upper end of an arm member connected to the dolly, and pivotally connecting a lower end of the arm member to the tubular clasp.'] | ['FIG.', '1 is an isometric view of an embodiment of the drilling rig system of the disclosed embodiments for a high trip rate drilling rig.; FIG.', '2 is a top view of the embodiment of FIG.', '1 of the disclosed embodiments for a high trip rate drilling rig.; FIG.', '3 is an isometric cut-away view of the retractable top drive in a drilling mast as used in an embodiment of the high trip rate drilling rig.; FIG.', '4 is a side cut-away view of the retractable top drive, showing it positioned over the well center.; FIG.', '5 is a side cut-away view of the retractable top drive, showing it retracted from its position over the well center.; FIG.', '6 is an isometric simplified block diagram illustrating the transfer of reaction torque to the top drive, to the torque tube, to the travelling block to the dolly, and to the mast.; FIG. 7 is a top view of the racking module, illustrating the operating envelope of the upper racking arm and the relationship of the stand hand-off position to the racking module, well center and mousehole, according to the embodiments disclosed.; FIG. 8 is an isometric view of the racking module, illustrating the upper racking arm translating the alleyway and delivering the drill pipe to a stand hand-off position, according to the disclosed embodiments.', '; FIG.', '9 is an isometric view of an embodiment of an upper racking arm component of the racking module of the disclosed embodiments, illustrating rotation of the arm suspended from the bridge.; FIG.', '10 is an isometric break-out view of an embodiment of the racking module, illustrating the upper racking arm translating the alleyway and delivering the tubular stand to the stand hand-off position.; FIG.', '11 an isometric view of the racking module from the opposite side, illustrating the upper stand securing the tubular stand in position at the stand hand-off position, according to the embodiments disclosed.; FIG.', '11A is an isometric view of an embodiment of a tubular stand constraint, illustrating the carriage retracted and the clasp open.; FIG.', '11B is an isometric view of an embodiment of a tubular stand constraint, illustrating the carriage extended and the clasp closed, as it would be to restrain a tubular stand.; FIG.', '12 is an isometric view of an embodiment of the tubular delivery arm component of the high trip rate drilling rig, shown having a free pivoting tubular clasp.; FIG.', '12A is an isometric exploded view of the embodiment of the tubular delivery arm illustrated in FIG.', '12.; FIG. 13 is an isometric view of another embodiment of the tubular delivery arm, having an incline controlled tubular clasp and an automatic box doping apparatus.; FIG.', '13A is an isometric exploded view of the tubular delivery arm of FIG.', '13.; FIG.', '13B is a fully assembled isometric view of the tubular delivery arm illustrated in FIGS.', '13 and 13A.; FIG.', '14 is a side view of an embodiment of the tubular delivery arm, illustrating the range of the tubular delivery arm to position a tubular stand relative to positions of use on a drilling rig.; FIG.', '14A is a side view of another embodiment of the tubular delivery arm illustrating the range of the tubular delivery arm to position a tubular stand relative to positions of use on a drilling rig.; FIG.', '14B is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position to receive a section of drill pipe from the catwalk.; FIG.', '14C is an isometric view of the embodiment of the tubular delivery arm of FIG.', '14B, illustrating the tubular delivery arm receiving a section of drill pipe from the catwalk.;', 'FIG.', '14D is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned to receive a tubular stand from, or deliver a section of pipe to, the mousehole.; FIG.', '14E is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position to receive (or deliver) a tubular stand at the stand hand-off position at the racking module.; FIG.', '14F is an isometric view of the embodiment of the tubular delivery arm of FIG. 7, illustrating the tubular delivery arm positioned over the stand hand-off position between the racking module and the mast, and having a tubular stand secured in the clasp.; FIG.', '14G is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned over well center to deliver a tubular stand into a stump at the well center, and to release the tubular stand when secured by the top drive.; FIG.', '15 is an isometric view of the embodiment of the tubular delivery arm of FIG.', '13, in which a portion of the upper racking module is cut away to more clearly illustrate the tubular delivery arm articulated to the stand hand-off position clasping a tubular stand.; FIG.', '16 is an isometric view of the embodiment of the tubular delivery arm of FIG.', '13, illustrating the tubular delivery arm articulated over the well center and handing a tubular stand to the top drive.; FIG.', '16A is an isometric view of the embodiment of the tubular delivery arm of FIG.', '16, illustrating the tubular delivery arm articulated to reach a tubular stand held by an upper stand constraint component at the stand hand-off position.; FIG.', '16B is an isometric view of the embodiment of the tubular delivery arm of FIG.', '16A, illustrating the upper stand constraint having released the tubular stand and the tubular delivery arm hoisting the tubular stand as the grease dispenser is lowered to spray grease into the box end of the tubular stand being lifted.;', 'FIG.', '16A is an isometric view of the embodiment of the tubular delivery arm of FIG.', '16, illustrating a closeup view of the tubular delivery arm connecting to a tubular stand at stand hand-off position.; FIG.', '16B is an isometric view of the embodiment of tubular delivery arm of FIG.', '16A, illustrating the tubular delivery arm hoisting (or lowering) a tubular stand released (or to be constrained) by the upper stand constraint.; FIG.', '17 is an isometric view of a lower stabilizing arm component according to the disclosed embodiments, illustrating the multiple extendable sections of the arm.; FIG.', '18 is a side view of the embodiment of FIG.', '16, illustrating positioning of the lower stabilizing arm to stabilize the lower portion of a tubular stand between a well center, mousehole, stand hand-off and catwalk position.;', 'FIG. 19 is an isometric view of the embodiment of FIG.', '18, illustrating the lower stabilizing arm capturing the lower end of a drill pipe section near the catwalk.', '; FIG.', '20 is an isometric view of an embodiment of the lower stabilizing arm, illustrated secured to the lower end of a stand of drill pipe and stabbing it at the mousehole.; FIG.', '21 is an isometric view of an embodiment of an intermediate stand constraint, illustrated extended.; FIG.', '22 is an isometric view of the embodiment of the intermediate stand constraint of FIG.', '21, illustrating the intermediate stand constraint folded for transportation between drilling locations.; FIGS.', '23 through 32 are isometric views that illustrate the high trip rate drilling rig of the disclosed embodiments in the process of moving tubular stands from a racked position and into the well, according to the disclosed embodiments.; FIG.', '33 is a top view of an embodiment of a setback platform of the tubular racking system of the disclosed embodiments.; FIG.', '34 is an isometric view of an embodiment of the setback platform of the tubular racking system of the disclosed embodiments.; FIG.', '35 is an isometric view of an upper racking module of the tubular racking system of the disclosed embodiments.; FIG.', '36 is an isometric view of the embodiment of FIG.', '35 of the upper racking module of the tubular racking system of the disclosed embodiments.;', 'FIG.', '37 is an isometric view of an embodiment of a stand hand-off station of the disclosed embodiments.; FIG.', '1 is an isometric view of an embodiment of the drilling rig system of the disclosed embodiments for a high trip rate drilling rig 1. FIG.', '1 illustrates drilling rig 1 having the conventional front portion of the drill floor removed, and placing well center 30 near to the edge of drill floor 6.', 'In this configuration, a setback platform 900 is located beneath the level of drill floor 6, and connected to base box sections of substructure 2 on the ground.', 'In this position, setback platform 900 is beneath racking module 300 such that tubular stands 80 (see FIG.', '33) located in racking module 300 will be resting on setback platform 900.; FIG.', '2 is a top view of the drilling rig 1 of FIG.', '1.', 'Racking module 300 has a frame 302 connected to a fingerboard assembly 310 (see FIG. 7), which may, if desired, have columns of racking positions 312 aligned perpendicular to conventional alignment.', 'As so aligned, racking column positions 312 run in a V-door to drawworks direction.', 'Drilling masts generally have a mast front or V-door side, and an opposite mast rear or drawworks side.', "Perpendicular to these sides are the driller's side and opposite off-driller's side.; FIG.", '3 is an isometric cut-away view of a retractable top drive assembly 200 in drilling mast 10 as used in an embodiment of drilling rig 1.', 'Retractable top drive assembly 200 is generally comprised of a travelling block assembly (230, 232), a top drive 240, a pair of links 252 and an elevator 250, along with other various components.', 'Retractable top drive assembly 200 may, for example, have a retractable dolly 202 that is mounted on guides 17 in mast 10.', 'A first yoke 210 connects block assembly 230, 232 to dolly 202.', 'A second yoke 212 extends between dolly 202 and top drive 240.', 'In the embodiment illustrated, guides 17 are proximate to the rear side 14 of mast 10, and dolly 202 is vertically translatable on the length of guides 17.; FIG.', '4 is a side cut-away view of an embodiment of retractable top drive assembly 200, showing it positioned over well center 30.', 'Retractable top drive assembly 200 may optionally have a torque tube 260 that functions to transfer torque from retractable top drive assembly 200 to dolly 202 and there through to guides 17 and mast 10.', '(See FIG. 6).; FIG.', '5 is a side cut-away view of the embodiment of retractable top drive assembly 200 in FIG.', '4, showing it retracted from its position over well center 30 to avoid contact with a tubular delivery arm 500 that vertically translates the same mast 10 as retractable top drive assembly 200 (see FIG. 12).; FIG.', '6 is an isometric cut-away view of an embodiment illustrating the force transmitted through torque tube 260 connected directly to the travel block assembly.', 'Torque tube 260 is solidly attached to the travelling block assembly, such as between block halves 230 and 232, and thus connected to dolly 202 through yoke 210 and yoke 212.', 'Torque may be encountered from make-up and break-out activity as well as drilling torque reacting from the drill bit and stabilizer engagement with the wellbore.', 'Torque tube 260 may be engaged to top drive 240 at torque tube bracket 262 in sliding relationship.', 'Top drive 240 is vertically separable from the travelling block assembly to accommodate different thread lengths in tubular couplings.', 'The sliding relationship of the connection at torque tube bracket 262 accommodates this movement.; FIG.', '7 is a top view of racking module 300, illustrating an operating envelope of upper racking arm 350, and the relationship of stand hand-off position 50 to racking module 300, in some embodiments.', 'Fingerboard assembly 310 may provide a rectangular grid of multiple tubular storage positions between its fingers.', 'Fingerboard assembly 310 has racking column positions 312 optionally aligned in the V-door to drawworks direction, opening in the direction of the mast 10, facing the opening on the front side of the mast, and a transverse alleyway 316 connecting to the stand hand-off position 50.; FIG.', '8 is an isometric view of racking module 300 component of the disclosed embodiments, illustrating upper racking arm 350 hoisting tubular stand 80 and traversing alleyway 316 towards stand hand-off position 50, or away from the stand hand-off position 50 to be transported into racking column position 312.; FIG.', '9 is an isometric view partially cut away to show an embodiment of racking module 300 in which upper racking arm 350 is hoisting tubular stand 80 in the stand hand-off position 50, after retrieving it from racking column position 312 of fingerboard assembly 310 (see FIG. 7) and carrying it along the alleyway 316 (see FIG.', '8) in preparation for setting down the tubular stand 80 in the stand hand-off position 50 (see FIG. 11); or after retrieving tubular stand 80 from the stand hand-off position 50 (see FIG.', '11) in preparation for traversing alleyway 316 (see FIG.', '8) to deliver the tubular stand to a racking column position 312 of fingerboard assembly 310 (see FIG. 7).; FIG.', '10 is an isometric view of an embodiment of upper racking arm 350, illustrating the travel range and rotation of gripper 382 connected to sleeve 380 and arm 370, as suspended from bridge 358.', 'Upper racking arm 350 may have a bridge 358 spanning an inner runway 304 and an outer runway 306 supported on frame 302.', 'Bridge 358 may have an outer roller assembly 354 and an inner roller assembly 356 for supporting movement of upper racking arm 350 along runways 306 and 304, respectively (see FIG.', '11)', ', on racking module 300.; FIG.', '11 is an isometric view of an embodiment of the racking module 300 of FIG.', '7 and the upper racking arm 350 of FIG.', '10, shown from the opposite side to illustrate clasp 408 of upper stand constraint 420 holding tubular stand 80 at stand hand-off position 50.', 'Mast 10 is removed from this view for clarity.', 'With the tubular stand 80 constrained at stand hand-off position 50, upper racking arm 350 is free to travel into position to hoist the next tubular stand 80 from the racking column position 312, or to retrieve the tubular stand 80 from the stand hand-off position 50 in the case of tripping out, for example.', 'Upper stand constraint 420 can be used to secure tubular stand 80 in place at stand hand-off position 50, e.g., restricting horizontal movement and optionally allowing vertical movement.', 'This facilitates delivery of tubular stand 80 and other tubular stands (such as drill collars) between the stand hand-off position 50 and upper racking arms 350, 351 and also between the stand hand-off position 50 and tubular delivery arm 500 or retractable top drive assembly 200.; FIG.', '11A is an isometric view of an embodiment of upper stand constraint 420 or lower stand constraint 440, shown with carriage 404 (FIG. 11) retracted.', 'Upper stand constraint 420 as shown in this embodiment can be positioned high above drill floor 6, on racking module 300 (FIG. 11).', 'The stand constraint 440 as shown in this embodiment can also be positioned below drill floor 6, on setback platform 900 (see FIG. 1).', 'In this configuration, the respective alleyway 316, 912 (FIGS. 7, 33) is clear to allow a tubular stand 80 to be moved to or from the stand hand-off position 50.; FIG.', '11B is an isometric view of stand constraint 420, 440 of FIG.', '11A, according to some embodiments, illustrating carriage 404 extended and clasp 408 closed, as it would be around a tubular stand 80 received in the stand hand-off position 50.', 'Stand constraint 420, 440 has a frame 402.', 'A surface 414 forms the top of stand constraint 420, 440.', 'A carriage 404 is connected to frame 402 in an extendable relationship.', 'A carriage actuator 406 is connected between frame 402 and carriage 404 and is operable to extend and retract carriage 404 from frame 402.', 'A clasp 408 is pivotally connected to the end of carriage 404.', 'A clasp actuator is operable to open and close clasp 408.; FIG.', '12 is an isometric view of an embodiment of tubular delivery arm 500 of the disclosed embodiments, and FIG.', '12A is an isometric exploded view.', 'Retractable top drive assembly 200 provides a first tubular handling device that vertical translates mast 10.', 'Tubular delivery arm 500 provides a second tubular handling functionality that may be, for example, vertically translatable along the same mast 10 of transportable land drilling rig 1, without physically interfering with retractable top drive assembly 200.', 'In some embodiments, tubular delivery arm 500 comprises a dolly 510.', 'In one embodiment, adjustment pads 514 are attached to ends 511 and 512 of dolly 510.', 'A slide pad 516 may be located on each adjustment pad 514, and configured for sliding engagement with front side 12 of mast 10 of drilling rig 1.', 'Adjustment pads 514 permit precise centering and alignment of dolly 510 on mast 10.', 'In other embodiments, rollers, rack and pinion, or other arrangements may be incorporated in place of or in addition to slide pads 516.; FIG. 13 is an isometric view of another embodiment of the tubular delivery arm 500 of the disclosed embodiments, and FIG.', '13A is an isometric exploded view.', 'In this embodiment, an incline actuator 552 is operative to control the angle of tubular clasp 550 relative to arm 532.', 'FIG.', '13 illustrates arms 532 rotated and tilted to position clasp 550 over well center 30 as seen in FIGS.', '14 and 14A, and FIG.', '13B illustrates arms 532 rotated and tilted to position clasp 550 to receive a tubular stand 80 in the stand hand-off position 50.', 'As also seen in FIG.', '14, extension of the incline actuator 552 inclines tubular clasp 550 to permit tilting of heavy tubular stands, such as large collars, and to position tubular clasp 550 properly for receiving a tubular section 81 or tubular stand 80 from catwalk 600 at catwalk position 60.; FIGS.', '14 and 14A illustrate an exemplary lateral range of the motion of tubular delivery arm 500 to position a tubular stand 80 relative to positions of use on drilling rig 1.', 'Tubular delivery arm 500 can retrieve and deliver a tubular stand 80 between well center 30, mousehole position 40, and stand hand-off position 50, and optionally to catwalk position 60, where clasp 550 can be inclined for retrieving or delivering tubular stand 80 from catwalk 600.; FIG.', '14B is a side view of one embodiment of tubular delivery arm 500 shown connected to drilling mast 10 of drilling rig 1 in catwalk position 60 (see FIG.', '3) to receive a tubular section 2 from catwalk 600.', 'For this purpose, it is advantageous to have inclination control of clasp 550, as disclosed in an embodiment shown in FIGS.', '11-14.; FIG.', '14C is an isometric view of the embodiment of tubular delivery arm 500 of FIG.', '14B, receiving a tubular section 2 (drill pipe 2) from catwalk 600.', 'As seen in this view, tubular delivery arm 500 is articulated outwards by tilt actuator 540 to permit clasp 550 to attach to tubular section 2.', 'From this position, tubular delivery arm 500 can be used to deliver tubular section 2 to the well center for make-up with the drill string in the well by an iron roughneck 750 shown positioned by a drill floor manipulating arm 700.', 'In some embodiments, tubular delivery arm 500 can be used to build a stand with another drill pipe 2 secured in a mousehole 40 as shown in FIG.', '14D.; FIG.', '14E is a side view of an embodiment of tubular delivery arm 500 connected to a drilling mast 10 and in position to receive (or deliver) tubular stand 80 from stand hand-off position 50 at racking module 300.; FIG.', '14F is an isometric view of the embodiment of tubular delivery arm 500 of FIG. 7, illustrating tubular delivery arm 500 articulated to stand hand-off position 50 between racking module 300 and mast 10, and having tubular stand 80 secured in clasp 550.; FIG.', '14G is a side view of an embodiment of tubular delivery arm 500 connected to drilling mast 10 and in position to deliver tubular stand 80 to well center 30 to stab into a stump secured at well center 30.', 'After stabbing, tubular delivery arm 500 can hand tubular stand 80 off to top drive assembly 200.; FIG.', '15 is an isometric view of an embodiment of the tubular delivery arm 500, in which a portion of the upper racking module is cut away to more clearly illustrate tubular delivery arm 500 articulated to stand hand-off position 50 between racking module 300 and mast 10, and having a tubular stand 80 secured in clasp 550.; FIG.', '16 is an isometric view of the embodiment of tubular delivery arm 500 of FIG.', '14, illustrating tubular delivery arm 500 being articulated over well center 30 and handing tubular stand 80 off to retractable top drive assembly 200.', 'Tubular delivery arm 500 is articulated by expansion of tilt actuator 540, which inclines arms 532 into position such that the centerline of tubular stand 80 in clasp 550 is directly over well center 30.; FIG.', '16A is an isometric view of the embodiment of the tubular delivery arm of FIG.', '16, illustrating tubular delivery arm 500 connected to tubular stand 80 at stand hand-off position 50.', 'Tubular stand 80 is shown secured in the stand hand-off position by clasp 408 of upper stand constraint 420 beneath racking module 300.', 'In this position, tubular delivery arm 500 may activate grease dispenser 560 to apply an appropriate amount of grease inside the box end of tubular stand 80.; FIG.', '16B is an isometric view of the embodiment of tubular delivery arm 500 of FIG.', '16A, illustrating tubular delivery arm 500 hoisting tubular stand 80 released by upper stand constraint 420 away from stand hand-off position 50 adjacent to racking module 300.', 'In this manner, tubular delivery arm 500 is delivering and centering tubular stands 80 for top drive assembly 200.', 'This design allows independent and simultaneous movement of tubular delivery arm 500 and top drive assembly 200.', 'This combined capability provides accelerated trip speeds.', 'The limited capacity of tubular delivery arm 500 to lift tubular stands 80 of drill pipe drill collars allows the weight of tubular delivery arm 500 and mast 10 to be minimized.', 'Tubular delivery arm 500 can be raised [and lowered along the front 12 of mast 10 with an electric or hydraulic crown winch 501 (see FIG.', '14B).', 'If desired, tubular delivery arm 500 could be raised and lowered along mast 10 by means of a rack and pinion arrangement, with drive motors.', '; FIG.', '17 is an isometric view of an embodiment of a lower stabilizing arm 800, that may be pivotally and/or rotatably mounted to the base for connection to a lower portion of a drilling mast, illustrating the rotation, pivot, and extension of an arm 824.', 'In this embodiment, arm 824 is pivotally and rotationally connected to a mast bracket 802.', 'An arm bracket 806 is rotationally connected to mast bracket 802.', 'Arm 824 is pivotally connected to arm bracket 806.', 'A pivot actuator 864 controls the pivotal movement of arm 824 relative to arm bracket 806 and thus mast bracket 802.', 'A rotary table 810 controls the rotation of arm 824 relative to arm bracket 806 and thus mast bracket 802.', 'Arm 824 is extendable as shown.; FIG.', '18 is a top view of an embodiment of a lower stabilizing arm 800, illustrating the change in positioning that occurs as lower stabilizing arm 800 relocates between the positions of well center 30, mousehole 40, stand hand-off position 50, and catwalk 60.; FIG.', '19 is an isometric view of an embodiment of lower stabilizing arm 800 connected to a leg 20 of drilling rig 1, and illustrating lower stabilizing arm 800 capturing the lower end of tubular stand 80 and guiding tubular stand 80 to well center 30 for stabbing into drill string 90.', 'Once stabbed, iron roughneck 760 will connect the tool joints.; FIG.', '20 illustrates an embodiment of lower stabilizing arm 800 secured to the lower end of tubular section 81 and preparing to stab it into the box connection of tubular section 81 located in mousehole 40 in a stand building procedure.', 'In FIG.', '20, tubular section 81 in mousehole 40 is secured to drill floor 6 by a tubular gripping 409 of intermediate stand constraint 430.; FIG.', '21 is an isometric view of an embodiment of an intermediate stand constraint 430.', 'Intermediate stand constraint 430 as shown can be connected at or immediately beneath drill floor 6, as illustrated in FIG.', '1.', 'Intermediate stand constraint 430 has a frame 433 that may be configured as a single unit or as a pair, as illustrated.', 'A carriage 435 is extendably connected to frame 433.', 'In the view illustrated, carriage 435 is extended from frame 433.', 'A carriage actuator 437 is connected between frame 433 and carriage 435 and is operable to extend and retract carriage 435 from frame 433.; FIG.', '22 is an isometric view of the embodiment of intermediate stand constraint 430 of FIG.', '21', ', illustrating carriage 435 retracted, and transport bracket pivoted into a transport position.', 'In operation, intermediate stand constraint 430 can facilitate stand building at mousehole 40.', 'For example, intermediate stand constraint 430 may be used to vertically secure a first tubular section 81.', 'A second tubular section 81 may then be positioned in series alignment by a hoisting mechanism such as the tubular delivery arm 500.', 'With the use of an iron roughneck 760 (see FIG. 19 and FIG.', '20) movably mounted at drill floor 6, the series connection between the first and second tubular sections 81 can be made to create a double tubular stand 80.', 'Gripping assembly 439 can then be released to permit the double tubular stand 80 to be lowered into mousehole 40.', 'Gripping assembly 439 can then be actuated to hold double tubular stand 80 in centered position, as a third tubular section 81 is hoisted above and stabbed into double tubular section 81.', 'Once again, iron roughneck 760 on drill floor 6 can be used to connect the third tubular section 81 and form a triple tubular stand 80.; FIGS.', '23-25 illustrate an embodiment of high trip rate drilling rig 1 in the process of moving tubular stands 80 from racking module 300 to well center 30 for placement into the well.', 'To keep the drawings readable, some items mentioned below may not be numbered.', 'Please refer to FIGS.', '1-22 for the additional detail.;', 'FIG.', '23 shows an embodiment of tubular delivery arm 500 on a front side 12 of mast 10 in an unarticulated position above racking module 300 on front side 12 of mast 10.', 'In this position, tubular delivery arm 500 is above stand hand-off position 50, and vertically above retractable top drive assembly 200.', 'Tubular stand 80 has been connected to the drill string in the well (not visible) and is now a component of drill string 90.', 'Tubular stand 80 and the rest of drill string 90 is held by retractable top drive assembly 200, which is articulated into its well center 30 position, and is descending along mast 10 downward towards drill floor 6.; FIG.', '33 is a top view of an embodiment of setback platform 900 on which the tubular stands 80 are stacked in accordance with their respective positions in the fingerboard assembly 310.', 'Drilling rig 1, catwalk 600 and tubular stands 80 are removed for clarity.', 'This embodiment illustrates the relationship between well center 30, mousehole 40, and stand hand-off position 50.', 'As seen in this view, an alleyway 912 is provided on the front edge of setback platform 900.', 'Stand hand-off position 50 is located in the platform alleyway 912, in alignment with mousehole 40 and well center 30.', 'A pair of lower racking arms 950 is also located in alleyway 912.; FIG.', '34 is an isometric view of an embodiment of setback platform 900 of the tubular racking system of the disclosed embodiments.', 'Setback platform 900 comprises platform 910 for vertical storage of tubular stands 80.', 'Platform 910 has a mast side and an opposite catwalk side.', 'Alleyway 912 extends along the mast side of platform 910.', 'Alleyway 912 is offset below platform 910.', 'Stand hand-off position 50 is located on alleyway 912.', 'A geared rail 914 is affixed to alleyway 912.', 'A lower racking arm 950 is provided, having a base 952 translatably connected to the rail 914.', 'A lower racking frame 970 is connected to the base 952 in rotatable and pivotal relation.', 'A lower racking arm member 980 is pivotally connected to the frame 970, and a clasp 990 is pivotally connected to the arm member 980.; FIG.', '35 is an isometric view of an embodiment of upper racking module 300 illustrating tubular stand 80 held at stand hand-off position 50 by upper stand constraint 420, and engaged by upper racking arm 350 and by lower racking arm 950.', 'Optional engagement with lower stand constraint 440 is not shown.', 'Lower racking arm 950 in some embodiments can allow the lower end of the stand 80 to rotate freely on the centerline of tubular stand 80, e.g., and the arm 950 can thus follow upper racking arm 350 between stand hand-off position 50 and any racking position in racking module 300, while keeping tubular stand 80 vertical.; FIG.', '36 is an isometric view illustrating an embodiment of tubular stand 80 supported vertically by upper racking arm 350 and held at its lower end by lower racking arm 950, and extended to its designated racking position.; FIG.', '37 is an isometric view of an embodiment of a stand hand-off station 450.', 'Referring to the embodiments illustrated in FIGS.', '34-36, stand hand-off station 450 is located at stand hand-off position 50, in alleyway 912.', 'Alleyway 912 is set vertically below surface 910.', 'This permits positioning of stand hand-off station 450 below surface 910 so that tubular stand 80 need not be raised a significant distance by upper racking arm 350 to achieve access to stand hand-off station 450.'] |
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US11136853 | Inflatable packer system for an annular blowout preventer | Dec 13, 2019 | Ray Zonoz, Steven Shimonek, Nicolas Arteaga, Bruce Boulanger, Taylor Mozisek, Jeffrey Lambert, Ian McDaniel | Schlumberger Technology Corporation | NPL References not found. | 3661204; May 1972; Blanding; 3737139; June 1973; Watts; 4007904; February 15, 1977; Jones; 6230824; May 15, 2001; Peterman; 20090090502; April 9, 2009; Lumbye; 20090101351; April 23, 2009; Hannegan; 20170058624; March 2, 2017; Jaffrey; 20180142543; May 24, 2018; Gupta | 2017/109506; June 2017; WO; 2017/109508; June 2017; WO; 2017/109509; June 2017; WO | ['An inflatable packer system for an annular blowout preventer (BOP) includes an inflatable bladder configured to be positioned within a housing of the annular BOP and to inflate upon receipt of a fluid within the inflatable bladder.', 'The inflatable bladder may be an annular structure that is configured to circumferentially surround a bore of the annular BOP.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'An annular blowout preventer (BOP) is installed on a wellhead to seal and control an oil and gas well during drilling operations.', 'A drill string may be suspended inside the oil and gas well from a rig through the annular BOP into the wellbore.', 'During drilling operations, a drilling fluid is delivered through the drill string and returned up through an annulus between the drill string and a casing that lines the wellbore.', 'In the event of a rapid invasion of formation fluid in the annulus, commonly known as a “kick,” the annular BOP may be actuated to seal the annulus and to control fluid pressure in the wellbore, thereby protecting well equipment disposed above the annular BOP.', 'Characteristics of a packer assembly of the annular BOP can affect the ability of the annular BOP to seal the annulus.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n is a block diagram of a mineral extraction system in accordance with an embodiment of the present disclosure;\n \nFIG.', '2\n is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes an inflatable bladder, a packer, and multiple inserts;\n \nFIG.', '3\n is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes an inflatable bladder, a packer, and multiple iris-style inserts;\n \nFIG.', '4\n is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes an inflatable bladder, a donut, a packer, and multiple iris-style inserts;\n \nFIG.', '5\n is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes an inflatable bladder positioned vertically below a packer and multiple inserts;\n \nFIG.', '6\n is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes an inflatable bladder and a piston;\n \nFIG.', '7\n is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes an inflatable bladder configured to contact and seal against a conduit within a bore of the annular BOP;\n \nFIG.', '8\n is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes an inflatable bladder, an additional inflatable bladder, and multiple inserts; and\n \nFIG.', '9\n is a cross-sectional top view of an embodiment of an annular BOP that may be used in the system of \nFIG.', '1\n, wherein the annular BOP includes multiple inflatable bladders positioned circumferentially about a packer assembly.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nOne or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'The present embodiments are generally directed to annular blowout preventers (BOPs).', 'In particular, the present embodiments are generally directed to annular BOPs that include an inflatable bladder (e.g., bag, container) that is configured to inflate (e.g., expand; adjust from a deflated state to an inflated state) upon receipt of a fluid (e.g., liquid or gas).', 'Inflation of the inflatable bladder may cause the annular BOP to transition from an open position to a closed position to seal an annulus around a conduit disposed through a central bore of the annular BOP or to close the central bore.', 'For example, upon inflation, the inflatable bladder may drive a packer and multiple inserts radially-inwardly such that the packer contacts the conduit and seals the annulus around the conduit.', 'In some embodiments, upon inflation, the inflatable bladder may expand such that the inflatable bladder contacts the conduit and seals the annulus around the conduit.', 'While the disclosed embodiments are described in the context of a drilling system and drilling operations to facilitate discussion, it should be appreciated that the annular BOP may be adapted for use in other contexts and other operations.', 'For example, the annular BOP may be used in a pressure control equipment (PCE) stack that is coupled to and/or positioned vertically above a wellhead during various intervention operations (e.g., inspection or service operations), such as wireline operations in which a tool supported on a wireline is lowered through the PCE stack to enable inspection and/or maintenance of a well.', 'In such cases, the annular BOP may be adjusted from the open position to the closed position (e.g., to seal about the wireline extending through the PCE stack) to isolate the environment, as well as other surface equipment, from pressurized fluid within the well.', 'In the present disclosure, a conduit may be any of a variety of tubular or cylindrical structures, such as a drill string, wireline, Streamline™, slickline, coiled tubing, or other spoolable rod.', 'With the foregoing in mind, \nFIG.', '1\n is a block diagram of an embodiment of a mineral extraction system \n10\n.', 'The mineral extraction system \n10\n may be configured to extract various minerals and natural resources, including hydrocarbons (e.g., oil and/or natural gas), from the earth, or to inject substances into the earth.', 'The mineral extraction system \n10\n may be a land-based system (e.g., a surface system) or an offshore system (e.g., an offshore platform system).', 'A BOP assembly \n16\n is mounted to a wellhead \n18\n, which is coupled to a mineral deposit \n25\n via a wellbore \n26\n (e.g., a casing string within the wellbore \n26\n).', 'The wellhead \n18\n may include any of a variety of other components such as a spool, a hanger, and a “Christmas” tree.', 'The wellhead \n18\n may return drilling fluid or mud to the surface \n12\n during drilling operations, for example.', 'Downhole operations are carried out by a conduit \n24\n that extends through the BOP assembly \n16\n, through the wellhead \n18\n, and into the wellbore \n26\n.', 'To facilitate discussion, the BOP assembly \n16\n and its components may be described with reference to an axial axis or direction \n30\n, a radial axis or direction \n32\n, and a circumferential axis or direction \n34\n.', 'The BOP assembly \n16\n may include one or more annular BOPs \n42\n.', 'A central bore \n44\n (e.g., flow bore) extends through the one or more annular BOPs \n42\n.', 'As discussed in more detail below, at least one of the annular BOPs \n42\n may include an inflatable bladder that is configured to inflate upon receipt of a fluid.', 'As the inflatable bladder inflates, the inflatable bladder may cause the annular BOP \n42\n to transition from an open position to a closed position to seal an annulus around the conduit \n24\n disposed through the central bore \n44\n of the annular BOP \n42\n or to close the central bore \n44\n (e.g., to block flow through the central bore \n44\n).', 'FIG.', '2\n is a cross-sectional side view of the annular BOP \n42\n that may be used in the system \n10\n of \nFIG.', '1\n.', 'To facilitate discussion, the annular BOP \n42\n is shown in an open position \n50\n on one side of a central axis \n52\n of the annular BOP \n42\n, and the annular BOP \n42\n is shown in a closed position \n54\n on the other side of the central axis \n52\n of the annular BOP \n42\n.', 'In the open position \n50\n, the annular BOP \n42\n may enable fluid flow through the central bore \n44\n of the annular BOP \n42\n.', 'In the closed position \n54\n, the annular BOP \n42\n may block fluid flow through the central bore \n44\n of the annular BOP \n42\n.', 'As shown, the annular BOP \n42\n includes a housing \n56\n (e.g., annular housing), and a packer assembly \n60\n (e.g., annular packer assembly) within the housing \n56\n includes a packer \n62\n (e.g., annular packer) and multiple inserts \n64\n.', 'The packer \n62\n may be a flexible component (e.g., elastomer) and the multiple inserts \n64\n may be rigid components (e.g., metal or metal alloy).', 'The multiple inserts \n64\n may extend axially through the packer \n62\n and may be positioned at discrete circumferential locations about the packer \n62\n.', 'As shown, the annular BOP \n42\n also includes an inflatable bladder system \n70\n, which includes an inflatable bladder \n72\n (e.g., inflatable packer) positioned within the housing \n56\n.', 'In the illustrated embodiment, the inflatable bladder \n72\n is an annular structure that circumferentially surrounds the packer assembly \n60\n, and the inflatable bladder \n72\n is positioned between the packer assembly \n60\n and side walls of the housing \n56\n along the radial axis \n32\n.', 'The inflatable bladder system \n70\n may also include an inflation conduit \n74\n (e.g., fluid conduit), a valve \n76\n configured to adjust a flow of a fluid (e.g., liquid or gas) from a fluid source \n78\n, an actuator \n80\n configured to control the valve \n76\n, and an electronic controller \n82\n that is configured to generate control signals to control the actuator \n80\n.', 'For example, upon an undesired increase in pressure within the wellbore (e.g., wellbore \n26\n, \nFIG.', '1\n), the electronic controller \n82\n may generate a control signal to instruct the actuator \n80\n to open the valve \n76\n to enable the flow of the fluid from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n.', 'The fluid source \n78\n may also include or be associated with a pump, and the electronic controller \n82\n may control the pump to force the fluid into the inflatable bladder \n72\n even in the presence of the undesired increase in pressure within the wellbore.', 'In some embodiments, the inflatable bladder system \n70\n may be configured to use the wellbore pressure as a booster to boost the pressure of the fluid within the inflatable bladder \n72\n (e.g., by diverting fluid from the wellbore to the inflatable bladder \n72\n and/or to a component that causes inflation of the inflatable bladder \n72\n).', 'In this way, the inflatable bladder system \n70\n may inflate the inflatable bladder \n72\n from a deflated state \n84\n to an inflated state \n86\n in response to the increase in pressure within the wellbore.', 'The inflatable bladder \n72\n may have a first volume in the deflated state \n84\n and a second volume, greater than the first volume, in the inflated state \n86\n.', 'In the illustrated embodiment, as the inflatable bladder \n72\n inflates, the inflatable bladder \n72\n may contact and exert a force (e.g., along the radial axis \n32\n) on the packer assembly \n60\n that drives the packer assembly \n60\n radially-inwardly into the central bore \n44\n of the annular BOP \n42\n, thereby enabling the packer \n62\n to contact and seal against the conduit \n24\n to block the fluid flow across the annular BOP \n42\n.', 'In particular, a radially-inner surface \n88\n (e.g. annular surface) of the inflatable bladder \n72\n contacts a radially-outer surface \n90\n (e.g., annular surface) of the packer assembly \n60\n to drive the packer assembly \n60\n radially-inwardly into the central bore \n44\n of the annular BOP \n42\n, thereby enabling the packer \n62\n to contact and seal against the conduit \n24\n to block the fluid flow across the annular BOP \n42\n.', 'The inflatable bladder system \n70\n may flow and/or force the fluid into the inflatable bladder \n72\n until the annular BOP \n42\n reaches the closed position \n54\n (e.g., as determined by the electronic controller \n82\n based on data obtained from a sensor, such as a pressure sensor, located vertically above the annular BOP \n42\n), until the fluid stops flowing and/or cannot be forced into the inflatable bladder \n72\n (e.g., due to a maximum inflation of the inflatable bladder \n72\n being reached and/or a maximum compression of the packer assembly \n60\n against the conduit \n24\n being reached), and/or in response to some other condition.', 'As shown, the inflatable bladder \n72\n may completely or substantially (e.g., approximately equal to or greater than 95, 90, 85, 80, or 75 percent) fill an annular space defined between the packer assembly \n60\n and the side walls of the housing \n56\n along the radial axis \n32\n while the inflatable bladder \n72\n is in the inflated state \n86\n and while the annular BOP \n42\n is in the closed position \n54\n.', 'Together, the packer assembly \n60\n and the inflatable bladder system \n70\n may form an inflatable packer system \n92\n.', 'As shown, the electronic controller \n82\n includes a processor \n94\n and a memory device \n96\n.', 'In some embodiments, the processor \n94\n may receive and process signals from a sensor that monitors the pressure within the wellbore to determine that the annular BOP \n42\n should be adjusted from the open position \n50\n to the closed position \n54\n.', 'In some embodiments, the processor \n94\n may receive other signals (e.g., operator input) that indicate that the annular BOP \n42\n should be adjusted from the open position \n50\n to the closed position \n54\n.', 'Then, the processor \n94\n may provide control signals, such as to the actuator \n80\n to adjust the valve \n76\n, in response to the determination or the indication that the annular BOP \n42\n should be adjusted from the open position \n50\n to the closed position \n54\n.', 'The electronic controller \n82\n may be part of or include a distributed controller or control system with one or more electronic controllers in communication with one another to carry out the various techniques disclosed herein.', 'The processor \n94\n may also include one or more processors configured to execute software, such as software for processing signals and/or controlling the components associated with the annular BOP \n42\n.', 'The memory device \n96\n disclosed herein may include one or more memory devices (e.g., a volatile memory, such as random access memory [RAM], and/or a nonvolatile memory, such as read-only memory [ROM]) that may store a variety of information and may be used for various purposes.', 'For example, the memory device \n96\n may store processor-executable instructions (e.g., firmware or software) for the processor \n94\n to execute, such as instructions for processing signals and/or controlling the components associated with the annular BOP \n42\n.', 'It should be appreciated that the electronic controller \n82\n may include various other components, such as a communication device \n98\n that is capable of communicating data or other information to various other devices (e.g., a remote computing system).', 'FIG.', '3\n is a cross-sectional side view of an embodiment of the annular BOP \n42\n that may be used in the system \n10\n of \nFIG.', '1\n, wherein the multiple inserts \n64\n are iris-style inserts.', 'The annular BOP \n42\n of \nFIG.', '3\n may operate similarly to the annular BOP \n42\n of \nFIG.', '2\n, except that the inserts \n64\n may be configured and arranged to carry out an iris-style closing (e.g., radially-inward rotation) similar to that of an iris shutter of a camera that acts to block extrusion of the flexible material of the packer \n62\n.', 'In particular, the annular BOP \n42\n is shown in the open position \n50\n on one side of the central axis \n52\n of the annular BOP \n42\n, and the annular BOP \n42\n is shown in the closed position \n54\n on the other side of the central axis \n52\n of the annular BOP \n42\n.', 'As shown, the annular BOP \n42\n includes the housing \n56\n, and the packer assembly \n60\n within the housing \n56\n includes the packer \n62\n and the multiple inserts \n64\n.', 'The multiple inserts \n64\n extend axially through the packer \n62\n and are positioned at discrete circumferential locations about the packer \n62\n.', 'As shown, the annular BOP \n42\n also includes the inflatable bladder system \n70\n having the inflatable bladder \n72\n, which circumferentially surrounds the packer assembly \n60\n and is positioned between the packer assembly \n60\n and side walls of the housing \n56\n along the radial axis \n32\n.', 'The inflatable bladder system \n70\n may also include the inflation conduit \n74\n, the valve \n76\n, the fluid source \n78\n, the actuator \n80\n, and the electronic controller \n82\n.', 'Upon an undesired increase in pressure within the wellbore, the inflatable bladder system \n70\n may cause the fluid to flow from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n.', 'In this way, the inflatable bladder system \n70\n may inflate the inflatable bladder \n72\n from the deflated state \n84\n to the inflated state \n86\n in response to the increase in pressure within the wellbore.', 'In the illustrated embodiment, as the inflatable bladder \n72\n inflates, the inflatable bladder \n72\n may contact and exert a force on the packer assembly \n60\n that drives the packer assembly \n60\n radially-inwardly into the central bore \n44\n of the annular BOP \n42\n, thereby enabling the packer \n62\n to contact and seal against the conduit \n24\n to block the fluid flow across the annular BOP \n42\n.', 'As the inflatable bladder \n72\n drives the packer assembly \n60\n radially-inwardly into the central bore \n44\n of the annular BOP \n42\n, the multiple inserts \n64\n carry out the iris-style closing by sliding against one another and rotating circumferentially relative to the central bore \n44\n.', 'In \nFIGS.', '2 and 3\n, the annular BOP \n42\n is devoid of a donut (e.g., flexible annular structure) that circumferentially surrounds the packer assembly \n60\n.', 'Instead, the inflatable bladder \n72\n directly contacts and extends radially between a portion of the packer assembly \n60\n (e.g., the packer \n62\n and/or the multiple inserts \n64\n) and the side walls of the housing \n56\n.', 'Indeed, the inflatable bladder \n72\n and the packer assembly \n60\n (e.g., the packer \n62\n and the multiple inserts \n64\n) may be the only adjustable (e.g., movable; capable of changing shapes) components that are positioned within a cavity of the housing \n56\n and that adjust to transition the annular BOP \n42\n to the closed position \n54\n.', 'However, it should be appreciated that a donut may be included and may be positioned to circumferentially surround the packer assembly \n60\n.', 'In such cases, the inflatable bladder \n72\n may be positioned in any of a variety of locations relative to the donut.', 'For example, \nFIG.', '4\n is a cross-sectional side view of an embodiment of the annular BOP \n42\n that may be used in the system \n10\n of \nFIG.', '1\n, wherein the annular BOP \n42\n includes the inflatable bladder \n72\n positioned vertically below a donut \n100\n, the packer \n62\n, and the multiple inserts \n64\n (e.g., relative to the wellbore, such as the wellbore \n26\n of \nFIG.', '1\n, along the axial axis \n30\n).', 'In \nFIG.', '4\n, the annular BOP \n42\n is shown in the open position \n50\n on one side of the central axis \n52\n of the annular BOP \n42\n, and the annular BOP \n42\n is shown in the closed position \n54\n on the other side of the central axis \n52\n of the annular BOP \n42\n.', 'As shown, the annular BOP \n42\n includes the housing \n56\n, and the packer assembly \n60\n within the housing \n56\n includes the packer \n62\n and the multiple inserts \n64\n.', 'The multiple inserts \n64\n extend axially through the packer \n62\n and are positioned at discrete circumferential locations about the packer \n62\n.', 'The donut \n100\n circumferentially surrounds the packer assembly \n60\n and is positioned between the packer assembly \n60\n and side walls of the housing \n56\n along the radial axis \n32\n.', 'In some embodiments, as shown, a push plate \n102\n (e.g., annular plate) may be positioned vertically below the donut \n100\n, the packer \n62\n, and the multiple inserts \n64\n.', 'The annular BOP \n42\n also includes the inflatable bladder system \n70\n having the inflatable bladder \n72\n, which is positioned vertically below the donut \n100\n, the packer assembly \n60\n, and the push plate \n102\n.', 'The inflatable bladder system \n70\n may also include the inflation conduit \n74\n, the valve \n76\n, the fluid source \n78\n, the actuator \n80\n, and the electronic controller \n82\n.', 'Upon an undesired increase in pressure within the wellbore, the inflatable bladder system \n70\n may cause the fluid to flow from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n.', 'In this way, the inflatable bladder system \n70\n may inflate the inflatable bladder \n72\n in response to the increase in pressure within the wellbore.', 'As shown, the inflatable bladder \n72\n may contact and exert a force (e.g., along the axial axis \n30\n) against the push plate \n102\n at least while the inflatable bladder \n72\n is in the inflated state \n86\n and the annular BOP \n42\n is in the closed position \n54\n.', 'The push plate \n102\n may contact and transfer the force to the donut \n100\n, the packer \n62\n, and/or the multiple inserts \n64\n at least while the inflatable bladder \n72\n is in the inflated state \n86\n and the annular BOP \n42\n is in the closed position \n54\n.', 'Thus, as the inflatable bladder \n72\n inflates, the inflatable bladder \n72\n may drive the push plate \n102\n, the donut \n100\n, and/or packer assembly \n60\n vertically upward within the housing \n56\n.', 'When driven vertically upward in this way, the packer assembly \n60\n may also move radially-inwardly into the central bore \n44\n of the annular BOP \n42\n (e.g., guided by top surfaces of the housing \n56\n and/or the top surface of the push plate \n102\n), thereby enabling the packer \n62\n to contact and seal against the conduit \n24\n to block the fluid flow across the annular BOP \n42\n.', 'As the inflatable bladder \n72\n drives the packer assembly \n60\n vertically upward and radially-inwardly into the central bore \n44\n of the annular BOP \n42\n, the multiple inserts \n64\n shown in \nFIG.', '4\n may carry out the iris-style closing by sliding against one another and rotating circumferentially relative to the central bore \n44\n.', 'It should be appreciated that the inflatable bladder \n72\n may be positioned vertically below the packer assembly \n60\n in other configurations.', 'For example, \nFIG.', '5\n is a cross-sectional side view of an embodiment of the annular BOP \n42\n that may be used in the system \n10\n of \nFIG.', '1\n, wherein the annular BOP \n42\n includes the inflatable bladder \n72\n positioned vertically below the packer assembly \n60\n.', 'As shown, the annular BOP \n42\n is shown in the open position \n50\n on one side of the central axis \n52\n of the annular BOP \n42\n, and the annular BOP \n42\n is shown in the closed position \n54\n on the other side of the central axis \n52\n of the annular BOP \n42\n.', 'Additionally, the annular BOP \n42\n includes the housing \n56\n, and the packer assembly \n60\n within the housing \n56\n includes the packer \n62\n and the multiple inserts \n64\n.', 'The multiple inserts \n64\n extend axially through the packer \n62\n and are positioned at discrete circumferential locations about the packer \n62\n.', 'The annular BOP \n42\n also includes the inflatable bladder system \n70\n having the inflatable bladder \n72\n, which is positioned vertically below the packer assembly \n60\n.', 'The inflatable bladder system \n70\n may also include a push plate \n103\n (e.g., annular push plate), the inflation conduit \n74\n, the valve \n76\n, the fluid source \n78\n, the actuator \n80\n, and the electronic controller \n82\n.', 'Upon an undesired increase in pressure within the wellbore, the inflatable bladder system \n70\n may cause the fluid to flow from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n.', 'In this way, the inflatable bladder system \n70\n may inflate the inflatable bladder \n72\n in response to the increase in pressure within the wellbore.', 'As shown, the inflatable bladder \n72\n may contact the push plate \n103\n at least while the inflatable bladder \n72\n is in the inflated state \n86\n and the annular BOP \n42\n is in the closed position \n54\n.', 'The push plate \n103\n may have a shape (e.g., an axially-extending segment) that blocks extrusion of the inflatable bladder \n72\n into the central bore \n44\n.', 'However, in some embodiments, the annular BOP \n42\n may not include the push plate \n103\n, and instead, the inflatable bladder \n72\n may contact the packer \n62\n and/or the multiple inserts \n64\n.', 'In the illustrated embodiment, as the inflatable bladder \n72\n inflates, the inflatable bladder \n72\n may contact and/or exert a force on the packer assembly \n60\n that drives the packer assembly \n60\n vertically upward within the housing \n56\n.', 'When driven vertically upward in this way, the packer assembly \n60\n may also move radially-inwardly into the central bore \n44\n of the annular BOP \n42\n (e.g., guided by curved surfaces of the housing \n56\n), thereby enabling the packer \n62\n to contact and seal against the conduit \n24\n to block the fluid flow across the annular BOP \n42\n.', 'In some embodiments, the inflatable bladder \n72\n may drive the packer assembly \n60\n radially-inwardly without rotation (e.g., without rotation in the circumferential direction \n34\n) and/or a shape of the packer assembly \n60\n may adapted to receive (e.g., mate with; accommodate) the inflatable bladder \n72\n.', 'For example, \nFIG.', '6\n is a side view of an embodiment of the annular BOP \n42\n that may be used in the system \n10\n of \nFIG.', '1\n, wherein the annular BOP \n42\n includes the inflatable bladder system \n70\n having the inflatable bladder \n72\n positioned within a recess \n104\n (e.g., annular recess) formed in a radially-outer surface of the packer assembly \n60\n.', 'The inflatable bladder system \n70\n may also include the inflation conduit \n74\n, the valve \n76\n, the fluid source \n78\n, the actuator \n80\n, and the electronic controller \n82\n.', 'Additionally, the annular BOP \n42\n includes the housing \n56\n, and the packer assembly \n60\n within the housing \n56\n includes the packer \n62\n and the multiple inserts \n64\n.', 'The multiple inserts \n64\n extend axially through the packer \n62\n and are positioned at discrete circumferential locations about the packer \n62\n.', 'Upon an undesired increase in pressure within the wellbore, the inflatable bladder system \n70\n may cause the fluid to flow from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n.', 'In this way, the inflatable bladder system \n70\n may inflate the inflatable bladder \n72\n in response to the increase in pressure within the wellbore.', 'Additionally, upon the undesired increase in pressure within the wellbore, a piston \n106\n (e.g., annular piston) may move in a direction \n108\n in response to a fluid being delivered to a space \n109\n (e.g., annular space).', 'Thus, the inflatable bladder \n72\n may work in conjunction with the piston \n106\n to adjust the annular BOP \n42\n from the illustrated open position \n50\n to the closed position \n54\n, which may place the packer assembly \n60\n in a similar position as shown in \nFIG.', '5\n.', 'In the illustrated embodiment, as the inflatable bladder \n72\n inflates, the inflatable bladder \n72\n may exert a respective force on the packer assembly \n60\n that drives the packer assembly \n60\n radially-inwardly within the housing \n56\n.', 'The piston \n106\n may also exert a respective force on the packer assembly \n60\n that drives the packer assembly \n60\n vertically-upwardly within the housing \n56\n, which may also further drive the packer assembly \n60\n radially-inwardly into the central bore \n44\n of the annular BOP \n42\n (e.g., guided by curved surfaces of the housing \n56\n).', 'In this way, the inflatable bladder \n72\n and the piston \n106\n may enable the packer \n62\n to contact and seal against the conduit \n24\n to block the fluid flow across the annular BOP \n42\n.', 'FIGS.', '2-6\n illustrate various embodiments in which the inflatable bladder \n72\n is configured to drive the packer assembly \n60\n to contact and to seal against the conduit \n24\n to adjust the annular BOP \n42\n to the closed position \n54\n.', 'However, it should be appreciated that the inflatable bladder \n72\n may instead be configured to contact and to seal against the conduit \n24\n in the central bore \n44\n of the annular BOP \n42\n.', 'For example, \nFIG.', '7\n is a cross-sectional side view of an embodiment of the annular BOP \n42\n that may be used in the system \n10\n of \nFIG.', '1\n, wherein the annular BOP \n42\n includes the inflatable bladder \n72\n that is configured to contact and to seal against the conduit \n24\n within the central bore \n44\n of the annular BOP \n42\n.', 'The annular BOP \n42\n is shown in the open position \n50\n on one side of the central axis \n52\n of the annular BOP \n42\n, and the annular BOP \n42\n is shown in the closed position \n54\n on the other side of the central axis \n52\n of the annular BOP \n42\n.', 'Additionally, the annular BOP \n42\n includes the multiple inserts \n64\n positioned within the housing \n56\n.', 'The annular BOP \n42\n also includes the inflatable bladder system \n70\n having the inflatable bladder \n72\n positioned within the housing \n56\n.', 'In particular, the multiple inserts \n64\n and the inflatable bladder \n72\n may be positioned within a cavity \n110\n (e.g., annular cavity) of the housing \n56\n.', 'Furthermore, the inflatable bladder \n72\n may be positioned within multiple insert cavities \n112\n (e.g., recesses) of the multiple inserts \n64\n.', 'For example, each insert \n64\n may include an axially-extending portion \n114\n, as well as a radially-extending upper portion \n116\n and a radially-extending lower portion \n118\n that are spaced apart from one another along the axial axis \n30\n.', 'Thus, the insert cavities \n112\n may be defined along the axial axis \n30\n by the radially-extending upper portion \n116\n and radially-extending lower portion \n118\n, and the arrangement of the portions \n114\n, \n116\n, \n118\n enable the inflatable bladder \n72\n to be withdrawn from the central bore \n44\n of the annular BOP \n42\n while the inflatable bladder \n72\n is in the deflated state \n84\n and while the annular BOP \n42\n is in the open position \n50\n.', 'Together, the insert cavities \n112\n of the multiple inserts \n64\n form an annular recess that supports the inflatable bladder \n72\n.', 'The inflatable bladder system \n70\n may also include the inflation conduit \n74\n, the valve \n76\n, the fluid source \n78\n, the actuator \n80\n, and the electronic controller \n82\n.', 'Upon an undesired increase in pressure within the wellbore, the inflatable bladder system \n70\n may cause the fluid to flow from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n.', 'In this way, the inflatable bladder system \n70\n may inflate the inflatable bladder \n72\n in response to the increase in pressure within the wellbore.', 'The inflatable bladder \n72\n may completely or substantially (e.g., approximately equal to or greater than 95, 90, 85, 80, or 75 percent) fill the insert cavities \n112\n while the inflatable bladder \n72\n is in the inflated state \n86\n.', 'The inflation conduit \n74\n may be positioned in any of a variety of locations.', 'For example, the inflation conduit \n74\n may generally extend through the housing \n56\n and/or may extend between adjacent inserts \n64\n to reach the inflatable bladder \n72\n.', 'In some embodiments, a radially-extending notch or gap may be provided between adjacent inserts \n64\n to receive the inflation conduit \n74\n and to enable the inflatable bladder \n72\n to receive the fluid from the fluid source \n78\n.', 'In some embodiments, the multiple inserts \n64\n may be driven radially inwardly into the central bore \n44\n prior to and/or as the inflatable bladder \n72\n is inflated.', 'In this way, the multiple inserts \n64\n may support and/or block extrusion of the inflatable bladder \n72\n while the inflatable bladder is in the inflated state \n86\n.', 'The multiple inserts \n64\n may be rotated radially-inwardly via any suitable technique.', 'In some cases, the annular BOP \n42\n may include an iris assembly that is configured to convert rotational motion output by one or more motors \n120\n into rotational motion of the inserts \n64\n and to drive the inserts \n64\n toward the central axis \n52\n.', 'For example, in some embodiments, the one or more motors \n120\n may rotate a plate \n122\n that is coupled to each insert \n64\n via a respective key-slot interface.', 'The key-slot interface may include a groove \n124\n (e.g., radially extending groove) formed in the plate \n122\n and that receives a pin \n126\n coupled to the insert \n64\n.', 'As the one or more motors \n120\n rotate the plate \n122\n, the pin \n126\n may slide in the groove \n124\n and cause the inserts \n64\n to move radially-inwardly (e.g., rotate radially-inwardly).', 'Thus, upon the undesired increase in pressure within the wellbore, the electronic controller \n82\n may generate a control signal to instruct the actuator \n80\n to open the valve \n76\n to enable the flow of the fluid from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n and may generate a control signal to instruct the one or more motors \n120\n to drive the multiple inserts \n64\n radially inwardly.', 'The movement of the multiple inserts \n64\n and the inflation of the inflatable bladder \n72\n may be coordinated to reduce or to block extrusion of the inflatable bladder \n72\n.', 'For example, the electronic controller \n82\n may provide the control signals in a manner that causes the multiple inserts \n64\n to move fully radially-inwardly into the central bore \n44\n (e.g., to a radially-innermost position) prior to the initiation of inflation of the inflatable bladder \n72\n and/or prior to the inflatable bladder \n72\n inflating sufficiently to seal the central bore \n44\n.', 'Together, the multiple inserts \n64\n and the inflatable bladder system \n70\n may form the inflatable packer system \n92\n that operates to transition the annular BOP \n42\n between the open position \n50\n and the closed position \n54\n.', 'The packer assembly \n60\n may also include an additional sealing element (e.g., a packer, an additional inflatable bladder) positioned about the inserts \n64\n to block the fluid in the central bore \n44\n from leaking around the packer assembly \n60\n.', 'For example, \nFIG.', '8\n is a cross-sectional side view of an embodiment of the annular BOP \n42\n that may be used in the system \n10\n of \nFIG.', '1\n, wherein the annular BOP \n42\n includes the multiple inserts \n64\n, the inflatable bladder \n72\n, and an additional inflatable bladder \n130\n.', 'The multiple inserts \n64\n and the inflatable bladder \n72\n of \nFIG.', '8\n operate similarly to the multiple inserts \n64\n and the inflatable bladder \n72\n of \nFIG.', '7\n.', 'However, instead of the one or more motors \n120\n, the additional inflatable bladder \n130\n is provided to drive the multiple inserts \n64\n and the inflatable bladder \n72\n radially inwardly to seal the central bore \n44\n of the annular BOP \n42\n.', 'It should be appreciated that the one or more motors \n120\n of \nFIG.', '7\n and the additional inflatable bladder \n130\n may be used together, in some embodiments.', 'The annular BOP \n42\n is shown in the open position \n50\n on one side of the central axis \n52\n of the annular BOP \n42\n, and the annular BOP \n42\n is shown in the closed position \n54\n on the other side of the central axis \n52\n of the annular BOP \n42\n.', 'Additionally, the annular BOP \n42\n includes the multiple inserts \n64\n positioned within the housing \n56\n.', 'The annular BOP \n42\n also includes the inflatable bladder system \n70\n having the inflatable bladder \n72\n and the additional inflatable bladder \n130\n positioned within the housing \n56\n.', 'The inflatable bladder system \n70\n may also include the inflation conduit \n74\n, the valve \n76\n, the fluid source \n78\n, the actuator \n80\n, and the electronic controller \n82\n.', 'The inflatable bladder system \n70\n may further include an additional inflation conduit \n132\n, an additional valve \n134\n, and an additional actuator \n136\n.', 'Upon an undesired increase in pressure within the wellbore, the electronic controller \n82\n may generate a control signal to instruct the actuator \n80\n to open the valve \n76\n to enable the flow of the fluid from the fluid source \n78\n to the inflatable bladder \n72\n via the inflation conduit \n74\n.', 'Similarly, the electronic controller \n82\n may generate a control signal to instruct the additional actuator \n136\n to open the additional valve \n134\n to enable the flow of the fluid from the fluid source \n78\n to the additional inflatable bladder \n130\n via the additional inflation conduit \n132\n.', 'In this way, the inflatable bladder system \n70\n may inflate the inflatable bladder \n72\n and the additional inflatable bladder \n130\n in response to the increase in pressure within the wellbore.', 'The inflation of the inflatable bladder \n72\n and the additional inflatable bladder \n130\n may be coordinated to reduce or to block extrusion of the inflatable bladder \n72\n.', 'For example, the electronic controller \n82\n may provide the control signals in a manner that causes the additional inflatable bladder \n130\n to inflate to drive the multiple inserts \n64\n radially inwardly into the central bore \n44\n (e.g., to a radially-innermost position) prior to the initiation of inflation of the inflatable bladder \n72\n and/or prior to the inflatable bladder \n72\n inflating sufficiently to seal the central bore \n44\n.', 'Together, the multiple inserts \n64\n and the inflatable bladder system \n70\n may form the inflatable packer system \n92\n that operates to transition the annular BOP \n42\n between the open position \n50\n and the closed position \n54\n.', 'It should be appreciated that the inflatable bladder \n72\n and the additional inflatable bladder \n130\n may contact and seal against one another (e.g., between adjacent inserts \n64\n) at least while the annular BOP \n42\n is in the closed position \n54\n, thereby blocking the fluid in the central bore \n44\n from leaking around the packer assembly \n60\n.', 'It should be appreciated that the multiple inserts \n64\n of \nFIGS.', '7 and 8\n may be similar to any of the inserts of \nFIGS.', '2-6\n.', 'For example, the multiple inserts \n64\n may be configured to move radially-inwardly without rotation about the vertical axis \n30\n in the circumferential direction \n34\n or the multiple inserts \n64\n may be iris-style inserts that rotate radially-inwardly as the multiple inserts \n64\n move into the central bore \n44\n of the annular BOP \n42\n.', 'The embodiments illustrated and described herein may have various other features.', 'For example, instead of the inflatable bladder \n72\n being annular as shown in \nFIGS.', '2-8\n, multiple inflatable bladders \n72\n may be positioned at discrete circumferential locations.', 'An example of this configuration is shown in \nFIG.', '9\n, in which the multiple inflatable bladders \n72\n are positioned to circumferentially surround the packer assembly \n60\n.', 'In operation, due to inflation of the multiple inflatable bladders \n72\n, the packer assembly \n60\n may be driven radially-inwardly to seal against the conduit \n24\n within the central bore \n44\n of the annular BOP \n42\n.', 'While four inflatable bladders \n72\n are shown in \nFIG.', '9\n, the annular BOP \n42\n may include any number of inflatable bladders \n72\n (e.g., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more).', 'Furthermore, while \nFIG.', '9\n illustrates the multiple inserts \n64\n that rotate radially-inwardly, additional components may be included to effectuate the seal against the conduit \n24\n.', 'The multiple inflatable bladders \n72\n may be used in any of the configurations shown in \nFIGS.', '2-8\n, and the annular BOP \n42\n of may also include multiple additional inflatable bladders \n130\n (\nFIG. 8\n).', 'In some embodiments, the inflatable bladder system \n70\n may be configured to effectuate a lock (e.g., hydraulic or pneumatic lock).', 'For example, in \nFIGS. 2-7\n, once the inflatable bladder \n72\n is inflated to the inflated state \n86\n, the valve \n76\n may be adjusted to a closed position to block the flow of the fluid out of the inflatable bladder \n72\n.', 'In this way, the annular BOP \n42\n may be locked in its closed position \n54\n.', 'Furthermore, once the inflatable bladder \n72\n is inflated and filled with the fluid, the fluid may be drained (e.g., via the inflation conduit \n74\n) to return the annular BOP \n42\n to the open position \n50\n.', 'It should be appreciated that any suitable fluid may be used to inflate the inflatable bladder \n72\n.', 'For example, any suitable liquid or gas may be used to inflate the inflatable bladder \n72\n.', 'In some embodiments, a non-Newtonian fluid (e.g., viscosity varies with stress) may be used to inflate the inflatable bladder \n72\n, which may improve the seal and/or the lock.', 'The fluid within the inflatable bladder \n72\n may also have sufficient pressure (e.g., greater than wellbore pressure) to effectuate the seal and/or the lock against wellbore pressure.', 'Furthermore, while the embodiments illustrated in \nFIGS.', '2-8\n illustrate the conduit \n24\n, it should be appreciated that the annular BOP \n42\n may be configured to seal the central bore \n44\n in the absence of the conduit \n24\n (e.g., the packer assembly \n60\n of \nFIGS.', '2-6\n may seal the central bore \n44\n and/or the inflatable bladder \n72\n of \nFIGS.', '7 and 8\n may seal the central bore \n44\n).', 'It is envisioned that the inflatable bladder \n72\n and/or the other components of the inflatable bladder system \n70\n may be adapted for use in any of a variety of annular BOPs \n42\n having any of a variety of structural features.', 'Accordingly, it should be understood that the annular BOP \n42\n of \nFIGS.', '2-9\n are merely exemplary and are not intended to be limiting.', 'For example, the housing \n56\n, the packer \n62\n, and/or the multiple inserts \n64\n may have various other shapes and configurations.', 'Furthermore, it should be understood that any of the various components, features, or characteristics illustrated or described above with respect to \nFIGS.', '1-9\n may be combined.', 'For example, a push plate (e.g., the push plate \n102\n of \nFIG.', '4\n) may be positioned between the packer assembly \n60\n and the inflatable bladder \n72\n in any of the embodiments, or the push plate \n102\n of \nFIG.', '4\n may be omitted.', 'As another example, multiple inflatable bladders \n72\n may be used instead of the single inflatable bladder \n72\n shown in \nFIGS.', '2-8\n.', 'The disclosed embodiments may enable the annular BOP \n42\n to have a low number of components and/or a compact size of the annular BOP \n42\n (e.g., compared to some existing annular BOPs), among other advantages.', 'While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.', 'Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.', 'The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical.', 'Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function] . . . ”', 'or “step for [perform]ing [a function] . . .', '”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f).', 'However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).'] | ['1.', 'An inflatable packer system for an annular blowout preventer (BOP), comprising:\na first inflatable bladder configured to be positioned within a housing of the annular BOP and to inflate upon receipt of a fluid within the first inflatable bladder;\na plurality of inserts configured to support the first inflatable bladder, the plurality of inserts disposed circumferentially about the first inflatable bladder; and\na second inflatable bladder disposed circumferentially about the plurality of inserts and configured to inflate upon receipt of the fluid within the second inflatable bladder.', '2.', 'The inflatable packer system of claim 1, wherein the first inflatable bladder is an annular structure configured to circumferentially surround a bore of the annular BOP.\n\n\n\n\n\n\n3.', 'The inflatable packer system of claim 1, wherein the first inflatable bladder is configured to contact and to seal against a conduit extending through a bore of the annular BOP.', '4.', 'The inflatable packer system of claim 1, further comprising a fluid conduit that is configured to deliver the fluid from a fluid source to the first inflatable bladder.', '5.', 'The inflatable packer system of claim 1, further comprising a fluid source, a first valve, and an electronic controller, wherein the electronic controller is configured to instruct actuation of the first valve to enable the fluid from the fluid source to flow into the first inflatable bladder upon receipt of a signal that indicates an increase in a wellbore pressure.', '6.', 'The inflatable packer system of claim 5, further comprising a second valve, wherein the electronic controller is further configured to instruct actuation of the second valve to enable the fluid from the fluid source to flow into the second inflatable bladder and inflate the second inflatable bladder prior to the first inflatable bladder inflating sufficiently to seal a bore of the annular BOP.\n\n\n\n\n\n\n7.', 'An annular blowout preventer (BOP), comprising:\na housing;\na first inflatable bladder positioned within the housing and configured to adjust from a deflated state to an inflated state;\na plurality of inserts disposed within the housing and configured to support the first inflatable bladder, the plurality of inserts disposed circumferentially about the first inflatable bladder; and\na second inflatable bladder disposed within the housing and circumferentially about the plurality of inserts and configured to adjust from a deflated state to an inflated state.', '8.', 'The annular BOP of claim 7, wherein the first inflatable bladder is configured to contact and to seal against a conduit extending through a bore of the annular BOP while the first inflatable bladder is in the inflated state.', '9.', 'The annular BOP of claim 7, comprising a first fluid conduit that is configured to deliver a fluid from a fluid source to the first inflatable bladder.', '10.', 'The annular BOP of claim 7, further comprising a fluid source, a first valve, and an electronic controller, wherein the electronic controller is configured to instruct actuation of the first valve to enable the fluid from a fluid source to flow into the first inflatable bladder upon receipt of a signal that indicates an increase in a wellbore pressure.\n\n\n\n\n\n\n11.', 'The annular BOP of claim 10, further comprising a second valve, wherein the electronic controller is further configured to instruct actuation of the second valve to enable the fluid from the fluid source to flow into the second inflatable bladder and inflate the second inflatable bladder prior to the first inflatable bladder inflating sufficiently to seal a bore of the annular BOP.\n\n\n\n\n\n\n12.', 'A method of operating an annular blowout preventer (BOP), comprising:\nproviding a fluid to a second inflatable bladder to inflate the second inflatable bladder, wherein the second inflatable bladder is disposed within a housing of the annular BOP and circumferentially about a plurality of inserts disposed within the housing;\ndriving, via the inflated second inflatable bladder, the plurality of inserts radially inwardly, wherein the plurality of inserts are disposed circumferentially about a first inflatable bladder disposed within the housing; and\nproviding the fluid to the first inflatable bladder to inflate the first inflatable bladder, thereby sealing a bore of the annular BOP.', '13.', 'The method of claim 12, wherein the second inflatable bladder is inflated prior to the first inflatable bladder inflating sufficiently to seal a bore of the annular BOP.'] | ['FIG.', '1 is a block diagram of a mineral extraction system in accordance with an embodiment of the present disclosure;; FIG.', '2 is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes an inflatable bladder, a packer, and multiple inserts;; FIG.', '3 is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes an inflatable bladder, a packer, and multiple iris-style inserts;; FIG.', '4 is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes an inflatable bladder, a donut, a packer, and multiple iris-style inserts;; FIG.', '5 is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes an inflatable bladder positioned vertically below a packer and multiple inserts;; FIG.', '6 is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes an inflatable bladder and a piston;; FIG. 7 is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes an inflatable bladder configured to contact and seal against a conduit within a bore of the annular BOP;; FIG. 8 is a cross-sectional side view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes an inflatable bladder, an additional inflatable bladder, and multiple inserts; and; FIG.', '9 is a cross-sectional top view of an embodiment of an annular BOP that may be used in the system of FIG.', '1, wherein the annular BOP includes multiple inflatable bladders positioned circumferentially about a packer assembly.; FIG.', '2 is a cross-sectional side view of the annular BOP 42 that may be used in the system 10 of FIG.', '1.', 'To facilitate discussion, the annular BOP 42 is shown in an open position 50 on one side of a central axis 52 of the annular BOP 42, and the annular BOP 42 is shown in a closed position 54 on the other side of the central axis 52 of the annular BOP 42.', 'In the open position 50, the annular BOP 42 may enable fluid flow through the central bore 44 of the annular BOP 42.', 'In the closed position 54, the annular BOP 42 may block fluid flow through the central bore 44 of the annular BOP 42.; FIG.', '3 is a cross-sectional side view of an embodiment of the annular BOP 42 that may be used in the system 10 of FIG.', '1, wherein the multiple inserts 64 are iris-style inserts.', 'The annular BOP 42 of FIG. 3 may operate similarly to the annular BOP 42 of FIG.', '2, except that the inserts 64 may be configured and arranged to carry out an iris-style closing (e.g., radially-inward rotation) similar to that of an iris shutter of a camera that acts to block extrusion of the flexible material of the packer 62.; FIGS.', '2-6 illustrate various embodiments in which the inflatable bladder 72 is configured to drive the packer assembly 60 to contact and to seal against the conduit 24 to adjust the annular BOP 42 to the closed position 54.', 'However, it should be appreciated that the inflatable bladder 72 may instead be configured to contact and to seal against the conduit 24 in the central bore 44 of the annular BOP 42.', 'For example, FIG. 7 is a cross-sectional side view of an embodiment of the annular BOP 42 that may be used in the system 10 of FIG.', '1, wherein the annular BOP 42 includes the inflatable bladder 72 that is configured to contact and to seal against the conduit 24 within the central bore 44 of the annular BOP 42.'] |
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US11125070 | Real time drilling monitoring | May 4, 2016 | Yuelin Shen, Wei Chen, Gang Xu, Guishui Zheng, Rongbing Chen, Riadh Boualleg, My Lien Ta, Gregg Alexander, Sujian Huang | Schlumberger Technology Corporation | International Search Report and Written Opinion issued in International Patent application PCT/CN2015/078613, dated Feb. 2, 2012. 11 pages.; International Search Report and Written Opinion issued in International Patent application PCT/US2016/030623, dated Aug. 3, 2016. 13 pages. | 5159577; October 27, 1992; Twist; 8170800; May 1, 2012; Aamodt; 8830232; September 9, 2014; Rothnemer; 20020120401; August 29, 2002; Macdonald; 20040154831; August 12, 2004; Seydoux et al.; 20080179094; July 31, 2008; Repin et al.; 20090152005; June 18, 2009; Chapman et al.; 20110186353; August 4, 2011; Turner et al.; 20140182934; July 3, 2014; Samuel; 20140262246; September 18, 2014; Li et al.; 20150083492; March 26, 2015; Wassell | 203134246; August 2013; CN; WO2007147135; December 2007; WO; WO2014158706; October 2014; WO | ['A method, system, and computer readable medium for managing drilling operations include calibrating a drilling model using collected drilling data, and executing, during a drilling operation, a simulation on the drilling model to generate a predicted measurement value for a drilling property.', 'During the drilling operation and from a drillstring, an actual measurement value for the drilling property is obtained.', 'Based on the actual measurement value matching the predicted measurement value, the simulation is extended to generate a simulated state of the drilling operation during the drilling operation, and a condition of the drilling operation is detected.', 'A notification may be presented based on the condition during the drilling operation.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThis application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Patent Application Ser.', 'No. 62/159,605, filed on May 11, 2015, and entitled, “REAL TIME DRILLING MONITORING,” which is incorporated herein by reference in its entirety.', 'This application further claims priority under 35 U.S.C. § 120 to PCT Patent Application Serial Number PCT/CN2015/078613, filed on May 8, 2015 and entitled, “REAL TIME DRILLING MONITORING,” which is incorporated herein by reference in its entirety.', 'BACKGROUND\n \nComputer simulation estimates the operations of a real-world system.', 'Generally, computer simulation allows a user to test various control parameters to select an optimal control parameter.', 'For example, in field management, computer simulation may be used to plan the drilling and production of valuable downhole assets.', 'In particular, drilling simulation is used extensively to design drilling tools and plan for drilling operations.', 'SUMMARY\n \nIn general, in one aspect, embodiments relate to a method, system, and non-transitory computer readable medium for managing drilling operations.', 'Managing drilling operations includes calibrating a drilling model using collected drilling data, and executing, during a drilling operation, a simulation on the drilling model to generate a predicted measurement value for a drilling property.', 'During the drilling operation and from a drillstring, an actual measurement value for the drilling property is obtained.', 'Based on the actual measurement value matching the predicted measurement value, the simulation is extended to generate a simulated state of the drilling operation during the drilling operation and a condition of the drillstring detected.', 'A notification may be presented based on the condition during the drilling operation.', 'Other aspects of the technology will be apparent from the following description and the appended claims.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nFIGS.', '1, 2, 3.1, 3.2, 4.1, and 4.2\n show schematic diagrams in accordance with one or more embodiments of the technology.', 'FIGS.', '5, 6, 7, 8, 9, 10, 11, 12, 13, 14.1, 15, and 16.1\n show flowcharts in accordance with one or more embodiments of the technology.', 'FIGS.', '14.2 and 16.2\n show example output in accordance with one or more embodiments of the technology.', 'DETAILED DESCRIPTION\n \nSpecific embodiments of the technology will now be described in detail with reference to the accompanying figures.', 'Like elements in the various figures are denoted by like reference numerals for consistency.', 'In the following detailed description of embodiments of the technology, numerous specific details are set forth in order to provide a more thorough understanding of the technology.', 'However, it will be apparent to one of ordinary skill in the art that the technology may be practiced without these specific details.', 'In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.', 'Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application).', 'The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being a single element unless expressly disclosed, such as by the use of the terms “before”, “after”, “single”, and other such terminology.', 'Rather, the use of ordinal numbers is to distinguish between the elements.', 'By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.', 'In general, embodiments of the technology are directed to real time management of drilling operations.', 'In particular, a drilling model is calibrated.', 'Simulations are continually performed on using the calibrated drilling model.', 'A predicted measurement value from the simulations is compared against an actual measurement value acquired from the field.', 'If the actual measurement value matches the simulated measurement value, then the simulations may be used to determine a simulated state of the drilling operation.', 'Based on the simulated state, a condition of the drilling operation is determined and a notification of the condition is presented.', 'One or more embodiments are directed to a drilling simulation-based real time system for drilling operation monitoring, diagnostics and optimization.', 'Real time may refer to presenting results within a minute, within an hour, or within a day to when the drilling data is received by the simulation server depending on the type of analysis being performed.', 'Real time may refer to presenting results within a minute, within an hour, or within a day to when the drilling data is acquired by sensors in the drilling tool.', 'In other words, one or more embodiments may perform diagnostics and optimization for drilling.', 'For example, one or more embodiments may perform real time vibration mitigation, real time rate of penetration (ROP) optimization, real time trajectory monitoring and directional drilling parameter recommendation, real time wellbore quality optimization, real time logging while drilling/measurement while drilling (LWD/MWD) measurement quality assurance, real time fatigue life monitoring, real time bit-reamer load balancing, real time bit and reamer wear monitoring, and real time buckling and weight on bit (WOB) transfer monitoring.', 'Trajectory monitoring may include ensuring that trajectory is within a threshold of the desired planned direction.', 'Wellbore quality is the degree of smoothness and straightness of the borehole.', 'Fatigue life managing is managing the amplitude of alternative stress on equipment, such as bending stress during the rotating of the drillstring while drilling the borehole.', 'One or more embodiments may detect and manage the remaining amount of fatigue life of each part of equipment.', 'Bit reamer load balancing is managing an amount of cutting force taken by the reamer as compared to the amount taken by the bit.', 'Bit and reamer wear monitoring may include detecting and managing when the cutters go blunt.', 'Buckling and WOB transfer monitoring may include managing actual weight transferred to bit, and preventing or managing deformation of the drill pipes.\n \nFIG.', '1\n depicts a schematic view, partially in cross section, of a field (\n100\n) in which one or more embodiments may be implemented.', 'In one or more embodiments, the field may be an oilfield.', 'In other embodiments, the field may be a different type of field.', 'In one or more embodiments, one or more of the modules and elements shown in \nFIG.', '1\n may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments should not be considered limited to the specific arrangements of modules shown in \nFIG.', '1\n.', 'A subterranean formation (\n104\n) is in an underground geological region.', 'An underground geological region is a geographic area that exists below land or ocean.', 'In one or more embodiments, the underground geological region includes the subsurface formation in which a borehole is or may be drilled and any subsurface region that may affect the drilling of the borehole, such as because of stresses and strains existing in the subsurface region.', 'In other words, the underground geological region may not just include the area immediately surrounding a borehole or where a borehole may be drilled, but also any area that affects or may affect the borehole or where the borehole may be drilled.', 'As used herein, subterranean formation, formation, and subsurface formations may be used interchangeably.', 'Further, wellbore, borehole, and hole may be used interchangeably.', 'As shown in \nFIG.', '1\n, the subterranean formation (\n104\n) may include several geological structures (\n106\n-\n1\n through \n106\n-\n4\n) of which \nFIG.', '1\n provides an example.', 'As shown, the subsurface formations may include a sandstone layer (\n106\n-\n1\n), a limestone layer (\n106\n-\n2\n), a shale layer (\n106\n-\n3\n), and a sand layer (\n106\n-\n4\n).', 'A fault line (\n107\n) may extend through the formation.', 'In one or more embodiments, various survey tools and/or data acquisition tools are adapted to measure the formation and detect the characteristics of the geological structures of the formation.', 'Further, as shown in \nFIG.', '1\n, the wellsite system (\n110\n) is associated with a rig (\n101\n), a wellbore (\n103\n), and other field equipment and is configured to perform wellbore operations, such as logging, drilling, fracturing, production, or other applicable operations.', 'The wellbore (\n103\n) may also be referred to as a borehole.', 'In one or more embodiments, the surface unit (\n112\n) is operatively coupled to a field management tool (\n116\n) and/or the wellsite system (\n110\n).', 'In particular, the surface unit (\n112\n) is configured to communicate with the field management tool (\n116\n) and/or the wellsite system (\n110\n) to send commands to the field management tool (\n116\n) and/or the wellsite system (\n110\n) and to receive data therefrom.', 'For example, the wellsite system (\n110\n) may be adapted for measuring downhole properties using LWD tools to obtain well logs and for obtaining core samples.', 'In one or more embodiments, the surface unit (\n112\n) may be located at the wellsite system (\n110\n) and/or remote locations.', 'The surface unit (\n112\n) may be provided with computer facilities for receiving, storing, processing, and/or analyzing data from the field management tool (\n116\n), the wellsite system (\n110\n), or other part of the field (\n100\n).', 'The surface unit (\n112\n) may also be provided with functionally for actuating mechanisms at the field (\n100\n).', 'The surface unit (\n112\n) may then send command signals to the field (\n100\n) in response to data received, for example, to control and/or optimize various field operations described above.', 'During the various oilfield operations at the field, data is collected for analysis and/or monitoring of the oilfield operations.', 'Such data may include, for example, subterranean formation, equipment, historical and/or other data.', 'Static data relates to, for example, formation structure and geological stratigraphy that define the geological structures of the subterranean formation.', 'Static data may also include data about the wellbore, such as well diameters, and depths.', 'Dynamic data relates to, for example, fluids flowing through the geologic structures of the subterranean formation over time.', 'The dynamic data may include, for example, pressures, fluid compositions (e.g. gas oil ratio, water cut, and/or other fluid compositional information), and states of various equipment, and other information.', 'The static and dynamic data collected from the wellbore and the oilfield may be used to create and update a three-dimensional model of the subsurface formations.', 'Additionally, static and dynamic data from other wellbores or oilfields may be used to create and update the three-dimensional model.', 'Hardware sensors, core sampling, and well logging techniques may be used to collect the data.', 'Other static measurements may be gathered using downhole measurements, such as core sampling and well logging techniques.', 'Well logging involves deployment of a downhole tool into the wellbore to collect various downhole measurements, such as density, resistivity, etc., at various depths.', 'Such well logging may be performed using, for example, a drilling tool and/or a wireline tool, or sensors located on downhole production equipment.', 'Once the well is formed and completed.', 'fluid flows to the surface using production tubing and other completion equipment.', 'As fluid passes to the surface, various dynamic measurements, such as fluid flow rates, pressure, and composition may be monitored.', 'These parameters may be used to determine various characteristics of the subterranean formation.', 'In one or more embodiments, the data is received by the surface unit (\n112\n), which is communicatively coupled to the field management tool (\n116\n).', 'Generally, the field management tool (\n116\n) is configured to analyze, model, control, optimize, or perform other management tasks of the aforementioned field operations based on the data provided from the surface unit (\n112\n).', 'Although the surface unit (\n112\n) is shown as separate from the field management tool (\n116\n) in \nFIG.', '1\n, in other examples, the surface unit (\n112\n) and the field management tool (\n116\n) may also be combined.', 'During a drilling operation, drilling tools are deployed from the oil and gas rigs.', 'The drilling tools advanced into the earth along a path to locate reservoirs containing the valuable downhole assets.', 'In one or more embodiments, the optimal path for the drilling is identified in a well plan that uses three-dimensional modeling.', 'Fluid, such as drilling mud or other drilling fluids, is pumped down the wellbore (or borehole) through the drilling tool and out the drilling bit.', 'The drilling fluid flows through the annulus between the drilling tool and the wellbore and out the surface, carrying away earth loosened during drilling.', 'The drilling fluids return the earth to the surface, and seal the wall of the wellbore to prevent fluid in the surrounding earth from entering the wellbore and causing a “blow out.”', 'During the drilling operation, the drilling tool may perform downhole measurements to investigate downhole conditions.', 'The drilling tool may be used to take core samples of subsurface formations.', 'In some cases, the drilling tool is removed and a wireline tool is deployed into the wellbore to perform additional downhole testing, such as logging or sampling.', 'Steel casing may be run into the well to a desired depth and cemented into place along the wellbore wall.', 'Drilling may be continued until the desired total depth is reached.', 'After the drilling operation is complete, the well may then be prepared for production.', 'Wellbore completion equipment is deployed into the wellbore to complete the well in preparation for the production of fluid through the wellbore.', 'Fluid is then allowed to flow from downhole reservoirs, into the wellbore and to the surface.', 'Production facilities are positioned at surface locations to collect the hydrocarbons from the wellsite(s).', 'Fluid drawn from the subterranean reservoir(s) passes to the production facilities via transport mechanisms, such as tubing.', 'Various equipment may be positioned about the oilfield to monitor oilfield parameters, to manipulate the oilfield operations and/or to separate and direct fluids from the wells.', 'Surface equipment and completion equipment may also be used to inject fluids into reservoir either for storage or at strategic points to enhance production of the reservoir.', 'Sensors (S) are located about the wellsite to collect data, may be in real time, concerning the operation of the wellsite, as well as conditions at the wellsite.', 'The sensors may also have features or capabilities, of monitors, such as cameras (not shown), to provide pictures of the operation.', 'Surface sensors or gauges (S) may be deployed about the surface systems to provide information about the surface unit, such as standpipe pressure, hookload, depth, surface torque, rotary rotations per minute (RPM), among others.', 'Downhole sensors or gauges (S) are disposed about the drilling tool and/or wellbore to provide information about downhole conditions, such as wellbore pressure, WOB, torque on bit, direction, inclination, collar RPM, tool temperature, annular temperature, and tool face (TF), among others.', 'For example, the sensors may include one or more of a camera, a pressure sensor.', 'a temperature sensor, a flow rate sensor, a vibration sensor, a current sensor, a voltage sensor, a resistance sensor, a gesture detection sensor or device, a voice actuated or recognition device or sensor, or other suitable sensors.', 'Example downhole drillstring sensors include functionality to obtain drilling dynamics measurements, such as tri-axis accelerations, collar RPM and stick-slip, bending moment, downhole torque, and axial weight.', 'Sensors that perform MWD and LWD may include functionality to perform caliper logging, acquire annulus pressure and equivalent circulating density (ECD) measurements, perform a well survey, acquire shock and vibration measurements, and obtain formation information at the drilling depths and ahead of a bit.', 'The information collected by the sensors and cameras is conveyed to the various parts of the drilling system and/or the surface control unit.', 'At the rig floor or the surface, the sensors may include functionality to obtain input drilling parameters (e.g., surface RPM (SRPM) (actual table revolution), rotating/sliding, rotary steerable system (RSS) steering ratio and desired tool face angle (TFA), WOB and hookload, and flow rate and mud weight (MW)), surface drilling measurements (e.g., surface torque, stand pipe pressure, top drive block location/feeding speed (ROP)), and mud logging (e.g., cuttings, and formation type and unconfined compression strength (UCS)).', 'FIG.', '2\n shows a schematic diagram depicting a drilling operation of a directional well in multiple sections.', 'The drilling operation depicted in \nFIG.', '2\n includes a wellsite drilling system (\n200\n) and a field management tool (\n220\n) for accessing fluid in the target reservoir through a borehole (\n250\n) of a directional well (\n217\n).', 'The wellsite drilling system (\n200\n) includes various components (e.g., drillstring (\n212\n), annulus (\n212\n), bottom hole assembly (BHA) (\n214\n), Kelly (\n215\n), mud pit (\n216\n), etc.) as generally described with respect to the wellsite drilling systems (\n100\n) (e.g., drillstring (\n115\n), annulus (\n126\n), bottom hole assembly (BHA) (\n120\n), Kelly (\n116\n), mud pit (\n122\n), etc.) of \nFIG.', '1\n above.', 'As shown in \nFIG.', '2\n.', 'the target reservoir may be located away from (as opposed to directly under) the surface location of the directional well (\n217\n).', 'Accordingly, special tools or techniques may be used to ensure that the path along the bore hole (\n250\n) reaches the particular location of the target reservoir (\n200\n).', 'For example, the BHA (\n214\n) may include sensors (\n208\n), a rotary steerable system (\n209\n), and the bit (\n210\n) to direct the drilling toward the target guided by a pre-determined survey program for measuring location details in the well.', 'Furthermore, the subterranean formation through which the directional well (\n217\n) is drilled may include multiple layers (not shown) with varying compositions, geophysical characteristics, and geological conditions.', 'Both the drilling planning during the well design stage and the actual drilling according to the drilling plan in the drilling stage may be performed in multiple sections (e.g., sections (\n201\n), (\n202\n), (\n202\n), (\n204\n)) corresponding to the multiple layers in the subterranean formation.', 'For example, certain sections (e.g., sections (\n201\n) and (\n202\n)) may use cement (\n207\n) reinforced casing (\n206\n) due to the particular formation compositions, geophysical characteristics, and geological conditions.', 'Further as shown in \nFIG.', '2\n, surface unit (\n211\n) (as generally described with respect to the surface unit (\n112\n) of \nFIG.', '1\n) may be operatively linked to the wellsite drilling system (\n200\n) and the field management tool (\n220\n) via communication links (\n218\n).', 'The surface unit (\n211\n) may be configured with functionalities to control and monitor the drilling activities by sections in real time via the communication links (\n218\n).', 'The field management tool (\n220\n) may be configured with functionalities to store oilfield data (e.g., historical data, actual data, surface data, subsurface data, equipment data, geological data, geophysical data, target data, anti-target data, etc.) and determine relevant factors for configuring a drilling model and generating a drilling plan.', 'The oilfield data, the drilling model, and the drilling plan may be transmitted via the communication link (\n218\n) according to a drilling operation workflow.', 'The communication link (\n218\n) may comprise the communication subassembly (\n252\n) as described with respect to \nFIG.', '1\n above.', 'To facilitate the processing and analysis of data, simulators may be used to process the data.', 'Specific simulators are often used in connection with specific oilfield operations, such as reservoir or wellbore production.', 'Data fed into the simulator(s) may be historical data, real time data or combinations thereof.', 'Simulation through one or more of the simulators may be repeated or adjusted based on the data received.', 'The oilfield operation is provided with wellsite and non-wellsite simulators.', 'The wellsite simulators may include a reservoir simulator, a wellbore simulator, and a surface network simulator.', 'The reservoir simulator solves for hydrocarbon flowrate through the reservoir and into the wellbores.', 'The wellbore simulator and surface network simulator solve for hydrocarbon flowrate through the wellbore and the surface gathering network of pipelines.', 'As shown, some of the simulators may be separate or combined, depending on the available systems.', 'The non-wellsite simulators may include process and economics simulators.', 'The processing unit has a process simulator.', 'The process simulator models the processing plant (e.g., the process facility) where the hydrocarbon is separated into its constituent components (e.g., methane, ethane, propane, etc.) and prepared for sales.', 'The oilfield is provided with an economics simulator.', 'The economics simulator models the costs of part of or the entire oilfield.', 'Various combinations of these and other oilfield simulators may be provided.', 'When gathering the field data, sensors might not be located along the entire length of the drillstring, but rather a few positions may have measurement values.', 'In such a scenario, when the field management tool receives the gathered field data, the field management tool may provide an estimation as to the remaining positions.', 'The field management tool may include functionality to generate a dynamics simulation model, calibrate and re-calibrate the model using real time data, execute the calibrated model, monitor variables through simulation, identify and warn of dangerous conditions, and explore parameters to mitigate adverse drilling dynamics.', 'The field management tool may provide simulation results to the surface unit, which displays the simulation results and event warnings.', 'Variables monitoring and diagnostics may include monitoring drilling efficiency (e.g., cutting structure compatibility (bit reamer balance) and bit wear), drilling stability (e.g., vibration levels along BHA, damaging vibration mode (whirling, stick-slip), neutral point), robustness (e.g., cumulative fatigue of drillstring, drillstring buckling, and overloading detection (predicted stress versus tool strength data)), measurement quality (e.g., survey rectification accounting for BHA sag, collar lateral displacement at MWD sensors), borehole quality (e.g., hole tortuosity/hole microDLS/hole spiraling, and hole size variation), directional tendency (e.g., steering parameter sensitivity: WOB, Steering Ratio, Drilling Cycle, flow rate, sliding/rotating distance) and other aspects of drilling (e.g., motor TF rectification accounting for drillstring twist, stuck point depth estimation, and jarring impact).', 'The system may perform warning and advising to the drilling process including, pulling out of hole (POOH) based on high cumulative fatigue and severe cutting structure wear.', 'The system may recommend to pull off the bottom based on damaging whirling motion detected, excessive drillstring buckling detected, etc.', 'The system may recommend a drilling parameter change based on high lateral/axial/torsional vibrations detected, poor borehole quality, challenging formation drilling (formation information based on LWD, mud logging, and the look-ahead detection of LWD), poor directional control, poor weight distribution between bit and reamer, an undesired neutral point depth, and mild drillstring buckling.\n \nFIG.', '3.1\n shows an example of a communication structure in accordance with one or more embodiments of the technology.', 'As shown in \nFIG.', '3.1\n, a wellsite drilling system (\n310\n) is connected to a surface unit (\n304\n) and simulation server (\n308\n).', 'The wellsite drilling system (\n310\n) and surface unit (\n304\n) may be the same or similar to the wellsite drilling system and surface unit discussed above with reference to \nFIG.', '2\n.', 'As shown in \nFIG.', '3.1\n, downhole sensors (\n300\n) may transmit downhole data (\n302\n) via the communication link to a surface unit (\n304\n).', 'Similarly, rig surface data (\n306\n) may also be transmitted to surface unit (\n304\n).', 'The surface unit (\n304\n) may provide the field data (\n312\n) to a simulation server (\n308\n).', 'The field data (\n312\n) includes rig surface data (\n306\n) and downhole data (\n302\n).', 'The rig surface data (\n306\n) is any data that is collected from the rig surface (\n314\n).', 'The downhole data (\n302\n) is any data collected downhole.', 'Example rig surface data (\n306\n) and downhole data (\n302\n) may include any of the data described above with reference to \nFIGS.', '1 and 2\n.', 'Continuing with \nFIG.', '3.1\n, the simulation server (\n308\n) may execute the field management tool, discussed above.', 'For example, the simulation server (\n308\n) may correspond to a computing system shown in \nFIGS.', '4.1 and 4.2\n and described below.', 'As shown in \nFIG.', '3.1\n, real time information in the form of the field data (\n312\n) is obtained from the wellsite as part of data acquisition and monitoring.', 'Further, wellbore and reservoir information may be gathered.', 'The surface unit (\n304\n) may compile the rig surface data (\n306\n) and downhole data (\n302\n) and send the field data (\n312\n) to the simulation server (\n308\n).', 'For example, the surface unit (\n304\n) may interface with the device controller of each item of equipment to gather and compile the data from the item of the equipment.', 'As shown in \nFIG.', '3.1\n, real time information is obtained from the wellsite as part of data acquisition and monitoring.', 'Further, wellbore and reservoir information may be gathered.', 'The surface unit may compile the gathered information and send the information to the simulation server.', 'For example, the surface unit may interface with the controller for each item of equipment to gather and compile the information.', 'When gathering the information, sensors might not be located along the entire length of the drillstring, but rather a few positions may have measurement values.', 'In such a scenario, when the simulator receives the gathered information, the simulator may provide an estimation as to the remaining positions.', 'The simulator may include functionality to generate a dynamics simulation model, calibrate and re-calibrate the model using real time data, execute the calibrated model, monitor variables through simulation, identify and warn of dangerous conditions, and explore parameters to mitigate adverse drilling dynamics.', 'The simulator may provide simulation results to the surface unit, which displays the simulation results and event warnings.\n \nFIG.', '3.2\n shows an example schematic diagram of a system showing flow in accordance with one or more embodiments of the technology.', 'As shown in \nFIG.', '3.2\n, at the rig site (\n350\n) of the drilling rig, drilling data may be collected (\n352\n).', 'The drilling data (\n352\n) may be transferred (\n354\n) to remote server (\n356\n), such as the field management tool.', 'The remote server may (\n356\n) perform real time drilling model calibration and simulation (\n358\n).', 'Results of the simulation may be transferred (\n360\n) to the rig site (\n350\n) for display (\n362\n).', 'In one or more embodiments, the field management tool discussed above may be implemented as or executed on a computing system.', 'The computing system may be a combination of mobile, desktop, server, embedded, or other types of hardware.', 'Embodiments may be implemented on a computing system.', 'Any combination of mobile, desktop, server, router, switch, embedded device, or other types of hardware may be used.', 'For example, as shown in \nFIG.', '4.1\n, the computing system (\n400\n) may include one or more computer processors (\n402\n), non-persistent storage (\n404\n) (e.g., volatile memory, such as random access memory (RAM), cache memory), persistent storage (\n406\n) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory, etc.), a communication interface (\n412\n) (e.g., Bluetooth interface, infrared interface, network interface, optical interface, etc.), and numerous other elements and functionalities.', 'The computer processor(s) (\n402\n) may be an integrated circuit for processing instructions.', 'For example, the computer processor(s) may be one or more cores or micro-cores of a processor.', 'The computing system (\n400\n) may also include one or more input devices (\n410\n), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.', 'The communication interface (\n412\n) may include an integrated circuit for connecting the computing system (\n400\n) to a network (not shown) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) and/or to another device, such as another computing device.', 'Further, the computing system (\n400\n) may include one or more output devices (\n408\n), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device.', 'One or more of the output devices may be the same or different from the input device(s).', 'The input and output device(s) may be locally or remotely connected to the computer processor(s) (\n402\n), non-persistent storage (\n404\n), and persistent storage (\n406\n).', 'Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.', 'Software instructions in the form of computer readable program code to perform embodiments may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium.', 'Specifically, the software instructions may correspond to computer readable program code that, when executed by a processor(s), is configured to perform one or more embodiments.', 'The computing system (\n400\n) in \nFIG.', '4.1\n may be connected to or be a part of a network.', 'For example, as shown in \nFIG.', '4.2\n, the network (\n420\n) may include multiple nodes (e.g., node X (\n422\n), node Y (\n424\n)).', 'Each node may correspond to a computing system, such as the computing system shown in \nFIG.', '4.1\n, or a group of nodes combined may correspond to the computing system shown in \nFIG.', '4.1\n.', 'By way of an example, embodiments may be implemented on a node of a distributed system that is connected to other nodes.', 'By way of another example, embodiments may be implemented on a distributed computing system having multiple nodes, where each portion may be located on a different node within the distributed computing system.', 'Further, one or more elements of the aforementioned computing system (\n400\n) may be located at a remote location and connected to the other elements over a network.', 'Although not shown in \nFIG.', '4.2\n, the node may correspond to a blade in a server chassis that is connected to other nodes via a backplane.', 'By way of another example, the node may correspond to a server in a data center.', 'By way of another example, the node may correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.', 'The nodes (e.g., node X (\n422\n), node Y (\n424\n)) in the network (\n420\n) may be configured to provide services for a client device (\n426\n).', 'For example, the nodes may be part of a cloud computing system.', 'The nodes may include functionality to receive requests from the client device (\n426\n) and transmit responses to the client device (\n426\n).', 'The client device (\n426\n) may be a computing system, such as the computing system shown in \nFIG.', '4.1\n.', 'Further, the client device (\n426\n) may include and/or perform at least a portion of one or more embodiments.', 'The field management tool may further include a data repository.', 'A data repository is any type of storage unit and/or device (e.g., a file system, database, collection of tables, or any other storage mechanism) for storing data.', 'Further, the data repository may include multiple different storage units and/or devices.', 'The multiple different storage units and/or devices may or may not be of the same type or located at the same physical site.', 'FIGS.', '5, 6, 7, 8, 9, 10, 11, 12, 13, 14.1, 15, and 16.1\n show example flowcharts in accordance with one or more embodiments of the technology.', 'While the various blocks in this flowchart are presented and described sequentially, one of ordinary skill will appreciate that some of the blocks may be executed in different orders, may be combined or omitted, and some of the blocks may be executed in parallel.', 'Furthermore, the blocks may be performed actively or passively.', 'For example, some blocks may be performed using polling or be interrupt driven in accordance with one or more embodiments of the technology.', 'By way of an example, determination blocks may not require a processor to process an instruction unless an interrupt is received to signify that condition exists in accordance with one or more embodiments of the technology.', 'As another example, determination blocks may be performed by performing a test, such as checking a data value to test whether the value is consistent with the tested condition in accordance with one or more embodiments of the technology.', 'Further, although the below discussion presents certain blocks as being performed by the rig computing device (or rig PC in \nFIGS.', '6-16\n) and other blocks being performed by the remote server, different allocations of may be used.', 'For example, all blocks may be performed by the remote server and none by the rig computing device, or all blocks performed by the rig computing device and none by the remote server.', 'By way of another example, additional blocks of the figures may be performed by the rig computing device.', 'Other allocations may be used without departing from the scope of the technology.', 'FIG.', '5\n shows an example flowchart in accordance with one or more embodiments.', 'In Block \n501\n, a drilling model is calibrated using collected drilling data in accordance with one or more embodiments.', 'In one or more embodiments, downhole sensors detect various physical properties of the rocks and the state of the drillstring as downhole data and transmit the downhole data to the surface unit.', 'Similarly, the rig surface may also collect and transmit rig surface data to the surface unit.', 'The surface unit may send the rig surface data and the downhole data as field data to a simulation server.', 'The simulation server may use the field data, along with detailed configuration information about the drillstring, and a subsurface model to generate a drilling model.', 'The drilling model describes how the drillstring progresses through the subsurface formations.', 'In Block \n503\n, during a drilling operation, a simulation on the drilling model is executed to generate a predicted measurement value for a drilling property.', 'In other words, the simulation predicts how the drillstring interacts with the rock and progresses through the subsurface formation.', 'The result of the simulation is a predicted measurement value that is for the drillstring when the drillstring is located at the current location of the drillstring or directly ahead of the current location.', 'The measurement value may be for the same property that is being monitored (e.g., stress, buckling, rotations, etc.).', 'In one or more embodiments, the simulation is performed by the simulation server.', 'In Block \n505\n, during the drilling operation and from a drillstring, an actual measurement value is obtained for the drilling property.', 'The actual measurement value is the actual value that is predicted in Block \n503\n.', 'In other words, the actual measurement value is the measurement value that is for the same location as the predicted measurement value.', 'The actual measurement value may be obtained using a similar method discussed above with reference to Block \n501\n, using a look ahead sensor, or another acquisition technique.', 'The predicted measurement value and the actual measurement value may be used to determine the accuracy of the model.', 'In other words, if the predicted measurement value matches the actual measurement value, then the drilling model is deemed accurate.', 'A match may be deemed to exist when the predicted measurement value is an exact match to the actual measurement value, or within an error threshold to the actual measurement value.', 'In Block \n507\n, the simulation is extended during the drilling operation, based on the actual measurement value matching the predicted measurement value, to generate a simulated state of the drilling operation.', 'In other words, the drilling model that is deemed accurate is used for continued simulation of the drilling operations.', 'As the drilling model simulates the progression of the drillstring through the borehole, the state of the drillstring is monitored in the simulations.', 'In Block \n509\n, during the drilling operation, a condition of the drilling operation is detected based on the simulated state.', 'For example, the condition may be a possible failure of the drillstring or a component of the drillstring, that the drillstring or a component of the drillstring is operating sub-optimally or another condition.', 'In one or more embodiments, the condition may be a current condition or a future condition.', 'For example, the future condition may be the predicted condition if drilling is maintained with the current drilling parameters.', 'In Block \n511\n, a notification is presented based on the condition during the drilling operation.', 'In one or more embodiments, the simulation server may send a communication with a notification of the condition directly or indirectly to the drilling engineer.', 'The communication may include a recommendation to change one or more drilling parameters, to pull the drillstring out of the hole, perform another operation, or any combination thereof.', 'In some embodiments, the simulation server may send a notification to the surface unit.', 'The notification may include a command to change the drilling parameters, stop drilling, or perform another operation or combination thereof.', 'The command may be processed with or without human interaction.', 'For example, the surface unit may stop the drillstring from operating.', 'By performing real time simulations of the drillstring, one or more embodiments may detect present and future conditions of the drillstring even when drilling is not being performed according to the drilling plan and/or the subsurface deviates from an expected drilling environment.', 'In other words, when the drilling being performed deviates from the drilling plan created prior to drilling and/or assumptions made during drilling are not accurate, the simulations performed prior to drilling may no longer be applicable.', 'By providing a technique for continually updating the drilling model and executing simulations in real time, one or more embodiments may account for deviations from the drilling plan and changing assumptions.', 'FIGS.', '6-13, 14.1, and 14.2\n show example workflows for performing one or more embodiments described herein.\n \nFIG.', '6\n shows an example flowchart (\n600\n) to calibrate a model in accordance with one or more embodiments of the technology.', 'In Block \n601\n, real time drilling data is collected.', 'Collecting real time drilling data may be performed as discussed above with reference to Block \n501\n of \nFIG.', '5\n.', 'In Block \n603\n, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'The surface unit may package and encrypt the real time drilling data.', 'The real time drilling data may be transmitted via one or more networks to the simulation server.', 'In Block \n605\n, simulation model data is obtained in accordance with one or more embodiments.', 'In other words, the simulation server may use the real time drilling data as well as other information.', 'For example, the simulation server may obtain detailed configuration of the drillstring, a subsurface model, and other data.', 'In Block \n607\n, a simulation model is developed using the simulation model data.', 'Developing the simulation model may be performed as discussed above with reference to Block \n501\n of \nFIG.', '5\n.', 'In Block \n609\n, at the current measurement depth of the drillstring, a simulation rock input per mud logging and a LWD measurement are selected in accordance with one or more embodiments.', 'From the real time drilling data obtained in Block \n601\n for the current position of the drillstring, a simulation rock input and a measurement are selected.', 'In one or more embodiments, the input and measurement are not used to develop the model in Block \n607\n, but rather used to determine the accuracy of the model.', 'In Block \n611\n, a drilling parameter is inputted per the real time surface data in the real time drilling data in accordance with one or more embodiments.', 'In particular, the drilling parameter that is used to perform the current drilling is provided to the simulation model.', 'In Block \n613\n, a simulation is run using the simulation model to obtain a prediction in accordance with one or more embodiments.', 'In other words, the simulation is executed using the drilling parameter.', 'The simulation is executed to predict the current state of the drilling using the current drilling parameters being used in the field.', 'Running the simulation may be performed in a same or similar manner discussed above with reference to Block \n503\n of \nFIG.', '5\n.', 'In Block \n615\n, a determination is made whether the prediction matches the real time field measurement in accordance with one or more embodiments.', 'A match may be deemed to exist when the predicted measurement value is an exact match to the real time field measurement, or within an error threshold to the real time field measurement.', 'In Block \n615\n, the model parameters are adjusted if the prediction does not match the real time field measurement.', 'Adjusting the model parameters may include perturbing one or more model parameters to vary the simulation.', 'The amount of perturbation and the model parameter to adjust may be based, for example, on the degree of disparity between the real time field measurement and the predicted measurement.', 'For example, the amount of perturbing and degree of disparity may be in a direct relationship whereby the greater the disparity, the greater the change of the model parameter(s).', 'The flow may proceed to Block \n613\n to run the simulation.', 'In other words, the model is calibrated based on the real time data.', 'Further, the calibration may continually be performed throughout the drilling to ensure that the simulation model matches the actual drilling By keeping the model updated, one or more embodiments provide a technique whereby the simulations provide a more accurate prediction of the drilling.', 'Returning to Block \n617\n, if the prediction matches the real time field measurement, then the flow proceeds to Block \n619\n.', 'In Block \n619\n, a determination is made whether to continue.', 'For example, the calibration may stop when the user determines to stop calibrating, drilling stops, simulations stop, etc.', 'In such a scenario, the flow may proceed to end.', 'If a determination is made to continue, the flow may proceed to Block \n621\n in accordance with one or more embodiments.', 'In Block \n621\n, simulations with the calibrated model are continued to be executed in accordance with one or more embodiments.', 'In other words, the simulations may be extended to reflect current and/or future drilling states of the drillstring.', 'In some embodiments, different drilling scenarios are provided to the simulation server.', 'For example, the drilling scenarios may be to adjust the drilling parameters in the drilling plan (e.g., test different weights on bit (WOB), change surface rotation speed (RPM), etc.), adjust the subsurface to account for uncertainty, or perform other changes.', 'The different drilling scenarios may be used to predict the drilling operations when changing conditions exist, minimize risk, test changes in the drilling plans to optimize operations, etc.', 'Because the simulation model is continuously calibrated, the result of the simulations may be deemed to be a more accurate predictor of the current and future state of the drillstring when the inputs to the simulation model exist or are performed.', 'In Block \n623\n, a determination is made whether the time has expired for a detailed comparison in accordance with one or more embodiments.', 'If the time expires for a detailed comparison, the flow returns to Block \n609\n.', 'In one or more embodiments, the simulation server performs a detailed comparison at a set interval.', 'The set interval may be defined in terms of time, in terms of displacement of the drillstring, or using another unit of measurement.', 'Thus, the time expired to perform the detailed comparison when the current interval has passed.', 'In Block \n625\n, if the time has not expired for the detailed comparison then a real time field measurement is obtained in accordance with one or more embodiments.', 'The real time drilling measurement may be obtained, directly or indirectly, from a LWD tool, a downhole sensor, the surface unit, or another component.', 'In Block \n627\n, a determination is made whether the prediction from the simulation matches the real time field measurement in accordance with one or more embodiments.', 'Determining whether the prediction matches may be performed as discussed above with reference to Block \n615\n.', 'If the prediction matches, the flow returns to Block \n619\n.', 'In other words, the simulation model may be continually used to predict the current and future states of the drillstring.', 'If the prediction does not match, the flow goes to Block \n609\n to perform recalibration in accordance with one or more embodiments.', 'As described above and as generally shown in \nFIG.', '6\n, the drilling model is calibrated to match actual drilling conditions.', 'In one or more embodiments of the technology, using a calibrated model, during a drilling operation, a simulation on the drilling model is performed to generate a predicted measurement value for a drilling property.', 'An actual measurement value is obtained from the sensors for the drilling property.', 'If the actual measurement value matches the predicted measurement value from simulations, the simulation is extended during the drilling operation to generate a simulated state of the drilling operation.', 'A condition of the drilling operation may be detected based on the simulated state and presented as discussed above.', 'Thus, simulations may be continuously performed on a calibrated drilling model to determine the state of the drillstring and detect when a condition exists that should be rectified.', 'Periodic recalibrations may be performed by adjusting model parameters when the predicted measurement value is not within a threshold of the actual measurement value for at least one position of the drillstring.', 'Turning to \nFIG.', '7\n, \nFIG.', '7\n shows a flowchart (\n700\n) for fatigue and overloading monitoring.', 'In \nFIG.', '7\n, fatigue for a segment may refer to a particular equipment part or an entire segment of the drillstring.', "Maximum stress may be determined, for example, based on equipment manufacturer's guidelines.", 'In Block \n701\n, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'Collecting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n601\n of \nFIG.', '6\n.', 'In Block \n703\n, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'Transmitting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n603\n of \nFIG.', '6\n.', 'In Block \n705\n, simulation model data is obtained in accordance with one or more embodiments.', 'Obtaining the simulation model data may be performed in a same or similar manner as discussed above with reference to Block \n605\n of \nFIG.', '6\n.', 'In Block \n707\n, a simulation model is developed using the simulation model data.', 'Developing the simulation model may be performed as discussed above with reference to Block \n607\n of \nFIG.', '6\n.', 'The simulation model models the various conditions that may cause stress on the drillstring.', 'For example, the simulation model may model the dimensions of the hole, the amount of rotation of different sections, interactions between the sections, as well as other aspects of the drillstring.', 'In Block \n709\n, simulation model calibration and simulation is performed in accordance with one or more embodiments.', 'The simulation model calibration and simulation may be performed as discussed above with reference to Blocks \n609\n-\n617\n of \nFIG.', '6\n.', 'The drilling simulation models the interaction between the drillstring and the subsurface formations.', 'For example, the simulations may calculate the amount of whirling motion, the dimensions of the borehole, and subsequently, the amount and type of stress on each piece of equipment of the drillstring.', 'The drilling simulation may be performed using a subsurface model of the underground formations.', 'In Block \n711\n, the stress along the drillstring is calculated using the calibrated model in accordance with one or more embodiments.', 'For each section, the stress is determined.', 'The stress may be cyclical based on the rotation of the drillstring.', 'For example, at a certain angle of rotation, one or more sections may have compression based stress and at another angle, the same components may have tension based stress.', 'Other forms of stress may also exist in the drillstring.', 'In one or more embodiments, the simulation may determine a stress value that includes bending stress amplitude and mean stress is obtained from the stress results.', 'In other words, for each section, the stress amplitude and mean stress is obtained.', 'In Block \n713\n, the cycles under different stress levels are counted in accordance with one or more embodiments.', 'The counting is for a predefined interval of time.', 'Counting the number of cycles may be based on the number of rotations of the drillstring and the number of cycles per rotation.', 'In Block \n715\n, a determination is made whether the time has expired to perform a comparison in accordance with one or more embodiments.', 'Block \n715\n may be performed in a same or similar manner discussed above with reference to Block \n623\n of \nFIG.', '6\n.', 'If the time expired to perform the comparison, the flow may proceed to Block \n717\n to determine whether to continue.', 'For example, the determination to not continue may be performed when the user determines to stop calibrating, drilling stops, simulations stop, etc.', 'In such a scenario, the flow may proceed to end.', 'If a determination is made to continue, the flow may proceed to Block \n709\n in accordance with one or more embodiments.', 'Returning to Block \n715\n, if the time has not expired for a comparison, the flow may proceed to Block \n719\n.', 'In Block \n719\n, the fatigue damage is calculated for each section in accordance with one or more embodiments.', 'Based on the amount of stress, the total amount of fatigue of the drillstring as drilling the section of wellbore may be determined.', 'In Block \n721\n, the fatigue damage is accumulated across the wellbore sections to obtain an accumulative fatigue damage.', 'The accumulation may be performed via additions, taking the maximum, or another accumulation technique.', 'In Block \n723\n, a determination is made whether the total fatigue damage is greater than the threshold or whether the maximum stress is greater than the yield stress in accordance with one or more embodiments.', 'In other words, a determination is made whether the fatigue for the drill string has accumulated sufficiently to cause a possible imminent failure of the drillstring or whether the current maximum stress may cause an imminent failure.', 'Imminent failure is determined to exist when the failure is within a predefined configurable threshold amount of time or use of the drillstring.', 'If the determination is made that the total fatigue damage is greater than the threshold or the maximum stress is greater than the yield stress, the flow may proceed to Block \n725\n to present an alert.', 'The alert may be presented by sending the alert via a network, displaying the alert via a display device, performing another alert presentation method, or any combination thereof.', 'The alert may be presented with a recommendation for a drilling operation based on the alert.', 'In one or more embodiments, a drilling operation may be performed based on the alert.', 'For example, the drilling operation may be to modify the mud weight, change a drilling parameter of the rotation, POOH (e.g., based on the detection of imminent failure), halt drilling, continue drilling without modification of drilling parameters, perform another operation, or combination thereof.', 'The drilling operation may be performed automatically or with human intervention.', 'For example, the field management tool may send a command to the surface unit that automatically performs the drilling operation.', 'By way of another example, the field management tool may generate a recommendation.', 'For example, the recommendation may be generated by obtaining stored rules for the equipment, and performing the action in the stored rules.', 'By using a continually calibrated simulation model that is updated using real time drilling data, one or more embodiments provide a mechanism to warn the drilling engineers when a current or future problem exists with the drillstring.\n \nFIG.', '8\n shows a flowchart (\n800\n) for vibration monitoring and diagnostics in accordance with one or more embodiments of the technology.', 'For example, the blocks in \nFIG.', '8\n may be used to monitor shock and vibration.', 'Such shock and vibration may be caused by damaging, rolling and stick sleeve.', 'In Block \n801\n, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'Collecting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n601\n of \nFIG.', '6\n.', 'In Block \n803\n, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'Transmitting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n603\n of \nFIG.', '6\n.', 'In Block \n805\n, simulation model data is obtained in accordance with one or more embodiments.', 'Obtaining the simulation model data may be performed in a same or similar manner as discussed above with reference to Block \n605\n of \nFIG.', '6\n.', 'In Block \n807\n, a simulation model is developed using the simulation model data.', 'Developing the simulation model may be performed as discussed above with reference to Block \n607\n of \nFIG.', '6\n.', 'The simulation model models the various conditions that may cause vibrations of the drillstring.', 'For example, the simulation model may model the dimensions of the hole, interactions between the drillstring and wellbore, as well as other aspects of the drillstring.', 'In Block \n809\n, simulation model calibration and simulation is performed in accordance with one or more embodiments.', 'The simulation model calibration and simulation may be performed as discussed above with reference to Blocks \n609\n-\n617\n of \nFIG.', '6\n.', 'The drilling simulation models the interaction between the drillstring and the subsurface formations.', 'In Block \n811\n, the vibrations along the drillstring are calculated using the calibrated model in accordance with one or more embodiments.', 'As discussed above, the simulation models the interaction between the drillstring and the subsurface formations.', 'Thus, calculating the vibrations may be performed by analyzing the interaction from the model for the vibrations.', 'In Block \n813\n, the vibrations are checked at defined drillstring components in accordance with one or more embodiments.', 'For selected components, the simulation server obtains the calculated vibrations.', 'The components that are selected may be configured and/or may be selected based on being possible points of failure.', 'In Block \n815\n, a determination is made whether the vibrations satisfy a threshold.', 'In other words, the determination is made whether the amount of vibration may lead to possible failure of the drillstring.', 'If the vibrations do not satisfy a threshold, the flow may proceed to Block \n829\n to determine whether to continue.', 'If the determination is made not to continue, the flow may proceed to end.', 'If the determination is made to continue, the flow may proceed to Block \n809\n.', 'Returning to Block \n815\n, if the vibrations satisfy the threshold, then the simulations are compared to real time vibration data in accordance with one or more embodiments.', 'In Block \n817\n, a determination is made whether the simulations match the real time vibration data.', 'Blocks \n815\n and \n817\n may be performed in a same or similar manner to Block \n707\n of \nFIG.', '7\n.', 'In other words, real time drilling measurement values of the vibrations are compared against the predicted values from the simulations.', 'The real time measurement values of vibrations that are used for the comparison may be at a particular section of the drillstring or may not be reflective of the entire current state of the drillstring.', 'Thus, the simulations may indicate a possible failure whereas the real time drilling data may not indicate a failure because of incompleteness of the measurements.', 'In Block \n819\n, if a determination is made that the simulations do not match the real time vibration data, the flow may return to Block \n809\n.', 'If matched, the flow may proceed to Block \n821\n.', 'In Block \n821\n, the vibration mode and severity are identified.', 'In other words, from the simulations, the type of vibration as well as the degree of vibration for the different components of the drillstring is determined.', 'In Block \n823\n, parameter optimization is performed for the simulation model in accordance with one or more embodiments.', 'In other words, the simulation is executed with different drilling parameters to determine whether a reduction of vibrations is possible.', 'In Block \n825\n, an alert is presented.', 'Further, changes may be performed based on the parameter optimization in Block \n827\n.', 'The changes may include changing a drilling operation based on the parameter optimization.', 'Presenting the alert and changing the drilling operation may be performed in a same or similar manner discussed above with reference to Block \n725\n of \nFIG.', '7\n.\n \nFIG.', '9\n shows a flowchart (\n900\n) for drillstring buckling and neutral point monitoring in accordance with one or more embodiments of the technology.', 'In Block \n901\n, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'Collecting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n601\n of \nFIG.', '6\n.', 'In Block \n903\n, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'Transmitting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n603\n of \nFIG.', '6\n.', 'In Block \n905\n, simulation model data is obtained in accordance with one or more embodiments.', 'Obtaining the simulation model data may be performed in a same or similar manner as discussed above with reference to Block \n605\n of \nFIG.', '6\n.', 'In Block \n907\n, a simulation model is developed using the simulation model data.', 'Developing the simulation model may be performed as discussed above with reference to Block \n607\n of \nFIG.', '6\n.', 'The simulation model models the movement of the drillstring through the borehole.', 'Thus, buckling of the drillstring and the neutral point may be identified.', 'In Block \n909\n, simulation model calibration and simulation is performed in accordance with one or more embodiments.', 'The simulation model calibration and simulation may be performed as discussed above with reference to Blocks \n609\n-\n617\n of \nFIG.', '6\n.', 'The drilling simulation models the interaction between the drillstring and the subsurface formations.', 'In Block \n911\n, the neutral point location is determined in accordance with one or more embodiments.', 'Determining the neutral point location may be performed as part of determining the stresses on the drillstring.', 'In particular, the neutral point is the point on a string of tubulars at which neither tension nor compression forces are present.', 'Below the neutral point, compression forces may exist that build toward the bottom of the wellbore.', 'Above the neutral point, tensile forces may exist build to a maximum applied at the hanger or as hook load.', 'Thus, determining the neutral point may include executing the simulations to identify a current and/or future state of the drillstring including the types of stresses on the different sections of the drillstring.', 'In Block \n913\n, a determination is made whether the neutral point is close to a particular tool in accordance with one or more embodiments.', 'The neutral point is determined to be close to the particular tool when the neutral point is within a threshold distance to the tool.', 'If the neutral point is close to the particular tool, an alert may be presented in Block \n919\n.', 'Further, a drilling operation may be performed.', 'Presenting the alert and performing the drilling operation may be performed in a same or similar manner as discussed above with reference to \nFIG.', '7\n.', 'Continuing from Block \n913\n, in Block \n915\n, the drillstring deformation in the wellbore is calculated in accordance with one or more embodiments.', 'Calculating the drillstring deformation includes determining how much the drillstring changes in shape based on the stresses in the borehole.', 'In other words, the drillstring should follow the path of the borehole linearly without any deformation.', 'However, some deformation may be present without causing a failure of the drillstring.', 'In Block \n917\n, a determination is made whether buckling is present in accordance with one or more embodiments.', 'Buckling is determined to be present when the amount of deformation is greater than a threshold.', 'If buckling is present, then an alert is presented in Block \n919\n.', 'A drilling operation may be performed in accordance with one or more embodiments.', 'Continuing with \nFIG.', '9\n, in Block \n920\n, a determination is made whether to continue.', 'If a determination is made not to continue, the flow may proceed to end.', 'If the determination is made to continue, the flow may proceed to Block \n909\n.', 'In particular, new real time drilling data may be obtained and compared against the simulation model in order to calibrate the simulation model.', 'Thus, as shown in the example of \nFIG.', '9\n, by continually updating and calibrating the simulation model using real time drilling data, one or more embodiments allow for a simulation based approach that is more accurate in order to monitor for drillstring failures caused by the neutral point being in a wrong location and/or drillstring deformation.\n \nFIG.', '10\n shows a flowchart (\n1000\n) for cutting structure force monitoring in accordance with one or more embodiments of the technology.', 'In Block \n1001\n, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'Collecting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n601\n of \nFIG.', '6\n.', 'In Block \n1003\n, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'Transmitting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block \n603\n of \nFIG.', '6\n.', 'In Block \n1005\n, simulation model data is obtained in accordance with one or more embodiments.', 'Obtaining the simulation model data may be performed in a same or similar manner as discussed above with reference to Block \n605\n of \nFIG.', '6\n.', 'In Block \n1007\n, a simulation model is developed using the simulation model data.', 'Developing the simulation model may be performed as discussed above with reference to Block \n607\n of \nFIG.', '6\n.', 'The simulation model models the various equipment that affects and/or includes the cutters.', 'In Block \n1009\n, simulation model calibration and simulation is performed in accordance with one or more embodiments.', 'The simulation model calibration and simulation may be performed as discussed above with reference to Blocks \n609\n-\n617\n of \nFIG.', '6\n.', 'The simulations using the simulation model may indicate the interaction between the cutters and the subsurface formation, the change in lubrication on the cutters, the speed of the cutters, and other aspects of the drilling operations that may affect the cutters.', 'In Block \n1011\n, the cutter status is determined using the simulation model.', 'Determining the cutter status may include determining various properties of the cutter.', 'In Block \n1013\n, a determination is made whether the cutter status indicates a problem.', 'If the cutter status does not indicate a problem, the flow may proceed to Block \n1015\n where a determination is made whether to continue.', 'If a determination is made to continue, the flow returns to Block \n1009\n to perform simulation model calibration and simulation using newly acquired real time drilling data.', 'If a determination is made to not continue the flow may proceed to end.', 'Returning to Block \n1013\n, if the cutter status indicates a problem, the flow may proceed to Block \n1017\n to compare the simulations with the real time data.', 'In Block \n1019\n, a determination is made whether the simulations match the real time drilling data.', 'Blocks \n1017\n and \n1019\n may be performed in a same or similar manner to Block \n707\n of \nFIG.', '7\n.', 'In other words, real time drilling measurement values of the cutter status of one or more of the cutters are compared against the predicted values from the simulations.', 'The real time measurement values that are used for the comparison may be at a particular section of the drillstring or may not be reflective of the entire current state of the drillstring.', 'Thus, the simulations may indicate a possible failure whereas the real time drilling data may not indicate a failure because of incompleteness of the measurements.', 'In Block \n1021\n, parameter optimization is performed for the simulation model in accordance with one or more embodiments.', 'In other words, the simulation is executed with different drilling parameters to determine whether the cutter status may be improved.', 'In Block \n1023\n, an alert is presented.', 'Further, changes may be performed based on the parameter optimization in Block \n1025\n.', 'The changes may include changing a drilling operation based on the parameter optimization.', 'Presenting the alert and changing the drilling operation may be performed in a same or similar manner discussed above with reference to Block \n725\n of \nFIG.', '7\n.', 'FIG.', '11\n shows a flowchart (\n1100\n) for measurement quality monitoring in accordance with one or more embodiments of the technology.', 'In Block \n1101\n, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'In Block \n1103\n, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'In Block \n1105\n, simulation model data is obtained in accordance with one or more embodiments.', 'In Block \n1107\n, a simulation model is developed using the simulation model data.', 'The simulation model models the various equipment of the drillstring and the subsurface formations.', 'In Block \n1109\n, simulation model calibration and simulation are performed in accordance with one or more embodiments.', 'The simulations using the simulation model may indicate the movement and forces of the drillstring.', 'Blocks \n1101\n-\n1109\n may be performed in a same or similar manner as discussed above with reference to Blocks \n1001\n-\n1009\n of \nFIG.', '10\n.', 'In Block \n1111\n, the movement and forces of the drillstring are determined using the simulation model.', 'In Block \n1113\n, a determination is made whether the movement and forces indicate a problem.', 'Determining whether the movement and forces indicate a problem may be performed by comparing output from the simulations with a rule base that relates simulation results to problem conditions.', 'If the movement and forces do not indicate a problem, the flow may proceed to Block \n1115\n where a determination is made whether to continue.', 'If a determination is made to continue, the flow returns to Block \n1109\n to perform simulation model calibration and simulation using newly acquired real time drilling data.', 'If a determination is made to not continue the flow may proceed to end.', 'Returning to Block \n1113\n, if the movement and/or forces indicate a problem, the flow may proceed to Block \n1117\n to compare the simulations with the real time data.', 'In Block \n1119\n, a determination is made whether the simulations match the real time drilling data.', 'Blocks \n1117\n and \n1119\n may be performed in a same or similar manner to Block \n707\n of \nFIG.', '7\n.', 'In Block \n1121\n, the problem is identified in accordance with one or more embodiments.', 'The problem may be identified, for example, from the rule base.', 'In Block \n1123\n, parameter optimization is performed for the simulation model in accordance with one or more embodiments.', 'In other words, the simulation is executed with different drilling parameters to determine whether the problem may be mitigated.', 'In Block \n1125\n, an alert is presented.', 'Further, changes may be performed based on the parameter optimization in Block \n1127\n.', 'The changes may include changing a drilling operation based on the parameter optimization.', 'Presenting the alert and changing the drilling operation may be performed in a same or similar manner discussed above with reference to Block \n725\n of \nFIG.', '7\n.', 'FIG.', '12\n shows a flowchart (\n1200\n) for borehole quality monitoring in accordance with one or more embodiments of the technology.', 'In Block \n1201\n, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'In Block \n1203\n, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'In Block \n1205\n, simulation model data is obtained in accordance with one or more embodiments.', 'In Block \n1207\n, a simulation model is developed using the simulation model data.', 'The simulation model models the various equipment of the drillstring and the subsurface formations.', 'In Block \n1209\n, simulation model calibration and simulation are performed in accordance with one or more embodiments.', 'The simulations using the simulation model may include how the drillstring moves through the borehole and the resulting dimensions and stability of the borehole.', 'Blocks \n1101\n-\n1109\n may be performed in a same or similar manner as discussed above with reference to Blocks \n1001\n-\n1009\n of \nFIG.', '10\n.', 'In Block \n1211\n, the well quality metrics are determined using the simulation model.', 'The well quality metrics quantify the dimensions, stability, and other properties of the borehole.', 'Determining the well quality metrics may be performed by comparing the various properties of the borehole with a rule base that assigns a value to each property.', 'In Block \n1213\n, a determination is made whether the well quality metrics satisfy a threshold.', 'If the well quality metrics satisfy a threshold, the flow may proceed to Block \n1215\n where a determination is made whether to continue.', 'If a determination is made to continue, the flow returns to Block \n1209\n to perform simulation model calibration and simulation using newly acquired real time drilling data.', 'If a determination is made to not continue the flow may proceed to end.', 'Returning to Block \n1213\n, if the well quality metrics do not satisfy a threshold, the flow may proceed to Block \n1217\n to compare the simulations with the real time data.', 'In Block \n1219\n, a determination is made whether the simulations match the real time drilling data.', 'Blocks \n1117\n and \n1119\n may be performed in a same or similar manner to Block \n707\n of \nFIG.', '7\n.', 'In Block \n1221\n, parameter optimization is performed for the simulation model in accordance with one or more embodiments.', 'In other words, the simulation is executed with different drilling parameters to determine whether the well quality may be improved.', 'For example, several simulations may be performed that each vary the weight on bit, flow rate, RPM, and other aspects of the drilling operations.', 'In Block \n1223\n, an alert is presented.', 'Further, changes may be performed based on the parameter optimization in Block \n1225\n.', 'The changes may include changing a drilling operation based on the parameter optimization.', 'Presenting the alert and changing the drilling operation may be performed in a same or similar manner discussed above with reference to Block \n725\n of \nFIG.', '7\n.', 'FIG.', '13\n shows a flowchart (\n1300\n) for jarring process monitoring in accordance with one or more embodiments of the technology.', 'The jarring process is a process to handle a stuck pipe failure.', 'In other words, different techniques may be performed to handle the problem when the drillstring is stuck.', 'Some techniques may cause breakage of the drillstring.', 'By simulating the jarring process, the drilling engineer may determine whether jarring will free the drillstring, perform nothing, or cause failure.', 'In Block \n1301\n, an event of a stuck pipe is detected.', 'For example, the surface unit may detect a stuck pipe using real time drilling data.', 'In Block \n1303\n, the top drive twist angle is measured.', 'In Block \n1305\n, real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'The real time drilling data may include the data discussed above and the top drive twist angle.', 'In Block \n1307\n, the top drive twisting process is simulated using a calibrated simulation model before stuck pipe to estimate depth of stuck pipe.', 'In other words, because a human cannot see into the subsurface formation at each depth, the location of the stuck pipe may be difficult to determine One or more embodiments use a calibrated simulation model, such as discussed above with reference to \nFIG.', '7\n to determine the location.', 'In Block \n1309\n, using the calibrated simulation model, the jarring process is simulated.', 'In Block \n1311\n, from the simulations, the force at the stuck point is obtained and the vibrations and forces along the drillstring are determined.', 'The forces and vibrations are compared with real time drilling data in Block \n1313\n and a determination is made whether the simulations match the real time data in Block \n1315\n.', 'If the simulations do not match, the flow proceeds to Block \n1317\n to recalibrate the simulation model before returning to Block \n1311\n.', 'If the simulations do match, the flow proceeds to Block \n1319\n, to perform parameter optimization for the simulation model in accordance with one or more embodiments.', 'In other words, the parameter optimization may optimize the drilling parameters when performing the jarring process.', 'In Block \n1321\n, a drilling parameter advisory is presented.', 'In Block \n1323\n, changes may be implemented to address the problem of the stuck pipe in accordance with one or more embodiments.', 'For example, the jarring process may be performed according to the parameter optimization.', 'By way of another example, if the determination is made that the jarring process does not improve the stuck pipe, then the other drilling operations may be performed.\n \nFIG.', '14.1\n shows a flowchart (\n1400\n) for motor tool face (TF) compensation in accordance with one or more embodiments of the technology.', 'The objective of the motor TF compensation module is to help the directional driller (DD) choose the right tool face offset before going on bottom.', 'DD may request help before going on bottom.', 'While on bottom, the system may obtain actual data and calibrate the drilling model to be ready for next DD request.', 'Output to the DD may be tool face as a function of flow and WOB.', 'In Block \n1401\n, real time drilling data that includes surface and downhole data including survey and drilling parameters is collected in accordance with one or more embodiments.', 'In Block \n1403\n, the real time drilling data is transmitted to the simulation server.', 'In Block \n1405\n, a request for TF estimation is received in accordance with one or more embodiments.', 'In Block \n1407\n, simulation model data is obtained.', 'In Block \n1409\n, the simulation model is developed using the simulation model data.', 'In Block \n1411\n, simulation model calibration and simulation is performed.', 'In Block \n1413\n, the results of the simulations are presented with recommendations.', 'In Block \n1415\n, the recommendations are applied.', 'In other words, a drilling operation is performed based on the recommendation.', 'In Block \n1417\n, a determination is made whether the recommendation is beneficial.', 'In other words, a determination is made whether the result of performing the recommendation improved performance.', 'If the recommendation is beneficial the flow may proceed to end.', 'Although not shown, the flow may proceed to perform simulations using the simulation model and then performing Block \n1413\n to provide additional recommendations.', 'If the recommendation is not beneficial, the simulation model may be recalibrated using new real time drilling data in Block \n1411\n.', 'The various blocks of \nFIG.', '14.1\n may be performed in a similar manner discussed above with reference to \nFIGS.', '7-13\n.\n \nFIG.', '14.2\n shows a diagram (\n1450\n) that may be presented as part of the recommendations to the drilling engineer.', 'As shown, the diagram presents a comparison of flow to WOB.', 'The numbers at the various positions indicate a simulated outcome when the corresponding flow and WOB are used.', 'The greyscale encoding presents the recommended flow and WOB (e.g., WOB of 5 and flow of 100) as well as the problematic flow and WOB (e.g., WOB of 35 and flow of 160).', 'Thus, a drilling engineer may optimize the drilling process accordingly.\n \nFIG.', '15\n shows a flowchart (\n1500\n) for steering parameter selection in accordance with one or more embodiments of the technology.', 'Steering parameter selection may apply to RSS or motor drilling.', 'The steering parameter selection suggests to the DD what steering parameters should be used to achieve the trajectory or DLS.', 'The steering parameter selection may be applied in real time or at the start of each stand and may include steering parameters, such as SR steering ratio, WOB, RPM, drilling cycle, and steering vs neutral distance.', 'In Block \n1501\n, real time drilling data that includes surface and downhole data including survey and drilling parameters is collected in accordance with one or more embodiments.', 'In Block \n1503\n, the real time drilling data is transmitted to the simulation server.', 'In Block \n1505\n, a request for steering parameters is received in accordance with one or more embodiments.', 'For example, the drilling engineering may submit the request to the simulation server.', 'In Block \n1507\n, simulation model data is obtained.', 'In Block \n1509\n, the simulation model is developed using the simulation model data.', 'In Block \n1511\n, simulation model calibration and simulation are performed.', 'In Block \n1513\n, the results of the simulations are presented with recommendations.', 'In Block \n1515\n, the recommendations are applied.', 'In other words, a drilling operation is performed based on the recommendation.', 'The drilling operation includes steering the drillstring according to the steering parameters.', 'In Block \n1517\n, a determination is made whether the recommendation is beneficial.', 'In other words, a determination is made whether the result of performing the recommendation improved performance.', 'If the recommendation is beneficial the flow may proceed to end.', 'Although not shown, the flow may proceed to perform simulations using the simulation model and then performing Block \n1513\n to provide additional recommendations.', 'If the recommendation is not beneficial, the simulation model may be recalibrated using new real time drilling data in Block \n1511\n.', 'The various blocks of \nFIG.', '15\n may be performed in a similar manner discussed above with reference to \nFIG.', '14.1\n.\n \nFIG.', '16.1\n shows a flowchart (\n1600\n) for drilling parameter optimization and recommendation in accordance with one or more embodiments of the technology.', 'In the planning phase, a drilling plan is generated.', 'However, the drilling plan is based on a certain formation, a certain friction coefficient and steering parameters that may or may not be similar to the actual well.', 'The drilling parameter optimization and recommendation in \nFIG.', '16.1\n is performed in real time during the drilling process.', 'In other words, the rock parameters and friction are computed/calibrated using real time data.', 'After calibration, the system may be used to understand the effects of changing drilling parameters.', 'In Block \n1601\n, real time drilling data that includes surface and downhole data including survey and drilling parameters is collected in accordance with one or more embodiments.', 'In Block \n1603\n, the real time drilling data is transmitted to the simulation server.', 'In Block \n1605\n, simulation model data is obtained.', 'In Block \n1607\n, the simulation model is developed using the simulation model data.', 'In Block \n1609\n, simulation model calibration and simulation is performed.', 'In Block \n1611\n, a request for drilling parameter analysis is received.', 'The drilling parameter analysis may be for new parameters, such as the parameters that the drilling engineer would like to submit or for current parameters.', 'In Block \n1613\n, simulations are executed in accordance with one or more embodiments.', 'In Block \n1615\n, the results of the simulations are presented.', 'A drilling operation may be performed based on the results of the simulations.', 'The various blocks of \nFIG.', '16.1\n may be performed in a similar manner discussed above with reference to \nFIG.', '14.1\n.', 'FIG.', '16.2\n shows a possible diagram (\n1650\n) of a presentation of simulation results.', 'As shown in \nFIG.', '16.2\n, the simulation results may be presented in a similar manner as \nFIG.', '14.2\n.', 'However, a different greyscale encoding may be applied to accommodate the particular drilling engineer request.', 'In other words, where the drilling engineer would like to optimize a particular variable (e.g., minimize risk, reduce cost, maximize recovery, etc.)', 'the user interface that is presented to the drilling engineer may have adjusted thresholds in order to show the drilling parameters that have the optimal value of the requested variable.', 'Although the above figures separately describe one or more embodiments, the various above figures may be combined in virtually any manner.', 'The various combinations are contemplated herein and do not depart from embodiments of the technology.', 'For example, the same simulation model may be used for several of the workflows described herein.', 'The computing system(s) performing one or more embodiments described herein may include functionality to perform a variety of operations disclosed herein.', 'For example, the computing system(s) may perform communication between processes on the same or a different system.', 'A variety of mechanisms, employing some form of active or passive communication, may facilitate the exchange of data between processes on the same device.', 'Examples representative of these inter-process communications include, but are not limited to, the implementation of a file, a signal, a socket, a message queue, a pipeline, a semaphore, shared memory, message passing, and a memory-mapped file.', 'Further details pertaining to some of these non-limiting examples are provided below.', 'Based on the client-server networking model, sockets may serve as interfaces or communication channel end-points enabling bidirectional data transfer between processes on the same device.', 'Foremost, following the client-server networking model, a server process (e.g., a process that provides data) may create a first socket object.', 'Next, the server process binds the first socket object, thereby associating the first socket object with a unique name and/or address.', 'After creating and binding the first socket object, the server process then waits and listens for incoming connection requests from one or more client processes (e.g., processes that seek data).', 'At this point, when a client process wishes to obtain data from a server process, the client process starts by creating a second socket object.', 'The client process then proceeds to generate a connection request that includes at least the second socket object and the unique name and/or address associated with the first socket object.', 'The client process then transmits the connection request to the server process.', 'Depending on availability, the server process may accept the connection request, establishing a communication channel with the client process, or the server process, busy in handling other operations, may queue the connection request in a buffer until server process is ready.', 'An established connection informs the client process that communications may commence.', 'In response, the client process may generate a data request specifying the data that the client process wishes to obtain.', 'The data request is subsequently transmitted to the server process.', 'Upon receiving the data request, the server process analyzes the request and gathers the requested data.', 'Finally, the server process then generates a reply including at least the requested data and transmits the reply to the client process.', 'The data may be transferred as datagrams or a stream of characters (e.g., bytes).', 'Shared memory refers to the allocation of virtual memory space in order to substantiate a mechanism for which data may be communicated and/or accessed by multiple processes.', 'In implementing shared memory, an initializing process first creates a shareable segment in persistent or non-persistent storage.', 'Post creation, the initializing process then mounts the shareable segment, subsequently mapping the shareable segment into the address space associated with the initializing process.', 'Following the mounting, the initializing process proceeds to identify and grant access permission to one or more authorized processes that may also write and read data to and from the shareable segment.', 'Changes made to the data in the shareable segment by one process may immediately affect other processes, which are also linked to the shareable segment.', 'Further, when one of the authorized processes accesses the shareable segment, the shareable segment maps to the address space of that authorized process.', 'Often, one authorized process may mount the shareable segment, other than the initializing process, at any given time.', 'Other techniques may be used to share data, such as the various data described in the present application, between processes without departing from the scope.', 'The processes may be part of the same or different application and may execute on the same or different computing system.', 'Rather than or in addition to sharing data between processes, the computing system performing one or more embodiments may include functionality to receive data from a user.', 'For example, in one or more embodiments, a user may submit data via a graphical user interface (GUI) on the user device.', 'Data may be submitted via the GUI by a user selecting one or more GUI widgets or inserting text and other data into GUI widgets using a touchpad, a keyboard, a mouse, or any other input device.', 'In response to selecting a particular item, information regarding the particular item may be obtained from persistent or non-persistent storage by the computer processor.', "Upon selection of the item by the user, the contents of the obtained data regarding the particular item may be displayed on the user device in response to the user's selection.", 'By way of another example, a request to obtain data regarding the particular item may be sent to a server operatively connected to the user device through a network.', 'For example, the user may select a uniform resource locator (URL) link within a web client of the user device, thereby initiating a Hypertext Transfer Protocol (HTTP) or other protocol request being sent to the network host associated with the URL.', 'In response to the request, the server may extract the data regarding the particular selected item and send the data to the device that initiated the request.', "Once the user device has received the data regarding the particular item, the contents of the received data regarding the particular item may be displayed on the user device in response to the user's selection.", 'Further to the above example, the data received from the server after selecting the URL link may provide a web page in Hyper Text Markup Language (HTML) that may be rendered by the web client and displayed on the user device.', 'Once data is obtained, such as by using techniques described above or from storage, the computing system, in performing one or more embodiments, may extract one or more data items from the obtained data.', 'For example, the extraction may be performed as follows by the computing system in \nFIG.', '4.1\n.', 'First, the organizing pattern (e.g., grammar, schema, layout) of the data is determined, which may be based on one or more of the following: position (e.g., bit or column position, Nth token in a data stream, etc.), attribute (where the attribute is associated with one or more values), or a hierarchical/tree structure (consisting of layers of nodes at different levels of detail—such as in nested packet headers or nested document sections).', 'Then, the raw, unprocessed stream of data symbols is parsed, in the context of the organizing pattern, into a stream (or layered structure) of tokens (where each token may have an associated token “type”).', 'Next, extraction criteria are used to extract one or more data items from the token stream or structure, where the extraction criteria are processed according to the organizing pattern to extract one or more tokens (or nodes from a layered structure).', 'For position-based data, the token(s) at the position(s) identified by the extraction criteria are extracted.', 'For attribute/value-based data, the token(s) and/or node(s) associated with the attribute(s) satisfying the extraction criteria are extracted.', 'For hierarchical/layered data, the token(s) associated with the node(s) matching the extraction criteria are extracted.', 'The extraction criteria may be as simple as an identifier string or may be a query presented to a structured data repository (where the data repository may be organized according to a database schema or data format, such as XML).', 'The extracted data may be used for further processing by the computing system.', 'For example, the computing system of \nFIG.', '4.1\n, while performing one or more embodiments, may perform data comparison.', 'Data comparison may be used to compare two or more data values (e.g., A, B).', 'For example, one or more embodiments may determine whether A>B, A=B, A!=B, A B, B may be subtracted from A (i.e., A−B), and the status flags may be read to determine if the result is positive (i.e., if A>B, then A−B>0).', 'In one or more embodiments, B may be considered a threshold, and A is deemed to satisfy the threshold if A=B or if A>B, as determined using the ALU.', 'In one or more embodiments, A and B may be vectors, and comparing A with B includes comparing the first element of vector A with the first element of vector B, the second element of vector A with the second element of vector B, etc.', 'In one or more embodiments, if A and B are strings, the binary values of the strings may be compared.', 'The computing system in \nFIG.', '4.1\n may implement and/or be connected to a data repository.', 'For example, one type of data repository is a database.', 'A database is a collection of information configured for ease of data retrieval, modification, re-organization, and deletion.', 'Database Management System (DBMS) is a software application that provides an interface for users to define, create, query, update, or administer databases.', 'The user, or software application, may submit a statement or query into the DBMS.', 'Then the DBMS interprets the statement.', 'The statement may be a select statement to request information, update statement, create statement, delete statement, etc.', 'Moreover, the statement may include parameters that specify data, or data container (database, table, record, column, view, etc.), identifier(s), conditions (comparison operators), functions (e.g. join, full join, count, average, etc.), sort (e.g. ascending, descending), or others.', 'The DBMS may execute the statement.', 'For example, the DBMS may access a memory buffer, a reference or index a file for read, write, deletion, or any combination thereof, for responding to the statement.', 'The DBMS may load the data from persistent or non-persistent storage and perform computations to respond to the query.', 'The DBMS may return the result(s) to the user or software application.', 'The computing system of \nFIG.', '4.1\n may include functionality to present raw and/or processed data, such as results of comparisons and other processing.', 'For example, presenting data may be accomplished through various presenting methods.', 'Specifically, data may be presented through a user interface provided by a computing device.', 'The user interface may include a GUI that displays information on a display device, such as a computer monitor or a touchscreen on a handheld computer device.', 'The GUI may include various GUI widgets that organize what data is shown as well as how data is presented to a user.', 'Furthermore, the GUI may present data directly to the user, e.g., data presented as actual data values through text, or rendered by the computing device into a visual representation of the data, such as through visualizing a data model.', 'For example, a GUI may first obtain a notification from a software application requesting that a particular data object be presented within the GUI.', 'Next, the GUI may determine a data object type associated with the particular data object, e.g., by obtaining data from a data attribute within the data object that identifies the data object type.', 'Then, the GUI may determine any rules designated for displaying that data object type, e.g., rules specified by a software framework for a data object class or according to any local parameters defined by the GUI for presenting that data object type.', 'Finally, the GUI may obtain data values from the particular data object and render a visual representation of the data values within a display device according to the designated rules for that data object type.', 'Data may also be presented through various audio methods.', 'In particular, data may be rendered into an audio format and presented as sound through one or more speakers operably connected to a computing device.', 'Data may also be presented to a user through haptic methods.', 'For example, haptic methods may include vibrations or other physical signals generated by the computing system.', 'For example, data may be presented to a user using a vibration generated by a handheld computer device with a predefined duration and intensity of the vibration to communicate the data.', 'The above description of functions presents a few examples of functions performed by the computing system of \nFIG.', '4.1\n and the nodes and/or client device in \nFIG.', '4.2\n.', 'Other functions may be performed using one or more embodiments.', 'The field management tool may further include a data repository.', 'A data repository is any type of storage unit and/or device (e.g., a file system, database, collection of tables, or any other storage mechanism) for storing data.', 'Further, the data repository may include multiple different storage units and/or devices.', 'The multiple different storage units and/or devices may or may not be of the same type or located at the same physical site.', 'Although the preceding description has been described herein with reference to particular means, materials, and embodiments, it is not intended to be limited to the particular disclosed herein.', 'By way of further example, embodiments may be utilized in conjunction with a handheld system (i.e., a phone, wrist or forearm mounted computer, tablet, or other handheld device), portable system (i.e., a laptop or portable computing system), a fixed computing system (i.e., a desktop, server, cluster, or high performance computing system), or across a network (i.e., a cloud-based system).', 'As such, embodiments extend to all functionally equivalent structures, methods, uses, program products, and compositions as are within the scope of the appended claims.', 'While the technology has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the technology as disclosed herein.', 'Accordingly, the scope of the technology should be limited by the attached claims.'] | ['1.', 'A method for managing drilling operations comprising:\ncalibrating a drilling model using collected drilling data;\nexecuting, during a drilling operation, a simulation of the drilling model to generate a predicted measurement value for a drilling property;\nobtaining, during the drilling operation and from a drillstring, an actual measurement value for the drilling property;\ncomparing the actual measurement value to the predicted measurement value;\ndetermining that the actual measurement value matches the predicted measurement value;\nwithout recalibrating the model, again executing the simulation of the drilling model to generate a second predicted measurement value;\ndetermining that a predetermined time for a comparison between actual and predicted measurement values has not expired;\nin response to determining that the time has not expired: obtaining a second actual measurement value; and comparing the second actual measurement value with a second predicted measurement value;\ndetermining that the second actual measurement value does not match the second predicted measurement value;\nin response to determining that the second actual measurement value does not match the second predicted measurement value, recalibrating the drilling model;\nextending the simulation during the drilling operation, based on the actual measurement value matching the predicted measurement value, to generate a simulated state of the drillstring during the drilling operation, the simulated state of the drillstring being monitored in the extended simulation;\ndetermining a neutral point of the drillstring based at least partially upon the simulated state of the drillstring, wherein the drillstring experiences compression forces below the neutral point and tensile forces above the neutral point;\ndetermining that a distance between the neutral point and a tool coupled to the drillstring is less than a predetermined distance;\ndetecting, during the drilling operation, a hazardous condition of the drilling operation based on the distance being less than the predetermined distance, wherein the condition comprises a likelihood that the tool will be damaged; and\npresenting a notification based on the condition during the drilling operation.', '2.', 'The method of claim 1, wherein detecting the condition comprises detecting vibration of the drillstring based on the simulated state of the drilling operation.', '3.', 'The method of claim 1, further comprising:\ndetermining, during the drilling operation, a setting for a rate of penetration of the drillstring,\nwherein presenting the notification comprises presenting the setting based on the estimated rate of penetration.', '4.', 'The method of claim 1, wherein detecting the condition comprises determining that an actual trajectory of a well bore based on the simulated state of the drilling operation fails to match a planned trajectory, and wherein the method further comprises:\nselecting a setting to adjust the actual trajectory to match the planned trajectory, wherein presenting the notification comprises presenting the setting.', '5.', 'The method of claim 1, wherein detecting the condition comprises determining that a shape of a well bore fails to satisfy a quality threshold, and wherein the method further comprises:\nselecting a setting to adjust the shape of the well bore to match the quality threshold, wherein presenting the notification comprises presenting the setting.', '6.', 'The method of claim 1, wherein detecting the condition comprises determining that a collection of drilling data fails to satisfy a quality threshold for a plurality of measurements, and wherein the method further comprises:\nselecting a setting to adjust the collection of data to satisfy the quality threshold, wherein presenting the notification comprises presenting the setting.', '7.', 'The method of claim 1, further comprising:\ncalculating an estimated amount of fatigue of a part of the drillstring using the simulated state,\nwherein detecting the condition comprises comparing the estimated amount of fatigue with a maximal fatigue for the part to obtain a remaining life of the part, and determining that the remaining life fails to satisfy a threshold, and wherein presenting the notification comprises presenting an alert to rectify the part.', '8.', 'The method of claim 1, further comprising:\ndetermining, during the drilling operation, a bit reamer load balancing setting,\nwherein detecting the condition comprises determining that the bit reamer load balancing setting fails to satisfy a predefined threshold of bit reamer load balancing,\nwherein presenting the notification comprises presenting an alert to rectify the bit reamer load balancing setting and the drilling parameter recommendation to achieve at least the predetermined threshold of bit reamer load balancing.', '9.', 'The method of claim 1, wherein detecting the condition comprises detecting a buckling of the drillstring, and presenting the notification comprises presenting a setting to address the bucking.', '10.', 'The method of claim 1, further comprising\ncollecting the drilling data from a plurality of sensors located along the drillstring.', '11.', 'The method of claim 1, wherein the drilling model is further calibrated with a subsurface model.\n\n\n\n\n\n\n12.', 'The method of claim 1, wherein the condition comprises vibration in the drillstring, shock in the drillstring, buckling of the drillstring, stress in the drillstring, or a combination thereof.', '13.', 'The method of claim 1, further comprising determining that the predetermined time for comparison has expired, and in response:\nmeasuring a real-time rock parameter for a real-time drillstring position;\nmeasuring a real-time drilling parameter for the real-time drillstring position;\nrecalibrating the model based in part on the real-time rock parameter and the real-time drilling parameter.', '14.', 'The method of claim 1, wherein the predetermined time is set based on chronological duration or displacement of the drillstring.', '15.', 'A system for managing drilling operations comprising:\na surface unit that: collects an actual measurement value from a drillstring during a drilling operation, and presents a notification based on a hazardous condition detected during the drilling operation, wherein the condition comprises a likelihood that a tool will be damaged; and\na simulation server that: calibrates a drilling model using collected drilling data, executes, during the drilling operation, a simulation on the drilling model to generate a predicted measurement value for a drilling property, obtains, during the drilling operation and from the surface unit, the actual measurement value for the drilling property, compares the actual measurement value to the predicted measurement value; determines that the actual measurement value matches the predicted measurement value; again executes the simulation of the drilling model to generate a second predicted measurement value, without recalibrating the model between executing and again executing; determines that a predetermined time for a comparison between actual and predicted measurement values has not expired; in response to determining that the time has not expired: obtains a second actual measurement value; and compares the second actual measurement value with a second predicted measurement value; determines that the second actual measurement value does not match the second predicted measurement value; in response to determining that the second actual measurement value does not match the second predicted measurement value, recalibrates the drilling model; extends the simulation during the drilling operation, based on the actual measurement value matching the predicted measurement value, to generate the simulated state of the drillstring during the drilling operation, the simulated state of the drillstring being monitored in the extended simulation; determines a neutral point of the drillstring based at least partially upon the simulated state of the drillstring, wherein the drillstring experiences compression forces below the neutral point and tensile forces above the neutral point; determining that a distance between the neutral point and the tool coupled to the drillstring is less than a predetermined distance; detects, during the drilling operation, the condition of the drilling operation based on the distance being less than the predetermined distance.', '16.', 'The system of claim 15, wherein the drillstring comprises a plurality of sensors for acquiring the actual measurement value, the drillstring for drilling a wellbore.\n\n\n\n\n\n\n17.', 'A non-transitory computer readable medium for managing drilling operations, the non-transitory computer readable medium comprising computer readable program code for:\ncalibrating a drilling model using collected drilling data;\nexecuting, during a drilling operation, a simulation on the drilling model to generate a predicted measurement value for a drilling property;\nobtaining, during the drilling operation and from a drillstring, an actual measurement value for the drilling property;\ncomparing the actual measurement value to the predicted measurement value;\ndetermining that the actual measurement value matches the predicted measurement value;\nwithout recalibrating the model after executing the simulation, again executing the simulation of the drilling model to generate a second predicted measurement value;\ndetermining that a predetermined time for a comparison between actual and predicted measurement values has not expired;\nin response to determining that the time has not expired: obtaining a second actual measurement value; and comparing the second actual measurement value with the second predicted measurement value;\ndetermining that the second actual measurement value does not match the second predicted measurement value;\nin response to determining that the second actual measurement value does not match the second predicted measurement value, recalibrating the drilling model;\nextending the simulation during the drilling operation, based on the actual measurement value matching the predicted measurement value, to generate a simulated state of the drillstring during the drilling operation, the simulated state of the drillstring being monitored in the extended simulation;\ndetermining a neutral point of the drillstring based at least partially upon the simulated state of the drillstring, wherein the drillstring experiences compression forces below the neutral point and tensile forces above the neutral point;\ndetermining that a distance between the neutral point and a tool coupled to the drillstring is less than a predetermined distance;\ndetecting, during the drilling operation, a hazardous condition of the drilling operation based on the distance being less than the predetermined distance, wherein the condition comprises a likelihood that the tool will be damaged; and\npresenting a notification based on the condition during the drilling operation.', '18.', 'The non-transitory computer readable medium of claim 17, wherein detecting the condition comprises detecting vibration of the drillstring based on the simulated state of the drilling operation.', '19.', 'The non-transitory computer readable medium of claim 17, further comprising computer readable program code for:\ndetermining, during the drilling operation, an optimal setting for a rate of penetration of the drillstring,\nwherein detecting the condition comprises determining that an estimated rate of penetration fails to match an actual rate of penetration, and\nwherein presenting the notification comprises presenting the optimal setting for an improved rate of penetration.', '20.', 'The non-transitory computer readable medium of claim 17, wherein detecting the condition comprises determining that an actual trajectory of a well bore based on the simulated state of the drilling operation fails to match a planned trajectory, and wherein the non-transitory computer readable medium further comprises computer readable program code for:\nselecting a setting to adjust the actual trajectory to match the planned trajectory, wherein presenting the notification comprises presenting the setting.', '21.', 'The non-transitory computer readable medium of claim 17, wherein detecting the condition comprises determining that a collection of drilling data fails to satisfy a quality threshold for a plurality of measurements, and wherein the non-transitory computer readable medium further comprises computer readable program code for:\nselecting a setting to adjust the collection of drilling data to satisfy the quality threshold, wherein presenting the notification comprises presenting the setting.', '22.', 'The non-transitory computer readable medium of claim 17, further comprising computer readable program code for:\ndetermining, during the drilling operation, a bit reamer load balancing setting,\nwherein detecting the condition comprises determining that the bit reamer load balancing setting fails to satisfy a predefined threshold of bit reamer load balancing, and\nwherein presenting the notification comprises presenting an alert to rectify the bit reamer load balancing setting and a drilling parameter recommendation to achieve the optimal load balancing.', '23.', 'The non-transitory computer readable medium of claim 17, wherein detecting the condition comprises detecting a buckling of the drillstring, and presenting the notification comprises presenting a setting to address the bucking.'] | ['FIGS.', '1, 2, 3.1, 3.2, 4.1, and 4.2 show schematic diagrams in accordance with one or more embodiments of the technology.;', 'FIGS. 5, 6, 7, 8, 9, 10, 11, 12, 13, 14.1, 15, and 16.1 show flowcharts in accordance with one or more embodiments of the technology.; FIGS.', '14.2 and 16.2 show example output in accordance with one or more embodiments of the technology.; FIG.', '1 depicts a schematic view, partially in cross section, of a field (100) in which one or more embodiments may be implemented.', 'In one or more embodiments, the field may be an oilfield.', 'In other embodiments, the field may be a different type of field.', 'In one or more embodiments, one or more of the modules and elements shown in FIG.', '1 may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments should not be considered limited to the specific arrangements of modules shown in FIG.', '1.; FIG.', '2 shows a schematic diagram depicting a drilling operation of a directional well in multiple sections.', 'The drilling operation depicted in FIG.', '2 includes a wellsite drilling system (200) and a field management tool (220) for accessing fluid in the target reservoir through a borehole (250) of a directional well (217).', 'The wellsite drilling system (200) includes various components (e.g., drillstring (212), annulus (212), bottom hole assembly (BHA) (214), Kelly (215), mud pit (216), etc.)', 'as generally described with respect to the wellsite drilling systems (100) (e.g., drillstring (115), annulus (126), bottom hole assembly (BHA) (120), Kelly (116), mud pit (122), etc.) of FIG.', '1 above.', 'As shown in FIG.', '2.', 'the target reservoir may be located away from (as opposed to directly under) the surface location of the directional well (217).', 'Accordingly, special tools or techniques may be used to ensure that the path along the bore hole (250) reaches the particular location of the target reservoir (200).; FIG.', '3.1 shows an example of a communication structure in accordance with one or more embodiments of the technology.', 'As shown in FIG.', '3.1, a wellsite drilling system (310) is connected to a surface unit (304) and simulation server (308).', 'The wellsite drilling system (310) and surface unit (304) may be the same or similar to the wellsite drilling system and surface unit discussed above with reference to FIG.', '2.', 'As shown in FIG.', '3.1, downhole sensors (300) may transmit downhole data (302) via the communication link to a surface unit (304).', 'Similarly, rig surface data (306) may also be transmitted to surface unit (304).', 'The surface unit (304) may provide the field data (312) to a simulation server (308).', 'The field data (312) includes rig surface data (306) and downhole data (302).', 'The rig surface data (306) is any data that is collected from the rig surface (314).', 'The downhole data (302) is any data collected downhole.', 'Example rig surface data (306) and downhole data (302) may include any of the data described above with reference to FIGS.', '1 and 2.; FIG.', '3.2 shows an example schematic diagram of a system showing flow in accordance with one or more embodiments of the technology.', 'As shown in FIG.', '3.2, at the rig site (350) of the drilling rig, drilling data may be collected (352).', 'The drilling data (352) may be transferred (354) to remote server (356), such as the field management tool.', 'The remote server may (356) perform real time drilling model calibration and simulation (358).', 'Results of the simulation may be transferred (360) to the rig site (350) for display (362).; FIGS.', '5, 6, 7, 8, 9, 10, 11, 12, 13, 14.1, 15, and 16.1 show example flowcharts in accordance with one or more embodiments of the technology.', 'While the various blocks in this flowchart are presented and described sequentially, one of ordinary skill will appreciate that some of the blocks may be executed in different orders, may be combined or omitted, and some of the blocks may be executed in parallel.', 'Furthermore, the blocks may be performed actively or passively.', 'For example, some blocks may be performed using polling or be interrupt driven in accordance with one or more embodiments of the technology.', 'By way of an example, determination blocks may not require a processor to process an instruction unless an interrupt is received to signify that condition exists in accordance with one or more embodiments of the technology.', 'As another example, determination blocks may be performed by performing a test, such as checking a data value to test whether the value is consistent with the tested condition in accordance with one or more embodiments of the technology.; FIG.', '5 shows an example flowchart in accordance with one or more embodiments.', 'In Block 501, a drilling model is calibrated using collected drilling data in accordance with one or more embodiments.', 'In one or more embodiments, downhole sensors detect various physical properties of the rocks and the state of the drillstring as downhole data and transmit the downhole data to the surface unit.', 'Similarly, the rig surface may also collect and transmit rig surface data to the surface unit.', 'The surface unit may send the rig surface data and the downhole data as field data to a simulation server.', 'The simulation server may use the field data, along with detailed configuration information about the drillstring, and a subsurface model to generate a drilling model.', 'The drilling model describes how the drillstring progresses through the subsurface formations.; FIGS.', '6-13, 14.1, and 14.2 show example workflows for performing one or more embodiments described herein.; FIG.', '6 shows an example flowchart (600) to calibrate a model in accordance with one or more embodiments of the technology.', 'In Block 601, real time drilling data is collected.', 'Collecting real time drilling data may be performed as discussed above with reference to Block 501 of FIG.', '5.; FIG. 8 shows a flowchart (800) for vibration monitoring and diagnostics in accordance with one or more embodiments of the technology.', 'For example, the blocks in FIG.', '8 may be used to monitor shock and vibration.', 'Such shock and vibration may be caused by damaging, rolling and stick sleeve.', 'In Block 801, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'Collecting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block 601 of FIG.', '6.; FIG.', '9 shows a flowchart (900) for drillstring buckling and neutral point monitoring in accordance with one or more embodiments of the technology.', 'In Block 901, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'Collecting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block 601 of FIG.', '6.; FIG.', '10 shows a flowchart (1000) for cutting structure force monitoring in accordance with one or more embodiments of the technology.', 'In Block 1001, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'Collecting the real time drilling data may be performed in a same or similar manner as discussed above with reference to Block 601 of FIG.', '6.; FIG.', '11 shows a flowchart (1100) for measurement quality monitoring in accordance with one or more embodiments of the technology.', 'In Block 1101, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'In Block 1103, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'In Block 1105, simulation model data is obtained in accordance with one or more embodiments.', 'In Block 1107, a simulation model is developed using the simulation model data.', 'The simulation model models the various equipment of the drillstring and the subsurface formations.', 'In Block 1109, simulation model calibration and simulation are performed in accordance with one or more embodiments.', 'The simulations using the simulation model may indicate the movement and forces of the drillstring.', 'Blocks 1101-1109 may be performed in a same or similar manner as discussed above with reference to Blocks 1001-1009 of FIG.', '10.; FIG. 12 shows a flowchart (1200) for borehole quality monitoring in accordance with one or more embodiments of the technology.', 'In Block 1201, real time drilling data is collected that includes surface and downhole data including actual pipe rotation.', 'In Block 1203, the real time drilling data is transmitted to the simulation server in accordance with one or more embodiments.', 'In Block 1205, simulation model data is obtained in accordance with one or more embodiments.', 'In Block 1207, a simulation model is developed using the simulation model data.', 'The simulation model models the various equipment of the drillstring and the subsurface formations.', 'In Block 1209, simulation model calibration and simulation are performed in accordance with one or more embodiments.', 'The simulations using the simulation model may include how the drillstring moves through the borehole and the resulting dimensions and stability of the borehole.', 'Blocks 1101-1109 may be performed in a same or similar manner as discussed above with reference to Blocks 1001-1009 of FIG.', '10.; FIG. 13 shows a flowchart (1300) for jarring process monitoring in accordance with one or more embodiments of the technology.', 'The jarring process is a process to handle a stuck pipe failure.', 'In other words, different techniques may be performed to handle the problem when the drillstring is stuck.', 'Some techniques may cause breakage of the drillstring.', 'By simulating the jarring process, the drilling engineer may determine whether jarring will free the drillstring, perform nothing, or cause failure.;', 'FIG.', '14.1 shows a flowchart (1400) for motor tool face (TF) compensation in accordance with one or more embodiments of the technology.', 'The objective of the motor TF compensation module is to help the directional driller (DD) choose the right tool face offset before going on bottom.', 'DD may request help before going on bottom.', 'While on bottom, the system may obtain actual data and calibrate the drilling model to be ready for next DD request.', 'Output to the DD may be tool face as a function of flow and WOB.; FIG.', '14.2 shows a diagram (1450) that may be presented as part of the recommendations to the drilling engineer.', 'As shown, the diagram presents a comparison of flow to WOB.', 'The numbers at the various positions indicate a simulated outcome when the corresponding flow and WOB are used.', 'The greyscale encoding presents the recommended flow and WOB (e.g., WOB of 5 and flow of 100) as well as the problematic flow and WOB (e.g., WOB of 35 and flow of 160).', 'Thus, a drilling engineer may optimize the drilling process accordingly.', '; FIG.', '15 shows a flowchart (1500) for steering parameter selection in accordance with one or more embodiments of the technology.', 'Steering parameter selection may apply to RSS or motor drilling.', 'The steering parameter selection suggests to the DD what steering parameters should be used to achieve the trajectory or DLS.', 'The steering parameter selection may be applied in real time or at the start of each stand and may include steering parameters, such as SR steering ratio, WOB, RPM, drilling cycle, and steering vs neutral distance.', '; FIG.', '16.1 shows a flowchart (1600) for drilling parameter optimization and recommendation in accordance with one or more embodiments of the technology.', 'In the planning phase, a drilling plan is generated.', 'However, the drilling plan is based on a certain formation, a certain friction coefficient and steering parameters that may or may not be similar to the actual well.', 'The drilling parameter optimization and recommendation in FIG.', '16.1 is performed in real time during the drilling process.', 'In other words, the rock parameters and friction are computed/calibrated using real time data.', 'After calibration, the system may be used to understand the effects of changing drilling parameters.; FIG.', '16.2 shows a possible diagram (1650) of a presentation of simulation results.', 'As shown in FIG.', '16.2, the simulation results may be presented in a similar manner as FIG.', '14.2.', 'However, a different greyscale encoding may be applied to accommodate the particular drilling engineer request.', 'In other words, where the drilling engineer would like to optimize a particular variable (e.g., minimize risk, reduce cost, maximize recovery, etc.)', 'the user interface that is presented to the drilling engineer may have adjusted thresholds in order to show the drilling parameters that have the optimal value of the requested variable.'] |
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US11125020 | Downhole drilling apparatus with drilling, steering, and reaming functions and methods of use | Apr 2, 2019 | Geoffrey Charles Downton, Jonathan D. Marshall | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 2715552; August 1955; Lane; 3276824; October 1966; Carter; 4549613; October 29, 1985; Case; 7159668; January 9, 2007; Herrera; 7775303; August 17, 2010; Goting; 8256536; September 4, 2012; Harrison et al.; 8365843; February 5, 2013; Hall et al.; 20080000693; January 3, 2008; Hutton; 20120205163; August 16, 2012; Azar; 20170159370; June 8, 2017; Evans; 20170234071; August 17, 2017; Spatz | Foreign Citations not found. | ['A downhole drilling apparatus may comprise a rotatable body with various cutting elements connected thereto, some radially protruding therefrom, some radially extendable therefrom, and some revolvable relative thereto about a common axis.', 'In operation, when the body is rotated, the radially protruding cutting elements may bore a generally cylindrical borehole.', "The radially extendable cutting elements may be extended during specific portions of the body's rotation to degrade certain areas of an inner wall of the borehole transforming it into a non-cylindrical borehole.", 'At certain times, the revolvable cutting elements may be allowed to slide against the non-cylindrical inner wall while freely revolving to minimize disturbance to the borehole shape.', 'At other times, revolution of these revolvable cutting elements may be restrained to ream the borehole back to a cylindrical shape.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nWhen exploring for or extracting subterranean resources, such as oil, gas, or geothermal energy, and in similar endeavors, it is common to form boreholes in the earth.', 'Such boreholes may be formed by engaging the earth with a rotating drill bit capable of degrading tough earthen materials.', 'As rotation continues the borehole may elongate and the drill bit may be fed into it on the end of a drill string.', 'At times it may be desirable to alter a direction of travel of the drill bit as it is forming a borehole.', 'This may be to steer toward valuable resources or away from obstacles.', 'A variety of techniques have been developed to accomplish such steering.', 'One such technique comprises giving a borehole a cross-sectional shape that urges the drill bit in a lateral direction.', 'For example, a cross-sectional shape comprising two circular arcs, one larger than the drill bit and one smaller, may urge the drill bit away from the smaller circular arc and into the open space provided by the larger circular arc.', 'Such a cross-sectional shape may be formed by an apparatus comprising one or more cutting elements radially extendable therefrom.', 'Timed extension of the cutting elements, while the apparatus is rotating within a borehole, may allow them to degrade an inner wall of the borehole in certain places to create a non-cylindrical borehole shape.', 'An abrasion-resistant gauge pad, protruding radially from the apparatus, may ride against this borehole inner wall to urge the apparatus sideways based on the borehole shape.', 'Ideally, the gauge pad may ride without significantly wearing the gauge pad or damaging the borehole.', 'BRIEF DESCRIPTION', 'A downhole drilling apparatus may comprise a rotatable body with various cutting elements connected thereto.', 'Specifically, the body may comprise one or more cutting elements radially protruding therefrom, one or more cutting elements radially extendable therefrom, and one or more cutting elements revolvable relative thereto about a common axis with the body.', 'In operation, when the body is rotated, the radially protruding cutting elements may bore a generally cylindrical borehole within an earthen formation.', "The radially extendable cutting elements may be extended during specific portions of the body's rotation to degrade certain areas of an inner wall of the borehole.", 'By so doing, the borehole may be transformed into a non-cylindrical shape.', 'The revolvable cutting elements may extend radially farther from the axis than the protruding cutting elements and from the extendable cutting elements when they are fully retracted.', 'However, when fully extended, the extendable cutting elements may extend radially farther than the revolvable cutting elements.', 'In such a configuration, the revolvable cutting elements may be allowed to slide against the non-cylindrical borehole shape while they are freely rotating.', "This free rotation may result in minimal disturbance to the borehole's cross-sectional shape during sliding.", 'The sliding may cause the body to be urged laterally to form a curve in the borehole at it is being formed.', 'When it is desirable for the apparatus to form a straight borehole, or if the apparatus gets stuck in the borehole, a clutch or locking device may restrain the revolvable cutting elements from revolving relative to the body.', 'When restrained in such a manner, the revolvable cutting elements may ream the borehole back to a cylindrical shape to remove the lateral urging.', 'In most cases, the extendable cutting elements will be retracted during this reaming process.', 'DRAWINGS\n \nFIG.', '1\n is an orthogonal view of an embodiment of a subterranean drilling operation.\n \nFIG.', '2\n is a perspective view of an embodiment of a drilling apparatus that may form part of a subterranean drilling operation.\n \nFIG.', '3\n is a perspective view of another embodiment of a drilling apparatus.', 'FIG.', '4-1\n is a perspective view of an embodiment of a sleeve and clutch device that may form part of a drilling apparatus.', 'FIG.', '4-2\n is a perspective view of an embodiment of a sleeve and locking device that may form part of a drilling apparatus.', 'DETAILED DESCRIPTION\n \nReferring now to the figures, \nFIG.', '1\n shows an embodiment of a subterranean drilling operation of the type commonly used to form boreholes in the earth.', 'As part of this drilling operation, a drilling apparatus \n111\n may be suspended from a derrick \n112\n by a drill string \n114\n into a borehole \n118\n formed in a subterranean formation \n116\n.', 'While a land-based derrick \n112\n is depicted, comparable water-based structures are also common.', 'Such a drill string \n114\n may be formed from a plurality of drill pipe sections fastened together end-to-end, as shown, or, alternately, a flexible tubing.', 'FIG.', '2\n shows an embodiment of a downhole drilling apparatus \n211\n that may form part of a subterranean drilling operation as just described.', 'This drilling apparatus \n211\n may comprise an elongated body \n220\n, roughly cylindrical in shape and rotatable about an axis \n221\n passing longitudinally therethrough.', 'The body \n220\n may comprise an attachment mechanism \n222\n disposed on one axial end thereof, allowing for the body \n220\n to be fastened to a distal end of a drill string as described previously.', 'Opposite from the attachment mechanism \n222\n, the body \n220\n may comprise a plurality of bit blades \n223\n projecting both axially from one end of the body \n220\n and radially from a side thereof.', 'These bit blades \n223\n may be spaced radially about the axis \n221\n and converge thereabout at the end.', 'A plurality of fixed cutting elements \n224\n may be secured to each of the bit blades \n223\n such that they protrude from leading edges of each.', 'The fixed cutting elements \n224\n may be formed of sufficiently tough materials to engage and degrade a subterranean formation, while the body \n220\n is rotated about the axis \n221\n, to form a borehole therein.', 'Due to their static positioning relative to the axis \n221\n, these fixed cutting elements \n224\n may form a generally cylindrical borehole.', 'The body \n220\n may also comprise extendable cutting elements \n225\n that may be selectively extended radially from the body \n220\n to engage sections of the subterranean formation forming an inner wall of the borehole.', "If extended during only a portion of a full rotation of the body \n220\n and retracted for a remainder thereof, such extendable cutting elements \n225\n may transform the borehole's cylindrical nature and replace it with a cross-sectional shape comprising two distinct radii.", 'In the embodiment shown, the extendable cutting elements \n225\n are secured to an exposed end of a translatable piston \n226\n that may extend or retract from a side of the body \n220\n via hydraulic pressure.', 'However, any number of other mechanisms capable of producing a similar extension could also be used.', 'As also shown, the piston \n226\n and extendable cutting elements \n225\n may be aligned with one of the bit blades \n223\n such that downhole fluids, often used in drilling operations, may flow freely past both the fixed cutting elements \n224\n and extendable cutting elements \n225\n in spaces in between the bit blades \n223\n.', 'However, such alignment is not essential as blade count and spacing can differ.', 'Revolvable cutting elements \n229\n may be secured to a hollow sleeve \n227\n encompassing the body \n220\n and free to rotate about the axis \n221\n relative to the body \n220\n.', 'These revolvable cutting elements \n229\n may extend radially farther from the axis \n221\n than the fixed cutting elements \n224\n described previously.', 'To provide for this radial extension, while still allowing downhole fluids to pass, a plurality of revolvable blades \n228\n, spaced radially about the axis \n221\n, may project radially from the sleeve \n227\n.', 'The revolvable cutting elements \n229\n may be secured to the revolvable blades \n228\n such that they protrude from leading edges of each.', 'In the embodiment shown, a single specimen of the revolvable cutting elements \n229\n is secured to each of the blades, however other arrangements are also possible.', 'With the revolvable cutting elements \n229\n extending radially farther than the fixed cutting elements \n224\n, the revolvable cutting elements \n229\n may not fit within a cylindrically-shaped borehole formed by just the fixed cutting elements \n224\n.', 'As such, the extendable cutting elements \n225\n may need to be extended in certain areas to expand an internal radius of the borehole.', 'Specifically, while the revolvable cutting elements \n229\n may extend radially farther from the axis \n221\n than these extendable cutting elements \n225\n when they are retracted, to expand the internal radius of the borehole such that the revolvable cutting elements \n229\n may pass through, the extendable cutting elements \n225\n may need to be extended radially beyond the revolvable cutting elements \n229\n when extended.', 'The revolvable cutting elements \n229\n may then slide against an inner wall of the borehole whereby what remains of the original cylindrically-shaped borehole may urge the apparatus into the open space created by the extendable cutting elements \n225\n.', 'This urging may cause a drilling operation to veer off its previously set course and create a curve in the borehole as it is formed.', "If allowed to freely rotate relative to the body \n220\n, the revolvable cutting elements \n229\n may cause minimal disturbance to the borehole's new non-cylindrical shape.", 'By gripping the inner wall of the borehole, the revolvable cutting elements \n229\n may tend to remain rotationally stationary with respect to the borehole while they slide.', "Such rotationally-stationary sliding may further protect the borehole's non-cylindrical shape from damage, which damage could reduce the lateral urgings that cause steering.", 'To drill straight, without the lateral urging or curving borehole, rotation of the sleeve \n227\n and revolvable cutting elements \n229\n relative to the body \n220\n may be restrained such that they all rotate in unison.', 'While rotating in unison, torque acting on the body \n220\n may cause the revolvable cutting elements \n229\n to engage the inner wall of the borehole and ream the borehole to a diameter that clears non-cylindricality therefrom.', 'The extendable cutting elements \n225\n may be retracted closer to the axis \n221\n than the revolvable cutting elements \n229\n during this process so as not to interfere.', 'With the borehole once again comprising a generally cylindrical shape the boring operation may drill straight.', 'It is not uncommon for a drilling apparatus to become stuck in a borehole.', 'This may be caused by the formation collapsing in on the apparatus or for other reasons.', 'It is also possible that some dysfunction, such as cutting element damage, pressure loss or actuator failure, could inhibit the extendable cutting elements \n225\n from extending completely.', 'If the body \n220\n were to become stuck in a borehole or the extendable cutting elements \n225\n failed to extend completely, a similar process of restraining relative rotation between the revolvable cutting elements \n229\n and the body \n220\n may be employed.', 'In this arrangement, reaming by the revolvable cutting elements \n229\n of the borehole may free the body \n220\n of the apparatus and allow it to drill straight.\n \nFIG.', '3\n shows another embodiment of a downhole drilling apparatus \n311\n.', 'In this embodiment, revolvable blades \n328\n, projecting radially from a sleeve \n327\n, may slope away from an axis \n321\n as they recede from bit blades \n323\n projecting axially and radially from a body \n320\n.', 'A plurality of revolvable cutting elements \n329\n, as opposed to the single cutting element described earlier, may be secured to leading edges of each of the revolvable blades \n328\n.', 'As each of the revolvable blades \n328\n slopes away from the axis \n321\n, each of the individual revolvable cutting elements \n329\n may extend radially farther from the axis \n321\n.', 'Furthermore, these revolvable cutting elements \n329\n may be staggered such that they are positioned at varied axial distances from one another.', 'This axial staggering may prevent a group of the revolvable cutting elements \n329\n from falling into grooves formed by other revolvable cutting elements \n329\n, leading to an uneven borehole inner wall.', 'With sufficient staggering, this unevenness may be avoided regardless of what rate of penetration the apparatus \n311\n is passing through the borehole.\n \nFIG.', '4-1\n shows an embodiment of a sleeve \n427\n-\n1\n that may form part of a subterranean drilling apparatus as just described.', 'The sleeve \n427\n-\n1\n may comprise a plurality of revolvable blades \n428\n-\n1\n projecting radially therefrom with a plurality of revolvable cutting elements \n429\n-\n1\n secured to and protruding from leading edges of each.', 'In this embodiment, the revolvable cutting elements \n429\n-\n1\n comprise generally pointed distal geometries.', 'It is believed that, in certain arrangements, such three-dimensional distal geometries may aid in minimizing disturbance to a borehole cross-sectional shape while the sleeve \n427\n-\n1\n is freely rotating about a body (not shown) but still allow the revolvable cutting elements \n429\n-\n1\n to ream out non-cylindrical sections of such a borehole shape when rotationally fixed.', 'A clutch device \n440\n-\n1\n may be axially translatable relative to the sleeve \n427\n-\n1\n via hydraulic, pneumatic, mechanic or any other means.', 'When translated, at least one surface of the clutch device \n440\n-\n1\n may engage a surface \n441\n-\n1\n of the sleeve \n427\n-\n1\n to restrict it from free rotation.', 'It is believed that such a clutch device \n440\n-\n1\n may hinder rotation of the sleeve \n427\n-\n1\n while permitting some rotation if desirable to reduce strain on the drilling apparatus.', 'FIG.', '4-2\n shows another embodiment of revolvable cutting elements \n429\n-\n2\n secured to a sleeve \n427\n-\n2\n.', 'In this embodiment, the revolvable cutting elements \n429\n-\n2\n each comprise a three-dimensional blade geometry.', 'In addition, a locking device \n440\n-\n2\n comprising a plurality of teeth \n442\n-\n2\n protruding therefrom may be axially translated relative to the sleeve \n427\n-\n2\n.', 'The teeth \n442\n-\n2\n of the locking device \n440\n-\n2\n may engage mating surfaces \n441\n-\n2\n of the sleeve \n427\n-\n2\n to rotationally fix the sleeve \n427\n-\n2\n to the locking device \n440\n-\n2\n.', 'While a variety of different shapes would be suitable for their purpose, in the embodiment shown, the teeth \n442\n-\n2\n and mating surfaces \n441\n-\n2\n comprise geometries such that their interaction also rotationally align the sleeve \n427\n-\n2\n relative to the locking device \n440\n-\n2\n.', 'Whereas this discussion has revolved around the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present disclosure.'] | ['1.', 'A downhole drilling assembly, comprising:\na body rotatable about an axis;\none or more first cutting elements radially protruding from the body;\none or more second cutting elements radially extendable from the body;\none or more third cutting elements revolvable about the axis, relative to the body; and\na clutch or locking device capable of rotationally fixing the third cutting elements to the body, wherein the one or more third cutting elements are freely revolvable about the axis when not fixed by the clutch or locking device.', '2.', 'The downhole drilling assembly of claim 1, wherein the one or more third cutting elements are secured to a sleeve encompassing the body and revolvable about the axis, relative to the body.', '3.', 'The downhole drilling assembly of claim 2, further comprising one or more blades projecting radially from the sleeve and sloping away from the axis at increasing distances from the one or more first cutting elements.\n\n\n\n\n\n\n4.', 'The downhole drilling assembly of claim 2, further comprising one or more blades projecting radially from the sleeve; wherein a single third cutting element is secured to each of the blades.', '5.', 'The downhole drilling assembly of claim 1, wherein the one or more third cutting elements extend radially farther from the axis than the one or more first cutting elements.', '6.', 'The downhole drilling assembly of claim 1, wherein the one or more third cutting elements extend radially farther from the axis than the one or more second cutting elements when the one or more second cutting elements are fully retracted, and the one or more second cutting elements extend radially farther from the axis than the third cutting elements when they fully extended.', '7.', 'The downhole drilling assembly of claim 1, wherein the one or more third cutting elements are axially staggered.', '8.', 'The downhole drilling assembly of claim 1, wherein the one or more third cutting elements comprise three-dimensional distal geometries.', '9.', 'The downhole drilling assembly of claim 1, wherein the one or more third cutting elements are secured to a sleeve and the clutch or locking device is capable of engaging the sleeve with one or more mating teeth.', '10.', 'The downhole drilling assembly of claim 9, wherein the teeth comprise a geometry such that mating of the teeth rotationally aligns the sleeve relative to the body.', '11.', 'A method of downhole drilling, comprising:\nrotating a body about an axis;\nboring a generally cylindrical hole within a formation with one or more first cutting elements radially protruding from the body;\ntransforming the hole to a non-cylindrical shape by extending one or more second cutting elements radially from the body;\nallowing one or more third cutting elements to freely revolve about the axis relative to the body; and\nsliding the one or more third cutting elements against the non-cylindrical hole shape while they are freely revolving relative to the body, wherein the one or more third cutting elements are configured to remain rotationally stationary with respect to the non-cylindrical hole shape while sliding.\n\n\n\n\n\n\n12.', 'The method of downhole drilling of claim 11, further comprising extending the one or more second cutting elements radially farther from the axis than the one or more third cutting elements while they are revolving.\n\n\n\n\n\n\n13.', 'The method of downhole drilling of claim 11, further comprising:\nrestraining the one or more third cutting elements from revolving about the axis relative to the body; and\nreaming the hole back to a cylindrical shape with the one or more third cutting elements.', '14.', 'The method of downhole drilling of claim 13, further comprising retracting the one or more second cutting elements radially closer to the axis than the one or more third cutting elements while they are restrained from revolving.\n\n\n\n\n\n\n15.', 'The method of downhole drilling of claim 13, wherein restraining the one or more third cutting elements comprises aligning them relative to the body.', '16.', 'The method of downhole drilling of claim 13, wherein restraining the one or more third cutting elements comprises engaging a clutch or locking device capable of rotationally fixing the one or more third cutting elements relative to the body.', '17.', 'The method of downhole drilling of claim 11, wherein the one or more third cutting elements comprise three-dimensional distal geometries.', '18.', 'The method of downhole drilling of claim 11, wherein the one or more third cutting elements are axially staggered on a sleeve about the body.', '19.', 'The method of downhole drilling of claim 11, wherein extending the one or more second cutting elements radially from the body comprises translating a piston radially from the body, wherein the one or more second cutting elements are secured to the piston.'] | ['FIG.', '1 is an orthogonal view of an embodiment of a subterranean drilling operation.; FIG.', '2 is a perspective view of an embodiment of a drilling apparatus that may form part of a subterranean drilling operation.; FIG.', '3 is a perspective view of another embodiment of a drilling apparatus.; FIG.', '4-1 is a perspective view of an embodiment of a sleeve and clutch device that may form part of a drilling apparatus.; FIG.', '4-2 is a perspective view of an embodiment of a sleeve and locking device that may form part of a drilling apparatus.', '; FIG.', '2 shows an embodiment of a downhole drilling apparatus 211 that may form part of a subterranean drilling operation as just described.', 'This drilling apparatus 211 may comprise an elongated body 220, roughly cylindrical in shape and rotatable about an axis 221 passing longitudinally therethrough.', 'The body 220 may comprise an attachment mechanism 222 disposed on one axial end thereof, allowing for the body 220 to be fastened to a distal end of a drill string as described previously.; FIG.', '3 shows another embodiment of a downhole drilling apparatus 311.', 'In this embodiment, revolvable blades 328, projecting radially from a sleeve 327, may slope away from an axis 321 as they recede from bit blades 323 projecting axially and radially from a body 320.', 'A plurality of revolvable cutting elements 329, as opposed to the single cutting element described earlier, may be secured to leading edges of each of the revolvable blades 328.', 'As each of the revolvable blades 328 slopes away from the axis 321, each of the individual revolvable cutting elements 329 may extend radially farther from the axis 321.', 'Furthermore, these revolvable cutting elements 329 may be staggered such that they are positioned at varied axial distances from one another.', 'This axial staggering may prevent a group of the revolvable cutting elements 329 from falling into grooves formed by other revolvable cutting elements 329, leading to an uneven borehole inner wall.', 'With sufficient staggering, this unevenness may be avoided regardless of what rate of penetration the apparatus 311 is passing through the borehole.; FIG.', '4-1 shows an embodiment of a sleeve 427-1 that may form part of a subterranean drilling apparatus as just described.', 'The sleeve 427-1 may comprise a plurality of revolvable blades 428-1 projecting radially therefrom with a plurality of revolvable cutting elements 429-1 secured to and protruding from leading edges of each.', 'In this embodiment, the revolvable cutting elements 429-1 comprise generally pointed distal geometries.', 'It is believed that, in certain arrangements, such three-dimensional distal geometries may aid in minimizing disturbance to a borehole cross-sectional shape while the sleeve 427-1 is freely rotating about a body (not shown) but still allow the revolvable cutting elements 429-1 to ream out non-cylindrical sections of such a borehole shape when rotationally fixed.; FIG.', '4-2 shows another embodiment of revolvable cutting elements 429-2 secured to a sleeve 427-2.', 'In this embodiment, the revolvable cutting elements 429-2 each comprise a three-dimensional blade geometry.', 'In addition, a locking device 440-2 comprising a plurality of teeth 442-2 protruding therefrom may be axially translated relative to the sleeve 427-2.', 'The teeth 442-2 of the locking device 440-2 may engage mating surfaces 441-2 of the sleeve 427-2 to rotationally fix the sleeve 427-2 to the locking device 440-2.', 'While a variety of different shapes would be suitable for their purpose, in the embodiment shown, the teeth 442-2 and mating surfaces 441-2 comprise geometries such that their interaction also rotationally align the sleeve 427-2 relative to the locking device 440-2.'] |
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US11131182 | Methods for characterizing multi-string cased wells using wide frequency bandwidth signals | Mar 27, 2018 | Yang Liu, Bikash K. Sinha, Smaine Zeroug | SCHLUMBERGER TECHNOLOGY CORPORATION | R. van Kuijk et al., “A Novel Ultrasonic Cased-Hole Imager for Enhanced Cement Evaluation”, This paper was prepared for presentation at the International Petroleum Technology Conference held in Doha, Qatar, Nov. 21-23, 2005. (Year: 2005).; Ekstrom, M. P., “Dispersion Estimation from Borehole Acoustic Arrays Using a Modified Matrix Pencil Algorithm,” Conference Record of the Twenty-Ninth Asilomar Conference on Signals, Systems and Computers, 1995, vol. 1, pp. 449-453.; Lu, C.-C. et al., “A three-dimensional dyadic Green's function for elastic waves in multilayer cylindrical structures”, Journal of Acoustical Society of America, 1995, 98(5), pp. 2825-2835.; Li, J. et al., “Implementing Guided Wave Mode Control by Use of a Phased Transducer Array”, IEEE Transactions on Ultrasonics, Ferroelectrics, and Frequency Control, 2001, 48(3), pp. 761-768.; Kimball, C. V. et al., “Semblance processing of borehole acoustic array data”, Geophysics, 1984, 49(3), pp. 274-281.; Liu, et al., “Acoustic Guided Waves in Cylindrical Solid-Fluid Structures: Modeling with a Sweeping Frequency Finite Element Method and Experimental Validation,” 43rd Annual Review of Progress in Quantitative Nondestructive Evaluation (QNDE), 2016.; Michaels, et al., “Chip excitation of ultrasonic guided waves,” Ultrasonics 53, 2013, pp. 265-270. | 4594691; June 10, 1986; Kimball et al.; 20060262643; November 23, 2006; Blankinship et al.; 20130289881; October 31, 2013; Sinha; 20150198032; July 16, 2015; Sinha et al.; 20150219780; August 6, 2015; Zeroug; 20160061029; March 3, 2016; Hayman | 2016187240; November 2016; WO; WO-2016187240; November 2016; WO | ['Methods are provided for estimating a quality of cement in the annuli of a multi-string wellbore.', 'Wideband acoustic energy signals are generated and detected in the wellbore and are processed to obtain indications of wideband casing-formation phase slowness dispersions in the wellbore.', 'The indications are compared to reference wideband model casing-formation phase slowness dispersions in order to estimate status of cement or lack of cement in the annuli at that location based on the results of the comparison.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThe present document is based on and claims priority to U.S. Provisional Application Ser.', 'No. 62/476,909, filed Mar. 27, 2017, which is incorporated herein by reference in its entirety.', 'TECHNICAL FIELD', 'The subject disclosure relates to well logging in the oil and gas field.', 'More particularly, the subject disclosure relates to methods utilizing acoustic tools for analyzing the quality of cement in the annuli of a doubly cased well.', 'BACKGROUND', 'In developing an oilfield, a wellbore is drilled, and steel casings and cement slurry are placed to ensure structural support, protection from fluid invasion, and to provide zonal isolation.', 'Over the lifespan of a cased borehole, damage to the cement sheath(s) may result from, among other things, improper cementing practices, casing eccentering, and stress fluctuations due to downhole operations such as pressure integrity testing, increased mud weight, casing perforation, stimulation, oil or gas production, and large wellbore temperature variations.', 'In some cases, highly pressurized downhole fluid squeezes through micro-channels within the cement sheath, or through small gaps at one or both of the casing-cement or cement-formation interfaces (micro annulus) facilitating hydraulic communication.', 'The consequences of hydraulic communication include jeopardizing hydrocarbon production efficiency, inducing casing corrosion, or even catastrophic environmental issues resulting from the leakage of toxic fluids.', 'To ensure well integrity and maintain environment-friendly production of hydrocarbons, sonic and ultrasonics have been widely used for nondestructive evaluation and structural health monitoring of the cement annuli.', 'These techniques provide different measurement modalities for well integrity evaluation through the development of various acoustic tools such as Cement Bond Logs (CBLs), Variable Density Logs (VDL—a trademark of Schlumberger), UltraSonic Imager (USI—a trademark of Schlumberger) and Isolation Scanner, etc.', 'CBL data are acquired through a pitch-catch mode of a sonic logging tool with a monopole transducer and two monopole receivers.', 'The low frequency casing extensional modes (10 kHz to 20 kHz) are actuated and the amplitude of the sonic waveforms are used as indicators of the bond quality between cement and outer casing surface.', 'Also, the waveforms are displayed in a VDL format for important qualitative interpretation.', 'The USI tool operates in a pulse-echo mode that excites the casing into the thickness-resonance mode.', 'This resonant frequency (250 kHz to 700 kHz) is dependent on casing thickness while the amplitude decay is dependent on acoustic impedances of the media on either side of the casing.', 'Acoustic impedance can be used to classify the medium as gas, liquid or cement based on a threshold set for acoustic impedance boundaries between these materials.', 'To characterize lightweight, or mud contaminated cements that are of low acoustic impedance, a Flexural Wave Imaging (FWI) technique has been integrated with the pulse-echo measurement.', 'The combined tool, called Isolation Scanner (a trademark of Schlumberger), provides excellent, detailed interpretations of the cement sheath.', 'The FWI measurement employs an oblique incidence technique to actuate the dispersive flexural mode in the casing (AO mode in a plate approximation), for which the attenuation is sensitive to the material behind the casing.', 'Further, FWI yields under certain conditions reflection echoes from the third interface (TIE) that provide further information about the cement sheath and geometry of the hole.', 'Despite all of the success of the aforementioned sonic and ultrasonic measurement tools, the sensitivity of current tools is limited to within the inner cement annulus while leaving the rest of the cement sheath and bonding interfaces uninspected.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'Illustrative embodiments of the present disclosure include generating wide bandwidth excitation signals inside a multi-string cased well, recording waveforms resulting from the wide bandwidth excitation signals, processing the recorded waveforms to generate full spectral slowness dispersion determinations, and comparing the spectral slowness dispersion determinations to reference wideband spectral dispersions for an intact wellbore with well-cemented annuli to identify possible cement degradations in one or more of the annuli of the multi-string cased well and/or possible bonding weaknesses at one or more of the cement-casing or cement-formation interfaces.', 'For purposes of the specification and claims, the term “wideband” or “wide bandwidth” is to be understood as encompassing a bandwidth in which at least the five lowest order slowness dispersion modes of a well-cemented system can be identified.', 'In many cases, and depending upon the geometry of the multi-string cased well, the five lowest order slowness dispersion modes can be identified in a range extending from 5 kHz to 70 kHz.', 'In certain embodiments, the wideband excitation signals are selected to permit at least the six lowest order slowness dispersion modes of a well-cemented system to be identified.', 'In some embodiments, the wideband signals cover a range extending from 5 kHz to 100 kHz, although lower and/or higher frequencies can be encompassed such as, by way of example only, a bandwidth of 500 Hz to 100 kHz.', 'According to one embodiment, a chirp transmitter is used to generate a wideband signal.', 'The chirp transmitter may take the form of a piezoelectric or magnetostrictive transducer or some other type of transducer.', 'In some embodiments, the spectral slowness dispersion determinations are compared to multiple reference wideband spectral dispersions which represent different wellbore scenarios including an intact wellbore with well-cemented annuli and a wellbore with cement degradations in one or more of the annuli of the multi-string cased well and/or possible bonding weaknesses at one or more of the cement-casing or cement-formation interfaces.', 'In some embodiments, in addition to generating wide bandwidth excitation signals at locations along the borehole or wellbore (the terms “borehole”, “hole”, “wellbore”, and “well” being used interchangeably herein), one or more narrowband signals are generated, and resulting waveforms are recorded in order to identify an axial location along the borehole where the wellbore scenario changes, e.g., from well-cemented to not well cemented.', 'In this manner, a cement to fluid transition may be identified.', 'Additional aspects, embodiments, objects and advantages of the disclosed methods may be understood with reference to the following detailed description taken in conjunction with the provided drawings.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a schematic diagram showing a cross-section of a fluid-filled well-bonded double-cased borehole.\n \nFIG.', '2\n is a diagram showing slowness dispersion curves in an intact double-cased hole with a well-cemented water-steel-cement-steel-cement-formation configuration.', 'The lines and asterisks indicate the skeletal dispersion curves obtained respectively from mode search and synthetic modeling algorithms.\n \nFIG.', '3\n is a schematic cross-sectional diagram of a double-cased hole with a water-steel-water-steel-cement-formation configuration.\n \nFIG.', '4\n is a diagram showing slowness dispersion curves in a double-cased hole of the configuration shown in \nFIG.', '3\n, with the skeleton modes of the \nFIG.', '3\n configuration shown as dashed (dash-dot-dash) lines and the dispersion curves shown with triangles.', 'These are overlaid with skeleton modes shown in solid lines and dispersion curves shown with circles for an intact double-cased hole.\n \nFIG.', '5\n is a magnified view of the slowness dispersion curves in zone 1 (Z1) of \nFIG.', '4\n.\n \nFIG.', '6\n is a schematic cross-section of a double-cased hole with a water-steel-cement-steel-water-formation configuration.\n \nFIG.', '7\n is a diagram showing slowness dispersion curves in a double-cased hole with the configuration shown in \nFIG.', '6\n shown with asterisks and the dispersion curves of the intact double-cased borehole shown with circles.', 'The skeleton modes are marked as solid lines.', 'FIG.', '8\n is a schematic cross-section of a double-cased hole with a water-steel-water-steel-water-formation configuration.\n \nFIG.', '9\n is a diagram showing slowness dispersion curves in a double-cased hole with the configuration of \nFIG.', '8\n shown with dots and the dispersion curves of the double-cased borehole of \nFIG.', '3\n shown with circles.', 'The skeleton modes are marked as solid lines.', 'FIG.', '10\n is a schematic cross-section of a double-cased hole with a water-steel-water-steel-degraded cement-formation configuration.\n \nFIG.', '11\n is a diagram showing slowness dispersion curves in a double-cased hole with the configuration of \nFIG.', '10\n shown with + signs, the dispersion curves for the configuration of \nFIG.', '8\n shown with triangles and the dispersion curves for the configuration of \nFIG.', '3\n shown with circles.', 'The skeleton modes are marked as solid and dashed (dash-dot-dash) lines.', 'FIG.', '12\n is a schematic cross-section of a double-cased hole with 4\nth \ninterface debonding.\n \nFIG.', '13\n is a diagram showing slowness dispersion curves in a double-cased wellbore with 4\nth \ninterface debonding shown with diamonds and the dispersion curves of an intact double-cased borehole shown with dots.', "The skeleton modes are marked as lines and with x's.\n \nFIG.", '14\n is a schematic cross-section of a double-cased hole with 5\nth \ninterface debonding.\n \nFIG.', '15\n is a diagram showing slowness dispersion curves in a double-cased wellbore with 5\nth \ninterface debonding shown with triangles and the skeleton modes for the \nFIG.', '14\n configuration shown in dashed (dash-dot-dash) lines.', 'These are overlaid with skeleton modes shown in solid lines and dispersion curves shown with dots for an intact double-cased hole.\n \nFIG.', '16\n is a flowchart of a method of wellbore damage characterization.', 'FIGS.', '17\na \nand 17\nb \nare respectively a cross-sectional diagram of a multi-element comb-like phased array transducer used to excite a selected wave mode in a borehole, and a schematic view of a pressure field resulting from the firing of the phased array transducer.\n \nFIG.', '18\n is a schematic axial cross-sectional diagram of a double-cased hole with axial cement-fluid transition zone at annuli A and B.\n \nFIG.', '19\n is a diagram showing slowness dispersion curves in a double-cased wellbore with a cement-fluid transition zone as shown in \nFIG.', '18\n.', 'The circles and triangular dots are dispersion curves respectively extracted at Pos 1 and Pos 3 shown in \nFIG.', '18\n, while the asterisks are those obtained at the cement-fluid transition region Pos 2 of \nFIG.', '18\n.', 'The solid lines denote the skeleton modes for the wellbore with different configurations.\n \nFIGS.', '20\na\n-20\nf \nare sample normalized displacement wave structures for a steel-cement-steel triple layer cylinder.', 'FIGS.', '21\na \nand 21\nb \nare displacement and stress modal shapes of S2 mode at 50 kHz in a steel-cement-steel triple layer cylinder.\n \nFIG.', '22\n are time domain signal waveforms for the S2 mode at 50 kHz.', 'The portions of the waveforms that are within the dashed oval indicate the reflection signals from the cement-fluid transition.\n \nFIG.', '23\n is a flowchart of another method wellbore damage characterization.', 'FIGS.', '24\na \nand 24\nb \nare schematic cross-sectional diagrams of 50% eccentered double strings immersed in infinite fluid with a free double string, and a cemented double string, respectively.\n \nFIG.', '25\n is a diagram showing slowness dispersion curves for concentric and 50% eccentered cemented double strings.', 'The solid dots and open circles, respectively, indicate concentric and 50% eccentered results.\n \nFIG.', '26\n is a diagram showing slowness dispersion curves for free and cemented double strings with identical eccentricity (50%).', 'The circles and dots, respectively, represents for experimental and numerical dispersions of cemented double strings, while the triangles indicate those extracted from a free double string.', 'DETAILED DESCRIPTION', 'The particulars shown herein are by way of example and for purposes of illustrative discussion of the examples of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure.', 'In this regard, no attempt is made to show details in more detail than is necessary, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice.', 'Furthermore, like reference numbers and designations in the various drawings indicate like elements.', 'A cased borehole may be viewed as a multilayered cylindrical waveguide extending to infinity along an axis (z) of a borehole.', 'The cased borehole system is usually composed of steel casings and cement annuli that are embedded in what may be considered an infinite formation.', 'Drilling fluid is considered to fill the inside of the innermost steel casing.', 'FIG.', '1\n shows the cross-section of a well bonded, double-cased borehole and a coordinate system.', 'The cylinders from the center to the outside of the cross-section are the fluid column \n10\n, inner casing \n20\n, cement annulus A \n30\n, outer casing \n40\n, cement annulus B \n50\n, and infinite formation media \n60\n, respectively.', 'The material properties and geometry parameters (including radii r, shear and compressional velocities V\ns \nand V\np\n, and densities ρ for the modeling are provided in Table I.\n \n \n \n \n \n \n \n \nTABLE I\n \n \n \n \n \n \n \n \nMaterial properties and input parameters for modeling of cased borehole\n \n \n \n \n \n \n \n \n \n \n \nDimensions\n \nMaterial properties\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nr\n3\n \n \nr\n5\n \nρ\ni\n \nV\nP\n \nV\ns\n \n \n \n \nr\n1 \n(mm)\n \nr\n2 \n(mm)\n \n(mm)\n \nr\n4 \n(mm)\n \n(mm)\n \n(kg/m\n3\n)\n \n(m/s)\n \n(', 'kg/m\n3\n)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nFluid\n \n78.537\n \n88.9\n \n107.95\n \n122.237\n \n152.4\n \n1000\n \n1500.00\n \n0\n \n \n \nSteel\n \n \n \n \n \n \n7392\n \n5959.09\n \n3229.39\n \n \n \nCement\n \n \n \n \n \n \n1900\n \n3625.00\n \n2015.00\n \n \n \nFormation\n \n \n \n \n \n \n2090\n \n2634.00\n \n1736.20\n \n \n \n \n \n \n \n \n \n The bonds between the casings and cement annuli are denoted as the 2\nnd\n, 3\nrd\n, 4\nth\n, and 5\nth \ninterfaces, respectively.', 'As will be discussed hereinafter, damaged borehole cases considered include the degradation of the cement annuli A and B, with one or more of these annuli being replaced by drilling/formation fluid or gas, and the weak bonding and debonding that could occur in the casing-cement interfaces or the cement-formation interface.', 'In modeling the described system, a modeled acoustic logging tool using a specified transmitter such as a monopole source using a chirp excitation sweep from 0 to 100 kHz (which is optionally conducted over several hundreds of microseconds) is considered concentrically placed inside a model borehole.', 'Resulting waveforms are obtained with a specified receiver array where the axial array receivers are placed at the same radial position as the transmitter and mounted along different azimuthal positions.', 'A transmitter to first receiver spacing is specified (e.g., one foot) as is a specified inter-receiver spacing (e.g., 1 inch).', 'An array of a specified number of axial receivers (e.g., 100 receivers) are used to collect (synthetic) waveforms with an specified recording time (e.g., 6 milliseconds).', 'A transient dynamic acoustic-solid interaction approach is applied for the modeling.', 'The waveforms received by the receivers are stacked and processed with a modified matrix pencil method in order to generate slowness dispersions.', 'See, e.g., Ekstrom, M. P., “Dispersion Estimation from Borehole Acoustic Arrays using a Modified Matrix Pencil Algorithm”, 29\nth \nAsilomar Conference on Signals, Systems and Computers (1995); Kimball, C. V., and Marzetta, T. L., “Semblance Processing of Borehole Acoustic Array Data”, Geophysics, Vol. 49, No. 3, p. 274-281 (1986), and U.S. Pat.', 'No. 4,594,691 to Kimball et al.\n \nFIG.', '2\n shows the slowness dispersion curves for the intact double-cased wellbore shown in \nFIG.', '1\n with the water or mud filled borehole, an inner steel casing, a well-cemented first annulus, a second steel casing, a well-cemented second annulus, and then the formation (which is referred to herein as a W/S/C/S/C/F configuration).', 'The “skeleton” or most solid portion of the cased wellbore of \nFIG.', '1\n is the SCS (steel-cement-steel) triple layer cylinder.', 'Corresponding skeleton dispersion curves (in solid lines identified through a mode search, and in asterisks identified by a Chirp Sweeping Finite Element Modeling (CSFEM) algorithm—see, Liu, Y. et al., “Guided Waves in Fluid-Elastic Concentric and Non-Concentric Cylindrical Structures: Theoretical and Experimental Investigations”, 43\nrd \nAnnual Review of Progress in Quantitative Nondestructive Evaluation (QNDE) (2016) are labeled S1-S6, while guided wave modalities indicated by labels 1-16 are also observed.', 'Skeleton dispersion curves S1-S6 are seen to have their genesis at different frequencies, with S1 starting at about 0 kHz, S2 starting at about 9 kHz, S3 starting at about 12 kHz, S4 starting at about 26 kHz, S5 starting at about 60 kHz, and skeleton dispersion curve S6 starting slightly above 90 kHz.', 'According to one aspect, skeleton dispersion curves S1-S5 for a SCS skeleton may be well identified in the frequency range of 5 kHz-70 kHz.', 'According to another aspect, skeleton dispersion curves S1-S6 for a SCS skeleton may be well identified in the frequency range of 5 kHz-100 kHz.', 'It should be appreciated that the frequency range may change depending upon the diameters of the steel casings, with larger casings causing the frequencies to shift toward lower frequencies and with smaller casing causing the frequencies to shift toward higher frequencies.', 'Turning now to \nFIG.', '3\n, a double-cased wellbore with water or mud \n110\n, inner casing \n120\n, water annulus A \n130\n, outer casing \n140\n, cement annulus B \n150\n, and infinite formation media \n160\n (W/S/W/S/C/F configuration) is shown.', 'FIG.', '4\n shows the CSFEM slowness dispersion curves (triangles) for a double-cased hole with W/S/W/S/C/F configuration and the associated skeletal modes.', 'The dispersion curves of an intact double-cased hole (W/S/C/S/C/F) is also shown (circles) in \nFIG.', '4\n as a baseline.', 'It is observed that the skeleton of the geometry transforms from a SCS triple layer cylinder to just separate inner and outer casings due to the presence of the water annulus \n130\n.', 'In \nFIG.', '4\n, the skeleton modes for the intact wellbore are labeled as S1 to S6 (shown as dash-dot-dash lines), while those for the damaged wellbore are labeled as S7 to S10 (S7 and S8 for the inner casing, and S9 and S10 for the outer casing).', 'Additional casing-fluid interaction modes exist in a W/S/W/S/C/F configuration when compared with that of an intact double-cased hole, as respectively, denoted by the circles and dots in \nFIG.', '4\n.', 'The extra casing-fluid interaction modes are due to the additional solid-fluid interfaces introduced by the presence of water in annulus A \n130\n.', 'A magnified view of an identified region of \nFIG.', '3\n (Z1 region) indicates that the slowness of a W/S/W/S/C/F configuration (labeled as “1” to “6” in \nFIG.', '5\n) increases compared with these of an intact wellbore (label as “7” to “11” in \nFIG.', '5\n).', 'The slowness increments are due to the softening effect of the whole geometry when cement is replaced by fluid in annulus A.', 'The skeletal transformation renders structural changes in dispersion curves, which includes modal branches S3, S4, S5, and S6 which are present in the well-cemented configuration of \nFIG.', '1\n being absent in the W/S/W/S/C/F configuration of \nFIG.', '3\n.', 'Hence, these features can be used to characterize cement annulus A.', 'Thus, according to one aspect, the presence of low-slowness branches S3, S5, and S6 (which may also be referred to as the SCS triple layer cylinder cut-off modes) indicates that the inner annulus is cemented.', 'As will be discussed hereinafter, this remains true when the outer annulus B is filled with lightweight cement or fluid.', 'In case annulus B is filled with very stiff cement (such that there is an extremely large stiffness contrast between the cement and the formation), the skeleton may be effectively transformed into a SCSC four layer cylinder which could change the slowness skeletal branches as discussed hereinafter.', 'FIG.', '6\n shows a double-cased wellbore with water or mud \n210\n, inner casing \n220\n, cement annulus A \n230\n, outer casing \n240\n, water annulus B \n250\n, and infinite formation media \n260\n (W/S/C/S/W/F configuration).', 'FIG.', '7\n shows the dispersion curves for the wellbore configuration of \nFIG.', '6\n as asterisks contrasted to the well-cemented W/S/C/S/C/F geometry of \nFIG.', '1\n in circles.', 'The skeletal dispersion curves for this geometry appear to be the same as the skeleton of the intact wellbore and are labeled by S1 to S6 in \nFIG.', '7\n.', 'With the same skeleton, it should be appreciated that the differences between the two cases are localized at low frequency ranges around what may be referred to as the casing-fluid interaction modes.', 'As can be seen in \nFIG.', '7\n, the slowness dispersions of these modal branches (1 to 3 compared to 4 to 6) experience increments due to the softening effect arising from removing the cement in annulus B \n250\n.', 'There are barely any changes at high frequencies between the two cases.', 'Thus, according to one aspect, when an S/C/S skeleton is present, the additional presence at low frequencies of increases in the slownesses associated with the casing-fluid interaction modes (relative to the slownesses for the well-cemented arrangement of \nFIG.', '1\n) indicates that the inner annulus is cemented and the outer annulus is fluid-filled.\n \nFIG.', '8\n presents a double-cased wellbore with water or mud \n310\n, inner casing \n320\n, water annulus A \n330\n, outer casing \n340\n, water annulus B \n350\n, and infinite formation media \n360\n (W/S/W/S/W/F configuration).', 'The skeleton of the W/S/W/S/W/F configuration is the same as that of a W/S/W/S/C/F double-cased wellbore (\nFIG.', '3\n); i.e., with separate inner and outer casings.', 'The resulting skeletal modes are labeled as S1 to S4 in \nFIG.', '9\n.', 'In addition, the slowness dispersions for the W/S/W/S/W/F double-cased hole are similar to these of a W/S/W/S/C/F configuration, except for the low frequency casing-fluid interaction regions which are changed due to the stiffness variations.', 'This is seen by the slowness dispersion curves shown in \nFIG.', '9\n, while the dots and circles denote the modalities of W/S/W/S/W/F and W/S/W/S/C/F configurations, respectively.', 'The skeletal and fluid resonant modes are identical for the two configurations, while the casing-fluid interaction modes for the W/S/W/S/W/F configuration (labeled as 1 to 4) exhibits higher slownesses compared with these of an intact wellbore (labeled as 5 to 8) due to the softening effect of the water in annulus B.\n \nThus, according to one aspect, with both annuli being fluid-filled, not only are the casing cut-off modes associated with the S/C/S skeleton missing, but there is an increase in the slowness associated with the casing-fluid interaction modes present at low frequencies (relative to a well-cemented second annulus).', 'Besides the possibility of having water or mud in one or both annuli of the double-cased wellbore, it is possible that one or both of the annuli may have degraded cement (dC) which can occur when one or both of the annuli are filled with fluid mixed with cement.', 'The effective mechanical properties of the degraded cement are between a healthy cement and a fluid.', 'FIG.', '10\n presents a double-cased wellbore with water or mud \n410\n, inner casing \n420\n, water annulus A \n430\n, outer casing \n440\n, degraded cement annulus B \n450\n, and an infinite formation media \n460\n (W/S/W/S/dC/F configuration).', 'The slowness dispersion curves for the W/S/W/S/dC/F configuration are shown in \nFIG.', '11\n, where plus signs (+) denote the modal curves of the wellbore with the W/S/W/S/dC/F configuration and where the circles and triangles, respectively, indicate the slowness dispersion curves of the W/S/W/S/W/F and W/S/W/S/C/F configurations for comparison purposes.', 'These three configurations contain the same skeleton; separate inner and outer casings, whose modal dispersions are labeled as S1 to S4 with the inner casing model dispersion shown as a solid line and the outer casing modal dispersion shown as a dash-dot-dash line.', 'Therefore, the visible dispersion variations for the three configurations occur at the lower frequency casing-fluid interaction regions as indicated by Z1 in \nFIG.', '11\n; particularly between 0 and 30 kHz, and even more particularly between about 4 or 5 kHz and 20 kHz.', 'It is observed that in this region, the W/S/W/S/dC/F configuration (labeled 1 and 2) exhibits higher slowness than that of the W/S/W/S/C/F wellbore (labeled 5 and 6), which is physically reasonable as the presence of degraded cement annulus softens the geometry as a whole.', 'Similarly, the degraded geometry is stiffer than a W/S/W/S/W/F configuration.', 'Therefore, the slowness dispersions of the degraded wellbore present between those of the W/S/W/S/W/F (labeled 3 and 4) and W/S/W/S/C/F (labeled 5 and 6) configurations, as shown in \nFIG.', '11\n.', 'Thus, according to one aspect, with annulus A fluid-filled, the casing-fluid interaction modes occurring at the low frequency range (e.g., below 20 kHz) provide signatures to identify the state of annulus B.', 'Their slowness increases as the content of annulus B softens from a solid cement to water.', 'This suggest a model-based workflow to quantify the slowness change associated with the softening of the content of annulus B.\n \nTurning now to \nFIG.', '12\n, a double-cased wellbore is seen with water or mud \n510\n inside the inner casing \n520\n, cement annulus A \n530\n between the inner casing and the outer casing \n540\n, a cement annulus B \n550\n adjacent to but having a weak bond at the interface \n551\n with the outer casing \n540\n, and an infinite formation media \n560\n (W/S/C/S/b4C/F configuration).', 'In some terminology, it is said that there is a “slip” at the 4\nth \ninterface between outer casing \n540\n and cement annulus \n550\n.', 'In modeling the wellbore of \nFIG.', '12\n, a weak bonding and debonding conditions are generated by assuming zero spring constants at the 4\nth \ninterface.\n \nFIG.', '13\n shows the slowness dispersion curves for the W/S/C/S/b4C/F configuration of \nFIG.', '12\n.', 'The dispersion curves for an intact double-cased hole (as shown in \nFIG.', "2\n) are also presented in the figure as a solid line for the mode search and as x's for the CSFEM as a baseline.", 'The curves for the intact and the 4\nth \ninterfacial debonded wellbores are indicated by dots and diamonds, respectively.', 'It is observed that the 4\nth \ninterfacial debonded double-cased hole of \nFIG.', '12\n shares the same skeleton (SCS) and hence the same skeletal modes with the intact wellbore which are labeled by S1 to S6.', 'The invariance of skeletal modes indicates that no structural change should occur in the wellbore dispersitivity.', 'On the other hand, it is observed that the lower frequency casing-fluid interaction modes (between about 5 kHz and 30 kHz) of the W/S/C/S/b4C/F configuration (labeled 1 to 3) exhibit mild increments in slowness dispersions relative to their counterparts of the W/S/C/S/C/F configuration (labeled by 4 to 6), which is due to the mechanical softening by the debonding.', 'In addition, certain casing cut-off modes (seen starting at 40 kHz, 60 kHz, and 67 kHz respectively) appear to be stronger than corresponding cut-off modes of the W/S/C/S/C/F configuration.', 'Thus, according to one aspect, with both annuli cemented, but with a slip/debond at the 4\nth \ninterface, there is sensitivity exhibited in the mild increase in slowness dispersion of the casing-fluid interaction modes at lower frequencies, and an increase in the strength of the casing cut-off modes at higher frequencies.\n \nFIG.', '14\n illustrates a double-cased wellbore with water or mud \n610\n inside the inner casing \n620\n, a cement annulus A \n630\n between the inner casing and the outer casing \n640\n, a cement annulus B \n650\n between the outer casing \n640\n and an infinite formation media \n660\n, with a weak bond at the (5\nth\n) interface \n661\n of the cement \n650\n and the formation \n660\n (W/S/C/S/Cb5/F configuration).', 'FIG.', '15\n shows the slowness dispersion curves for the W/S/C/S/b4C/F configuration of \nFIG.', '14\n with the triangles indicating the dispersion curves of a double-cased hole with 5\nth \ninterface debonding, and the dots denoting those of an intact wellbore as in \nFIG.', '1\n.', 'A skeletal transformation is observed when considering the geometrical changes from a SCS triple layer cylinder (with skeletal modes shown as curves labeled by S1 to S6) to a SCSC four layer cylinder (with skeletal modes shown as dash-dot-dash curves labeled by S7 to S16) caused by the 5\nth \ninterface debonding.', 'The skeletal transformation induces a structural change in borehole guided characteristics, where feature branches (such as S9, S10, S13, and S15) not found for the SCS triple layer cylinder are presented as indicated by regions Z2 to Z5 in \nFIG.', '15\n.', 'In addition, at least one skeletal mode (S8) has a significantly increased slowness than its counterpart (S2) at higher frequencies (above 35 or 40 kHz).', 'Further, since the stiffness of the geometry as a whole decreases with the presence of 5\nth \ninterfacial debonding, it is expected that slowness increments will occur at lower frequency casing-fluid interaction modes (particularly between 5 kHz and 25 kHz).', 'This prediction is validated by the slowness variations as observed in Z1 in \nFIG.', '15\n.', 'Thus, according to one aspect, with the cement annuli well bonded to the inner casing, but with the outer cement annulis presenting of a slip/debond at the 5\nth \ninterface (between annulus B and the formation) extra skeletal modes (e.g., S9, S10, S13 and S15) associated with a SCSC skeletal structure are found beyond those found with the SCS skeletal structure.', 'In addition, a mild increase in slowness dispersion of the casing-fluid interaction modes at lower frequencies (below 30 kHz) occurs.', 'Also, at least one skeletal mode (S8) has a significantly increased slowness than its counterpart (S2) at higher frequencies (above 35 or 40 kHz).', 'Based on the foregoing, methods are presented for characterizing multi-string cased wells using wide frequency bandwidth signals.', 'In one embodiment shown in \nFIG.', '16\n, at \n701\n, at least one model is obtained for modeling acoustic tools in a geological formation.', 'The model may be a synthetic model such as CSFEM or finite difference time domain (FD-TD), and/or an analytical model.', 'With the embodiment of \nFIG.', '16\n showing the use of a synthetic model, synthetic wideband waveforms generated by a wide bandwidth monopole, dipole or quadrupole source and detected by an axial array of receivers are recorded at \n703\n.', 'The recorded waveforms are processed at \n705\n using a modified matrix pencil method in order to generate at \n707\n synthetic slowness dispersion curves over the wideband.', 'In one embodiment, steps \n701\n-\n707\n are conducted for the W/S/C/S/C/F configuration shown in \nFIG.', '1\n and the results are stored in electronic and/or hard copy format.', 'In another embodiment, steps \n701\n-\n707\n are conducted for multiple configurations (e.g., \nFIGS.', '1, 3, 6, 8, 10, 12 and 14\n) and the results for each configuration is stored in a desired format.', 'In one embodiment, steps \n701\n-\n707\n are conducted for multiple dual string well geometries (e.g., different casing radii, different casing thicknesses, different annulus thicknesses, etc.) for the configuration shown in \nFIG.', '1\n or for multiple configurations and the results are stored in a desired format.', 'In one embodiment, the slowness dispersion curves for each well geometry are separately kept together as a set.', 'At \n711\n, wideband acoustic logging waveforms received at the receivers of a tool (modeled at \n701\n) which was placed downhole in a double-cased wellbore are recorded.', 'At \n713\n, the recorded waveforms are conditioned and stacked, and at \n715\n the conditioned and stacked waveforms are processed to isolate nondispersive and dispersive modes.', 'At \n717\n, slowness dispersion curves are generated using the modified matrix pencil method.', 'At \n721\n, the slowness dispersion curves generated at \n717\n from the data obtained from the borehole tool are compared to the synthetic slowness dispersion curves generated at \n707\n.', 'The comparison may be done utilizing a least squares fit or other comparison techniques and/or visually.', 'In one aspect, skeletal modes are identified in order to determine whether the investigated double-cased wellbore has a S/C/S skeleton as in \nFIGS.', '2, 7 and 13\n, or whether the skeleton of the double-cased wellbore has separated metal casings (e.g., S/W/S) as in \nFIGS.', '4, 9, and 11\n.', 'The skeletal modes may also be identified in order to determine whether the investigated double-cased wellbore has a S/C/S/C skeleton as in \nFIG.', '15\n.', 'In particular, if five (or six) skeletal modes are found at expected frequency ranges and slownesses, it may be concluded that the first and second anuli are well cemented.', 'If more than six skeletal modes are found, it may be concluded that the first annulus is well cemented and the second annulus contains cement but has a weak bond or slip at the 5\nth \ninterface.', 'If only four skeletal modes are found, it may be concluded that the first annulus contains liquid.', 'In addition to the skeletal mode identification, lower frequency (e.g., between about 0 kHz and 30 kHz, or a portion thereof) casing-fluid interaction modes may be identified and compared to one or more of the stored dispersion curve plots by steps \n701\n-\n707\n.', 'If, for a S/C/S skeleton, increases in the slownesses associated with the casing-fluid interaction modes are found (relative to the slownesses for the well-cemented arrangement of \nFIG.', '1\n), it may be concluded that the inner annulus is cemented and the outer annulus is fluid-filled.', 'Of course, if a reference dispersion curve plot for a W/S/C/S/W/F configuration is generated and generated, the comparison at \n721\n will show such a match.', 'Similarly, for a skeleton with the metal casings separated by liquid, the slownesses of the casing-fluid interaction modes may be used to distinguish whether the outer annulus is cemented or not (see \nFIG.', '9\n).', 'Likewise, the slownesses of the casing-fluid interaction modes may be used to identify degraded cement in the second annulus (see \nFIG.', '11\n) or to identify debonding at the 4\nth \ninterface (see \nFIG.', '13\n).', 'It will be appreciated that the method of \nFIG.', '16\n may be conducted at multiple locations in the double-cased well.', 'If the state of the well is uniform along its length, the results obtained by the tool will be relatively static.', 'However, if the state of the well is not uniform along its length, the results obtained by the tool will change.', 'Because the tool has detectors spaced along its length, without further information, it may be difficult to locate precisely the location of transition of the well state.', 'In accordance with another embodiment, additional apparatus and methods are provided for characterizing multi-string cased wells, where the characterization is both radial and axial.', 'A transducer \n800\n useful for helping characterizing multi-string cased wells is seen in cross section in \nFIG.', '17\na \nand the pressure field generated by the transducer is seen in \nFIG.', '17\nb. \n \nMore particularly, a multi-element comb-like transducer \n800\n is designed for selective modal excitation in a cased-borehole geometry.', 'The transducer has a series of circular transducer elements \n881\n, \n882\n, which in one embodiment are of different polarities.', 'The transducer elements can be piezoelectric, magnetostrictive, or electromagnetic.', 'As seen in \nFIG.', '17\na\n, the transducer \n800\n has a pitch denoted by L, and the transducer elements \n881\n, \n882\n have concave faces \n883\n that have portions that are at a distance d from the casing wall \n884\n.', 'The transducer elements generate pressure fields \n885\n, \n886\n (which in one embodiment are of different polarities) having a width w at the casing wall.', 'As seen in \nFIG.', '17\nb\n, the pressure fields \n885\n, \n886\n are circular.', 'For both phased and non-phased transducer array applications, the input signals to the transducer elements are narrowband toneburst signals of a certain frequency.', 'A toneburst signal with more cycles results in a narrower band frequency spectrum which is advantageous in a selective guided wave actuation.', 'For a single element transducer, mode control capability is generally not possible beyond the designed parameters, and all possible harmonic guided modes at that specific frequency will be generated.', 'The amplitude of each harmonic mode can be represented as \n \nA\nn\n(\nz\n)=\nF\n(ω)·\nd C\nn\n(\nz\n),\u2003\u2003(1) \n where F(ω) is the frequency response of the single element, and C\nn\n(z) is the coupling coefficient between the surface loading function and the guided wave mode.', 'Based on the normal mode expansion method, C\nn\n(z) for a generated mode can be represented as an area integral\n \n \n \n \n \n \n \n \n \n \n \nC\n \nn\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n=\n \n \n \n \ne\n \n \n \n-\n \ni\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nβ\n \nn\n \n \n\u2062\n \nz\n \n \n \n \n4\n \n\u2062\n \n \nP\n \nnn\n \n \n \n \n\u2062\n \n \n \n \n∫\n \n \n-\n \nL\n \n \n \nL\n \n \n\u2062\n \n \n \n \ne\n \n \n \n-\n \ni\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nβ\n \nn\n \n \n\u2062\n \nη\n \n \n \n(\n \n \n \n∫\n \n \n∂\n \nD\n \n \n \n\u2062\n \n \n \n \nv\n \nn\n \n*\n \n \n·\n \n \n(\n \n \nt\n \n·\n \n \nn\n \n1\n \n \n \n)\n \n \n \n\u2062\n \nds\n \n \n \n)\n \n \n\u2062\n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nη\n \n \n \n \n \n,\n \n \n \n \n \n(\n \n2\n \n)\n \n \n \n \n \n \n \n where t is the exerted surface traction by a source loading function, θD is the surface area that the source loading contacts with the waveguide, β\nn \nis the wavenumber of the harmonic mode n, and v\nn\n* is the particle velocity distribution of the mode n.', 'In addition, n\n1 \nis the unit normal to the surface ∂D, and P\nm \nis the power density carried by the harmonic mode n.', 'If it is assumed that the length of the array element w is far less that the wavelength, the exponential term e\n−β\nn\nη\n and the particle velocity v\nn\n* will be approximately uniform within the integral area.', 'Then, equation (2) can be recast as\n \n \n \n \n \n \n \n \n \n \n \nC\n \nn\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n=\n \n \n \nS\n \n·\n \n \n \n \nv\n \nn\n \n*\n \n \n\u2062\n \n \nt\n \n·\n \n \nn\n \n1\n \n \n \n \n \n4\n \n\u2062\n \n \nP\n \nnn\n \n \n \n \n \n\u2062\n \n \ne\n \n \n \n-\n \ni\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nβ\n \nn\n \n \n\u2061\n \n \n(\n \n \nz\n \n-\n \n \nz\n \n0\n \n \n \n)\n \n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n where S is the area where the single element contacts the waveguide while z\n0 \nis the element location.', 'It is assumed for a non-phased array transducer with N elements of distance D that all the element are of identical response, the amplitude of a harmonic mode A\nn\n(z) is given by\n \n \n \n \n \n \n \n \n \n \n \nA\n \nn\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n=\n \n \nV\n \n·\n \n \nF\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n·\n \n \n \nC\n \nn\n \n \n\u2061\n \n \n(\n \nz\n \n)\n \n \n \n·\n \n \nH\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n,\n \n \n \n \n \n(\n \n4\n \n)\n \n \n \n \n \n \nwhere\n \n \n \n \n \n \n \n \n \n \n \n \n \nH\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n=\n \n \n \n \n∑\n \n \ni\n \n=\n \n1\n \n \nN\n \n \n\u2062\n \n \ne\n \n \nj\n \n\u2061\n \n \n[\n \n \n \nω\n \n\u2062\n \n \n \n \n\u2062\n \nt\n \n \n±\n \n \n \nβ\n \nn\n \n \n·\n \n \n(\n \n \nz\n \n-\n \n \nz\n \ni\n \n \n \n)\n \n \n \n \n]\n \n \n \n \n \n=\n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \nN\n \n\u2062\n \n \nL\n \nλ\n \n \n\u2062\n \nπ\n \n \n)\n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \n \nL\n \nλ\n \n \n\u2062\n \nπ\n \n \n)', '\u2062\n \n \ne\n \n \nj\n \n\u2061\n \n \n[\n \n \n \nω\n \n\u2062\n \n \n \n \n\u2062\n \nt\n \n \n±\n \n \n \nβ\n \nn\n \n \n·\n \n \n(\n \n \nz\n \n-\n \n \nz\n \ncenter\n \n \n \n)\n \n \n \n \n]\n \n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n5\n \n)\n \n \n \n \n \n \n \n and where ± indicates wave propagation in the −z and +z direction, respectively.', 'L is the element spacing, A is the wavelength of the harmonic mode n, and z\ncenter \nis the center location of the multi-element array.', 'From equation (5), it is evident that the total frequency response of the array transducer is shaped by H(ω), which is a function of the element spacing L and wavelength λ.', 'When L is equivalent to an integer multiple times of the wavelength, H(ω) will attain the maximum value that leads to a suppression of the modes that are of wavelengths other than λ. Equation (5) is the basis for phased or non-phased multi-element array transducer.', 'As previously discussed, the investigation of dispersion signatures enables the radial damage characterization of a double-cased hole; i.e., how the cementation or lack thereof diverges from the ideal.', 'In particular, acoustic tools are implemented to extract dispersion curves which relate to the borehole geometry.', 'These dispersion signatures are compared with the modeling results to identify the configuration and skeletons of the geometry.', 'However, as set forth below, proper guided wave modes need to be selected and excited to accurately and precisely localize and characterize the damage axially.', 'Thus, as set forth below, with the skeleton modes in hand, mode sensitivity and excitability study are conducted to select the waves that are sensitive to the targeting damage types.', 'In this way, features such as reflection coefficients, attenuation, and harmonic generation can be utilized to accurately characterize and locate the damage to the cement annuli along the length of the cased hole.', 'Those skilled in the art are aware that when a borehole is being cased, a poor cement job can result in gaps or voids in annuli A or B that are not filled with cement slurry.', 'After the cement curing process, formation fluid and drilling mud can migrate into these gaps.', 'Resulting long term fluctuating stresses can cause the cement sheath to degrade and crack and be invaded with fluid after a long service time.', 'Zonal isolation and well integrity become compromised with the presence of these axial fluid columns.', 'Therefore, it is important to detect the location and length of these axial fluid columns.', 'Detection involves the problem of locating the axial transition from cemented to uncemented annuli.', 'In one aspect, it is useful to consider a configuration transition from a W/S/C/S/C/F configuration to a W/S/W/S/W/F configuration, during which the cement sheath at both annuli A and B are replaced by drilling or reservoir fluids.', 'A schematic of a borehole with axial transition at both annuli A and B is shown in \nFIG.', '18\n, in which a transmitter \n901\n and multi-receiver arrays \n903\n, \n904\n and \n905\n are provided.', 'Receiver array \n904\n is shown with n receivers R\n1 \n. . .', 'R\nn\n.', 'The receiver arrays \n903\n, \n904\n and \n905\n are placed at various locations, including in the intact wellbore POS \n1\n (with fluid stack \n910\n, inner casing \n920\n, inner cement annulus \n930\na\n, outer casing \n940\n, outer cement annulus \n950\na \nand formation \n960\n), the transition region POS \n2\n and a fluid occupied double-cased hole POS \n3\n (with fluid stack \n910\n, inner casing \n920\n, fluid \n930\nb \nin the inner annulus, outer casing \n940\n, fluid \n950\nb \nin the outer annulus, and formation \n960\n), to extract the local acoustic signatures.', 'The slowness dispersion curves that are generated in a wellbore with an axial cement-fluid transition at annuli A and B are shown in \nFIG.', '19\n.', 'The circles and triangles are dispersion curves, respectively, extracted at Pos 1 and Pos 3, while the asterisks are these obtained at the cement to fluid transition region Pos 2.', 'Skeletal modes S1 to S6 (shown as dash-dot-dash lines) relate to a S/C/S skeleton, while skeletal modes S7 to S10 relate to a skeleton with separated metal casings.', 'As a skeleton transformation occurs from an intact wellbore with a W/S/C/S/C/F configuration to a cased-hole with W/S/W/S/W/F configuration, the dispersion curves obtained at Pos 2 depend on the spatial averaging of material properties that exhibit signatures of both the configurations, which can be used to roughly locate the cement to fluid transition.', 'In one embodiment, a selective guided wave modal actuation has been conducted to further characterize the cement-fluid transition.', 'More particularly and for purposes of illustration, assume that the transmitter is placed at the W/S/C/S/C/F side of the double-cased wellbore for which the skeleton is a S/C/S triple layer cylinder.', 'To effectively detect the cement-fluid transition at the annulus A and B, guided wave modes that are of high energy concentration in the cement annulus are desirable.', 'Waves with outer-plane dominant displacement components on the inner wellbore surface can be efficiently actuated by a pressure transmitter.', 'FIGS.', '20\na\n-20\nf \nshow sample displacement modal shapes in a S/C/S triple layer cylinder for points P1 to P6 marked in the dispersion plot of \nFIG.', '2\n for an intact borehole (W/S/C/S/C/F configuration), with ur representing radial displacement and u\nz \nrepresenting axial displacement.', 'Analysis indicates that the S2 mode at 50 kHz is an ideal candidate for cement-fluid transition characterization in both annuli because the particle displacement is relatively large in both annuli.', 'The field displacement and stress distributions of S2 mode at 50 kHz through thickness of the SCS triple layer cylinder are shown respectively in \nFIGS.', '21\na \nand \n21\nb.', 'A multi-element comb-like transducer such as described with respect to \nFIG.', '17\na \nhas been designed to actuate the desired S2 mode at 50 kHz.', 'A receiver array has been used to collect the transmission signals.', 'The A-scan signals from primary S2 excitation at 50 kHz in a double-cased hole with W/S/C/S/C/F configuration are shown in \nFIG.', '22\n.', 'Reflection signals are observed as noted in \nFIG.', '22\n.', 'The reflection signals can be manipulated for accurate characterization of cement-fluid transition.', 'In particular, the amplitudes of the reflections may be associated with the severity of the reflections, and the time-of-flight may indicate the location of the axial anomalies as described hereinafter.', 'Based on the foregoing, additional methods are presented for characterizing multi-string cased wells using wide frequency bandwidth signals including precisely locating locations of cement quality transition in doubly cased wells.', 'In one embodiment shown in \nFIG.', '23\n, at \n1001\n, at least one model is obtained for modeling acoustic tools in a geological formation.', 'The model may be a synthetic model such as CSFEM or finite difference time domain (FD-TD), and/or an analytical model.', 'With the embodiment of \nFIG.', '23\n showing the use of a synthetic model, synthetic wideband waveforms generated by a wide bandwidth monopole, dipole or quadrupole source and detected by an axial array of receivers are recorded at \n1003\n.', 'The recorded waveforms are processed at \n1005\n using a modified matrix pencil method in order to generate at \n1007\n synthetic slowness dispersion curves over the wideband.', 'In one embodiment, steps \n1001\n-\n1007\n are conducted for the W/S/C/S/C/F configuration shown in \nFIG.', '1\n and the results are stored in electronic and/or hard copy format.', 'In another embodiment, steps \n1001\n-\n1007\n are conducted for multiple configurations (e.g., \nFIGS.', '1, 3, 6, 8, 10, 12 and 14\n) and the results for each configuration is stored in a desired format.', 'In one embodiment, steps \n1001\n-\n1007\n are conducted for multiple dual string well geometries (e.g., different casing radii, different casing thicknesses, different annulus thicknesses, etc.) for the configuration shown in \nFIG.', '1\n or for multiple configurations and the results are stored in a desired format.', 'In one embodiment, the slowness dispersion curves for each well geometry are separately kept together as a set.', 'At \n1011\n, wideband acoustic logging waveforms received at the receivers of a tool (modeled at \n1001\n) which was placed downhole in a double-cased wellbore are recorded.', 'At \n1013\n, the recorded waveforms are conditioned and stacked, and at \n1015\n the conditioned and stacked waveforms are processed to isolate nondispersive and dispersive modes.', 'At \n1017\n, slowness dispersion curves are generated using the modified matrix pencil method.', 'At \n1021\n, the slowness dispersion curves generated at \n1017\n from the data obtained from the borehole tool are compared to the synthetic slowness dispersion curves generated at \n1007\n.', 'The comparison may be done utilizing a least squares fit or other comparison techniques and/or visually.', 'In one aspect, skeletal modes are identified in order to determine whether the investigated double-cased wellbore has a S/C/S skeleton as in \nFIGS.', '2, 7 and 13\n, or whether the skeleton of the double-cased wellbore has separated metal casings (e.g., S/W/S) as in \nFIGS.', '4, 9, and 11\n.', 'The skeletal modes may also be identified in order to determine whether the investigated double-cased wellbore has a S/C/S/C skeleton as in \nFIG.', '15\n.', 'In particular, if five (or six) skeletal modes are found at expected frequency ranges and slownesses, it may be concluded that the first and second anuli are well cemented.', 'If more than six skeletal modes are found, it may be concluded that the first annulus is well cemented and the second annulus contains cement but has a weak bond or slip at the 5\nth \ninterface.', 'If only four skeletal modes are found, it may be concluded that the first annulus contains liquid.', 'In addition to the skeletal mode identification, lower frequency (e.g., between about 0 kHz and 30 kHz, or a portion thereof) casing-fluid interaction modes may be identified and compared to one or more of the stored dispersion curve plots by steps \n1001\n-\n1007\n.', 'If, for a S/C/S skeleton, increases in the slownesses associated with the casing-fluid interaction modes are found (relative to the slownesses for the well-cemented arrangement of \nFIG.', '1\n), it may be concluded that the inner annulus is cemented and the outer annulus is fluid-filled.', 'Of course, if a reference dispersion curve plot for a W/S/C/S/W/F configuration is generated, the comparison at \n1021\n will show such a match.', 'Similarly, for a skeleton with the metal casings separated by liquid, the slownesses of the casing-fluid interaction modes may be used to distinguish whether the outer annulus is cemented or not (see \nFIG.', '9\n).', 'Likewise, the slownesses of the casing-fluid interaction modes may be used to identify degraded cement in the second annulus (see \nFIG.', '11\n) or to identify debonding at the 4\nth \ninterface (see \nFIG.', '13\n).', 'It will be appreciated that the comparison between the measured and calculated slowness dispersions at \n1021\n may be conducted at each depth of the borehole that acoustic logging is conducted.', 'Thus, as a logging tool is moved up the borehole, the calculated slowness dispersions may change.', 'Thus, at \n1031\n, a determination is made as to whether the skeletal modes and/or the lower frequency casing-fluid interaction modes are changing.', 'If not, then it may be concluded that there is no change in the double casing borehole structure (such as the cement integrity).', 'However, if such skeletal modes and/or lower frequency casing-fluid interaction modes appear to be changing from one depth to another, then, in one embodiment, at \n1041\n, in addition to running the wideband acoustic logging, a guided wave modal actuation using a narrowband transmitter such as the comb-like phased array transducer of \nFIGS.', '17\na \nand 17\nb \nis used to generate a narrowband signal at a desired frequency (e.g., 50 kHz) and the resulting waveforms are detected.', 'In one embodiment, the narrowband tone burst signal is chosen to excite a selected guided wave mode that has major acoustic energy concentrated in the cement annulus of interest.', 'With the acoustic wave propagating through the cement to fluid transition, the acoustic energy is reflected due to the impedance mismatch between the cement section and the fluid.', 'The detected signal is then analyzed at \n1043\n to locate reflection signals such as in \nFIG.', '22\n, or other indications of a changing borehole structure such as phase shifts.', 'Based on these indications, (e.g., time-of-flight of the reflection given the wave speed of the acoustic mode and the transmitter location), a determination is made as to the location of the transition.', 'Of course, where the transition is gradual, a determination can be made as to the location of the start of the transition and the location where the transition ends and a new configuration is established.', 'In accord with another aspect, wide frequency bandwidth signals were used to analyze eccentered double string boreholes.', 'FIG.', '24\na \nis a cross-sectional diagram of a 50% eccentered free double string immersed in fluid.', 'In particular, \nFIG.', '24\na \nshows a double-cased wellbore configuration with water or mud \n1110\n inside the inner casing \n1120\n, a water annulus A \n1130\n between the inner casing and the outer casing \n1140\n, and infinite fluid \n1150\n outside the outer casing \n1140\n, with the inner casing \n1120\n (50%) eccentered relative to the outer casing \n1140\n.', 'FIG.', '24\nb \nshows a double-cased wellbore configuration with water or mud \n1210\n inside the inner casing \n1220\n, a water annulus A \n1230\n between the inner casing and the outer casing \n1240\n, cement \n1250\n outside the outer casing \n1240\n, and infinite fluid \n1260\n beyond the cement \n1250\n, with the inner casing \n1220\n (50%) eccentered relative to the outer casing \n1240\n.', 'In the arrangements of \nFIGS.', '24\na \nand 24\nb\n, the casing eccentricity is defined according to\n \n \n \n \n \n \nE\n \n=\n \n \n \ne\n \n \n \nr\n \n2\n \n \n-\n \n \nr\n \n1\n \n \n \n \n×\n \n100\n \n\u2062\n \n%\n \n \n \n,\n \n \n \n \n where r\n1 \nis the inner diameter of the inner casing and r\n2 \nis the outer diameter of the inner casing.', 'The geometric and material properties for the double string system of \nFIGS.', '24\na \nand 24\nb \nare given in Table II.', 'TABLE II\n \n \n \n \n \n \n \n \n \n \nDimensions\n \nMaterial properties\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nr\n3\n \nr\n4\n \nr\n5\n \nρ\ni\n \nV\nP\n \nV\ns\n \n \n \n \nr\n1 \n(mm)\n \nr\n2 \n(mm)\n \n(mm)\n \n(mm)\n \n(mm)\n \n(kg/m\n3\n)\n \n(m/s)\n \n(kg/m\n3\n)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nFluid\n \n19.8755\n \n22.2250\n \n27.50\n \n31.75\n \n38.81\n \n1000\n \n1500.00\n \n0\n \n \n \nSteel\n \n \n \n \n \n \n7890\n \n5790.00\n \n3100.00\n \n \n \nCement\n \n \n \n \n \n \n1900\n \n3625.00\n \n2015.00\n \n \n \n \n \n \n \n \n \n \nIn \nFIG.', '25\n, the slowness dispersion curves for concentric and 50% eccentered cemented double strings are seen.', 'The closed circles and the open circles, respectively indicate concentric and 50% eccentered results.', 'It is observed that the slowness dispersion for the concentric and eccentered geometries coincide in most of the regions.', 'However, the presence of moderate casing eccentricity induces a slowness reduction at low frequency casing-fluid interaction modes and cut-off modes in identified regions Z1 and Z2.', 'In \nFIG.', '26\n, the slowness dispersion curves are plotted for free and cemented double strings with identical eccentricity (50%).', 'The circles and dots, respectively, represent experimental and numerical dispersions of cemented double strings (\nFIG.', '24\nb\n), while the triangles indicate those extracted from free double string (\nFIG.', '24\na\n).', 'The skeletons for both the two geometries are the inner and outer steel casings with 50% eccentricity.', 'Therefore, no change should occur at skeleton and fluid resonant modes regions.', 'It is observed from \nFIG.', '26\n the only changes on the slowness dispersions occur at low frequency casing-fluid interaction mode region Z1.', 'Therefore, the features can be used to characterize cement annulus B in double string geometries.', 'Thus, in one aspect, in characterizing a multi-string borehole, and particularly with respect to \nFIGS.', '16 and 23\n, the modeling of different dual string well geometries may include the modeling of eccentered casings for the configuration shown in \nFIG.', '1\n or for multiple configurations.', 'Then, after wideband acoustic logging is conducted, the resulting slowness dispersions may be compared to a database of calculated slowness dispersions which includes eccentered casing examples.', 'In this manner, a determination may be made not only as to the presence or lack thereof of cement in the annuli of the dual string wellbore and the possibility of a slip at certain interfaces, but also of eccentering.', 'In one aspect, some of the methods and processes described above, such as filtering and TKO processing of sonic signals and the fitting of dispersion curves to model curves are performed by a processor.', 'The term “processor” should not be construed to limit the embodiments disclosed herein to any particular device type or system.', 'The processor may include a computer system.', 'The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing any of the methods and processes described above.', 'The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.', 'Some of the methods and processes described above, can be implemented as computer program logic for use with the computer processor.', 'The computer program logic may be embodied in various forms, including a source code form or a computer executable form.', 'Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, or JAVA).', 'Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor.', 'The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).', 'Alternatively or additionally, the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)).', 'Any of the methods and processes described above can be implemented using such logic devices.', 'Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples without materially departing from this subject disclosure.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A method of characterizing the annuli of a multi-string wellbore, comprising:\nutilizing at least one tool in the wellbore to excite wideband acoustic energy and detect resulting wideband signals at a location in the wellbore;\nprocessing the detected wideband signals to obtain indications of wideband casing-formation phase slowness dispersions in the wellbore;\ncomparing the indications of wideband casing-formation phase slowness dispersions in the wellbore to reference wideband model casing-formation phase slowness dispersions; and\nestimating status of cement or lack of cement in the annuli at said location based on said comparing.', '2.', 'The method of claim 1, wherein said wideband signals include a range of at least 5 kHz to 70 kHz.\n\n\n\n\n\n\n3.', 'The method of claim 1, wherein said wideband signals range from at least 5 kHz to 100 kHz.\n\n\n\n\n\n\n4.', 'The method of claim 1, wherein said wideband signals range from at least 1 kHz to 100 kHz.\n\n\n\n\n\n\n5.', 'The method of claim 1, wherein said comparing comprises comparing indications of wideband casing-formation phase slowness dispersions in the wellbore to sets of a plurality of reference wideband model casing-formation phase slowness dispersions, each set of said sets being for a different wellbore configuration.', '6.', 'The method of claim 5, wherein said sets include a water-inner metal-inner cement-outer metal-outer cement-formation configuration, a water-inner metal-water-outer metal-cement-formation configuration, a water-inner metal-cement-outer metal-water-formation configuration, and a water-inner metal-water-outer metal-water-formation configuration.', '7.', 'The method of claim 6, wherein said sets further include a water-inner metal-inner cement-outer metal-outer cement-formation configuration with a slip between the outer metal and the outer cement, and a water-inner metal-inner cement-outer metal-outer cement-formation configuration with a slip between the outer cement and the formation.', '8.', 'The method of claim 1, wherein said comparing comprises identifying skeletal modes in said indications of wideband casing-formation phase slowness dispersions.', '9.', 'The method of claim 8, wherein said estimating comprises determining the presence of cement in both annuli where said indications of wideband casing-formation phase slowness dispersions in the wellbore include at least five skeletal modes.', '10.', 'The method of claim 8, wherein said estimating comprises determining the lack of cement in the first annulus where said indication of wideband casing-formation phase slowness dispersion in the wellbore include fewer than five skeletal modes.', '11.', 'The method of claim 10, wherein said comparing comprises comparing casing-fluid interaction modes at frequencies below 30 kHz in order to identify the presence or lack of cement in the second annulus.\n\n\n\n\n\n\n12.', 'The method of claim 8, wherein said comparing comprises comparing casing-fluid interaction modes at frequencies below 30 kHz in order to identify the presence or lack of cement in the second annulus.\n\n\n\n\n\n\n13.', 'The method of claim 8, wherein said comparing comprises comparing casing-fluid interaction modes at frequencies of between 30 kHz and 60 kHz in order to identify the presence or lack of eccentering of an inner casing within an outer casing.\n\n\n\n\n\n\n14.', 'The method of claim 1, further comprising:\nrepeating said utilizing, processing, comparing and estimating at multiple locations in wellbore in order to estimate status of cement or lack thereof in the annuli at said multiple locations; and\ndetermining a change between two locations in said estimate of status of cement or lack of cement in the annuli.\n\n\n\n\n\n\n15.', 'The method of claim 14, further comprising:\ngenerating a narrowband signal at a desired frequency at a second of said two locations and detecting resulting waveforms; and\nanalyzing said resulting waveforms to obtain an indication of a location of transition from a first estimate of quality of cement or lack thereof in the annuli to a second different estimate of status of cement or lack of cement in the annuli.', '16.', 'The method of claim 15, wherein said analyzing said resulting waveforms comprises locating reflection signals in said resulting waveforms.', '17.', 'A method for characterizing the annuli of a double-cased wellbore traversing a formation, comprising:\nobtaining reference dispersions for an intact wellbore with well-cemented first and second annuli;\ndeploying an acoustic logging tool in the double-cased wellbore, the acoustic tool including an acoustic source that generates wide band excitation signals and a receiver array that records resulting wideband signal wavetrains;\nprocessing the detected wideband signals to obtain indications of measured wideband casing-formation phase slowness dispersions in the wellbore;\ncomparing the measured wideband slowness dispersions and said reference dispersions; and\nidentifying differences in said measured and reference dispersions in order to characterize at least one of (1) the presence or the lack of cement in at least one of said first and second annuli, and (2) bonding weakness of at least one of a cement-casing interface and a cement-formation interface.', '18.', 'The method of claim 17, wherein said wideband signals include a range of at least 5 kHz to 70 kHz.\n\n\n\n\n\n\n19.', 'The method of claim 17, wherein said wideband signals range from at least 5 kHz to 100 kHz.\n\n\n\n\n\n\n20.', 'The method of claim 17, wherein said wideband signals range from at least 1 kHz to 100 kHz.'] | ['FIG.', '1 is a schematic diagram showing a cross-section of a fluid-filled well-bonded double-cased borehole.; FIG.', '2 is a diagram showing slowness dispersion curves in an intact double-cased hole with a well-cemented water-steel-cement-steel-cement-formation configuration.', 'The lines and asterisks indicate the skeletal dispersion curves obtained respectively from mode search and synthetic modeling algorithms.;', 'FIG. 3 is a schematic cross-sectional diagram of a double-cased hole with a water-steel-water-steel-cement-formation configuration.; FIG. 4 is a diagram showing slowness dispersion curves in a double-cased hole of the configuration shown in FIG.', '3, with the skeleton modes of the FIG.', '3 configuration shown as dashed (dash-dot-dash) lines and the dispersion curves shown with triangles.', 'These are overlaid with skeleton modes shown in solid lines and dispersion curves shown with circles for an intact double-cased hole.; FIG.', '5 is a magnified view of the slowness dispersion curves in zone 1 (Z1) of FIG.', '4.; FIG. 6 is a schematic cross-section of a double-cased hole with a water-steel-cement-steel-water-formation configuration.; FIG. 7 is a diagram showing slowness dispersion curves in a double-cased hole with the configuration shown in FIG.', '6 shown with asterisks and the dispersion curves of the intact double-cased borehole shown with circles.', 'The skeleton modes are marked as solid lines.', '; FIG. 8 is a schematic cross-section of a double-cased hole with a water-steel-water-steel-water-formation configuration.; FIG.', '9 is a diagram showing slowness dispersion curves in a double-cased hole with the configuration of FIG.', '8 shown with dots and the dispersion curves of the double-cased borehole of FIG.', '3 shown with circles.', 'The skeleton modes are marked as solid lines.', '; FIG.', '10 is a schematic cross-section of a double-cased hole with a water-steel-water-steel-degraded cement-formation configuration.; FIG.', '11 is a diagram showing slowness dispersion curves in a double-cased hole with the configuration of FIG.', '10 shown with + signs, the dispersion curves for the configuration of FIG.', '8 shown with triangles and the dispersion curves for the configuration of FIG.', '3 shown with circles.', 'The skeleton modes are marked as solid and dashed (dash-dot-dash) lines.', '; FIG.', '12 is a schematic cross-section of a double-cased hole with 4th interface debonding.; FIG. 13 is a diagram showing slowness dispersion curves in a double-cased wellbore with 4th interface debonding shown with diamonds and the dispersion curves of an intact double-cased borehole shown with dots.', "The skeleton modes are marked as lines and with x's.; FIG.", '14 is a schematic cross-section of a double-cased hole with 5th interface debonding.; FIG.', '15 is a diagram showing slowness dispersion curves in a double-cased wellbore with 5th interface debonding shown with triangles and the skeleton modes for the FIG.', '14 configuration shown in dashed (dash-dot-dash) lines.', 'These are overlaid with skeleton modes shown in solid lines and dispersion curves shown with dots for an intact double-cased hole.; FIG.', '16 is a flowchart of a method of wellbore damage characterization.; FIGS. 17a and 17b are respectively a cross-sectional diagram of a multi-element comb-like phased array transducer used to excite a selected wave mode in a borehole, and a schematic view of a pressure field resulting from the firing of the phased array transducer.; FIG.', '18 is a schematic axial cross-sectional diagram of a double-cased hole with axial cement-fluid transition zone at annuli A and B.; FIG.', '19 is a diagram showing slowness dispersion curves in a double-cased wellbore with a cement-fluid transition zone as shown in FIG.', '18.', 'The circles and triangular dots are dispersion curves respectively extracted at Pos 1 and Pos 3 shown in FIG.', '18, while the asterisks are those obtained at the cement-fluid transition region Pos 2 of FIG.', '18.', 'The solid lines denote the skeleton modes for the wellbore with different configurations.; FIGS.', '20a-20f are sample normalized displacement wave structures for a steel-cement-steel triple layer cylinder.; FIGS.', '21a and 21b are displacement and stress modal shapes of S2 mode at 50 kHz in a steel-cement-steel triple layer cylinder.; FIG.', '22 are time domain signal waveforms for the S2 mode at 50 kHz.', 'The portions of the waveforms that are within the dashed oval indicate the reflection signals from the cement-fluid transition.;', 'FIG.', '23 is a flowchart of another method wellbore damage characterization.; FIGS. 24a and 24b are schematic cross-sectional diagrams of 50% eccentered double strings immersed in infinite fluid with a free double string, and a cemented double string, respectively.; FIG.', '25 is a diagram showing slowness dispersion curves for concentric and 50% eccentered cemented double strings.', 'The solid dots and open circles, respectively, indicate concentric and 50% eccentered results.', '; FIG.', '26 is a diagram showing slowness dispersion curves for free and cemented double strings with identical eccentricity (50%).', 'The circles and dots, respectively, represents for experimental and numerical dispersions of cemented double strings, while the triangles indicate those extracted from a free double string.', '; FIG.', '1 shows the cross-section of a well bonded, double-cased borehole and a coordinate system.', 'The cylinders from the center to the outside of the cross-section are the fluid column 10, inner casing 20, cement annulus A 30, outer casing 40, cement annulus B 50, and infinite formation media 60, respectively.', 'The material properties and geometry parameters (including radii r, shear and compressional velocities Vs and Vp, and densities ρ for the modeling are provided in Table I.; FIG.', '2 shows the slowness dispersion curves for the intact double-cased wellbore shown in FIG.', '1 with the water or mud filled borehole, an inner steel casing, a well-cemented first annulus, a second steel casing, a well-cemented second annulus, and then the formation (which is referred to herein as a W/S/C/S/C/F configuration).', 'The “skeleton” or most solid portion of the cased wellbore of FIG. 1 is the SCS (steel-cement-steel) triple layer cylinder.', 'Corresponding skeleton dispersion curves (in solid lines identified through a mode search, and in asterisks identified by a Chirp Sweeping Finite Element Modeling (CSFEM) algorithm—see, Liu, Y. et al., “Guided Waves in Fluid-Elastic Concentric and Non-Concentric Cylindrical Structures: Theoretical and Experimental Investigations”, 43rd Annual Review of Progress in Quantitative Nondestructive Evaluation (QNDE) (2016) are labeled S1-S6, while guided wave modalities indicated by labels 1-16 are also observed.', 'Skeleton dispersion curves S1-S6 are seen to have their genesis at different frequencies, with S1 starting at about 0 kHz, S2 starting at about 9 kHz, S3 starting at about 12 kHz, S4 starting at about 26 kHz, S5 starting at about 60 kHz, and skeleton dispersion curve S6 starting slightly above 90 kHz.; FIG.', '6 shows a double-cased wellbore with water or mud 210, inner casing 220, cement annulus A 230, outer casing 240, water annulus B 250, and infinite formation media 260 (W/S/C/S/W/F configuration).', 'FIG.', '7 shows the dispersion curves for the wellbore configuration of FIG.', '6 as asterisks contrasted to the well-cemented W/S/C/S/C/F geometry of FIG.', '1 in circles.', 'The skeletal dispersion curves for this geometry appear to be the same as the skeleton of the intact wellbore and are labeled by S1 to S6 in FIG.', '7.', 'With the same skeleton, it should be appreciated that the differences between the two cases are localized at low frequency ranges around what may be referred to as the casing-fluid interaction modes.', 'As can be seen in FIG.', '7, the slowness dispersions of these modal branches (1 to 3 compared to 4 to 6) experience increments due to the softening effect arising from removing the cement in annulus B 250.', 'There are barely any changes at high frequencies between the two cases.', '; FIG.', '8 presents a double-cased wellbore with water or mud 310, inner casing 320, water annulus A 330, outer casing 340, water annulus B 350, and infinite formation media 360 (W/S/W/S/W/F configuration).', 'The skeleton of the W/S/W/S/W/F configuration is the same as that of a W/S/W/S/C/F double-cased wellbore (FIG. 3); i.e., with separate inner and outer casings.', 'The resulting skeletal modes are labeled as S1 to S4 in FIG.', '9.', 'In addition, the slowness dispersions for the W/S/W/S/W/F double-cased hole are similar to these of a W/S/W/S/C/F configuration, except for the low frequency casing-fluid interaction regions which are changed due to the stiffness variations.', 'This is seen by the slowness dispersion curves shown in FIG.', '9, while the dots and circles denote the modalities of W/S/W/S/W/F and W/S/W/S/C/F configurations, respectively.', 'The skeletal and fluid resonant modes are identical for the two configurations, while the casing-fluid interaction modes for the W/S/W/S/W/F configuration (labeled as 1 to 4) exhibits higher slownesses compared with these of an intact wellbore (labeled as 5 to 8) due to the softening effect of the water in annulus B.; FIG.', '13 shows the slowness dispersion curves for the W/S/C/S/b4C/F configuration of FIG.', '12.', 'The dispersion curves for an intact double-cased hole (as shown in FIG.', "2) are also presented in the figure as a solid line for the mode search and as x's for the CSFEM as a baseline.", 'The curves for the intact and the 4th interfacial debonded wellbores are indicated by dots and diamonds, respectively.', 'It is observed that the 4th interfacial debonded double-cased hole of FIG.', '12 shares the same skeleton (SCS) and hence the same skeletal modes with the intact wellbore which are labeled by S1 to S6.', 'The invariance of skeletal modes indicates that no structural change should occur in the wellbore dispersitivity.', 'On the other hand, it is observed that the lower frequency casing-fluid interaction modes (between about 5 kHz and 30 kHz) of the W/S/C/S/b4C/F configuration (labeled 1 to 3) exhibit mild increments in slowness dispersions relative to their counterparts of the W/S/C/S/C/F configuration (labeled by 4 to 6), which is due to the mechanical softening by the debonding.', 'In addition, certain casing cut-off modes (seen starting at 40 kHz, 60 kHz, and 67 kHz respectively) appear to be stronger than corresponding cut-off modes of the W/S/C/S/C/F configuration.; FIG.', '14 illustrates a double-cased wellbore with water or mud 610 inside the inner casing 620, a cement annulus A 630 between the inner casing and the outer casing 640, a cement annulus B 650 between the outer casing 640 and an infinite formation media 660, with a weak bond at the (5th) interface 661 of the cement 650 and the formation 660 (W/S/C/S/Cb5/F configuration).; FIG.', '15 shows the slowness dispersion curves for the W/S/C/S/b4C/F configuration of FIG.', '14 with the triangles indicating the dispersion curves of a double-cased hole with 5th interface debonding, and the dots denoting those of an intact wellbore as in FIG.', '1.', 'A skeletal transformation is observed when considering the geometrical changes from a SCS triple layer cylinder (with skeletal modes shown as curves labeled by S1 to S6) to a SCSC four layer cylinder (with skeletal modes shown as dash-dot-dash curves labeled by S7 to S16) caused by the 5th interface debonding.', 'The skeletal transformation induces a structural change in borehole guided characteristics, where feature branches (such as S9, S10, S13, and S15) not found for the SCS triple layer cylinder are presented as indicated by regions Z2 to Z5 in FIG.', '15.', 'In addition, at least one skeletal mode (S8) has a significantly increased slowness than its counterpart (S2) at higher frequencies (above 35 or 40 kHz).', 'Further, since the stiffness of the geometry as a whole decreases with the presence of 5th interfacial debonding, it is expected that slowness increments will occur at lower frequency casing-fluid interaction modes (particularly between 5 kHz and 25 kHz).', 'This prediction is validated by the slowness variations as observed in Z1 in FIG.', '15.; FIGS.', '20a-20f show sample displacement modal shapes in a S/C/S triple layer cylinder for points P1 to P6 marked in the dispersion plot of FIG.', '2 for an intact borehole (W/S/C/S/C/F configuration), with ur representing radial displacement and uz representing axial displacement.', 'Analysis indicates that the S2 mode at 50 kHz is an ideal candidate for cement-fluid transition characterization in both annuli because the particle displacement is relatively large in both annuli.', 'The field displacement and stress distributions of S2 mode at 50 kHz through thickness of the SCS triple layer cylinder are shown respectively in FIGS.', '21a and 21b.'] |
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US11136884 | Well construction using downhole communication and/or data | Feb 2, 2017 | Shunfeng Zheng, Benjamin Peter Jeffryes, Mochammad Faisal Wingky | Schlumberger Technology Corporation | NPL References not found. | 5995449; November 30, 1999; Green; 6944547; September 13, 2005; Womer et al.; 8196678; June 12, 2012; Jeffryes; 10082942; September 25, 2018; Jarrot et al.; 20050046591; March 3, 2005; Pacault et al.; 20060001549; January 5, 2006; Shah et al.; 20080110612; May 15, 2008; Prinz; 20090177404; July 9, 2009; Hartmann et al.; 20100161227; June 24, 2010; Deere; 20110280104; November 17, 2011; McClung; 20120290206; November 15, 2012; Hartmann et al.; 20130000981; January 3, 2013; Grimmer et al.; 20140240140; August 28, 2014; Switzer et al.; 20140326505; November 6, 2014; Davis et al.; 20140338900; November 20, 2014; Jones; 20150053483; February 26, 2015; Mebane, III; 20150107901; April 23, 2015; Eriksson et al.; 20150139615; May 21, 2015; Hill; 20150240619; August 27, 2015; Frosell; 20150337652; November 26, 2015; Rodney; 20160003035; January 7, 2016; Logan et al.; 20160090800; March 31, 2016; Jeffryes; 20160194950; July 7, 2016; Zheng et al.; 20160230484; August 11, 2016; Johnson et al. | 2004090285; October 2004; WO; 2009058635; May 2009; WO; 2009089150; July 2009; WO; 2009132281; October 2009; WO | ['Apparatus and methods pertaining to a processing system operable to determine a change to an operation of a well construction system based on an indication of a quality of transmitted communication between downhole equipment of the well construction system in a wellbore and surface communication equipment of the well construction system transmitted during the operation, a projected effect of the operation on future communication between the downhole equipment and the surface communication equipment, downhole data related to one or more conditions in the wellbore, or a combination thereof.', 'The processing system is operable to cause the change to the operation of the well construction system to be implemented.'] | ['Description\n\n\n\n\n\n\nBACKGROUND OF THE DISCLOSURE', 'In the drilling of oil and gas wells, drilling rigs are used to create a well by drilling a wellbore into a formation to reach oil and gas deposits (e.g., hydrocarbon deposits).', 'During the drilling process, as the depth of the wellbore increases, so does the length and weight of the drillstring.', 'A drillstring may include sections of drill pipe, a bottom hole assembly, and other tools for creating a well.', 'The length of the drillstring may be increased by adding additional sections of drill pipe as the depth of the wellbore increases.', 'Various components of a drilling rig can be used to advance the drillstring into the formation.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus including a processing system that includes a processor and a memory including computer program code.', 'The processing system is operable to determine a change to an operation of a well construction system based on an indication of a quality of transmitted communication between downhole equipment of the well construction system in a wellbore and surface communication equipment of the well construction system transmitted during the operation, a projected effect of the operation on future communication between the downhole equipment and the surface communication equipment, downhole data related to one or more conditions in the wellbore, or a combination thereof.', 'The processing system is also operable to cause the change to the operation of the well construction system to be implemented.', 'The present disclosure also introduces a method including operating a processing system having a processor and a memory including computer program code.', 'Operating the processing system includes determining a change to an operation of at least some of surface equipment of the well construction system based on: (i) an indication of a quality of a transmitted communication between downhole equipment of the well construction system in a wellbore and surface communication equipment of the well construction system transmitted during the operation; (ii) a projected effect of the operation on future communication between the downhole equipment and the surface communication equipment; (iii) downhole data related to one or more conditions in the wellbore; or (iv) a combination thereof.', 'Operating the processing system also includes causing the change to the operation to be implemented.', 'The present disclosure also introduces an apparatus including a processing system having a processor and a memory including computer program code, the processing system being operable to analyze a communication between downhole equipment and surface equipment of a well construction system to obtain an indication of a quality of the communication, determine a change to an operation of the well construction system based on the indication of the quality of the communication, and cause the change to the operation of the well construction system to be implemented.', 'The present disclosure also introduces a method including operating a processing system having a processor and a memory including computer program code.', 'Operating the processing system includes analyzing a communication between downhole equipment and surface equipment of a well construction system to obtain an indication of a quality of the communication, determining a change to an operation of the well construction system based on the indication of the quality of the communication, and causing the change to the operation of the well construction system to be implemented.', 'The present disclosure also introduces an apparatus including a processing system having a processor and a memory including computer program code, the processing system being operable to determine a projected effect on a future communication based on a future sequence of an operation of a well construction system.', 'The future communication is between downhole equipment and surface equipment of the well construction system.', 'The processing system is also operable to determine a change to the operation of the well construction system based on the projected effect, and cause the change to the operation of the well construction system to be implemented.', 'The present disclosure also introduces a method including operating a processing system having a processor and a memory including computer program code.', 'Operating the processing system includes determining a projected effect on a future communication based on a future sequence of an operation of a well construction system.', 'The future communication is between downhole equipment and surface equipment of the well construction system.', 'Operating the processing system also includes determining a change to the operation of the well construction system based on the projected effect, and causing the change to the operation of the well construction system to be implemented.', 'The present disclosure also introduces an apparatus including a processing system having a processor and a memory including computer program code, the processing system being operable to determine a change to an operation of a well construction system based on downhole data relating to one or more conditions in a wellbore at a well site, and cause the change to the operation of the well construction system to be implemented.', 'The present disclosure also introduces a method including operating a processing system having a processor and a memory including computer program code.', 'Operating the processing system includes determining a change to an operation of a well construction system based on downhole data relating to one or more conditions in a wellbore at a well site, and causing the change to the operation of the well construction system to be implemented.', 'The present disclosure also introduces an apparatus including equipment of a well construction apparatus, one or more equipment controllers operable to control the equipment, and a processing system including a processor and a memory including computer program code.', 'The one or more equipment controllers and the processing system are communicatively coupled to a network.', 'The processing system is operable to identify an operation of the equipment, determine a change to the identified operation of the equipment based on downhole data relating to one or more conditions in a wellbore formed by the well construction apparatus, and cause the change to the identified operation to be implemented.', 'The present disclosure also introduces a method including operating a processing system having a processor and a memory including computer program code, the processing system being communicatively coupled to a network.', 'Operating the processing system includes identifying an operation of equipment of a well construction apparatus, and determining a change to the identified operation of the equipment based on downhole data relating to one or more conditions in a wellbore formed by the well construction apparatus.', 'The method also includes operating the equipment of the well construction apparatus based on the change.', 'Operating the equipment includes controlling the equipment using one or more equipment controllers communicatively coupled to the network.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '4\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '5\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.', 'FIG.', '6\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.\n \nFIG.', '7\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Systems and methods and/or processes according to one or more aspects of the present disclosure may be used or performed in connection with well construction operations, such as at a well site for constructing a well to obtain hydrocarbons (e.g., oil and/or gas) from a formation.', 'For example, some aspects may be described in the context of drilling a wellbore in the oil and gas industry.', 'One or more aspects of the present disclosure may be applied in other contexts, such as for any construction operations.', 'One or more aspects of the present disclosure may permit automated, real-time analysis of current and/or projected downhole conditions in operating a well construction process, which may further analyze surface conditions in some example implementations.', 'One or more aspects of the present disclosure may also permit automated, real-time alteration of the operation of the well construction process based on the analysis.', 'Based on such analysis and alteration, communications made between a surface acquisition module and downhole equipment may be made more efficiently, and/or operations of the well construction process may be performed more effectively and/or efficiently.', 'In some example implementations, a quality of a communication between downhole equipment and a surface acquisition module may be determined, and a change in the operation of the well construction process may be made to improve a quality of a subsequent communication between the downhole equipment and the surface acquisition module.', 'In some example implementations, an operation of a job plan and/or command can be analyzed to determine and/or project an effect on communications between downhole equipment and a surface acquisition module, and a change in the operation may be made to reduce and/or prevent the effect on the communications.', 'In some example implementations, downhole data relating to conditions in the wellbore (e.g., whether obtained and/or originating from downhole equipment or surface equipment), with or without other surface data, may be used to determine how to more effectively and/or efficiently operate the well construction process, and a change in the operation of the well construction process may be made to implement the more effective and/or efficient operation.', 'Various aspects disclosed herein may be used together or independent from other aspects disclosed herein, and various aspects may be modified.', 'Such use of aspects and modifications are within the scope of the present disclosure.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of a well construction system \n100\n operable to drill a wellbore \n104\n into one or more subsurface formations \n102\n at a well site in accordance with one or more aspects of the present disclosure.', 'A drillstring \n106\n penetrates the wellbore \n104\n and includes a bottom hole assembly (BHA) \n108\n that comprises or is mechanically and hydraulically coupled to a drill bit \n110\n.', 'The well construction system \n100\n includes a mast \n114\n (at least a portion of which is depicted in \nFIG.', '1\n) extending from a rig floor \n112\n that is erected over the wellbore \n104\n.', 'A top drive \n116\n is suspended from the mast \n114\n and is mechanically coupled to the drillstring \n106\n.', 'The top drive \n116\n provides a rotational force (e.g., torque) to drive rotational movement of the drillstring \n106\n, such as to advance the drillstring \n106\n into the one or more subsurface formations \n102\n to form the wellbore \n104\n.', 'The top drive \n116\n is suspended from the mast \n114\n via hoisting equipment.', 'The hoisting equipment includes a traveling block \n118\n with a hook \n120\n, a crown block \n122\n, a drawworks \n124\n, a deadline anchor \n126\n, a supply reel (not depicted), and a drill line \n128\n with a deadline \n130\n (a portion of which is shown in phantom).', 'The hook \n120\n of the traveling block \n118\n mechanically couples with the top drive \n116\n, although other means for coupling the traveling block \n118\n with the top drive \n116\n are also within the scope of the present disclosure.', 'The crown block \n122\n is suspended from, coupled with, and/or otherwise supported by the mast \n114\n.', 'The drawworks \n124\n and the deadline anchor \n126\n are on and supported by the rig floor \n112\n.', 'The drill line \n128\n is supplied from the supply reel through the deadline anchor \n126\n.', 'The drill line \n128\n may be wrapped around and clamped at the deadline anchor \n126\n such that the drill line \n128\n that extends from the deadline anchor \n126\n to the crown block \n122\n is stationary during normal drilling operations, and hence, the portion of the drill line \n128\n that extends from the deadline anchor \n126\n to the crown block \n122\n is referred to as the deadline \n130\n.', 'The crown block \n122\n and traveling block \n118\n comprise one or more pulleys or sheaves.', 'The drill line \n128\n is reeved around the pulleys or sheaves of the crown block \n122\n and the traveling block \n118\n.', 'The drill line \n128\n extends from the crown block \n122\n to the drawworks \n124\n.', 'The drawworks \n124\n can comprise a drum, a prime mover (e.g., an engine or motor), a control system, and one or more brakes, such as a mechanical brake (e.g., a disk brake), an electrodynamic brake, and/or the like.', 'The prime mover of the drawworks \n124\n drives the drum to rotate and reel in drill line \n128\n, which in turn causes the traveling block \n118\n and top drive \n116\n to move upward.', 'The drawworks \n124\n can reel out drill line \n128\n by a controlled rotation of the drum using the prime mover and control system, and/or by disengaging the prime mover (such as with a clutch) and disengaging and/or operating one or more brakes to control the release of the drill line \n128\n.', 'By unreeling drill line \n128\n from the drawworks \n124\n, the traveling block \n118\n and top drive \n116\n may move downward.', 'Implementations within the scope of the present disclosure include land-based rigs, as depicted in \nFIG.', '1\n, as well as offshore implementations.', 'In offshore implementations, the hoisting equipment may also include a motion or heave compensator between the mast \n114\n and the crown block \n122\n and/or between the traveling block \n118\n and the hook \n120\n, for example.', 'The top drive \n116\n includes a drive shaft \n132\n, a pipe handling assembly \n134\n with an elevator \n136\n, and various other components not shown in \nFIG.', '1\n, such as a prime mover and a grabber.', 'The drillstring \n106\n is mechanically coupled to the drive shaft \n132\n (e.g., with or without a sub saver between the drillstring \n106\n and the drive shaft \n132\n).', 'The prime mover drives the drive shaft \n132\n, such as through a gearbox or transmission, to rotate the drive shaft \n132\n and, therefore, the drillstring \n106\n, such as to advance the drillstring \n106\n into the one or more subsurface formations \n102\n to form the wellbore \n104\n.', 'The pipe handling assembly \n134\n and elevator \n136\n permit the top drive \n116\n to handle tubulars (e.g., single, double, or triple stands of drill pipe and/or casing) that are not mechanically coupled to the drive shaft \n132\n.', 'The grabber includes a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft \n132\n.', 'A guide system (e.g., rollers, rack-and-pinion elements, and/or other mechanisms) includes a guide \n140\n affixed or integral to the mast \n114\n and portions \n138\n integral to or otherwise carried with the top drive \n116\n up and down the guide \n140\n.', 'The guide system may provide torque reaction, such as to prevent rotation of the top drive \n116\n while the prime mover is rotating the drive shaft \n132\n.', 'The guide system may also or instead aid in maintaining alignment of the top drive \n116\n with an opening \n113\n in the rig floor \n112\n through which the drillstring \n106\n extends.', 'A drilling fluid circulation system circulates oil-based mud (OBM), water-based mud (WBM), and/or other drilling fluid to the drill bit \n110\n.', 'A pump \n142\n delivers drilling fluid through, for example, a discharge line \n144\n, a standpipe \n146\n, and a rotary hose \n148\n to a port \n150\n of the top drive \n116\n.', 'The drilling fluid is then conducted through the drillstring \n106\n to the drill bit \n110\n, exiting into the wellbore \n104\n via ports in the drill bit \n110\n.', 'The drilling fluid then circulates upward through an annulus \n152\n defined between the outside of the drillstring \n106\n and the wall of the wellbore \n104\n.', 'In this manner, the drilling fluid lubricates the drill bit \n110\n and carries formation cuttings up to the surface as the drilling fluid is circulated.', 'At the surface, the drilling fluid may be processed for recirculation.', 'For example, the drilling fluid may flow through a blowout preventer \n154\n and a bell nipple \n156\n that diverts the drilling fluid to a return flowline \n158\n.', 'The return flowline \n158\n may direct the drilling fluid to a shale shaker \n160\n that removes at least large formation cuttings from the drilling fluid.', 'The drilling fluid may then be directed to reconditioning equipment \n162\n, such as may remove gas and/or finer formation cuttings from the drilling fluid.', 'The reconditioning equipment \n162\n can include a desilter, a desander, a degasser, and/or other components.', 'After treatment by the reconditioning equipment \n162\n, the drilling fluid may be conveyed to one or more mud tanks \n164\n.', 'Intermediate mud tanks may also be used to hold drilling fluid before and/or after the shale shaker \n160\n and/or various ones of the reconditioning equipment \n162\n.', 'The mud tank(s) \n164\n can include an agitator to assist in maintaining uniformity (e.g., homogeneity) of the drilling fluid contained therein.', 'A hopper (not depicted) may be disposed in a flowline between the mud tank(s) \n164\n and the pump \n142\n to disperse an additive, such as caustic soda, in the drilling fluid.', 'A catwalk \n166\n can be used to convey tubulars from a ground level to the rig floor \n112\n.', 'The catwalk \n166\n has a horizontal portion \n167\n and an inclined portion \n168\n that extends between the horizontal portion \n167\n and the rig floor \n112\n.', 'A skate \n169\n may be positioned in a groove and/or other alignment means in the horizontal and inclined portions of the catwalk \n166\n.', 'The skate \n169\n can be driven along the groove by a rope, chain, belt, and/or other pulley system (not depicted), thereby pushing tubulars up the inclined portion \n168\n of the catwalk \n166\n to a position at or near the rig floor \n112\n for subsequent engagement by the elevator \n136\n of the top drive \n116\n and/or other pipe handling means.', 'However, other means for transporting tubulars from the ground to the rig floor \n112\n are also within the scope of the present disclosure.', 'One or more pipe racks may also adjoin the horizontal portion \n167\n of the catwalk \n166\n, and may have a spinner unit and/or other means for transferring tubulars to the horizontal portion \n167\n of the catwalk \n166\n in a mechanized and/or automated manner.', 'An iron roughneck \n170\n is also disposed on the rig floor \n112\n.', 'The iron roughneck \n170\n comprises a spinning system \n172\n and a torque wrench comprising a lower tong \n174\n and an upper tong \n176\n.', 'The iron roughneck \n170\n is moveable (e.g., in a translation movement \n178\n) to approach the drillstring \n106\n (e.g., for making up and/or breaking out a connection of the drillstring \n106\n) and to move clear of the drillstring \n106\n.', 'The spinning system \n172\n applies low-torque spinning to threadedly engage or disengage a threaded connection between tubulars of the drillstring \n106\n, and the torque wrench applies a higher torque to ultimately make up or initially break out the threaded connection.', 'Manual, mechanized, and/or automated slips \n180\n are also disposed on and/or in the rig floor \n112\n.', 'The drillstring \n106\n extends through the slips \n180\n.', 'In mechanized and/or automated implementations of the slips \n180\n, the slips \n180\n can be actuated between open and closed positions.', 'In the open position, the slips \n180\n permit advancement of the drillstring \n106\n through the slips \n180\n.', 'In the closed position, the slips \n180\n clamp the drillstring \n106\n to prevent advancement of the drillstring \n106\n, including with sufficient force to support the weight of the drillstring \n106\n suspended in the wellbore \n104\n.', 'To form the wellbore \n104\n (e.g., “make hole”), the hoisting equipment lowers the top drive \n116\n, and thus the drillstring \n106\n suspended from the top drive \n116\n, while the top drive \n116\n rotates the drillstring \n106\n.', 'During this advancement of the drillstring \n106\n, the slips \n180\n are in the open position, and the iron roughneck \n170\n is clear of the drillstring \n106\n.', 'When the upper end of the tubular in the drillstring \n106\n that is made up to the top drive \n116\n nears the slips \n180\n, the hoisting equipment ceases downward movement of the top drive \n116\n, the top drive \n116\n ceases rotating the drillstring \n106\n, and the slips \n180\n close to clamp the drillstring \n106\n.', 'The grabber of the top drive \n116\n clamps the upper portion of the tubular made up to the drive shaft \n132\n.', 'The drive shaft \n132\n is driven via operation of the prime mover of the top drive \n116\n to break out the connection between the drive shaft \n132\n and the drillstring \n106\n.', 'The grabber of the top drive \n116\n then releases the tubular of the drillstring \n106\n, and the hoisting equipment raises the top drive \n116\n clear of the “stump” of the drillstring \n106\n extending upward from the slips \n180\n.', 'The elevator \n136\n of the top drive \n116\n is then pivoted away from the drillstring \n106\n towards another tubular extending up through the rig floor \n112\n via operation of the catwalk \n166\n.', 'The elevator \n136\n and the hoisting mechanism are then operated to grasp the additional tubular with the elevator \n136\n.', 'The hoisting equipment then raises the additional tubular, and the elevator \n136\n and the hoisting equipment are then operated to align and lower the bottom end of the additional tubular to proximate the upper end of the stump.', 'The iron roughneck \n170\n is moved \n178\n toward the drillstring \n106\n, and the lower tong \n174\n clamps onto the stump of the drillstring \n106\n.', 'The spinning system \n172\n then rotates the suspended tubular to engage a threaded (e.g., male) connector with a threaded (e.g., female) connector at the top end of the stump.', 'Such spinning continues until achieving a predetermined torque, number of spins, vertical displacement of the additional tubular relative to the stump, and/or other operational parameters.', 'The upper tong \n176\n then clamps onto and rotates the additional tubular with a higher torque sufficient to complete making up the connection with the stump.', 'In this manner, the additional tubular becomes part of the drillstring \n106\n.', 'The iron roughneck \n170\n then releases the drillstring \n106\n and is moved \n178\n clear of the drillstring \n106\n.', 'The grabber of the top drive \n116\n then grasps the drillstring \n106\n proximate the upper end of the drillstring \n106\n.', 'The drive shaft \n132\n is moved into contact with the upper end of the drillstring \n106\n and is rotated via operation of the prime mover to make up a connection between the drillstring \n106\n and the drive shaft \n132\n.', 'The grabber then releases the drillstring \n106\n, and the slips \n180\n are moved into the open position.', 'Drilling may then resume.\n \nFIG.', '1\n also depicts a pipe handling manipulator (PHM) \n182\n and a fingerboard \n184\n disposed on the rig floor \n112\n, although other implementations within the scope of the present disclosure may include one or both of the PHM \n182\n and the fingerboard \n184\n located elsewhere or excluded.', 'The fingerboard \n184\n provides storage (e.g., temporary storage) of tubulars \n194\n, such that the PHM \n182\n can be operated to transfer the tubulars \n194\n from the fingerboard \n184\n for inclusion in the drillstring \n106\n during drilling or tripping-in operations, instead of (or in addition to) from the catwalk \n166\n, and similarly for transferring tubulars \n194\n removed from the drillstring \n106\n to the fingerboard \n184\n during tripping-out operations.', 'The PHM \n182\n includes arms and clamps \n186\n collectively operable for grasping and clamping onto a tubular \n194\n while the PHM \n182\n transfers the tubular \n194\n to and from the drillstring \n106\n, the fingerboard \n184\n, and the catwalk \n166\n.', 'The PHM \n182\n is movable in at least one translation direction \n188\n and/or a rotational direction \n190\n around an axis of the PHM \n182\n.', 'The arms of the PHM \n182\n can extend and retract along direction \n192\n.', 'The tubulars \n194\n conveyed to the rig floor \n112\n via the catwalk \n166\n (such as for subsequent transfer by the elevator \n136\n and/or the PHM \n182\n to the drillstring \n106\n and/or the fingerboard \n184\n) may be single joints and/or double- or triple-joint stands assembled prior to being fed onto the catwalk \n166\n.', 'In other implementations, the catwalk \n166\n may include means for making/breaking the multi-joint stands.', 'The multi-joint stands may also be made up and/or broken out via cooperative operation of two or more of the top drive \n116\n, the drawworks \n124\n, the elevator \n136\n, the catwalk \n166\n, the iron roughneck \n170\n, the slips \n180\n, and the PHM \n182\n.', 'For example, the catwalk \n166\n may position a first joint (drill pipe, casing, etc.) to extend above the rig floor \n112\n or another orientation where the joint can be grasped by the elevator \n136\n.', 'The top drive \n116\n, the drawworks \n124\n, and the elevator \n136\n may then cooperatively transfer the first joint into the wellbore \n104\n, where the slips \n180\n may retain the first joint.', 'The catwalk \n166\n may then position a second joint that will be made up with the first joint.', 'The top drive \n116\n, the drawworks \n124\n, and the elevator \n136\n may then cooperatively transfer the second joint to proximate the upper end of the first joint extending up from the slips \n180\n.', 'The iron roughneck \n170\n may then make up the first and second joints to form a double stand.', 'The top drive \n116\n, the drawworks \n124\n, the elevator \n136\n, and the slips \n180\n may then cooperatively move the double stand deeper into the wellbore \n104\n, and the slips \n180\n may retain the double stand such that an upper end of the second joint extends upward.', 'If the contemplated drilling, casing, or other operations are to utilize triple stands, the catwalk \n166\n may then position a third joint to extend above the rig floor \n112\n, and the top drive \n116\n, the drawworks \n124\n, and the elevator \n136\n may then cooperatively transfer the third joint to proximate the upper end of the second joint extending up from the slips \n180\n.', 'The iron roughneck \n170\n may then make up the second and third joints to form a triple stand.', 'The top drive \n116\n (or the elevator \n136\n) and the drawworks \n124\n may then cooperatively lift the double or triple stand out of the wellbore \n104\n.', 'The PHM \n182\n may then transfer the stand from the top drive \n116\n (or the elevator \n136\n) to the fingerboard \n184\n, where the stand may be stored until retrieved by the PHM \n182\n for the drilling, casing, and/or other operations.', 'This process of assembling stands may generally be performed in reverse to disassemble the stands.', 'A power distribution center \n196\n is also at the well site.', 'The power distribution center \n196\n includes one or more generators, one or more AC-to-DC power converters, one or more DC-to-AC power inverters, one or more hydraulic systems, one or more pneumatic systems, the like, or a combination thereof.', 'The power distribution center \n196\n can distribute AC and/or DC electrical power to various motors, pumps, or the like that are throughout the well construction system \n100\n.', 'Similarly, the power distribution center \n196\n can distribute pneumatic and/or hydraulic power throughout the well construction system \n100\n.', 'Components of the power distribution center \n196\n can be centralized in the well construction system \n100\n or can be distributed throughout the well construction system \n100\n.', 'A control center \n198\n is also at the well site.', 'The control center \n198\n houses one or more processing systems of a network of the well construction system \n100\n.', 'Details of the network of the well construction system \n100\n are described below.', 'Generally, various equipment of the well construction system \n100\n, such as the drilling fluid circulation system, the hoisting equipment, the top drive \n116\n, the PHM \n182\n, the catwalk \n166\n, etc., can have various sensors and controllers to monitor and control the operations of that equipment.', 'Additionally, the control center \n198\n can receive information regarding the formation and/or downhole conditions from modules and/or components of the BHA \n108\n.', 'The BHA \n108\n can comprise various components with various capabilities, such as measuring, processing, and storing information.', 'A telemetry device can be in the BHA \n108\n to enable communications with surface equipment (which includes a surface acquisition module that receives communications from the telemetry device), such as at the control center \n198\n.', 'The BHA \n108\n shown in \nFIG.', '1\n is depicted as having a modular construction with specific components in certain modules.', 'However, the BHA \n108\n may be unitary or select portions thereof may be modular.', 'The modules and/or the components therein may be positioned in a variety of configurations throughout the BHA \n108\n.', 'The BHA \n108\n may comprise a measurement while drilling (MWD) module \n200\n that may include tools operable to measure wellbore trajectory, wellbore temperature, wellbore pressure, and/or other example properties.', 'The BHA \n108\n may comprise a sampling while drilling (SWD) system comprising a sample module \n202\n for communicating a formation fluid through the BHA \n108\n and obtaining a sample of the formation fluid.', 'The SWD system may comprise gauges, sensor, monitors and/or other devices that may also be utilized for downhole sampling and/or testing of a formation fluid.', 'The BHA \n108\n may comprise a logging while drilling (LWD) module \n204\n that may include tools operable to measure formation parameters and/or fluid properties, such as resistivity, porosity, permeability, sonic velocity, optical density, pressure, temperature, and/or other example properties.', 'A person having ordinary skill in the art will readily understand that a well construction system may include more or fewer equipment than as described herein and/or depicted in the figures.', 'Additionally, various equipment and/or systems of the example implementation of the well construction system \n100\n depicted in \nFIG.', '1\n may include more or fewer equipment.', 'For example, various engines, motors, hydraulics, actuators, valves, or the like that were not described above and/or depicted in \nFIG.', '1\n may be included in other implementations of equipment and/or systems also within the scope of the present disclosure.', 'Additionally, the well construction system \n100\n of \nFIG.', '1\n may be implemented as a land-based rig or on an offshore rig.', 'One or more aspects of the well construction system \n100\n of \nFIG.', '1\n may be incorporated in and/or omitted from a land-based rig or an offshore rig.', 'Such modifications are within the scope of the present disclosure.', 'Even further, one or more equipment and/or systems of the well construction system \n100\n of \nFIG.', '1\n may be transferrable via a land-based movable vessel, such as a truck and/or trailer.', 'As examples, each of the following equipment and/or systems may be transferrable by a separate truck and trailer combination: the mast \n114\n, the PHM \n182\n (and associated frame), the drawworks \n124\n, the fingerboard \n184\n, the power distribution center \n196\n, the control center \n198\n, and mud tanks \n164\n (and associated pump \n142\n, shale shaker \n160\n, and reconditioning equipment \n162\n), the catwalk \n166\n, etc.', 'Some of the equipment and/or systems may be collapsible to accommodate transfer on a trailer.', 'For example, the mast \n114\n, the fingerboard \n184\n, the catwalk \n166\n, and/or other equipment and/or systems may be telescopic, folding, and/or otherwise collapsible.', 'Other equipment and/or systems may be collapsible by other techniques, or may be separable into subcomponents for transportation purposes.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of a well construction system \n250\n operable to drill a wellbore \n104\n into one or more subsurface formations \n102\n at a well site in accordance with one or more aspects of the present disclosure.', 'Some of the components and operation of those components are common (as indicated by usage of common reference numerals) between the well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively.', 'Hence, discussion of the common components may be omitted here for brevity, although a person of ordinary skill in the art will readily understand the components and their operation, with any modification, in the well construction system \n250\n of \nFIG.', '2\n.', 'The well construction system \n250\n includes a mast \n114\n (at least a portion of which is depicted in \nFIG.', '2\n) extending from a rig floor \n252\n that is erected over the wellbore \n104\n.', 'A swivel \n256\n and kelly \n254\n are suspended from the mast \n114\n and are mechanically coupled to the drillstring \n106\n.', 'A kelly spinner is between the kelly \n254\n and the swivel \n256\n, although not specifically illustrated.', 'The kelly \n254\n extends through an opening \n112\n through a master bushing (not specifically depicted) in the rig floor \n252\n and a kelly bushing \n258\n that engages the master bushing and the kelly \n254\n.', 'The rig floor \n252\n includes a rotary table that includes the master bushing and a prime mover.', 'The prime mover of the rotary table, through the master bushing and the kelly bushing \n258\n, provides a rotational force (e.g., torque) to drive rotational movement of the drillstring \n106\n, such as to advance the drillstring \n106\n into the one or more subsurface formations \n102\n to form the wellbore \n104\n.', 'The well construction system \n250\n includes hoisting equipment similar to what is depicted in \nFIG.', '1\n and described above.', 'The hook \n120\n of the traveling block \n118\n mechanically couples with the swivel \n256\n, although other means for coupling the traveling block \n118\n with the swivel \n256\n are also within the scope of the present disclosure.', 'The drawworks \n124\n and the deadline anchor \n126\n are on and supported by the rig floor \n252\n.', 'The well construction system \n250\n includes a drilling fluid circulation system similar to what is depicted in \nFIG.', '1\n and described above.', 'The pump \n142\n delivers drilling fluid through, for example, a discharge line \n144\n, a standpipe \n146\n, and a rotary hose \n148\n to a port \n150\n of the swivel \n256\n.', 'The drilling fluid is then conducted through the kelly \n254\n and the drillstring \n106\n to the drill bit \n110\n, exiting into the wellbore \n104\n via ports in the drill bit \n110\n.', 'The drilling fluid then circulates upward through the annulus \n152\n defined between the outside of the drillstring \n106\n and the wall of the wellbore \n104\n.', 'The drilling fluid can be passed through, e.g., a shale shaker \n160\n, reconditioning equipment \n162\n, one or more mud tanks \n164\n, pump \n142\n, and/or other equipment, as described above.', 'Although not illustrated, tongs, a cathead, and/or a spinning wrench or winch spinning system may be used for making up and/or breaking out connections of tubulars.', 'A winch spinning system may include a chain, rope, or the like that is driven by a winch.', 'The spinning wrench or winch spinning system can be used to apply low torque spinning to make up and/or break out a threaded connection between tubulars of the drillstring \n106\n.', 'For example, with a winch spinning system, a roughneck can wrap a chain around a tubular, and the chain is pulled by the winch to spin the tubular to make up and/or break out a connection.', 'The tongs and cathead can be used to apply a high torque to make up and/or break out the threaded connection.', 'For example, a roughneck can manually apply tongs on tubulars, and the cathead mechanically coupled to the tongs (such as by chains) can apply a high torque to make up and/or break out the threaded connection.', 'Additionally, removable slips may be used in securing the drillstring \n106\n when making up and/or breaking out a connection.', 'The removable slips may be placed by a roughneck between the drillstring \n106\n and the rig floor \n252\n and/or master bushing of the rotary table to suspend the drillstring \n106\n in the wellbore \n104\n.', 'To form the wellbore \n104\n (e.g., “make hole”), the hoisting equipment lowers the drillstring \n106\n while the rotary table, through the master bushing and kelly bushing \n258\n, rotates the drillstring \n106\n.', 'During this advancement of the drillstring \n106\n, the removable slips are removed, and the tongs are clear of the drillstring \n106\n.', 'When the upper end of the kelly \n254\n nears the kelly bushing \n258\n and/or rig floor \n252\n, the rotary table ceases rotating the drillstring \n106\n.', 'The hoisting equipment raises the kelly \n254\n until the upper end of the drillstring \n106\n protrudes from the master bushing and/or rig floor \n252\n, and the slips are placed between the drillstring \n106\n and the master bushing and/or rig floor \n252\n to clamp the drillstring \n106\n.', 'When the kelly \n254\n is raised, a flange at the bottom of the kelly \n254\n can grasp the kelly bushing \n258\n to clear the kelly bushing \n258\n from the master bushing.', 'Roughnecks then can break out the connection between the kelly \n254\n and the drillstring \n106\n using the tongs and cathead for applying a high torque, and the prime mover of the rotary table can cause the drillstring \n106\n to rotate to spin out of the connection to the kelly \n254\n, for example.', 'A tubular may be positioned in preparation to being made up to the kelly \n254\n and the drillstring \n106\n.', 'For example, a tubular may be manually transferred to a mouse hole in the rig floor \n252\n.', 'Other methods and systems for transferring a tubular may be used.', 'With the connection between the drillstring \n106\n and the kelly \n254\n broken out, the hoisting equipment maneuvers the kelly \n254\n into a position such that a connection between the kelly \n254\n and the tubular projecting through the mouse hole can be made up.', 'Roughnecks then can make up the connection between the kelly \n254\n and the tubular by spinning the kelly \n254\n with the kelly spinner to apply a low torque and by using the tongs and cathead to apply a high torque.', 'The hoisting equipment then raises and maneuvers the kelly \n254\n and attached tubular into a position such that a connection between the attached tubular and drillstring \n106\n can be made up.', 'Roughnecks then can make up the connection between the tubular and the drillstring \n106\n by clamping one of the tongs to the tubular and spinning the kelly \n254\n with the kelly spinner to apply a low torque and by using the tongs and cathead to apply a high torque.', 'The slips are then removed, and the drillstring \n106\n and kelly \n254\n are lowered by the hoisting equipment until the drill bit \n110\n engages the one or more subsurface formations \n102\n.', 'The kelly bushing \n258\n engages the master bushing and the kelly \n254\n, and the prime mover of the rotary table beings providing rotational movement to the drillstring \n106\n to resume drilling.', 'A power distribution center \n196\n and control center \n198\n are also at the well site as described above.', 'The control center \n198\n houses one or more processing systems of a network of the well construction system \n250\n.', 'Details of the network of the well construction system \n250\n are described below.', 'Generally, various equipment of the well construction system \n250\n, such as the drilling fluid circulation system, the hoisting equipment, the rotary table, etc., can have various sensors and controllers to monitor and control the operations of that equipment.', 'Additionally, the control center \n198\n can receive information regarding the formation and/or downhole conditions from modules and/or components of the BHA \n108\n.', 'The BHA \n108\n can comprise various components with various capabilities, such as measuring, processing, and storing information, as described above.', 'A person having ordinary skill in the art will readily understand that a well construction system may include more or fewer equipment than as described herein and/or depicted in the figures.', 'Additionally, various equipment and/or systems of the example implementation of the well construction system \n250\n depicted in \nFIG.', '2\n may include more or fewer equipment.', 'For example, various engines, motors, hydraulics, actuators, valves, or the like that were not described above and/or depicted in \nFIG.', '2\n may be included in other implementations of equipment and/or systems also within the scope of the present disclosure.', 'Additionally, the well construction system \n250\n of \nFIG.', '2\n may be implemented as a land-based rig or on an offshore rig.', 'One or more aspects of the well construction system \n250\n of \nFIG.', '2\n may be incorporated in and/or omitted from a land-based rig or an offshore rig.', 'Such modifications are within the scope of the present disclosure.', 'Even further, one or more equipment and/or systems of the well construction system \n250\n of \nFIG.', '2\n may be transferrable via a land-based movable vessel, such as a truck and/or trailer.', 'As examples, each of the following equipment and/or systems may be transferrable by a separate truck and trailer combination: the mast \n114\n, the drawworks \n124\n, the fingerboard \n184\n, the power distribution center \n196\n, the control center \n198\n, and mud tanks \n164\n (and associated pump \n142\n, shale shaker \n160\n, and reconditioning equipment \n162\n), etc. Some of the equipment and/or systems may be collapsible to accommodate transfer on a trailer.', 'For example, the mast \n114\n, the fingerboard \n184\n, and/or other equipment and/or systems may be telescopic, folding, and/or otherwise collapsible.', 'Other equipment and/or systems may be collapsible by other techniques, or may be separable into subcomponents for transportation purposes.', 'The well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively, illustrate various example equipment and systems that may be incorporated in a well construction system.', 'Various other example well construction systems may include any combination of equipment and systems described with respect to the well construction systems \n100\n and \n250\n of \nFIGS.', '1 and 2\n, respectively, and may omit some equipment and/or systems and/or include additional equipment and/or systems not specifically described herein.', 'Such well construction systems are within the scope of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of a simplified operations network \n300\n of a well construction system according to one or more aspects of the present disclosure.', 'The physical network used to implement the operations network \n300\n of \nFIG.', '3\n can have any network topology, such as a bus topology, a ring topology, a star topology, mesh topology, etc.', 'The operations network \n300\n can include one or more processing systems, such as one or more network appliances, on and/or through which various aspects of the operations network \n300\n of \nFIG.', '3\n operate.', 'Various other processing systems, such as ones that implement one or more switches, gateways, and/or other functionality, can be implemented in the operations network and are within the scope of the present disclosure.', 'A person having ordinary skill in the art will readily understand how such processing systems and functionality may be implemented.', 'The operations network \n300\n includes a common data bus \n302\n.', 'In some examples, components communicatively coupled to the common data bus \n302\n can communicate using a common protocol, such as OPC, OPC UA, data distribution service (DDS) protocol, or other example protocols.', 'The common data bus \n302\n can comprise or be implemented by a physical network, one or more software programs on one or more processing systems, and/or other techniques.', 'Various component that communicate through the common data bus \n302\n can do so by various techniques.', 'For example, multiple components may communicate, such as with any protocol, with a software application on one or more processing systems that translates communications from one or more of those components and implements the common data bus in software to permit one or more of those components to receive the communications from the common data bus.', 'In some examples, each component may have a respective gateway that translates communications to the common protocol and transmits the translated communications through a physical common data bus to another component.', 'In various examples, other techniques and/or combinations of the described example techniques may be implemented, which is within the scope of the present disclosure.', 'The operations network \n300\n includes N number of equipment controllers (ECs) communicatively coupled to the common data bus \n302\n.', 'An EC can include one or a plurality of programmable logic controllers (PLCs), industrial computers, personal computer based controllers, soft PLCs, the like, and/or any example controllers configured and operable to perform sensing of an environmental status and/or control equipment.', 'In some example implementations, an EC may include one or a plurality of programmable logic controller (PLCs) and a communication gateway, in which the communication gateway is used to translate communications between the EC and the common data bus \n302\n.\n \nFIG.', '3\n illustrates an EC-\n1\n \n304\n and an EC-N \n306\n both communicatively coupled to the common data bus \n302\n.', 'The ECs (e.g., EC-\n1\n \n304\n and EC-N \n306\n) can be at least a part of multiple control subsystems, respectively, of the well construction system, an entire control system of the well construction system, and/or any permutation therebetween.', 'Example subsystems include a drilling fluid circulation system (which may include drilling fluid pumps, valves, fluid reconditioning equipment, etc.), a rig control system (which may include hoisting equipment, drillstring rotary mover equipment (such as a top drive and/or rotary table), a PHM, a catwalk, etc.), a managed pressure drilling system, a cementing system, a rig walk system, etc.', 'A subsystem may include a single piece of equipment or may include multiple pieces of equipment, e.g., that are jointly used to perform one or more function.', 'Each subsystem can include one or more ECs.', 'Any number of control subsystems may be implemented, and any number of ECs may be used in any control subsystem.', 'If multiple subsystems are on the same physical network for communication, the subsystems can be segmented from each other, such as by implementing respective virtual networks and/or domain designation.', 'Further, in some examples, a gateway may be disposed between a subsystem (e.g., an EC of the subsystem) and the common data bus \n302\n to translate communications, and in other examples, a gateway is not between a subsystem (e.g., an EC of the subsystem) and the common data bus \n302\n, such as when the subsystem implements the common protocol that is used through the common data bus \n302\n.', 'The ECs are communicatively coupled to one or more sensors and/or one or more actuators.', 'By being communicatively coupled to one or more actuators, the ECs may be operable to control equipment, for example.', 'By being communicatively coupled to one or more sensors, the ECs may be operable to receive sensor and/or status data from sensors, for example.', 'In the illustrated example of \nFIG.', '3\n, the EC-\n1\n \n304\n is communicatively coupled to sensor(s) and/or actuator(s) \n308\n, and the EC-N \n306\n is communicatively coupled to sensor(s) and/or actuator(s) \n310\n.', 'Each EC can implement logic to monitor and/or control one or more sensors and/or one or more controllable equipment.', 'Each EC can include logic to interpret a command and/or other data and to communicate a signal to one or more controllable equipment to control the one or more controllable equipment in response to the command and/or other data.', 'Each EC can also receive a signal from one or more sensors, can reformat the signal, such as from an analog signal to a digital signal, into interpretable data.', 'The logic for each EC can be programmable, such as compiled from a low level programming language, such as described in IEC 61131 programming languages for PLCs, structured text, ladder diagram, functional block diagrams, and/or functional charts; a high level programming language, such as C or C++; and/or other example programming languages.', 'Further in the illustrated example of \nFIG.', '3\n, a downhole system is an example sensor system of the drilling system and is communicatively coupled to the common data bus \n302\n.', 'The downhole system includes a surface acquisition module \n312\n (e.g., at least a portion of surface equipment) that is communicatively coupled to the common data bus \n302\n and a downhole communication module \n314\n on a drillstring (e.g., in the BHA \n108\n of the drillstring \n106\n in \nFIGS.', '1 and 2\n).', 'The downhole communication module \n314\n is further communicatively coupled to downhole sensor(s) and/or actuator(s) \n316\n on the drillstring (e.g., in the BHA \n108\n, such as in MWD module \n200\n, sample module \n202\n, and/or LWD module \n204\n).', 'The downhole communication module \n314\n can include a downhole mud-pulse telemetry system, a downhole electromagnetic signal communication system, a transceiver for wired communication, and/or other example communication systems.', 'The surface acquisition module \n312\n can be implemented by or comprise a PLC, an industrial computer, a personal computer, or another processing system, for example, and can include appropriate communication equipment to communicate with the downhole communication module \n314\n, such as a surface mud-pulse telemetry system, a surface electromagnetic signal communication system, a transceiver for wired communication, and/or other example communication systems.', 'As described in additional examples below, the surface acquisition module \n312\n can receive data from the downhole communication module \n314\n, which is further received from the downhole sensors and actuators \n316\n, relating to conditions in the wellbore.', 'This data can be communicated to the common data bus \n302\n from the surface acquisition module \n312\n.', 'Other sensor subsystems can be included in the operations network \n300\n.', 'Any number of sensor subsystems may be implemented.', 'The operations network \n300\n includes a coordinated controller \n318\n, which may be a software program instantiated and operable on one or more processing systems, such as one or more network appliances.', 'The coordinated controller \n318\n may be a software program written in and compiled from a high-level programming language, such as C/C++ or the like.', 'The coordinated controller \n318\n can control operations of subsystems as described in further detail below.', 'The operations network \n300\n also includes one or more human-machine interfaces (HMIs), which as illustrated includes HMI \n320\n.', 'The HMI \n320\n may be, comprise, or be implemented by one or more processing system with a keyboard, a mouse, a touchscreen, a joystick, one or more control switches or toggles, one or more buttons, a track-pad, a trackball, an image/code scanner, a voice recognition system, a display device (such as a liquid crystal display (LCD), a light-emitting diode (LED) display, and/or a cathode ray tube (CRT) display), a printer, speaker, and/or other examples.', 'The HMI \n320\n may permit entry of commands to the coordinated controller \n318\n and/or ECs (e.g., EC-\n1\n \n304\n and EC-N \n306\n) and for visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data.', 'The operations network \n300\n further includes one or more process applications \n322\n, which may be a software program instantiated and operable on one or more processing systems, such as one or more network appliances, such as server devices.', 'The one or more process applications \n322\n may each be a software program written in and compiled from a high-level programming language, such as C/C++ or the like.', 'The one or more process applications \n322\n may monitor operations by analyzing data, e.g., consumed from the common data bus \n302\n, and output information, e.g., a job plan to inform various construction operations.', 'The job plan may include a model for controlling well construction within identified constraints, which can be transmitted to the coordinated controller \n318\n.', 'The job plan may contain an operation sequence for the equipment, which can be transmitted to the coordinated controller \n318\n.', 'The coordinated controller \n318\n can implement the job plan through determining and issuing commands to one or more of the ECs, which then control equipment according to the issued commands.', 'Other configurations of an operations network are also within the scope of the present disclosure.', 'Different numbers of ECs, different numbers of subsystems, and different physical topologies and connections are within the scope of the present disclosure.', 'Additionally, other example implementations may include or omit various components, such as an HMI, a historian database, and/or others, for example.', 'Various aspects described with respect to the operations network \n300\n can be implemented by centralized computing on one processing system, by distributed computing on multiple processing systems, or any permutation therebetween.\n \nFIG.', '4\n is a schematic view of at least a portion of an example implementation of a processing system \n400\n according to one or more aspects of the present disclosure.', 'The processing system \n400\n may execute example machine-readable instructions to implement at least a portion of one or more of the methods and/or processes described herein.', 'The processing system \n400\n may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, server devices, personal computers, network appliances, programmable logic controller (PLC), industrial computer, and/or other types of computing devices.', 'In some examples, each of an EC, surface acquisition module, a coordinated controller, an HMI, and a process application may be implemented by a processing system \n400\n and/or a computer program operating on the processing system \n400\n.', 'Various processing systems \n400\n and functionalities can be in a single device or distributed across multiple devices.', 'The processing system \n400\n comprises a processor \n412\n such as, for example, a general-purpose programmable processor.', 'The processor \n412\n may comprise a local memory \n414\n, and may execute program code instructions \n432\n present in the local memory \n414\n and/or in another memory device.', 'The processor \n412\n may execute, among other things, machine-readable instructions or programs to implement one or more aspects of the methods and/or processes described herein.', 'The programs stored in the local memory \n414\n may include program instructions or computer program code that, when executed by an associated processor, enable one or more aspects of functionality as described herein.', 'The processor \n412\n may be, comprise, or be implemented by one or more processors of various types operable in the local application environment, and may include one or more general purpose processors, special-purpose processors, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), processors based on a multi-core processor architecture, and/or other processors.', 'More particularly, examples of a processor \n412\n include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, embedded soft/hard processors in one or more FPGAs, etc.', 'The processor \n412\n may be in communication with a main memory \n417\n, such as via a bus \n422\n and/or other communication means.', 'The main memory \n417\n may comprise a volatile memory \n418\n and a non-volatile memory \n420\n.', 'The volatile memory \n418\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices.', 'The non-volatile memory \n420\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as read-only memory, flash memory and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n418\n and/or the non-volatile memory \n420\n.', 'The processing system \n400\n may also comprise an interface circuit \n424\n connected and communicatively coupled to the bus \n422\n.', 'The interface circuit \n424\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, and/or a cellular interface, among other examples.', 'The interface circuit \n424\n may also comprise a graphics driver card.', 'The interface circuit \n424\n may also comprise a communication device such as a modem or network interface card to facilitate exchange of data with external computing devices via a network, such as via Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, and/or satellite, among other examples.', 'The interface circuit \n424\n may also be, comprise, or be implemented by one or more of a digital output (DO) circuit, an analog output (AO) circuit, a digital input (DI) circuit, and/or an analog input (AI) circuit, such as when the processing system \n400\n is implemented as an EC.', 'One or more input devices \n426\n may be connected to the interface circuit \n424\n.', 'One or more of the input devices \n426\n may permit a user to enter data and/or commands for utilization by the processor \n412\n.', 'Each input device \n426\n may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an image/code scanner, and/or a voice recognition system, among other examples.', 'One or more output devices \n428\n may also be connected to the interface circuit \n424\n.', 'One or more of the output device \n428\n may be, comprise, or be implemented by a display device, such as LCD, a LED display, and/or a CRT display, among other examples.', 'One or more of the output devices \n428\n may also or instead be, comprise, or be implemented by a printer, speaker, and/or other examples.', 'The processing system \n400\n may also comprise a mass storage device \n430\n for storing machine-readable instructions and data.', 'The mass storage device \n430\n may be connected to the interface circuit \n424\n, such as via the bus \n422\n.', 'The mass storage device \n430\n may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples.', 'The program code instructions \n432\n may be stored in the mass storage device \n430\n, the volatile memory \n418\n, the non-volatile memory \n420\n, the local memory \n414\n, and/or on a removable storage medium \n434\n, such as a CD or DVD.', 'The modules and/or other components of the processing system \n400\n may be implemented in accordance with hardware (such as in one or more integrated circuit chips, such as an ASIC), or may be implemented as software or firmware for execution by a processor.', 'In the case of firmware or software, the implementation can be provided as a computer program product including a computer readable medium or storage structure containing computer program code (i.e., software or firmware) for execution by the processor.', 'The following methods or processes may permit improved efficiency and operation and/or communications of a well construction system.', 'Generally, in some example implementations, current and/or projected downhole conditions, along with possibly surface conditions, and/or an indication of a quality of a communication are used to determine operations of the well construction system at the well site.', 'In some examples, such information may result in continuing planned operations or changing from the operations, such as by delaying an operation, changing parameters of the operation, and/or other changes.', 'The methods or processes are described in the context of devices and components described above, although in other implementations, methods or processes within the scope of this disclosure may be performed in the context of other devices and components.', 'The methods or processes described below are presented in a given order, although other implementations also within the scope of the present disclosure may comprise the described and/or other methods or processes in other orders and/or in parallel.', 'Various other modifications to the methods or processes described below may also be consistent with the scope of the present disclosure.', 'For example, such implementations may include additional or fewer calculations, determinations, computations, logic, and/or other aspects.\n \nFIG.', '5\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n500\n) for implementing operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (\n500\n) includes operating (\n502\n) a well construction process.', 'The well construction process can be, for example, any process used in constructing a well, such as drilling, cementing, and/or other example processes.', 'The operating (\n502\n) can be by using the operations network \n300\n of \nFIG.', '3\n, including using a job plan from the one or more process applications \n322\n, a controller \n318\n to implement a job plan, and ECs (e.g., EC-\n1\n \n304\n and EC-N \n306\n) to receive commands from the controller \n318\n and to control equipment for the well construction process.', 'The method (\n500\n) includes communicating (\n504\n) between a surface acquisition module and downhole equipment, e.g., while the well construction process is continued to be operated (\n502\n).', 'The communication techniques can include mud-pulse telemetry, electromagnetic telemetry, wired communication, and/or other techniques, and such communication can be implemented by appropriate systems.', 'The communications can include communications from the surface acquisition module to the downhole equipment (e.g., downlink communications) and/or communications from the downhole equipment to the surface acquisition module (e.g., uplink communications).', 'The method (\n500\n) includes analyzing (\n506\n) an indication of the quality of communication.', 'In some examples, a surface acquisition module communicates settings and/or commands to the downhole equipment, and the downhole equipment repeats the received settings and/or commands that it received back to the surface acquisition module.', 'In these examples, the indication of the quality of the communication can include how closely what was received by the surface acquisition module matches what was originally transmitted by the surface acquisition module.', 'In other examples, the downhole equipment can determine a quality of communication, such as a strength of a received signal, a signal-to-noise ratio, and/or another quality degrading factor, and can transmit an indication of the quality of the communication to the surface acquisition module.', 'In further examples, the surface acquisition module can determine an indication of a quality of communications received from the downhole equipment, such as a strength of a received signal, a signal-to-noise ratio, and/or another quality degrading factor.', 'If the indication of the quality of the communication indicates that the communication had a low fidelity and/or reliability, the method (\n500\n) proceeds to determining (\n508\n) a change to the operation of the well construction process.', 'The change may be, for example, changing strokes per minute (SPM) of one or more drilling fluid pumps, changing a flow of drilling fluid through one or more valves in the drilling fluid circulation system by changing the extent to which the valve is opened and/or closed, changing rotations per minute (RPM) of the drillstring as rotated by the top drive, operating a drawworks, and/or changing other aspects of other example equipment.', 'In some examples, the determined change may be based on a predetermined list of identified, likely sources of noise, for example.', 'In other examples, an algorithm may be used to correlate noise in the communication with expected noise signals that can result from equipment used in the well construction process.', 'The algorithm may account for what equipment is being operated during the communication and the conditions at the surface and downhole to determine a source of the noise.', 'In some examples, multiple sources of noise may be identified, and a change to one or more of those sources may be determined.', 'For example, a source that is expected to generate the largest amount of noise can have its operation changed to reduce the noise that is generated.', 'In other examples, one or more sources of noise can be changed even if those sources may not be expected to generate the largest amount of noise if, for example, changing those sources may result in a satisfactory quality of communication.', 'Further, in some examples, sources that are expected to generate noise may be changed based on the impact on the well construction process as a result of the change.', 'For example, a change that has the least impact on the well construction process may be determined before a change that has a larger impact on the well construction process.', 'The method (\n500\n) includes changing (\n510\n) the operation of the well construction process as determined (\n508\n).', 'The method (\n500\n) then includes communicating (\n504\n) between the surface acquisition module and the downhole equipment, which may permit looping of some of the method (\n500\n) until communicating (\n504\n) with a satisfactory indication of quality of the communication is achieved, for example.', 'In some examples, different changes of operations may be determined (\n508\n) in different iterations of the loop.', 'For example, different iterations can implement changes starting with a least impact on operations and increasing in impact until a satisfactory indication is achieved.', 'Other techniques for choosing which change to implement may be used.', 'The analyzing (\n506\n), determining (\n508\n), and changing (\n510\n) of method (\n500\n) may be implemented by one or more software programs operating on one or more processing system.', 'For example, the surface acquisition module can include a transducer that can interpret and convert a communication signal from the downhole equipment, such as through mud-pulse telemetry, to a digital signal that is then made available on the common data bus.', 'In some examples, the process application(s) accesses the data signal from the common data bus and analyzes the digital signal to obtain an indication of a quality of the communication, which may be obtained as described above.', 'The process application(s) can then determine what operation to change and can generate an updated job plan, which is communicated to the coordinated controller through the common data bus.', 'The coordinated controller then implements the updated job plan by issuing commands to ECs to control equipment according to the updated job plan, which changes the operation of the well construction process.', 'In some other examples, the coordinated controller accesses the data signal from the common data bus and analyzes the digital signal to obtain an indication of a quality of the communication, which may be obtained as described above.', 'The coordinated controller can then determine what operation to change and implements the change by issuing commands to ECs to control equipment.', 'Other processing system(s) and/or other software application(s) can be used to implement the analyzing (\n506\n), determining (\n508\n), and changing (\n510\n) in other examples.', 'FIG.', '6\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n600\n) for implementing operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (\n600\n) includes identifying (\n602\n) an operation of a well construction process.', 'The identifying (\n602\n) can identify an operation that has not begun but is intended to begin and/or can identify an operation that previously began and is on-going.', 'The well construction process can be, for example, any process used in constructing a well, such as drilling, cementing, and/or other example processes.', 'In a planned operation, the operation can be implemented by using the operations network \n300\n of \nFIG.', '3\n, including using a job plan from the one or more process applications \n322\n, a controller \n318\n to implement a job plan, and ECs (e.g., EC-\n1\n \n304\n and EC-N \n306\n) to receive commands from the controller \n318\n and to control equipment for the well construction process.', 'In an on-the-fly operation, an operator can input data to an HMI \n320\n that is received by the controller \n318\n via the operations network \n300\n, and the controller \n318\n can implement the input as commands transmitted to the ECs for controlling equipment to implement the operation.', 'The identifying (\n602\n) the operation of the well construction process can be based on a job plan and/or commands, which may be for beginning the operation and/or for an on-going operation.', 'The identifying (\n602\n) the operation of the well construction process can include identifying an initial operation based on inputs through an HMI by an operator to begin the operation on-the-fly.', 'The identifying (\n602\n) the operation of the well construction process can similarly include identifying on-going operations controlled at least in part through an HMI by an operator on-the-fly.', 'The method (\n600\n) includes communicating (\n604\n) between a surface acquisition module and downhole equipment, e.g., while the identified operation of the well construction process on-going and/or before the identified operation is initiated.', 'The communication techniques can include mud-pulse telemetry, electromagnetic telemetry, wired communication, and/or other techniques, and such communication can be implemented by appropriate systems.', 'The communications can include communications from the surface acquisition module to the downhole equipment (e.g., downlink communications) and/or communications from the downhole equipment to the surface acquisition module (e.g., uplink communications).', 'The method (\n600\n) includes analyzing (\n606\n) a job plan and/or one or more commands to be executed.', 'The one or more commands can be generated from a job plan and/or based at least in part on input to an HMI by an operator operating on-the-fly.', 'The analyzing (\n600\n) includes projecting and determining whether the job plan and/or one or more commands may affect (e.g., negatively affect) the communicating (\n604\n) between the surface acquisition module and the downhole equipment.', 'For example, initiating and/or increasing SPM of one or more drilling fluid pumps and/or RPM of the top drive can cause more noise in a mud-pulse telemetry signal communicated between the surface acquisition module and the downhole equipment.', 'If the analyzing (\n606\n) projects that the job plan and/or one or more commands may affect the communicating (\n604\n), the method (\n600\n) proceeds to determining (\n608\n) a change to the identified operation of the well construction process.', 'The change may be, for example, rescheduling and/or delaying the identified operation indicated by, for example, the job plan and/or one or more commands.', 'For example, the identified operation of the job plan and/or one or more commands may be rescheduled and/or delayed until after the conclusion of the communicating (\n604\n) such that the operation does not affect the communicating (\n604\n).', 'In other example implementations, the determined change may alter the operation by reducing one or more various levels of activities of the operation to permit the communicating (\n604\n) to be affected within some predetermined limits.', 'For example, a job plan and/or one or more commands may indicate that the SPM of one or more drilling fluid pumps and/or RPM of the top drive is to be increased to a high level, and the change may permit the increase to be to a reduced level that permits the communicating (\n604\n) to be affected, albeit within a predetermined limit of noise.', 'The method (\n600\n) includes changing (\n610\n) the identified operation of the well construction process as determined (\n608\n).', 'The method (\n600\n) then includes communicating (\n604\n) between the surface acquisition module and the downhole equipment, which may permit looping of some of the method (\n600\n) until communicating (\n604\n) is concluded, for example.', 'In some examples, different changes of operations may be determined (\n608\n) in different iterations of the loop.', 'The analyzing (\n606\n), determining (\n608\n), and changing (\n610\n) of method (\n600\n) may be implemented by one or more software programs operating on one or more processing system.', 'In some examples, the process application(s) analyzes the job plan to determine if an operation of the job plan may affect the communication signal between the surface acquisition module and downhole equipment.', 'The process application(s) may access data from the common data bus to determine what the current wellbore conditions are and project what the wellbore conditions may become in response to the operation of the job plan.', 'The process application(s) can then determine how to change the operation and can generate an updated job plan, which is communicated to the coordinated controller through the common data bus.', 'The coordinated controller then implements the updated job plan by issuing commands to ECs to control equipment according to the updated job plan, which changes the operation of the well construction process.', 'In some other examples, the coordinated controller receives a job plan and/or one or more commands from the process application(s) (or received input from an HMI and generates one or more commands based on the received input) and analyzes the job plan and/or one or more commands to determine if an operation of the job plan and/or one or more commands may affect the communication signal between the surface acquisition module and downhole equipment.', 'The coordinated controller may access data from the common data bus to determine what the current wellbore conditions are and project what the wellbore conditions may become in response to the operation of the job plan and/or one or more commands.', 'The coordinated controller can then determine what operation to change and implements the change by issuing commands to ECs to control equipment.', 'Other processing system(s) and/or other software application(s) can be used to implement the analyzing (\n606\n), determining (\n608\n), and changing (\n610\n) in other examples.', 'FIG.', '7\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n700\n) for implementing operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (\n700\n) includes identifying (\n702\n) an operation of a well construction process.', 'The identifying (\n702\n) can identify an operation that has not begun but is intended to begin and/or can identify an operation that previously began and is on-going.', 'The well construction process can be, for example, any process used in constructing a well, such as drilling, cementing, and/or other example processes.', 'In a planned operation, the operation can be implemented by using the operations network \n300\n of \nFIG.', '3\n, including using a job plan from the one or more process applications \n322\n, a controller \n318\n to implement a job plan, and ECs (e.g., EC-\n1\n \n304\n and EC-N \n306\n) to receive commands from the controller \n318\n and to control equipment for the well construction process.', 'In an on-the-fly operation, an operator can input data to an HMI \n320\n that is received by the controller \n318\n via the operations network \n300\n, and the controller \n318\n can implement the input as commands transmitted to the ECs for controlling equipment to implement the operation.', 'The identifying (\n702\n) the operation of the well construction process can be based on a job plan and/or commands, which may be for beginning the operation and/or for an on-going operation.', 'The identifying (\n702\n) the operation of the well construction process can include identifying an initial operation based on inputs through an HMI by an operator to begin the operation on-the-fly.', 'The identifying (\n702\n) the operation of the well construction process can similarly include identifying on-going operations controlled at least in part through an HMI by an operator on-the-fly.', 'The method (\n700\n) includes obtaining (\n704\n) downhole data relating to conditions in the wellbore.', 'Obtaining (\n704\n) the downhole data may include communicating downhole data measured in the wellbore from downhole equipment to a surface acquisition module, which may be before the identified operation of the well construction process is initiated, while the identified operation continues operation, while the identified operation is temporarily paused for the communication, and/or at other states.', 'The communication techniques can include mud-pulse telemetry, electromagnetic telemetry, wired communication, and/or other techniques, and such communication can be implemented by appropriate systems.', 'In some examples, downhole equipment communicates data that is measured in the wellbore.', 'Various MWD, LWD, and/or SWD modules may be used to measure conditions downhole.', 'Obtaining (\n704\n) the downhole data may instead or also include obtaining downhole data from equipment on the surface of the well site, which may be before the identified operation of the well construction process is initiated, while the identified operation continues operation, while the identified operation is temporarily paused for the communication, and/or at other states.', 'This downhole data may be communicated from one or more ECs (e.g., originating from one or more sensors and/or actuators at the surface), which may be in one or more subsystems, through the common data bus.', 'Some example data, e.g., measured in the wellbore and/or obtained from equipment on the surface, can include rotational speed of the drill bit, torque at the drill bit, a stick-slip ratio, annulus fluid pressure, weight-on-bit (WOB), wellbore trajectory, properties of fluid in the wellbore, and other data.', 'The method (\n700\n) includes analyzing (\n706\n) the downhole data.', 'The downhole data, with or without other data acquired at the surface, can be analyzed to determine an efficacy of the identified operation (\n702\n) of the well construction process.', 'As examples, some of which are described in more detail below, torsional vibrations (e.g., stick-slip) may occur during drilling, which may be determined based on analyzing rotational speeds of the drill bit downhole.', 'Other examples are described below, and even more example data and analysis is within the scope of the present disclosure.', 'If the analysis (\n706\n) of the downhole data (e.g., with or without other surface data) indicates poor efficacy of and/or adverse effects caused by the identified operation of the well construction process, the method (\n700\n) proceeds to determining (\n708\n) a change to the identified operation of the well construction process.', 'The change may be, for example, initiating and/or changing SPM of one or more drilling fluid pumps, initiating and/or changing RPM of the top drive, adding and/or altering a concentration of a constituent component of drilling fluid using, e.g., a hopper, operating a drawworks, and/or changing other aspects of other example equipment.', 'The change may include changes to parameters of equipment based, at least in part, on the job plan under which the well construction process is operating and/or parameters determined based on inputs through an HMI from an operator on-the-fly.', 'Various algorithms may be used to determine appropriate remedial action to change the identified operation of the well construction process, some of which are referenced below.', 'The method (\n700\n) includes changing (\n710\n) the identified operation of the well construction process as determined (\n708\n).', 'The changing (\n710\n) may include changing a job plan and/or one or more commands, which may include changing one or more command generated in response to an input through an HMI from an operator controlling the operation on-the-fly.', 'The method (\n700\n) then includes obtaining (\n704\n) downhole data, which may permit looping of some of the method (\n700\n) until an intended result of the well construction process is achieved, for example.', 'The analyzing (\n706\n), determining (\n708\n), and changing (\n710\n) of method (\n700\n) may be implemented by one or more software programs operating on one or more processing system.', 'For example, the surface acquisition module can include a transducer that can interpret and convert a communication signal from the downhole equipment, such as through mud-pulse telemetry, to digital data, e.g., the downhole data, that is then made available on the common data bus.', 'In some examples, the process application(s) accesses the digital data from the common data bus and analyzes the digital data to determine the efficacy of the well construction process, as described above.', 'The process application(s) can then determine what operation to change and can generate an updated job plan, which is communicated to the coordinated controller through the common data bus.', 'The coordinated controller then implements the updated job plan by issuing commands to ECs to control equipment according to the updated job plan, which changes the operation of the well construction process.', 'In some other examples, the coordinated controller accesses the digital data from the common data bus and analyzes the digital data to determine the efficacy of the well construction process, as described above.', 'The coordinated controller can then determine what operation to change and implements the change by issuing commands to ECs to control equipment, which may be to change parameters of the equipment, for example.', 'Other processing system(s) and/or other software application(s) can be used to implement the analyzing (\n706\n), determining (\n708\n), and changing (\n710\n) in other examples.', 'As described above, communications from downhole equipment to a surface acquisition module may be adversely affected by noise, and a processing system according to one or more aspects of the present disclosure may be utilized to identify a source of noise and cause operations to be altered to reduce the effect of that source on the communications.', 'Communication between the surface acquisition module and downhole equipment can be affected by noise generated by various equipment operating on the well construction system.', 'For example, in mud-pulse telemetry implementations, noise may be caused by a pressure variation due to variations in SPM of one or more drilling fluid pumps, which can be caused by power variations that result from the operation of other heavy equipment, such as the drawworks.', 'In electromagnetic telemetry implementations, noise may be a result of electromagnetic interference due to the operation of heavy equipment, such as by an induction motor like the top drive.', 'In some implementations, the mud-pulse or other telemetry may have a communication rate of 10 bits per second or less.', 'In such implementations, among others, noise that can cause a poor signal-to-noise ratio (SNR) can result in failed communications, which can cause the communication process to be repeated, which in turn can delay operations.', 'After commencing communication from the downhole equipment to the surface acquisition module, the surface acquisition module may receive a signal, which may include noise.', 'Once the signal is converted to a digital signal, for example, a processing system according to one or more aspects of the present disclosure may be utilized to analyze the digital signal to determine whether a SNR is too low.', 'The processing system may then determine a probable source of the noise, such as by correlating known noise signatures of various equipment with the data signal.', 'A probable source with a highest correlation between the data signal and the known noise signature of the source may be determined, for example.', 'With the probable source identified, operation of the probable source can be altered to reduce the noise generated by that source.', 'As an example, in mud-pulse telemetry, acoustic noise can be caused by drilling fluid pumps operating within the spectrum of the communication being transmitted from the downhole equipment to the surface acquisition module.', 'The drilling fluid pumps can be identified as a probable source and can be controlled to operate outside of the spectrum of the communications to reduce noise within the communication spectrum.', 'With the noise generating equipment in a state that reduces the noise in the communication, downhole data can be transmitted to the surface acquisition module, which can communicate the data to, for example, the coordinated controller and/or process application(s) through the common data bus.', 'The coordinated controller and/or the process application(s) may also coordinate the operation of equipment to reduce noise in the communication signal.', 'The process application(s) may plan the operation of the well construction system in a way to reduce the noise by altering the operation or by scheduling or delaying the operation of equipment that can cause noise.', 'A payload on equipment may also be determined and used to start and/or stop the top drive.', 'For example, the payload (e.g., reactive torque) on the top drive can depend on a length of the drillstring, the fluid in the wellbore, and the wellbore profile.', 'When turning on a top drive to reach an intended RPM, this payload can affect the operation of the top drive.', 'The payload of a drawworks (e.g., hookload) and/or a drilling fluid system component (e.g., pump pressure) may depend on the drillstring downhole, fluid property, and wellbore information.', 'When starting such equipment, the payload can affect their operation.', 'The coordinated controller may receive the job plan from the process application(s) and/or input from an HMI when an operation is on-the-fly.', 'The coordinated controller may also receive real-time drilling parameters from the drilling control system (such as the length of drillstring in the wellbore), equipment operation parameters, and/or downhole parameters from the downhole system.', 'A payload corresponding to equipment can be calculated or estimated based on the received parameters.', 'Example payloads can be an estimated hookload, an estimated pump pressure, an estimated torque, and/or other example estimated payloads.', 'The estimated payload can be used as an input to operate the equipment, such as the variable frequency drive (VFD) of the top drive, drawworks, drilling fluid pump, etc.', 'For example, a proportional-integral-derivative (PID) controller of the VFD for equipment could be adjusted based on the payload.', 'In this way, for example, when an operator presses the start button to start some equipment or to ramp up the speed of some equipment, e.g., a top drive, the VFD controller of the top drive will use a set of coefficients of the PID controller to run the equipment in a smooth way.', 'By operating the equipment in such a manner, adverse spikes and/or transient effects to the equipment may be reduced and/or avoided, which can reduce wear and tear of the equipment.', 'Further, stick-slip and/or downhole vibration may be reduced and/or avoided, which may improve equipment life and drilling efficiency.', 'Resonant frequencies and/or rotational impedance of a drillstring may also be estimated, and control of drilling can be based on the resonant frequencies and/or rotational impedance, such as to control torsional vibrations (e.g., stick-slip or rotational vibrations).', 'The resonant frequencies and/or rotational impedance can be estimated using data acquired from downhole modules, and/or in some instances, with data acquired from a surface acquisition module.', 'A downhole module can measure oscillations and/or rotational speed of the drill bit, for example.', 'A stick-slip ratio (e.g., a ratio of the max rotational speed minus the minimum rotational speed to two times the average rotational speed) of the drill bit can be determined based on measurements made in the downhole module.', 'Based on the measurements and/or stick-slip ratio, a rotational speed of the top drive can be controlled to reduce torsional vibrations.', 'A process application can calculate the parameters for controlling the top drive, such as by using the estimated resonant frequencies and/or rotational impedance of the drillstring, and the parameters for controlling the top drive can be passed on to the coordinated controller to control drilling.', 'Downhole data may also be used to determine parameters for operation transitions of various equipment.', 'U.S. Patent Publication 2016/0139615, which is incorporated by reference herein in its entirety, includes description of how transitions between set parameters may be made using linear ramps over time periods chosen to reduce and/or avoid exciting strong resonances of the system.', 'Examples of such resonances include the rotational resonances of the drillstring and the hydraulic resonances of the fluid in the annulus.', 'The ramp times can be chosen based on the period of these resonances, and for some operations (for example, starting the drillstring from rest in a deviated well), the ramp times may be implemented based on additional calculations based on torque calculations and/or measurements and based on simulations of drilling dynamics.', 'Examples of set parameters that may benefit from these transitions include drillstring rotation speed, WOB, annular choke back-pressure (e.g., for managed pressure drilling systems), and/or other example parameters.', 'WOB, annulus fluid pressure, etc. may be measured by downhole equipment in some examples.', 'Various calculations can be made by the process application(s), which can choose the appropriate ramp periods.', 'The process application(s) can then pass parameters to the coordinated controller, which determines commands for one or more control systems, and which parameters may reduce and/or avoid exciting resonances.', 'Modulated flow variations from the pumps may also be used to communicate with downhole tools.', 'In such communications, the length of time per bit for the downlink may be adjusted according to how well the flow modulations at surface are reflected in flow modulations measured by equipment near the bit.', 'The transfer function between the surface acquisition module and the downhole equipment may be calculated (e.g., based on fluid type in the drillstring, pressure drops along the drillstring and at the bit, and/or fluid volume inside the drillstring).', 'With the calculated transfer function, the appropriate length of time per bit can be determined.', 'The calculations to calculate the transfer function and the length of time per bit can be performed by the process application(s), and the appropriate flow variation sequence can be communicated to the coordinated controller to implement commands for the control system.', 'As another example for a downlink for communications to a downhole system, U.S. Pat. No. 8,196,678, which is incorporated by reference herein in its entirety, includes description of how pump “over” and “under” shoots may be used during flow modulation sequences in order to improve detectability of flow changes downhole.', 'Appropriate time periods and flow levels for a modulation sequence can include some additional modelling and may also be kept within limits for equipment of the well construction system.', 'Again, these calculations may be performed by the process application(s), with the results being communicated to the coordinated controller to implement commands for the control system.', 'As a further example for “over” and “under” shoots with a hydraulic system, U.S. Patent Publication 2016/0090800, which is incorporated by reference herein in its entirety, includes description of how, when initiating fluid flow in the wellbore, a higher initial flow may be used to reduce the time to when the first survey point can be transmitted to surface.', 'This may be based on a calculation using the properties of the fluid hydraulic system, optionally combined with measurements made during drilling (e.g., the time for the pressure to fall after the pumps are switched off).', "The process application(s) may perform these calculations, may monitor the pumps' off pressure fall, and may monitor the pump state.", 'The process application(s) may therefore identify when the pumps have been switched off and measure the time for the standpipe pressure to fall to a chosen fraction of its initial value.', 'Once the calculations and/or measurements have been made, a pump flow sequence can be calculated and communicated to the coordinated controller to implement commands for the control system.', 'Commands may also be communicated to downhole equipment and repeated back by the downhole equipment to the surface acquisition module, and based on a comparison between the commands transmitted and received by the surface acquisition module, a determination can be made whether to change an operation for better communication between the surface acquisition module and downhole equipment.', 'For example, if the repeated command received at the surface acquisition module matches what was transmitted by the surface acquisition module, operations may continue unaltered, and if there is no match, operations may be altered before communications are retried.', 'Data measured downhole may suffer under some operating conditions, and when such conditions are detected, operation of the well construction can be altered.', 'For example, LWD measurements can be detrimentally affected by drilling at too great of a speed in some situations.', 'When poor measurements are detected, such as by a processing system at the surface and/or by an indication communicated from a downhole module, equipment of the well construction system can be controlled to improve the LWD measurements.', 'For example, a drillstring rotation can be slowed down by controlling a top drive, and/or a WOB may be reduced by controlling a drawworks.', 'These actions can reduce noise that can degrade LWD measurements, and hence, by controlling the top drive and/or drawworks, the LWD measurements may improve.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to: (A) determine a change to an operation of a well construction system based on: (i) an indication of a quality of transmitted communication between downhole equipment of the well construction system in a wellbore and surface communication equipment of the well construction system transmitted during the operation; (ii) a projected effect of the operation on future communication between the downhole equipment and the surface communication equipment; (iii) downhole data related to one or more conditions in the wellbore; or (iv) a combination thereof; and (B) cause the change to the operation of the well construction system to be implemented.', 'The processing system may be a first processing system, the apparatus may further comprise a second processing system communicatively coupled to the first processing system and comprising a processor and a memory including computer program code, the first processing system may be further operable to develop an updated job plan to cause the change to the operation of the well construction system to be implemented, and the second processing system may be operable to interpret the updated job plan and issue one or more commands to one or more equipment controllers of surface equipment to implement the updated job plan.', 'The processing system may be further operable to cause the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of surface equipment.', 'The processing system may be further operable to determine the change to the operation of the well construction system based on surface measurement data not acquired downhole.', 'The determination may be based on the indication of the quality of the transmitted communication, and the indication of the quality may be based on noise in a signal of the transmitted communication.', 'The determination may be based on the indication of the quality of the transmitted communication, and the indication of the quality may be based on a content of the transmitted communication relative to a previous communication.', 'The determination may be based on the projected effect of the operation on the future communication.', 'The projected effect may be based on (i) one or more current conditions in the wellbore, a current state of the well construction system, or a combination thereof, and (ii) a future sequence of the operation.', 'The determination may be based on the downhole data.', 'The downhole data may include measurement data measured in the wellbore.', 'The downhole data may include data obtained from originating equipment at a surface level.', 'The change may be to operational parameters of a top drive and/or a drawworks.', 'The change may be to operational parameters of a drilling fluid system component.', 'For example, the drilling fluid system component may be a pump and/or a valve.', 'The drilling fluid system component may be operable to add or alter a concentration of a constitutional component of drilling fluid circulated by the drilling fluid system.', 'The present disclosure also introduces a method comprising operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises: (A) determining a change to an operation of at least some of surface equipment of the well construction system based on: (i) an indication of a quality of a transmitted communication between downhole equipment of the well construction system in a wellbore and surface communication equipment of the well construction system transmitted during the operation; (ii) a projected effect of the operation on future communication between the downhole equipment and the surface communication equipment; (iii) downhole data related to one or more conditions in the wellbore; or (iv) a combination thereof; and (B) causing the change to the operation to be implemented.', 'The processing system may be a first processing system, the method may further comprise operating a second processing system comprising a processor and a memory including computer program code, operating the first processing system may further comprise developing an updated job plan to cause the change to the operation of the well construction system to be implemented, and operating the second processing system may comprise interpreting the updated job plan and issuing one or more commands to one or more equipment controllers of the surface equipment to implement the updated job plan.\n \nOperating the processing system may further comprise causing the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of the surface equipment.', 'Operating the processing system may further comprise determining the change to the operation of the well construction system based on surface measurement data acquired at a surface level.', 'Determining the change may be based on the indication of the quality of the transmitted communication, and the indication of the quality may be based on noise in a signal of the transmitted communication.', 'Determining the change may be based on the indication of the quality of the transmitted communication, and the indication of the quality may be based on a content of the transmitted communication relative to a previous communication.', 'Determining the change may be based on the projected effect of the operation on the future communication.', 'The projected effect may be based on (i) one or more current conditions in the wellbore, a current state of the well construction system, or a combination thereof, and (ii) a future sequence of the operation.', 'Determining the change may be based on the downhole data.', 'The downhole data may include measurement data measured in the wellbore.', 'The downhole data may include data obtained from originating equipment at a surface level.', 'In such implementations, among others within the scope of the present disclosure, the change may be to operational parameters of a top drive, a drawworks, and/or a drilling fluid system component.', 'The present disclosure also introduces an apparatus comprising a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to: analyze a communication between downhole equipment and surface equipment of a well construction system to obtain an indication of a quality of the communication; determine a change to an operation of the well construction system based on the indication of the quality of the communication; and cause the change to the operation of the well construction system to be implemented.', 'The processing system may be a first processing system, the apparatus may further comprise a second processing system communicatively coupled to the first processing system and comprising a processor and a memory including computer program code, the first processing system may be further operable to develop an updated job plan to cause the change to the operation of the well construction system to be implemented, and the second processing system may be operable to interpret the updated job plan and issue one or more commands to one or more equipment controllers of the surface equipment to implement the updated job plan.', 'The processing system may be further operable to cause the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of the surface equipment.', 'The analysis may determine an indication of noise in a signal of the communication to obtain the indication of the quality.', 'The analysis may compare a content of the communication relative to a previous communication to obtain the indication of the quality.', 'The present disclosure also introduces a method comprising operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises: analyzing a communication between downhole equipment and surface equipment of a well construction system to obtain an indication of a quality of the communication; determining a change to an operation of the well construction system based on the indication of the quality of the communication; and causing the change to the operation of the well construction system to be implemented.', 'The processing system may be a first processing system, the method may further comprise operating a second processing system comprising a processor and a memory including computer program code, operating the first processing system may further comprise developing an updated job plan to cause the change to the operation of the well construction system to be implemented, and operating the second processing system may comprise interpreting the updated job plan and issuing one or more commands to one or more equipment controllers of the surface equipment to implement the updated job plan.\n \nOperating the processing system may further comprise causing the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of the surface equipment.', 'Analyzing the communication may comprise determining an indication of noise in a signal of the communication to obtain the indication of the quality.', 'Analyzing the communication may comprise comparing a content of the communication relative to a previous communication to obtain the indication of the quality.', 'The present disclosure also introduces an apparatus comprising a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to: determine a projected effect on a future communication based on a future sequence of an operation of a well construction system, wherein the future communication is between downhole equipment and surface equipment of the well construction system; determine a change to the operation of the well construction system based on the projected effect; and cause the change to the operation of the well construction system to be implemented.', 'The processing system may be a first processing system, the apparatus may further comprise a second processing system communicatively coupled to the first processing system and comprising a processor and a memory including computer program code, the first processing system may be further operable to develop an updated job plan to cause the change to the operation of the well construction system to be implemented, and the second processing system may be operable to interpret the updated job plan and issue one or more commands to one or more equipment controllers of the surface equipment to implement the updated job plan.', 'The processing system may be further operable to cause the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of the surface equipment.', 'The change to the operation may include delaying the future sequence.', 'The change to the operation may include changing the future sequence to reduce the projected effect.', 'The present disclosure also introduces a method comprising operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises: determining a projected effect on a future communication based on a future sequence of an operation of a well construction system, wherein the future communication is between downhole equipment and surface equipment of the well construction system; determining a change to the operation of the well construction system based on the projected effect; and causing the change to the operation of the well construction system to be implemented.', 'The processing system may be a first processing system, the method may further comprise operating a second processing system comprising a processor and a memory including computer program code, operating the first processing system may further comprise developing an updated job plan to cause the change to the operation of the well construction system to be implemented, and operating the second processing system may comprise interpreting the updated job plan and issuing one or more commands to one or more equipment controllers of the surface equipment to implement the updated job plan.\n \nOperating the processing system may further comprise causing the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of the surface equipment.', 'The change to the operation may include delaying the future sequence.', 'The change to the operation may include changing the future sequence to reduce the projected effect.', 'The present disclosure also introduces an apparatus comprising a processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to: determine a change to an operation of a well construction system based on downhole data relating to one or more conditions in a wellbore at a well site; and cause the change to the operation of the well construction system to be implemented.', 'The processing system may be a first processing system, the apparatus may further comprise a second processing system communicatively coupled to the first processing system and comprising a processor and a memory including computer program code, the first processing system may be further operable to develop an updated job plan to cause the change to the operation of the well construction system to be implemented, and the second processing system may be operable to interpret the updated job plan and issue one or more commands to one or more equipment controllers of surface equipment to implement the updated job plan.', 'The processing system may be further operable to cause the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of surface equipment.', 'The downhole data may include measurement data measured in the wellbore.', 'The downhole data may include data obtained from originating equipment at a surface level.', 'The processing system may be further operable to determine the change to the operation of the well construction system based on surface measurement data acquired at a surface level.', 'The change may be to operational parameters of a top drive, a drawworks, and/or a drilling fluid system, for example.', 'The present disclosure also introduces a method comprising operating a processing system comprising a processor and a memory including computer program code, wherein operating the processing system comprises: determining a change to an operation of a well construction system based on downhole data relating to one or more conditions in a wellbore at a well site; and causing the change to the operation of the well construction system to be implemented.', 'The processing system may be a first processing system, the method may further comprise operating a second processing system comprising a processor and a memory including computer program code, operating the first processing system may further comprise developing an updated job plan to cause the change to the operation of the well construction system to be implemented, and operating the second processing system may comprise interpreting the updated job plan and issuing one or more commands to one or more equipment controllers of surface equipment to implement the updated job plan.\n \nOperating the processing system may further comprise causing the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of surface equipment.', 'The downhole data may include measurement data measured in the wellbore.', 'The downhole data may include data obtained from originating equipment at a surface level.', 'Operating the processing system may further comprise determining the change to the operation of the well construction system based on surface measurement data acquired at a surface level.', 'The change may include altering operational parameters of a top drive, a drawworks, and/or a drilling fluid system, for example.', 'The present disclosure also introduces an apparatus comprising: (A) equipment of a well construction apparatus; (B) one or more equipment controllers operable to control the equipment; and (C) a processing system comprising a processor and a memory including computer program code, wherein the one or more equipment controllers and the processing system are communicatively coupled to a network, wherein the processing system is operable to: (i) identify an operation of the equipment; (ii) determine a change to the identified operation of the equipment based on downhole data relating to one or more conditions in a wellbore formed by the well construction apparatus; and (iii) cause the change to the identified operation to be implemented.', 'The apparatus may further comprise surface communication equipment operable to communicate with downhole equipment in the wellbore, wherein the surface communication equipment may be communicatively coupled to the network, and the downhole data may include measurement data measured in the wellbore by the downhole equipment and communicated to the surface communication equipment.', 'The apparatus may further comprise one or more sensors on the surface communicatively coupled to the network, and the downhole data may include data obtained from the one or more sensors on the surface.', 'The processing system may be operable to identify the operation based on a job plan.', 'The processing system may be operable to identify the operation based on one or more commands to be issued to the equipment.', 'The apparatus may further comprise a human-machine interface communicatively coupled to the network, and the processing system may be operable to identify the operation based on input to the human-machine interface.', 'The processing system may be operable to identify the operation before the operation is initiated.', 'The processing system may be operable to identify the operation while the operation is on-going.', 'The change may include delaying or rescheduling issuance of one or more commands to the equipment controllers.', 'The change may include changing operational parameters of the equipment.', 'The identified operation may be a drilling process operation, and the equipment may include a top drive and/or a drawworks.', 'In such implementations, among others within the scope of the present disclosure, the drilling process operation may include initiating, ramping up, or maintaining a rotating speed of the top drive, and the change may include a change, relative to the identified drilling process operation, to one or more parameters relating to the initiating, ramping up, or maintaining the rotating speed of the top drive, one or more commands to be issued to at least one of the one or more equipment controllers operable to control the top drive, or a combination thereof.', 'The present disclosure also introduces a method comprising: (A) operating a processing system comprising a processor and a memory including computer program code, wherein the processing system is communicatively coupled to a network, wherein operating the processing system comprises: (i) identifying an operation of equipment of a well construction apparatus; and (ii) determining a change to the identified operation of the equipment based on downhole data relating to one or more conditions in a wellbore formed by the well construction apparatus; and (B) operating the equipment of the well construction apparatus based on the change, wherein operating the equipment comprises controlling the equipment using one or more equipment controllers communicatively coupled to the network.', 'The method may comprise: measuring the downhole data in the wellbore by downhole equipment in the wellbore; and communicating the downhole data to surface communication equipment from the downhole equipment, wherein the surface communication equipment is communicatively coupled to the network.', 'The method may comprise obtaining the downhole data using one or more sensors on the surface communicatively coupled to the network.', 'Identifying the operation may be based on a job plan, and/or on one or more commands to be issued to the equipment.', 'The method may comprise initiating operating the operation of the equipment before the change is determined, and operating the operation may be on-going when the change is determined.', 'In such implementations, among others within the scope of the present disclosure, operating the operation may be based on a job plan.', 'Operating the operation may be based on input to a human-machine interface communicatively coupled to the network, and the input to the human-machine interface may be on-the-fly.', 'The operation may be identified before the operation is initiated.', 'In such implementations, among others within the scope of the present disclosure, the operation may be based on a job plan and/or on input to a human-machine interface communicatively coupled to the network, and the input to the human-machine interface may be on-the-fly.', 'The change may include delaying or rescheduling issuance of one or more commands to the equipment controllers.', 'The change may include changing operational parameters of the equipment.', 'The identified operation may be a drilling process operation, and the equipment may include a top drive and/or a drawworks.', 'In such implementations, among others within the scope of the present disclosure, operating the equipment may include initiating, ramping up, or maintaining a rotating speed of the top drive, and the change may include a change, relative to the identified drill process operation, to one or more parameters relating to the initiating, ramping up, or maintaining the rotating speed of the top drive, one or more commands to be issued to at least one of the one or more equipment controllers operable to control the top drive, or a combination thereof.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'An apparatus comprising:\na processing system comprising a processor and a memory including computer program code, wherein the processing system is operable to: receive an indication of a quality of transmitted communication between downhole equipment of a well construction system in a wellbore and surface communication equipment of the well construction system transmitted during an operation of the well construction system; in response to determining that the indication of the quality indicates that the communication has one or both of low fidelity and low reliability: identify a probable cause of the low fidelity or the low reliability; determine one or more changes to the operation that will improve the quality of the transmitted communication; and cause the change to the operation of the well construction system to be implemented.', '2.', 'The apparatus of claim 1 wherein:\nthe processing system is a first processing system;\nthe apparatus further comprises a second processing system communicatively coupled to the first processing system and comprising a processor and a memory including computer program code;\nthe first processing system is further operable to develop an updated job plan to cause the change to the operation of the well construction system to be implemented; and\nthe second processing system is operable to interpret the updated job plan and issue one or more commands to one or more equipment controllers of surface equipment to implement the updated job plan.', '3.', 'The apparatus of claim 1 wherein the processing system is further operable to cause the change to the operation of the well construction system to be implemented by issuing one or more commands to one or more controllers of surface equipment.', '4.', 'The apparatus of claim 1 wherein the determination is based on the indication of the quality of the transmitted communication, and wherein the indication of the quality is based on noise in a signal of the transmitted communication.', '5.', 'The apparatus of claim 1 wherein the determination is based on the indication of the quality of the transmitted communication, and wherein the indication of the quality is based on a content of the transmitted communication relative to a previous communication.', '6.', 'The apparatus of claim 1 wherein the determination is based on the projected effect of the operation on the future communication.', '7.', 'The apparatus of claim 1 wherein the determination is based on the downhole data.', '8.', 'An apparatus comprising:\nequipment of a well construction apparatus;\none or more equipment controllers operable to control the equipment; and\na processing system comprising a processor and a memory including computer program code, wherein the one or more equipment controllers and the processing system are communicatively coupled to a network, wherein the processing system is operable to: identify an operation of the equipment; receive an indication of a quality of transmitted communication between downhole equipment in a wellbore and surface communication equipment that is transmitted during an operation of the well construction apparatus; in response to determining that the indication of the quality indicates that the communication has one or both of low fidelity and low reliability: identify a probable cause of the low fidelity or the low reliability; determine one or more changes to the operation that will improve the quality of the transmitted communication; and cause the change to the identified operation to be implemented.', '9.', 'The apparatus of claim 8 further comprising surface communication equipment operable to communicate with downhole equipment in the wellbore, wherein:\nthe surface communication equipment is communicatively coupled to the network; and\nthe downhole data includes measurement data measured in the wellbore by the downhole equipment and communicated to the surface communication equipment.', '10.', 'The apparatus of claim 8 further comprising one or more sensors on the surface communicatively coupled to the network, wherein the downhole data includes data obtained from the one or more sensors on the surface.', '11.', 'The apparatus of claim 8 wherein the processing system is operable to identify the operation based on a job plan.', '12.', 'The apparatus of claim 8 wherein the processing system is operable to identify the operation based on one or more commands to be issued to the equipment.', '13.', 'The apparatus of claim 8 further comprising a human-machine interface communicatively coupled to the network, where the processing system is operable to identify the operation based on input to the human-machine interface.', '14.', 'A method comprising:\noperating a processing system comprising a processor and a memory including computer program code, wherein the processing system is communicatively coupled to a network, wherein operating the processing system comprises: identifying an operation of equipment of a well construction apparatus; and receiving an indication of a quality of transmitted communication between downhole equipment in a wellbore and surface communication equipment that is transmitted during an operation of the well construction apparatus; in response to determining that the indication of the quality indicates that the communication has one or both of low fidelity and low reliability: identifying a probable cause of the low fidelity or the low reliability; determining one or more changes to the operation that will improve the quality of the transmitted communication; and operating the equipment of the well construction apparatus based on the one or more changes, wherein operating the equipment comprises controlling the equipment using one or more equipment controllers communicatively coupled to the network.', '15.', 'The method of claim 14 further comprising initiating operating the operation of the equipment before the change is determined, wherein the operating the operation is on-going when the change is determined.', '16.', 'The method of claim 14 wherein the operation is identified before the operation is initiated.', '17.', 'The method of claim 14 wherein the change includes delaying or rescheduling issuance of one or more commands to the equipment controllers.', '18.', 'The method of claim 14 wherein the change includes changing operational parameters of the equipment.\n\n\n\n\n\n\n19.', 'The method of claim 14 wherein:\nthe identified operation is a drilling process operation; and\nthe equipment includes a top drive and a drawworks.', '20.', 'The method of claim 19 wherein:\noperating the equipment includes initiating, ramping up, or maintaining a rotating speed of the top drive; and the change includes a change, relative to the identified drill process operation, to one or more parameters relating to the initiating, ramping up, or maintaining the rotating speed of the top drive, one or more commands to be issued to at least one of the one or more equipment controllers operable to control the top drive, or a combination thereof.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '4 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '5 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG.', '6 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG. 7 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG.', '1 is a schematic view of at least a portion of an example implementation of a well construction system 100 operable to drill a wellbore 104 into one or more subsurface formations 102 at a well site in accordance with one or more aspects of the present disclosure.', 'A drillstring 106 penetrates the wellbore 104 and includes a bottom hole assembly (BHA) 108 that comprises or is mechanically and hydraulically coupled to a drill bit 110.', 'The well construction system 100 includes a mast 114 (at least a portion of which is depicted in FIG.', '1) extending from a rig floor 112 that is erected over the wellbore 104.', 'A top drive 116 is suspended from the mast 114 and is mechanically coupled to the drillstring 106.', 'The top drive 116 provides a rotational force (e.g., torque) to drive rotational movement of the drillstring 106, such as to advance the drillstring 106 into the one or more subsurface formations 102 to form the wellbore 104.; FIG. 1 also depicts a pipe handling manipulator (PHM) 182 and a fingerboard 184 disposed on the rig floor 112, although other implementations within the scope of the present disclosure may include one or both of the PHM 182 and the fingerboard 184 located elsewhere or excluded.', 'The fingerboard 184 provides storage (e.g., temporary storage) of tubulars 194, such that the PHM 182 can be operated to transfer the tubulars 194 from the fingerboard 184 for inclusion in the drillstring 106 during drilling or tripping-in operations, instead of (or in addition to) from the catwalk 166, and similarly for transferring tubulars 194 removed from the drillstring 106 to the fingerboard 184 during tripping-out operations.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of a well construction system 250 operable to drill a wellbore 104 into one or more subsurface formations 102 at a well site in accordance with one or more aspects of the present disclosure.', 'Some of the components and operation of those components are common (as indicated by usage of common reference numerals) between the well construction systems 100 and 250 of FIGS.', '1 and 2, respectively.', 'Hence, discussion of the common components may be omitted here for brevity, although a person of ordinary skill in the art will readily understand the components and their operation, with any modification, in the well construction system 250 of FIG.', '2.; FIG.', '3 is a schematic view of at least a portion of a simplified operations network 300 of a well construction system according to one or more aspects of the present disclosure.', 'The physical network used to implement the operations network 300 of FIG. 3 can have any network topology, such as a bus topology, a ring topology, a star topology, mesh topology, etc.', 'The operations network 300 can include one or more processing systems, such as one or more network appliances, on and/or through which various aspects of the operations network 300 of FIG.', '3 operate.', 'Various other processing systems, such as ones that implement one or more switches, gateways, and/or other functionality, can be implemented in the operations network and are within the scope of the present disclosure.', 'A person having ordinary skill in the art will readily understand how such processing systems and functionality may be implemented.', '; FIG.', '3 illustrates an EC-1 304 and an EC-N 306 both communicatively coupled to the common data bus 302.', 'The ECs (e.g., EC-1 304 and EC-N 306) can be at least a part of multiple control subsystems, respectively, of the well construction system, an entire control system of the well construction system, and/or any permutation therebetween.', 'Example subsystems include a drilling fluid circulation system (which may include drilling fluid pumps, valves, fluid reconditioning equipment, etc.), a rig control system (which may include hoisting equipment, drillstring rotary mover equipment (such as a top drive and/or rotary table), a PHM, a catwalk, etc.), a managed pressure drilling system, a cementing system, a rig walk system, etc.', 'A subsystem may include a single piece of equipment or may include multiple pieces of equipment, e.g., that are jointly used to perform one or more function.', 'Each subsystem can include one or more ECs.', 'Any number of control subsystems may be implemented, and any number of ECs may be used in any control subsystem.', 'If multiple subsystems are on the same physical network for communication, the subsystems can be segmented from each other, such as by implementing respective virtual networks and/or domain designation.', 'Further, in some examples, a gateway may be disposed between a subsystem (e.g., an EC of the subsystem) and the common data bus 302 to translate communications, and in other examples, a gateway is not between a subsystem (e.g., an EC of the subsystem) and the common data bus 302, such as when the subsystem implements the common protocol that is used through the common data bus 302.; FIG.', '4 is a schematic view of at least a portion of an example implementation of a processing system 400 according to one or more aspects of the present disclosure.', 'The processing system 400 may execute example machine-readable instructions to implement at least a portion of one or more of the methods and/or processes described herein.; FIG.', '5 is a flow-chart diagram of at least a portion of an example implementation of a method (500) for implementing operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (500) includes operating (502) a well construction process.', 'The well construction process can be, for example, any process used in constructing a well, such as drilling, cementing, and/or other example processes.', 'The operating (502) can be by using the operations network 300 of FIG.', '3, including using a job plan from the one or more process applications 322, a controller 318 to implement a job plan, and ECs (e.g., EC-1 304 and EC-N 306) to receive commands from the controller 318 and to control equipment for the well construction process.', '; FIG.', '6 is a flow-chart diagram of at least a portion of an example implementation of a method (600) for implementing operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (600) includes identifying (602) an operation of a well construction process.', 'The identifying (602) can identify an operation that has not begun but is intended to begin and/or can identify an operation that previously began and is on-going.', 'The well construction process can be, for example, any process used in constructing a well, such as drilling, cementing, and/or other example processes.', 'In a planned operation, the operation can be implemented by using the operations network 300 of FIG.', '3, including using a job plan from the one or more process applications 322, a controller 318 to implement a job plan, and ECs (e.g., EC-1 304 and EC-N 306) to receive commands from the controller 318 and to control equipment for the well construction process.', 'In an on-the-fly operation, an operator can input data to an HMI 320 that is received by the controller 318 via the operations network 300, and the controller 318 can implement the input as commands transmitted to the ECs for controlling equipment to implement the operation.', 'The identifying (602) the operation of the well construction process can be based on a job plan and/or commands, which may be for beginning the operation and/or for an on-going operation.', 'The identifying (602) the operation of the well construction process can include identifying an initial operation based on inputs through an HMI by an operator to begin the operation on-the-fly.', 'The identifying (602) the operation of the well construction process can similarly include identifying on-going operations controlled at least in part through an HMI by an operator on-the-fly.; FIG.', '7 is a flow-chart diagram of at least a portion of an example implementation of a method (700) for implementing operations of a well construction system according to one or more aspects of the present disclosure.', 'The method (700) includes identifying (702) an operation of a well construction process.', 'The identifying (702) can identify an operation that has not begun but is intended to begin and/or can identify an operation that previously began and is on-going.', 'The well construction process can be, for example, any process used in constructing a well, such as drilling, cementing, and/or other example processes.', 'In a planned operation, the operation can be implemented by using the operations network 300 of FIG.', '3, including using a job plan from the one or more process applications 322, a controller 318 to implement a job plan, and ECs (e.g., EC-1 304 and EC-N 306) to receive commands from the controller 318 and to control equipment for the well construction process.', 'In an on-the-fly operation, an operator can input data to an HMI 320 that is received by the controller 318 via the operations network 300, and the controller 318 can implement the input as commands transmitted to the ECs for controlling equipment to implement the operation.', 'The identifying (702) the operation of the well construction process can be based on a job plan and/or commands, which may be for beginning the operation and/or for an on-going operation.', 'The identifying (702) the operation of the well construction process can include identifying an initial operation based on inputs through an HMI by an operator to begin the operation on-the-fly.', 'The identifying (702) the operation of the well construction process can similarly include identifying on-going operations controlled at least in part through an HMI by an operator on-the-fly.'] |
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US11125021 | Customized drilling tools | Jul 1, 2019 | Xiaoge Gan, Youhe Zhang, Huimin Song | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 4245708; January 20, 1981; Cholet et al.; 4492277; January 8, 1985; Creighton; 4540055; September 10, 1985; Drummond et al.; 4733735; March 29, 1988; Barr et al.; 4744426; May 17, 1988; Reed; 4848491; July 18, 1989; Burridge et al.; 4887677; December 19, 1989; Warren et al.; 5199511; April 6, 1993; Tibbitts et al.; 5284215; February 8, 1994; Tibbitts; 5433280; July 18, 1995; Smith; 5441121; August 15, 1995; Tibbitts; 5651420; July 29, 1997; Tibbitts et al.; 5906245; May 25, 1999; Tibbitts et al.; 5957227; September 28, 1999; Besson et al.; 6302223; October 16, 2001; Sinor; 6454030; September 24, 2002; Findley et al.; 20080029312; February 7, 2008; Hall et al.; 20080075618; March 27, 2008; Martin; 20100006345; January 14, 2010; Stevens; 20110192651; August 11, 2011; Lyons et al.; 20130160611; June 27, 2013; Matthews, III et al.; 20130316149; November 28, 2013; Atkins; 20140231151; August 21, 2014; Matthias; 20150167397; June 18, 2015; Matthews, III; 20180002986; January 4, 2018; Zhang et al.; 20180038167; February 8, 2018; Xu | 104353833; February 2015; CN | ['A downhole cutting tool has a body that includes a cutting end, a connection end, a longitudinal axis extending axially through the body, and a gradient composition having one or more gradients.', 'Each gradient extends a distance in a respective direction through the body.', 'Each gradient has changing amounts of a first material in the gradient composition along the respective direction in which the gradient extends.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a continuation of U.S. patent application Ser.', 'No. 15/630,420, filed on Jun. 22, 2017 and titled “Customized Drilling Tools,” which claims the benefit of, and priority to, U.S. Patent Application No. 62/357,270, filed Jun. 30, 2016 and titled “Drilling Tools with Customized Hydraulics for Cutting Elements,” U.S. Patent Application No. 62/357,087, filed Jun. 30, 2016 and titled “Bit Body Having Compositional Gradient,” and U.S. Patent Application No. 62/356,839, filed Jun. 30, 2016 and titled “3D Printed Body with 3D Layered Structure.”', 'Each of the foregoing applications is incorporated herein by this reference in its entirety.', 'BACKGROUND\n \nWellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes.', 'For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations.', 'A variety of drilling methods and tools may be utilized depending partly on the characteristics of the formation through which the wellbore is drilled.', 'A drilling system may use a variety of bits in the creation, maintenance, extension, and abandonment of a wellbore.', 'Bits include drilling bits, mills, reamers, hole openers, and other cutting tools.', 'Some drilling systems rotate a bit relative to the wellbore to remove material from the sides and/or bottom of the wellbore.', 'Some bits are used to remove natural material from the surrounding geologic formation to extend or expand the wellbore.', 'For instance, so-called fixed cutter or drag bits, or roller cone bits, may be used to drill or extend a wellbore, and a reamer or hole opener may be used to remove formation materials to extend or widen a wellbore.', 'Some bits are used to remove material positioned in the wellbore during construction or maintenance of the wellbore.', 'For example, bits are used to remove cement, scale, or metal casing from a wellbore during maintenance, creation of a window for lateral drilling in an existing wellbore, or during remediation.', 'Bit bodies may be fabricated from either steel or a hard metal “matrix” material.', 'The matrix material can include tungsten carbide infiltrated with a binder alloy.', 'Matrix bit bodies may have higher wear or erosion resistance, but may sacrifice toughness and may be more susceptible to impact damage than steel bit bodies.', 'Matrix bit bodies are manufactured by sintering, a process unique from infiltration.', 'The sintering process involves the introduction of a refractory compound into a mold.', 'The refractory may include a carbide of tungsten, titanium, or tantalum, or other specialized use materials.', 'Before the carbide is introduced into the mold, it is mixed with a binder metal.', 'The binder metal may be cobalt, but iron, nickel, and other materials may also be used.', 'In the mold, the combination is heated to a point just below the melting point of the binder metal, and bonds are formed between the binder metal and the carbide by diffusion bonding or by liquid phase material transport.', 'Infiltration, on the other hand, involves the introduction of a refractory compound such as the above carbides into a mold with an opening at its top.', 'A slug or cubes of binder metal are then placed against the refractory compound at the opening.', 'The mold, refractory compound, and binder metal are placed into a furnace, and the binder metal is heated to its melting point.', 'By capillary action and gravity, the molten metal from the slug infiltrates the refractory compound in the mold, thereby binding the refractory compound into a part.', 'The infiltration binder may be a copper alloy including nickel, manganese, zinc, tin, other materials, or some combination thereof.', 'Cutting elements on a bit may be formed of an ultrahard material, such as a tungsten carbide or polycrystalline diamond (PCD).', 'PCD may be used in various drilling operations as the material is very hard and wear resistant.', 'PCD is, however, susceptible to thermal degradation during operations.', 'SUMMARY\n \nIn some embodiments, a downhole cutting tool has a body that includes a cutting end, a connection end, a longitudinal axis extending axially through the body, and a gradient composition having one or more gradients.', 'Each gradient extends a distance in a respective direction through the body.', 'Each gradient has changing amounts of a first material in the gradient composition along the respective direction in which the gradient extends.', 'In some embodiments, a method of manufacturing a downhole cutting tool includes successively depositing a volume of at least two materials using a deposition device to build a three dimensional body of the cutting tool having a gradient composition.', 'The gradient composition includes at least two gradients in composition extending in different directions along the body.', 'Each gradient includes a progressively increasing or decreasing amount of a first material by percent composition.', 'In some embodiments, a downhole cutting tool includes a body having a cutting end, a connection end, and a longitudinal axis extending therethrough.', 'The downhole cutting tool also includes a first gradient composition having a progressively decreasing amount of a first material in the composition along a first distance from the cutting end, the first gradient composition forming a cutting end portion of the body.', 'This summary is provided to introduce a selection of concepts that are further described in the detailed description, and is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'Additional features and aspects of embodiments of the disclosure will be set forth in the description that follows.', 'These and other features will become more fully apparent from the following description and appended claims, or may be learned by the practice of such embodiments as set forth herein.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings.', 'While some of the drawings may be schematic or exaggerated representations of concepts, other drawings may be drawn to scale and can be used for relative dimensions of various components.', 'Such scale drawings are illustrative of some embodiments and are not to scale for other embodiments within the scope of the disclosure.', 'Accordingly, understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:\n \nFIG.', '1\n is a schematic representation of a drilling system, according to embodiments of the present disclosure;\n \nFIG.', '2\n is a side cross-sectional schematic representation of a bit having hydraulic fluid conduits, according to some embodiments of the present disclosure;\n \nFIG.', '3\n is a bottom view of another bit having hydraulic fluid conduits, according to some embodiments of the present disclosure;\n \nFIG.', '4-1\n is a side view of a bit, according to some embodiments of the present disclosure;\n \nFIG.', '4-2\n is a perspective view of the bit of \nFIG.', '4-1\n;\n \nFIG.', '4-3\n is a bottom view of the bit of \nFIG.', '4-1\n;\n \nFIG.', '5-1\n is a bottom view of the blade of the bit of \nFIG.', '4-1\n;\n \nFIG.', '5-2\n is a cross-sectional view of the blade of \nFIG.', '5-1\n;\n \nFIG.', '5-3\n is another cross-sectional view of the blade of \nFIG.', '5-1\n;\n \nFIG.', '6-1\n is a perspective view of yet another bit, according to some embodiments of the present disclosure;\n \nFIG.', '6-2\n is a bottom view of the bit of \nFIG.', '6-1\n;\n \nFIG.', '7\n is a side cross-sectional view of a bit, according to further embodiments of the present disclosure;\n \nFIG.', '8\n is a flowchart of a method of removing material with a bit, according to some embodiments of the present disclosure;\n \nFIG.', '9\n is a cross-sectional, schematic view of a downhole cutting tool having a gradient composition, according to some embodiments of the present disclosure;\n \nFIG.', '10\n is a cross-sectional, schematic view of a downhole cutting tool having a gradient composition, according to additional embodiments of the present disclosure;\n \nFIG.', '11\n is a cross-sectional, schematic view of a downhole cutting tool having a gradient composition, according to further embodiments of the present disclosure;\n \nFIG.', '12\n is a cross-sectional, schematic view of a downhole cutting tool having a multi-directional gradient, according to some embodiments of the present disclosure;\n \nFIG.', '13\n shows a grid pattern developed from a cutting tool model, according to some embodiments of the present disclosure; and\n \nFIG.', '14\n is a cross-sectional diagram of a cutting tool model and graphs of a gradient composition design of the cutting tool model, according to some embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'Some embodiments of this disclosure generally relate to devices, systems, and methods for cooling, cleaning, or lubricating (or combinations of cooling, cleaning, and lubricating) one or more cutting elements of a bit.', 'More particularly, some embodiments of the present disclosure relate to bits having a plurality of fluid outlets that may increase operational lifetime, improve cooling, reduce the likelihood of cutting element or bit body failure, provide improved flushing of cuttings, or combinations thereof.', 'While a drill bit for cutting through an earth formation is described herein, it should be understood that the present disclosure may be applicable to other bits such as mills, reamers, hole openers, and other bits used in downhole or other applications.', 'FIG.', '1\n shows one example of a drilling system \n100\n for forming a wellbore \n102\n in an earth formation \n104\n.', 'The drilling system \n100\n includes a drilling tool assembly \n106\n that extends downward into the wellbore \n102\n.', 'The drilling tool assembly \n106\n may include a drill string \n108\n and a bottomhole assembly (“BHA”) \n110\n attached to a downhole end portion of drill string \n108\n.', 'The BHA \n110\n may include a bit \n112\n for drilling, milling, reaming, or performing other cutting operations within the wellbore.', 'The drill string \n108\n may include several joints of drill pipe connected end-to-end through tool joints.', 'The drill rig \n114\n may include a top drive or rotary table \n116\n that rotates the drill string \n108\n, and the drill string \n108\n optionally transmits rotational power and torque from the drill rig \n114\n to the BHA \n110\n.', 'The drill string \n108\n may also transmit drilling fluid through a central bore.', 'In some embodiments, the drill string \n108\n may further include additional components such as subs, pup joints, jars, vibration tools, stabilizers, sensors, etc.', 'The drill string \n108\n may include slim drill pipe, coiled tubing, or other materials that transmit drilling fluid through a central bore, which may not transmit rotational power.', 'Where rotational power is used, a downhole motor (e.g., a positive displacement motor, turbine-driven motors, electric motor, etc.) may be included in the BHA \n110\n.', 'The drill string \n108\n provides a hydraulic passage through which drilling fluid is pumped from the surface.', 'The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit \n112\n (or other components of the drill string \n108\n or BHA \n110\n) for the purposes of cooling, cleaning, or both cooling and cleaning the bit \n112\n and cutting structures thereon, for lifting cuttings out of the wellbore \n102\n as downhole operations are performed, or for other purposes (e.g., cleaning, powering a motor, etc.).', 'The BHA \n110\n may include the bit \n112\n or other components.', 'An example BHA \n110\n may include additional or other components (e.g., coupled between to the drill string \n108\n and the bit \n112\n).', 'Examples of additional BHA components include drill collars, stabilizers \n118\n, measurement tools \n120\n (e.g., measurement-while-drilling (“MWD”) tools or logging-while-drilling (“LWD”) tools), downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.', 'For example, other measurement tools \n120\n may include accelerometers to measure the movement of the bit \n112\n, a torque meter to measure forces on the bit \n112\n, sensors to measure weight on the bit \n112\n, other sensing or logging tools, or combinations of the foregoing.', 'In general, the drilling system \n100\n may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves).', 'Additional components included in the drilling system \n100\n may be considered a part of the drilling tool assembly \n106\n, the drill string \n108\n, or a part of the BHA \n110\n depending on their locations or functions in the drilling system \n100\n.', 'The bit \n112\n in the BHA \n110\n may be any type of bit suitable for degrading downhole materials.', 'For example, the bit \n112\n may be a drill bit suitable for drilling the earth formation \n104\n.', 'Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, impregnated bits, or coring bits.', 'In other embodiments, the bit \n112\n may be a mill used for removing metal, composite, elastomer, or other materials downhole.', 'For instance, the bit \n112\n may be used with a whipstock (not shown) to mill a window into a casing that lines at least a portion of the wellbore \n102\n.', 'The bit \n112\n may also be a section mill used to mill away an entire section of the casing, or a junk mill used to mill away tools, plugs, cement, or other materials within the wellbore \n102\n.', 'Swarf or other cuttings formed by use of a mill may be lifted to surface, or may be allowed to fall downhole.', 'Referring to \nFIG.', '2\n, an embodiment of a bit \n112\n is shown in side cross-section.', 'The bit \n112\n has a bit body \n122\n with one or more blades \n124\n (one is shown in \nFIG.', '2\n) coupled thereto.', 'The blades \n124\n may have a plurality of pockets \n126\n formed on the surface thereof.', 'Each of the plurality of pockets \n126\n may be configured to receive and retain a single cutting element (not shown), or a pocket may be configured to receive an assembly that includes multiple cutting elements.', 'The cutting elements may include an ultrahard material for removing material from an earth formation, a manmade structure, or other object through which the bit \n112\n is desired to cut.', 'As used herein, the term “ultrahard” is understood to refer to those materials known in the art to have a grain hardness of about 1,500 HV (Vickers hardness in kg/mm2) or greater.', 'Some such ultrahard materials are capable of demonstrating physical stability at temperatures above 750° C., and for certain applications above 1,000° C., and may be formed from consolidated materials.', 'Such ultrahard materials can include but are not limited to metal carbides (e.g., tungsten carbide, titanium carbide, chromium carbide, niobium carbide, tantalum carbide, vanadium carbide, etc.), cobalt cemented metal carbide, metal alloy cemented metal carbide, diamond, polycrystalline diamond (PCD), leached metal catalyst PCD, non-metal catalyst PCD, hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), binderless PCD or nanopolycrystalline diamond (NPD), Q-carbon, binderless PcBN, diamond-like carbon, boron suboxide, aluminum manganese boride, metal borides, boron carbon nitride, and other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, as well as combinations of the above materials.', 'In at least one embodiment, the cutting element may be a monolithic PCD.', 'For example, the cutting element may consist of a PCD compact without an attached substrate or metal catalyst phase.', 'In some embodiments, the ultrahard material may have a hardness value above 3,000 HV.', 'In other embodiments, the ultrahard material may have a hardness value above 4,000 HV.', 'In yet other embodiments, the ultrahard material may have a hardness value greater than 80 HRa (Rockwell hardness A).', 'Some ultrahard materials (such as PCD) may be susceptible to thermal degradation due to increased temperatures of the cutting element during operation of the bit \n112\n.', 'For instance, PCD may have a cobalt or other metal-based interstitial phase with the bonded diamond grains.', 'The diamond phase and the interstitial phase have different coefficients of thermal expansion.', 'When the cutting element is heated during operation (e.g., through frictional heating between the cutting element an earth formation), the phases of the cutting element expand at different rates, generating internal strain in the cutting element material.', 'The additional internal strain increases the likelihood of failure of the cutting element.', 'According to at least some embodiments of the present disclosure, the bit \n112\n may provide cooling at or near the pockets \n126\n to cool the cutting elements.', 'Such cooling can be directed directly to the cutting elements to cool the cutting elements to reduce the thermal expansion (and relative differences in thermal expansion) in a diamond and interstitial phase of the cutting element, and thereby extend the operational life of the cutting elements.', 'The bit \n112\n may have a central conduit \n128\n into which a drilling fluid may be conveyed, as described in relation to \nFIG.', '1\n.', 'The drilling fluid may be water, drilling mud, or another fluid that provides lubrication and cooling to the bit \n112\n.', 'The drilling fluid may also be used to flush cuttings from the bit \n112\n surface and carry the cuttings uphole (or otherwise away from the cutting region).', 'In some bits, the drilling fluid is directed through a bit body to a small number of nozzles exiting the bit body in junk slot or fluid course regions between blades.', 'A relatively high volume of fluid may flow through each nozzle to flush cuttings from the bit.', 'Such nozzles are often limited in their placement and orientation due to their comparatively large size.', 'For example, a conventional nozzle is too large in diameter to be positioned on a blade \n124\n, particularly without disrupting the cutting profile of the bit \n112\n.', 'As shown in \nFIG.', '2\n, in some embodiments, a central conduit \n128\n may direct drilling fluid to a chamber \n130\n.', 'In some embodiments, the chamber \n130\n may be a crowfoot chamber, as shown in \nFIG.', '2\n.', 'In other embodiments, the chamber \n130\n may have other shapes or configurations to distribute fluid pressure throughout the chamber \n130\n and to a plurality of conduits extending from the chamber \n130\n.', 'For example, one or more primary conduits \n132\n may extend from the chamber \n130\n or central conduit \n128\n and provide fluid communication from the respective chamber \n130\n or central conduit \n128\n to a surface of the blade \n124\n.', 'The primary conduits \n132\n may branch within the blades \n124\n into cooling, cleaning, or other fluid conduits \n134\n that direct drilling fluid out of fluid outlets \n136\n formed on the blades themselves.', 'The fluid outlets \n136\n may be smaller than conventional nozzles in diameter, thereby allowing the fluid conduits \n136\n to be located in more locations on the bit \n112\n and provide more even flow of drilling fluid, and hence cleaning and cooling, to the cutting elements and to the bit \n112\n.', 'As shown in \nFIG.', '3\n, in some embodiments of a bit \n212\n, fluid outlets \n236\n may be provided directly on a primary blade \n224\n-\n1\n, a secondary blade \n224\n-\n2\n, or a tertiary blade \n224\n-\n3\n, (collectively blades \n224\n) or some combination of the foregoing.', 'In the illustrated embodiment, each tertiary blade \n224\n-\n3\n is located between a primary blade \n224\n-\n1\n and a secondary blade \n224\n-\n2\n, such that there are twice as many (six) tertiary blades \n224\n-\n3\n as either primary blades \n224\n-\n1\n (three) or secondary blades \n224\n-\n2\n (three).', 'The illustrated design is, however, merely illustrative, and in some embodiments different numbers of primary blades \n224\n-\n1\n, secondary blades \n224\n-\n2\n, or tertiary blades \n224\n-\n3\n may be used.', 'In some embodiments, there may be no tertiary blades \n224\n-\n3\n, and each blade between primary blades \n224\n-\n1\n may be a secondary blades.', 'The smaller diameter of the fluid outlets \n236\n relative to conventional nozzles, as well as the use of more fluid outlets \n236\n nearer the cutting elements to cool the cutting elements and flush away cuttings, may allow for a denser blade design of the bit \n212\n, such that a bit \n212\n may have twelve or more blades \n224\n positioned on the bit \n212\n.', 'The denser blade design of the bit \n212\n may allow for smoother cutting profiles, longer cutting element operational lifetime, more efficient removal of harder formations, or combinations thereof.', 'In some embodiments, the denser blade design of the bit \n212\n may be used to cut hard formations, which may tend to break into smaller cuttings that can be more easily evacuated through smaller fluid courses between the blades \n224\n.', 'In other embodiments, however, the bit \n212\n may be used in softer formations.', 'In some embodiments, the bit \n212\n has one fluid conduit \n236\n for each pocket \n226\n (corresponding to one fluid conduit \n126\n for each cutting element).', 'For example, a fluid conduit \n236\n may be positioned in front of the pocket \n226\n, to lead the pocket \n226\n in the direction of rotation (shown by arrow A).', 'A fluid conduit \n236\n located in such a position may provide drilling fluid to the face of a cutting element positioned in the pocket \n226\n (and particularly to the cutting tip of the cutting element), thereby directly cooling, flushing, and lubricating the cutting element to extend the operational lifetime of the cutting element.', 'In some embodiments, such as that shown in \nFIG.', '3\n, the fluid conduit \n236\n and the pockets \n226\n or cutting elements may be formed in the same surface of the blade \n224\n.', 'In other embodiments, however, a fluid conduit may be on a different surface than the pocket \n226\n or cutting element.', 'For instance, as shown in \nFIGS.', '4-1 to 4-3\n, at least some fluid outlets formed on the blade may be on a surface that is axially, radially, or both axially and radially recessed relative to the cutting elements (including the cutting face of a cutting element).', 'FIG.', '4-1\n illustrates another embodiment of a bit \n312\n, according to some embodiments of the present disclosure.', 'The bit \n312\n includes cutting elements \n338\n coupled to one or more blades \n324\n having a nose region \n337\n, a shoulder region \n339\n, and a gage region \n341\n.', 'At least a portion of the cutting elements \n338\n may be positioned in pockets \n326\n on the nose region \n337\n and the shoulder region \n339\n.', 'In some embodiments, a blade \n324\n may have a row of primary pockets \n326\n-\n1\n and a row of secondary pocket \n326\n-\n2\n.', 'For example, a blade \n324\n may have a row of primary cutting elements \n338\n on the blade \n324\n in the row of primary pockets \n326\n-\n1\n and a row of secondary cutting elements \n338\n positioned in the secondary pockets \n326\n-\n2\n.', 'The row of secondary pockets \n326\n-\n2\n may be positioned rotationally behind the primary pockets \n326\n-\n1\n relative to a rotational direction of the bit \n312\n.', 'The cutting elements \n338\n in the primary pockets \n326\n may therefore rotationally lead the cutting elements in the secondary pockets \n326\n-\n2\n.', 'In some embodiments, at least one primary fluid outlet \n336\n-\n1\n may be positioned in front of (i.e., rotationally lead)', 'the primary pockets \n326\n-\n1\n.', 'In the same or other embodiments a row, series, array, or other set of primary fluid outlets \n336\n-\n1\n may be positioned in front of the primary pockets \n326\n-\n1\n to rotationally lead the cutting elements \n338\n in the primary pockets \n326\n-\n1\n.', 'In some embodiments, at least one secondary fluid outlet \n336\n-\n2\n may be positioned in front of, to rotationally lead, the secondary pockets \n326\n-\n2\n.', 'In the same or other embodiments, a row, series, array, or other set of secondary fluid outlets \n336\n-\n2\n may be positioned in front of the secondary pockets \n326\n-\n2\n relative to a rotational direction of the bit \n312\n.', 'The secondary fluid outlets \n336\n-\n2\n may be rotationally behind the cutting elements \n338\n in the primary pockets \n326\n-\n1\n in some embodiments of the present disclosure.', 'Because the fluid outlets described herein have a diameter less than that of a conventional nozzle, the fluid outlets may be positioned on a blade \n324\n and not simply in a junk slot, fluid course, or other channel or location between blades \n324\n.', 'While the secondary outlets \n336\n-\n2\n are described herein in relation to the secondary pockets \n326\n-\n2\n or cutting elements \n338\n in the secondary pockets \n326\n-\n2\n, it should be understood that additional rows of secondary outlets \n336\n-\n2\n may be located on the blade \n324', 'when additional (i.e., tertiary, quaternary, etc.) rows of pockets or cutting elements \n338\n are positioned on the blade \n324\n.', 'In other words, the primary outlets \n336\n-\n1\n may be positioned rotationally in front of the primary pockets \n326\n-\n1\n and the secondary outlets \n336\n-\n2\n may be positioned elsewhere on the blade \n324\n rotationally in front of one or more other rows of pockets or cutting elements behind the primary row.', 'In some embodiments, the outlets \n336\n may be used in connection with cutting elements not be located within pockets (e.g., integral with the blade).', 'In some embodiments, the cutting elements \n338\n in the nose region \n337\n, the shoulder region \n339\n, or in both the nose and shoulder regions \n337\n, \n339\n may be cooled, cleaned, or lubricated by a drilling fluid provided through the fluid outlets.', 'As will be described in more detail in relation to \nFIG.', '4-3\n, according to some embodiments, at least 10% of the cutting elements \n338\n may have a fluid outlet \n336\n positioned in close proximity thereto.', 'For instance, at least 10% of the cutting elements \n338\n—which may include each cutting element in the bit or each cutting element in a particular region, depending on the manner described—may have a fluid outlet \n336\n within a distance equal to or less than twice the cutting element diameter away from the cutting face of the cutting element \n338\n.', 'In some embodiments, the cutting tip (i.e., the portion of the cutting element which is primarily used to cut the formation or other workpiece by shearing, impacting, gouging, etc.), will be within a distance of less than twice or less than three times the cutting element diameter of the cutting element \n338\n from a fluid outlet \n336\n.', 'The embodiment of a bit \n312\n is shown in a perspective view in \nFIG.', '4-2\n.', 'The bit \n312\n may have a plurality of blades \n324\n oriented at angular intervals about the bit \n312\n.', 'In some embodiments, the plurality of blades \n324\n may be oriented at equal intervals about the bit \n312\n, such as centered at the 180° intervals as shown in \nFIG.', '4-2\n.', 'In other embodiments, more than two blades \n324\n may be used, blades may be at other intervals, or unequal intervals may be used when orienting blades \n324\n about the bit \n312\n.', 'The blades \n324\n may be spaced apart with a fluid course or junk slot \n340\n positioned between the blades \n324\n to allow flow of fluid, cuttings, or other materials through the junk slots \n340\n.', 'In some embodiments, the junk slots \n340\n may provide clearance to flow drilling fluid or other materials around the bit \n312\n in an uphole or downhole direction.', 'For example, the junk slots \n340\n may provide clearance for cuttings, swarf, debris, drilling particles, or other particulates in the drilling fluid to flow around and upward past the bit \n312\n, thereby flushing material from the space around the bit \n312\n during cutting operations and as the materials return to the surface of a wellbore.', 'In other embodiments, the junk slots \n340\n may provide clearance for materials to flow around and downward past the bit \n312\n to flush material from space around the bit \n312\n during cutting operations.', 'In some embodiments, a nozzle opening \n342\n may be positioned on the bit \n312\n in one or more junk slots \n340\n.', 'The nozzle opening \n342\n may provide drilling fluid from inside the bit \n312\n to the junk slot \n340\n.', 'The nozzle opening \n342\n may provide a larger volume of fluid flow that a fluid outlet positioned on the blades \n324\n.', 'In some embodiments, an amount of fluid flow through the nozzle opening \n342\n may be between 150% and 1000% greater than the amount of fluid flow through a fluid outlet on a blade \n324\n.', 'For instance, the amount of fluid flow through the nozzle opening \n342\n may be within a range having an upper value, a lower value, or upper and lower values including any of 150%, 200%, 250%, 300%, 350%, 400%, 450%, 500%, 750%, 1000%, or any value therebetween, compared to the amount of fluid flow through a fluid outlet on a blade \n324\n.', 'For example, the nozzle opening \n342\n may allow an amount of fluid flow greater than 150% of the fluid flow of a fluid outlet.', 'In other examples, the nozzle opening \n342\n may allow an amount of fluid flow greater than 200% of the fluid flow of a fluid outlet.', 'In yet other examples, the nozzle opening \n342\n may allow an amount of fluid flow greater than 300% of the fluid flow of a fluid outlet, or between 250% and 400% of the fluid flow of a fluid outlet.', 'In other embodiments, the fluid flow through the nozzle opening \n342\n may be less than 150% or greater than 1000% of the fluid flow through a fluid outlet on a blade \n324\n.\n \nFIG.', '4-3\n illustrates a bottom view of the nose region and shoulder region (as described in relation to \nFIG.', '4-1\n) of the blade \n324\n shown in \nFIGS.', '4-1 and 4-2\n.', 'The blade \n324\n includes primary fluid outlets \n336\n-\n1\n and secondary fluid outlets \n336\n-\n2\n.', 'The fluid outlets \n336\n may each have an equal outlet diameter and shape, or the fluid outlets \n336\n may have varying outlet diameters or shapes, as shown in \nFIG.', '4-3\n.', 'In some embodiments, the fluid outlets \n336\n may have outlet diameters that vary at least partially based upon the work rate of nearest cutting elements \n338\n (e.g., the volume of material removed by the cutting element during period of time or at a predetermined cutting element velocity).', 'For example, a fluid outlet \n336\n proximate to a cutting element \n338\n with a higher work rate may having a larger outlet diameter to provide greater fluid flow to the cutting element \n338\n with a higher work rate.', 'In some embodiments, the additional fluid flow may provide additional cleaning (i.e., clearance of debris and material) of the cutting element \n338\n.', 'In the same or other embodiments, the additional fluid flow may provide additional cooling to the cutting element \n338\n.', 'In at least some embodiments, the additional cleaning or cooling may increase the operational lifetime of the cutting element \n338\n.', 'In some embodiments, differences in size may be used where fluid outlets \n336\n are used for cooling, cleaning, or providing flow to different numbers of cutting elements \n338\n.', 'For instance, a fluid outlet \n336\n directing fluid flow to a single cutting element \n338\n may have a smaller size than a fluid outlet \n336\n directing fluid flow to two or more cutting elements \n338\n.', 'Similarly, a fluid outlet \n336\n directing flow to multiple cutters may have a more elongated shape, in some embodiments, to disperse the flow more than would a circular fluid outlet \n336\n.', 'Combinations of the foregoing may also be used.', 'In some embodiments, one or more of the primary fluid outlets \n336\n-\n1\n have a primary outlet diameter \n344\n-\n1\n in a range having an upper value, a lower value, or upper and lower values including any of 0.075 in.', '(1.91 mm), 0.100 in.', '(2.54 mm), 0.200 in.', '(5.08 mm), 0.300 in.', '(7.62 mm), 0.400 in.', '(10.16 mm), 0.500 in.', '(12.72 mm), 0.600 in.', '(15.24 mm), 0.700 in.', '(17.78 mm), 0.800 in.', '(20.32 mm), 0.900 in.', '(22.86 mm), 1.000 in.', '(25.40 mm), or any values therebetween.', 'For example, a primary outlet diameter \n344\n-\n1\n may be greater than 0.200 in.', '(5.08 mm).', 'In other examples, a primary outlet diameter \n344\n-\n1\n may be less than 1.000 in.', '(25.40 mm).', 'In yet other examples, a primary outlet diameter \n344\n-\n1\n may be in range of 0.200 in.', '(5.08 mm) to 1.000 in.', '(25.40 mm).', 'In further examples, a primary outlet diameter \n344\n-\n1\n may be in range of 0.200 in.', '(5.08 mm) to 0.500 in.', '(12.72 mm).', 'In still other embodiments, a primary outlet diameter \n334\n-\n1\n may be less than 0.075 in.', '(1.91 mm) or greater than 1.000 in.', '(25.40 mm).', 'In some embodiments, the secondary fluid outlets \n336\n-\n2\n have a secondary outlet diameter \n344\n-\n2\n that is the same as, or different from, a primary outlet diameter \n344\n-\n1\n.', 'For instance, a secondary outlet diameter \n344\n-\n2\n of one or more secondary fluid outlets \n336\n-\n2\n may be in a range having an upper value, a lower value, or upper and lower values including any of 0.075 in.', '(1.91 mm), 0.100 in.', '(2.54 mm), 0.200 in.', '(5.08 mm), 0.300 in.', '(7.62 mm), 0.400 in.', '(10.16 mm), 0.500 in.', '(12.72 mm), 0.600 in.', '(15.24 mm), 0.700 in.', '(17.78 mm), 0.800 in.', '(20.32 mm), 0.900 in.', '(22.86 mm), 1.000 in.', '(25.40 mm), or any values therebetween.', 'For example, a secondary outlet diameter \n344\n-\n2\n may be greater than 0.075 in.', '(1.905 mm).', 'In other examples, the secondary outlet diameter \n344\n-\n2\n may be less than 1.000 in.', '(25.40 mm).', 'In yet other examples, the secondary outlet diameter \n344\n-\n2\n may be in a range of 0.200 in.', '(5.08 mm) to 1.000 in.', '(25.40 mm).', 'In further examples, the secondary outlet diameter \n344\n-\n2\n may be in a range of 0.200 in.', '(5.08 mm) to 0.500 in.', '(12.72 mm).', 'In still other embodiments, a secondary outlet diameter \n334\n-\n2\n may be less than 0.075 in.', '(1.91 mm) or greater than 1.000 in.', '(25.40 mm).', 'In some embodiments, the primary outlet diameter \n344\n-\n1\n of one or more primary fluid outlets \n336\n-\n1\n (and potentially each primary fluid outlet \n336\n-\n1\n) may be equal to the secondary outlet diameter \n344\n-\n2\n of one or more secondary fluid outlets \n336\n-\n2\n (and potentially each secondary fluid outlet \n336\n-\n2\n).', 'In other embodiments, a primary outlet diameter \n344\n-\n1\n may be greater than a secondary outlet diameter \n344\n-\n2\n, or a primary outlet diameter \n344\n-\n1\n may be less than a secondary outlet diameter \n344\n-\n2\n.', 'According to at least some embodiments, the outlet diameter may alter the energy with which a fluid is discharged from the fluid outlet.', 'For example, a smaller diameter may provide a higher speed of the fluid at the fluid outlet (such as by the Venturi Principle), thereby increasing the energy of the fluid flow.', 'In other examples, a larger diameter may allow for a greater volume of flow (at the same flow speed), increasing the transport capacity of the fluid to flush debris, cuttings, or other materials from the blade \n324\n or a cutting element \n338\n.', 'While the fluid outlets \n336\n have been described in terms of a diameter, it will be appreciated by those skilled in the art in view of the disclosure herein, that the fluid outlets \n336\n may not have a constant diameter, or may have other shapes without any diameter.', 'Thus, the outlet diameters \n344\n may equally apply to fluid outlets \n336\n having a width (e.g., a square), a height (e.g., a triangle), or other configurations.', 'In some embodiments, such as where a fluid outlet \n336\n has an elliptical or elongated shape, the dimensions or other features described for an outlet diameter \n344\n can apply to a major diameter/width, a minor diameter/width, or both a major and minor diameter/width.', 'In some embodiments, the secondary outlet diameter \n344\n-\n2\n may be at least partially related to the row spacing \n346\n between rows of cutting elements \n338\n at the corresponding location of a secondary fluid outlet \n336\n.', 'For example, the secondary outlet diameter \n344\n-\n2\n may be a percentage of the row spacing \n346\n.', 'In some embodiments, the secondary outlet diameter \n344\n-\n2\n may be in a range having an upper value, a lower value, or an upper and lower value, including any of 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90% or 100%, or any value therebetween of the row spacing \n346\n.', 'For example, the secondary outlet diameter \n344\n-\n2\n may be greater than 10% of the row spacing \n346\n.', 'In other examples, the secondary outlet diameter \n344\n-\n2\n may be less than 100% of the row spacing \n346\n.', 'In yet other examples, the secondary outlet diameter \n344\n-\n2\n may be in a range of 10% to 100% of the row spacing \n346\n.', 'In further examples, the secondary outlet diameter \n344\n-\n2\n may be in a range of 20% to 90% of the row spacing \n346\n.', 'In yet further examples, the secondary outlet diameter \n344\n-\n2\n may be in a range of 30% to 80% of the row spacing \n346\n.', 'In still further examples, the secondary outlet diameter \n344\n-\n2\n may be less than 10% of the row spacing \n346\n.', 'In some embodiments, a blade \n324\n may have a variety of values for the primary outlet diameters \n344\n-\n1\n for the primary fluid outlets \n336\n-\n1\n.', 'In other embodiments, a blade \n324\n may have a constant value for the primary outlet diameter \n344\n-\n1\n for the primary fluid outlets \n336\n-\n1\n.', 'In some embodiments, a blade \n324\n may have a variety of values for the secondary outlet diameters \n344\n-\n2\n for the secondary fluid outlets \n336\n-\n2\n.', 'In the same or other embodiments, a blade \n324\n may have a constant value for the secondary outlet diameter \n344\n-\n2\n for the secondary fluid outlets \n336\n-\n2\n.', 'For example, the primary outlet diameters \n334\n-\n1\n or the secondary outlet diameters \n344\n-\n2\n may vary depending at least partially upon the work rate of the nearest cutting element \n338\n, the number of cutting elements \n338\n the fluid outlet \n336\n serves, and the like.', 'In some embodiments, the primary outlet diameters \n344\n-\n1\n, the secondary outlet diameters \n344\n-\n2\n, or both, may be a percentage of a nozzle opening diameter \n348\n.', 'For example, a primary outlet diameter \n344\n-\n1\n, a secondary outlet diameter \n344\n-\n2\n, or both, may be less than the nozzle opening diameter \n348\n.', 'In other examples, a primary outlet diameter \n344\n-\n1\n or a secondary outlet diameters \n344\n-\n2\n may be less than 90%, 80%, 70%, 60%, 50%, 40%, 30%, or 20% of the nozzle opening diameter \n348\n.', 'Any or each of the fluid outlets located on the nose region, the shoulder region, or both the nose and shoulder regions of the blade \n324\n may be positioned an outlet distance \n350\n from the nearest cutting element \n338\n.', 'The outlet distance \n350\n is the shortest distance between any portion of the fluid outlet and any portion of a cutting face of a cutting element \n338\n.', 'In some embodiments, the outlet distance \n350\n may be at defined or described in relation to a cutting face diameter \n352\n of the cutting elements \n338\n.', 'In some embodiments, an outlet distance \n350\n may be in a range having an upper value, a lower value, or an upper and lower value including any of 5%, 10%, 25%, 50%, 75%, 100%, 150%, 200%, 250%, 300%, 500%, any value therebetween, or any other percentage, of a cutting face diameter \n352\n.', 'For example, an outlet distance \n350\n may be greater than 5% of a cutting face diameter \n352\n.', 'In the same or other examples, an outlet distance \n350\n may be less than or equal to 300% of a cutting face diameter \n352\n (or triple a cutting face diameter \n352\n).', 'In yet other examples, an outlet distance \n350\n may be less than or equal to 200% of a cutting face diameter \n352\n (or double a cutting face diameter \n352\n).', 'In further examples, an outlet distance \n350\n may be in a range of 5% to 300% or in a range of 50% to 200% of a cutting face diameter \n352\n.', 'In some embodiments, at least 10% of the cutting elements \n338\n located on the nose region, the shoulder region, or on both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 400% of a cutting face diameter \n352\n.', 'In other embodiments, at least 10% of the cutting elements \n338\n located on the nose region, the shoulder region, or on both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 300% of a cutting face diameter \n352\n.', 'In other embodiments, at least 50% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 400% of a cutting face diameter \n352\n.', 'In other embodiments, at least 50% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 300% of a cutting face diameter \n352\n.', 'In yet other embodiments, at least 70% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 400% of a cutting face diameter \n352\n.', 'In yet other embodiments, at least 70% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 300% of a cutting face diameter \n352\n.', 'In further embodiments, at least 80% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and the shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 400% of a cutting face diameter \n352\n.', 'In some embodiments, at least 80% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and the shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 300% of a cutting face diameter \n352\n.', 'In some embodiments, at least 10% of the cutting elements \n338\n located on the nose region, the shoulder region, or on both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 200% of a cutting face diameter \n352\n.', 'In other embodiments, at least 10% of the cutting elements \n338\n located on the nose region, the shoulder region, or on both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 100% of a cutting face diameter \n352\n.', 'In other embodiments, at least 50% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 200% of a cutting face diameter \n352\n.', 'In other embodiments, at least 50% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 100% of a cutting face diameter \n352\n.', 'In yet other embodiments, at least 70% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 200% of a cutting face diameter \n352\n.', 'In yet other embodiments, at least 70% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 100% of a cutting face diameter \n352\n.', 'In further embodiments, at least 80% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and the shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 200% of a cutting face diameter \n352\n.', 'In some embodiments, at least 80% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and the shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 100% of a cutting face diameter \n352\n.', 'In some embodiments, at least 10% of the cutting elements \n338\n located on the nose region, the shoulder region, or on both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 500% of a cutting face diameter \n352\n.', 'In other embodiments, at least 10% of the cutting elements \n338\n located on the nose region, the shoulder region, or on both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 50% of a cutting face diameter \n352\n.', 'In other embodiments, at least 50% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 500% of a cutting face diameter \n352\n.', 'In other embodiments, at least 50% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 50% of a cutting face diameter \n352\n.', 'In yet other embodiments, at least 70% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 500% of a cutting face diameter \n352\n.', 'In yet other embodiments, at least 70% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 50% of a cutting face diameter \n352\n.', 'In further embodiments, at least 80% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and the shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 500% of a cutting face diameter \n352\n.', 'In some embodiments, at least 80% of the cutting elements \n338\n located on the nose region, the shoulder region, or both the nose and the shoulder regions are positioned relative to a fluid outlet such that an outlet distance \n350\n of the fluid outlet is less than or equal to 50% of a cutting face diameter \n352\n.', 'In some embodiments, a ratio of the quantity of fluid outlets to the quantity of cutting elements \n338\n in the respective nose region, shoulder region, or both shoulder and nose regions, may be greater than 1.0 (i.e., more fluid outlets than cutting elements \n338\n).', 'In other embodiments, a ratio of the quantity of fluid outlets to the quantity of cutting elements \n338\n in the respective nose region, shoulder region, or both shoulder and nose regions of the blade \n324\n may be less than 1.0 (i.e., less fluid outlets than cutting elements \n338\n).', 'For instance, the ratio may be within a range having an upper value, a lower value, or both upper and lower values including any of 0.05, 0.1, 0.25, 0.35, 0.5, 0.75, 0.85, 0.95, 0.99, or values therebetween.', 'In yet other embodiments, a ratio of the quantity of fluid outlets to the quantity of cutting elements \n338\n on the respective nose region, shoulder region, or both shoulder and nose regions of the blade \n324\n may be equal to 1.0.', 'A blade \n324\n may have any number of designs.', 'For instance, in some embodiments, a back-up, trailing, or secondary row of cutting elements may generally extend in a row that is about parallel to a row of leading or primary row of cutting elements.', 'As shown in \nFIG.', '4-3\n, however, in other embodiments, the blade \n324\n may have other configurations.', 'For instance, in the illustrated embodiment, a leading or primary set/row \n343\n-\n1\n of cutting elements \n338\n may be trailed by one or more back-up or trailing sets/rows \n343\n-\n2\n, \n343\n-\n3\n, \n343\n-\n4\n.', 'In the illustrated embodiment, row \n343\n-\n2\n may extend in a direction more closely parallel to the primary row \n343\n-\n1\n than rows \n343\n-\n3\n, \n343\n-\n4\n.', 'Row \n343\n-\n3\n may also extend in a direction more closely parallel to the primary row \n343\n-\n1\n than row \n343\n-\n4\n.', 'Indeed, in the illustrated embodiment, the trailing row \n343\n-\n4\n may extend in a direction that is about perpendicular to, or that is between 75° and 105° offset from, the primary row \n343\n-\n1\n.', 'As each of the rows \n343\n may be associated with corresponding fluid outlets \n336\n, the fluid outlets corresponding to each of the rows \n343\n may, when viewed in the bottom view shown in \nFIG.', '4-3\n, also follow a similar path.', 'Thus, rows or arrays of secondary fluid outlets \n336\n-\n2\n associated with cutting elements \n338\n in the trailing rows \n343\n-\n2\n, \n343\n-\n3\n, \n343\n-\n4\n may have the same or similar angular offsets relative to rows or arrays of primary fluid outlets \n336\n-\n1\n associated with cutting elements \n338\n-\n1\n of the leading row \n343\n-\n1\n.\n \nFIG.', '5-1\n illustrates the embodiment of a blade \n324\n of \nFIG.', '4-1 through 4-3\n without the bit body.', 'The primary fluid outlets \n336\n-\n1\n may be positioned in a row on the blade \n324\n.', 'The secondary fluid outlets \n336\n-\n2\n may be positioned in a row on the blade \n324\n.', 'FIG.', '5-2\n illustrates a cross-section through the row of primary fluid outlets \n336\n-\n1\n and \nFIG.', '5-3\n illustrates a cross-section through the row of secondary fluid outlets \n336\n-\n2\n.', 'Fluid conduits (such as described in relation to \nFIG.', '2\n) may branch from a chamber or primary conduit within a bit, or may be singular to limit or even prevent loss of energy or fluid pressure between the chamber or primary conduit.', 'As shown in \nFIG.', '5-2\n (taken along line \n2\n-\n2\n of \nFIG.', '5-1\n), in some embodiments, a fluid conduit may be a singular cooling or fluid conduit \n334\n-\n1\n extending from a fluid reservoir \n354\n within the bit \n312\n.', 'The fluid reservoir \n354\n may be a fluid head from which fluid is dispersed in the bit \n312\n, and may not hold or store any fluid.', 'In some embodiments, the fluid reservoir \n354\n may be the chamber \n130\n described in relation to \nFIG.', '2\n.', 'In other embodiments, at least part of the fluid reservoir \n354\n may be round, such as a sphere or an ellipsoid, or a hemispherical or semi-ellipsoid volume as shown in \nFIG.', '5-2\n.', 'A fluid reservoir that is at least partially round (e.g., at a downhole end portion) may reduce energy loss to turbulence of the fluid flow and limit or even prevent internal erosion that may occur in a more conventional crowfoot chamber design having a generally flat downhole end surface, as shown in \nFIG.', '2\n.', 'In other embodiments, the fluid reservoir \n354\n may be the primary conduit \n132\n described in relation to \nFIG.', '2\n.', 'In yet other embodiments, the fluid reservoir \n354\n may be the central conduit \n128\n described in relation to \nFIG.', '2\n.', 'As shown in \nFIG.', '5-3\n (taken along line \n3\n-\n3\n in \nFIG.', '5-1\n), in some embodiments, a fluid conduit may be a branching cooling or fluid conduit \n334\n-\n2\n that includes multiple branching conduits between a fluid reservoir \n354\n to deliver and discharge a fluid therein.', 'While \nFIGS.', '5-2 and 5-3\n illustrate cooling, cleaning, lubricating, or other fluid conduits \n334\n-\n1\n, \n334\n-\n2\n (collectively fluid conduits \n334\n) as extending in a generally linear direction from the fluid reservoir \n354\n and potentially to fluid outlets on the blade \n324\n (e.g., fluid outlets \n336\n-\n1\n and \n336\n-\n2\n of \nFIG.', '4-3\n), and as having a generally constant cross-sectional area/profile, the fluid conduits \n334\n may follow any number of paths and have any number of configurations.', 'For instance, a fluid conduit \n334\n may follow a curved or tortious path, or have a variable cross-sectional area.', 'Such shapes and configurations, particularly in connection with a large number of fluid conduits \n334\n, may be difficult and impractical, if not impossible, to manufacture using conventional mold operations in which sand displacements are used to define fluid paths.', 'However, using three-dimensional printing or additive manufacturing processes to print/form the bit, complex fluid conduits \n334\n may be formed.', 'In some embodiments, the fluid conduits \n334\n may be used to provide customized hydraulics that may be modified at a rig, in a servicing location, or at a manufacturing center, or any other location.', 'In \nFIG.', '5-2\n, for instance, illustrates example obstruction devices, such as balls \n351\n (shown in dashed lines) which may be inserted into the bit \n312\n through a shank of the bit \n312\n.', 'The balls \n351\n may be dropped into a bore of the bit \n312\n, and conveyed into corresponding fluid conduits \n334\n.', 'In some embodiments, magnets or other devices may facilitate positioning of the balls \n351\n.', 'The balls \n351\n can set in the fluid conduits \n334\n and obstruct the flow of fluid therein.', 'As the bit is moved into the wellbore and used in a drilling operation, the balls \n351\n or other obstruction devices may restrict, or even prevent fluid from flowing to one or more fluid outlets.', 'To remove the balls \n351\n, the bit may be turned with the bit face up (i.e., as shown in \nFIG.', '5-2\n).', 'Optionally, a rod may be inserted through a fluid outlet and extended through fluid conduits \n334\n to push against the balls \n351\n to remove them.', 'Based on the positioning of the balls \n351\n, an operator can effectively decide which fluid outlets to turn on or off for a particular application or operation.', 'FIGS.', '6-1 and 6-2\n illustrate yet another embodiment of a bit \n412\n according to some embodiments of the present disclosure.', 'The bit \n412\n may have three blades \n424\n with a junk slot \n440\n positioned angularly between each pair of blades \n424\n.', 'The blades \n424\n may have cutting elements \n438\n positioned thereon with primary fluid outlets \n436\n-\n1\n positioned on the rotationally leading edge of the blades \n424\n.', 'The blades \n424\n may have secondary fluid outlets \n436\n-\n2\n positioned on the blades \n424\n rotationally behind the primary row of cutting elements \n438\n and primary fluid outlets \n436\n-\n1\n.', 'In the embodiment shown in \nFIG.', '6-1\n, some of the fluid outlets \n436\n may be recessed relative to a surface having a pocket therein, and recessed relative to corresponding cutting elements \n438\n, and faces of the cutting elements \n438\n, to which they provide cooling, cleaning, lubricating, or other fluid.', 'Other fluid outlets \n436\n may be formed in the same surface into which a pocket of a corresponding cutting element is positioned.', 'While cutting elements (e.g., cutting elements \n438\n) described herein may include shear cutting elements having a flat or planar cutting surface, with a cutting edge that cuts formation or another workpiece by applying shear forces, the disclosure is not limited to any particular type of cutting element.', 'For instance, \nFIG.', '6-1\n illustrates that at least some cutting elements \n439\n may be non-planar.', 'Example non-planar cutting elements may include cutting elements having conical, frusto-conical, ridged, domed, other three-dimensional shaped cutting faces, or combinations of the foregoing.', 'Moreover, non-planar cutting elements may be used in a nose, shoulder, or gage region of a bit (or any combination thereof), and may be combined with planar cutting elements or different types of non-planar cutting elements.\n \nFIG.', '6-2\n is a bottom view of the embodiment of the bit \n412\n.', 'The bit \n412\n may have one or more nozzle openings \n442\n positioned in a bit body \n422\n.', 'In the same or other embodiments, one or more nozzle openings \n442\n may be located on a blade \n424\n.', 'The blade \n424\n may have secondary fluid outlets \n436\n-\n2\n positioned on the blades \n424\n rotationally behind the primary row of cutting elements \n438\n and primary fluid outlets \n436\n-\n1\n and behind the secondary row of cutting elements \n438\n with one or more additional secondary fluid outlets \n436\n-\n3\n providing fluid for cooling, cleaning, or lubrication to a tertiary row of cutting elements \n438\n.', 'In the illustrated embodiment, the primary, secondary, and tertiary rows of cutting elements \n438\n may be on the same blade \n424\n, and optionally extend from the gage of the bit \n412\n to different positions relative to a central axis of the bit \n412\n.', 'For instance, the primary row of cutting elements \n438\n may extend to a radial position nearest the axis of the bit \n412\n, and the secondary row of cutting elements \n438\n may extend to a radial position nearer the axis of the bit \n412\n than the tertiary row of cutting elements \n438\n.', 'Similarly, the primary fluid outlets \n436\n-\n1\n may be in one or more rows or arrays that extend nearer the axis of the bit \n412\n than the secondary fluid outlets \n436\n-\n2\n associated with the secondary row of cutting elements \n438\n, which in turn may extend nearer the axis of the bit \n412\n than the secondary fluid outlets \n436\n-\n3\n associated with the tertiary row of cutting elements \n438\n.\n \nFIG.', '7\n illustrates yet another bit \n512\n according to some embodiments of the present disclosure.', 'The bit \n512\n may have a cooling or other fluid conduit \n534\n having a non-linear path.', 'For example, the fluid conduit \n534\n may have a curved path.', 'A fluid conduit \n534\n that is at least partially curved may reduce energy loss to turbulence of the fluid flow and limit, or potentially prevent, internal erosion.', 'A fluid conduit \n534\n that is at least partially curved may provide smaller overall dimensions of the fluid conduit \n534\n in an axial or radial direction (or in both axial and radial directions), allowing for greater design flexibility in bit design.', 'In other examples, the fluid conduit \n534\n may have a path with a discontinuous angle.', 'In some embodiments, a non-linear fluid conduit \n534\n may allow the fluid conduit \n534\n to discharge a drilling fluid in a fluid path \n558\n extending across or toward a cutting face \n560\n of a cutting element \n538\n.', 'In some embodiments, the fluid path \n558\n may cause fluid in the direction of flow to engage at least a portion of a cutting face \n560\n of the cutting element \n538\n.', 'For example, the fluid path \n558\n may be directed to intersect with the cutting face \n560\n.', 'In at least one embodiment, the fluid path \n558\n may be directed to intersect with or contact a cutting edge \n562\n (or cutting tip) of the cutting face \n560\n.', 'In accordance with some embodiments of the present disclosure, the fluid path \n558\n may form a nonzero fluid path angle \n554\n with a rotational axis \n556\n of the bit \n512\n relative to the rotational direction of the bit \n512\n.', 'In some embodiments, the fluid path \n558\n may be about parallel to the cutting face \n560\n (to direct fluid flow across the cutting face \n560\n rather than at a particular portion of the cutting face \n560\n), although in other embodiments, such as that shown in \nFIG.', '7\n, the fluid path \n558\n may be non-parallel with the cutting face \n560\n.', 'In some embodiments, the cutting face \n560\n of the cutting element \n538\n may be oriented in the rotational direction of the bit \n512\n and the fluid path \n558\n may be oriented to direct fluid onto the cutting face \n560\n.', 'In some embodiments, the fluid path angle \n554\n may be in a range having an upper value, a lower value, or an upper and lower value including any of 0°, 1°, 5°, 10°, 20°, 30°, 40°, 50°, 60°, 70°, 80°, 90°, or any values therebetween.', 'For example, the fluid path angle \n554\n may be greater than 1°.', 'In other examples, the fluid path angle \n554\n may be less than 90°.', 'In yet other examples, the fluid path angle \n554\n may be between 1° and 60°, or between 5° and 55°.', 'In further examples, the fluid path angle \n554\n may be between 10° and 50°.', 'In yet further examples, the fluid path angle \n554\n may be between 20° and 40°.', 'In \nFIG.', '7\n, for instance, the fluid path angle \n554\n is about 30°.', 'In some embodiments, the angular offset between the fluid path \n558\n and the cutting face \n560\n (e.g., a planar cutting face) may be in a range having an upper value, a lower value, or an upper and lower value including any of 0°, 1°, 5°, 10°, 20°, 30°, 40°, 50°, 60°, 70°, 80°, 90°, or any values therebetween.', 'For example, the fluid path \n558\n may extend at an angle that is 0° offset from the cutting face \n560\n (i.e., is directly across the cutting face \n560\n), that is at least 1° offset from the cutting face \n560\n, that is less than 90° offset from the cutting face \n560\n, or that is 90° offset from the cutting face \n560\n (i.e., is directly into the cutting face \n560\n).', 'In other examples, the fluid path \n558\n may be between 1° and 60°, between 5° and 55°, between 10° and 50°, or between 20° and 40° offset from the cutting face \n560\n.', 'In \nFIG.', '7\n, for instance, the fluid path \n558\n is about 10° offset from the cutting face \n560\n.', 'In some embodiments, the fluid conduit \n534\n may taper to decrease at or near the exit of the fluid conduit \n534\n toward the cutting element \n538\n.', 'A decreasing taper may, for example, accelerate the fluid within the fluid conduit \n534\n.', 'In some embodiments, the fluid conduit \n534\n may taper to reduce the flow area of the fluid conduit \n534\n by a percentage that is in a range having an upper value, a lower value, or an upper and lower value including any of 1%, 5%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or any values therebetween.', 'For example, the fluid conduit \n534\n may taper by a percentage of a flow area of the fluid conduit \n534\n that is greater than 1%, that is less than 90%, that is between 10% and 80%, that is between 20% and 70%, or that is between 30% and 60%.', 'In other embodiments, the fluid conduit \n534\n may taper to widen at or near the exit of the fluid conduit \n534\n toward the cutting element \n538\n.', 'A widening exit may, for example, spread the fluid more broadly upon exit from the fluid conduit \n534\n.', 'In some embodiments, the fluid conduit \n534\n may widen by a percentage of a flow area of the fluid conduit \n534\n that is in a range having an upper value, a lower value, or an upper and lower value including any of 1%, 5%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or any values therebetween.', 'For example, the fluid conduit \n534\n may widen by a percentage of a flow area of the fluid conduit \n534\n that is greater than 1%, that is less than 90%, that is between 10% and 80%, that is between 20% and 70%, or that is between 30% and 60%.', 'In some embodiments, the fluid conduit \n534\n may widen in one or more dimensions and while decreasing in one or more other dimensions, or may widen or decrease by a greater extent in one dimension than in another dimension, thereby changing a cross-sectional shape of the fluid conduit \n534\n.', 'In some embodiments, the fluid conduits \n534\n may lead to nozzles in one or more junk slots.', 'In some embodiments, the fluid conduits \n534\n may lead to fluid outlets on one or more blades.', 'Thus, the description of the fluid conduits \n534\n, including their dimensions, directions, flow paths to or across cutting elements, and the like, may be applied to each other embodiment disclosed herein.', 'As shown in \nFIG.', '8\n, a method \n664\n of removing material with a bit includes flowing \n667\n a fluid through a bit.', 'The method \n664\n further includes directing \n668\n the fluid and/or a fluid path out of a bit.', 'In some embodiments, the method \n664\n may further include discharging \n670\n the fluid along a fluid path along any combination of out a fluid outlet in a blade, across a cutting face of a cutting element, or at a cutting element (e.g., at a cutting portion such as a cutting edge or cutting tip).', 'In some embodiments, discharging \n670\n may further include cooling, cleaning, or lubricating at least a part of the cutting face of the cutting element with the fluid and/or fluid path (e.g., by contacting the cutting face with the fluid).', 'In at least one embodiment, directing \n668\n or discharging \n670\n may include accelerating the fluid through at least a portion of a bit (e.g., within or through a fluid conduit).', 'Accelerating the fluid may increase the energy of the fluid to improve cooling, flushing, deballing, or combinations thereof at the face or other portion of the cutting element.', 'In some embodiments, the method \n664\n may include one or more of the techniques, processes, apparatus, or other features described herein, in any combination.', 'In at least some embodiments, a bit having a system of fluid conduits and fluid outlets according to the present disclosure may cool, clean, or lubricate a cutting elements more efficiently and effectively than a conventional bit.', 'The cutting elements may experience an extended operational lifetime due at least partially to the improved cooling, cleaning, or lubrication, which may, in turn, increase run time and efficiency of a drilling system.', 'Drill bits and other tools having fluid outlets in a blade, fluid conduits leading to a blade, individual fluid outlets for each cutting element (or for groups of cutting elements), fluid conduits directing fluid along a fluid path at or across a cutting element, and other features of the present disclosure may be provided by additive manufacturing techniques.', 'Example techniques may include depositing a composition layer-by-layer into the three-dimensional structure of the cutting tool, where the material composition of each layer is selected and shaped to provide the fluid conduit and fluid outlet positions at each deposition layer level.', 'Methods of depositing a material composition according to embodiments of the present disclosure may use an additive manufacturing deposition device, where each layer may be deposited by one or more feeders from the deposition device.', 'The material composition of each layer, as well as the physical design parameters of each layer (e.g., shape of the outer perimeter of each layer, area of each layer, thickness of each layer, voids where fluid conduits are located, etc.), may be designed prior to deposition using a software modeling program, such as a computer aided design (“CAD”) system.', 'For example, according to embodiments of the present disclosure, a method of making a cutting tool may include modeling the cutting tool using a software modeling program.', 'The modeled cutting tool may have a designed composition and physical structure (such as internal fluid conduit paths and locations, general sizes and shapes, etc.).', 'The cutting tool can be divided into multiple planes, and the composition and structure of the planes can be specified for a particular plane, or for locations within a plane (e.g., mapped into grid patterns).', 'Each layer deposited during the deposition process can be used to build the three dimensional cutting tool body.', 'FIG.', '9\n, for instance, shows a diagram of a cutting tool model and a graph of the gradient composition design of the cutting tool model, according to some embodiments of the present disclosure.', 'As shown, the cutting tool is a drill bit \n900\n that includes a body \n902\n having a plurality of blades \n904\n extending outwardly from the body and forming the cutting end \n906\n of the drill bit \n900\n.', 'A connection end \n908\n is opposite the cutting end \n906\n, and a longitudinal axis \n901\n extends axially through the body \n902\n.', 'The composition design of the drill bit \n900\n (or drill bit model when programmed or designed) includes an axial gradient \n910\n having a gradually changing amount of a first material in the composition along a first distance from the cutting end \n906\n.', 'The first gradient composition may form at least the cutting end portion of the body \n902\n and, in some embodiments, may extend to a connection end portion of the body \n902\n.', 'The axial gradient \n910\n may include a first gradient portion having a first compositional slope \n912\n over a first portion (e.g., the cutting end portion \n906\n and a shank portion of the bit \n900\n) of the distance of the axial gradient \n910\n.', 'A second gradient portion may have a second compositional slope \n914\n over a second portion of the distance of the axial gradient \n910\n (e.g., extending over a connection end portion \n909\n of the body, or the connection end portion \n909\n extending an axial distance from the connection end \n908\n).', 'The first compositional slope \n912\n may be different from the second compositional slope \n914\n.', 'For example, as shown, the second compositional slope \n914\n may include a relatively steep slope having very little or no change in composition over the connection end portion \n909\n of the cutting tool, for example, having less than 5 wt % or less than 1 wt % change in composition over the connection end portion \n909\n of the cutting tool, whereas the first compositional slope \n912\n may include a relatively shallow slope having a relatively larger percent change in composition over the first portion of the axial gradient distance (e.g., the cutting end and shank portions of the cutting tool).', 'In some embodiments, the first compositional slope \n912\n may include a continuously and gradually decreasing amount of erosion resistant material in the composition from the cutting end to the second compositional slope \n914\n (e.g., ranging from up to 90 wt % or 95 wt % of an erosion resistant material in the composition at the cutting end \n906\n to about 30 wt %, 20 wt %, 10 wt %, or less of the erosion resistant material (e.g., carbide, ceramic, etc.) in the composition at a portion of the cutting tool between the shank portion and the connection end portion \n908\n of the cutting tool \n900\n.', 'The second compositional slope \n914\n may include a composition having a substantial majority (or entire) composition of a relatively softer or more machinable metallic material suitable for machining (e.g., steel, tungsten, etc.).', 'In some embodiments, a compositional slope may be undefined (x=0), where the composition may not change over a selected portion of the cutting tool.', 'For example, in some embodiments, a connection end portion \n909\n of a cutting tool \n900\n may be printed or otherwise formed as having a uniform composition of steel, tungsten, or relatively more machinable metallic matrix material suitable for machining and/or welding to a connection piece.', 'A connection end portion \n909\n of a cutting tool \n900\n may include the portion of the cutting tool extending an axial distance from the cutting end ranging from, for example, about 1 in.', '(2.5 cm), 2 in.', '(5.1 cm), 4 in.', '(10.2 cm), or 6 in.', '(15.2 cm), depending on the overall size of the cutting tool \n900\n.', 'In some embodiments, the connection end portion \n909\n may be greater than 6 in.', '(15.2 cm) in length.', 'In some embodiments, a cutting end portion \n909\n may include the portion of the cutting tool \n900\n extending an axial distance from the cutting end \n906\n ranging up to 5%, 10%, 20%, 30%, 50%, or 70% of the total axial length of the cutting tool \n900\n.', 'The drill bit \n900\n (or drill bit model) may be divided into a plurality of thin cross-sectional, two-dimensional planes, and one or more compositions may be mapped to each plane.', 'For instance, for a two-dimensional gradient such as the gradient shown in \nFIG.', '9\n (where the gradient changes in a single axial direction, but not in a radial direction), each plane may have a single composition, and the same composition may be used for a single plane (or for a few planes), before changing to another composition that is also constant for the next plane.', 'In other embodiments, the composition may vary within a plane.', 'In some embodiments, the compositions of the drill bit \n900\n may be graphed or mapped as a function of axial distance along the drill bit \n900\n, where the composition \n921\n at the first axial location \n920\n may be different from the composition \n923\n at the second axial location \n922\n, and where the difference between the first composition \n921\n and the second composition \n923\n corresponds to the designed first compositional slope \n912\n.', 'While the composition may vary uniformly across the length of at least a portion of the drill bit \n900\n, in other embodiments, the composition mapped to the drill bit \n900\n may be varied (non-uniform) across two or more planes, such that multiple gradient compositions may be formed axially through the drill bit \n900\n (where different axial gradient compositions may be formed in different radial positions of the drill bit according to the radial positions of the varied composition across the two or more grid patterns).', 'According to embodiments of the present disclosure, a method of manufacturing a drill bit may include providing a model of the drill bit \n900\n, dividing the model into multiple planes, mapping a composition to each of the planes (or to cells or grids within each plane), and successively depositing a volume of the composition using a deposition device according to each mapped composition, in sequential layers to build a three dimensional body of the drill bit.', 'While the cutting portion of a drill bit may have a generally constant slope to the composition, in other embodiments, the composition may vary in other manners.', 'FIG.', '10\n, for instance, shows a diagram of a cutting tool \n1000\n having a gradient composition design graphed along a cross-sectional view of the cutting tool.', 'As shown, the cutting tool \n1000\n is a drill bit including a body \n1002\n having a plurality of blades \n1004\n extending outwardly from the body \n1002\n and forming the cutting end \n1006\n of the drill bit.', 'A connection end \n1008\n is opposite the cutting end \n1006\n, and a longitudinal axis \n1001\n extends axially through the body \n1002\n.', 'The composition design of the cutting tool \n1000\n includes an axial gradient \n1010\n having a gradually changing amount of a first material in the composition along a first distance from the cutting end \n1006\n.', 'The first gradient composition may form at least the cutting end portion \n1006\n of the body \n702\n and, in some embodiments, may extend to a connection end portion of the body \n702\n.', 'According to embodiments of the present disclosure, gradient compositions may include a constant compositional slope along the entire gradient.', 'In some embodiments, a gradient composition may include multiple gradient portions at different regions, or which form different regions, of the cutting tool, where adjacent gradient portions have different compositional slopes.', 'In some embodiments, a gradient composition may include one or more stepped changes in gradient compositional slope. \nFIG.', '10\n shows an example of an embodiment having a gradient composition including multiple gradient portions forming different regions of the cutting tool \n1000\n, where adjacent gradient portions have different compositional slopes.', 'As shown, the axial gradient \n1010\n may include a first gradient portion having a first compositional slope \n1012\n over a first portion (e.g., the cutting end portion) of the length of the cutting tool \n1000\n, and a second gradient portion having a second compositional slope \n1014\n over a second portion of the length of the cutting tool \n1000\n.', 'The axial gradient \n1010\n may further include a third compositional slope \n1016\n over a third portion of the length of the cutting tool \n1000\n.', 'The first compositional slope \n1012\n may be different from the second compositional slope \n1014\n, and the third compositional slope \n1016\n may be different from the second compositional slope \n1014\n and equal to or different than the first compositional slope \n1012\n.', 'While three portions of the drill bit \n1000\n are shown having different slopes \n1012\n, \n1014\n, and \n1016\n relative to an adjacent portion, in other embodiments, the axial gradient \n1010\n may have more than three different slopes or other gradient or varied compositional portions.', 'The compositional slopes \n1012\n, \n1014\n, \n1016\n of the axial gradient \n1010\n may be defined over the same interval of the total gradient distance (or cutting tool length), where different compositional slopes correspond to different rates of changes in percent composition of a first material in the composition.', 'In other words, the rate of change by percent composition of at least a first material in the composition differs as compared to an adjacent portion.', 'In some embodiments, the compositional slope of a gradient portion may be defined as the distance the gradient portion extends over a difference in percent composition of at least a first material in the composition from one end to the other of the gradient portion.', 'In some embodiments, a gradient composition extending axially through a cutting tool may have a first gradient portion having a first compositional slope extending a first distance of the gradient composition through a cutting end portion of the cutting tool, extending the axial length of the cutting tool from an axially lowermost portion of the cutting tool (e.g., a blade profile nose) through the entire axial length of the cutting profile of the cutting tool (e.g., to a gage portion of a blade profile).', 'In some embodiments, a first gradient portion of the composition forming the cutting end of a cutting tool may have an amount of an erosion resistant material, such as tungsten carbide, in the composition ranging from about 90 wt % to about 60 wt % as an upper limit of the first gradient portion positioned at a first end of the first gradient portion (e.g., at the axially lowermost portion of the cutting tool) to about 60 wt % to about 30 wt % as a lower limit of the first gradient portion positioned at an opposite end of the first gradient portion (e.g., in a gage region of the cutting tool).', 'A gradient composition may further include a second gradient portion extending from the first gradient portion through a shank portion of the cutting tool, the second gradient portion having a second compositional slope over a second distance.', 'In some embodiments, a gradient composition may include more than two gradient portions having different compositional slopes extending partial axial lengths along a cutting tool.', 'In the embodiment shown in \nFIG.', '10\n, the gradient composition includes a first gradient portion having the first compositional slope \n1012\n and forming a cutting end portion of the cutting tool \n1000\n.', 'The cutting end gradient may have a compositional slope \n1012\n that is steeper (less change in composition of the first material over the same length) than an adjacent gradient portion having the second compositional slope \n1014\n.', 'For example, the cutting end gradient may have an amount of an erosion resistant material (e.g., tungsten carbide) within a range having a lower limit, an upper limit, or lower and upper limits including any of 20 wt %, 30 wt %, 40 wt %, 50 wt %, 60 wt %, 70 wt %, 80 wt %, 90 wt %, 95 wt %, 99 wt %, or values therebetween.', 'A composition having the upper limit of the compositional range may form the nose region of the drill bit and the composition having the lower limit of the compositional range may form a portion of a shoulder or gage region of the drill bit.', 'The gradient composition design shown in \nFIG.', '10\n further includes a second gradient portion having a second compositional slope \n1014\n, which may extend an axial distance along, for example, the shank of the drill bit and between the first gradient portion and a connection end portion.', 'The second gradient portion may have an amount of an erosion resistant material (e.g., tungsten carbide) within a range including a lower limit, an upper limit, or lower and upper limits including any of 0 wt %, 10 wt %, 20 wt %, 30 wt %, 40 wt %, 50 wt %, 60 wt %, 70 wt %, 80 wt %, and values therebetween.', 'In other embodiments, the lower or upper limit may be greater than 80 wt %.', 'The gradient composition design shown in \nFIG.', '10\n further includes a third gradient portion having a third compositional slope \n1016\n and forming the connection end portion of the cutting tool \n1000\n.', 'The connection end gradient optionally has a compositional slope \n1016\n that is steeper (less change in composition of the first material over an equal distance) than the adjacent gradient portion having the second compositional slope \n1014\n, and optionally the gradient portion having the first compositional slope \n1012\n.', 'For example, the connection end gradient may have an amount of an erosion resistant material (e.g., tungsten carbide) within a range including a lower limit, an upper limit, or lower and upper limits including any of 0 wt %, 10 wt %, 20 wt %, 30 wt %, 40 wt %, 50 wt %, and values therebetween.', 'In other embodiments, the lower or upper limit may be greater than 50 wt %.', 'In some embodiments, rather than having a gradient composition, a connection end portion of a cutting tool may have a uniform composition including API rated connection end material, such as API rated steel.', 'The connection end portion of the cutting tool may be machined to form a connection (which may be used to connect the cutting tool to a drill string, for example), or the final geometry of a connection end may be formed by the additive manufacturing process to meet API specifications.', 'Further, in some embodiments, rather than printing the connection end of a cutting tool in the additive manufacturing process to form the cutting tool and connection end as a single piece, a cutting tool body may be formed according to embodiments disclosed herein with a connection end that may be welded or mechanically attached to a separate connection piece, where the separate connection piece may connect the cutting tool to a drill string, for example.', 'In some embodiments, the gradient composition may include gradually decreasing amounts of tungsten carbide or other wear or erosion resistant materials, and increasing amounts of steel from a cutting end portion of a cutting tool to connection end portion of the cutting tool to provide the cutting end portion with greater erosion resistance.', 'In some embodiments, differing types and/or sizes of tungsten carbide or other erosion resistant material (e.g., carbides or borides) may be deposited at an interval to form a gradient composition having an erosion resistance gradient (i.e., a gradient in the erosion resistance of the composition), where relatively higher erosion resistant compositions may be located in a cutting end portion of a cutting tool.', 'Referring now to \nFIG.', '11\n, an example of an embodiment having a gradient composition including stepped changes in gradient compositional slope is shown.', 'As shown, a cutting tool \n1100\n may include a body \n1102\n having a plurality of blades \n1104\n extending outwardly from the body and forming the cutting end \n1106\n of the cutting tool \n1100\n, a connection end \n1108\n opposite the cutting end \n1106\n, and a longitudinal axis \n1101\n extending axially through the body \n1102\n.', 'The composition design of the cutting tool model \n1100\n includes a gradient composition \n1110\n optionally having one or more axial gradients \n1112\n, \n1114\n, \n1116\n with a gradually changing amount of a first material in the composition along an axial distance of the cutting tool.', 'In the embodiment shown, the axial gradients \n1112\n, \n1114\n, \n1116\n have negatively sloping compositional slopes and may be separated by axial portions of the cutting tool having a constant composition over an axial length of the axial portions), or by axial portions of the cutting tool having relatively steep compositional slopes (e.g., less than 5 wt % or less than 1 wt % change in an amount of a first material of the composition over the length of the axial portions), such that the gradient composition of the cutting tool has a generally stepped pattern in composition along a length of the cutting tool.', 'In some embodiments, rather than a sloping axial gradient \n1112\n, \n114\n, \n116\n, there may be an abrupt change in composition.', 'In the illustrated embodiment, a first axial portion of the cutting tool extending a distance from the cutting end \n1106\n of the cutting tool \n1100\n may include a first composition having a vertical (or undefined) compositional slope \n1111\n, representing no compositional change over the length of the first axial portion.', 'A second axial portion of the cutting tool extends a distance from the first axial portion and may include a second composition having compositional slope \n1112\n.', 'A third axial portion of the cutting tool extends a distance from the second axial portion and may include a third composition having a constant composition and a vertical (or undefined or very steep) compositional slope \n1113\n.', 'A fourth axial portion of the cutting tool extends a distance from the third axial portion and may include a fourth composition having compositional slope \n1114\n.', 'A fifth axial portion extends a distance from the fourth axial portion and may include a fifth composition having an undefined compositional slope \n1115\n.', 'A sixth axial portion of the cutting tool extends a distance from the fifth axial portion and may include a sixth composition having compositional slope \n1116\n.', 'A seventh axial portion of the cutting tool extends a distance from the sixth axial portion and may include a seventh composition having an undefined compositional slope \n1117\n.', 'The compositional slopes of the second, fourth and sixth axial portions \n1112\n, \n1114\n, \n1116\n may be the same or different.', 'Further, although the stepped pattern of gradient composition \n1110\n includes seven axial portions forming the stepped pattern, other embodiments may include a different number of axial portions forming a stepped pattern.', 'For example, in some embodiments, a gradient composition may include three, four, five, six or more than seven axial portions having compositional slopes forming a stepped pattern.', 'Further, steps may be formed with abrupt changes in composition rather than using gradual, sloped changes.', 'In the embodiment shown, the axial portions may correspond with locations along the length of the cutting tool encountering different wear or erosion conditions.', 'For example, the first composition forming the first axial portion of the cutting tool may extend a distance from the cutting end \n1106\n and may have a wear or erosion resistance suitable for encountering the most severe wear or erosion when compared to the remaining portions of the cutting tool.', 'Compositions forming transitional sections of the cutting tool (e.g., the fourth axial portion forming the transition from the bladed region of the cutting tool to the shank portion of the cutting tool) may have compositional slopes that transition the material composition from more erosion resistant compositions to tougher or more machinable compositions.', 'The seventh axial portion of the cutting tool (having the seventh composition with undefined compositional slope \n1117\n) may form a connection end portion of the cutting tool, extending a distance from the connection end \n1108\n of the cutting tool, where the seventh composition may be relatively more machinable compared with the remaining axial portions of the cutting tool \n1100\n.', 'Further, compositional slopes of one or more axial portions may vary according to axial position along a length of the cutting tool.', 'For example, axial portions of a cutting tool \n1100\n having a transition in size and/or shape (e.g., an axial portion including the transition from the bladed region of a bit to the shank region of the bit; an axial portion including the transition from the shoulder region of a bit to the gage region of the bit; an axial portion including the transition from the shank region of a bit to a connection region of the bit) may have relatively shallow compositional slopes compared to axial portions of the cutting tool having a uniform size and/or shape.', 'For example, \nFIG.', '11\n shows transition regions having negatively sloping compositional slopes (in second axial portion \n1112\n, fourth axial portion \n1114\n, and sixth axial portion \n1116\n) and alternating axial portions having undefined slopes (\n1111\n, \n1113\n, \n1115\n, \n1117\n).', 'In the embodiment shown in \nFIG.', '11\n, second axial portion including second compositional slope \n1112\n is positioned in a transition region from a shoulder region of the cutting tool \n1100\n to a gage region of the cutting tool, and the axial portions adjacent to and on either side of the second axial portion have relatively uniform compositions, where the first axial portion has undefined compositional slope \n1111\n through the shoulder region of the cutting tool \n1100\n, and the third axial portion has undefined compositional slope \n1113\n through the gage region of the cutting tool \n1100\n.', 'According to embodiments of the present disclosure, a cutting tool may have one or more transitional axial portions extending an axial length along the cutting tool that includes a change in size and/or shape of the cutting tool outer perimeter, where transitional axial portions may have a greater change in composition over the transitional axial portion than the change in composition over an adjacent axial portion.', 'In some embodiments, compositional slopes of axial gradients may vary at different radial positions of a cutting tool to correspond with different conditions encountered by the cutting tool.', 'For example, bladed drill bits may have a plurality of blades extending outwardly from the drill bit body, where two or more of the blades may have different shapes and/or sizes.', 'In some embodiments, for example, primary blades may be longer and extend to a radial position nearer the longitudinal axis \n1101\n of the bit than do secondary or tertiary blades.', 'The different blades may have axial gradients with different compositional slopes to correspond with the individual conditions of each blade type.', 'For example, a first type of blade larger than a second type of blade on a drill bit may have a greater percent composition of erosion resistant material than the second type of blade.', 'In some embodiments, an axial gradient formed through all or a portion of the first type of blade from the cutting end of the bit may have a relatively steeper compositional slope (or undefined slope) than an axial gradient formed through all or a portion of the second type of blade from the cutting end of the bit, such that an erosion resistant material may be present at a relatively higher percentage (by weight) for a distance from the cutting end in the first blade type farther than that in the second blade type.', 'Different blades may have axial gradient compositions formed therethrough having the same or different compositional slopes.', 'For example, a relatively larger blade on a drill bit may have a relatively steeper compositional slope of a change in wear/erosion resistant material (having relatively less change in erosion resistant material amount by percent composition over the distance of the gradient) when compared with another relatively smaller blade on the drill bit in order to provide the relatively larger blade with more erosion resistance.', 'In some embodiments, however, compositional slopes may provide different changes in material properties to one or more blades of a drill bit.', 'For example, in some embodiments, one or more blades of a first type may be relatively taller and/or relatively more narrow when compared to a second blade type, where a first axial gradient may be formed through the first type of blade and a second axial gradient (different from the first axial gradient) may be formed through the second type of blade to provide the first type of blade with relatively higher toughness when compared to the second type of blade.', 'In some embodiments, axial gradients having equal or unequal compositional slopes may be provided in a cutting tool to provide different axial portions of the cutting tool with relatively increased strength when compared to the remaining axial portions of the cutting tool.', 'Different material properties along an axial gradient formed through a cutting tool may be provided by progressively increasing or decreasing one or more of the constituent materials forming the gradient composition.', 'FIG.', '12\n shows a cross sectional view of a downhole cutting tool \n1200\n having a bit body \n1210\n with a cutting end \n1212\n, a connection end \n1214\n, a longitudinal axis \n1202\n extending axially therethrough, and a plurality of blades \n1220\n extending outwardly from the bit body \n1210\n.', 'The blades \n1220\n may have a blade profile at the cutting end \n1212\n that includes a cone region \n1222\n proximate the longitudinal axis \n1202\n, a nose region \n1224\n extending from the cone region to a shoulder region \n1226\n, and the shoulder region \n1226\n extending to a gage region \n1228\n.', 'The cone region \n1222\n includes the radially innermost region of the blade profile, extending generally from the longitudinal axis \n1202\n to the nose region \n1224\n.', 'The cone region may extend axially downward (in a direction away from the connection end \n1214\n), and may be generally concave, planar, or convex.', 'Adjacent the cone region \n1222\n is the nose region \n1224\n, which includes the region immediately around the axially lowermost point of the blade profile, referred to as a blade profile nose.', 'At the blade profile nose, the slope of a tangent line to the blade profile is zero.', 'Thus, as used herein, the term “blade profile nose” may refer to the point along a convex region of a blade profile of a cutting tool in rotated profile view at which the slope of a tangent to the blade profile is zero.', 'The nose region \n1224\n may sometimes be considered part of the shoulder (or the upturned curve) region \n1226\n of the blade profile.', 'As shown, the shoulder region \n1226\n may be generally convex.', 'Moving radially outwardly, adjacent the shoulder region \n1226\n is the gage region \n1228\n, which extends parallel to the longitudinal axis \n1202\n at the outer radial periphery of the blade profile.', 'The cutting tool body \n1210\n and blades \n1220\n may be integrally formed as a single piece having a varying composition throughout the cutting tool, for example, as opposed to other cutting tools that may have one or more components attached to or formed around a blank (e.g., a carbide portion of a body and blades formed in a mold around a steel blank used for forming the connection end of the cutting tool).', 'The cutting tool \n1200\n may be formed both as an integral, single piece and as having a varying composition using additive manufacturing, as discussed in more detail herein.', 'In the embodiment shown in \nFIG.', '12\n, the varying composition may include a gradient composition having gradients \n1230\n, \n1232\n in multiple directions, each gradient \n1230\n, \n1232\n extending a distance through the body and having variable and optionally progressively increasing and/or decreasing amounts of a first material in the composition along the direction in which the gradient extends.', 'The gradients in composition are represented by arrows in \nFIG.', '12\n.', 'The gradient composition may include radial gradients \n1230\n extending from an interior portion to an exterior portion of one or more blades (or the tool body), where the interior portion composition has a first amount of the first material by percent composition, the exterior portion composition has a second amount of the first material by percent composition greater or lesser than the first amount.', 'The first material may gradually or otherwise increase or decrease from the first amount to the second amount along the gradients \n1230\n.', 'In some embodiments, a gradient may include multiple steps, changes or other variations of the composition in the radial direction.', 'For instance, both increasing and decreasing amounts of a first material in a composition may be positioned along the distance of the gradient (e.g., to provide an increase in and a decrease in erosion resistance along the direction and distance of the gradient).', 'One or more radial gradients in a cutting tool composition may extend a radial distance from an outer surface of the body (or from an outer surface of a blade extending from the body), where the radial distance may be greater than or equal to 75 percent of a cutting tool radius measured from the outer surface to the longitudinal axis \n1202\n of the cutting tool \n1200\n.', 'In some embodiments, one or more radial gradients may extend a radial distance equal to the cutting tool radius (from an outer surface of the cutting tool to the longitudinal axis).', 'In some embodiments, a radial gradient may extend less than 75 percent of the cutting tool radius, for example, from an outer surface along a cone region \n1222\n of a blade to an outer surface along a shoulder region \n1226\n or gage region \n1228\n of the blade.', 'The arrows shown in \nFIG.', '12\n representing the radial gradients \n1230\n are spread a thickness (or axial height) along a full or partial gage region \n1228\n of the blades \n1220\n.', 'According to some embodiments of the present disclosure, one or more radial gradients may span an entire blade profile (from the nose to an upper surface of the gage region), a partial axial height of a blade profile (e.g., an axial height of a shoulder region \n1226\n, an axial height of a cone region \n1222\n, or from a blade profile nose to a partial axial height of the gage region \n1228\n), or an axial height greater than the entire blade profile (e.g., from a blade profile nose to the connection end \n1214\n or from a blade profile nose to a portion of the body \n1210\n axially above the blades \n1220\n).', 'Further, where the rate of composition change along the gradient (referred to as a compositional slope) is progressive or continual, the rate of composition change along one or more radial gradients may vary along the axial height that the radial gradient expands.', 'In the embodiment shown, the cutting tool gradient composition may further include an axial gradient \n1232\n extending an axial distance in an axial direction (parallel with the longitudinal axis \n1202\n), where the changing amounts of the first material varies along the axial direction.', 'For example, in some embodiments an axial gradient \n1232\n may include gradually decreasing amounts of a first material in the composition along the axial direction from the cutting end \n1212\n toward the connection end \n1214\n, where the first material has the greatest erosion resistance relative to the remaining constituents of the composition.', 'The axial gradient \n1232\n may span an entire diameter (width) of the cutting tool or may span a partial width of the cutting tool \n1200\n.', 'Further, the rate of composition change along the gradient (the compositional slope) of one or more axial gradients may vary along the width the axial gradient spans.', 'The cutting tool shown in \nFIG.', '12\n is a fixed cutter drill bit.', 'However, other cutting tool bodies may be manufactured according to embodiments of the present disclosure to having multi-gradient compositions, for example, to provide erosion resistant outer surfaces, relatively tougher interior regions, and transitioning compositions therebetween.', 'According to embodiments of the present disclosure, a cutting tool may have one or more gradient compositions extending in a single direction or in multiple directions.', 'For example, a cutting tool may include one or more radial gradients extending in a radial direction and having progressively increasing and/or decreasing amounts of a first material in the composition along the radial direction, one or more axial gradients extending in an axial direction and having progressively increasing and/or decreasing amounts of a first material in the composition along the axial direction, one or more lateral gradients extending in a lateral direction (parallel with a radial direction) and having progressively increasing and/or decreasing amounts of a first material in the composition along the lateral direction, or one or more azimuthal gradients extending in an azimuthal direction (e.g., around an outer perimeter of the cutting tool) and having progressively increasing and/or decreasing amounts of a first material in the composition.', 'In some embodiments, a cutting tool may include gradients extending in a combination of two or more of the axial, radial, lateral and azimuthal directions (e.g., extending laterally and axially).', 'Multi-directional gradient compositions (compositions having gradients extending in multiple directions) may form a three-dimensional compositional gradients or variances throughout the cutting tool.', 'The rate of compositional change of a first material in the composition may be defined in terms of a compositional slope of an amount of the first material along the gradient composition, where the compositional slope is equal to an interval of the total gradient distance over a change in percent composition of the first material in the composition.', 'According to some embodiments of the present disclosure, multi-gradient compositions may include two or more of the gradients having different compositional slopes.', 'In some embodiments, multi-gradient compositions may have each gradient with substantially equal compositional slopes, where two or more gradients extend in different directions and/or extend different distances.', 'Cutting tool compositions may include one or more of an erosion resistance material, such as transition metal carbide, e.g., tungsten carbide, a metallic binder, and steel, where different combinations of the materials and in different amounts may be distributed in different regions of the cutting tool.', 'For example, a composition at a cutting tool cutting end may include a mixture of tungsten carbide and metallic binder without steel, while a cutting tool connection end may have a composition absent tungsten carbide that includes steel, or which may include tungsten without tungsten carbide or with reduced amounts of tungsten carbide.', 'Suitable metallic binders may include alloys of copper, nickel, zinc, and tin.', 'For example, a binder alloy may have a composition by weight of about 52 wt % copper, 15 wt % nickel, 23 wt % manganese, and 9 wt % zinc.', 'In another example, a binder alloy may include a composition by weight of manganese in a range of about 0 to 25 wt %, nickel in a range of about 0 to 15 wt %, zinc in a range of about 3 to 20 wt %, tin in a range of more than 1 wt % to about 10 wt %, and copper making up the remainder by weight of the alloy composition.', 'Steels may include carbon steel (e.g., steel having about 0.1-0.5 wt % carbon content) or other machinable steels.', 'Gradient compositions formed through the cutting tool may include a progressively increasing or decreasing amount of a first material in the composition and optionally a progressively decreasing or increasing amount of a second material inversely corresponding to the change in percent composition of the first material along the direction in which the gradient extends.', 'For example, a gradient composition may include a progressively decreasing amount of a wear or erosion resistant material (e.g., tungsten carbide) in the composition, along the gradient and a progressively increasing amount of a second material in the composition (e.g., steel, tungsten, or a metallic binder material) inversely corresponding to the change in percent composition of the erosion resistant material along the direction in which the gradient extends, thereby providing a composition having a relatively higher erosion resistance at a first end of the gradient and a composition having a relatively higher toughness at a second end of the gradient.', 'A changing composition in a cutting tool may be provided by depositing the composition layer-by-layer into the three dimensional structure of the cutting tool, where the material composition of each layer is selected to provide the changing composition at the deposition layer level.', 'Methods of depositing a material composition according to embodiments of the present disclosure may use an additive manufacturing deposition device, where each layer may be deposited using one or more feeders or nozzles of the deposition device.', 'The material composition of each layer, as well as the physical design parameters of each layer (e.g., shape of the outer perimeter of each layer, area of each layer, thickness of each layer, locations of different material compositions), may be designed prior to deposition using a software modeling program, such as a computer aided design (“CAD”) system.', 'According to some embodiments, an additive manufacturing process of forming a cutting tool body may include depositing a first layer of a selected material composition (according to a first grid pattern of a cutting tool body model) using one or more feeders of a deposition device.', 'The first layer composition may include a first material, a second material and a metallic binder, where the first material is present in a first amount by percent composition.', 'Subsequent layers may be deposited using the feeders of the deposition device, where one or more of the subsequent layers may have a subsequent material composition different than the first layer composition and including a second amount of the first material by percent composition.', 'A laser or electron beam (“E-beam”) may be used to heat each layer as or after each layer is deposited to a sintering temperature to sinter the layers as they are deposited, thereby forming the cutting tool body in a sequential layer-by-layer manner.', 'Sintering layers as they are deposited using a laser, in a layer-by-layer manner, may be referred to as laser sintering.', 'In some embodiments, the first layer may include different cells or portions that have different compositions, thereby creating a gradient or variation in composition that is within a layer.', 'Accordingly, compositional variation may occur axially (i.e., different layers have different compositions), radially (i.e., different portions of the same layer have different compositions), or combinations of axially and radially.', 'In some embodiments, the minimum thickness of the layers is limited by the particle size of the material that is being layered, with the minimum layer thickness being equal to or greater than the diameter of the particular material being layered.', 'In some embodiments, each layer may have a thickness ranging from 0.002 in.', '(50 μm) to 0.020 in.', '(510 μm).', 'The number of distinct layers may vary.', 'For instance, the number of layers may be within a range including a lower limit, an upper limit, or lower and upper limits including any of 400, 500, 1,000, 2,000 5,000, 10,000, 100,000, or values therebetween.', 'In some embodiments, the number of layers may be less than 400 or greater than 100,000.', 'The number of layers may be at least partially dependent on the height/size of the cutting tool being built and the size of particles being deposited.', 'In some embodiments, different layers have different heights.', 'As discussed herein, in some embodiments, multiple types of material in a composition (for example, materials having a difference in shape, size, or chemical composition) may be applied as a single layer.', 'For example, a first composition may be deposited by a deposition device in a first region of a layer, and a second composition may be deposited by a separate pass of the deposition device in a second region of the layer, such that the deposited layer has at least two distinct regions formed of the first composition and the second composition.', 'In other embodiments, a material mixture of a first composition and second composition (the first composition having at least a different shape, size, or chemical composition than the second composition) may be deposited in a single pass of a deposition device.', 'For example, a deposition device may have two or more feeders or nozzles, where each feeder/nozzle may be used to deposit a different material in a different region of the layer during a single pass.', 'In another example, a deposition device may have two or more feeders or nozzles, where each feeder/nozzle may deposit a different material simultaneously during a pass to form a layer of composite material, e.g., a combination of metallic material and an adhesive or an organic binder.', 'According to some embodiments, a deposition device may have two or more feeders or nozzles, where each feeder/nozzle may feed one of multiple materials forming a composition.', 'Feeders on a deposition device may include nozzles to control the amount of material fed from the feeder, thereby helping to control the resolution of a composition layer being deposited.', 'In some embodiments, nozzles on feeders may be adjustable to allow material to be flowed through the feeder at higher or lower flow rates.', 'According to some embodiments of the present disclosure, multiple materials in a composition may be deposited by a deposition device according to a grid pattern.', 'The grid pattern may be developed according to a three-dimensional model of a cutting tool body having gradients or other variations in composition formed throughout, where the cutting tool model is divided into a plurality of thin cross-sectional, two dimensional planes to develop grid patterns according to the composition making each cross-sectional plane.', 'FIG.', '13\n is a cross-sectional view of an example of a drill bit model having a multi-gradient compositional design taken from the sectional plane.', 'The drill bit \n1300\n includes a body \n1302\n having a plurality of blades \n1304\n extending outwardly from the body and forming the cutting end of the drill bit (where the sectional view is taken at the cutting end of the bit).', 'The drill bit composition includes gradients \n1310\n extending in multiple directions, including radial directions shown in the sectional view, and axial directions as shown and discussed herein.', 'In the embodiment shown, the gradient composition includes radial gradients \n1310\n extending from interior portions of the drill bit to exterior portions of the drill bit.', 'Particularly, the radial gradients \n1310\n formed along the sectional plane \n1320\n exposed in the sectional view of \nFIG.', '13\n extend from an interior portion of each blade \n1304\n to exterior portions of the blades \n1304\n, where the composition along an outer surface \n1312\n of the blade \n1304\n has greater erosion resistance than the composition at the interior portion \n1314\n of the blade \n1304\n.', 'The particular embodiment in \nFIG.', '13\n also shows that a gradient may extend radially from an interior portion of each blade \n1304\n to interior portions of the blades \n1304\n, and/or in one or more circumferential directions from an interior of a blade \n1304\n toward exterior leading and trailing surfaces of the blade \n1304\n.', 'In some embodiments, the gradient composition may include gradually increasing or decreasing amounts of tungsten carbide or other wear/erosion resistant materials, and decreasing amounts of steel from an interior portion of a cutting tool to an exterior portion of the cutting tool to provide the exterior portions with greater erosion resistance along the exterior of the cutting tool.', 'In some embodiments, differing types and/or sizes of tungsten carbide or other wear/erosion resistant material (e.g., carbides or borides) may be deposited at an interval to form a gradient composition having an erosion resistance gradient (i.e., a gradient in the erosion resistance of the composition).', 'In the embodiment shown, the gradient composition of the cutting tool \n1300\n may include varying mixtures of steel, tungsten carbide (and/or other erosion resistant material), a metallic binder, and optionally, an adhesive or organic binder to provide regions of relatively higher wear or erosion resistance.', 'A relatively lower wear/erosion resistant composition in the gradient composition may include relatively higher amounts of steel and/or metallic binder, and a relatively higher wear/erosion resistant composition in the gradient composition may include relatively higher amounts of tungsten carbide.', 'For example, the interior portions \n1314\n of the cutting tool may have a composition including between 0 and 30 wt % tungsten carbide, while the exterior portions along the outer surface \n1312\n of the cutting tool may have a composition including between 40 and 90 wt % tungsten carbide (and in particular embodiments, between 60 and 90 wt % tungsten carbide), where the gradient composition may gradually transition from the interior portion composition to the exterior portion composition by including gradually increasing amounts of tungsten carbide moving from the interior portion to the exterior portion.', 'In some embodiments, a “gradually increasing” amount of tungsten carbide may include a change of less than 5 wt % of tungsten carbide at a resolution interval (where the resolution interval is an interval of the total distance of the gradient in composition equal to the resolution of the deposition device, and the resolution of the deposition device being equal to the thickness of the material layer deposited by the deposition device).', 'In the embodiment shown in \nFIG.', '13\n, the sectional plane \n1320\n is taken along a plane perpendicular to a longitudinal axis of the cutting tool.', 'According to some embodiments of the present disclosure, a cutting tool model may be divided as a plurality of radial planes (sectioned perpendicularly to a longitudinal axis extending axially through the cutting tool).', 'However, in some embodiments, sectional planes may be divided along a non-axial axis.', 'The compositional design along the sectional plane \n1320\n may be transferred to a grid pattern \n1330\n of the sectional plane \n1320\n.', 'Particularly, as shown, the compositional design along the sectional plane \n1320\n may be transferred to a grid pattern \n1330\n of the sectional plane \n1320\n by transferring the pattern of the compositional design over a grid overlaying the outline or perimeter of the cutting tool \n1300\n along the sectional plane \n1320\n.', 'In such a manner, gradients \n1310\n formed through the compositional design may be transferred onto a grid of the grid pattern having cells \n1332\n of a selected size, such that a particular composition according to the compositional design is designated to each cell \n1332\n.', 'Cell sizes may have widths, for example, from about 0.002 in.', '(50 μm) to 0.020 in.', '(510 μm).', 'In some embodiments, cell sizes may be based on a particle size, where the cell size in a grid may be selected according to the particle sizes of the composition.', 'For example, in some embodiments, the cell size of a grid pattern may be one, two, three, five, or ten times larger than a maximum particle size in the composition.', 'By designating a composition to each cell on grid patterns forming a cutting tool model and depositing the composition in an additive manufacturing process to build a cutting tool according to the grid patterns, a change in composition (e.g., in gradient compositions) may be provided at the cell level, thereby providing a cutting tool formed by additive manufacturing having highly controlled changes in composition.', 'According to embodiments of the present disclosure, a method of manufacturing a downhole cutting tool may include providing a model of a cutting tool having a varying composition.', 'The cutting tool model may be divided into a plurality of sectional planes (e.g., in radial planes along an axial direction of the cutting tool), where the sectional planes may have a thickness according to the depth of the layers to be deposited during the additive manufacturing process of forming the cutting tool, such as described above.', 'The composition of the cutting tool model may vary along at least one of the sectional planes, as well as across adjacent sectional planes (e.g., in the axial direction in embodiments having sectional planes divided along the axial direction).', 'A grid pattern may be generated for each of the sectional planes, where the compositional design of each sectional plane forming the cutting tool is mapped over a grid on the grid pattern.', 'A deposition device having multiple feeders and nozzles may be used to deposit the varying amounts of materials forming the varying composition of the cutting tool model using an intelligent programming system to control the multiple feeders.', 'Methods using the multi-feeder deposition device may include depositing a first layer of a composition on a substrate according to a first grid pattern.', 'As used herein, a substrate may refer to a platform or base that is separate from but supports the cutting tool as it is manufactured, or a substrate may refer to any layer of the cutting tool that has a second or subsequent layer deposited thereon, depending on the stage of manufacture.', 'For example, a first step of manufacturing a cutting tool may include depositing a first layer on a substrate or base that is separate from the cutting tool, and in a second step of manufacturing the mold, the first layer may be the substrate for a second or subsequent layer deposited thereon.', 'A first grid pattern may have a varying composition or a uniform composition across each of the cells forming the grid pattern, where the multiple feeders of the deposition device may deposit the materials forming the composition design of the first grid pattern in a corresponding grid layout on a substrate.', 'For example, a first grid pattern may include a uniform compositional design including a mixture of tungsten carbide and a metallic binder.', 'A tungsten carbide feeder of the deposition device may deposit tungsten carbide, and a metallic binder feeder may deposit metallic binder in a first layer on a substrate according to the compositional design of the first grid pattern.', 'A laser may be passed over the deposited first layer to heat the metallic binder material to a sintering temperature to sinter the composition of the first layer.', 'A second grid pattern of the cutting tool model may have a varying composition or a uniform composition across each of the cells forming the second grid pattern.', 'Further, the second grid pattern may have the same compositional design as the first grid pattern or may have a different composition design as the first grid pattern, depending on whether an axial compositional gradient is designed to extend into the first and second sectional planes and/or depending on the interval of a gradient composition (e.g., when a gradient composition interval is greater than or equal to the thickness of two deposited layers, the composition of adjacent layers may be the same, or when a gradient composition interval is equal to the thickness of one deposited layer, the composition of adjacent layers may be different).', 'For example, in embodiments where an axial compositional gradient is designed to extend into the first and second sectional planes, a second grid pattern may include a compositional design different from the first grid pattern and including a mixture of tungsten carbide, steel and a metallic binder.', 'A tungsten carbide feeder of the deposition device may deposit tungsten carbide in locations of the second layer corresponding to the designated cells of the second grid pattern containing tungsten carbide, a steel feeder of the deposition device may deposit steel in locations of the second layer corresponding to the designated cells of the second grid pattern containing steel, and a metallic binder feeder may deposit metallic binder in locations of the second layer corresponding to the designated cells of the second grid pattern containing metallic binder.', 'A laser may be passed over the deposited second layer to heat the metallic binder material to a sintering temperature to sinter the composition of the second layer to the first layer.', 'Subsequent grid patterns of the cutting tool model may have a varying composition or a uniform composition across each of the cells forming the subsequent grid patterns.', 'Further, subsequent grid patterns may have the same compositional design as an adjacent grid pattern and/or may have a different composition design as an adjacent grid pattern.', 'For example, in embodiments having a subsequent grid pattern with a varying composition (e.g., having a radial gradient composition), the subsequent grid pattern may include a compositional design having different amounts of tungsten carbide in different regions of the subsequent grid pattern, different amounts of steel in the different regions of the subsequent grid pattern, and different amounts of metallic binder in the different regions of the subsequent grid pattern.', 'A tungsten carbide feeder of the deposition device may deposit tungsten carbide in locations of the subsequent layer corresponding to the designated cells of the subsequent grid pattern containing tungsten carbide, a steel feeder of the deposition device may deposit steel in locations of the subsequent layer corresponding to the designated cells of the subsequent grid pattern containing steel, and a metallic binder feeder may deposit metallic binder in locations of the subsequent layer corresponding to the designated cells of the subsequent grid pattern containing metallic binder.', 'A laser may be passed over the deposited subsequent layer to heat the metallic binder material to a sintering temperature to sinter the composition of the subsequent layer to the previously deposited and adjacent layer.', 'Varying compositions (deposited throughout different deposited layers and/or deposited along a single deposited layer) may include material mixtures having varying particle shapes, varying particle size, and/or different material types.', 'Referring now to \nFIG.', '14\n, an example is shown of a diagram of multiple grid patterns taken from a cutting tool model having a gradient composition design graphed along a cross-sectional view of the cutting tool.', 'As shown, the cutting tool model is a drill bit model \n1400\n including a body \n1402\n having a plurality of blades \n1404\n extending outwardly from the body and forming the cutting end \n1406\n of the drill bit, a connection end \n1408\n opposite the cutting end \n1406\n, and a longitudinal axis \n1401\n extending axially through the body \n1402\n.', 'The composition design of the drill bit model \n1400\n includes an axial gradient \n1410\n having a gradually decreasing amount of a first material in the composition along an axial distance from the cutting end \n1406\n and a radial gradient \n1420\n having a gradually decreasing and increasing amount of the first material in the composition along a radial distance extending between two opposite outer surfaces of the bit.', 'The axial gradient \n1410\n may include a first axial gradient portion having a first compositional slope \n1412\n over a first portion (e.g., the cutting end portion and a shaft portion of the bit) of the distance of the axial gradient \n1410\n.', 'A second axial gradient portion may have a second compositional slope \n1414\n over a second portion of the distance of the axial gradient \n1410\n (e.g., extending over a connection end portion \n1409\n of the body, the connection end portion \n1409\n extending an axial distance from the connection end \n1408\n).', 'The first compositional slope \n1412\n may be different from the second compositional slope \n1414\n.', 'For example, as shown, the second compositional slope \n1414\n may include a relatively steep slope having very little or no change in composition over the connection end portion \n1409\n of the cutting tool, for example, having less than 1 wt % or less than 5 wt % change in composition over the connection end portion \n1409\n of the cutting tool, whereas the first compositional slope \n1412\n may include a relatively shallow slope having a relatively larger percent change in composition over the first portion of the axial gradient distance (e.g., the cutting end and shaft portions of the cutting tool).', 'The first compositional slope \n1412\n may include a gradually decreasing amount of erosion resistant material in the composition from the cutting end to the second compositional slope \n1414\n (e.g., ranging from up to 90 or 95 wt % of a wear/erosion resistant material in the composition at the cutting end \n1406\n to about 30 wt %, 20 wt %, 10 wt %, or less of the erosion resistant material in the composition at a portion of the cutting tool between the shaft portion and the connection end portion of the cutting tool).', 'The second compositional slope \n1414\n may include a composition having a substantial majority (or entire) composition of soft metallic material suitable for machining (e.g., steel).', 'In some embodiments, a compositional slope may be undefined (x=0), where the composition may not change over a selected portion of the cutting tool.', 'For example, in some embodiments, a connection end portion of a cutting tool may be printed as having a uniform composition of steel or other soft metallic matrix material suitable for machining and/or welding to a connection piece.', 'A connection end portion of a cutting tool may include the portion of the cutting tool extending an axial distance from the cutting end as discussed herein, depending on the overall size of the cutting tool.', 'In some embodiments, a cutting end portion may include the portion of the cutting tool extending a percentage of the axial distance from the cutting end as discussed herein.', 'The radial gradient \n1420\n may include a first radial gradient portion having a first compositional slope \n1422\n and a second radial gradient portion having a second compositional slope \n1424\n, different than the first composition slope \n1422\n.', 'In the embodiment shown, the first radial gradient portion has a progressively decreasing amount of the first material by percent composition from an outer surface of the bit to an interior portion of the bit, and the second radial gradient portion has a progressively increasing amount of the first material by percent composition from the interior portion to an opposite outer surface of the bit.', 'The first and second radial gradient portions may have compositional slopes substantially mirror to one another to create a radial gradient design across the width of the bit of increased amounts of the first material at the outer surfaces and progressively decreasing amounts of the first material in a direction toward the central longitudinal axis \n1401\n of the bit.', 'Other embodiments may include radial gradient(s) having different compositional slopes to form different radial compositional designs.', 'In some embodiments, greater amounts of an erosion resistant material (e.g., carbide) by percent composition may be at an end of a radial gradient at an outer surface of the cutting tool, and greater amounts of a relatively tougher material (e.g., metal) by percent composition may be at an end of the radial gradient in an interior portion of the cutting tool.', 'The drill bit model \n1400\n may be divided into a plurality of thin cross-sectional, two dimensional planes to develop grid patterns according to the composition making each cross sectional plane.', 'Each grid pattern \n1430\n, \n1432\n is mapped from a cross-sectional plane transversely extending through the longitudinal axis \n1401\n at different axial locations, along adjacent intervals of the axial gradient distance.', 'The composition of the drill bit along each plane is mapped into the grid patterns \n1430\n, \n1432\n, such that each cell of the grid has the particular composition of the corresponding locations in the drill bit model \n1400\n.', 'The compositions of the drill bit model \n1400\n may be graphed as a function of axial position within the drill bit model \n1400\n (e.g., the particular cross-sectional plane) and as a function of radial position within the drill bit model (e.g., using polar, x-y, or other coordinate systems).', 'The composition mapped to cells may be varied (non-uniform) across two or more grid patterns, such that multiple gradient compositions may be formed axially and radially through the multiple grid patterns.', 'According to embodiments of the present disclosure, a method of manufacturing a drill bit may include providing a drill bit model \n1400\n, dividing the drill bit model \n1400\n into multiple cross-sectional planes, mapping a composition of each of the planes into a grid pattern (e.g., grid patterns \n1430\n and \n1432\n), and successively depositing a volume of the composition using a deposition device according to each of the grid patterns in sequential layers to build a three-dimensional body of the drill bit or other cutting tool.', 'According to embodiments of the present disclosure, bladed drill bits may have a plurality of blades extending outwardly from the drill bit body.', 'According to embodiments of the present disclosure, different blades of a cutting tool may have one or more gradients with different compositional gradients to correspond with the individual conditions of each blade type.', 'For example, an axial gradient formed from the cutting end of a bit through all or a portion of a first type of blade may have a relatively steeper compositional slope (or undefined slope) than an axial gradient formed from the cutting end of the bit through all or a portion of a second type of blade, such that a wear or erosion resistant material may be present at a relatively higher percentage (by composition) for a distance from the cutting end in the first blade type farther than that in the second blade type.', 'In some embodiments, different gradients (axial, radial, lateral or combinations thereof) may be formed in a first type of blade and a second type of blade on a bit (e.g., a primary vs. secondary blade), where a larger amount of change in percent composition of erosion resistant material along the gradient(s) may be present in the second type of blade than the first type of blade.', 'In some embodiments, different gradients may be designed through different types of blades of a cutting tool to provide a first type of blade (larger than a second type of blade) with a greater amount of wear/erosion resistant material at the outer surfaces of the first type of blade than at the outer surfaces of the second type of blade.', 'In some embodiments, a first type of blade larger than a second type of blade on a drill bit may have a greater percent composition of erosion resistant material than the second type of blade.', 'Different blades may have gradient compositions formed there through having the same or different compositional slopes.', 'For example, a relatively larger blade on a drill bit may have a relatively steeper compositional slope of a change in wear/erosion resistant material (having relatively less change in erosion resistant material amount by weight percent composition over the distance of the gradient) when compared with another relatively smaller blade on the drill bit in order to provide the relatively larger blade with more erosion resistance.', 'However, in some embodiments, compositional slopes may provide different changes in material properties to one or more blades of a drill bit.', 'For example, in some embodiments, one or more first type of blade of a drill bit may be relatively taller and/or relatively more narrow when compared to a second type of blade of the drill bit, where a first gradient may be formed through the first type of blade and a second gradient (different from the first axial gradient) may be formed through the second type of blade to provide the first type of blade with relatively higher toughness through an interior region of the first type of blade when compared to the second type of blade.', 'In some embodiments, gradients having equal or unequal compositional slopes may be provided in a cutting tool to provide different portions of the cutting tool with relatively increased strength when compared to the remaining portions of the cutting tool.', 'Different material properties along one or more gradients formed through a cutting tool may be provided by progressively increasing or decreasing one or more of the constituent materials forming the gradient composition.', 'In some embodiments, compositions may comprise powdered materials.', 'The powdered materials in embodiments covered by this disclosure may include carbides, such as tungsten carbide, oxides, borides, nitrides, silicates and metals, such as steel, alloys, and metallic binder materials.', 'In some embodiments, the powdered materials that are metals may include silicon, titanium, tantalum, molybdenum, and tungsten.', 'In one or more embodiments, a second material may be coated on a first material to form a material mixture.', 'The particle size of the powdered materials may be from about 10 nm to about 200 μm.', 'In more particular embodiments, the particle flow during the layering process may be enhanced when the particle size of the powdered materials is at least about 50 μm.', 'In some embodiments, the particle size of the powdered materials may be from about 10 μm to about 200 μm.', 'In more particular embodiments, the particle size of the powdered materials may be from about 50 μm to about 100 μm.', 'In some embodiments, powdered materials may be granulated prior to their deposition.', 'The granulated powders may be substantially circular and possess diameters from about 0.1-4 mm.', 'For example, in some embodiments, granulated powders may be formed by the granulation of a single material, while in other embodiments, granulated powders may be formed by the granulation of at least two different materials (having a difference in at least one of particle shape, particle size, or material type) to form a material mixture.', 'During the granulation of at least two different materials, the materials may form a substantially homogenous granule.', 'In other embodiments, one material may be confined substantially to the interior of a granule while the other material may be substantially on the exterior of the granule to form a granule with a core-shell motif.', 'A core-shell granule may be created by granulating one powdered material first to create a first granule and then granulating the first granule with another powdered material to create the final core-shell granule.', 'However, in some embodiments, a core-shell granule may result from the direct granulation of at least two powdered materials with differing particle sizes.', 'In some embodiments, the core of the granule may substantially include the powdered materials with larger particle size and the exterior of the granule may include the powdered materials with smaller particle size, while in some embodiments the opposite may also occur.', 'In embodiments using granulated powders, the particle size of the powders making up the granule may be as small as about 10 nanometers.', 'In embodiments using organic binders or adhesives, suitable organic binders may be or include one or more waxes or resins that are insoluble, or at least substantially insoluble, in water.', 'Waxes may include, for example, animal waxes, vegetable waxes, mineral waxes, synthetic waxes, or any combination thereof.', 'Illustrative animal waxes may include, but are not limited to, bees wax, spermaceti, lanolin, shellac wax, or any combination thereof.', 'Illustrative vegetable waxes may include, but are not limited to, carnauba, candelilla, or any combination thereof.', 'Illustrative mineral waxes may include, but are not limited to, ceresin and petroleum waxes (e.g., paraffin wax).', 'Illustrative synthetic waxes may include, but are not limited to, polyolefins (e.g., polyethylene), polyol ether-esters, chlorinated naphthalenes, hydrocarbon waxes, or any combination thereof.', 'An organic binder may also include waxes that are insoluble in organic solvents.', 'Illustrative waxes that are insoluble in organic solvents may include, but are not limited to, polyglycol, polyethylene glycol, hydroxyethylcellulose, tapioca starch, carboxymethylcellulose, or any combination thereof.', 'Illustrative organic binders may also include, but are not limited to, starches, and cellulose, or any combination thereof.', 'The organic binders may also include, but are not limited to, microwaxes or microcrystalline waxes.', 'Microwaxes may include waxes produced by de-oiling petrolatum, which may contain a higher percentage of isoparaffinic and naphthenic hydrocarbons as compared to paraffin waxes.', 'Other suitable binders may include, for example, sodium silicate, acrylic copolymers, arabic gum, portland cement and the like.', 'Binders may be deposited in solid or liquid form.', 'Particle size ranges for materials deposited by deposition devices may depend, for example, on the type of material being deposited, the region of the cutting tool body being formed, the type of deposition device used, and the amount of porosity desired in the cutting tool body design, but may range from nano-sized, micro-sized and larger.', 'For example, in some embodiments, particles being deposited may range from less than 1 micron, from 1-10 microns, from greater than 10 microns, and greater than 100 microns, where various sub-ranges thereof may be used alone or in combination to form a layer of material being deposited.', 'According to embodiments of the present disclosure, selected material mixtures may be deposited to form different regions of a cutting tool body, depending on, for example, the desired properties of the cutting tool body.', 'For example, according to some embodiments, one or more layers being deposited to form a cutting tool body may include a first composition (comprising a first material mixture) and a second composition (comprising a second material mixture different from the first material mixture), where the first and second compositions form different regions of the one or more layers.', 'The different regions may provide desired properties to different parts of the cutting tool body.', 'By using the grid patterns of a cutting tool model and intelligent deposition system described herein to control multiple feeders to deposit selected materials in locations corresponding to designated cells in the grid patterns, changes in the built cutting tool body composition may be precisely controlled to provide fine resolution gradient compositions through the cutting tool body.', 'For example, intelligent deposition systems according to embodiments of the present disclosure may be used to provide a fine resolution gradient composition having a compositional slope of greater than 0 and less than 5 percent by composition change in amount of a first material in the composition over an interval equal to the resolution of the deposition device (i.e., the thickness of the material layer deposited by the deposition device).', 'Forming gradients of different types of materials through a cutting tool may provide different gradients of material properties.', 'For example, gradients of progressively decreasing amounts of tungsten carbide and corresponding progressively increasing amounts of steel and/or other metallic matrix material may provide a gradient having increased erosion resistance at the end of the gradient having greater amounts of tungsten carbide and having increased material strength and toughness at the end of the gradient having greater amounts of steel and/or other metallic matrix material.', 'Further, cutting tool bodies having multi-gradient compositions may be built using intelligent deposition systems according to embodiments disclosed herein, where the built cutting tool body may be ready for use with or without further processing.', 'For example, by laser or electron beam sintering layers deposited by intelligent deposition systems according to embodiments of the present disclosure, a cutting tool body having a multi-gradient composition may be built in a layer-by-layer manner to exact or near exact specifications.', 'Although the embodiments of bits, cutting elements, and fluid conduits have been primarily described with reference to wellbore drilling operations, the embodiments within the scope of the present disclosure may be used in applications other than the drilling of a wellbore.', 'In other embodiments, bits, cutting elements, and fluid conduits according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources.', 'For instance, fluid conduits of the present disclosure may be used in a borehole used for placement of utility lines, or in a bit used for a machining or manufacturing process.', 'Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.', 'The articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements in the preceding descriptions.', 'The terms “coupled,” “attached,” “connected,” “secured,” and the like are intended to encompass connections that are both direct and indirect.', 'Features that are integrally formed from a monolithic body are also to be considered coupled, attached, connected, or secured together.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'For example, any element described in relation to an embodiment herein is combinable with any element of any other embodiment described herein, unless such features are described as, or by their nature are, mutually exclusive.', 'Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure.', 'A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result.', 'The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.', 'Where ranges are described in combination with a set of potential lower or upper values, each value may be used in an open-ended range (e.g., at least 50%, up to 50%), as a single value, or two values may be combined to define a range (e.g., between 50% and 75%).', 'It should be understood that any directions or reference frames in the preceding description are merely relative directions or movements.', 'For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.', 'The term “may” when used with components or features is intended to indicate that such features are provided by some embodiments, but other embodiments are contemplated which do not include such components or features.', 'Features of any embodiment disclosed herein may be used in combination with features of any one or more other embodiments.', 'For instance, cutting tools with customized hydraulics may be produced with material composition variations in one or more directions, although they may also be produced without such variations.', 'A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure.', 'Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function.', 'It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function.', 'Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.', 'Features of various embodiments may be used in any combination, except where such features are clearly mutually exclusive.', 'While cutting tools having customized hydraulics may be produced using additive manufacturing and gradients according to other embodiments disclosed herein, but may be produced without such gradients.', 'The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics.', 'The described embodiments are to be considered as illustrative and not restrictive.', 'The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description.', 'Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.'] | ['1.', 'A downhole cutting tool, comprising:\na body comprising: a cutting end; a connection end; a longitudinal axis extending axially through the body; a plurality of layers successively sintered together, wherein each layer of the plurality of layers comprises a first material, and each layer of the plurality of layers comprises a thickness between 0.002 to 0.020 inches; and a gradient composition having one or more gradients, each gradient extending a distance in a respective direction through the body, and each gradient comprising changing amounts of the first material in the gradient composition along the respective direction in which the gradient extends; wherein the one or more gradients comprise an axial gradient extending along the longitudinal axis and at least one radial gradient extending in a radial direction, the changing amounts of the first material in the axial gradient varying along the longitudinal axis from the cutting end to the connection end, and the at least one radial gradient comprises progressively increasing and decreasing amounts of the first material along the radial direction.', '2.', 'The tool of claim 1, wherein the gradient composition of the axial gradient comprises a compositional slope equal to an interval of the distance over the changing amounts of the first material in percent composition of the first material in the gradient composition, wherein the compositional slope varies over the distance.', '3.', 'The tool of claim 1, wherein the at least one radial gradient extends a radial distance from an outer surface of the body to an interior portion of the body, the radial distance being greater than or equal to 75 percent of a body radius measured from the outer surface to the longitudinal axis.', '4.', 'The tool of claim 1, wherein the cutting tool is a drill bit comprising:\na plurality of blades extending outwardly from the body;\nwherein the gradient composition comprises one or more gradients extending from an interior portion of each blade to an exterior portion of each blade, the interior portion composition comprising a first amount of the first material by percent composition, the exterior portion composition comprising a second amount of the first material by percent composition greater than the first amount, and the changing amounts of the first material gradually increasing from the first amount to the second amount.', '5.', 'The tool of claim 4, wherein a first blade of the plurality of blades has a first compositional slope and a second blade of the plurality of blades has a second compositional slope different from the first compositional slope, the first compositional slope equal to an interval of the distance over a change in percent composition of the first material in the composition, and the second compositional slope equal to the interval of the distance over a different change in percent composition of the first material in the composition.', '6.', 'The tool of claim 1, wherein at least one of the one or more gradients comprises a changing amount of a second material inversely corresponding to the change in percent composition of the first material along the direction in which the respective gradient extends, the second material comprising steel.', '7.', 'The tool of claim 1, wherein the one or more gradients correspond to an erosion profile of the cutting tool, the erosion profile comprising a map of forces encountered by the cutting tool during a downhole operation.', '8.', 'The tool of claim 1, wherein each gradient of the one or more gradients comprises changing amounts of the first material of less than 5 wt % of the first material at a resolution interval along the direction in which the respective gradient extends.', '9.', 'The tool of claim 1, wherein the first material comprises an erosion resistant material.', '10.', 'A method of manufacturing a downhole cutting tool, the method comprising:\nsuccessively depositing a volume of at least two materials in sequential layers using a deposition device to build a three dimensional body of the cutting tool having a gradient composition with at least two gradients in composition extending in different directions along the body, each gradient comprising a progressively increasing or decreasing amount of a first material by percent composition, wherein the body of the cutting tool comprises an exterior portion and an interior portion, the gradient composition of the exterior portion having greater erosion resistance than the gradient composition of the interior portion; and\nsuccessively sintering each layer to an adjacent layer of the sequential layers.', '11.', 'The method of claim 10, wherein successively depositing comprises:\ndepositing the at least two materials in a first layer on a substrate according to a first grid pattern, the first layer having a first material composition pattern corresponding to the first grid pattern; and\ndepositing the at least two materials in multiple layers over the first layer, each layer of the multiple layers having a sequential material composition pattern corresponding to sequential grid patterns,\nwhere the first material composition pattern and the sequential material composition patterns form the gradient composition when deposited.', '12.', 'The method of claim 11, further comprising:\nmodeling the cutting tool;\ndividing the cutting tool model into multiple planes; and\nmapping the material composition of one of the planes into the first grid pattern.', '13.', 'The method of claim 10, wherein the deposition device comprises at least two feeders, each feeder feeding one of the at least two materials, and one of the at least two materials is a metallic binder material.\n\n\n\n\n\n\n14.', 'The method of claim 10, comprising:\nsimulating the cutting tool during a downhole operation;\ngenerating an erosion profile of the cutting tool based on the simulating; and\ndesigning the gradient composition to correspond with the erosion profile.', '15.', 'The method of claim 10, wherein each layer of the multiple layers comprises a thickness between 0.002 to 0.020 inches.', '16.', 'The method of claim 10, wherein the first material comprises an erosion resistant material.', '17.', 'The method of claim 10, wherein the cutting tool is a drill bit comprising:\na plurality of blades extending outwardly from the body, wherein each blade of the plurality of blades comprises an interior blade portion and an exterior blade portion;\nwherein the at least two gradients comprise: a first gradient extending radially from the interior blade portion to the exterior blade portion, the gradient composition of the interior blade portion comprising a first amount of the first material by percent composition, the gradient composition of the exterior blade portion comprising a second amount of the first material by percent composition greater than the first amount, and the changing amounts of the first material gradually increasing from the first amount to the second amount; and a second gradient extending circumferentially from an exterior leading surface of each blade to an exterior trailing surface of each blade.', '18.', 'A downhole cutting tool, comprising:\na body comprising a cutting end, a connection end, and a longitudinal axis extending therethrough;\na first gradient composition comprising a progressively decreasing amount of a first material in the composition along the longitudinal axis a first distance from the cutting end, the first gradient composition forming a cutting end portion of the body and having a first compositional slope, the first compositional slope equal to the first distance over a first total amount of change in composition of the first material; and\na second gradient composition having a second compositional slope different from the first compositional slope, the extending along the longitudinal axis a second distance from the cutting end portion of the body, wherein the second compositional slope is equal to the second distance over a second total amount of change in composition of the first material.', '19.', 'The tool of claim 18, comprising at least one radial gradient extending in a radial direction, wherein the at least one radial gradient comprises a progressively increasing amount of the first material in the composition along the radial direction from the longitudinal axis.', '20.', 'The tool of claim 18, comprising at least one radial gradient extending in a radial direction, wherein the at least one radial gradient comprises changing amounts of the first material along the radial direction.'] | ['FIG.', '1 is a schematic representation of a drilling system, according to embodiments of the present disclosure;; FIG.', '2 is a side cross-sectional schematic representation of a bit having hydraulic fluid conduits, according to some embodiments of the present disclosure;; FIG.', '3 is a bottom view of another bit having hydraulic fluid conduits, according to some embodiments of the present disclosure;; FIG.', '4-1 is a side view of a bit, according to some embodiments of the present disclosure;; FIG.', '4-2 is a perspective view of the bit of FIG.', '4-1;; FIG.', '4-3 is a bottom view of the bit of FIG.', '4-1;; FIG.', '5-1 is a bottom view of the blade of the bit of FIG.', '4-1;; FIG.', '5-2 is a cross-sectional view of the blade of FIG.', '5-1;; FIG.', '5-3 is another cross-sectional view of the blade of FIG.', '5-1;; FIG.', '6-1 is a perspective view of yet another bit, according to some embodiments of the present disclosure;; FIG.', '6-2 is a bottom view of the bit of FIG.', '6-1;; FIG. 7 is a side cross-sectional view of a bit, according to further embodiments of the present disclosure;; FIG. 8 is a flowchart of a method of removing material with a bit, according to some embodiments of the present disclosure;; FIG.', '9 is a cross-sectional, schematic view of a downhole cutting tool having a gradient composition, according to some embodiments of the present disclosure;; FIG.', '10 is a cross-sectional, schematic view of a downhole cutting tool having a gradient composition, according to additional embodiments of the present disclosure;; FIG.', '11 is a cross-sectional, schematic view of a downhole cutting tool having a gradient composition, according to further embodiments of the present disclosure;; FIG.', '12 is a cross-sectional, schematic view of a downhole cutting tool having a multi-directional gradient, according to some embodiments of the present disclosure;; FIG.', '13 shows a grid pattern developed from a cutting tool model, according to some embodiments of the present disclosure; and; FIG.', '14 is a cross-sectional diagram of a cutting tool model and graphs of a gradient composition design of the cutting tool model, according to some embodiments of the present disclosure.; FIG.', '1 shows one example of a drilling system 100 for forming a wellbore 102 in an earth formation 104.', 'The drilling system 100 includes a drilling tool assembly 106 that extends downward into the wellbore 102.', 'The drilling tool assembly 106 may include a drill string 108 and a bottomhole assembly (“BHA”) 110 attached to a downhole end portion of drill string 108.', 'The BHA 110 may include a bit 112 for drilling, milling, reaming, or performing other cutting operations within the wellbore.; FIG.', '4-1 illustrates another embodiment of a bit 312, according to some embodiments of the present disclosure.', 'The bit 312 includes cutting elements 338 coupled to one or more blades 324 having a nose region 337, a shoulder region 339, and a gage region 341.', 'At least a portion of the cutting elements 338 may be positioned in pockets 326 on the nose region 337 and the shoulder region 339.', 'In some embodiments, a blade 324 may have a row of primary pockets 326-1 and a row of secondary pocket 326-2.', 'For example, a blade 324 may have a row of primary cutting elements 338 on the blade 324 in the row of primary pockets 326-1 and a row of secondary cutting elements 338 positioned in the secondary pockets 326-2.', 'The row of secondary pockets 326-2 may be positioned rotationally behind the primary pockets 326-1 relative to a rotational direction of the bit 312.', 'The cutting elements 338 in the primary pockets 326 may therefore rotationally lead the cutting elements in the secondary pockets 326-2.; FIG.', '4-3 illustrates a bottom view of the nose region and shoulder region (as described in relation to FIG.', '4-1) of the blade 324 shown in FIGS.', '4-1 and 4-2.', 'The blade 324 includes primary fluid outlets 336-1 and secondary fluid outlets 336-2.', 'The fluid outlets 336 may each have an equal outlet diameter and shape, or the fluid outlets 336 may have varying outlet diameters or shapes, as shown in FIG.', '4-3.', 'In some embodiments, the fluid outlets 336 may have outlet diameters that vary at least partially based upon the work rate of nearest cutting elements 338 (e.g., the volume of material removed by the cutting element during period of time or at a predetermined cutting element velocity).', 'For example, a fluid outlet 336 proximate to a cutting element 338 with a higher work rate may having a larger outlet diameter to provide greater fluid flow to the cutting element 338 with a higher work rate.', 'In some embodiments, the additional fluid flow may provide additional cleaning (i.e., clearance of debris and material) of the cutting element 338.', 'In the same or other embodiments, the additional fluid flow may provide additional cooling to the cutting element 338.', 'In at least some embodiments, the additional cleaning or cooling may increase the operational lifetime of the cutting element 338.', 'In some embodiments, differences in size may be used where fluid outlets 336 are used for cooling, cleaning, or providing flow to different numbers of cutting elements 338.', 'For instance, a fluid outlet 336 directing fluid flow to a single cutting element 338 may have a smaller size than a fluid outlet 336 directing fluid flow to two or more cutting elements 338.', 'Similarly, a fluid outlet 336 directing flow to multiple cutters may have a more elongated shape, in some embodiments, to disperse the flow more than would a circular fluid outlet 336.', 'Combinations of the foregoing may also be used.; FIG.', '5-1 illustrates the embodiment of a blade 324 of FIG.', '4-1 through 4-3 without the bit body.', 'The primary fluid outlets 336-1 may be positioned in a row on the blade 324.', 'The secondary fluid outlets 336-2 may be positioned in a row on the blade 324.', 'FIG.', '5-2 illustrates a cross-section through the row of primary fluid outlets 336-1 and FIG.', '5-3 illustrates a cross-section through the row of secondary fluid outlets 336-2.; FIGS.', '6-1 and 6-2 illustrate yet another embodiment of a bit 412 according to some embodiments of the present disclosure.', 'The bit 412 may have three blades 424 with a junk slot 440 positioned angularly between each pair of blades 424.', 'The blades 424 may have cutting elements 438 positioned thereon with primary fluid outlets 436-1 positioned on the rotationally leading edge of the blades 424.', 'The blades 424 may have secondary fluid outlets 436-2 positioned on the blades 424 rotationally behind the primary row of cutting elements 438 and primary fluid outlets 436-1.', 'In the embodiment shown in FIG.', '6-1, some of the fluid outlets 436 may be recessed relative to a surface having a pocket therein, and recessed relative to corresponding cutting elements 438, and faces of the cutting elements 438, to which they provide cooling, cleaning, lubricating, or other fluid.', 'Other fluid outlets 436 may be formed in the same surface into which a pocket of a corresponding cutting element is positioned.', '; FIG.', '6-2 is a bottom view of the embodiment of the bit 412.', 'The bit 412 may have one or more nozzle openings 442 positioned in a bit body 422.', 'In the same or other embodiments, one or more nozzle openings 442 may be located on a blade 424.', 'The blade 424 may have secondary fluid outlets 436-2 positioned on the blades 424 rotationally behind the primary row of cutting elements 438 and primary fluid outlets 436-1 and behind the secondary row of cutting elements 438 with one or more additional secondary fluid outlets 436-3 providing fluid for cooling, cleaning, or lubrication to a tertiary row of cutting elements 438.', 'In the illustrated embodiment, the primary, secondary, and tertiary rows of cutting elements 438 may be on the same blade 424, and optionally extend from the gage of the bit 412 to different positions relative to a central axis of the bit 412.', 'For instance, the primary row of cutting elements 438 may extend to a radial position nearest the axis of the bit 412, and the secondary row of cutting elements 438 may extend to a radial position nearer the axis of the bit 412 than the tertiary row of cutting elements 438.', 'Similarly, the primary fluid outlets 436-1 may be in one or more rows or arrays that extend nearer the axis of the bit 412 than the secondary fluid outlets 436-2 associated with the secondary row of cutting elements 438, which in turn may extend nearer the axis of the bit 412 than the secondary fluid outlets 436-3 associated with the tertiary row of cutting elements 438.; FIG.', '7 illustrates yet another bit 512 according to some embodiments of the present disclosure.', 'The bit 512 may have a cooling or other fluid conduit 534 having a non-linear path.', 'For example, the fluid conduit 534 may have a curved path.', 'A fluid conduit 534 that is at least partially curved may reduce energy loss to turbulence of the fluid flow and limit, or potentially prevent, internal erosion.', 'A fluid conduit 534 that is at least partially curved may provide smaller overall dimensions of the fluid conduit 534 in an axial or radial direction (or in both axial and radial directions), allowing for greater design flexibility in bit design.', 'In other examples, the fluid conduit 534 may have a path with a discontinuous angle.', 'In some embodiments, a non-linear fluid conduit 534 may allow the fluid conduit 534 to discharge a drilling fluid in a fluid path 558 extending across or toward a cutting face 560 of a cutting element 538.', 'In some embodiments, the fluid path 558 may cause fluid in the direction of flow to engage at least a portion of a cutting face 560 of the cutting element 538.', 'For example, the fluid path 558 may be directed to intersect with the cutting face 560.', 'In at least one embodiment, the fluid path 558 may be directed to intersect with or contact a cutting edge 562 (or cutting tip) of the cutting face 560.; FIG. 9, for instance, shows a diagram of a cutting tool model and a graph of the gradient composition design of the cutting tool model, according to some embodiments of the present disclosure.', 'As shown, the cutting tool is a drill bit 900 that includes a body 902 having a plurality of blades 904 extending outwardly from the body and forming the cutting end 906 of the drill bit 900.', 'A connection end 908 is opposite the cutting end 906, and a longitudinal axis 901 extends axially through the body 902.', 'The composition design of the drill bit 900 (or drill bit model when programmed or designed) includes an axial gradient 910 having a gradually changing amount of a first material in the composition along a first distance from the cutting end 906.', 'The first gradient composition may form at least the cutting end portion of the body 902 and, in some embodiments, may extend to a connection end portion of the body 902.; FIG.', '12 shows a cross sectional view of a downhole cutting tool 1200 having a bit body 1210 with a cutting end 1212, a connection end 1214, a longitudinal axis 1202 extending axially therethrough, and a plurality of blades 1220 extending outwardly from the bit body 1210.', 'The blades 1220 may have a blade profile at the cutting end 1212 that includes a cone region 1222 proximate the longitudinal axis 1202, a nose region 1224 extending from the cone region to a shoulder region 1226, and the shoulder region 1226 extending to a gage region 1228.', 'The cone region 1222 includes the radially innermost region of the blade profile, extending generally from the longitudinal axis 1202 to the nose region 1224.', 'The cone region may extend axially downward (in a direction away from the connection end 1214), and may be generally concave, planar, or convex.', 'Adjacent the cone region 1222 is the nose region 1224, which includes the region immediately around the axially lowermost point of the blade profile, referred to as a blade profile nose.', 'At the blade profile nose, the slope of a tangent line to the blade profile is zero.', 'Thus, as used herein, the term “blade profile nose” may refer to the point along a convex region of a blade profile of a cutting tool in rotated profile view at which the slope of a tangent to the blade profile is zero.', 'The nose region 1224 may sometimes be considered part of the shoulder (or the upturned curve) region 1226 of the blade profile.', 'As shown, the shoulder region 1226 may be generally convex.', 'Moving radially outwardly, adjacent the shoulder region 1226 is the gage region 1228, which extends parallel to the longitudinal axis 1202 at the outer radial periphery of the blade profile.', '; FIG.', '13 is a cross-sectional view of an example of a drill bit model having a multi-gradient compositional design taken from the sectional plane.', 'The drill bit 1300 includes a body 1302 having a plurality of blades 1304 extending outwardly from the body and forming the cutting end of the drill bit (where the sectional view is taken at the cutting end of the bit).', 'The drill bit composition includes gradients 1310 extending in multiple directions, including radial directions shown in the sectional view, and axial directions as shown and discussed herein.', 'In the embodiment shown, the gradient composition includes radial gradients 1310 extending from interior portions of the drill bit to exterior portions of the drill bit.', 'Particularly, the radial gradients 1310 formed along the sectional plane 1320 exposed in the sectional view of FIG.', '13 extend from an interior portion of each blade 1304 to exterior portions of the blades 1304, where the composition along an outer surface 1312 of the blade 1304 has greater erosion resistance than the composition at the interior portion 1314 of the blade 1304.', 'The particular embodiment in FIG.', '13 also shows that a gradient may extend radially from an interior portion of each blade 1304 to interior portions of the blades 1304, and/or in one or more circumferential directions from an interior of a blade 1304 toward exterior leading and trailing surfaces of the blade 1304.'] |
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US11125331 | Liner lock flange for a piston pump | Aug 9, 2018 | Jaakko Jalmari Halmari, David Scott Crew, Jr., Jeffrey Boardman Pruitt, Ban Tran | Schlumberger Technology Corporation | NPL References not found. | 3786729; January 1974; Rizzone; 6209445; April 3, 2001; Roberts, Jr.; 10041490; August 7, 2018; Jahnke; 10246955; April 2, 2019; Berthaud et al.; 10280910; May 7, 2019; Berthaud et al.; 20050089427; April 28, 2005; Riley et al.; 20060123616; June 15, 2006; Aday et al.; 20110236238; September 29, 2011; Cordes et al.; 20180010601; January 11, 2018; Berthaud et al. | 201827066; May 2011; CN | ['A piston pump includes a frame, a housing configured to be coupled to the frame via a fastener, an annular liner defining a chamber configured to receive a piston of the piston pump, and an annular liner lock flange circumferentially surrounding the annular liner.', 'The annular liner lock flange includes a radially-extending portion configured to be positioned within a respective counterbore of the frame and a respective counterbore of the housing while the housing is coupled to the frame via the fastener to block relative movement between the liner lock flange, the frame, and the housing.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'Natural resources, such as oil and gas, are used as fuel to power vehicles, heat homes, and generate electricity, in addition to various other uses.', 'Once a desired resource is discovered below the surface of the earth, drilling and production systems are often employed to access and extract the resource.', 'These systems may be located onshore or offshore depending on the location of the desired resource.', 'Further, such systems may include a wide variety of components, such as various casings, fluid conduits, valves, pumps, and the like, that facilitate extraction of the resource from a well during drilling or extraction operations.', 'For example, a mud pump system may be utilized to pump drilling fluid (e.g., mud) from surface tanks into a drill pipe.', 'However, some mud pump systems may be difficult to maintain and/or repair, thereby resulting in increased downtime during maintenance and/or repair operations.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n is a schematic diagram of a portion of a drilling and production system, in accordance with an embodiment of the present disclosure;\n \nFIG.', '2\n is a side view of a pump that may be used in the drilling and production system of \nFIG.', '1\n, in accordance with an embodiment of the present disclosure;\n \nFIG.', '3\n is a side view of a liner assembly that may be used in the pump of \nFIG.', '2\n, in accordance with an embodiment of the present disclosure;\n \nFIG.', '4\n is a side view of the liner assembly taken within line \n4\n-\n4\n of \nFIG.', '3\n, in accordance with an embodiment of the present disclosure; and\n \nFIG.', '5\n is a method of assembling a portion of the pump of \nFIG.', '2\n, in accordance with an embodiment of the present disclosure.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nOne or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'The present embodiments are generally directed to pump systems for use within a drilling and production system.', 'Certain embodiments include a pump system having a liner lock flange (e.g., annular flange) designed to facilitate alignment between a piston liner (e.g., annular liner) and a piston, and to also enable replacement of a wear plate (e.g., annular plate) without removal of the liner lock flange.', 'The disclosed embodiments may advantageously provide a compact pump system, may reduce wear on components of the pump system, and/or may facilitate maintenance and/or repair of the components of the pump system, for example.', 'It should be appreciated that the liner lock flange that is used as part of the pump system disclosed herein may be adapted for use with various types of equipment, such as any piston pump system, including but not limited to mud pump systems.', 'With the foregoing in mind, \nFIG.', '1\n is a schematic diagram of a portion of a drilling and production system \n10\n, in accordance with an embodiment of the present disclosure.', 'As shown, a wellbore \n12\n is formed in a subsurface formation, and a drill string \n14\n is suspended within the wellbore \n12\n.', 'The drill string may include a drill bit \n16\n that cuts through the subsurface formation to form or to drill the wellbore \n12\n.', 'The system \n10\n includes a mast \n18\n positioned on a drill floor \n20\n and over the wellbore \n12\n.', 'A hoisting system \n22\n includes a crown block \n24\n, a traveling block \n26\n, and a drawworks system \n28\n.', 'A cable \n30\n (e.g., wire) extends from the drawworks system \n28\n and couples the crown block \n24\n to the traveling block \n26\n.', 'In the illustrated embodiment, a top drive \n32\n is coupled to the traveling block \n26\n.', 'The top drive \n32\n rotates the drill string \n14\n as the hoisting system \n22\n raises and lowers the top drive \n32\n and the drill string \n14\n relative to the drill floor \n20\n to facilitate drilling of the wellbore \n12\n.', 'It should be appreciated that hoisting systems having various other components (e.g., swivels) and configurations may be utilized in the system \n10\n.', 'The system \n10\n also includes a pump system \n40\n having a pump \n42\n that pumps a drilling fluid (e.g., mud; water-based, oil-based, or synthetic-based fluid) from a tank \n44\n to an interior channel in the drill string \n14\n.', 'For example, the pump \n42\n may pump the drilling fluid from the tank \n44\n, through a fluid conduit \n46\n (e.g., pipe), through a port in the top drive \n32\n, and into the interior channel in the drill string \n14\n, as shown by arrow \n48\n.', 'The drilling fluid may exit the drill string \n14\n via ports in the drill bit \n16\n, and then circulate upwardly through an annulus between an outer surface (e.g., annular surface) of the drill string \n14\n and an inner surface (e.g., annular surface) that defines the wellbore \n12\n, as shown by arrows \n50\n.', 'The drilling fluid may then return to the tank \n44\n via a fluid conduit \n52\n (e.g., pipe).', 'The drilling fluid may lubricate the drill bit \n16\n, may carry formation cuttings toward the surface, and/or may maintain hydrostatic pressure within the wellbore \n12\n.', 'As discussed in more detail below, the pump \n42\n may include a liner assembly \n54\n (e.g., piston liner assembly) with various features that facilitate operation of the pump \n42\n, as well as maintenance of the pump \n42\n, for example.', 'While \nFIG.', '1\n illustrates a land-based drilling and production system \n10\n to facilitate discussion, it should be understood that the disclosed embodiments may be adapted for use within an offshore drilling and production system.', 'FIG.', '2\n is a cross-sectional side view of the pump \n42\n that may be used in the drilling and production system \n10\n of \nFIG.', '1\n.', 'To facilitate discussion, the pump system \n42\n and its components may be described with reference to an axial axis or direction \n56\n, a radial axis or direction \n58\n, a lateral axis or direction \n60\n, and a circumferential axis or direction \n62\n.', 'In the illustrated embodiment, the pump \n42\n is supported on a skid \n64\n (e.g., support structure) and includes a frame \n68\n (e.g., main frame) that is coupled to the skid \n64\n.', 'The pump \n42\n extends from a power end portion \n70\n to a fluid end portion \n72\n.', 'The power end portion \n70\n may include components of a drive system \n74\n (e.g., motor, gears, and/or crankshaft assembly that coverts rotation into reciprocating motion to drive one or more pistons \n76\n back and forth along the axial axis \n56\n).', 'The fluid end portion \n72\n may include the one or more pistons \n76\n, one or more modules \n78\n (e.g., housings) surrounding and/or supporting one or more valves \n80\n (e.g., one-way check valves), and one or more fluid inlets \n82\n (e.g., suction manifold) through which the drilling fluid is drawn (e.g., suctioned) into the one or more modules \n78\n to be pumped (e.g., discharged) toward the drill string \n14\n (\nFIG.', '1\n).', 'The frame \n68\n surrounds (e.g., houses or covers) the one or more pistons \n76\n and associated components (e.g., piston rod), and the frame \n68\n is coupled to the one or more modules \n78\n.', 'As shown in the illustrated embodiment, each piston \n76\n is associated with a suction module \n84\n and a discharge module \n86\n that are coupled to one another.', 'In operation, the reciprocating motion of the piston \n76\n draws the drilling fluid, for example mud, in through a corresponding fluid inlet \n82\n and a corresponding suction module \n84\n and then forces the mud out through a corresponding fluid outlet or discharge manifold extending from a corresponding discharge module \n86\n (e.g., positioned out of view behind the discharge module \n84\n along the lateral axis \n60\n in \nFIG.', '2\n).', 'In the illustrated embodiment, the fluid end portion \n72\n also includes one or more liner assemblies \n54\n, and each of the one or more liner assemblies \n54\n circumferentially surrounds a respective one of the one or more pistons \n76\n.', 'One liner assembly \n54\n is shown schematically in \nFIG.', '2\n to illustrate its position relative to other components of the pump \n42\n, and details of the liner assembly \n54\n are shown in \nFIGS.', '3 and 4\n.', 'In general, the liner assembly \n54\n may include a liner defining a chamber through which the piston \n76\n moves, as well as a liner lock flange and associated liner lock nut that together retain the liner in its position proximate to a respective one of the one or more modules \n78\n.', 'In the cross-section of \nFIG.', '2\n, only one piston \n76\n and its corresponding modules \n78\n and corresponding liner assembly \n54\n are shown.', 'However, it should be appreciated that the pump \n42\n may include multiple pistons \n76\n and corresponding modules \n78\n and liner assemblies \n54\n distributed along the lateral axis \n60\n (e.g., side-by-side along the lateral axis \n60\n).', 'Furthermore, while each piston \n76\n has two corresponding modules \n78\n (e.g., the suction module \n84\n and the discharge module \n86\n) in \nFIG.', '2\n, it should be appreciated that each piston \n76\n may have only one corresponding module \n78\n having a different valve structure to enable suction and discharge functionality.', 'FIG.', '3\n is a side view of the liner assembly \n54\n that may be used in the pump \n42\n (\nFIG.', '2\n), and \nFIG.', '4\n is a side view of the liner assembly \n54\n taken within line \n4\n-\n4\n of \nFIG.', '3\n, in accordance with an embodiment of the present disclosure.', 'In \nFIG.', '3\n, only a portion of the frame \n68\n is shown to facilitate discussion and to simplify the drawing.', 'Furthermore, the illustrated module \n78\n includes a different valve structure than the modules \n78\n shown in \nFIG.', '2\n, but the valves \n80\n operate in the same manner to suction and discharge the drilling fluid.', 'As shown in \nFIGS.', '3 and 4\n, the frame \n68\n is coupled to the module \n78\n via one or more fasteners \n100\n (e.g., threaded fasteners, such as bolts, studs, nuts).', 'The liner assembly \n54\n includes a liner \n102\n (e.g., annular liner) defining a chamber through which the piston \n76\n (\nFIG.', '2\n) moves.', 'The liner assembly \n54\n also includes a liner lock flange \n104\n (e.g., annular flange) and a liner lock nut \n106\n (e.g., annular nut) that together retain the liner \n102\n in its position proximate to the module \n78\n.', 'In the illustrated embodiment, the liner lock flange \n104\n and the liner lock nut \n106\n are coupled to one another via a threaded interface \n108\n, although other coupling interfaces (e.g., key-slot interface, j-slot, quarter-turn) may be utilized.', 'The liner assembly \n54\n may include a wear plate \n110\n (e.g., annular wear plate or sleeve), a wear plate seal \n112\n (e.g., annular seal), and/or a liner seal \n114\n (e.g., annular seal).', 'As shown, the wear plate \n110\n is positioned between the module \n78\n and the liner \n102\n along the axial axis \n56\n.', 'In some embodiments, this may be a high-wear region due at least in part to a difference between an inner diameter \n116\n of the liner \n102\n and an inner diameter \n118\n of a bore \n120\n of the module \n78\n (e.g., the inner diameter \n116\n is greater than the inner diameter \n118\n).', 'The wear plate seal \n112\n seals against and is positioned between the wear plate \n110\n and the module \n78\n along the axial axis \n56\n.', 'The liner seal \n114\n seals against and is positioned between the wear plate \n110\n and the liner \n102\n along the axial axis \n56\n.', 'When assembled, the liner lock flange \n104\n may circumferentially surround at least a portion of the wear plate \n110\n.', 'The liner assembly \n54\n is designed to facilitate alignment between the liner \n102\n and the piston \n76\n (\nFIG.', '1\n), and also to enable replacement of the wear plate \n110\n (as well as the liner seals \n114\n, \n116\n) without removal of the liner lock flange \n104\n.', 'As shown, the liner lock flange \n104\n extends from a first end \n122\n that couples to the liner lock nut \n106\n to a second end \n124\n that includes a radially-extending flange \n126\n (e.g., annular flange or portion).', 'A portion of the radially-extending flange \n126\n is positioned within a counterbore \n128\n (e.g., annular recess) formed in a module-facing surface \n130\n (e.g., housing-facing or axially-facing surface) of the frame \n68\n.', 'Another portion of the radially-extending flange \n126\n is positioned within a counterbore \n132\n (e.g., annular recess) formed in a frame-facing surface \n134\n (e.g., axially-facing surface) of the module \n78\n.', 'When the frame \n68\n is coupled to the module \n78\n via the fasteners \n100\n, the radially-extending flange \n126\n within the counterbores \n128\n, \n132\n is trapped between the frame \n68\n and the module \n78\n, thereby blocking movement of the liner lock flange \n104\n relative to the frame \n68\n and the module \n78\n.', 'It should be appreciated that the liner lock nut \n106\n may be rotated to drive the liner \n102\n toward the liner lock flange \n104\n, thereby tightening the fit or connection between the various components (e.g., between the liner \n102\n, the liner lock flange \n104\n, the module \n78\n).', 'To assemble the liner lock flange \n104\n within the pump \n42\n (\nFIG.', '1\n), the liner lock flange \n104\n may be inserted into an opening (e.g., bore) defined by the frame \n68\n from a module-facing side (e.g., housing-facing side) of the frame \n68\n, as shown by arrow \n140\n.', 'The liner lock flange \n104\n and the frame \n68\n may be moved toward one another along the axial axis \n56\n until a frame-engaging surface \n142\n (e.g., axially-facing surface) of the radially-extending flange \n126\n engages a flange-engaging surface \n144\n of the frame \n68\n.', 'The frame \n68\n may then be coupled to the module \n78\n via the threaded fasteners \n100\n, and the position of the radially-extending flange \n126\n in both counterbores \n128\n, \n132\n assists in alignment between the frame \n68\n and the module \n78\n.', 'The other components of the liner assembly \n54\n may then be assembled.', 'In particular, the components may be inserted through the liner lock flange \n104\n from a piston-facing side of the frame \n68\n (e.g., opposite from the module-facing side of the frame \n68\n), as shown by arrow \n148\n.', 'For example, the wear plate seal \n112\n may be inserted and positioned within the module \n78\n, then the wear plate \n110\n may be inserted and positioned against the module \n78\n, then the liner seal \n114\n may be inserted and positioned into a groove within the liner \n102\n, then the liner \n102\n may be inserted and positioned against the wear plate \n110\n.', 'Subsequently, the liner lock nut \n106\n may be coupled to (e.g., threaded onto) the liner lock flange \n104\n.', 'As shown, the liner \n102\n includes a radially-extending liner flange \n150\n (e.g., annular flange).', 'When the liner lock nut \n106\n is coupled to the liner lock flange \n104\n, the radially-extending liner flange \n150\n is positioned between the liner lock nut \n106\n and the liner lock flange \n104\n along the axial axis \n56\n.', 'In particular, an axially-facing surface \n152\n of the liner lock nut \n106\n and an axially-facing surface \n154\n at the first end \n122\n of the liner lock flange \n104\n each engage the radially-extending liner flange \n150\n and block movement of the liner \n102\n relative to the liner lock nut \n106\n and the liner lock flange \n104\n.', 'It should be appreciated that the liner \n102\n may not include the liner flange \n105\n, but instead the liner lock nut \n106\n may extend to and engage an end of the liner \n102\n to block movement of the liner \n102\n relative to the liner lock nut \n106\n and the liner lock flange \n104\n.', 'To replace the liner lock flange \n104\n, the fasteners \n100\n are loosened to separate the module \n78\n from the frame \n68\n, and then the liner lock flange \n104\n can be moved out of the frame \n68\n (e.g., by pulling the liner lock flange in a direction opposite arrow \n140\n).', 'Another liner lock flange \n104\n, and the other components of the liner assembly \n54\n, can then be assembled in the manner set forth above.', 'In operation, the piston \n76\n (\nFIG.', '2\n) moves through the liner \n102\n along the axial axis \n56\n to pump the drilling fluid through the module \n78\n.', 'The disclosed embodiments enable the liner \n102\n to remain in its position tightly against the wear plate \n110\n, and enables the wear plate \n110\n to remain in its position tightly against the module \n78\n during operation of the pump \n42\n (\nFIG.', '2\n) without any fasteners (e.g., threaded fasteners, such as bolts) coupling the liner lock flange \n104\n to the module \n78\n and without any fasteners (e.g., threaded fasteners, such as bolts) coupling the liner lock flange \n104\n to the frame \n68\n.', 'Thus, the liner lock flange \n104\n may be devoid of openings to receive fasteners.', 'The lack of such fasteners provides a small, light-weight pump \n42\n (\nFIG.', '2\n) with fewer parts compared to some existing drilling fluid pumps such as mud pumps or slurry pumps.', 'Furthermore, the disclosed embodiments enable replacement of the liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n without removing the liner lock flange \n104\n (e.g., without separating the liner lock flange \n104\n from the frame \n68\n and/or the module \n78\n).', 'The liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n are subject to wear and may need to be replaced relatively frequently (e.g., compared to the liner lock flange \n104\n), and this configuration enables efficient replacement of these high-wear components without removing the liner lock flange \n104\n or altering alignment between the frame \n68\n and the module \n78\n (e.g., since the liner lock flange \n104\n, the frame \n68\n, and the module \n78\n are not separated from one other during replacement of the liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n).', 'For example, the liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n can be removed by uncoupling the liner lock nut \n106\n from the liner lock flange \n104\n, and subsequently pulling the liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n through the liner lock flange \n104\n in a direction opposite the arrow \n148\n.', 'As shown, the liner lock flange \n104\n includes an inner diameter \n160\n that is greater than an outer diameter \n162\n of the wear plate \n110\n, and the inner diameter \n160\n also accommodates removal of the seals \n112\n, \n114\n and the liner \n102\n.', 'The disclosed embodiments enable a tight fit (e.g., press fit) between the liner lock flange \n104\n and the frame \n68\n and/or between the liner lock flange \n104\n and the module \n78\n because the liner lock flange \n104\n does not need to be separated from the frame \n68\n and/or the module \n78\n during regular maintenance operations to replace the liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n.', 'In contrast, some existing liner lock flanges \n108\n must be removed or separated from the frame \n68\n and/or the module \n78\n (e.g., by uncoupling threaded fasteners that hold the liner lock flange \n104\n to the frame \n68\n and/or to the module \n78\n) to replace the liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n, and as a result, the parts may generally have relatively loose fits to assist with loosening the fasteners and the like.', 'The tight fit in the present embodiments maintains alignment between the liner \n102\n and the piston \n76\n (\nFIG.', '2\n), thereby reducing wear on the liner \n102\n and the piston \n76\n (\nFIG.', '2\n) and extending component life.', 'FIG.', '5\n is a method \n200\n of assembling a portion of the pump \n42\n (\nFIG.', '2\n).', 'The method \n200\n includes various steps represented by blocks.', 'Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Additionally, steps may be added to or omitted from of the method \n200\n.', 'The discussion of the method \n200\n refers to certain components that are described and illustrated in \nFIGS.', '1-4\n.', 'In step \n202\n, the radially-expanded portion \n126\n of the liner lock flange \n104\n is positioned within the counterbore \n128\n of the frame \n68\n.', 'As discussed above, the liner lock flange \n104\n may be inserted into an opening defined by the frame \n68\n from the module-facing side of the frame \n68\n, as shown by arrow \n140\n.', 'The liner lock flange \n104\n and the frame \n68\n may be moved toward one another along the axial axis \n56\n until the frame-engaging surface \n142\n of the radially-extending flange \n126\n engages the flange-engaging surface \n144\n of the frame \n68\n.', 'In step \n204\n, the radially-extending portion \n126\n of the liner lock flange \n104\n is aligned with and positioned within the counterbore \n132\n of the module \n78\n.', 'In step \n206\n, the frame \n68\n may then be coupled to the module \n78\n (e.g., via the threaded fasteners \n100\n).', 'The position of the radially-extending flange \n126\n in both counterbores \n128\n, \n132\n assists in alignment between the frame \n68\n and the module \n78\n.', 'In step \n208\n, once the liner lock flange \n104\n is secured to the frame \n68\n and the module \n78\n, the wear plate \n110\n may be inserted through the liner lock flange \n104\n to a position against the module \n78\n.', 'In step \n210\n, the liner \n102\n may be inserted through the liner lock flange \n104\n to a position against the wear plate \n110\n.', 'In step \n212\n, the liner lock nut \n106\n may then be coupled to the liner lock flange \n104\n to secure the liner \n102\n and block movement of the liner \n102\n relative to the liner lock flange \n104\n and relative to the liner lock nut \n106\n.', 'As noted above, the liner \n102\n, the wear plate \n110\n, the wear seal \n112\n, and/or the liner seal \n114\n may be removed through the liner lock flange \n104\n without separating the liner lock flange \n104\n from the frame \n68\n or the module \n78\n.', 'The pump \n42\n disclosed herein is merely exemplary, and it should be appreciated that various combinations and arrangements of the features shown and described with respect to \nFIGS.', '1-4\n are envisioned.', 'Indeed, any of the features and components of \nFIGS.', '1-5\n may be utilized together and/or combined in any suitable manner.', 'Furthermore, the liner assembly \n54\n and some or all of the components therein may be used in any of a variety of piston pump systems.', 'While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.', 'Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.', 'The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical.', 'Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function] . . . ”', 'or “step for [perform]ing [a function] . . .', '”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f).', 'However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).'] | ['1.', 'A piston pump, comprising:\na frame defining a first counterbore;\na housing configured to be coupled to the frame via a fastener, the housing defining a second counterbore;\nan annular liner defining a chamber configured to receive a piston of the piston pump; and\nan annular liner lock flange circumferentially surrounding the annular liner and comprising a radially-extending portion configured to be positioned within the first counter bore and the second counterbore, wherein the first counterbore and the second counterbore are aligned so that the radially-extending portion is trapped between and the housing.', '2.', 'The piston pump of claim 1, comprising an annular liner lock nut configured to couple to the annular liner lock flange.', '3.', 'The piston pump of claim 2, wherein the annular liner lock flange and the annular liner lock nut are configured to engage a radially-extending liner portion of the annular liner to block movement of the annular liner relative to the annular liner lock flange and relative to the annular liner lock nut.', '4.', 'The piston pump of claim 1, comprising an annular wear plate configured to be positioned between the annular liner and the housing along an axial axis of the piston pump, wherein the annular wear plate is movable through the annular liner lock flange.', '5.', 'The piston pump of claim 4, wherein the annular liner lock flange comprises a first inner diameter and the annular wear plate comprises a second outer diameter that is less than the first inner diameter.', '6.', 'The piston pump of claim 4, wherein the annular liner lock flange is configured to circumferentially surround at least a portion of the annular wear plate when the piston pump is assembled.', '7.', 'The piston pump of claim 1, wherein the annular liner lock flange is devoid of openings to receive fasteners.', '8.', 'The piston pump of claim 1, wherein the housing surrounds one or more valves that facilitate pumping fluid through the piston pump, and the frame surrounds the piston and a piston rod coupled to the piston.', '9.', 'A method of assembling a piston pump, comprising:\npositioning a radially-expanded portion of an annular liner lock flange within a counterbore of a frame;\npositioning the radially-expanded portion of the annular liner lock flange within a counterbore of a housing; and\nsubsequently coupling the frame to the housing using a fastener, thereby trapping the radially-expanded portion of the annular liner lock flange between the housing and the frame and blocking movement of the annular liner lock flange relative to the housing and the frame.', '10.', 'The method of claim 9, wherein positioning the radially-expanded portion of the annular liner lock flange within the counterbore of the frame comprises inserting the annular liner lock flange into an opening defined by the frame from a housing-facing side of the frame.', '11.', 'The method of claim 9, inserting an annular wear plate through the annular liner lock flange to position the annular wear plate against the housing after coupling the frame and the housing to one another.\n\n\n\n\n\n\n12.', 'The method of claim 9, inserting an annular liner through the annular liner lock flange after coupling the frame and the housing to one another, and subsequently coupling an annular liner lock nut to the annular liner lock flange, wherein the annular liner lock flange and the annular liner lock nut engage the annular liner to block movement of the annular liner relative to the annular liner lock nut and relative to the annular liner lock flange.'] | ['FIG.', '1 is a schematic diagram of a portion of a drilling and production system, in accordance with an embodiment of the present disclosure;; FIG.', '2 is a side view of a pump that may be used in the drilling and production system of FIG.', '1, in accordance with an embodiment of the present disclosure;; FIG.', '3 is a side view of a liner assembly that may be used in the pump of FIG.', '2, in accordance with an embodiment of the present disclosure;; FIG. 4 is a side view of the liner assembly taken within line 4-4 of FIG.', '3, in accordance with an embodiment of the present disclosure; and; FIG. 5 is a method of assembling a portion of the pump of FIG.', '2, in accordance with an embodiment of the present disclosure.; FIG. 2', 'is a cross-sectional side view of the pump 42 that may be used in the drilling and production system 10 of FIG.', '1.', 'To facilitate discussion, the pump system 42 and its components may be described with reference to an axial axis or direction 56, a radial axis or direction 58, a lateral axis or direction 60, and a circumferential axis or direction 62.; FIG.', '3 is a side view of the liner assembly 54 that may be used in the pump 42 (FIG. 2), and FIG.', '4 is a side view of the liner assembly 54 taken within line 4-4 of FIG.', '3, in accordance with an embodiment of the present disclosure.', 'In FIG.', '3, only a portion of the frame 68 is shown to facilitate discussion and to simplify the drawing.', 'Furthermore, the illustrated module 78 includes a different valve structure than the modules 78 shown in FIG.', '2, but the valves 80 operate in the same manner to suction and discharge the drilling fluid.;', 'FIG. 5 is a method 200 of assembling a portion of the pump 42 (FIG. 2).', 'The method 200 includes various steps represented by blocks.', 'Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Additionally, steps may be added to or omitted from of the method 200.', 'The discussion of the method 200 refers to certain components that are described and illustrated in FIGS.', '1-4.'] |
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US11125217 | Pressure-reducing choke assembly | Nov 5, 2015 | Gustavo Plaza, Kim A. Hodgson, Gocha Chochua, Walter Taylor, Donald E. Hensley, John Starr, Jijo Oommen Joseph | Schlumberger Technology Corporation | McLaury et al., “Effect of Entrance Shape on Erosion in the Throat of Chokes”, ASME, vol. 122, Dec. 2000, pp. 198-204.; McLaury et al., “Predicting Sand Erosion in Chokes for High Pressure Wells”, SPE 49308, 1998 SPE Annual Technical Conference and Exhibition, Sep. 27-30, 1998, pp. 769-780.; McLaury et al., “How Erosion-Corrosion Patters in a Choke Change as Material Losses in the Choke Progress”, Corrosion 96, The NAC International Annual Conference and Exposition, Paper No. 16, 1996, 16 pages.; Ali et al., “Sand Erosion Control by Using Chokes in Series in Deep, High Pressure Oil Producing Wells in North of Monagas, Venezuela”, SPE 38843, SPE Annual Technical Conference and Exhibition, Oct. 5-8, 1997, pp. 987-998.; Peri et al., “Understanding Erosion Prediction: Determining Erosion in a Choke”, IPTC 11770, International Petroleum Technology Conference, Dec. 4-6, 2007, 9 pages.; International Search Report and Written Opinion issued in International Patent Application No. PCT/US2016/060412 dated Mar. 2, 2017; 14 pages. | 4354552; October 19, 1982; Zingg; 4644974; February 24, 1987; Zingg; 7086417; August 8, 2006; De Almeida; 20060219967; October 5, 2006; Wang; 20120186662; July 26, 2012; De Almeida; 20140231554; August 21, 2014; Ungchusri; 20150159795; June 11, 2015; Ungchusri et al. | Foreign Citations not found. | ['A choke for fluid connection between a manifold and a pump.', 'The choke includes a fluid passage having an inlet, a contraction portion, a throat, an expansion portion, and an outlet.', 'The inlet has a first diameter and the outlet has a second diameter.', 'The throat is substantially cylindrical, having a third diameter that is substantially less than the first and second diameters.', 'The contraction portion connects the inlet and the throat and gradually decreases from the first diameter to the third diameter along a longitudinal axis of the fluid passage.', 'The expansion portion connects the throat and the outlet and includes a substantially cylindrical chamber having the second diameter.'] | ['Description\n\n\n\n\n\n\nBACKGROUND OF THE DISCLOSURE', 'In oilfield operations, reciprocating pumps are utilized at wellsites for large scale, high-pressure operations.', 'Such operations may include drilling, cementing, acidizing, water jet cutting, and hydraulic fracturing of subterranean formations.', 'In some applications, several pumps may be connected in parallel to a single manifold, flow line, or well.', 'Some reciprocating pumps include reciprocating members driven by a crankshaft toward and away from a fluid chamber to alternatingly draw in, pressurize, and expel fluid from the fluid chamber.', 'Hydraulic fracturing of a subterranean formation, for example, may utilize fluid at a pressure exceeding 15,000 pounds per square inch (PSI).', 'A reciprocating pump may discharge pressurized fluid in an oscillating manner that forms fluid pressure fluctuations at the pump outlet.', 'The oscillating pressure fluctuations may be amplified in a pumping system comprising two or more reciprocating pumps, such as due to resonance phenomena caused by interaction between two or more fluid flows, thus producing high-pressure spikes.', 'At a wellsite, the oscillation and the amplified high-pressure spikes may be transmitted to the piping and/or other portions of the wellsite system, causing vibrations and strain in such equipment.', 'Equipment failures have been linked to material fatigue caused by systematic occurrence of such oscillations, spikes, vibration, and strain.', 'Such failures may be reduced by installing pressure-reducing chokes between pump outlets and the downstream equipment, but such chokes exhibit short service lives due to erosion caused by the oscillations, spikes, vibration, and strain induced by the pressurized fluid discharged by the pumps.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus that includes a manifold, multiple pumps, and choke assemblies each fluidly connected between the manifold and a corresponding one of the pumps.', 'Each choke assembly includes a body having a fluid passage conducting fluid from the corresponding pump to the manifold.', 'The fluid passage includes an inlet having a first diameter, an outlet having a second diameter, a substantially cylindrical throat having a third diameter that is substantially less than the first and second diameters, a contraction portion connecting the inlet and the throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the fluid passage, and an expansion portion connecting the throat and the outlet.', 'The expansion portion is or substantially includes a substantially cylindrical chamber having the second diameter.', 'The present disclosure also introduces a method that includes connecting a choke assembly in fluid communication between a pump and a manifold such that a fluid passage of the choke assembly conducts fluid from the pump to the manifold.', 'The fluid passage includes an inlet having a first diameter, an outlet having a second diameter, a substantially cylindrical throat having a third diameter that is substantially less than the first and second diameters, a contraction portion connecting the inlet and the throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the fluid passage, and an expansion portion connecting the throat and the outlet.', 'The expansion portion is or substantially includes a substantially cylindrical chamber having the second diameter.', 'The method also includes operating the pump to move the fluid through the choke assembly toward the manifold.', 'The present disclosure also introduces an apparatus that includes a choke assembly for fluid connection between a manifold and a pump.', 'A fluid passage of the choke assembly includes an inlet having a first diameter, an outlet having a second diameter, a substantially cylindrical throat having a third diameter that is substantially less than the first and second diameters, a contraction portion connecting the inlet and the throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the fluid passage, and an expansion portion connecting the throat and the outlet.', 'The expansion portion is or substantially includes a substantially cylindrical chamber having the second diameter.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a side sectional view of an example implementation of a portion of the apparatus shown in \nFIG.', '1\n according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a graph related to one or more aspects of the present disclosure.', 'FIG.', '4\n is a graph related to one or more aspects of the present disclosure.', 'FIG.', '5\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.\n \nFIG.', '1\n is a schematic view of at least a portion of an example wellsite system \n100\n according to one or more aspects of the present disclosure, representing an example environment in which one or more aspects described below may be implemented.', 'The figure depicts a wellsite \n102\n adjacent to a wellbore \n104\n and a partial sectional view of the subterranean formation \n106\n penetrated by the wellbore \n104\n below the wellsite \n102\n.', 'The wellsite system \n100\n may comprise a first mixer \n108\n fluidly connected with one or more tanks \n110\n and a first container \n112\n.', 'The first container \n112\n may contain a first material and the tanks \n110\n may contain a liquid.', 'The first material may be or comprise a hydratable material or gelling agent, such as guar, polymers, synthetic polymers, galactomannan, polysaccharides, cellulose, and/or clay, among other examples, and the liquid may be or comprise an aqueous fluid, which may comprise water or an aqueous solution comprising water, among other examples.', 'The first mixer \n108\n may be operable to receive the first material and the liquid via two or more fluid conduits \n114\n, \n116\n, and mix or otherwise combine the first material and the liquid to form a base fluid.', 'The base fluid may be or comprise that which is known in the art as a gel.', 'The first mixer \n108\n may then discharge the base fluid via one or more fluid conduits \n118\n.', 'The first mixer \n108\n and the first container \n112\n may each be disposed on corresponding trucks, trailers, and/or other mobile carriers \n120\n, \n122\n, respectively, such as may permit their transportation to the wellsite \n102\n.', 'However, the first mixer \n108\n and/or first container \n112\n may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite \n102\n.', 'The wellsite system \n100\n may further comprise a second mixer \n124\n fluidly connected with the first mixer \n108\n and a second container \n126\n.', 'The second container \n126\n may contain a second material that may be substantially different than the first material.', 'For example, the second material may be or comprise a proppant material, such as sand, sand-like particles, silica, quartz, and/or propping agents, among other examples.', 'The second mixer \n124\n may be operable to receive the base fluid from the first mixer \n108\n via one or more fluid conduits \n118\n, and the second material from the second container \n126\n via one or more fluid conduits \n128\n, and mix or otherwise combine the base fluid and the second material to form a mixture.', 'The mixture may be or comprise that which is known in the art as a fracturing fluid.', 'The second mixer \n124\n may then discharge the mixture via one or more fluid conduits \n130\n.', 'The second mixer \n124\n and the second container \n126\n may each be disposed on corresponding trucks, trailers, and/or other mobile carriers \n132\n, \n134\n, respectively, such as may permit their transportation to the wellsite \n102\n.', 'However, the second mixer \n124\n and/or second container \n126\n may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite \n102\n.', 'The mixture may be communicated from the second mixer \n124\n to a common manifold \n136\n via the one or more fluid conduits \n130\n.', 'The common manifold \n136\n may comprise a plurality of valves and diverters, as well as a suction line \n138\n and a discharge line \n140\n, such as may be operable to direct flow of the mixture in a selected or predetermined manner.', 'The common manifold \n136\n, which may be known in the art as a missile or a missile trailer, may distribute the mixture to a pump fleet, which may comprise a plurality of pump assemblies \n150\n each comprising a pump \n152\n, a prime mover \n154\n, and perhaps a heat exchanger \n156\n.', 'Each pump assembly \n150\n may receive the mixture from the suction line \n138\n of the common manifold \n136\n, via one or more fluid conduits \n142\n, and discharge the mixture under pressure to the discharge line \n140\n of the common manifold \n136\n, via one or more fluid conduits \n144\n.', 'Each pump assembly \n150\n may discharge the mixture at a pressure ranging between about 4,000 PSI and about 15,000 PSI, or more.', 'The mixture may then be discharged from the common manifold \n136\n into the wellbore \n104\n via one or more fluid conduits \n146\n, perhaps through various valves, conduits, and/or other hydraulic circuitry fluidly connected between the common manifold \n136\n and the wellbore \n104\n.', 'Each pump \n152\n of the plurality of pump assemblies \n150\n may be fluidly connected with the other pumps \n152\n via the plurality of fluid conduits \n144\n and the discharge line \n140\n of the common manifold \n136\n.', 'The common manifold \n136\n may be mounted on a corresponding truck, trailer, and/or another mobile carrier, such as may permit its transportation to the wellsite \n102\n.', 'However, the common manifold \n136\n may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite \n102\n.', 'The common manifold \n136\n or a portion of the common manifold \n136\n may also be or comprise treating iron or other process piping configured as a ground manifold.', 'Furthermore, the pump assemblies \n150\n may each be mounted on corresponding trucks, trailers, and/or other mobile carriers \n158\n, such as may permit their transportation to the wellsite \n102\n.', 'However, the pump assemblies \n150\n may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite \n102\n.', 'The pump assemblies \n150\n shown in \nFIG.', '1\n may comprise pumps \n152\n having a substantially same or similar structure and/or function, although other implementations within the scope of the present disclosure may include different types and/or sizes of pumps \n152\n.', 'Although the pump fleet of the wellsite system \n100\n is shown comprising six pump assemblies \n150\n, each disposed on a corresponding mobile carrier \n158\n, pump fleets comprising other quantities of pump assemblies \n150\n are also within the scope of the present disclosure.', 'The wellsite system \n100\n may also comprise a control center \n160\n, such as may be operable to monitor and control at least a portion of the wellsite system \n100\n during pumping operations.', 'For example, the control center \n160\n may be operable to monitor and control operational parameters of each pump assembly \n150\n, such as operating frequency or speed, phase or rotational position, temperature, and pressure.', 'The control center \n160\n may be disposed on a corresponding truck, trailer, and/or other mobile carrier \n162\n, such as may permit its transportation to the wellsite \n102\n.', 'However, the control center \n160\n may be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite \n102\n.\n \nFIG.', '1\n shows the wellsite system \n100\n operable to produce and/or mix fluids and/or mixtures (hereinafter collectively referred to as a “fluid”) that may be pressurized and individually or collectively injected into the wellbore \n104\n during hydraulic fracturing of the subterranean formation \n106\n.', 'However, it is to be understood that the wellsite system \n100\n may be operable to mix and/or produce other mixtures and/or fluids that may be pressurized and individually or collectively injected into the wellbore \n104\n during other oilfield operations, such as drilling, cementing, acidizing, chemical injecting, and/or water jet cutting operations, among other examples.', 'During operations of the wellsite system \n100\n, the pumps \n152\n may discharge the pressurized fluids in an oscillating manner.', 'Accordingly, some portions of the wellsite system \n100\n may experience amplified high-pressure pulsations or spikes due to a resonance phenomenon caused by interaction of two or more oscillating fluid streams discharged from two or more pumps \n152\n.', 'Such amplified high-pressure spikes may be transmitted through or along the fluid conduits \n144\n, \n146\n, the common manifold \n136\n, and/or other portions of the wellsite system \n100\n fluidly connected downstream from the pumps \n152\n.', 'The oscillating nature of the fluid discharged by the pumps \n152\n and the amplified high pressure spikes caused by the fluid resonance may produce vibrations in the fluid conduits \n144\n, \n146\n, the common manifold \n136\n, and/or other equipment located downstream from the pumps \n152\n.', 'As equipment failures have been linked to material fatigue caused by systematic occurrence of these pressure fluctuations and vibrations, functional or service life of certain wellsite equipment may be increased by reducing the magnitude of these pressure fluctuations.', 'Accordingly, the wellsite system \n100\n may further comprise a plurality of choke assemblies \n200\n operable to produce a pressure drop in the fluid being discharged by the pumps \n152\n.', 'Each choke assembly \n200\n may be connected along a corresponding fluid conduit \n144\n between a pump outlet and a corresponding fluid inlet \n148\n of the common manifold \n136\n.', 'The pressure drop caused by each choke assembly \n200\n may be monitored by the control center \n160\n via one or more pressure sensors located along each fluid conduit \n144\n.', 'For example, a pressure sensor may be located between each pump \n152\n and choke assembly \n200\n, and another pressure sensor may be located between the common manifold \n136\n and each choke assembly \n200\n.', 'FIG.', '2\n is a side sectional view of an example implementation of one of the choke assemblies \n200\n shown in \nFIG.', '1\n according to one or more aspects of the present disclosure.', 'The choke assembly \n200\n comprises a body \n202\n.', 'A fluid passage \n204\n extends through the body along a longitudinal axis \n206\n of the body \n202\n.', 'The fluid passage \n204\n comprises an inlet \n203\n and an outlet \n207\n.', 'A diameter \n205\n of the inlet \n203\n may be substantially equal (e.g., within about 5%) to a diameter \n209\n of the outlet \n207\n.', 'The fluid passage \n204\n also comprises a contraction portion \n210\n, a throat \n220\n, and an expansion portion \n230\n collectively extending between the inlet \n203\n and the outlet \n207\n.', 'The throat \n220\n is substantially cylindrical, having a diameter \n224\n that is substantially less than the inlet and outlet diameters \n205\n, \n209\n.', 'The contraction portion \n210\n is defined by an inwardly tapered or otherwise converging surface \n212\n extending between the inlet \n203\n and the throat \n220\n, such that the contraction portion \n210\n gradually and/or substantially continuously decreases in diameter from the inlet diameter \n205\n to the throat diameter \n224\n along the axis \n206\n.', 'The cross-sectional provide of the converging surface \n212\n may be substantially rounded or otherwise non-linear.', 'The expansion portion \n230\n is a substantially cylindrical chamber extending between the throat \n220\n and the outlet \n207\n and having the same diameter as the outlet diameter \n209\n.', 'An end of the substantially cylindrical expansion portion \n230\n is defined by an annular surface \n240\n extending radially from the throat \n220\n such that the axis \n206\n of the fluid passage is substantially coincident with a normal of the annular surface \n240\n.', 'The interface between the annular surface \n240\n and the substantially cylindrical inner surface of the expansion portion \n230\n may be tapered or rounded, such as may prevent or reduce initiation of cracking at the interface.', 'The choke assembly \n200\n may also comprise a housing \n250\n in which the body \n202\n may be threadedly and/or otherwise removably disposed.', 'The housing \n250\n and the body \n202\n may comprise various mating features, such as for indicating full insertion of the body \n202\n into the housing \n250\n and/or for reacting axially directed forces generated by fluid flowing through the passage \n204\n.', 'For example, the housing \n250\n may comprise an internal mating feature \n254\n that contacts an external mating feature \n244\n of the body \n202\n.', 'The external mating feature \n244\n may be a shoulder connecting proximate ends of first and second substantially cylindrical external surfaces \n242\n of the body \n202\n, and the internal mating feature \n254\n may be a shoulder connecting proximate ends of corresponding first and second substantially cylindrical internal surfaces \n252\n of the housing \n250\n.', 'As depicted in the example implementation shown in \nFIG.', '2\n, the mating features \n244\n, \n254\n may each be substantially planar, such that surface normals thereof extend substantially parallel to the axis \n206\n (although in opposite directions).', 'However, the mating features \n244\n, \n254\n may also be tapered relative to the axis \n206\n and/or otherwise shaped.', 'The external surfaces \n242\n of the body \n202\n and/or the internal surfaces \n252\n of the housing \n250\n may also not be substantially cylindrical, such as in implementations in which the external profile of the body \n202\n and the internal profile of the housing \n250\n are otherwise correspondingly shaped in a manner permitting the body \n202\n to be removably disposed within the housing \n250\n.', 'The choke assembly \n200\n may be coupled between opposing portions \n145\n, \n149\n of the fluid conduit \n144\n via various means.', 'For example, as depicted in the example implementation shown in \nFIG.', '2\n, an upstream coupling \n255\n between the upstream portion \n145\n of the fluid conduit \n144\n and the inlet end of the choke assembly \n200\n may be between a mechanical, fluid-conducting connector and/or other interface \n143\n of the upstream portion \n145\n and a correspondingly similar interface \n256\n of the housing \n250\n.', 'However, the body \n202\n and/or another component of the choke assembly \n200\n may also or instead at least partially form or comprise the interface \n256\n and/or other means for connecting with the upstream portion \n145\n of the fluid conduit \n144\n.', 'As also depicted in the example implementation shown in \nFIG.', '2\n, a downstream coupling \n259\n between the downstream portion \n149\n of the fluid conduit \n144\n and the outlet end of the choke assembly \n200\n may be between a mechanical, fluid-conducting connector and/or other interface \n147\n of the downstream portion \n149\n and a correspondingly similar interface \n258\n of the housing \n250\n.', 'However, the body \n202\n and/or another component of the choke assembly \n200\n may also or instead at least partially form or comprise the interface \n258\n and/or other means for connecting with the downstream portion \n149\n of the fluid conduit \n144\n.', 'The interfaces \n143\n, \n147\n, \n256\n, \n258\n may comprise threaded portions, clamps, and/or other means for making up the mechanical, fluid-conducting couplings \n255\n, \n259\n.', 'A fluid seal may be achieved between the body \n202\n, the housing \n250\n, and/or the portions \n145\n, \n149\n of the fluid conduit \n144\n, such as may prevent fluid from leaking between the body \n202\n, the housing \n250\n, and/or the fluid conduit \n144\n.', 'For example, the choke assembly \n200\n may comprise one or more optional fluid seals \n260\n disposed in corresponding grooves \n261\n extending into one or more of the outer surfaces \n242\n of the body \n202\n, such that each fluid seal \n260\n prevents the passage of fluid between the body \n202\n and the housing \n250\n or the portions \n145\n, \n149\n of the fluid conduit \n144\n.', 'The fluid seals \n260\n may include seal rings, cup seals, O-rings, and/or other sealing means.', 'In an embodiment, the fluid seal between the body \n202\n, the housing \n250\n, and/or the portions \n145\n, \n149\n of the fluid conduit \n144\n may comprises a metal-to-metal seal, and/or the various components \n202\n, \n250\n, and/or \n144\n may be connected by a threaded or welded connection.', 'Although the choke assembly \n200\n shown in \nFIG.', '2\n comprises multiple components (i.e., the body \n202\n and the housing \n250\n), it is to be understood that the choke assembly \n200\n may also be implemented as a single, discrete member, such as in implementations in which the body \n202\n and the housing \n250\n are integrally formed, such that the external surfaces \n242\n of the body \n202\n and the internal surfaces \n252\n of the housing \n250\n do not exist, or in implementations in which the housing \n250\n does not exist.', 'However, such implementations may otherwise comprise substantially the same structure and/or operation described herein.', 'The geometry of the fluid passage \n204\n may cause an energy loss in the fluid flowing through the fluid passage \n204\n by introducing a pressure drop in the fluid and, thus, reducing vibration and the resulting fatigue failures in the downstream equipment, such as the fluid conduits \n144\n, \n146\n and the common manifold \n136\n.', 'Comparative studies were conducted between chokes having a geometry similar to the choke assembly \n200\n shown in \nFIG.', '2\n and described above (hereinafter referred to as a “sudden expansion choke”) and chokes having a gradually expanding expasion portion as currently utilized in the industry (hereinafter referred to as a “gradual expansion choke”).', 'A gradual expansion choke differs from the choke assembly \n200\n shown in \nFIG.', '2\n in that, instead of the substantially cylindrical expansion portion \n230\n extending between the throat \n220\n and the outlet \n207\n, the throat \n220\n and the outlet \n207\n are connected by a frustoconical or otherwise gradually expanding portion \n274\n defined by a gradually expanding surface \n270\n, as depicted in \nFIG.', '2\n in phantom lines to more clearly show the geometric differences between the sudden expansion choke and the gradual expansion choke.', 'The gradually extending surface \n270\n extends from the throat \n220\n at an angle \n272\n with respect to the axis \n206\n.', 'The comparative studies demonstrated that a sudden expansion choke according to one or more aspects introduced in the present disclosure exhibited improved performance relative to gradual expansion chokes.', 'A first comparative study included simulating, measuring, and comparing fluid flow rates through several chokes, pressure drops across the chokes, and erosion experienced by the chokes.', 'Such study simulated high-pressure water at room temperature pumped through a gradual expansion choke and four sudden expansion chokes, each having a different throat diameter.', 'The gradual expansion choke had a throat diameter of about 2.5 centimeters (cm), and the four sudden expansion chokes had throat diameters of about 2.8 cm, about 2.5 cm, about 2.4 cm, and about 2.2 cm.', 'The throats of the sudden expansion chokes had an axial length (such as the axial length \n226\n shown in \nFIG.', '2\n) ranging between about 5 cm and about 10 cm.', 'The water flow ranged between about 5 barrels per minute (BPM) and about 15 BPM.', 'Three pressure transducers were simulated to measure water pressure at three different locations with respect to each choke.', 'A first pressure transducer measured pressure at an inlet of each choke, a second pressure transducer measured pressure at an outlet of each choke, and a third pressure transducer measured pressure further downstream (e.g., about 45 cm) from each choke.', 'FIGS.', '3 and 4\n are graphs showing the results of the first comparative study.', 'The following description refers to \nFIGS.', '2-4\n, collectively.', 'The graph in \nFIG.', '3\n depicts a plurality of curves from the simulation showing the relationship between the measured pressure drop across each choke, in PSI, and the flow rate of water through each choke, in BPM.', 'Curves \n301\n, \n302\n, \n303\n, \n304\n depict the relationship between the pressure drop and the flow rate for the sudden expansion chokes comprising the throat diameters of about 2.2 cm, about 2.4 cm, about 2.5 cm, and about 2.8 cm, respectively.', 'Curve \n305\n depicts the relationship between the pressure drop and the flow rate for the gradual expansion choke comprising the throat diameter of about 2.5 cm.', 'The curves \n301\n, \n302\n, \n303\n show that the pressure drops caused by the sudden expansion chokes having the throat diameters of about 2.2 cm, about 2.4 cm, and about 2.5 cm, respectively, were greater than the pressure drop caused by the gradual expansion choke having the throat diameter of about 2.5 cm, shown by the curve \n305\n.', 'Furthermore, the curve \n304\n shows that the pressure drop caused by the sudden expansion choke having the throat diameter of about 2.8 cm was similar or slightly smaller than the pressure drop caused by the gradual expansion choke having the throat diameter of about 2.5 cm, shown by the curve \n305\n.', 'Such results indicate that the sudden expansion choke geometry causes a greater energy loss than the gradual expansion choke geometry, thereby more effectively decreasing downstream pressure fluctuations caused by the pumps \n152\n.', 'This conclusion is especially evident when comparing curves \n303\n, \n305\n, showing the pressure drops caused by the sudden expansion and gradual expansion chokes having the same throat diameter, wherein the sudden expansion choke having the throat diameter of about 2.5 cm caused a substantially greater pressure drop (e.g., by about 55 PSI at 10 BPM) than the gradual expansion choke having the same throat diameter.', 'The conclusion is further supported by comparing curves \n304\n, \n305\n, which show that the sudden expansion choke having the throat diameter of about 2.2 cm caused a similar pressure drop (e.g., about 100 PSI at 10 BPM) as the gradual expansion choke.', 'Accordingly, the comparative study results show that when utilizing chokes having the same throat diameters under the same flow conditions, the sudden expansion choke geometry causes a greater energy loss and, thus, a greater pressure drop than the gradual expansion choke.', 'Examining the curves \n301\n, \n302\n, \n303\n, \n304\n at an example water flow rate of about 10 BPM, the sudden expansion choke having the throat diameter of about 2.2 cm produced a pressure drop of about 255 PSI, the sudden expansion choke having the throat diameter of about 2.4 cm produced a pressure drop of about 215 PSI, the sudden expansion choke having the throat diameter of about 2.5 cm produced a pressure drop of about 160 PSI, and the sudden expansion choke having the throat diameter of about 2.8 cm produced a pressure drop of about 106 PSI.', 'Accordingly, the maximum flow rate for a sudden contraction choke having the throat diameter of about 2.8 cm to achieve about a 100 PSI pressure drop is about 10 BPM.', 'To test for erosion susceptibility, a mixture of corrosive particles (e.g., sand) and high-pressure water was simulated to flow through the chokes.', 'The graph in \nFIG.', '4\n depicts a plurality of curves showing the relationship between a rate of erosion experienced by each choke, in millimeters per hour (mm/hr), against the flow rate of the mixture through each choke, in BPM.', 'Curves \n311\n, \n312\n, \n313\n, \n314\n depict the relationship between the erosion rate and the flow rate associated with the sudden expansion chokes comprising the throat diameters of about 2.2 cm, 2.4 cm, 2.5 cm, and 2.8 cm, respectively.', 'Curve \n315\n depicts the relationship between the erosion rate and the flow rate associated with the gradual expansion choke comprising the throat diameter of about 2.5 cm.', 'The erosion experienced by the sudden expansion chokes was measured at an erosion region \n246\n (\nFIG.', '2\n) located at the transition between the throat \n220\n and the expansion portion \n230\n, including the annular surface \n240\n and an upstream portion of the expansion portion \n230\n.', 'The erosion measurements included measuring the amount (i.e., depth) of material that was lost from the erosion region \n246\n.', 'The erosion region \n246\n is a high wear concentration region caused by fluid turbulence produced by the high velocity fluid jet or stream that exits the throat \n220\n while carrying particles (e.g., proppant material), such that collisions between the particles and surfaces within the erosion region \n246\n cause erosion of the body \n202\n within the region \n246\n.', 'The erosion experienced by the gradual expansion choke was measured along the gradually expanding surface \n270\n within the erosion region \n246\n.', 'As shown in \nFIG.', '4\n, the erosion rates associated with the sudden expansion chokes were substantially less than the erosion rate associated with the gradual expansion choke for flow rates ranging between about 4 BPM and about 11 BPM.', 'Such results demonstrated that sudden expansion chokes are substantially less susceptible to erosion caused by the particle-containing fluid flow.', 'Furthermore, the erosion rates associated with the sudden expansion chokes having the throat diameters of about 2.5 cm and 2.8 cm, shown by the curves \n313\n, \n314\n, respectively, experienced the lowest erosion rates.', 'Such results may be caused at least partially by lower fluid velocities associated with the larger throat diameters, as explained below.', 'Additional comparative studies were conducted using computational fluid dynamics (CFD) to numerically simulate performances of three chokes, each comprising a different geometry.', 'The first choke was a gradual expansion choke having the gradually expanding surface \n270\n extending at the angle \n272\n of about 15 degrees.', 'The second choke was a gradual expansion choke having the gradually expanding surface \n270\n extending at the angle \n272\n of about 40 degrees.', 'The third choke was a sudden expansion choke.', 'The CFD simulations included simulating a fluid flowing though the chokes.', 'The simulated fluid comprised a mixture of water and sand having the following characteristics: water density of about 1,000 kilograms per cubic meter (kg/m\n3\n), water viscosity of about one centipoise, sand density of about 2,650 kg/m\n3\n, and an overall fluid density of about 0.25 PPA (lbm of proppant added per gallon).', 'The first simulation included comparing the three chokes, each comprising a throat diameter of about 2.5 cm, while the fluid flow rate was adjusted to produce a pressure drop of about 100 PSI.', 'Some simulation parameters and results for the three chokes are set forth below in Table 1.\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nTABLE 1\n \n \n \n \n \n \n \n \n \nThroat\n \nPressure\n \nFlow\n \nErosion\n \n \n \n \nChoke\n \nDiameter\n \nDrop\n \nRate\n \nRate\n \n \n \n \nGeometry\n \n(cm)\n \n(PSI)\n \n(BPM)\n \n(mm/hr)', 'Gradual 15°\n \n2.5\n \n100.18\n \n10.55\n \n0.310\n \n \n \n \nGradual 40°\n \n2.5\n \n100.22\n \n8.81\n \n0.123', 'Sudden 90°\n \n2.5\n \n100.08\n \n7.56\n \n0.063\n \n \n \n \n \n \n \n \n \n \n \nThe results showed that the sudden expansion choke geometry was less susceptible to erosion.', 'For example, the erosion rate of 0.063 mm/hr associated with the sudden expansion choke is about half of the erosion rate of 0.123 mm/hr associated with the forty degree gradual expansion choke, and about five times less than the erosion rate of 0.310 mm/hr associated with the fifteen degree gradual expansion choke.', 'The results further showed that the gradual expansion chokes were less effective at producing energy loss, because the gradual expansion chokes are tested at higher flow rates to achieve the intended 100 PSI pressure drop.', 'The second simulation included comparing the three choke geometries at a constant fluid flow rate of about 10 BPM, while the throat diameter was adjusted to produce a pressure drop of about 100 PSI.', 'These simulation parameters and results for the three chokes are set forth below in Table 2.\n \n \n \n \n \n \n \n \n \n \n \n \n \nTABLE 2\n \n \n \n \n \n \n \nThroat\n \nPressure\n \nFlow\n \nFluid\n \nErosion\n \n \n \nChoke\n \nDiameter\n \nDrop\n \nRate\n \nVelocity\n \nRate\n \n \n \nGeometry\n \n(cm)\n \n(PSI)\n \n(BPM)\n \n(meter/sec)\n \n(mm/hr)\n \n \n \n \n \n \n \n \nGradual 15°\n \n2.46\n \n102.8\n \n10\n \n60.5\n \n0.307', 'Gradual 40°\n \n2.66\n \n104.7\n \n10\n \n48.6\n \n0.173\n \n \n \nSudden 90°\n \n2.82\n \n106.2\n \n10\n \n45.0\n \n0.041\n \n \n \n \n \n \n \n \n \n \nSuch results also showed that the sudden expansion choke is less susceptible to erosion than the gradual expansion choke.', 'For example, the erosion rate of 0.041 millimeters per hour (mm/hr) associated with the sudden expansion choke is about four times less than the erosion rate of 0.173 mm/hr associated with the forty degree gradual expansion choke, and about seven and a half times less than the erosion rate of 0.307 mm/hr associated with the fifteen degree gradual expansion choke.', 'The results further showed that the gradual expansion chokes were less effective at producing energy loss.', 'For example, the sudden expansion choke produced a pressure drop that was substantially similar to the pressure drop produced by the gradual expansion chokes despite the gradual expansion chokes having throat diameters smaller than the throat diameter of the sudden expansion choke.', 'The lower erosion rates associated with the sudden expansion choke shown in Tables 1 and 2 may be a result of several factors.', 'Erosion is often expected at locations where the fluid exiting the throat changes direction and impacts certain inner surfaces extending at different angles.', 'For example, in a sudden expansion choke, the fluid impacts the surfaces within the erosion region \n246\n, whereas fluid flow in a gradual expansion choke impacts the gradually expanding surface \n270\n.', 'The erosion region \n246\n of the sudden expansion choke experiences less erosion because the fluid jet exiting the throat \n220\n remains substantially centered within the expansion portion \n230\n, and the fluid located between the fluid jet and the cylindrical surface of the expansion portion \n230\n recirculates or moves against the erosion region \n246\n at a slower velocity, thus acting as buffer insulating the erosion region \n246\n from the high velocity fluid jet exiting the throat \n220\n.', 'However, the gradually expanding surface \n270\n of a gradual expansion choke experiences more erosion at least partially because the fluid jet exiting the throat is substantially closer to the gradually expanding surface \n270\n, thus permitting the high-velocity sand particles to impact the gradually expanding surface \n270\n.', 'The lower erosion rates associated with the sudden expansion choke shown in Tables 1 and 2 may also be partially affected by the throat diameters and fluid flow rates.', 'For example, larger throat diameters and lower flow rates translate to lower velocities of the fluid moving through the throat.', 'Because particles suspended within the fluid also have a lower velocity moving through the throat, the erosion rates caused by the particles are also lower.', 'The results shown in Table 1 are consistent with this phenomenon.', 'For example, the chokes associated with the lower flow rates comprise smaller erosion rates.', 'The results shown in Table 2 are also consistent with this phenomenon.', 'For example, the sudden expansion choke having the throat diameter of about 2.8 cm generated the lowest fluid velocity (45.0 meters per second (m/s)) through the choke and the lowest erosion rate (0.041 mm/hr).', 'However, the 15- and 40-degree gradual expansion chokes having throat diameters of 2.46 cm and 2.66 cm generated higher fluid velocities (60.50 m/s and 48.6 m/s) and higher erosion rates (0.307 mm/hr and 0.173 mm/hr).', 'FIG.', '5\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n400\n) according to one or more aspects of the present disclosure.', 'The method (\n400\n) may utilize at least a portion of a wellsite system and choke assembly, such as the wellsite system \n100\n shown in \nFIG.', '1\n and the choke assembly \n200\n shown in \nFIG.', '2\n, for example.', 'Thus, for the sake of clarity, the following description refers to \nFIGS.', '1, 2, and 5\n, collectively.', 'The method (\n400\n) comprises connecting (\n410\n) the choke assembly \n200\n in fluid communication between a pump \n152\n and the manifold \n136\n such that the fluid passage \n204\n of the choke assembly \n200\n conducts fluid from the pump \n152\n to the manifold \n136\n.', 'As described above, various portions of fluid conduits \n144\n may connect the choke assembly \n200\n between the pump \n152\n and the manifold \n136\n.', 'Connecting (\n410\n) the choke assembly \n200\n in fluid communication between the pump \n152\n and the manifold \n136\n may comprise connecting the upstream conduit portion \n145\n with the inlet connector \n256\n of the choke assembly \n200\n and connecting the downstream conduit portion \n149\n with the outlet connector \n258\n of the choke assembly \n200\n.', 'The method (\n400\n) also comprises operating (\n420\n) the pump \n152\n to move fluid through the choke assembly \n200\n towards the manifold \n136\n.', 'The fluid may be fracturing fluid.', 'Operating (\n420\n) the pump \n152\n to move the fluid through the choke assembly \n200\n may produce a pressure drop in the fluid as the fluid moves through the choke assembly \n200\n.', 'Operating (\n420\n) the pump \n152\n may also move the fluid from the manifold \n136\n into the wellbore \n104\n.', 'Operating (\n420\n) the pump \n152\n may comprise discharging the fluid from the pump \n152\n at a pressure ranging between about 4,000 PSI and about 15,000 PSI.', 'The method (\n400\n) may also comprise detecting (\n430\n) pressure of the fluid at the inlet \n203\n and the outlet \n207\n while operating (\n420\n) the pump to move fluid through the choke assembly \n200\n toward the manifold \n136\n.', 'Detecting (\n430\n) the pressure may be performed during wellsite operations, such as fracturing operations, during fluid flow rate setting operations, or during choke assembly \n200\n testing operations.', 'In view of the entirety of the present disclosure, including the claims and the figures, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising: a manifold; a plurality of pumps; and a plurality of choke assemblies each fluidly connected between the manifold and a corresponding one of the pumps, wherein each choke assembly comprises a body having a fluid passage conducting fluid from the corresponding pump to the manifold, and wherein the fluid passage comprises: an inlet having a first diameter; an outlet having a second diameter; a substantially cylindrical throat having a third diameter that is substantially less than the first and second diameters; a contraction portion connecting the inlet and the throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the fluid passage; and an expansion portion connecting the throat and the outlet and substantially comprising a substantially cylindrical chamber having the second diameter.', 'An end of the substantially cylindrical chamber may be defined by an annular surface extending radially from the throat such that the longitudinal axis of the fluid passage may be substantially coincident with a normal of the annular surface.', 'The contraction portion may substantially continuously decrease from the first diameter to the third diameter along the longitudinal axis of the fluid passage.', 'Each choke assembly may be operable to cause a pressure drop in the fluid conducted from the corresponding pump to the manifold.', 'The first and second diameters may be substantially equal.', 'Each choke assembly may further comprise: an inlet connector fluidly coupling the inlet with a first fluid conduit that fluidly connects the inlet with the corresponding pump; and an outlet connector fluidly coupling the outlet with a second fluid conduit that fluidly connects the outlet with the manifold.', 'An axial length of the throat may range between about 5 cm and about 10 cm.', 'In such implementations, among others within the scope of the present disclosure, the third diameter may be about 2.8 cm.', 'In such implementations, among others within the scope of the present disclosure, a maximum flow rate of each choke assembly may be about 10 BPM, velocity of the fluid conducted through the throat may be less than about 46 m/s at a fluid flow rate of about 10 BPM, and/or fluid conducted through the throat at a flow rate of about 10 BPM may experience a pressure drop of about 106 PSI.', 'The third diameter may be about 2.5 cm, and fluid conducted through the throat at a flow rate of about 10 BPM may experience a pressure drop of about 160 PSI.', 'The third diameter may be about 2.4 cm, and fluid conducted through the throat at a flow rate of about 10 BPM may experience a pressure drop of about 215 PSI.', 'The third diameter may be about 2.2 cm, and fluid conducted through the throat at a flow rate of about 10 BPM may experience a pressure drop of about 255 PSI.', 'Each choke assembly may further comprise a housing, and the body may be removably disposed within the housing.', 'At least one of the housing and the body may comprise an inlet connector fluidly coupling the inlet with a first fluid conduit that fluidly connects the inlet with the corresponding pump, and at least one of the housing and the body may comprise an outlet connector fluidly coupling the outlet with a second fluid conduit that fluidly connects the outlet with the manifold.', 'The fluid may be fracturing fluid.', 'However, other fluids are also within the scope of the present disclosure.', 'Each pump may discharge the fluid at a pressure ranging between about 4,000 PSI and about 15,000 PSI.', 'The present disclosure also introduces a method comprising: connecting a choke assembly in fluid communication between a pump and a manifold such that a fluid passage of the choke assembly conducts fluid from the pump to the manifold, wherein the fluid passage comprises: an inlet having a first diameter; an outlet having a second diameter; a substantially cylindrical throat having a third diameter that is substantially less than the first and second diameters; a contraction portion connecting the inlet and the throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the fluid passage; and an expansion portion connecting the throat and the outlet and substantially comprising a substantially cylindrical chamber having the second diameter; and operating the pump to move the fluid through the choke assembly toward the manifold.', 'Operating the pump to move the fluid through the choke assembly may produce a pressure drop in the fluid as the fluid moves through the choke assembly.', 'Operating the pump to move the fluid through the choke assembly toward the manifold may further move the fluid from the manifold into a wellbore extending into a subterranean formation.', 'The method may further comprise, while operating the pump to move fluid through the choke assembly toward the manifold, detecting pressure of the fluid at the inlet and the outlet.', 'Connecting the choke assembly in fluid communication between the pump and the manifold may comprise: connecting a first fluid conduit with an inlet connector of the choke assembly to fluidly couple the inlet with the first fluid conduit, wherein the first fluid conduit fluidly connects the inlet with the pump; and connecting a second fluid conduit with an outlet connector of the choke assembly to fluidly couple the outlet with the second fluid conduit, wherein the second fluid conduit fluidly connects the outlet with the manifold.', 'Operating the pump may comprise discharging the fluid from the pump at a pressure ranging between about 4,000 PSI and about 15,000 PSI.', 'An axial length of the throat may range between about 5 cm and about 10 cm, the third diameter may be about 2.8 cm, and operating the pump may move the fluid through the throat at a velocity less than about 46 m/s at a fluid flow rate of about 10 BPM.', 'In such implementations, among others within the scope of the present disclosure, fluid conducted through the throat may experience a pressure drop of about 106 PSI.', 'An axial length of the throat may range between about 5 cm and about 10 cm, the third diameter may be about 2.5 cm, and operating the pump may move the fluid through the throat at a fluid flow rate of about 10 BPM.', 'In such implementations, among others within the scope of the present disclosure, fluid conducted through the throat may experience a pressure drop of about 160 PSI.', 'An axial length of the throat may range between about 5 cm and about 10 cm, the third diameter may be about 2.4 cm, and operating the pump may move the fluid through the throat at a fluid flow rate of about 10 BPM.', 'In such implementations, among others within the scope of the present disclosure, fluid conducted through the throat may experience a pressure drop of about 215 PSI.', 'An axial length of the throat may range between about 5 cm and about 10 cm, the third diameter may be about 2.2 cm, and operating the pump may move the fluid through the throat at a fluid flow rate of about 10 BPM.', 'In such implementations, among others within the scope of the present disclosure, fluid conducted through the throat may experience a pressure drop of about 255 PSI.', 'The fluid may be fracturing fluid.', 'The present disclosure also introduces an apparatus comprising: a choke assembly for fluid connection between a manifold and a pump, wherein a fluid passage of the choke assembly comprises: an inlet having a first diameter; an outlet having a second diameter; a substantially cylindrical throat having a third diameter that is substantially less than the first and second diameters; a contraction portion connecting the inlet and the throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the fluid passage; and an expansion portion connecting the throat and the outlet and substantially comprising a substantially cylindrical chamber having the second diameter.', 'An end of the substantially cylindrical chamber may be defined by an annular surface extending radially from the throat such that the longitudinal axis of the fluid passage may be substantially coincident with a normal of the annular surface.', 'The contraction portion may substantially continuously decrease from the first diameter to the third diameter along the longitudinal axis of the fluid passage.', 'The choke assembly may decrease pressure of fluid conducted from the inlet to the outlet.', 'The first and second diameters may be substantially equal.', 'The choke assembly may further comprise: a body through which the fluid passage extends; an inlet connector for fluidly coupling the inlet with a first fluid conduit; and an outlet connector for fluidly coupling the outlet with a second fluid conduit.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'An apparatus, comprising:\na manifold;\na plurality of pumps, each of the pumps having a suction and a discharge;\na plurality of fluid conduits fluidly connecting each discharge of the plurality of pumps with the manifold; and\na plurality of choke assemblies each connecting portions of the plurality of fluid conduits, wherein each choke assembly comprises a housing and a body, wherein the body is integrally formed as a single piece and removably disposable within the housing, the body having a sealed fluid passage conducting a first fluid flow through the respective choke assembly from a corresponding pump to the manifold, and wherein the body having the sealed fluid passage comprises: an inlet having a first diameter and fluidly connected to the plurality of pumps to receive the first fluid flow; an outlet having a second diameter substantially equal to the first diameter and fluidly connected to the manifold to discharge the first fluid flow; a cylindrical throat having a third diameter that is less than the first and second diameters; a contraction portion connecting the inlet and the cylindrical throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the sealed fluid passage; and an expansion portion connecting the cylindrical throat and the outlet and comprising a cylindrical chamber having the second diameter, wherein an end of the cylindrical chamber is defined by an annular surface extending radially from the cylindrical throat to an inner surface of the expansion portion such that the longitudinal axis of the sealed fluid passage is coincident with a normal of the annular surface, and wherein each choke assembly is operable to cause a pressure drop in the first fluid flow conducted through the respective choke assembly from the discharge of the corresponding pump to the manifold.', '2.', 'The apparatus of claim 1 wherein the contraction portion continuously decreases from the first diameter to the third diameter along the longitudinal axis of the sealed fluid passage.', '3.', 'The apparatus of claim 1 wherein each choke assembly further comprises:\nan inlet connector fluidly coupling the inlet with a first fluid conduit that fluidly connects the inlet with the corresponding pump; and\nan outlet connector fluidly coupling the outlet with a second fluid conduit that fluidly connects the outlet with the manifold.', '4.', 'The apparatus of claim 1 wherein:\nan axial length of the cylindrical throat ranges between 5 centimeters (cm) and 10 cm;\nthe third diameter ranges between 2.2 cm and 2.8 cm; and\na maximum flow rate of each choke assembly is 10 barrels per minute (BPM).', '5.', 'The apparatus of claim 4 wherein the first fluid flow conducted through the cylindrical throat experiences a pressure drop of between 106 pounds per square inch (PSI) and 255 PSI.', '6.', 'The apparatus of claim 1 wherein:\nat least one of the housing and the body comprises an inlet connector fluidly coupling the inlet with a first fluid conduit that fluidly connects the inlet with the corresponding pump; and\nat least one of the housing and the body comprises an outlet connector fluidly coupling the outlet with a second fluid conduit that fluidly connects the outlet with the manifold.', '7.', 'The apparatus of claim 1 wherein the first fluid flow is a fracturing fluid flow, and wherein each pump discharges the fracturing fluid flow at a pressure ranging between 4,000 PSI and 15,000 PSI.\n\n\n\n\n\n\n8.', 'The apparatus of claim 1 wherein the housing is positioned between a first fluid conduit portion and a second fluid conduit portion of the plurality of fluid conduits, wherein the first fluid conduit portion interfaces with a first outer surface of the housing, and wherein the second fluid conduit portion interfaces with a second outer surface of the housing, opposite the first outer surface.', '9.', 'The apparatus of claim 8 wherein the second fluid conduit portion comprises a conduit inner diameter that is substantially equal to the second diameter.', '10.', 'The apparatus of claim 1 wherein the housing comprises an internal mating shoulder configured to contact an external mating shoulder of the body.', '11.', 'The apparatus of claim 1 wherein an interface between the annular surface and the inner surface of the expansion portion is tapered or rounded.', '12.', 'An apparatus, comprising:\na choke assembly for fluid connection between opposing portions of a fluid conduit disposed between a manifold and a discharge of a pump, wherein the choke assembly is operable to cause a pressure drop in a first fluid flow conducted through the choke assembly from the discharge of a corresponding pump along the fluid conduit, wherein the choke assembly comprises a housing and a body, wherein the body is integrally formed as a single piece and removably disposable within the housing, and wherein the body of the choke assembly defines a sealed fluid passage of the choke assembly and comprises: an inlet having a first diameter, wherein the inlet is configured to receive the first fluid flow; an outlet having a second diameter equal to the first diameter, wherein the outlet is configured to discharge the first fluid flow; a cylindrical throat having a third diameter that is less than the first and second diameters; a contraction portion connecting the inlet and the cylindrical throat and gradually decreasing from the first diameter to the third diameter along a longitudinal axis of the sealed fluid passage; and an expansion portion connecting the cylindrical throat and the outlet and comprising a cylindrical chamber having the second diameter, wherein an end of the cylindrical chamber is defined by an annular surface extending radially from the cylindrical throat to an inner surface of the expansion portion such that the longitudinal axis of the sealed fluid passage is coincident with a normal of the annular surface.\n\n\n\n\n\n\n13.', 'The apparatus of claim 12 wherein the contraction portion continuously decreases from the first diameter to the third diameter along the longitudinal axis of the sealed fluid passage.', '14.', 'The apparatus of claim 12 wherein each choke assembly further comprises:\nan inlet connector fluidly coupling the inlet with a first fluid conduit that fluidly connects the inlet with the corresponding pump; and\nan outlet connector fluidly coupling the outlet with a second fluid conduit that fluidly connects the outlet with the manifold.', '15.', 'The apparatus of claim 12 wherein:\nat least one of the housing and the body comprises an inlet connector fluidly coupling the inlet with a first fluid conduit that fluidly connects the inlet with the corresponding pump; and\nat least one of the housing and the body comprises an outlet connector fluidly coupling the outlet with a second fluid conduit that fluidly connects the outlet with the manifold.', '16.', 'The apparatus of claim 12 wherein the first fluid flow is a fracturing fluid flow, and wherein each pump discharges the fracturing fluid flow at a pressure ranging between 4,000 PSI and 15,000 PSI.', '17.', 'The apparatus of claim 12 wherein an axial length of the cylindrical throat ranges between 5 centimeters (cm) and 10 cm.', '18.', 'The apparatus of claim 12 wherein a maximum flow rate of each choke assembly is 10 barrels per minute (BPM).', '19.', 'The apparatus of claim 12 wherein:\nan axial length of the cylindrical throat ranges between 5 centimeters (cm) and 10 cm;\nthe third diameter ranges between 2.2 cm and 2.8 cm; and\na maximum flow rate of the choke assembly is 10 barrels per minute (BPM).', '20.', 'The apparatus of claim 19 wherein the first fluid flow conducted through the cylindrical throat experiences a pressure drop of between 106 pounds per square inch (PSI) and 255 PSI.'] | ['FIG.', '1 is a schematic view of at least a portion of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a side sectional view of an example implementation of a portion of the apparatus shown in FIG.', '1 according to one or more aspects of the present disclosure.', '; FIG.', '3 is a graph related to one or more aspects of the present disclosure.', '; FIG.', '4 is a graph related to one or more aspects of the present disclosure.; FIG.', '5 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG. 1 is a schematic view of at least a portion of an example wellsite system 100 according to one or more aspects of the present disclosure, representing an example environment in which one or more aspects described below may be implemented.', 'The figure depicts a wellsite 102 adjacent to a wellbore 104 and a partial sectional view of the subterranean formation 106 penetrated by the wellbore 104 below the wellsite 102.', 'The wellsite system 100 may comprise a first mixer 108 fluidly connected with one or more tanks 110 and a first container 112.', 'The first container 112 may contain a first material and the tanks 110 may contain a liquid.', 'The first material may be or comprise a hydratable material or gelling agent, such as guar, polymers, synthetic polymers, galactomannan, polysaccharides, cellulose, and/or clay, among other examples, and the liquid may be or comprise an aqueous fluid, which may comprise water or an aqueous solution comprising water, among other examples.', 'The first mixer 108 may be operable to receive the first material and the liquid via two or more fluid conduits 114, 116, and mix or otherwise combine the first material and the liquid to form a base fluid.', 'The base fluid may be or comprise that which is known in the art as a gel.', 'The first mixer 108 may then discharge the base fluid via one or more fluid conduits 118.; FIG.', '1 shows the wellsite system 100 operable to produce and/or mix fluids and/or mixtures (hereinafter collectively referred to as a “fluid”) that may be pressurized and individually or collectively injected into the wellbore 104 during hydraulic fracturing of the subterranean formation 106.', 'However, it is to be understood that the wellsite system 100 may be operable to mix and/or produce other mixtures and/or fluids that may be pressurized and individually or collectively injected into the wellbore 104 during other oilfield operations, such as drilling, cementing, acidizing, chemical injecting, and/or water jet cutting operations, among other examples.; FIG.', '2 is a side sectional view of an example implementation of one of the choke assemblies 200 shown in FIG.', '1 according to one or more aspects of the present disclosure.', 'The choke assembly 200 comprises a body 202.', 'A fluid passage 204 extends through the body along a longitudinal axis 206 of the body 202.', 'The fluid passage 204 comprises an inlet 203 and an outlet 207.', 'A diameter 205 of the inlet 203 may be substantially equal (e.g., within about 5%) to a diameter 209 of the outlet 207.', 'The fluid passage 204 also comprises a contraction portion 210, a throat 220, and an expansion portion 230 collectively extending between the inlet 203 and the outlet 207.; FIG.', '5 is a flow-chart diagram of at least a portion of an example implementation of a method (400) according to one or more aspects of the present disclosure.', 'The method (400) may utilize at least a portion of a wellsite system and choke assembly, such as the wellsite system 100 shown in FIG.', '1', 'and the choke assembly 200 shown in FIG.', '2, for example.', 'Thus, for the sake of clarity, the following description refers to FIGS.', '1, 2, and 5, collectively.'] |
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well and maintaining zonal isolation involve preparing a cement slurry that contains water, an inorganic cement and an expanding agent.', 'The slurry is placed in the annular region between casing and the formation or between two casing strings.', 'After the cement sets, the expanding agent reacts and causes the set cement to be in a state of compression within the annular region.', 'The casing dimensions may fluctuate in response to a temperature change, a pressure change, a mechanical disturbance resulting from a well intervention, or mud contamination or a combination thereof.', 'The expanding agent may further react and maintain a state of compression within the annular region.', 'The state of compression in the annular region may be monitored by acoustic impedance measurements.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'This application claims benefit of EP Patent App.', 'Ser.', 'No. 14305938.4 filed Jun. 18, 2014, which is herein incorporated by reference in its entirety.', 'BACKGROUND', 'The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.', 'The present disclosure broadly relates to systems and methods for cementing subterranean wells and maintaining zonal isolation therein.', 'Good bonding between set cement and casing and between set cement and the formation is essential for effective zonal isolation.', 'Poor bonding limits production and reduces the effectiveness of stimulation treatments.', 'Communication between zones can be caused by inadequate mud removal, poor cement/formation bonding, expansion and contraction of the casing resulting from internal pressure variations or thermal stresses, and cement contamination by drilling or formation fluids.', 'Under such circumstances a small gap or microannulus may form at the cement/casing or the cement/formation interface or both.', 'Cement systems that expand slightly after setting may provide a means for sealing microannuli and improving primary cementing results.', 'The improved bonding may be the result of mechanical resistance or tightening of the cement against the pipe and formation.', 'Portland cement manufacturers generally limit the amount of certain alkaline impurities to avoid expansion of the set cement, a condition called “unsoundness.”', 'In an unrestrained environment such as a road or building, expansion of the set cement can result in cracking and failure.', 'In a wellbore environment, however, the cement is restrained by the casing and, when competent, the formation.', 'Consequently, once the cement has expanded to eliminate void spaces, further expansion reduces internal porosity.', 'Generally, expanding cements should be more flexible than the formation; otherwise, the cement may not expand toward the casing, risking the formation of a microannulus.', 'The presence or absence of cement in the annulus between casing and the formation (or between two casing strings) may be detected by acoustic logging.', 'Among the tools currently available, sonic or ultrasonic imagers are commonly used.', 'However, when a gas-filled microannulus exists, these tools are unable to detect the presence of cement behind.', 'A common practice is to run logs while applying pressure inside the casing, thus causing the casing to expand and contact the cement sheath.', 'SUMMARY\n \nThe present disclosure reveals methods for pre-stressing the cement sheath, thereby allowing the cement to maintain an acoustic coupling with the casing despite pressure and temperature variations, mechanical perturbations arising from well intervention operations and deposits of drilling fluid or spacer left on the casing surface.', 'In an aspect, embodiments relate to methods for cementing a subterranean well having a borehole.', 'A cement slurry is prepared that comprises water, an inorganic cement and an expanding agent.', 'The slurry is then placed in an annular region between a tubular body and a borehole wall, or between two tubular bodies.', 'The slurry is allowed to harden and form a set cement.', 'After setting, the expanding agent is allowed to react and cause the set cement to be in a state of compression within the annular region.', 'In a further aspect, embodiments relate to methods for maintaining zonal isolation in a wellbore.', 'A cement slurry is prepared that comprises water, an inorganic cement and an expanding agent.', 'The slurry is then placed in an annular region between a tubular body and a borehole wall, or between two tubular bodies.', 'The slurry is allowed to harden and form a set cement.', 'The dimensions of the tubular body are allowed to fluctuate in response to a temperature change, a pressure change, or a mechanical disturbance resulting from a well intervention or a combination thereof.', 'The expanding agent is then allowed to react and cause the set cement to be in a state of compression within the annular region.', 'In yet a further aspect, embodiments relate to methods for determining the presence of cement behind a tubular body in a subterranean well.', 'A cement slurry is prepared that comprises water, an inorganic cement and an expanding agent.', 'The slurry is then placed in an annular region between a tubular body and a borehole wall, or between two tubular bodies.', 'The slurry is allowed to harden and form a set cement.', 'After setting, the expanding agent is allowed to react and cause the set cement to be in a state of compression within the annular region.', 'An acoustic logging tool is then introduced into the tubular body.', 'The tool measures the acoustic impedance, an amplitude, an attenuation or a bond index or a combination thereof, the measurements taken azimuthally, longitudinally or both along the tubular body.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n shows a diagram of an apparatus for measuring cement expansion and prestress development.', 'FIGS.', '2A and 2B\n show the results of confined cement expansion experiments.', 'FIGS.', '3A and 3B\n show the results of expansion experiments for cements with a constant supply of external water, and cements in a sealed environment.\n \nFIG.', '4\n is a photograph of a laboratory apparatus for measuring the acoustic impedance of cements in an annulus.', 'FIGS.', '5A and 5B\n show an acoustic impedance scale and an impedance map showing good bonding in the annulus.', 'FIGS.', '6A and 6B\n show the acoustic impedance measurements of neat cement systems after curing in the laboratory apparatus of \nFIG.', '4\n.', 'FIGS.', '7A and 7B\n show the acoustic impedance measurements of expansive cement systems after curing in the laboratory apparatus of \nFIG.', '4\n.', 'FIG.', '8\n shows strain measurements taken from the laboratory apparatus of \nFIG.', '4\n during the curing of an expanding cement system.', 'FIG.', '9\n shows temperature measurements taken in the annular region of the laboratory apparatus of \nFIG.', '4\n during the curing of an expanding cement system.', 'FIGS.', '10A and 10B\n show the acoustic impedance measurements of neat cement systems after curing in the laboratory apparatus of \nFIG.', '4\n.', 'FIGS.', '11A, 11B and 11C\n show the acoustic impedance measurement of expansive cement systems after curing in the laboratory apparatus of \nFIG.', '4\n.', 'DETAILED DESCRIPTION', 'The present disclosure will be described in terms of treatment of vertical wells, but is equally applicable to wells of any orientation.', 'The disclosure will be described for hydrocarbon-production wells, but it is to be understood that the disclosed methods can be used for wells for the production of other fluids, such as water or carbon dioxide, or, for example, for injection or storage wells.', 'It should also be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated.', 'Furthermore, each numerical value should be read once as modified by the term “about” (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context.', 'For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10.', 'In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the Applicants appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the Applicants have possession of the entire range and all points within the range.', 'In this disclosure, the tubular body may be any string of tubulars that may be run into the wellbore and at least partially cemented in place.', 'Examples include casing, liner, solid expandable tubular, production tubing and drill pipe.', 'In an aspect, embodiments relate to methods for cementing a subterranean well having a borehole.', 'A cement slurry is prepared that comprises water, an inorganic cement and an expanding agent.', 'The slurry is then placed in an annular region between a tubular body and a borehole wall, or between two tubular bodies.', 'The slurry is allowed to harden and form a set cement.', 'After setting, the expanding agent is allowed to react and cause the set cement to be in a state of compression within the annular region.', 'The method may further comprise allowing the dimensions of the tubular body to fluctuate in response to a temperature change, a pressure change, or a mechanical disturbance resulting from a well intervention or a combination thereof.', 'The method may also further comprise allowing the set cement to expand and maintain the state of compression after the dimensional fluctuation of the tubular body.', 'In a further aspect, embodiments relate to methods for maintaining zonal isolation in a wellbore.', 'A cement slurry is prepared that comprises water, an inorganic cement and an expanding agent.', 'The slurry is then placed in an annular region between a tubular body and a borehole wall, or between two tubular bodies.', 'The slurry is allowed to harden and form a set cement.', 'The dimensions of the tubular body are allowed to fluctuate in response to a temperature change, a pressure change, or a mechanical disturbance resulting from a well intervention or a combination thereof.', 'The expanding agent is then allowed to react and cause the set cement to be in a state of compression within the annular region.', 'In yet a further aspect, embodiments relate to methods for determining the presence of cement behind a tubular body in a subterranean well.', 'A cement slurry is prepared that comprises water, an inorganic cement and an expanding agent.', 'The slurry is then placed in an annular region between a tubular body and a borehole wall, or between two tubular bodies.', 'The slurry is allowed to harden and form a set cement.', 'After setting, the expanding agent is allowed to react and cause the set cement to be in a state of compression within the annular region.', 'An acoustic logging tool is then introduced into the tubular body.', 'The tool measures the acoustic impedance, an amplitude, an attenuation or a bond index or a combination thereof, the measurements taken azimuthally, longitudinally or both along the tubular body.', 'For all aspects, the viscosity of the cement slurry during placement may be lower than 1000 cP at a shear rate of 100 s\n−1\n.', 'The inorganic cement may comprise portland cement, calcium aluminate cement, fly ash, blast furnace slag, lime/silica blends, zeolites, magnesium oxychloride, geopolymers or chemically bonded phosphate ceramics or combinations thereof.', 'For all aspects, the expanding agent may comprise calcium oxide, magnesium oxide or calcium sulfate hemihydrate or combinations thereof.', 'The expanding agent may be present at a concentration between 5% and 25% by weight of cement.', 'For all aspects, the cement expansion may be delayed.', 'The expanding agent may be encapsulated or held as an internal phase of an emulsion.', 'For all aspects the cement slurry may further comprise silica, diatomaceous earth, gilsonite, hematite, ilmenite, manganese tetraoxide, barite, glass or ceramic microspheres or combinations thereof.', 'EXAMPLES', 'The following examples are provided to more fully illustrate the disclosure.', 'These examples are not intended to limit the scope of the disclosure in any way.', 'All of the experiments presented here were performed with Class G oilwell cement.', 'For the confined expansion measurements described in Example 1, the expanding agent was hard-burned magnesium oxide (MgO).', 'The MgO was present at concentrations of 5%, 14%, and 25% by weight of cement (BWOC).', 'The 5% concentration is at the upper end of what is typically used in the field.', 'Slurries were prepared at a water-to-solids ratio of 0.41, and mixed by hand or with a low-speed paddle mixer.', 'No other additives were used.', 'For confined expansion testing, approximately 50 g of slurry was used.', 'The expansion tests were conducted at 85° C. and ambient pressure.', 'For the logging experiments described in Example 2, Class G cement was used, and the expanding agent was a mixture of hard-burned CaO and hard-burned MgO. The CaO/MgO weight ratio was 1.43.', 'CaO and MgO hydrate in similar ways to generate expansion, but CaO tends to be much more reactive at a given temperature than MgO. These experiments were conducted with a neat cement slurry or one with 12% BWOC of expanding agent.', 'In both cases the water-to-solids ratio was 0.41.', 'Small amounts of dispersant, anti-settling agent, and antifoaming agent were also added to generate a stable slurry.', 'Mixing was performed in a Waring high-speed blender with a capacity of 4 L. Because the logging test requires about 7 L of slurry, two batches were prepared for each test and combined.', 'Example 1\n \nTo measure the effects of expanding agents under confined conditions, a temperature-controlled confinement cell was designed and built (\nFIG.', '1\n).', 'Radial confinement is provided by a hollow steel cylinder \n101\n with ID=2.86 cm (1.125 in.)', 'and OD=7.62 cm (3 in.).', 'The cylinder was sealed at the bottom with a removable metallic plug \n102\n that screws into the bottom and seals with two O-rings.', 'This cell was designed such that the axial confinement from the top is provided by a piston \n107\n that slides easily inside the steel cylinder and is connected by a rod \n109\n to a programmable mechanical testing machine with a 5-kN load cell.', 'The steel cylinder is screwed inside a heating/insulator chamber \n103\n where a glycol bath is heated up with a resistance heater \n104\n.', 'Tests can be performed at temperatures between room temperature and about 95° C.', 'The upper limit is defined by the inability to prevent water escaping from the cement as vapor, since the device is not pressure-tight.', 'Two thermocouples are placed near the heater and near the cement sample.', 'They are connected to the heater power supply box and are used to maintain a fixed set-point temperature.', 'Two general modes of operation can be used with the expansion cell: fixed displacement of the piston (in which case the compressive load is measured) and fixed load applied to the piston (in which case the displacement of the piston is measured).', 'The experiments reported here were conducted in fixed displacement mode.', 'To simulate hydration of cement placed against a permeable formation containing water, a porous ceramic disk \n105\n that was saturated with water was placed on top of the cement sample \n106\n, with a layer of filter paper between to keep the disk clean.', 'The piston was then inserted into the cylinder until it made contact with the porous disk.', 'Additional water \n108\n was poured on top of the piston, and then finally a layer of high-boiling-point silicon oil was added to prevent evaporation of the water.', 'Holes in the piston allowed water access between the sample and reservoir.', 'As the cement and expanding agent reacted, volume lost to chemical shrinkage was replaced by external water flowing into the slurry from above, keeping the pores of the sample saturated.', 'To simulate hydration of cement placed against a tight formation that supplies no water to the cement, the piston was placed directly in contact with the cement and a thick layer of lubricant was used to prevent water evaporation from the specimen.', 'In this case, chemical shrinkage desaturated the pore system, causing some shrinkage that may have been compensated by the expanding agent.\n \nFIG.', '2\n shows the compressive stress in cement/MgO blends as they hydrate at 85° C., calculated by dividing the force applied by the piston to maintain a fixed displacement by the area of the specimen.', 'In \nFIG.', '2A\n, results are shown for three different blends containing 5%, 15%, and 25% MgO by weight of cement (BWOC), with water available through a porous ceramic disk above the specimen.', 'This represents the condition of cemented annulus placed against a stiff, water-filled rock formation.', 'Note that 25% MgO BWOC corresponds to a blend of 80% cement/20% MgO.\n \nAfter 1 week, compressive stresses ranging from about 90-750 psi (0.6-5 MPa) had developed in the samples, with the stress level roughly proportional to the MgO concentration.', 'The kinetics of load development did not follow the kinetics of MgO hydration.', 'Whereas the hydration of MgO exhibited a declining rate that nearly reached a plateau after a several days, the load development was still increasing strongly after one week.', 'One confinement test was also performed with 14% BWOC of the more reactive expanding agent consisting of a blend of hard-burned CaO and MgO (\nFIG.', '2B\n).', 'For this test, the temperature was held at 40° C. for the first 72 h, and then increased to 85° C. thereafter.', 'The behavior shown in \nFIG.', '2B\n can be related to the presence of both MgO and CaO in the expanding agent.', 'The CaO is much more reactive, so it provides early expansion even at 40° C. and then becomes completely hydrated after about 24 h, whereas the MgO is nearly inert at 40° C. When the temperature is increased to 85° C. the MgO begins to react, giving strong expansion over the next week and beyond.', 'The effect of water availability on the development of expansive stress within the cement was also explored, as shown in \nFIGS.', '3A and 3B\n.', 'Under sealed conditions, chemical shrinkage caused by hydration of both the cement and expanding agent will cause the pores to become desaturated, resulting in autogeneous shrinkage.', 'Such a condition will occur for cement placed against a tight formation such as a shale, or for cementing between casings.', 'FIG.', '3A\n shows the expansion comparison for cements containing 5% BWOC MgO, one exposed to external water and the other sealed.', 'The sealed cement exhibited a delay in the expansion, after which the kinetics of load development were similar to that of the cement exposed to water, such that the stress curves were parallel.', 'This can be explained simply by a superposition of the expansion caused by MgO hydration and the autogeneous shrinkage at early times with sealed curing.', 'The same comparison for 25% bwoc MgO (\nFIG.', '3B\n) shows a different behavior, in that the axial expansion stress was higher with the sealed curing condition.', 'This was unexpected due to the expected autogeneous shrinkage as noted above.', 'Considering the kinetics of the shrinkage and expansion provides some insight.', 'During the first 20 h of hydration, when most autogeneous shrinkage occurs, the sealed cement indeed gives less expansion as expected.', 'At later times, however, the expansion is greater.', 'This suggests that the desaturation of the pore system has a positive effect on the expansion.', 'While the reason for this is not clear, and Applicant does not wish to be held to any theory, it may be a chemical effect that relates to the amount of crystallization pressure that is generated between the Mg(OH)\n2 \ncrystals and the cement paste matrix.', 'Overall, the results shown in \nFIGS.', '3A and 3B\n indicate that expansive stresses can be generated under both saturated and sealed curing conditions, although expansion may be delayed in the latter case.', 'Example 2\n \nAn apparatus was built to study the acoustic response of cement systems or additives in different controlled configurations in an annular geometry typical of a wellbore (\nFIG.', '4\n).', 'The apparatus consists of an inner steel casing with a diameter of 7 in.', '(178 mm), and an outer steel casing with a diameter of 9⅝ in.', '(244 mm), and height of about 370 mm.', 'For logging purposes, the inner casing is filled with water.', 'The temperature of the cement annulus can be controlled by use of a heating jacket around the outside of the outer casing, along with a resistance heater submerged in the inner casing.', 'A laboratory version of an Ultrasonic Imager Tool (USIT), available from Schlumberger, may be placed inside the inner casing.', 'This tool consists of a piezoelectric transducer mounted on a control arm that can move the transducer both axially and azimuthally.', 'The transducer operates between 250-750 kHz and is designed for use at ambient pressure.', 'With this setup, the acoustic impedance of the annulus at different locations can be measured, and an impedance map of the entire annulus can be generated.', 'High impedance indicates that cement is well bonded to the inner casing, while low impedance values indicate poor bonding or the presence of a microannulus.', 'This logging setup has a vertical resolution of about 25 mm and an azimuthal resolution of approximately 5°.', 'After preparing a slurry as described earlier, the slurry was pumped slowly into the annulus from below.', 'A layer of silicone oil was poured on top of the slurry to prevent drying.', 'No external water was provided to the cement.', 'Immediately after placement of the cement slurry in the annulus, the inner casing was pressurized hydraulically to 3000 psi [20.7 MPa] using a pressure sleeve.', 'The purpose of this step was to allow a drop in casing pressure to be simulated at later times after the cement has set, by removing the hydraulic pressure.', 'Such a step will often cause the cement to debond from the casing.', 'Because the logging tool and pressure sleeve could not be inside the casing at the same time, logging of the annulus was begun only after the pressure sleeve was removed.', 'The logging procedure allowed the acoustic impedance of the annulus material to be characterized over a vertical distance of 250 mm and the entire 360° azimuthal angle.', 'These measurements were converted into an impedance map of the annulus material, as shown by an example in \nFIGS.', '5A and 5B\n for a neat cement paste hydrated with no change in casing pressure.', 'The color coding of the map (\nFIG.', '5A\n) is designed to facilitate the interpretation of the material behind the casing: cement (tan or brown), liquid (blue), or gas (red) based on their typical acoustic properties.', 'It should be noted that low impedance values in the blue range can also indicate very weakly bonded cement.', 'The example map (\nFIG.', '5B\n) indicates good cement behind casing everywhere.', 'A series of two experiments using the logging apparatus of \nFIG.', '4\n was designed to test the ability of an expanding formulation to close a microannulus created by a pressure drop inside the inner casing.', 'One experiment was conducted with neat cement, and the other with the expanding formulation.', 'In each case the procedure was the same.', 'The slurry was first pumped into the annulus and then the device was heated up to 30° C.', 'While the slurry was still liquid, the casing was expanded hydraulically to the equivalent of 3000 psi [20.7 MPa].', 'The cement was cured for 50 h at 30° C. and, at that point, the casing pressure was removed causing the casing to contract.', 'The logging began and continued until the set cement was 115 h old.', 'At that point the cement was heated to 66° C. for 8 h, and then further cured at 30° C. until 139 h at which time the logging was resumed.', 'The purpose of the 8-h heat treatment at 66° C. was to generate additional delayed expansion from the MgO present in the expanding agent; however, it was also applied to the neat cement system to provide a valid control experiment.', 'FIGS.', '6A and 6B\n show the impedance maps from the neat cement system at 118 h (68 h after the pressure decrease) and at 310 h. Both maps show zero impedance everywhere, indicating that the pressure drop caused the cement to completely debond from the casing, creating a dry microannulus, and that the heat treatment did not induce any change.', 'FIGS.', '7A and 7B\n show impedance maps for the expanding formulation conducted at 115 h (65 h after the pressure decrease), and at 139 h (89 h after the pressure decrease).', 'After the pressure decrease, the impedance map shows zero impedance everywhere, indicating a dry microannulus similar to the neat cement.', 'However after the heat treatment, the impedance map shows good cement all around the casing, demonstrating that the expansion can help close a pre-existing microannulus and restore the acoustic coupling.', 'Example 3\n \nThe apparatus of Example 2 (\nFIG.', '4\n) was further equipped with three strain gauges inside the inner casing and three strain gauges outside the outer casing.', 'A series of two experiments was designed to test the ability of an expanding cement system to prevent the formation of an inner microannulus after a pressure drop inside the inner casing.', 'One experiment was conducted with a neat cement system and the other was conducted with a pre-stressed cement containing 12% BWOC MgO/CaO expanding agent described earlier.', 'In both cases the water-to-cement ratio was 0.41.', 'For both experiments, the device was first heated to 30° C. and then the slurry was poured into place.', 'While the slurry was still liquid, the casing was expanded mechanically to the equivalent of 9 MPa.', 'The cement was cured for 24 h at 30° C., and then heated to 85° C. for 8 h, and then further cured at 30° C. until the cement was 48 h old.', 'At that point, the casing pressure was removed (causing the casing to contract), the apparatus was allowed to cool to 23° C., and the logging commenced.', 'The purpose of the 8-h heat treatment at 85° C. was to generate additional pre-stress from the MgO present in the expanding agent; however, it was also applied to the neat cement system to provide a valid control experiment.', 'The pre-stress level was measured independently at around 3.5 MPa (\nFIGS.', '8, 9\n and Table 1).', 'FIG.', '8\n and Table 1 present strain measurements taken from the inner and outer casings.', 'The strain values below zero corresponded to the inner casing.', 'Values above zero corresponded to the outer casing.', 'The measured temperature between the concentric cylinders during the experiments is shown in \nFIG.', '9\n.', 'TABLE 1\n \n \n \n \n \n \n \n \nMeasured inner and outer mean strains at different times for the\n \n \n \nexpanding cement system containing 12% BWOC of MgO/CaO\n \n \n \nexpanding agent.', 'Inner strain\n \nOuter strain\n \nInner stress\n \nOuter stress\n \n \n \nTime\n \n(μm/m)\n \n(μm/m)\n \n(MPa)\n \n(MPa)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n20 h\n \n−80\n \n80\n \n−1.5\n \n−1.5\n \n \n \n50 h\n \n−210\n \n190\n \n−3.4\n \n−3.3\n \n \n \n66 h\n \n−210\n \n190\n \n−3.4\n \n−3.3\n \n \n \n382 h\u2002\n \n−210\n \n190\n \n−3.4\n \n−3.3\n \n \n \n \n \n \n \n \n \n \nLogging experiments were conducted in the apparatus after the pressure decrease and at later times.', 'FIGS.', '10A and 10B\n show impedance maps measured during the experiments with the neat cement system.', 'The map recorded at 50 h (just after the pressure drop) is shown in \nFIG.', '10A\n.', 'FIG.', '10B\n is a map recorded 184 h following the pressure drop.', 'The maps indicate that complete debonding of the cement sheath from the casing occurred.\n \nFIGS.', '11A, 11B and 11C\n show impedance maps measured during experiments with the expanding cement system.', 'The measurements were taken at 51 h (\nFIG.', '11A\n, just after the pressure drop), at 88 h (\nFIG.', '11B\n) and at 168 h (\nFIG.', '11C\n).', 'Just after the pressure drop, the impedance map was not entirely red, indicating that the cement/casing acoustic coupling was maintained at some locations.', 'With the passage of time, the average impedance increased significantly, indicating acoustic coupling improvements.', 'Although various embodiments have been described with respect to enabling disclosures, it is to be understood that this document is not limited to the disclosed embodiments.', 'Variations and modifications that would occur to one of skill in the art upon reading the specification are also within the scope of the disclosure, which is defined in the appended claims.'] | ['1.', 'A method, comprising:\npreparing a cement slurry comprising water, portland cement and an expanding agent that comprises calcium sulfate hemihydrate, or a blend of hard-burned calcium oxide (CaO) and hard-burned magnesium oxide (MgO), or combinations thereof, wherein the expanding agent is present at a concentration between 5% and 20% by weight of cement;\nplacing the slurry in an annular region between a tubular body and a borehole wall or a concentric region between two tubular bodies, whereupon the slurry hardens and forms a set cement, and the expanding agent reacts and causes the set cement to be in a state of compression within the annular region;\nperforming a well intervention;\nintroducing an acoustic logging tool into the tubular body; and\nwithout applying pressure inside the tubular body, measuring an acoustic impedance, an amplitude, an attenuation or a bond index or a combination thereof, the measurements taken azimuthally, longitudinally or both along the tubular body to determine a presence of set cement behind the tubular body or bodies in a subterranean well.', '2.', 'The method of claim 1, wherein\ndimensions of the tubular body fluctuate in response to a temperature change, a pressure change, or a mechanical disturbance, or a combination thereof resulting from the well intervention.', '3.', 'The method of claim 1, further comprising:\nallowing the set cement to expand and maintain the state of compression.', '4.', 'The method of claim 1, wherein the cement expansion is delayed.', '5.', 'The method of claim 1, wherein the expanding agent is encapsulated or held as an internal phase of an emulsion.', '6.', 'The method of claim 1, wherein the cement slurry further comprises fly ash, blast furnace slag, silica, diatomaceous earth, gilsonite, hematite, ilmenite, manganese tetraoxide or barite or combinations thereof.', '7.', 'A method for cementing a subterranean well having a borehole, comprising:\npreparing a cement slurry comprising water, an inorganic cement and an expanding agent, wherein the expanding agent is present at a concentration between 5% and 20% by weight of cement, and the expanding agent comprises calcium sulfate hemihydrate, a blend of hard-burned calcium oxide (CaO) and hard-burned magnesium oxide (MgO), or combinations thereof;\nplacing the slurry in an annular region between a tubular body and a borehole wall or a concentric region between two tubular bodies, whereupon the slurry hardens and forms a set cement, and the expanding agent reacts to cause the set cement to be in a state of compression within the annular region;\nperforming a well intervention, during which dimensions of the tubular body or bodies fluctuate in response to a temperature change, a pressure change, a mechanical disturbance or a combination thereof, and after which the set cement expands and maintains the state of compression; and\nwithout applying pressure within the tubular body, determining a presence of set cement behind the tubular body or bodies in a subterranean well.', '8.', 'The method of claim 7, wherein the cement expansion is delayed.', '9.', 'The method of claim 7, wherein the expanding agent is encapsulated or held as an internal phase of an emulsion.', '10.', 'The method of claim 7, wherein the cement slurry further comprises fly ash, blast furnace slag, silica, diatomaceous earth, gilsonite, hematite, ilmenite, manganese tetraoxide or barite or combinations thereof.', '11.', 'The method of claim 7, wherein the inorganic cement comprises portland cement, calcium aluminate cement, fly ash, blast furnace slag, lime/silica blends, magnesium oxychloride, geopolymers or zeolites or combinations thereof.\n\n\n\n\n\n\n12.', 'The method of claim 7, further comprising:\nheating the cement slurry to about 85° C. following curing of the cement slurry.\n\n\n\n\n\n\n13.', 'A method for maintaining zonal isolation in a wellbore, comprising:\npreparing a cement slurry comprising water, portland cement and an expanding agent, wherein the expanding agent is present at a concentration between 5% and 20% by weight of cement, and the expanding agent comprises calcium sulfate hemihydrate, or a blend of hard-burned calcium oxide (CaO) and hard- burned magnesium oxide (MgO), or combinations thereof;\nplacing the slurry in an annular region between a tubular body and a borehole wall or a concentric region between two tubular bodies, whereupon the slurry hardens and forms a set cement;\nperforming a well intervention, during which the dimensions of the tubular body or bodies fluctuate in response to a temperature change, a pressure change, or a mechanical disturbance or a combination thereof, and after which the expanding agent reacts and causes the set cement to expand and maintain a state of compression within the annular region; and\nwithout applying pressure within the tubular body, determining a presence of set cement behind the tubular body or bodies in the wellbore.', '14.', 'The method of claim 13, wherein the cement expansion is delayed.', '15.', 'The method of claim 13, wherein the expanding agent is encapsulated or held as an internal phase of an emulsion.', '16.', 'The method of claim 13, wherein the cement slurry further comprises silica, diatomaceous earth, gilsonite, hematite, ilmenite, manganese tetraoxide, barite, glass or ceramic microspheres or combinations thereof.', '17.', 'The method of claim 1, further comprising:\nheating the cement slurry to about 85° C. following curing of the cement slurry.', '18.', 'The method of claim 13, further comprising:\nheating the cement slurry to about 85° C. following curing of the cement slurry.'] | ['FIG.', '1 shows a diagram of an apparatus for measuring cement expansion and prestress development.;', 'FIGS.', '2A and 2B show the results of confined cement expansion experiments.', '; FIGS.', '3A and 3B show the results of expansion experiments for cements with a constant supply of external water, and cements in a sealed environment.;', 'FIG. 4 is a photograph of a laboratory apparatus for measuring the acoustic impedance of cements in an annulus.; FIGS.', '5A and 5B show an acoustic impedance scale and an impedance map showing good bonding in the annulus.;', 'FIGS.', '6A and 6B show the acoustic impedance measurements of neat cement systems after curing in the laboratory apparatus of FIG.', '4.; FIGS.', '7A and 7B show the acoustic impedance measurements of expansive cement systems after curing in the laboratory apparatus of FIG.', '4.; FIG.', '8 shows strain measurements taken from the laboratory apparatus of FIG.', '4 during the curing of an expanding cement system.', '; FIG.', '9 shows temperature measurements taken in the annular region of the laboratory apparatus of FIG.', '4 during the curing of an expanding cement system.;', 'FIGS.', '10A and 10B show the acoustic impedance measurements of neat cement systems after curing in the laboratory apparatus of FIG.', '4.; FIGS.', '11A, 11B and 11C show the acoustic impedance measurement of expansive cement systems after curing in the laboratory apparatus of FIG.', '4.; FIG.', '2 shows the compressive stress in cement/MgO blends as they hydrate at 85° C., calculated by dividing the force applied by the piston to maintain a fixed displacement by the area of the specimen.', 'In FIG.', '2A, results are shown for three different blends containing 5%, 15%, and 25% MgO by weight of cement (BWOC), with water available through a porous ceramic disk above the specimen.', 'This represents the condition of cemented annulus placed against a stiff, water-filled rock formation.', 'Note that 25% MgO BWOC corresponds to a blend of 80% cement/20% MgO.; FIGS.', '6A and 6B show the impedance maps from the neat cement system at 118 h (68 h after the pressure decrease) and at 310 h. Both maps show zero impedance everywhere, indicating that the pressure drop caused the cement to completely debond from the casing, creating a dry microannulus, and that the heat treatment did not induce any change.', ';', 'FIGS.', '7A and 7B show impedance maps for the expanding formulation conducted at 115 h (65 h after the pressure decrease), and at 139 h (89 h after the pressure decrease).', 'After the pressure decrease, the impedance map shows zero impedance everywhere, indicating a dry microannulus similar to the neat cement.', 'However after the heat treatment, the impedance map shows good cement all around the casing, demonstrating that the expansion can help close a pre-existing microannulus and restore the acoustic coupling.; FIG. 8 and Table 1 present strain measurements taken from the inner and outer casings.', 'The strain values below zero corresponded to the inner casing.', 'Values above zero corresponded to the outer casing.', 'The measured temperature between the concentric cylinders during the experiments is shown in FIG.', '9.; FIGS.', '11A, 11B and 11C show impedance maps measured during experiments with the expanding cement system.', 'The measurements were taken at 51 h (FIG.', '11A, just after the pressure drop), at 88 h (FIG.', '11B) and at 168 h (FIG.', '11C).', 'Just after the pressure drop, the impedance map was not entirely red, indicating that the cement/casing acoustic coupling was maintained at some locations.', 'With the passage of time, the average impedance increased significantly, indicating acoustic coupling improvements.'] |
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US11123769 | Adjustable rotating weight | Oct 18, 2017 | Robert A. Lunnemann | Schlumberger Technology Corporation | Search Report R. 62 issued in European Patent Application 17864353.2 dated May 28, 2020, 4 pages.; International Preliminary Report on Patentability for the equivalent International patent application PCT/US2017/057069 dated May 9, 2019.; International Search Report and Written Opinion for the equivalent International patent application PCT/US2017/057069 dated Feb. 1, 2018. | 3352418; November 1967; Swallow; 4940336; July 10, 1990; Dryga; 5134893; August 4, 1992; Hukki; 6401933; June 11, 2002; Cohen; 20090269525; October 29, 2009; Kawano et al. | 2008/003156; January 2008; WO | ['This disclosure is drawn systems, devices, apparatus, and/or methods related to the separation of a mixture of solids according to size and the separation of solids from liquid.', 'Specifically, this disclosure is drawn to an adjustable weight set for use on vibratory separators.', 'In some examples, the adjustable weight set may include a base plate rotatable about an axis and extending radially outward from the axis; a plurality of slots extending through the base plate and being disposed between a radially outward periphery of the base plate and the axis; a plurality of weights coupled to each other about the base plate; and a weight locking tab that partially surrounds the base plate that may include one or more hooks extending through a portion of a slot.'] | ['Description\n\n\n\n\n\n\nThe present document is based on and claims priority to U.S. Provisional Application Ser.', 'No. 62/414,337, filed Oct. 28, 2016, which is incorporated herein by reference in its entirety.', 'BACKGROUND\n \nVibratory separators, which may be used to separate solids of a first size from solids of a second size or to separate solids from liquids, are used in many industries.', 'For example, vibratory separators may be used in agriculture, biofuel, ceramics, chemical production, food and beverage production, mining, pharmaceuticals production, plastic separation and processing, powder coating, paper production and processing, recycling, shot peening, and wastewater separation industries.', 'Vibratory separators may separate a feed stream into one or more discharge streams, each discharge stream having a different particle size range.', 'Often, vibratory separators have adjustable, three-dimensional vibration profiles.', 'Vibratory separators often include a vertically mounted motor located below a separator stack comprising one or more frames and screens.', 'The motor may include unbalanced, rotating weight sets disposed on the top and bottom of the motor.', 'The weight set(s) may include a manual force adjustment mechanism and angle adjustment mechanism to adjust one weight or weight set relative to another weight or weight set.', 'These adjustments enable adjustment of the three-dimensional vibration profiles of the vibratory separators.', 'The location of the motor often makes adjustment of the forces and angles of the weight set(s) difficult.', 'Adjustment may require stopping the machine, removing guards from the machine, and an operator to reach into a dark space to adjust the unbalanced weights.', 'This practical difficulty may make adjustment of the weights physically difficult and adjustment of the three-dimensional vibration profile imprecise.', 'For example, a conventional weight set may include a circular base plate and an axis of rotation near the center of the base plate.', 'A plurality of weights, for example, two weights, may extend radially outward from the axis of rotation.', 'The weights may be larger or thicker near a radially outward end.', 'The weights may be adjustable to move independently of each other.', 'The circular base plate may have a plurality of slots disposed 360 degrees around the base plate, and the weights may have notches sized and shaped to fit into the slots to maintain the position of the weight with respect to the base plate.', 'The slots disposed around the base plate may be labeled and may be equally spaced from each other.', 'In operation, the weight set rotates.', 'When two weights are disposed on opposite ends of the base plate, the weight set becomes balanced, the forces of the weights cancel, and a net force of zero is imparted into the vibratory separator.', 'As one or both weights are adjusted to move closer together, the weight set becomes unbalanced, and the net force imparted into the vibratory separator increases.', 'The weight set described in the paragraph immediately above suffers from a number of drawbacks.', 'First, adjustment remains difficult, as an operator may still need to orient himself into an awkward or uncomfortable position to reach the weight set.', 'The operator may need to maintain visual contact to identify the desired weight position all while maintaining haptic contact to manipulate the weight(s) to make the adjustment.', 'These difficulties may result in longer vibratory separator down times, operator frustration, and/or operator injury.', 'Furthermore, even if the slots are equally spaced about the circular base plate, for example, one slot every five degrees, the change in force as a weight is adjusted relative to the other is non-linear slot to slot.', 'For example, if two weights are directly opposing each other in an initial position, an adjustment of one slot may yield a larger force change than a subsequent adjustment of one slot in the same direction.', 'This non-linear force adjustment makes adjusting the weight set unpredictable, increasing the risk of dangerous vibrations to the vibratory separator and more down time if additional adjustments are needed.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThe foregoing and other features of the present disclosure will become more fully apparent from the following description and appended claims, taken in conjunction with the accompanying drawings.', 'Understanding that these drawings depict several examples in accordance with the disclosure and are, therefore, not to be considered limiting of its scope, the disclosure is described with additional specificity and detail below through the use of the accompanying drawings.', 'In the drawings:\n \nFIG.', '1\n depicts an isometric view of a portion of a vibratory separator having an exemplary adjustable weight set in accordance with the present disclosure;\n \nFIG.', '2\n depicts a side view of a portion of a vibratory separator having an exemplary adjustable weight set in accordance with the present disclosure; and\n \nFIG.', '3\n depicts a perspective view of a motor for use in a vibratory separator with an exemplary adjustable weight set in accordance with the present disclosure attached thereto.', 'DETAILED DESCRIPTION', 'In the following detailed description, reference is made to the accompanying drawings, which form a part hereof.', 'In the drawings, similar symbols identify similar components, unless context dictates otherwise.', 'The illustrative examples described in the detailed description and drawings are not meant to be limiting and are for explanatory purposes.', 'Other examples may be utilized, and other changes may be made, without departing from the spirit or scope of the subject matter presented herein.', 'It will be readily understood that the aspects of the present disclosure, as generally described herein and illustrated in the drawings, may be arranged, substituted, combined, and designed in a wide variety of different configurations, each of which are explicitly contemplated and made part of this disclosure.', 'This disclosure is generally drawn to systems, devices, apparatus, and/or methods related to the separation of a mixture of solids according to size and the separation of solids from liquid.', 'Specifically, this disclosure is drawn to an adjustable weight set for use on vibratory separators.', 'FIG.', '1\n depicts an isometric view of a portion of a vibratory separator \n100\n having an exemplary adjustable weight set coupled to a motor \n107\n in accordance with the present disclosure.', 'In this example, the adjustable weight set may include a base plate \n101\n, which may be rotatable about an axis of rotation \n106\n.', 'Base plate \n101\n may include a top surface \n108\n, a first side \n109\n, a second side \n110\n, and a bottom surface (not visible) opposite the top surface \n108\n.', 'Generally, first side \n109\n and second side \n110\n may refer to the opposing sides of the base plate \n101\n that extend radially outward from the axis of rotation \n106\n.', 'The base plate \n101\n may include a plurality of slots \n105\n extending through the top surface \n108\n and the bottom surface of the base plate \n101\n.', 'In an embodiment, slots \n105\n may be arranged as lateral pairs of slots \n105\n (as is the case of the example embodiment of \nFIG.', '1\n).', 'Slots \n105\n may be equally spaced from each other.', 'In an embodiment where slots \n105\n are arranged as lateral pairs, each pair of slots \n105\n may be equally spaced from each other pair.', 'Slots \n105\n may be arranged linearly between the axis of rotation \n106\n and a radially outward periphery \n111\n of base plate \n101\n.', 'An adjustable weight set according to the present disclosure may include weights \n102\n(\na\n), \n102\n(\nb\n).', 'Weights \n102\n(\na\n), \n102\n(\nb\n) may be coupled to each other by a coupling mechanism \n112\n.', 'In an embodiment, coupling mechanism \n112\n may be bolts, but other coupling mechanisms will be apparent to those of skill in the art.', 'A first weight \n102\n(\na\n) may be disposed above base plate \n101\n, and a second weight \n102\n(\nb\n) may be disposed below base plate \n101\n.', 'When weights \n102\n(\na\n), \n102\n(\nb\n) are coupled together, one or both weights may contact top surface \n108\n and/or bottom surface of base plate \n101\n.', 'When weights \n102\n(\na\n), \n102\n(\nb\n) are coupled together, they may be able to slide along a length of base plate \n101\n.', 'Weights \n102\n(\na\n) and/or \n102\n(\nb\n) may include one or more flanges \n104\n.', 'An adjustable weight set according to the present disclosure may further include a weight locking tab \n103\n, which is discussed in more detail below.', 'In embodiments where they are included, one or more flanges \n104\n of weights \n102\n(\na\n) and/or \n102\n(\nb\n) may be positioned radially outward of weight locking tab \n103\n.', 'FIG.', '2\n depicts a side view of a portion of a vibratory separator \n200\n having an exemplary adjustable weight set \n209\n in accordance with the present disclosure.', 'A vibratory separator may include a vibratory motor that includes a vertically disposed motor \n207\n, upper weight set \n209\n, and lower weight set \n208\n.', 'Upper weight set \n209\n and/or lower weight set \n208\n may be adjustable.', 'Upper weight set \n209\n and lower weight set \n208\n may rotate about axis of rotation \n206\n.', 'When upper weight set \n209\n and lower weight set \n208\n are unbalanced, they may induce vibratory force into a vibratory separator.', 'In an embodiment, upper weight set \n209\n may induce vibratory force causing a frame and screen section to move horizontally, while a lower weight set may induce vibratory force causing a frame and screen section to move vertically.', 'The force induced by a given weight set may be proportional to the amplitude of motion caused by the weight set.', 'Adjustment of the upper and lower weight sets with respect to one another may cause changes in the phase angle of the vibratory motion.', 'Still with reference to \nFIG.', '2\n, an upper weight set \n209\n may be an adjustable weight set in accordance with an embodiment of the present disclosure.', 'Adjustable weight set may include base plate \n201\n, weights \n202\n(\na\n) and \n202\n(\nb\n), and weight locking tab \n203\n.', 'Weights \n202\n(\na\n), \n202\n(\nb\n) may be coupled together by coupling mechanism \n212\n.', 'Base plate \n201\n may extend radially outward from axis of rotation \n206\n to radially outward periphery \n211\n.\n \nFIG.', '3\n depicts a perspective view of a motor coupled to an upper weight set \n300\n for use in a vibratory separator in accordance with an embodiment of the present disclosure.', 'Shown in \nFIG.', '3\n is a motor \n307\n having an adjustable upper weight set coupled thereto.', 'The weight set may include a base plate \n301\n, which may be rotatable with respect to axis of rotation \n306\n.', 'From the perspective of \nFIG.', '3\n, a top surface \n308\n and a second side \n310\n of the base plate \n301\n are visible.', 'Base plate \n301\n may extend radially outward from axis of rotation \n306\n to a radially outward periphery \n311\n.', 'Base plate \n301\n may include a plurality of slots \n305\n disposed thereon.', 'In an embodiment, slots \n305\n may be arranged as lateral pairs of slots \n305\n (as is the case of the example embodiment of \nFIG.', '3\n).', 'Slots \n305\n may be equally spaced from each other.', 'In an embodiment where slots \n305\n are arranged as lateral pairs, each pair of slots \n305\n may be equally spaced from each other pair.', 'Slots \n305\n may be arranged linearly between the axis of rotation \n306\n and a radially outward periphery \n311\n of base plate \n301\n.', 'An adjustable weight set according to the present disclosure may include weights \n302\n(\na\n), \n302\n(\nb\n).', 'Weights \n302\n(\na\n), \n302\n(\nb\n) may be coupled to each other by a coupling mechanism \n312\n.', 'In an embodiment, coupling mechanism \n312\n may be bolts, but other coupling mechanisms will be apparent to those of skill in the art.', 'A first weight \n302\n(\na\n) may be disposed above base plate \n301\n, and a second weight \n302\n(\nb\n) may be disposed below base plate \n301\n.', 'When weights \n302\n(\na\n), \n302\n(\nb\n) are coupled together, one or both weights may contact top surface \n308\n and/or bottom surface of base plate \n301\n.', 'When weights \n302\n(\na\n), \n302\n(\nb\n) are coupled together, they may be able to slide along a length of base plate \n301\n.', 'Weights \n302\n(\na\n) and/or \n302\n(\nb\n) may include one or more flanges \n304\n.', 'An adjustable weight set according to the present disclosure may further include a weight locking tab \n303\n.', 'In embodiments where they are included, one or more flanges \n304\n of weights \n302\n(\na\n) and/or \n302\n(\nb\n) may be positioned radially outward of weight locking tab \n303\n.', 'An embodiment of weight locking tab \n303\n is shown in more detail in \nFIG.', '3\n.', 'Weight locking tab \n303\n may include a top portion \n321\n, a first side portion \n322\n, a second side portion \n323\n, a first flange \n324\n, and a second flange \n325\n.', 'In an embodiment, top portion \n321\n, first side portion \n322\n, second side portion \n323\n, first flange \n324\n, and second flange \n325\n may be integrally formed.', 'Weight locking tab \n303\n may further include one or more hooks \n320\n.', 'In an embodiment, hooks \n320\n may be integrally formed with the rest of weight locking tab \n303\n.', 'In an alternate embodiment, hooks \n320\n may be coupled to top portion \n321\n by a coupling mechanism or by a process such as welding.', 'Herein, a hook \n320\n that is coupled to top portion \n321\n may include a hook being integrally formed with weight locking tab \n303\n or a portion thereof.', 'Top portion \n321\n of weight locking tab \n303\n may extend across top surface \n308\n of base plate \n301\n.', 'First side portion \n322\n may be coupled to (or be integrally formed with) top portion \n321\n and may extend from top surface \n308\n of base plate \n301\n past the bottom surface of the base plate \n301\n along a first side of base plate \n301\n.', 'Second side portion \n323\n may be coupled to (or be integrally formed with) top portion \n321\n and may extend from top surface \n308\n of base plate \n301\n past the bottom surface of the base plate \n301\n along second side \n310\n of base plate \n301\n.', 'First flange \n324\n may be coupled to (or be integrally formed with) first side portion \n322\n and may extend across at least a portion of the bottom surface of base plate \n301\n.', 'Second flange \n325\n may be coupled to (or be integrally formed with) second side portion \n323\n and may extend across at least a portion of the bottom surface of base plate \n301\n.', 'Herein, first flange \n324\n and second flange \n325\n may be said to extend across at least a portion of the bottom surface of base plate \n301\n, but this does not necessarily require first flange \n324\n and second flange \n325\n to be touching the bottom surface of base plate \n301\n.', 'Rather, since, first side portion \n322\n and second side portion \n323\n may extend past the bottom surface of base plate \n301\n, first flange \n324\n and second flange \n325\n may exist in a plane parallel to the plane defined by the bottom surface of base plate \n301\n.', 'Hooks \n320\n of weight locking tab \n303\n may extend in the same direction as first side portion \n322\n and second side portion \n323\n but may be smaller.', 'Hooks \n320\n may be sized and shaped to extend at least partially through slots \n305\n.', 'In the embodiment of \nFIG.', '3\n, a pair of hooks \n320\n is provided on weight locking tab \n303\n, corresponding to a pair of slots \n305\n on base plate \n301\n.', 'Hooks \n320\n may be sized such that hooks \n320\n extend through slots \n305\n when the underside of first portion \n321\n is resting on top surface \n308\n of base plate \n301\n.', 'First side portion \n322\n and second side portion \n323\n may be sized such that, when an operator lifts up on weight locking tab \n303\n to bring first flange \n324\n and second flange \n325\n into contact with the bottom surface of base plate \n301\n, hooks \n320\n do not extend through slots \n305\n.', 'This may allow an operator to move weight locking tab \n303\n along base plate \n301\n to allow hooks \n320\n to extend through a different pair of slots \n305\n.', 'In operation, the rotation of motor \n307\n may cause the adjustable weight set to rotate.', 'During rotation, weights \n302\n(\na\n), \n302\n(\nb\n) experience centrifugal force, which may cause weights \n302\n(\na\n), \n302\n(\nb\n) to move radially outward.', 'When hooks \n320\n of weight locking tab \n303\n extend through a pair of slots \n305\n, weight locking tab \n303\n establishes a radially outward boundary, preventing further movement of weights \n302\n(\na\n), \n302\n(\nb\n).', 'The centrifugal force may maintain weights \n302\n(\na\n), \n302\n(\nb\n) in a biasing relationship against weight locking tab \n303\n during operation.', 'Hooks \n320\n may include flanges \n326\n to prevent weight locking tab \n303\n from rising upward during operation.', 'When weights \n302\n(\na\n), \n302\n(\nb\n) are arranged to move radially inward or outward along base plate \n302\n, the force imparted by the unbalanced weight set may change linearly when adjusted.', 'An adjustable weight set may impart more vibratory force when weights \n302\n(\na\n), \n302\n(\nb\n) are disposed radially outward compared to when weights \n302\n(\na\n), \n302\n(\nb\n) are disposed radially inward.', 'Because the amount of force may change linearly when adjustments are made, when slots \n305\n are equally spaced, each change in slot may change the force by an equal amount.', 'This may allow for an greater predictability when an operator makes force adjustments to the weight set.', 'Further, an adjustable weight set according to the present disclosure may allow portions of weights \n302\n(\na\n), \n302\n(\nb\n) to move through the center of rotation.', 'This may allow centrifugal forces to begin to cancel each outer and may allow for a greater range of force output.', 'For example, in \nFIG.', '3\n, weights \n302\n(\na\n), \n302\n(\nb\n) are geometrically shaped substantially in a U-shape, which may allow portions of weights \n302\n(\na\n), \n302\n(\nb\n) to move through the center of rotation as described above when weight locking tab is adjusted radially inward.', 'In such a configuration, the arms of the “U” shape may extend back toward the axis of rotation.', 'Slots \n305\n may be spaced linearly and may be equally spaced from each other, for example as shown in \nFIG.', '3\n.', 'As described above, such an arrangement of slots may allow for more predictable force adjustments.', 'Furthermore, the weight locking tab \n303\n may allow an operator to more easily make force adjustments.', 'While various aspects and embodiments have been disclosed herein, other aspects and embodiments will be apparent to those skilled in the art.', 'The various aspects and embodiments disclosed herein are for purposes of illustration and are not intended to be limiting.'] | ['1.', 'An adjustable weight set for a vibratory motor, comprising:\na base plate rotatable about an axis and extending radially outward from the axis, comprising: a top surface; a first side; a second side; and a bottom surface;\nwherein the top surface and the bottom surface of the base plate are in a plane that is substantially perpendicular to the axis;\na plurality of slots extending through the top surface and the bottom surface of the base plate, the slots being disposed between a radially outward periphery of the base plate and the axis;\na plurality of weights coupled to each other, wherein at least a first weight is disposed above the base plate, and wherein at least a second weight is disposed below the base plate; and\na weight locking tab that partially surrounds the base plate comprising: a top portion extending across the top surface of the base plate; and a hook coupled to the top portion and extending through at least a portion of a slot;\nwherein the weights include flanges positioned radially outward of and contacting at least a portion of the weight locking tab.', '2.', 'The adjustable weight set of claim 1, wherein the weight locking tab further comprises:\na first side portion coupled to the top portion and extending from the top surface of the base plate past the bottom surface of the base plate along the first side of the base plate;\na second side portion coupled to the top portion and extending from the top surface of the base plate past the bottom surface of the base plate along the second side of the base plate;\na first flange coupled to the first side and extending across at least a portion of the bottom surface of the base plate; and\na second flange coupled to the second side and extending across at least a portion of the bottom surface of the base plate;\nwherein the hook is smaller than the first side portion and the second side portion and is sized such that, when the weight locking tab is lifted, the hook rises out of the slot.', '3.', 'The adjustable weight set of claim 1, wherein the slots are arranged linearly and are equally spaced from each other.', '4.', 'The adjustable weight set of claim 1, further comprising:\na plurality of lateral pairs of slots extending through the top surface and the bottom surface of the base plate;\nwherein the lateral pairs of slots are disposed between a radially outward periphery of the base plate and the axis;\nwherein the lateral pairs of slots are arranged linearly and are equally spaced from each other; and\nwherein the weight locking tab includes a pair of hooks coupled to the top portion, and each hook of the pair of hooks extends through at least a portion of a slot.', '5.', 'The adjustable weight set of claim 1, wherein the weights are U-shaped and have arms, and wherein the arms of the U-shape extend toward the axis.', '6.', 'The adjustable weight set of claim 1, further comprising:\na plurality of lateral pairs of slots extending through the top surface and the bottom surface of the base plate;\nwherein the lateral pairs of slots are disposed between a radially outward periphery of the base plate and the axis;\nwherein the lateral pairs of slots are arranged linearly and are equally spaced from each other;\nwherein the weight locking tab further comprises: a first side portion coupled to the top portion and extending from the top surface of the base plate past the bottom surface of the base plate along the first side of the base plate; a second side portion coupled to the top portion and extending from the top surface of the base plate past the bottom surface of the base plate along the second side of the base plate; a first flange coupled to the first side and extending across at least a portion of the bottom surface of the base plate; and a second flange coupled to the second side and extending across at least a portion of the bottom surface of the base plate;\nwherein the weight locking tab includes a pair of hooks coupled to the top portion, and each hook of the pair of hooks extends through at least a portion of a slot;\nwherein the hooks are smaller than the first side portion and the second side portion and are sized such that, when the weight locking tab is lifted, the hooks rise out of the slots; and\nwherein the weights are U-shaped and have arms, and wherein the arms of the U-shape extend toward the axis.', '7.', 'A vibratory motor for use in a vibratory separator, comprising:\na motor;\na lower weight set operatively coupled to a lower end of the motor; and\nan upper weight set operatively coupled to an upper end of the motor, the upper weight set comprising: a base plate rotatable about an axis and extending radially outward from the axis; a plurality of slots extending through the base plate between the axis and a periphery of the base plate; a plurality of weights coupled to each other about the base plate; and a weight locking tab that partially surrounds the base plate comprising one or more hooks, wherein each hook extends through at least a portion of a slot.', '8.', 'The vibratory motor of claim 7, wherein the at least one hook is sized such that, when the weight locking tab is lifted, the hook completely rises out of the slot.', '9.', 'The vibratory motor of claim 7, wherein the slots are equally spaced from each other and are disposed linearly between the axis and the periphery of the base plate.', '10.', 'The vibratory motor of claim 7,\nwherein the slots are arranged as lateral pairs of slots disposed linearly between the axis and the periphery of the base plate;\nwherein the lateral pairs of slots are equally spaced from each other; and\nwherein the weight locking tab includes a pair of hooks, each hook being sized and spaced to extend through at least a portion of a slot.', '11.', 'The vibratory motor of claim 7, wherein the weights are U-shaped and have arms, and wherein the arms of the U-shape extend toward the axis.', '12.', 'The vibratory motor of claim 7,\nwherein the slots are arranged as lateral pairs of slots disposed linearly between the axis and the periphery of the base plate;\nwherein the lateral pairs of slots are equally spaced from each other;\nwherein the weight locking tab includes a pair of hooks, each hook being sized and spaced to extend through at least a portion of a slot;\nwherein the hooks are sized such that, when the weight locking tab is lifted, the hooks completely rise out of the slots; and\nwherein the weights are U-shaped and have arms, and wherein the arms of the U-shape extend toward the axis.', '13.', 'A vibratory separator, comprising:\none or more separator frames;\none or more separator screens positioned between the one or more separator frames; and\na vibratory motor operatively coupled to the one or more separator frames and the one or more separator screens, the vibratory motor comprising: a motor; a lower weight set operatively coupled to a lower end of the motor; and an upper weight set operatively coupled to an upper end of the motor, the upper weight set comprising: a base plate rotatable about an axis and extending radially outward from the axis; a plurality of slots extending through the base plate between the axis and a periphery of the base plate; a plurality of weights coupled to each other about the base plate; and a weight locking tab that partially surrounds the base plate comprising one or more hooks, wherein each hook extends through at least a portion of a slot.', '14.', 'The vibratory separator of claim 13, wherein the at least one hook is sized such that, when the weight locking tab is lifted, the hook completely rises out of the slot.', '15.', 'The vibratory separator of claim 13, wherein the slots are arranged linearly and are equally spaced from each other.', '16.', 'The vibratory separator of claim 13,\nwherein the slots are arranged as lateral pairs of slots disposed linearly between the axis and the periphery of the base plate;\nwherein the lateral pairs of slots are equally spaced from each other;\nwherein the weight locking tab includes a pair of hooks, each hook being sized and spaced to extend through at least a portion of a slot; and\nwherein the hooks are sized such that, when the weight locking tab is lifted, the hooks completely rise out of the slots.', '17.', 'The vibratory separator of claim 13, wherein the weights are U-shaped and have arms, and wherein the arms of the U-shape extend toward the axis.', '18.', 'The vibratory separator of claim 13, wherein the one or more separator frames are circular and the one or more separator screens are circular.\n\n\n\n\n\n\n19.', 'The vibratory separator of claim 13, further comprising:\na housing surrounding the one or more separator frames and the one or more separator screens, wherein the vibratory motor is coupled to the housing.'] | ['FIG.', '1 depicts an isometric view of a portion of a vibratory separator having an exemplary adjustable weight set in accordance with the present disclosure;; FIG.', '2 depicts a side view of a portion of a vibratory separator having an exemplary adjustable weight set in accordance with the present disclosure; and; FIG.', '3 depicts a perspective view of a motor for use in a vibratory separator with an exemplary adjustable weight set in accordance with the present disclosure attached thereto.; FIG.', '1 depicts an isometric view of a portion of a vibratory separator 100 having an exemplary adjustable weight set coupled to a motor 107 in accordance with the present disclosure.', 'In this example, the adjustable weight set may include a base plate 101, which may be rotatable about an axis of rotation 106.', 'Base plate 101 may include a top surface 108, a first side 109, a second side 110, and a bottom surface (not visible) opposite the top surface 108.', 'Generally, first side 109 and second side 110 may refer to the opposing sides of the base plate 101 that extend radially outward from the axis of rotation 106.; FIG.', '2 depicts a side view of a portion of a vibratory separator 200 having an exemplary adjustable weight set 209 in accordance with the present disclosure.', 'A vibratory separator may include a vibratory motor that includes a vertically disposed motor 207, upper weight set 209, and lower weight set 208.', 'Upper weight set 209 and/or lower weight set 208 may be adjustable.', 'Upper weight set 209 and lower weight set 208 may rotate about axis of rotation 206.', 'When upper weight set 209 and lower weight set 208 are unbalanced, they may induce vibratory force into a vibratory separator.', 'In an embodiment, upper weight set 209 may induce vibratory force causing a frame and screen section to move horizontally, while a lower weight set may induce vibratory force causing a frame and screen section to move vertically.', 'The force induced by a given weight set may be proportional to the amplitude of motion caused by the weight set.', 'Adjustment of the upper and lower weight sets with respect to one another may cause changes in the phase angle of the vibratory motion.', '; FIG.', '3 depicts a perspective view of a motor coupled to an upper weight set 300 for use in a vibratory separator in accordance with an embodiment of the present disclosure.', 'Shown in FIG.', '3 is a motor 307 having an adjustable upper weight set coupled thereto.', 'The weight set may include a base plate 301, which may be rotatable with respect to axis of rotation 306.', 'From the perspective of FIG.', '3, a top surface 308 and a second side 310 of the base plate 301 are visible.', 'Base plate 301 may extend radially outward from axis of rotation 306 to a radially outward periphery 311.', 'Base plate 301 may include a plurality of slots 305 disposed thereon.', 'In an embodiment, slots 305 may be arranged as lateral pairs of slots 305 (as is the case of the example embodiment of FIG.', '3).', 'Slots 305 may be equally spaced from each other.', 'In an embodiment where slots 305 are arranged as lateral pairs, each pair of slots 305 may be equally spaced from each other pair.', 'Slots 305 may be arranged linearly between the axis of rotation 306 and a radially outward periphery 311 of base plate 301.'] |
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US11126694 | Automatic calibration for modeling a field | Jun 13, 2016 | Claudio Schirrmann, Adrian Kleine, Christian Vogt | Schlumberger Technology Corporation | Lin Y. Hu, “Gradual Deformation and Iterative Calibration of Gaussian-Related Stochastic Models”, 2000, International Association for Mathematical Geology, pp. 87-108 (Year: 2000).; Mediero, et al., “Probabilistic calibration of a distributed hydrological model for flood forecasting,” Hydrological Sciences Journal, vol. 56, No. 7, Oct. 1, 2011, pp. 1129-1149.; Extended Search Report for the counterpart European patent application 16905630.6 dated Feb. 7, 2020.; Hantschel, et al., “Fundamentals of Basin and Petroleum Systems Modeling,” Springer, Apr. 10, 2009.; International Search Report and Written Opinion for the equivalent International patent application PCT/US2016/037147 dated Mar. 13, 2017.; International Preliminary Report on Patentability for the equivalent International patent application PCT/US2016/037147 dated Dec. 27, 2018. | 6813565; November 2, 2004; Hu; 20010056339; December 27, 2001; Robinson et al.; 20050010383; January 13, 2005; Le Ravalec-Dupin; 20050172699; August 11, 2005; Hu; 20060149520; July 6, 2006; Le Ravalec-Dupin; 20080077371; March 27, 2008; Yeten; 20090070086; March 12, 2009; Le Ravalec et al.; 20090166033; July 2, 2009; Brouwer et al.; 20090182541; July 16, 2009; Crick et al.; 20100326669; December 30, 2010; Zhu et al.; 20110144965; June 16, 2011; Rossi et al.; 20130132052; May 23, 2013; Hogg et al.; 20140039859; February 6, 2014; Maucec | 2014/160741; October 2014; WO | ['Automatic calibration for modeling a field includes performing model calibration iterations based on measurements of the field.', 'Each model iteration includes obtaining, during the field operation, a current measurement of the field, generating likelihood values corresponding to model realizations of the field, where each likelihood value is generated by at least comparing the current measurement of the field to a modeling result of a corresponding model realization, selecting, based on the likelihood values, at least one selected model realization from the model realizations, generating, by at least adjusting a first input value of the at least one selected model realization, an adjusted model realization of the field based on the at least one selected model realization, and adding the adjusted model realization to the model realizations.', 'Automatic calibration for modeling a field further includes generating a calibrated modeling result of the field based on the adjusted model realization.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nParameters (e.g., rock permeability, compaction laws, basal heat flows, etc.) used in modeling and simulation of a field are highly uncertain, especially when geological times are considered.', 'The standard procedure is a manual calibration of selected uncertainties to specific measurements.', 'For instance, vitrinite reflectance data may be used to calibrate basal heat flows and thermal conductivities, and porosity and pore pressures may be used to calibrate rock permeability and compaction laws.', 'SUMMARY\n \nIn general, in one aspect, an embodiment of automatic calibration for modeling a field includes a method for performing a field operation of a field.', 'The method includes performing model calibration iterations based on measurements of the field.', 'Each model calibration iteration includes obtaining, during the field operation, a current measurement of the field, generating likelihood values corresponding to model realizations of the field, where each likelihood value is generated by at least comparing the current measurement of the field to a modeling result of a corresponding model realization, selecting, based on the likelihood values, at least one selected model realization from the model realizations, generating, by at least adjusting a first input value of the at least one selected model realization, an adjusted model realization of the field based on the at least one selected model realization, and adding the adjusted model realization to the model realizations.', 'The method further includes generating a calibrated modeling result of the field based on the adjusted model realization from at least one of the model calibration iterations.', 'Other aspects will be apparent from the following description and the appended claims.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nThe appended drawings illustrate several embodiments of automatic calibration for modeling a field and are not to be considered limiting of its scope, for automatic calibration for modeling a field may admit to other equally effective embodiments.', 'FIG.', '1.1\n is a schematic view, partially in cross-section, of a field in which one or more embodiments of automatic calibration for modeling a field may be implemented.\n \nFIG.', '1.2\n shows a schematic diagram of a system in accordance with one or more embodiments.\n \nFIG.', '2\n shows a flowchart in accordance with one or more embodiments.\n \nFIGS.', '3.1, 3.2, 3.3, 3.4, 3.5, and 3.6\n show an example in accordance with one or more embodiments.', 'FIGS.', '4.1 and 4.2\n show systems in accordance with one or more embodiments.', 'DETAILED DESCRIPTION\n \nSpecific embodiments will now be described in detail with reference to the accompanying figures.', 'Like elements in the various figures are denoted by like reference numerals for consistency.', 'In the following detailed description of embodiments, numerous specific details are set forth in order to provide a more thorough understanding.', 'However, it will be apparent to one of ordinary skill in the art that one or more embodiments may be practiced without these specific details.', 'In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.', 'In general, embodiments provide a method and system for performing a field operation by at least generating a calibrated modeling result of the field.', 'In one or more embodiments, the calibrated modeling result is generated based on an adjusted model realization from at least one of a number of model calibration iterations.', 'The model calibration iterations are performed based on a number of measurements of the field.', 'In particular, each model calibration iteration includes obtaining, during the field operation, a current measurement of the field.', 'Based on the current measurement, a number of likelihood values corresponding to a number of model realizations are generated.', 'Specifically, each likelihood value is generated by at least comparing the current measurement of the field to a modeling result of a corresponding model realization.', 'Based on the number of likelihood values, at least one model realization is selected from the number of model realizations.', 'By at least adjusting an input value of the at least one selected model realization, an adjusted model realization of the field is generated based on the at least one selected model realization.', 'Accordingly, the adjusted model realization is added to the number of model realizations for the subsequent model calibration iteration.', 'FIG.', '1.1\n depicts a schematic view, partially in cross section, of a field (\n100\n) in which one or more embodiments of automatic calibration for modeling a field may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in \nFIG.', '1.1\n may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of automatic calibration for modeling a field should not be considered limited to the specific arrangements of modules shown in \nFIG.', '1.1\n.', 'As shown in \nFIG.', '1.1\n, the field (\n100\n) includes the subterranean formation (\n104\n), data acquisition tools (\n102\n-\n1\n), (\n102\n-\n2\n), (\n102\n-\n3\n), and (\n102\n-\n4\n), wellsite system A (\n114\n-\n1\n), wellsite system B (\n114\n-\n2\n), wellsite system C (\n114\n-\n3\n), a surface unit (\n112\n), and an exploration and production (E&P) computer system (\n118\n).', 'The subterranean formation (\n104\n) includes several geological structures, such as a sandstone layer (\n106\n-\n1\n), a limestone layer (\n106\n-\n2\n), a shale layer (\n106\n-\n3\n), a sand layer (\n106\n-\n4\n), and a fault line (\n107\n).', 'In particular, these geological structures form at least one reservoir containing fluids (e.g., hydrocarbon) as described below.', 'Petroleum (i.e., oil and gas) may be formed within a basin by chemical reactions of sedimentary organic matter material.', 'After generation, petroleum migrates within the basin via permeable pathways until the petroleum accumulates within porous and permeable reservoir rock formations, or the petroleum is dissipated by chemical or biochemical reactions, or leakage to the surface of the basin.', 'Within any particular basin, one or more “plays” for possible production of hydrocarbons may exist.', 'The United States Geological Survey defines a “play” as “a set of discovered or undiscovered oil and gas accumulations or prospects that exhibit nearly identical geological characteristics such as trapping style, type of reservoir and nature of the seal”.', 'A reservoir may include several different plays which differ from each other by the nature of the fluids within the pore spaces of the rock formations and/or the pressure thereof.', 'A “reservoir” is a rock formation with substantially uniform rock mineral properties and spatial distribution of permeability such that the rock formation has the capability to store fluids, and has the capability for fluids to be moved therethrough by application of suitable pressure variations.', 'Modeling is a technique to represent and simulate characteristics, operations, and other behaviors of at least a portion of a field (e.g., the field (\n100\n), subterranean formation (\n104\n), wellsite system A (\n114\n-\n1\n), etc.) using mathematical and physical rules.', 'The modeling result may include a value related to the characteristics, operations, and other behaviors of the field (\n100\n) that is derived using such mathematical and physical rules.', 'Basin modeling (or basin simulation) is a technique for modeling geological processes that may have occurred in sedimentary basins over geological times.', 'For example, basin modeling may simulate the deposition and erosion of sediments through geologic time, calculating the temperature, pressure and rock stress distribution.', 'Input parameters to the basin modeling include burial history, paleo-water-depth maps, SWITs (sediment water interface temperatures), HF maps, and several rock attributes (e.g., thermal conductivities, permeabilities, rock densities, radiogenic sources).', 'During the basin modeling, temperatures and pressures are determined by solving a differential equation e.g., by using a finite element solver.', 'In one or more embodiments, basin modeling may be used without considering any hydrocarbon fluids or reservoir.', 'In one or more embodiments, overpressure prediction may be performed with basin modeling to reveal basin-wide water flow connectivities, porosity distributions correlating with potential hydrocarbon storage capacity and fracturing, i.e., sealing strengths of potential hydrocarbon storage containers.', 'Further, basin modeling may also be used for evaluation of basin-wide temperature distributions, which is the main controlling parameter determining the velocity of chemical reactions for generation of hydrocarbons within source rocks.', 'Accordingly, the maturity defining the hydrocarbon bearing potential of source rocks may be modeled.', 'In one or more embodiments, the basin modeling includes petroleum system modeling that simulates the events leading to generation, migration and accumulation of hydrocarbons in reservoir rocks.', 'In such embodiments, inputs to basin modeling include the “charge potential” (e.g., source rock organic carbon content, source rock thickness, and source rock properties), and the trap (e.g., the reservoir geometry, reservoir and seal qualities) of a play.', 'In one or more embodiments, the basin modeling may also include modeling the thermal, pressure and hydrocarbon generation and migration history to make predictions of current hydrocarbon quality and spatial distribution within the basin.', 'In one or more embodiments, the basin modeling may also include a description of petroleum fluids (e.g., pressure, volume, and temperature (PVT), composition, etc.)', 'that is determined, at least in part, by the processes of generation and expulsion that govern the composition of the fluids, and the PVT behavior responsible for the distribution of components in each fluid phase during secondary migration and accumulation in a reservoir.', 'The charge history of an accumulation or an individual reservoir may be tracked in compositional form according to selected compound classes, for example, CO\n2\n, H\n2\nS, methane, C\n2-5\n, C\n6-15\n, C\n16+\n.', 'Thermodynamic models known as equations of state, e.g., SRK (Soave-Redlich-Kwong) and PR (Peng-Robinson), may be used to make phase property predictions such as gas-oil ratio (GOR), fluid density and/or fluid viscosity.', 'Post-accumulation alteration processes such as biodegradation, water washing, and oil-to-gas cracking may also be simulated.', 'Source rock tracking, the evolution of the composition through time, yields and compositions of the products generated and released may also be modeled.', 'Returning to the discussion of \nFIG.', '1.1\n, in one or more embodiments, data acquisition tools (\n102\n-\n1\n), (\n102\n-\n2\n), (\n102\n-\n3\n), and (\n102\n-\n4\n) are positioned at various locations along the field (\n100\n) for collecting data of the subterranean formation (\n104\n), referred to as survey operations.', 'In particular, the data acquisition tools are adapted to measure the subterranean formation (\n104\n) and detect the characteristics of the geological structures of the subterranean formation (\n104\n).', 'For example, data plots (\n108\n-\n1\n), (\n108\n-\n2\n), (\n108\n-\n3\n), and (\n108\n-\n4\n) are depicted along the field (\n100\n) to demonstrate the data generated by the data acquisition tools.', 'Specifically, the static data plot (\n108\n-\n1\n) is a seismic two-way response time.', 'Static data plot (\n108\n-\n2\n) is core sample data measured from a core sample of the subterranean formation (\n104\n).', 'Static data plot (\n108\n-\n3\n) is a logging trace, referred to as a well log.', 'Production decline curve or graph (\n108\n-\n4\n) is a dynamic data plot of the fluid flow rate over time.', 'Other data may also be collected, such as historical data, analyst user inputs, economic information, and/or other measurement data and other parameters of interest.', 'Further as shown in \nFIG.', '1.1\n, each of the wellsite system A (\n114\n-\n1\n), wellsite system B (\n114\n-\n2\n), and wellsite system C (\n114\n-\n3\n) is associated with a rig, a wellbore, and other wellsite equipment configured to perform wellbore operations, such as logging, drilling, fracturing, production, or other applicable operations.', 'For example, the wellsite system A (\n114\n-\n1\n) is associated with a rig (\n101\n), a wellbore (\n103\n), and drilling equipment to perform drilling operation.', 'Similarly, the wellsite system B (\n114\n-\n2\n) and wellsite system C (\n114\n-\n3\n) are associated with respective rigs, wellbores, other wellsite equipments, such as production equipment and logging equipment to perform production operations and logging operations, respectively.', 'Generally, survey operations and wellbore operations are referred to as field operations of the field (\n100\n).', 'In addition, data acquisition tools and wellsite equipments are referred to as field operation equipments.', 'The field operations are performed as directed by a surface unit (\n112\n).', 'For example, the field operation equipment may be controlled by a field operation control signal that is sent from the surface unit (\n112\n).', 'In one or more embodiments, the surface unit (\n112\n) is operatively coupled to the data acquisition tools (\n102\n-\n1\n), (\n102\n-\n2\n), (\n102\n-\n3\n), (\n102\n-\n4\n), and/or the wellsite systems.', 'In particular, the surface unit (\n112\n) is configured to send commands to the data acquisition tools (\n102\n-\n1\n), (\n102\n-\n2\n), (\n102\n-\n3\n), (\n102\n-\n4\n), and/or the wellsite systems and to receive data therefrom.', 'In one or more embodiments, the surface unit (\n112\n) may be located at the wellsite system A (\n114\n-\n1\n), wellsite system B (\n114\n-\n2\n), wellsite system C (\n114\n-\n3\n), and/or remote locations.', 'The surface unit (\n112\n) may be provided with computer facilities (e.g., an E&P computer system (\n118\n)) for receiving, storing, processing, and/or analyzing data from the data acquisition tools (\n102\n-\n1\n), (\n102\n-\n2\n), (\n102\n-\n3\n), (\n102\n-\n4\n), the wellsite system A (\n114\n-\n1\n), wellsite system B (\n114\n-\n2\n), wellsite system C (\n114\n-\n3\n), and/or other parts of the field (\n100\n).', 'The surface unit (\n112\n) may also be provided with or have functionally for actuating mechanisms at the field (\n100\n).', 'The surface unit (\n112\n) may then send command signals to the field (\n100\n) in response to data received, stored, processed, and/or analyzed, for example to control and/or optimize various field operations described above.', 'In one or more embodiments, the surface unit (\n112\n) is communicatively coupled to the E&P computer system (\n118\n).', 'In one or more embodiments, the data received by the surface unit (\n112\n) may be sent to the E&P computer system (\n118\n) for further analysis.', 'Generally, the E&P computer system (\n118\n) is configured to analyze, model, control, optimize, or perform management tasks of the aforementioned field operations based on the data provided from the surface unit (\n112\n).', 'In one or more embodiments, the E&P computer system (\n118\n) is provided with functionality for manipulating and analyzing the data, such as performing simulation, planning, and optimization of production operations of the wellsite system A (\n114\n-\n1\n), wellsite system B (\n114\n-\n2\n), and/or wellsite system C (\n114\n-\n3\n).', 'In one or more embodiments, the result generated by the E&P computer system (\n118\n) may be displayed for an analyst user to view the result in a two dimensional (2D) display, three dimensional (3D) display, or other suitable displays.', 'Although the surface unit (\n112\n) is shown as separate from the E&P computer system (\n118\n) in \nFIG.', '1.1\n, in other examples, the surface unit (\n112\n) and the E&P computer system (\n118\n) may also be combined.', 'Although \nFIG.', '1.1\n shows a field (\n100\n) on the land, the field (\n100\n) may be an offshore field.', 'In such a scenario, the subterranean formation may be in the sea floor.', 'Further, field data may be gathered from the field (\n100\n) that is an offshore field using a variety of offshore techniques for gathering field data.', 'FIG.', '1.2\n shows more details of the E&P computer system (\n118\n) in which one or more embodiments of automatic calibration for modeling a field may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in \nFIG.', '1.2\n may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of automatic calibration for modeling a field should not be considered limited to the specific arrangements of modules shown in \nFIG.', '1.2\n.', 'As shown in \nFIG.', '1.2\n, the E&P computer system (\n118\n) includes an E&P tool (\n230\n), a data repository (\n238\n) for storing input data, intermediate data, and resultant outputs of the E&P tool (\n230\n), and a field task engine (\n231\n) for performing various tasks of the field operation.', 'In one or more embodiments, the data repository (\n238\n) may include one or more disk drive storage devices, one or more semiconductor storage devices, other suitable computer data storage devices, or combinations thereof.', 'In one or more embodiments, content stored in the data repository (\n238\n) may be stored as a data file, a linked list, a data sequence, a database, a graphical representation, any other suitable data structure, or combinations thereof.', 'In one or more embodiments, the content stored in the data repository (\n238\n) includes the input value sets (\n233\n), probability density functions (PDFs) (\n234\n), model realizations (\n235\n), and calibrated modeling result (\n236\n).', 'In one or more embodiments, each of the input value sets (\n233\n) includes a set of input values corresponding to input parameters for modeling the field (\n100\n).', 'In one or more embodiments, the input parameters include one or more of a boundary condition (e.g., pressure, temperature, saturation, etc.), rock parameter (e.g., porosity, permeability, maturity, thermal conductivity, etc.), pore fluid data (e.g., fluid density, fluid kinetics, etc.), layer and fault geometry (e.g., layer thickness, etc.), and fault parameter (e.g., capillary pressure, etc.) associated with the field (\n100\n).', 'In one or more embodiments, the input values are assigned in an input value set based on a user input and/or field measurements to model the field (\n100\n).', 'For example, at least a portion of the assigned values are based on measurements obtained from the data acquisition tools depicted in \nFIG.', '1.1\n above.', 'In one or more embodiments, multiple sets of input values (e.g., input value set A (\n233\n-\n1\n), input value set B (\n233\n-\n2\n), input value set C (\n233\n-\n3\n), etc.) are used to generate multiple model realizations (e.g., model realizations (\n235\n)) of the field (\n100\n).', 'A model realization is a model of the field.', 'In other words, the model realization is an estimate of the attributes of the field.', 'Multiple model realizations may exist, whereby each model realization is a different estimate.', 'In one or more embodiments, at least a portion of the input parameters may be assigned different values among the multiple sets of input values (e.g., input value set A (\n233\n-\n1\n), input value set B (\n233\n-\n2\n), input value set C (\n233\n-\n3\n), etc.) to generate different model realizations.', 'For example, the model realization A (\n235\n-\n1\n) and model realization B (\n235\n-\n2\n) may be generated based on the input value set A (\n233\n-\n1\n) and input value set B (\n233\n-\n2\n), respectively, that have different assigned values for at least one input parameter.', 'In one or more embodiments, some of the input value sets (\n233\n) may be automatically adjusted during modeling of the field (\n100\n) to generate adjusted input value sets.', 'For example, the input value set A (\n233\n-\n1\n) may be automatically adjusted to generate the adjusted input value set A (\n233\n-\n4\n).', 'Similarly, the input value set B (\n233\n-\n2\n) may be automatically adjusted to generate the adjusted input value set B (\n233\n-\n5\n).', 'In one or more embodiments, each input parameter of the input value sets (\n233\n) is assigned one of the PDFs (\n234\n).', 'A PDF is a mathematical function that describes a probability for a variable to have any given value within a set of values.', 'For example, the PDF A (\n234\n-\n1\n) may represent a probability for a particular input parameter associated with the input value sets (\n233\n) to have a value, such as in the corresponding values assigned throughout the input value set A (\n233\n-\n1\n), input value set B (\n233\n-\n2\n), input value set C (\n233\n-\n3\n), adjusted input value set A (\n233\n-\n4\n), adjusted input value set B (\n233\n-\n5\n), etc.', 'In one or more embodiments, the probability is based on a level of uncertainty of the assigned value, for example as a result of equipment resolution and/or error limitation of the data acquisition tools depicted in \nFIG.', '1.1\n above.', 'In another example, the PDF B (\n234\n-\n2\n) may represent a probability for another input parameter associated with the input value sets (\n233\n) to take on various values assigned throughout the input value set A (\n233\n-\n1\n), input value set B (\n233\n-\n2\n), input value set C (\n233\n-\n3\n), adjusted input value set A (\n233\n-\n4\n), adjusted input value set B (\n233\n-\n5\n), etc.', 'A model realization (e.g., model realization A (\n235\n-\n1\n), model realization B (\n235\n-\n2\n), adjusted model realization A (\n235\n-\n3\n), adjusted model realization B (\n235\n-\n4\n), etc.) includes a three-dimensional (3D) volume (not shown) that represents a portion of the field (\n100\n).', 'For example, the 3D volume may represent a portion of the subterranean formation (\n104\n) depicted in \nFIG.', '1.1\n above.', 'In one or more embodiments, the 3D volume is associated with a grid having a large number (e.g., thousands, hundreds of thousand, millions, etc.) of grid points corresponding to locations in the subterranean formation (\n104\n).', 'In one or more embodiments, each model realization (e.g., model realization A (\n235\n-\n1\n), model realization B (\n235\n-\n2\n), adjusted model realization A (\n235\n-\n3\n), adjusted model realization B (\n235\n-\n4\n), etc.) further includes information assigned to each grid point that describes characteristics, operations, or other behaviors of a corresponding location in the field (\n100\n).', 'The information assigned to the grid points may include the input values (referred to as the modeling input data) in an input value set and/or a modeling result (referred to as the modeling output data) derived from the input value set.', 'In particular, the modeling output data is an output of the modeling engine (\n223\n) described below.', 'For example, the modeling result A (\n236\n-\n1\n) of the model realization A (\n235\n-\n1\n) may include derived porosity or pore pressure values that are assigned to the grid points and are derived based on the input data set A (\n233\n-\n1\n).', 'Similarly, the modeling result B (\n236\n-\n2\n) of the model realization B (\n235\n-\n2\n) may include derived porosity or pore pressure values that are assigned to the grid points and are derived based on the input data set B (\n233\n-\n2\n).', 'In addition, the modeling result C (\n236\n-\n3\n) of the adjusted model realization A (\n235\n-\n3\n) may include derived porosity or pore pressure values that are assigned to the grid points and are derived based on the adjusted input value set A (\n233\n-\n4\n).', 'In one or more embodiments, each model realization (e.g., model realization A (\n235\n-\n1\n), model realization B (\n235\n-\n2\n), adjusted model realization A (\n235\n-\n3\n), adjusted model realization B (\n235\n-\n4\n), etc.) also includes a likelihood value representing the likelihood of the modeling results (e.g., derived porosity or pore pressure values) matching actual measurements (e.g., measured porosity or pore pressure values).', 'For example, the likelihood value A (\n237\n-\n1\n), likelihood value B (\n237\n-\n2\n), and likelihood value C (\n237\n-\n3\n) may represent the likelihood of the modeling result A (\n236\n-\n1\n), modeling result B (\n236\n-\n2\n), and modeling result C (\n236\n-\n3\n), respectively, matching actual measurements.', 'In one or more embodiments, the likelihood values are statistical measures and are updated iteratively based on new measurements obtained over time or obtained from additional locations.', 'Calibration is a technique to adjust the likelihood values of the model realizations (\n235\n) (e.g., model realization A (\n235\n-\n1\n), model realization B (\n235\n-\n2\n), adjusted model realization A (\n235\n-\n3\n), adjusted model realization B (\n235\n-\n4\n), etc.) to improve how accurate the likelihood values are in representing the matching between the modeling results and the actual measurements.', 'In one or more embodiments, multiple iterations of the calibration are performed during the field operation to continuously improve the likelihood values of the model realizations (\n235\n).', 'In one or more embodiments, the model realization A (\n235\n-\n1\n) and model realization B (\n235\n-\n2\n) are part of an initial portion of the model realizations (\n235\n) that is generated prior to performing any calibration of the model realizations (\n235\n).', 'In particular, the modeling result A (\n236\n-\n1\n), modeling result B (\n236\n-\n2\n), and any other modeling results of the initial portion of the model realizations (\n235\n) are generated once without being regenerated in their entirety during subsequent calibrations of the model realizations (\n235\n).', 'In this context, the modeling result A (\n236\n-\n1\n), modeling result B (\n236\n-\n2\n), and any other modeling results of the initial portion are collectively referred to as the initial modeling results.', 'Similarly, the portion of the input value sets (\n233\n) (e.g., input value set A (\n233\n-\n1\n), input value set B (\n233\n-\n2\n), etc.) used to generate the initial portion of the model realizations (\n235\n) is referred to as the initial portion of the input value sets (\n233\n).', 'During the calibration, one or more of the model realization A (\n235\n-\n1\n), model realization B (\n235\n-\n2\n), and/or other model realizations in the initial portion may be adjusted in an attempt to increase the likelihood value of the resultant model realization, such as the adjusted model realization A (\n235\n-\n3\n).', 'In this context, the initial portion of the model realizations (\n235\n) is referred to as an initial set of model realizations while the model realizations (\n235\n) is referred to as an expanded set of model realizations.', 'In one or more embodiments, the actual measurements (e.g., measured porosity or pore pressure values) may be obtained using the data acquisition tools (as depicted in \nFIG.', '1.1\n above) at different time points or from different locations of the field (\n100\n).', 'Accordingly, the likelihood value A (\n237\n-\n1\n) and likelihood value B (\n237\n-\n2\n) may be dependent on when and where the actual measurements are performed.', 'For example, when a new pore pressure measurement is performed at a new depth as the drilling operation progresses, the likelihood value A (\n237\n-\n1\n) and likelihood value B (\n237\n-\n2\n) may be updated based on the comparison between the new pore pressure measurement and the modeling result A (\n236\n-\n1\n) and modeling result B (\n236\n-\n2\n), respectively.', 'Based on the update, the accuracies of the likelihood value A (\n237\n-\n1\n) and likelihood value B (\n237\n-\n2\n) are improved in representing the matching between the initial modeling results and the actual measurements.', 'For example, one or both of the likelihood value A (\n237\n-\n1\n) and likelihood value B (\n237\n-\n2\n) may be increased or decreased as an improvement in accuracy.', 'In one or more embodiments, one or more of the model realizations (\n235\n) may be adjusted during the calibration.', 'For example, based on the likelihood value A (\n237\n-\n1\n) meeting a pre-determined criterion, the model realization A (\n235\n-\n1\n) may be selected during a calibration iteration for adjustment to generate the adjusted model realization A (\n235\n-\n3\n).', 'As noted above, the adjusted model realization A (\n235\n-\n3\n) is generated based on the adjusted input value set A (\n233\n-\n4\n), which is adjusted from the input value set A (\n233\n-\n1\n) initially used to generate the model realization A (\n235\n-\n1\n) prior to the calibration.', 'In one or more embodiments, the adjusted input value set A (\n233\n-\n4\n) may be further adjusted in a subsequent calibration iteration to generate a further adjusted input value set, such as the adjusted input value set B (\n233\n-\n5\n).', 'In one or more embodiments, the calibrated modeling result (\n236\n) is a modeling result based on at least one iteration of the calibration.', 'In other words, the calibrated modeling result (\n236\n) is based on a combination of the initial portion of the model realizations (\n235\n) and at least on adjusted model realization (e.g., adjusted model realization A (\n235\n-\n3\n)).', 'In one or more embodiments, the E&P tool (\n230\n) includes the input receiver (\n221\n), the modeling calibrator (\n222\n), and the modeling engine (\n223\n).', 'Each of these components of the E&P tool (\n230\n) is described below.', 'In one or more embodiments, the input receiver (\n221\n) is configured to obtain the input value sets (\n233\n) and the PDFs (\n234\n) for analysis by the modeling calibrator (\n222\n) and the modeling engine (\n223\n).', 'In one or more embodiments, the input receiver (\n221\n) obtains at least a portion of the input value sets (\n233\n) and the PDFs (\n234\n) from a user.', 'In other words, the portion of the input value sets (\n233\n) and the PDFs (\n234\n) is specified by the user.', 'In one or more embodiments, the input receiver (\n221\n) obtains the input value sets (\n233\n) and the PDFs (\n234\n), at least in part, from the surface unit (\n112\n) depicted in \nFIG.', '1.1\n above.', 'For example, the input receiver (\n221\n) may obtain one or more portions of the input value sets (\n233\n) and the PDFs (\n234\n) from the surface unit (\n112\n) intermittently, periodically, in response to a user activation, or as triggered by an event.', 'Accordingly, the intermediate and final results of the modeling calibrator (\n222\n) and the modeling engine (\n223\n) may be generated intermittently, periodically, in response to a user activation, or as triggered by an event.', 'In one or more embodiments, the modeling calibrator (\n222\n) is configured to perform iterations of the calibration for the model realizations (\n235\n).', 'During each iteration, the modeling calibrator (\n222\n) generates and/or updates the likelihood values (e.g., likelihood value A (\n237\n-\n1\n), etc.) of the model realizations (\n235\n).', 'In one or more embodiments, the modeling calibrator (\n222\n) generates and/or updates the likelihood values by, at least in part, comparing the modeling results of the model realizations (\n235\n) to current measurements obtained during each calibration iteration.', 'In other words, the modeling calibrator (\n222\n) iteratively improves the accuracies of the likelihood values based on a sequence of new measurements obtained as the field operation progresses.', 'For example, a sequence of new well measurements may be obtained from the bottom hole assembly in the ever increasing well trajectory made accessible by the progression of the drilling operation.', 'Further, the modeling calibrator (\n222\n) updates the model realizations (\n235\n) during each iteration.', 'In one or more embodiments, the modeling calibrator (\n222\n) updates the model realizations (\n235\n) by selecting at least one model realization based on the generated/updated likelihood values.', 'For example, a model realization (e.g., model realization A (\n235\n-\n1\n)) with high likelihood value (e.g., the likelihood value A (\n237\n-\n1\n) exceeding a pre-determined threshold) may be selected.', 'An adjusted model realization (e.g., adjusted model realization A (\n235\n-\n3\n)) is then generated based on the selected model realization(s) (e.g., model realization A (\n235\n-\n1\n)).', 'Accordingly, the model realizations (\n235\n) is updated by adding the adjusted model realization (e.g., model realization A (\n235\n-\n1\n)).', 'In one or more embodiments, the modeling calibrator (\n222\n) may also remove a model realization (e.g., model realization B (\n235\n-\n2\n)) with low likelihood value (e.g., the likelihood value B (\n237\n-\n2\n) below a pre-determined threshold) to update the model realizations (\n235\n).', 'In addition, the modeling calibrator (\n222\n) is configured to generate the calibrated modeling result (\n236\n) based on, at least in part, the model realization (\n235\n-\n3\n) as adjusted during at least one of the model calibration iterations.', 'In one or more embodiments, the modeling calibrator (\n222\n) performs the calibration iterations and generates the calibrated modeling result (\n236\n) using the method described in reference to \nFIG.', '2\n below.', 'An example of generating/updating the model realizations (\n235\n) during the calibration iterations is described in reference to \nFIG.', '3.2\n below.', 'In one or more embodiments, the modeling engine (\n223\n) is configured to perform modeling of the field (\n100\n).', 'In one or more embodiments, the modeling includes the aforementioned basin modeling and/or the petroleum system modeling.', 'In one or more embodiments, the modeling further includes reservoir modeling, such as performing simulation, planning, and optimization of exploratory and/or production operations of the wellsite system A (\n114\n-\n1\n), wellsite system B (\n114\n-\n2\n), and/or wellsite system C (\n114\n-\n3\n) depicted in \nFIG.', '1.1\n above.', 'In one or more embodiments, the modeling engine (\n223\n) generates the model realizations (\n235\n) based on the input value sets (\n233\n) according to the aforementioned mathematical and physical laws.', 'In one or more embodiments, the modeling engine (\n223\n) generates the model realizations (\n235\n) using a simulator that performs mathematical computations based on the physical laws.', 'The final results of the mathematical computations form the output of the simulator and included as modeling output data in a model realization.', 'In one or more embodiments, the modeling engine (\n223\n) generates the model realizations (\n235\n) using the method described in reference to \nFIG.', '2\n below.', 'In one or more embodiments, the result generated by the E&P computer system (\n118\n) may be displayed to a user using a two dimensional (2D) display, three dimensional (3D) display, or other suitable displays.', 'For example, the calibrated modeling result (\n236\n) may be used by the user to predict hydrocarbon content throughout portions of the field (\n100\n) and to facilitate drilling, fracturing, or other exploratory and/or production operations of the field (\n100\n).', 'In one or more embodiments, the E&P computer system (\n118\n) includes the field task engine (\n231\n) that is configured to generate a field operation control signal based at least on a result generated by the E&P tool (\n230\n), such as based on the adjusted model realization A (\n235\n-\n3\n) and/or the calibrated modeling result (\n236\n).', 'As noted above, the field operation equipment depicted in \nFIG.', '1.1\n above may be controlled by the field operation control signal.', 'For example, the field operation control signal may be used to control drilling equipment, an actuator, a fluid valve, or other electrical and/or mechanical devices disposed about the field (\n100\n) depicted in \nFIG.', '1.1\n above.', 'The E&P computer system (\n118\n) may include one or more system computers, such as shown in \nFIGS.', '4.1 and 4.2\n below, which may be implemented as a server or any conventional computing system.', 'However, those skilled in the art, having benefit of this disclosure, will appreciate that implementations of various technologies described herein may be practiced in other computer system configurations, including hypertext transfer protocol (HTTP) servers, hand-held devices, multiprocessor systems, microprocessor-based or programmable consumer electronics, network personal computers, minicomputers, mainframe computers, and the like.', 'While specific components are depicted and/or described for use in the units and/or modules of the E&P computer system (\n118\n) and the E&P tool (\n230\n), a variety of components with various functions may be used to provide the formatting, processing, utility and coordination functions for the E&P computer system (\n118\n) and the E&P tool (\n230\n).', 'The components may have combined functionalities and may be implemented as software, hardware, firmware, or combinations thereof.\n \nFIG.', '2\n depicts an example method in accordance with one or more embodiments.', 'For example, the method depicted in \nFIG.', '2\n may be practiced using the E&P computer system (\n118\n) described in reference to \nFIGS.', '1.1 and 1.2\n above.', 'In one or more embodiments, one or more of the elements shown in \nFIG.', '2\n may be omitted, repeated, and/or performed in a different order.', 'Accordingly, embodiments of automatic calibration for modeling a field should not be considered limited to the specific arrangements of elements shown in \nFIG.', '2\n.', 'Initially in Block \n201\n, the initial portion of a set of model realizations is generated.', 'In one or more embodiments, the set of model realizations is iteratively updated during calibration iterations.', 'Prior to any calibration iteration, the initial portion of the set of model realizations is generated based on an initial portion of input value sets.', 'In one or more embodiments, a Monte Carlo risking algorithm is used to generate the initial portion of the set of model realizations using randomly selected input values specified in the initial portion of input value sets.', 'In Block \n202\n, a current measurement of the field is obtained during a current portion of the field operation.', 'For example, the current portion of the field operation may correspond to a particular depth being drilled during a drilling operation.', 'Accordingly, the new measurement is obtained from the particular depth just becoming accessible to the data acquisition tools.', 'In one or more embodiments, the current measure may include a well pressure, temperature log, porosity data, vitrinite reflectance, layer thickness, thermal conductivity data, geochemical data, permeability data, etc. obtained by using logging techniques such as logging-while-drilling (LWD), measuring-while-drilling (MWD), or other suitable logging techniques.', 'In Block \n203\n, a likelihood value is generated for each model realization in the set of model realizations.', 'In one or more embodiments, the likelihood value is generated by at least comparing the current measurement to a modeling result of the corresponding model realization.', 'Specifically, a statistical value of error is generated as the result of the comparison to represent the difference between the current measurement and the modeling result across grid points of the model realization.', 'For example, the statistical value of error may be a root-mean-squared average, an arithmetic mean, a geometric mean, a median value, or any other type of statistical average of the comparison differences from the grid points.', 'An example statistical value of error based on the root-mean-squared average is shown in Eq (1) below where d\nj\nsim \nrepresents a simulated parameter value for j\nth \ngrid point, d\nj\nobs \nrepresents a measured parameter value for j\nth \ngrid point, and n represents the number of grid points in the model realization.', 'RMSE\n \n=\n \n \n \n \n1\n \nn\n \n \n\u2062\n \n \n \n \n∑\n \nn\n \n \n \nj\n \n=\n \n1\n \n \n \n\u2062\n \n \n \n(\n \n \n \nd\n \nj\n \nsim\n \n \n-\n \n \nd\n \nj\n \nobs\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \n \n \nEq\n \n\u2061\n \n \n(\n \n1\n \n)', 'In one or more embodiments, the likelihood value includes a component that is inversely proportional to the statistical value of error.', 'For example, the likelihood value may include the inverse of the statistical value of error or other inversely proportional function of the statistical value of error.', 'An example likelihood value based on the root-mean-squared average shown in Eq (1) above is 1/RMSE.', 'In one or more embodiments, the likelihood value includes an additional component that is dependent on a set of probability functions (PDFs) where each PDF represents a level of uncertainty of a corresponding input parameter.', 'For example, the additional component of the likelihood value adjusts the likelihood value by multiplying using an adjustment factor or by adding an additional adjustment term.', 'In one or more embodiments, the adjustment factor or the additional adjustment term is proportional to a product of PDFs of input parameter values included in the input value set that is used to generate the model realization.', 'In one or more embodiments, the PDFs is further adjusted based on the likelihood values to be used in the subsequent calibration iteration.', 'For example, the probability of the input values associated with high likelihood model realization may be adjusted higher.', 'In one or more embodiments, the adjusted PDFs are posteriori PDFs.', 'In Block \n204\n, at least one model realization is selected from the set of model realizations based on the likelihood values.', 'In one or more embodiments, the model realization with the highest likelihood value among the set of model realizations is selected.', 'In one or more embodiments, each model realization having a likelihood value exceeding a pre-determined threshold is selected.', 'In one or more embodiments, a portion of the set of modeling realizations is selected using a statistical sampling technique, such as using a genetic algorithm, a Markov Chain Monte Carlo algorithm, a Metropolis Sampling algorithm, a Kalman Filtering algorithm, etc.', 'A genetic algorithm is a search heuristic that mimics the process of natural selection.', 'In the genetic algorithm, a population of candidate solutions (referred to as individuals) is iteratively evolved toward better solutions where the individuals in each iteration form a generation.', 'Each individual has a set of alterable genotype properties (i.e., genome) that may be mutated between generations.', 'In each generation, an objective function representing the fitness of the individual is evaluated to stochastically select more fit individuals.', "The selected individual's genome is modified (e.g., recombined or randomly mutated) to form a new generation.", 'In one or more embodiments, each model realization with the associated likelihood value and the input value set are treated as the individual with associated fitness and genome to apply the genetic algorithm.', 'In other words, the likelihood value corresponds to the fitness, the input value set corresponds to the genome, and selecting the model realization corresponds to selecting the more fit individuals.', 'The Metropolis-Hastings algorithm is a Markov chain Monte Carlo method for obtaining a sequence of random samples from a probability distribution.', 'In one or more embodiments, the likelihood values of the set of model realizations are treated as the probability distribution to apply the Metropolis-Hastings algorithm.', 'Specifically, selecting the model realization corresponds to selecting the sequence of random samples in the Metropolis-Hastings algorithm.', 'In Block \n205\n, an adjusted model realization is generated by adjusting one or more selected model realizations.', 'In one or more embodiments, the adjusted model realization is generated by adjusting an input value set of the one or more selected model realizations.', 'For example, the input value set may be adjusted by applying a linear combination of multiple input value sets of the selected model realizations, applying random adjustments (e.g., noises) to input values in an input value set, applying a genetic algorithm, applying a linear quadratic estimation (e.g., a steady-state Kalman filter with a single filter step and a damping factor of one or greater), etc.', "In one or more embodiments, the input value set is adjusted by randomly adjusting one or more input values, which corresponds to mutating the individual's genome in the genetic algorithm.", 'Accordingly, the adjusted model realization is generated by simulating the field using the adjusted input value set as inputs to the modeling engine.', "In one or more embodiments, the adjusted model realization is generated by randomly combining two or more input value sets of the selected model realizations, which corresponds to recombining two individual's genomes in the genetic algorithm.", "In one or more embodiments, input parameters' values from two input value sets are intermixed to generate an adjusted input value set that is used to generate the adjusted model realization.", "For example, one input parameter's value from an input value set may be combined with a different input parameter's value from another input value set to generate the adjusted input value set.", 'Accordingly, the adjusted model realization is generated by simulating the field using the adjusted input value set as inputs to the modeling engine.', 'Specifically, simulating the field using the adjusted input value set updates the modeling output data in the selected model realizations to generate the adjusted modeling realization.', 'In other words, the adjusted modeling realization includes updated modeling output data derived from the adjusted input value set.', 'In Block \n206\n, the adjusted model realization is added to the set of model realizations to be used in the subsequent calibration iteration.', 'In one or more embodiments, the non-selected model realizations remain in the set of model realizations.', 'In Block \n207\n, a calibrated modeling result is generated based on the adjusted model realization.', 'In one or more embodiments, the model realization having the highest likelihood value in the expanded set of modeling realizations is used to generate the calibrated modeling result.', 'In one or more embodiments, the modeling results from at least a portion of the expanded set of modeling realizations are aggregated to generate the calibrated modeling result.', 'For example, the modeling results (denoted as X\ni\n) are multiplied by respective likelihood values (denoted as w\ni\n) and aggregated using a weighted average formula (e.g., Eq (2) below) to generate the calibrated modeling result (denoted as X\nc\n).', 'X\nc\n=Σ\nM\ni=1\nw\ni\n*X\ni\n/Σ\nM\ni=1\nw\ni\n\u2003\u2003Eq (2) \n \nwherein M denotes the number of model realizations that are aggregated.', 'In one or more embodiments, a statistical distribution of the modeling results is generated as the calibrated modeling result.', 'For example, the statistical distribution may be a percentile distribution of a pore pressure value as a function of depth.', 'An example of the calibrated modeling result including the percentile distribution is described in reference to \nFIGS.', '3.5 and 3.6\n below.', 'In Block \n208\n, a current portion of the field operation is performed based on the calibrated modeling result.', 'In one or more embodiments, a control signal is first generated based on the calibrated modeling result.', 'Accordingly, the current portion of the field operation is then performed based on the control signal.', 'In Block \n209\n, a determination is made as to whether the field operation has been completed.', 'If the determination is negative, i.e., the field operation has not been completed, the method returns to Block \n202\n to perform the subsequent calibration iteration for the subsequent portion of the field operation.', 'If the determination is positive, i.e., the field operation has been completed, the method ends.', 'FIGS.', '3.1, 3.2, 3.3, 3.4, 3.5, and 3.6\n show an example in accordance with one or more embodiments.', 'In one or more embodiments, the example shown in these figures may be practiced using the E&P computer system shown in \nFIGS.', '1.1 and 1.2\n and the method described in reference to \nFIG.', '2\n above.', 'The following example is for example purposes and not intended to limit the scope of the claims.', 'As noted above, basin modeling and/or petroleum systems modeling consider the evolution of a sedimentary basin on geological time scales that are reflected in the field measurements obtained at varying depths in the subterranean formation of a basin. \nFIG.', '3.1\n shows a workflow for performing real-time automatic calibration of a stochastic ensemble of model realizations “c” used in the basin modeling and/or petroleum systems modeling.', 'In particular, the real-time automatic calibration is performed during a field operation, such as a drilling operation at a rig “a” of the subterranean formation (\n312\n).', 'The real-time automatic calibration is performed by incorporating well measurements “b” from the drilling operation directly into the model realizations “c”.', 'The well measurements “b” may include well pressures, temperature logs, porosities, vitrinite reflectances, layer thicknesses, thermal conductivities, geochemical data, permeabilities, etc. obtained using logging-while-drilling (LWD), measuring-while-drilling (MWD), or other standard logging techniques.', 'In the example, the model realizations are stored in a shared pool of configurable computing resources that is referred to as the cloud (\n311\n).', 'As is used herein, the cloud (\n311\n) is an Internet-based computing platform that provides shared processing resources and data to user computers and other devices on demand.', 'The cloud (\n311\n) may be rapidly provisioned and released with minimal management effort.', 'Input data and output data (e.g. at well trajectories) related to the field operation are stored to avoid exploding of data storage space.', 'Cloud computing and storage solutions provide sharing of resources to achieve coherence and economy of scale, similar to the utility distributed over a network, such as the electricity grid.', 'As new real-time well measurements “b” are uploaded (e.g., via a satellite link (\n314\n)) into the cloud (\n311\n) concurrently with the drilling operation at the rig “a”, the ensemble of model realizations “c” is adjusted accordingly and used to calculate improved model predictions.', 'In addition, uncertainties of the model predictions may be quantified from the variety of model realizations.', 'Because the updated likelihood function may be re-evaluated, a direct assessment of already simulated model realizations “c” is performed on-the-fly to provide real-time feedback back to the rig “a”.', 'Accordingly, the ensemble of model realizations “c” is constantly updated when new data “b” becomes available during drilling and the generated model predictions are accessible via mobile devices in real time.', 'The up-to-date modeling results “d” (including a quantified uncertainty) are then used instantaneously for decision making, such as adjusting a drill path (\n313\n) of the well being drilled or determining locations of new wells to be drilled.', 'The instantaneous decision making based on real-time well measurements and up-to-date modeling results reduces drilling time as well as drilling failures.', 'The basin modeling and/or petroleum systems modeling workflow may include the following: building of the input model, simulation of the model, and viewing the simulation output.', 'First, the simulation from a workstation or an on-premises computer cluster is moved into a cloud computing environment.', 'Cloud computing utilizes massive parallel computing facilities at low cost, hence enabling the user to compare the real-time well measurements to modeling results of millions of different model realizations.', 'As the single realization simulations run independently and have to communicate during calibration and model adding steps, the simulations may be distributed among a large number of processor nodes in the cloud and run in parallel.', 'Thus, the automatic calibration workflow may be suitable for parallel computing on cloud processors.', 'Using the cloud computing based workflow, calibrated modeling results such as a pressure or mud-weight depth plots are generated iteratively during the drilling operation for user viewing by mobile devices, such as smartphones and tablets.', 'FIG.', '3.2\n show example model realizations (\n235\n), such as an example of the model realization described above with reference to \nFIG.', '1.2\n.', 'In particular, the model realizations (\n235\n) are represented as a two dimensional (2D) region (\n235\n-\n5\n) that corresponds to an input parameter space for modeling the field (\n100\n).', 'Each position within the 2D region (\n235\n-\n5\n) corresponds to a particular set of values of the input parameters.', 'In other words, each position within the 2D region (\n235\n-\n5\n) corresponds to a particular input value set.', 'Each model realization (e.g., model realization A (\n235\n-\n1\n), model realization B (\n235\n-\n2\n), etc.) in the initial portion of the model realizations (\n235\n) is represented as a square icon within the 2D region (\n235\n-\n5\n).', 'The position of each square icon corresponds to the input value set that is used to generate the model realization in the initial portion.', 'In addition, each square icon is annotated with “++”, “+”, or “−” to indicate the likelihood value of the corresponding model realization.', 'For example, “++” indicates that the likelihood value is in a high range, “+” indicates that the likelihood value is in an intermediate range, and “−” indicates that the likelihood value is in a low range.', 'Each adjusted model realization (e.g., adjusted model realization A (\n235\n-\n3\n), adjusted model realization B (\n235\n-\n4\n), etc.) in the model realizations (\n235\n) is represented as a round icon within the 2D region (\n235\n-\n5\n).', 'For example, the adjusted model realization A (\n235\n-\n3\n) may be generated from the model realization A (\n235\n-\n1\n) based on a random adjustment described in reference to \nFIG.', '3.3\n below.', 'In particular, the model realization A (\n235\n-\n1\n) is selected based on the high likelihood value indicated by the annotation “++”.', 'In another example, the adjusted model realization B (\n235\n-\n4\n) may be generated by combining the model realization A (\n235\n-\n1\n) and model realization B (\n235\n-\n2\n) using a genetic algorithm described in reference to \nFIG.', '3.4\n below.', 'In particular, the model realization A (\n235\n-\n1\n) and model realization B (\n235\n-\n2\n) are selected based on the high likelihood values indicated by the annotation “++” and “+”, respectively.', 'By applying the random adjustment and the genetic algorithm to model realizations with relatively high likelihood values (e.g., model realization A (\n235\n-\n1\n), model realization B (\n235\n-\n2\n)), high likelihood value areas (e.g., area A (\n235\n-\n6\n) bounded by the two dash lines) of the input parameter space (i.e., the 2D region (\n235\n-\n5\n)) are explored for expanding the model realizations (\n235\n) and avoiding the local maxima or minima of the likelihood values (e.g., within the area B (\n235\n-\n7\n) and area C (\n235\n-\n8\n)).', 'FIG.', '3.3\n shows a schematic diagram of generating adjusted model realizations by applying the random adjustment.', 'In particular, the model realization A (\n235\n-\n1\n) in the initial portion (\n235\n-\n5\n) of the model realizations (\n235\n) and the model realization B (\n235\n-\n2\n) in an expanded portion of the model realizations (\n235\n) are selected based on the high likelihood values.', 'By applying random adjustments to the input values of the model realization A (\n235\n-\n1\n), five adjusted model realizations are generated in a first generation including the adjusted model realization A (\n235\n-\n3\n).', 'By applying random adjustments to the input values of the adjusted model realization A (\n235\n-\n3\n), five further adjusted model realizations are generated in a second generation including the adjusted model realization B (\n235\n-\n4\n).', 'In an example scenario, the first generation is generated in an earlier calibration iteration and the second generation is generated in a subsequent calibration iteration.', 'Accordingly, the five adjusted model realizations are added to expand the model realizations (\n235\n) in the earlier calibration iteration.', 'Subsequently, the five further adjusted model realizations are added to further expand the model realizations (\n235\n) in the subsequent calibration iteration.', 'In particular, the remaining four adjusted model realizations, except the adjusted model realization A (\n235\n-\n1\n), are not selected to generate any more adjusted model realization in the second generation.', 'In this context, the model realizations (\n235\n) is said to be expanded based on survival of the fittest.', 'In another example scenario, the first generation and second generation are both generated in the same calibration iteration.', 'Accordingly, the model realization A (\n235\n-\n1\n) selected from the first generation and the adjusted model realization B (\n235\n-\n4\n) selected from the second generation are added to expand the model realizations (\n235\n) for use in a subsequent calibration iteration.', 'In particular, the remaining four adjusted model realizations and the remaining four further adjusted model realizations are not selected to generate any more adjusted model realization to expand the model realizations (\n235\n).', 'In this context, the model realizations (\n235\n) are said to be expanded based on survival of the fittest.\n \nFIG.', '3.4\n shows a schematic diagram of generating adjusted model realizations by applying the genetic algorithm.', 'In particular, five model realization pair combinations are selected out of 32 possible model realization pair combinations in the initial portion (\n235\n-\n5\n) of the model realizations (\n235\n) based on the high likelihood values.', 'By intermixing the input values of each selected model realization pair combination, five adjusted model realizations are generated including the adjusted model realization A (\n235\n-\n3\n) and the adjusted model realization B (\n235\n-\n4\n).', 'Accordingly, the five adjusted model realizations are added to expand the model realizations (\n235\n) for use in a subsequent calibration iteration.', 'FIG.', '3.5\n shows an example calibrated modeling result that is an equivalent mud weight plot generated when a drilling operation reaches a drilling depth of 2000 m (meters).', 'In particular, the example equivalent mud weight plot includes a plot A (\n320\n-\n1\n) of equivalent mud weight for pore pressure and a plot B (\n320\n-\n2\n) of equivalent mud weight for fracture pressure.', 'To guide the drilling operation, the plot A (\n320\n-\n1\n) of equivalent mud weight for pore pressure serves as a lower bound to the mud weight used for drilling while the plot B (\n320\n-\n2\n) of equivalent mud weight for fracture pressure serves as an upper bound to the mud weight used for drilling.', 'According to the legend (\n320\n), each “x” in the plot A (\n320\n-\n1\n) denotes a pore pressure value or a fracture pressure value based on a well measurement obtained at a corresponding depth during the drilling from the surface to the depth of 2000 m. The well measurement is used for an automatic calibration iteration performed when the drilling reaches the corresponding depth.', 'Specifically, the well measurement “A” and well measurement “B” are new measurements obtained at the depth of 2000 m and corresponding to the pore pressure and fracture pressure, respectively.', 'In particular, the well measurement “A” and well measurement “B” are the aforementioned current measurements used in the automatic calibration iteration to generate the selected model realization(s) and to add the adjusted model realization(s) to the ensemble.', 'Based on the updated ensemble with the newly added adjusted model realization(s), the pore pressure predictions and fracture pressure predictions below the depth 2000 m are generated as the calibrated modeling results.', 'These pressure predictions are used to set up improved mud-weight limits for preventing blow-outs and well destruction by fracturing and for improving the safety and the drilling speed.', 'As shown in \nFIG.', '3.5\n, the pore pressure predictions below the depth 2000 m include P\n10\n, P\n50\n, and P\n90\n of the plot A (\n320\n-\n1\n) that denote 10 percentile, 50 percentile, and 90 percentile, respectively, of the simulated pore pressure values of the millions of different model realizations.', 'In other words, the simulated pore pressure values from 10% of the millions of different model realizations are below P\n10\n, the simulated pore pressure values from 50% of the millions of different model realizations are below P\n50\n, and the simulated pore pressure values from 90% of the millions of different model realizations are below P\n90\n.', 'Similarly, the fracture pressure predictions below the depth 2000 m include P\n10\n, P\n50\n, and P\n90\n of the plot B (\n320\n-\n2\n) that denote 10 percentile, 50 percentile, and 90 percentile, respectively, of the simulated fracture pressure values of the millions of different model realizations.', 'In other words, the simulated fracture pressure values from 10% of the millions of different model realizations are below P\n10\n, the simulated fracture pressure values from 50% of the millions of different model realizations are below P\n50\n, and the simulated fracture pressure values from 90% of the millions of different model realizations are below P\n90\n.\n \nFIG.', '3.6\n shows an example calibrated modeling result that is an equivalent mud weight plot generated when the drilling operation reaches a drilling depth of 3600 m. In particular, the example equivalent mud weight plot includes a plot C (\n330\n-\n1\n) of equivalent mud weight for pore pressure and a plot D (\n330\n-\n2\n) of equivalent mud weight for fracture pressure.', 'Similar to the example equivalent mud weight plot depicted in \nFIG.', '3.5\n above, the plot C (\n330\n-\n1\n) of equivalent mud weight for pore pressure serves as a lower bound to the mud weight used for drilling while the plot D (\n330\n-\n2\n) of equivalent mud weight for fracture pressure serves as an upper bound to the mud weight used for drilling.', 'According to the legend (\n330\n), each “x” in the plot A (\n320\n-\n1\n) denotes a pore pressure value or a fracture pressure value based on a well measurement obtained at a corresponding depth during the drilling from the surface to the depth of 3600 m. The well measurement is used for an automatic calibration iteration performed when the drilling reaches the corresponding depth.', 'Specifically, the well measurement “C” and well measurement “D” are new measurements obtained at the depth of 3600 m and corresponding to the pore pressure and fracture pressure, respectively.', 'In particular, the well measurement “C” and well measurement “D” are the aforementioned current measurements used in the automatic calibration iteration to generate the selected model realization(s) and to add the adjusted model realization(s) to the ensemble.', 'Based on the updated ensemble with the newly added adjusted model realization(s), the pore pressure predictions and fracture pressure predictions below the depth 3600 m are generated as the calibrated modeling results.', 'These pressure predictions are used to set up improved mud-weight limits for preventing blow-outs and well destruction by fracturing and for improving the safety and the drilling speed.', 'As shown in \nFIG.', '3.6\n, the pore pressure predictions below the depth 3600 m include P\n10\n, P\n50\n, and P\n90\n of the plot C (\n330\n-\n1\n) that denote 10 percentile, 50 percentile, and 90 percentile, respectively, of the simulated pore pressure values of the millions of different model realizations.', 'Similarly, the fracture pressure predictions below the depth 3600 m include P\n10\n, P\n50\n, and P\n90\n of the plot D (\n330\n-\n2\n) that denote 10 percentile, 50 percentile, and 90 percentile, respectively, of the simulated fracture pressure values of the millions of different model realizations.', 'During the drilling operation described in \nFIGS.', '3.5 and 3.6\n above, the modeling input data and a portion of the modeling output data (e.g., modeling results at well trajectories) are included in the model realizations to reduce the data storage space.', 'Re-simulation of any model realization is performed to add additional data (e.g., related to a new well location) to reduce computing resources.', 'Embodiments of automatic calibration for modeling a field may be implemented on a computing system.', 'Any combination of mobile, desktop, server, router, switch, embedded device, or other types of hardware may be used.', 'For example, as shown in \nFIG.', '4.1\n, the computing system (\n400\n) may include one or more computer processors (\n402\n), non-persistent storage (\n404\n) (e.g., volatile memory, such as random access memory (RAM), cache memory), persistent storage (\n406\n) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory, etc.), a communication interface (\n412\n) (e.g., Bluetooth interface, infrared interface, network interface, optical interface, etc.), and numerous other elements and functionalities.', 'The computer processor(s) (\n402\n) may be an integrated circuit for processing instructions.', 'For example, the computer processor(s) may be one or more cores or micro-cores of a processor.', 'The computing system (\n400\n) may also include one or more input devices (\n410\n), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.', 'The communication interface (\n412\n) may include an integrated circuit for connecting the computing system (\n400\n) to a network (not shown) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) and/or to another device, such as another computing device.', 'Further, the computing system (\n400\n) may include one or more output devices (\n408\n), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device.', 'One or more of the output devices may be the same or different from the input device(s).', 'The input and output device(s) may be locally or remotely connected to the computer processor(s) (\n402\n), non-persistent storage (\n404\n), and persistent storage (\n406\n).', 'Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.', 'Software instructions in the form of computer readable program code to perform embodiments may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium.', 'Specifically, the software instructions may correspond to computer readable program code that, when executed by a processor(s), is configured to perform one or more embodiments.', 'The computing system (\n400\n) in \nFIG.', '4.1\n may be connected to or be a part of a network.', 'For example, as shown in \nFIG.', '4.2\n, the network (\n420\n) may include multiple nodes (e.g., node X (\n422\n), node Y (\n424\n)).', 'Each node may correspond to a computing system, such as the computing system shown in \nFIG.', '4.1\n, or a group of nodes combined may correspond to the computing system shown in \nFIG.', '4.1\n.', 'By way of an example, embodiments may be implemented on a node of a distributed system that is connected to other nodes.', 'By way of another example, embodiments may be implemented on a distributed computing system having multiple nodes, where each portion may be located on a different node within the distributed computing system.', 'Further, one or more elements of the aforementioned computing system (\n400\n) may be located at a remote location and connected to the other elements over a network.', 'Although not shown in \nFIG.', '4.2\n, the node may correspond to a blade in a server chassis that is connected to other nodes via a backplane.', 'By way of another example, the node may correspond to a server in a data center.', 'By way of another example, the node may correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.', 'The nodes (e.g., node X (\n422\n), node Y (\n424\n)) in the network (\n420\n) may be configured to provide services for a client device (\n426\n).', 'For example, the nodes may be part of a cloud computing system.', 'The nodes may include functionality to receive requests from the client device (\n426\n) and transmit responses to the client device (\n426\n).', 'The client device (\n426\n) may be a computing system, such as the computing system shown in \nFIG.', '4.1\n.', 'Further, the client device (\n426\n) may include and/or perform at least a portion of one or more embodiments.', 'The computing system or group of computing systems described in \nFIGS.', '4.1 and 4.2\n may include functionality to perform a variety of operations disclosed herein.', 'For example, the computing system(s) may perform communication between processes on the same or different system.', 'A variety of mechanisms, employing some form of active or passive communication, may facilitate the exchange of data between processes on the same device.', 'Examples representative of these inter-process communications include, but are not limited to, the implementation of a file, a signal, a socket, a message queue, a pipeline, a semaphore, shared memory, message passing, and a memory-mapped file.', 'Further details pertaining to a couple of these non-limiting examples are provided below.', 'Based on the client-server networking model, sockets may serve as interfaces or communication channel end-points enabling bidirectional data transfer between processes on the same device.', 'Foremost, following the client-server networking model, a server process (e.g., a process that provides data) may create a first socket object.', 'Next, the server process binds the first socket object, thereby associating the first socket object with a unique name and/or address.', 'After creating and binding the first socket object, the server process then waits and listens for incoming connection requests from one or more client processes (e.g., processes that seek data).', 'At this point, when a client process wishes to obtain data from a server process, the client process starts by creating a second socket object.', 'The client process then proceeds to generate a connection request that includes at least the second socket object and the unique name and/or address associated with the first socket object.', 'The client process then transmits the connection request to the server process.', 'Depending on availability, the server process may accept the connection request, establishing a communication channel with the client process, or the server process, busy in handling other operations, may queue the connection request in a buffer until server process is ready.', 'An established connection informs the client process that communications may commence.', 'In response, the client process may generate a data request specifying the data that the client process wishes to obtain.', 'The data request is subsequently transmitted to the server process.', 'Upon receiving the data request, the server process analyzes the request and gathers the requested data.', 'Finally, the server process then generates a reply including at least the requested data and transmits the reply to the client process.', 'The data may be transferred as datagrams or a stream of characters (e.g., bytes).', 'Shared memory refers to the allocation of virtual memory space in order to substantiate a mechanism for which data may be communicated and/or accessed by multiple processes.', 'In implementing shared memory, an initializing process first creates a shareable segment in persistent or non-persistent storage.', 'Post creation, the initializing process then mounts the shareable segment, subsequently mapping the shareable segment into the address space associated with the initializing process.', 'Following the mounting, the initializing process proceeds to identify and grant access permission to one or more authorized processes that may also write and read data to and from the shareable segment.', 'Changes made to the data in the shareable segment by one process may immediately affect other processes, which are also linked to the shareable segment.', 'Further, when one of the authorized processes accesses the shareable segment, the shareable segment maps to the address space of that authorized process.', 'Often, one authorized process may mount the shareable segment, other than the initializing process, at any given time.', 'Other techniques may be used to share data, such as the various data described in the present application, between processes without departing from the scope of the claims.', 'The processes may be part of the same or different application and may execute on the same or different computing system.', 'Rather than or in addition to sharing data between processes, the computing system performing one or more embodiments may include functionality to receive data from a user.', 'For example, in one or more embodiments, a user may submit data via a graphical user interface (GUI) on the user device.', 'Data may be submitted via the graphical user interface by a user selecting one or more graphical user interface widgets or inserting text and other data into graphical user interface widgets using a touchpad, a keyboard, a mouse, or any other input device.', 'In response to selecting a particular item, information regarding the particular item may be obtained from persistent or non-persistent storage by the computer processor.', "Upon selection of the item by the user, the contents of the obtained data regarding the particular item may be displayed on the user device in response to the user's selection.", 'By way of another example, a request to obtain data regarding the particular item may be sent to a server operatively connected to the user device through a network.', 'For example, the user may select a uniform resource locator (URL) link within a web client of the user device, thereby initiating a Hypertext Transfer Protocol (HTTP) or other protocol request being sent to the network host associated with the URL.', 'In response to the request, the server may extract the data regarding the particular selected item and send the data to the device that initiated the request.', "Once the user device has received the data regarding the particular item, the contents of the received data regarding the particular item may be displayed on the user device in response to the user's selection.", 'Further to the above example, the data received from the server after selecting the URL link may provide a web page in Hyper Text Markup Language (HTML) that may be rendered by the web client and displayed on the user device.', 'Once data is obtained, such as by using techniques described above or from storage, the computing system, in performing one or more embodiments, may extract one or more data items from the obtained data.', 'For example, the extraction may be performed as follows by the computing system in \nFIG.', '4.1\n.', 'First, the organizing pattern (e.g., grammar, schema, layout) of the data is determined, which may be based on one or more of the following: position (e.g., bit or column position, Nth token in a data stream, etc.), attribute (where the attribute is associated with one or more values), or a hierarchical/tree structure (including layers of nodes at different levels of detail-such as in nested packet headers or nested document sections).', 'Then, the raw, unprocessed stream of data symbols is parsed, in the context of the organizing pattern, into a stream (or layered structure) of tokens (where each token may have an associated token “type”).', 'Next, extraction criteria are used to extract one or more data items from the token stream or structure, where the extraction criteria are processed according to the organizing pattern to extract one or more tokens (or nodes from a layered structure).', 'For position-based data, the token(s) at the position(s) identified by the extraction criteria are extracted.', 'For attribute/value-based data, the token(s) and/or node(s) associated with the attribute(s) satisfying the extraction criteria are extracted.', 'For hierarchical/layered data, the token(s) associated with the node(s) matching the extraction criteria are extracted.', 'The extraction criteria may be as simple as an identifier string or may be a query presented to a structured data repository (where the data repository may be organized according to a database schema or data format, such as XML).', 'The extracted data may be used for further processing by the computing system.', 'For example, the computing system of \nFIG.', '4.1\n, while performing one or more embodiments, may perform data comparison.', 'Data comparison may be used to compare two or more data values (e.g., A, B).', 'For example, one or more embodiments may determine whether A>B, A=B, A !=B, A B, B may be subtracted from A (i.e., A−B), and the status flags may be read to determine if the result is positive (i.e., if A>B, then A−B>0).', 'In one or more embodiments, B may be considered a threshold, and A is deemed to satisfy the threshold if A=B or if A>B, as determined using the ALU.', 'In one or more embodiments, A and B may be vectors, and comparing A with B includes comparing the first element of vector A with the first element of vector B, the second element of vector A with the second element of vector B, etc.', 'In one or more embodiments, if A and B are strings, the binary values of the strings may be compared.', 'The computing system in \nFIG.', '4.1\n may implement and/or be connected to a data repository.', 'For example, one type of data repository is a database.', 'A database is a collection of information configured for ease of data retrieval, modification, re-organization, and deletion.', 'Database Management System (DBMS) is a software application that provides an interface for users to define, create, query, update, or administer databases.', 'The user, or software application, may submit a statement or query into the DBMS.', 'Then the DBMS interprets the statement.', 'The statement may be a select statement to request information, update statement, create statement, delete statement, etc.', 'Moreover, the statement may include parameters that specify data, or data container (database, table, record, column, view, etc.), identifier(s), conditions (comparison operators), functions (e.g. join, full join, count, average, etc.), sort (e.g. ascending, descending), or others.', 'The DBMS may execute the statement.', 'For example, the DBMS may access a memory buffer, a reference or index a file for read, write, deletion, or any combination thereof, for responding to the statement.', 'The DBMS may load the data from persistent or non-persistent storage and perform computations to respond to the query.', 'The DBMS may return the result(s) to the user or software application.', 'The computing system of \nFIG.', '4.1\n may include functionality to present raw and/or processed data, such as results of comparisons and other processing.', 'For example, presenting data may be accomplished through various presenting methods.', 'Specifically, data may be presented through a user interface provided by a computing device.', 'The user interface may include a GUI that displays information on a display device, such as a computer monitor or a touchscreen on a handheld computer device.', 'The GUI may include various GUI widgets that organize what data is shown as well as how data is presented to a user.', 'Furthermore, the GUI may present data directly to the user, e.g., data presented as actual data values through text, or rendered by the computing device into a visual representation of the data, such as through visualizing a data model.', 'For example, a GUI may first obtain a notification from a software application requesting that a particular data object be presented within the GUI.', 'Next, the GUI may determine a data object type associated with the particular data object, e.g., by obtaining data from a data attribute within the data object that identifies the data object type.', 'Then, the GUI may determine any rules designated for displaying that data object type, e.g., rules specified by a software framework for a data object class or according to any local parameters defined by the GUI for presenting that data object type.', 'Finally, the GUI may obtain data values from the particular data object and render a visual representation of the data values within a display device according to the designated rules for that data object type.', 'Data may also be presented through various audio methods.', 'In particular, data may be rendered into an audio format and presented as sound through one or more speakers operably connected to a computing device.', 'Data may also be presented to a user through haptic methods.', 'For example, haptic methods may include vibrations or other physical signals generated by the computing system.', 'For example, data may be presented to a user using a vibration generated by a handheld computer device with a predefined duration and intensity of the vibration to communicate the data.', 'The above description of functions presents a few examples of functions performed by the computing system of \nFIG.', '4.1\n and the nodes and/or client device in \nFIG.', '4.2\n.', 'Other functions may be performed using one or more embodiments.', 'While one or more embodiments have been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope as disclosed herein.', 'Accordingly, the scope should be limited by the attached claims.'] | ['1.', 'A method for performing a field operation of a field, comprising:\nperforming a plurality of model calibration iterations based on a plurality of measurements of the field, wherein each of the plurality of model calibration iterations comprises: obtaining, during the field operation, a current measurement of the field; generating a plurality of likelihood values corresponding to a plurality of model realizations of the field, wherein each of the plurality of likelihood values is generated by at least comparing the current measurement of the field to a modeling result of a corresponding model realization; selecting, based on the plurality of likelihood values, at least one selected model realization from the plurality of model realizations; generating, by at least adjusting a first input value of the at least one selected model realization, an adjusted model realization of the field based on the at least one selected model realization, wherein adjusting the first input value comprises aggregating the first input value with a second input value of at least one of the plurality of model realizations, or wherein adjusting the first input value comprises a random adjustment; and adding the adjusted model realization to the plurality of model realizations; and\ngenerating a calibrated modeling result of the field based on the adjusted model realization from at least one of the plurality of model calibration iterations.', '2.', 'The method of claim 1, wherein obtaining the current measurement during each of the plurality of model calibration iterations comprises:\nobtaining, during a first portion of the field operation, a first measurement from a first field location accessed by the first portion of the field operation, wherein the first measurement is the current measurement used in a first model calibration iteration performed during the first portion of the field operation; and\nobtaining, during a second portion of the field operation, a second measurement from a second field location accessed by the second portion of the field operation, wherein the second measurement is the current measurement used in a second model calibration iteration performed during the second portion of the field operation, and\nwherein the second portion of the field operation is performed subsequent to the first portion of the field operation and based on the adjusted model realization generated in the first model calibration iteration.', '3.', 'The method of claim 1,\nwherein adjusting the first input value comprises a random adjustment.', '4.', 'The method of claim 1,\nwherein adjusting the first input value comprises aggregating the first input value with a second input value of at least one of the plurality of model realizations.', '5.', 'The method of claim 1, further comprising:\nidentifying a plurality of input value sets, wherein each of the plurality of input value sets comprises a plurality of input values corresponding to a plurality of input parameters for modeling the field; and\ngenerating, prior to the plurality of model calibration iterations, an initial set of model realizations, wherein each model realization in the initial set of model realizations is based on one of the plurality of input value sets,\nwherein the plurality of model realizations in each of the plurality of model calibration iterations is based at least on the initial set of model realizations.', '6.', 'The method of claim 5, wherein generating each of the plurality of likelihood values comprises:\nobtaining a plurality of probability density functions corresponding to the plurality of input parameters, wherein each of the plurality of probability density functions represents a level of uncertainty of a corresponding input parameter; and\ngenerating a statistical value of error in response to comparing the measurement of the field to the modeling result of the corresponding model realization,\nwherein each of the plurality of likelihood values is generated based on the plurality of probability density functions and the statistical value of error.', '7.', 'The method of claim 6, wherein at least one of the plurality of model calibration iterations further comprises:\nadjusting, based on the plurality of likelihood values, the plurality of probability density functions to be used in a subsequent model calibration iteration.', '8.', 'The method of claim 1, wherein selecting the at least one selected model realization comprises:\nperforming statistical sampling from the plurality of likelihood values using at least one consisting of a genetic algorithm, a Markov Chain Monte Carlo algorithm, a Metropolis Sampling algorithm, and a Kalman Filtering algorithm.', '9.', 'A system for performing a field operation of a field, comprising:\nan exploration and production (E&P) computer system, comprising: a computer processor; and memory storing instructions executed by the computer processor, wherein the instructions comprise functionality to: perform a plurality of model calibration iterations based on a plurality of measurements of the field, wherein each of the plurality of model calibration iterations comprises: obtaining, during the field operation, a current measurement of the field; generating a plurality of likelihood values corresponding to a plurality of model realizations of the field, wherein each of the plurality of likelihood values is generated by at least comparing the current measurement of the field to a modeling result of a corresponding model realization; selecting, based on the plurality of likelihood values, at least one selected model realization from the plurality of model realizations; generating, by at least adjusting a first input value of the at least one selected model realization, an adjusted model realization of the field based on the at least one selected model realization, wherein adjusting the first input value comprises aggregating the first input value with a second input value of at least one of the plurality of model realizations, or wherein adjusting the first input value comprises a random adjustment; and adding the adjusted model realization to the plurality of model realizations; and generate a calibrated modeling result of the field based on the adjusted model realization from at least one of the plurality of model calibration iterations; and\na repository for storing the plurality of model realizations, the plurality of likelihood values, and the calibrated modeling result.', '10.', 'The system of claim 9, wherein obtaining the current measurement during each of the plurality of model calibration iterations comprises:\nobtaining, during a first portion of the field operation, a first measurement from a first field location accessed by the first portion of the field operation, wherein the first measurement is the current measurement used in a first model calibration iteration performed during the first portion of the field operation; and\nobtaining, during a second portion of the field operation, a second measurement from a second field location accessed by the second portion of the field operation, wherein the second measurement is the current measurement used in a second model calibration iteration performed during the second portion of the field operation, and\nwherein the second portion of the field operation is performed subsequent to the first portion of the field operation and based on the adjusted model realization generated in the first model calibration iteration.', '11.', 'The system of claim 9, wherein the instructions further comprise functionality to:\nidentify a plurality of input value sets, wherein each of the plurality of input value sets comprises a plurality of input values corresponding to a plurality of input parameters for modeling the field; and\ngenerate, prior to the plurality of model calibration iterations, an initial set of model realizations, wherein each model realization in the initial set of model realizations is based on one of the plurality of input value sets,\nwherein the plurality of model realizations in each of the plurality of model calibration iterations is based at least on the initial set of model realizations.\n\n\n\n\n\n\n12.', 'The system of claim 11, wherein generating each of the plurality of likelihood values comprises:\nobtaining a plurality of probability density functions corresponding to the plurality of input parameters, wherein each of the plurality of probability density functions represents a level of uncertainty of a corresponding input parameter; and\ngenerating a statistical value of error in response to comparing the measurement of the field to the modeling result of the corresponding model realization,\nwherein each of the plurality of likelihood values is generated based on the plurality of probability density functions and the statistical value of error.', '13.', 'The system of claim 12, wherein at least one of the plurality of model calibration iterations further comprises:\nadjusting, based on the plurality of likelihood values, the plurality of probability density functions to be used in a subsequent model calibration iteration.', '14.', 'The system of claim 9, wherein selecting the at least one selected model realization comprises:\nperforming statistical sampling from the plurality of likelihood values using at least one consisting of a genetic algorithm, a Markov Chain Monte Carlo algorithm, a Metropolis Sampling algorithm, and a Kalman Filtering algorithm.', '15.', 'A non-transitory computer readable medium storing instructions that are configured to, when executed, cause a computer processor to:\nperform a plurality of model calibration iterations based on a plurality of measurements of a field, wherein each of the plurality of model calibration iterations comprises: obtaining, during a field operation, a current measurement of the field; generating a plurality of likelihood values corresponding to a plurality of model realizations of the field, wherein each of the plurality of likelihood values is generated by at least comparing the current measurement of the field to a modeling result of a corresponding model realization; selecting, based on the plurality of likelihood values, at least one selected model realization from the plurality of model realizations; generating, by at least adjusting a first input value of the at least one selected model realization, an adjusted model realization of the field based on the at least one selected model realization, wherein adjusting the first input value comprises aggregating the first input value with a second input value of at least one of the plurality of model realizations, or wherein adjusting the first input value comprises a random adjustment; and adding the adjusted model realization to the plurality of model realizations; and\ngenerate a calibrated modeling result of the field based on the adjusted model realization from at least one of the plurality of model calibration iterations.', '16.', 'The computer readable medium of claim 15, wherein the instructions are further configured to, when executed, cause the computer processor to:\nidentify a plurality of input value sets, wherein each of the plurality of input value sets comprises a plurality of input values corresponding to a plurality of input parameters for modeling the field; and\ngenerate, prior to the plurality of model calibration iterations, an initial set of model realizations, wherein each model realization in the initial set of model realizations is based on one of the plurality of input value sets,\nwherein the plurality of model realizations in each of the plurality of model calibration iterations is based at least on the initial set of model realizations.', '17.', 'The computer readable medium of claim 16, wherein the instructions are configured to, when executed, cause the computer processor to generate each of the plurality of likelihood values by, when executed, causing the computer processor to:\ngenerate each of the plurality of likelihood values comprises:\nobtain a plurality of probability density functions corresponding to the plurality of input parameters, wherein each of the plurality of probability density functions represents a level of uncertainty of a corresponding input parameter; and\ngenerate a statistical value of error in response to comparing the measurement of the field to the modeling result of the corresponding model realization,\nwherein each of the plurality of likelihood values is generated based on the plurality of probability density functions and the statistical value of error.\n\n\n\n\n\n\n18.', 'The computer readable medium of claim 17, wherein at least one of the plurality of model calibration iterations further comprises:\nadjusting, based on the plurality of likelihood values, the plurality of probability density functions to be used in a subsequent model calibration iteration.', '19.', 'The computer readable medium of claim 15, wherein selecting the at least one selected model realization comprises:\nperforming statistical sampling from the plurality of likelihood values using at least one consisting of a genetic algorithm, a Markov Chain Monte Carlo algorithm, a Metropolis Sampling algorithm, and a Kalman Filtering algorithm.', '20.', 'The computer readable medium of claim 15, wherein the obtaining the current measurement during each of the plurality of model calibration iterations comprises: wherein the second portion of the field operation is performed subsequent to the first portion of the field operation and based on the adjusted model realization generated in the first model calibration iteration.', 'obtaining, during a first portion of the field operation, a first measurement from a first field location accessed by the first portion of the field operation, wherein the first measurement is the current measurement used in a first model calibration iteration performed during the first portion of the field operation; and\nobtaining, during a second portion of the field operation, a second measurement from a second field location accessed by the second portion of the field operation, wherein the second measurement is the current measurement used in a second model calibration iteration performed during the second portion of the field operation, and'] | ['FIG.', '1.1 is a schematic view, partially in cross-section, of a field in which one or more embodiments of automatic calibration for modeling a field may be implemented.; FIG.', '1.2 shows a schematic diagram of a system in accordance with one or more embodiments.; FIG.', '2 shows a flowchart in accordance with one or more embodiments.; FIGS.', '3.1, 3.2, 3.3, 3.4, 3.5, and 3.6 show an example in accordance with one or more embodiments.; FIGS.', '4.1 and 4.2 show systems in accordance with one or more embodiments.; FIG.', '1.1 depicts a schematic view, partially in cross section, of a field (100) in which one or more embodiments of automatic calibration for modeling a field may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in FIG.', '1.1 may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of automatic calibration for modeling a field should not be considered limited to the specific arrangements of modules shown in FIG.', '1.1.; FIG.', '1.2 shows more details of the E&P computer system (118) in which one or more embodiments of automatic calibration for modeling a field may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in FIG.', '1.2 may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of automatic calibration for modeling a field should not be considered limited to the specific arrangements of modules shown in FIG.', '1.2.; FIG.', '2 depicts an example method in accordance with one or more embodiments.', 'For example, the method depicted in FIG.', '2 may be practiced using the E&P computer system (118) described in reference to FIGS.', '1.1 and 1.2 above.', 'In one or more embodiments, one or more of the elements shown in FIG.', '2 may be omitted, repeated, and/or performed in a different order.', 'Accordingly, embodiments of automatic calibration for modeling a field should not be considered limited to the specific arrangements of elements shown in FIG.', '2.; FIGS. 3.1, 3.2, 3.3, 3.4, 3.5, and 3.6 show an example in accordance with one or more embodiments.', 'In one or more embodiments, the example shown in these figures may be practiced using the E&P computer system shown in FIGS.', '1.1 and 1.2 and the method described in reference to FIG.', '2 above.', 'The following example is for example purposes and not intended to limit the scope of the claims.; FIG.', '3.2 show example model realizations (235), such as an example of the model realization described above with reference to FIG.', '1.2.', 'In particular, the model realizations (235) are represented as a two dimensional (2D) region (235-5) that corresponds to an input parameter space for modeling the field (100).', 'Each position within the 2D region (235-5) corresponds to a particular set of values of the input parameters.', 'In other words, each position within the 2D region (235-5) corresponds to a particular input value set.; FIG.', '3.3 shows a schematic diagram of generating adjusted model realizations by applying the random adjustment.', 'In particular, the model realization A (235-1) in the initial portion (235-5) of the model realizations (235) and the model realization B (235-2) in an expanded portion of the model realizations (235) are selected based on the high likelihood values.', 'By applying random adjustments to the input values of the model realization A (235-1), five adjusted model realizations are generated in a first generation including the adjusted model realization A (235-3).', 'By applying random adjustments to the input values of the adjusted model realization A (235-3), five further adjusted model realizations are generated in a second generation including the adjusted model realization B (235-4).', 'In an example scenario, the first generation is generated in an earlier calibration iteration and the second generation is generated in a subsequent calibration iteration.', 'Accordingly, the five adjusted model realizations are added to expand the model realizations (235) in the earlier calibration iteration.', 'Subsequently, the five further adjusted model realizations are added to further expand the model realizations (235) in the subsequent calibration iteration.', 'In particular, the remaining four adjusted model realizations, except the adjusted model realization A (235-1), are not selected to generate any more adjusted model realization in the second generation.', 'In this context, the model realizations (235) is said to be expanded based on survival of the fittest.; FIG.', '3.4 shows a schematic diagram of generating adjusted model realizations by applying the genetic algorithm.', 'In particular, five model realization pair combinations are selected out of 32 possible model realization pair combinations in the initial portion (235-5) of the model realizations (235) based on the high likelihood values.', 'By intermixing the input values of each selected model realization pair combination, five adjusted model realizations are generated including the adjusted model realization A (235-3) and the adjusted model realization B (235-4).', 'Accordingly, the five adjusted model realizations are added to expand the model realizations (235) for use in a subsequent calibration iteration.; FIG.', '3.5 shows an example calibrated modeling result that is an equivalent mud weight plot generated when a drilling operation reaches a drilling depth of 2000 m (meters).', 'In particular, the example equivalent mud weight plot includes a plot A (320-1) of equivalent mud weight for pore pressure and a plot B (320-2) of equivalent mud weight for fracture pressure.', 'To guide the drilling operation, the plot A (320-1) of equivalent mud weight for pore pressure serves as a lower bound to the mud weight used for drilling while the plot B (320-2) of equivalent mud weight for fracture pressure serves as an upper bound to the mud weight used for drilling.', 'According to the legend (320), each “x” in the plot A (320-1) denotes a pore pressure value or a fracture pressure value based on a well measurement obtained at a corresponding depth during the drilling from the surface to the depth of 2000 m. The well measurement is used for an automatic calibration iteration performed when the drilling reaches the corresponding depth.', 'Specifically, the well measurement “A” and well measurement “B” are new measurements obtained at the depth of 2000 m and corresponding to the pore pressure and fracture pressure, respectively.', 'In particular, the well measurement “A” and well measurement “B” are the aforementioned current measurements used in the automatic calibration iteration to generate the selected model realization(s) and to add the adjusted model realization(s) to the ensemble.', 'Based on the updated ensemble with the newly added adjusted model realization(s), the pore pressure predictions and fracture pressure predictions below the depth 2000 m are generated as the calibrated modeling results.', 'These pressure predictions are used to set up improved mud-weight limits for preventing blow-outs and well destruction by fracturing and for improving the safety and the drilling speed.', '; FIG.', '3.6 shows an example calibrated modeling result that is an equivalent mud weight plot generated when the drilling operation reaches a drilling depth of 3600 m. In particular, the example equivalent mud weight plot includes a plot C (330-1) of equivalent mud weight for pore pressure and a plot D (330-2) of equivalent mud weight for fracture pressure.', 'Similar to the example equivalent mud weight plot depicted in FIG.', '3.5 above, the plot C (330-1) of equivalent mud weight for pore pressure serves as a lower bound to the mud weight used for drilling while the plot D (330-2) of equivalent mud weight for fracture pressure serves as an upper bound to the mud weight used for drilling.', 'According to the legend (330), each “x” in the plot A (320-1) denotes a pore pressure value or a fracture pressure value based on a well measurement obtained at a corresponding depth during the drilling from the surface to the depth of 3600 m. The well measurement is used for an automatic calibration iteration performed when the drilling reaches the corresponding depth.', 'Specifically, the well measurement “C” and well measurement “D” are new measurements obtained at the depth of 3600 m and corresponding to the pore pressure and fracture pressure, respectively.', 'In particular, the well measurement “C” and well measurement “D” are the aforementioned current measurements used in the automatic calibration iteration to generate the selected model realization(s) and to add the adjusted model realization(s) to the ensemble.', 'Based on the updated ensemble with the newly added adjusted model realization(s), the pore pressure predictions and fracture pressure predictions below the depth 3600 m are generated as the calibrated modeling results.', 'These pressure predictions are used to set up improved mud-weight limits for preventing blow-outs and well destruction by fracturing and for improving the safety and the drilling speed.'] |
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US11131540 | Tubular measurement | Jan 26, 2017 | Jacques Orban, Shunfeng Zheng, Vishwanathan Parmeshwar | Schlumberger Technology Corporation | Office Action and Search Report issued in Russian Patent Application No. 2018145326/03 dated Aug. 10, 2020; 12 pages (with English translation). | 4459752; July 17, 1984; Babcock; 5107705; April 28, 1992; Wraight et al.; 6892812; May 17, 2005; Niedermayr et al.; 6896055; May 24, 2005; Koithan; 6931621; August 16, 2005; Green et al.; 7172037; February 6, 2007; Dashevskiy et al.; 7264050; September 4, 2007; Koithan et al.; 7357196; April 15, 2008; Goldman et al.; 7860593; December 28, 2010; Boone; 7938197; May 10, 2011; Boone et al.; 8121971; February 21, 2012; Edwards et al.; 8215417; July 10, 2012; Annaiyappa et al.; 8250816; August 28, 2012; Donnally et al.; 8386059; February 26, 2013; Boone; 8590635; November 26, 2013; Koederitz; 8718802; May 6, 2014; Boone; 9027671; May 12, 2015; Koederitz; 9223594; December 29, 2015; Brown et al.; 9285794; March 15, 2016; Wang et al.; 9410417; August 9, 2016; Reckmann et al.; 9429009; August 30, 2016; Paulk et al.; 9436173; September 6, 2016; Wang et al.; 9506336; November 29, 2016; Orbell; 9528364; December 27, 2016; Samuel et al.; 9593567; March 14, 2017; Pink et al.; 9598947; March 21, 2017; Wang et al.; 9784089; October 10, 2017; Boone et al.; 9828845; November 28, 2017; Kpetehoto et al.; 9896925; February 20, 2018; Hernandez et al.; 9933919; April 3, 2018; Raja et al.; 9934338; April 3, 2018; Germain et al.; 9938816; April 10, 2018; Astrid et al.; 9946445; April 17, 2018; Whalley; 9959022; May 1, 2018; Anghelescu et al.; 9988880; June 5, 2018; Dykstra; 9995129; June 12, 2018; Dykstra et al.; 10113408; October 30, 2018; Pobedinski et al.; 10138722; November 27, 2018; Magnuson; 20070097789; May 3, 2007; Coffey; 20080105427; May 8, 2008; Hampton et al.; 20130271576; October 17, 2013; Ellis; 20130275100; October 17, 2013; Ellis et al.; 20140210821; July 31, 2014; Kapoor et al.; 20140233804; August 21, 2014; Gustavsson et al.; 20140353033; December 4, 2014; Pink et al.; 20150345261; December 3, 2015; Kruspe et al.; 20150369030; December 24, 2015; Hay et al.; 20160024906; January 28, 2016; Jamison et al.; 20170308802; October 26, 2017; Ramsoy et al.; 20180156023; June 7, 2018; Dykstra et al.; 20180298693; October 18, 2018; Van Duivendijk et al.; 20180298694; October 18, 2018; Van Duivendijk et al.; 20180328159; November 15, 2018; Mandava et al.; 20180334887; November 22, 2018; Dashevskiy et al. | 2324812; May 2008; RU; 2593609; August 2016; RU; 03087714; October 2003; WO; 2012038863; March 2012; WO; 2017204655; November 2017; WO; 2018186745; October 2018; WO | ['A tubular measuring system having a sensor at a predetermined position with respect to a datum and a processing device comprising a processor and a memory storing computer program code in signal communication with the sensor.', 'The sensor generates a signal indicative of a feature of a tubular, and the processing device receives and processes the signal to determine position of the feature of the tubular with respect to the datum.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThis application claims priority to and the benefit of U.S. Provisional Application No. 62/287,097, titled “Drill Pipe Length Measurement System,” filed Jan. 26, 2016, the entire disclosure of which is hereby incorporated herein by reference.', 'This application also claims priority to and the benefit of U.S. Provisional Application No. 62/341,522, titled “Image Based System for Drilling Operations,” filed May 25, 2016, the entire disclosure of which is hereby incorporated herein by reference.', 'BACKGROUND OF THE DISCLOSURE\n \nWells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other natural resources that are trapped in subsurface rock formations.', 'Such wells are drilled using a drill bit attached to the lower end of a drill string.', 'Drilling fluid is pumped from the wellsite surface down through the drill string to the drill bit.', 'The drilling fluid lubricates and cools the bit, and may additionally carry drill cuttings from the wellbore back to the surface.', 'Length of the drill string may be tracked for several reasons.', 'Operational safety, for example, may be enhanced by monitoring the length of the drill string.', 'Further, the well plan for the well may be at least partially mapped out according to well depth, and the string length may serve as a proxy or partial basis for tracking well depth.', 'To track the length of the drill string, each new length (e.g., a stand of one or more, e.g., up to three) of drill pipe may be measured and added to the length of the drill string that was previously ran into the well.', 'Such measurements are generally done manually, such as by using a measuring tool like a measuring tape to measure the 10-30 feet of drill pipe added by the new length.', 'The margin of error using such process is relatively wide, however, even when measurements are carefully taken.', 'For example, the margin of error might be about 1% or more.', 'While such a margin of error may translate into a mere few inches, when such errors are multiplied potentially hundreds of times for a well that extends 10,000 feet or more, the cumulative error becomes an impediment to tracking the length of the drill string.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces a method including measuring a first distance between a first point and a second point, positioning a first end of a downhole tool in alignment with the first point, measuring a second distance between the second point and a second end of the downhole tool, and determining length of the downhole tool based on the first and second distances.', 'The present disclosure also introduces an apparatus including a tubular measuring system.', 'The tubular measuring system includes a sensor disposed at a predetermined location with respect to a datum.', 'The sensor is operable to generate a signal indicative of a tubular feature position relative to the sensor.', 'The tubular measuring system also includes a processing device comprising a processor and a memory storing computer program code.', 'The processing device is operable to receive and process the signal to determine position of the tubular feature with respect to the datum.', 'The present disclosure also introduces an apparatus including a measuring system operable to determine length of a tubular.', 'The measuring system includes a first contact member positionally fixed at a first distance from a datum and configured to contact a first end of the tubular.', 'The measuring system also includes a second contact member configured to move toward the first contact member to contact a second end of the tubular.', 'The measuring system also includes a sensor operable to generate a signal indicative of a second distance between the datum and the second contact member when the first contact member is in contact with the first end of the tubular and the second contact member is in contact with the second end of the tubular.', 'The measuring system also includes a processing device operable to determine the length of the tubular based on the first distance and the signal.', 'The present disclosure also introduces a method including transferring a tubular via tubular handling equipment disposed at an oil and/or gas drilling wellsite, and operating a sensor located at a predetermined location, relative to a datum at the wellsite, to generate a signal dependent upon a first characteristic of a feature of the tubular.', 'The first characteristic is a dimension or position of the tubular feature relative to the predetermined sensor location.', 'The method also includes operating a processing device comprising a processor and a memory storing computer program code to determine a second characteristic based on the signal.', 'The second characteristic is a dimension of the tubular or the tubular feature or a position of the tubular or the tubular feature relative to the datum.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '4\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '5\n is an enlarged view of a portion of the apparatus shown in \nFIG.', '4\n according to one or more aspects of the present disclosure.', 'FIG.', '6\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '7\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '8\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.\n \nFIG.', '9\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '10\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '11\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '12\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.', 'FIG.', '13\n is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.\n \nFIG.', '1\n is a schematic view of at least a portion of an example implementation of a drilling system \n100\n operable to drill a wellbore \n104\n into one or more subsurface formations \n102\n in accordance with one or more aspects of the present disclosure, to which one or more aspects of the present disclosure may be applicable.', 'A drill string \n106\n penetrates the wellbore \n104\n and may include a bottom hole assembly (BHA) \n108\n that comprises or is mechanically coupled to a drill bit \n110\n.', 'The BHA \n108\n may comprise various downhole tools \n109\n, such as for measuring, processing, and storing information.', 'A telemetry device may be in the BHA \n108\n to facilitate communications with a control system \n200\n (shown in \nFIGS.', '2 and 3\n) of the drilling system \n100\n.', 'The BHA \n108\n may have a modular construction with specific downhole tools \n109\n in certain modules.', 'However, the BHA \n108\n may be unitary or select downhole tools \n109\n may be modular.', 'The downhole tools \n109\n or modules may be positioned in a variety of configurations throughout the BHA \n108\n.', 'The BHA \n108\n may comprise a measuring while drilling (MWD) downhole tool or module, such as may include tools operable to measure wellbore trajectory, wellbore temperature, wellbore pressure, and/or other example properties.', 'The BHA \n108\n may comprise a sampling while drilling (SWD) system comprising a sample downhole tool or module for communicating a formation fluid through the BHA \n108\n and obtaining a sample of the formation fluid.', 'The SWD system may comprise gauges, sensor, monitors and/or other devices that may also be utilized for downhole sampling and/or testing of a formation fluid.', 'The BHA \n108\n may comprise a logging while drilling (LWD) downhole tool or module that may include tools operable to measure formation parameters and/or fluid properties, such as resistivity, porosity, permeability, sonic velocity, optical density, pressure, temperature, and/or other example properties.', 'The drilling system \n100\n may include a drill rig \n111\n above the surface of the formation \n102\n.', 'The drill rig \n111\n may comprise a mast \n114\n (at least a portion of which is depicted in \nFIG.', '1\n) extending from a rig floor \n112\n that is positioned over the wellbore \n104\n.', 'A top drive \n116\n may be suspended from the mast \n114\n and mechanically coupled to the drill string \n106\n.', 'The top drive \n116\n provides a rotational force (e.g., torque) to drive rotational movement of the drill string \n106\n, which may advance the drill string \n106\n into the formation and form the wellbore \n104\n.', 'The top drive \n116\n may be suspended from the mast \n114\n utilizing hoisting equipment.', 'The hoisting equipment may include a traveling block \n118\n with a hook \n120\n, a crown block \n122\n, a drawworks \n124\n, a deadline anchor \n126\n, a supply reel (not shown), and a drill line \n128\n with a deadline \n130\n (a portion of which is shown in phantom lines).', 'The hook \n120\n of the traveling block \n118\n may mechanically couple the top drive \n116\n.', 'The crown block \n122\n may be suspended from and supported by the mast \n114\n.', 'The drawworks \n124\n and the deadline anchor \n126\n may be on and supported by the rig floor \n112\n.', 'The drill line \n128\n may be supplied from the supply reel through the deadline anchor \n126\n.', 'The drill line \n128\n may be wrapped around and clamped at the deadline anchor \n126\n such that the drill line \n128\n that extends from the deadline anchor \n126\n to the crown block \n122\n is stationary during normal drilling operations, and hence, the portion of the drill line \n128\n that extends from the deadline anchor \n126\n to the crown block \n122\n is referred to as the deadline \n130\n.', 'The crown block \n122\n and traveling block \n118\n may comprise one or more pulleys or sheaves.', 'The drill line \n128\n may be reeved around the pulleys or sheaves of the crown block \n122\n and the traveling block \n118\n.', 'The drill line \n128\n may extend from the crown block \n122\n to the drawworks \n124\n.', 'The drawworks \n124\n may comprise a drum, a prime mover (e.g., an engine or motor), a control system, and one or more brakes, such as a mechanical brake (e.g., a disk brake), an electrodynamic brake, and/or the like.', 'The prime mover of the drawworks \n124\n may drive the drum to rotate and reel in the drill line \n128\n, which in turn may cause the traveling block \n118\n and top drive \n116\n to move upward.', 'The drawworks \n124\n may release the drill line \n128\n by a controlled rotation of the drum utilizing the prime mover and control system, and/or by disengaging the prime mover (such as with a clutch) and disengaging and/or operating one or more brakes to control the release of the drill line \n128\n.', 'By releasing drill line \n128\n from the drawworks \n124\n, the traveling block \n118\n and top drive \n116\n may move downward.', 'If the drilling system \n100\n is an off-shore system, the hoisting equipment may also include a motion or heave compensator between the mast \n114\n and the crown block \n122\n and/or between the traveling block \n118\n and the hook \n120\n, for example.', 'The top drive \n116\n may be suspended by the hook \n120\n and include a prime mover (not shown) with a drive shaft \n132\n, a grabber (not shown), a swivel (not shown), and a tubular handling assembly \n134\n terminating with an elevator \n136\n.', 'The drill string \n106\n may be mechanically coupled to the drive shaft \n132\n (e.g., with or without a sub saver between the drill string \n106\n and the drive shaft \n132\n).', 'The prime mover may drive the drive shaft \n132\n, such as through a gear box or transmission, to rotate the drive shaft \n132\n and, therefore, the drill string \n106\n, which, when working in conjunction with operation of the drawworks \n124\n, may advance the drill string \n106\n into the formation and form the wellbore \n104\n.', 'The tubular handling assembly \n134\n and elevator \n136\n may permit the top drive \n116\n to handle tubulars, e.g., drill pipes, drill collars, casing joints, and the like, that are not mechanically coupled to the drive shaft \n132\n, for example.', 'For example, when the drill string \n106\n is being tripped into or out of the wellbore \n104\n, the elevator \n136\n may grasp onto the tubulars of the drill string \n106\n such that the tubulars may be raised and/or lowered utilizing the hoisting equipment mechanically coupled to the top drive \n116\n.', 'The grabber may include a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft \n132\n.', 'The top drive \n116\n may have a guide system \n138\n, such as rollers, that track up and down a guide rail \n140\n on the mast \n114\n.', 'The guide system \n138\n and guide rail \n140\n may aid in keeping the top drive \n116\n aligned with the wellbore \n104\n and in preventing the top drive \n116\n from rotating during drilling by transferring the reactive torque from the drill string \n106\n to the mast \n114\n.', 'The drill rig \n111\n may further include a drilling fluid circulation system operable to circulate drilling fluid (e.g., mud) to the drill bit \n110\n during drilling operations.', 'A pump \n142\n may deliver the drilling fluid through a discharge line \n144\n, stand pipe \n146\n, rotary hose \n148\n, and a gooseneck \n150\n to the swivel of the top drive \n116\n.', 'The swivel may conduct the drilling fluid through the tubulars of the drill string \n106\n, and the drilling fluid may exit the drill string \n106\n via ports in the drill bit \n110\n.', 'The drilling fluid may then circulate upward through the annulus \n152\n defined between the outside of the drill string \n106\n and the wall of the wellbore \n104\n.', 'In this manner, the drilling fluid may lubricate the drill bit \n110\n and carry formation cuttings up to the surface as the drilling fluid is circulated.', 'At the surface, the drilling fluid may flow through a blowout preventer \n154\n and a bell nipple \n156\n that diverts the drilling fluid to a return flowline \n158\n.', 'The return flowline \n158\n may direct the drilling fluid to a shale shaker \n160\n that removes large formation cuttings from the drilling fluid.', 'The drilling fluid may be then directed to reconditioning equipment \n162\n.', 'Reconditioning equipment \n162\n may remove gas and/or finer formation cuttings from the drilling fluid.', 'The reconditioning equipment \n162\n may include a desilter, a desander, a degasser, and/or the like.', 'After being treated by the reconditioning equipment \n162\n and/or between being treated by various ones of the reconditioning equipment \n162\n, the drilling fluid may be conveyed to a mud tank \n164\n.', 'In some examples, intermediate mud tanks may be utilized to hold drilling fluid between the shale shaker \n160\n and various ones of the reconditioning equipment \n162\n.', 'The mud tank \n164\n may include an agitator to maintain uniformity of the drilling fluid contained in the mud tank \n164\n.', 'The pump \n142\n may then recirculate the drilling fluid from the mud tank \n164\n.', 'A hopper (not shown) may be disposed in a flowline between the mud tank \n164\n and the pump \n142\n to disperse an additive, such as caustic soda, in the drilling fluid.', 'The drill rig \n111\n may further include other tubular handling equipment operable to move tubulars, including drill pipe, during drilling operations.', 'For example, a catwalk \n166\n may be utilized to convey tubulars from a ground level to the rig floor \n112\n.', 'The catwalk \n166\n may have a horizontal portion and an inclined portion that extends between the horizontal portion and the rig floor \n112\n.', 'A skate \n168\n may be positioned in a groove in the horizontal and inclined portions of the catwalk \n166\n.', 'The skate \n168\n may be driven along the groove by a rope and pulley system, for example.', 'Additionally, one or more racks (not shown) may adjoin the horizontal portion of the catwalk \n166\n, and the racks may have a spinner unit for transferring tubulars to the groove of the catwalk \n166\n.', 'An iron roughneck \n170\n may be positioned on the rig floor \n112\n.', 'The iron roughneck \n170\n may comprise a spinning system \n172\n and a torque wrench comprising a lower tong \n174\n and an upper tong \n176\n.', 'The iron roughneck \n170\n may be moveable (e.g., in a translation movement as indicated by arrow \n178\n) to approach the drill string \n106\n (e.g., for making up and/or breaking out a connection of the drill string \n106\n) and to move clear of the drill string \n106\n.', 'The spinning system \n172\n may be generally utilized to apply low torque spinning to make up and/or break out a threaded connection between tubulars of the drill string \n106\n.', 'The torque wrench applies a higher torque to make up and/or break out the threaded connection.', 'A reciprocating slip system \n180\n may be located on and/or in the rig floor \n112\n such that the drill string \n106\n extends through the reciprocating slip \n180\n.', 'The reciprocating slip \n180\n may be in an open position to permit advancement of the drill string \n106\n through the reciprocating slip \n180\n, and the reciprocating slip \n180\n may be in a closed position to clamp the drill string \n106\n to prevent advancement of the drill string \n106\n.', 'In a closed position, the reciprocating slip \n180\n may suspend the drill string \n106\n in the wellbore \n104\n.', 'In operation, the hoisting equipment may lower the drill string \n106\n while the top drive \n116\n rotates the drill string \n106\n to advance the drill string \n106\n downward in the wellbore \n104\n.', 'During the advancement of the drill string \n106\n, the reciprocating slip \n180\n is in an open position, and the iron roughneck \n170\n is clear of the drill string \n106\n.', 'When the upper portion of the tubular in the drill string \n106\n that is made up to the top drive \n116\n is near to the reciprocating slip \n180\n and/or rig floor \n112\n, the top drive \n116\n ceases rotating the drill string \n106\n, and the reciprocating slip \n180\n closes to clamp the drill string \n106\n.', 'The grabber of the top drive \n116\n clamps the upper portion of the tubular made up to the drive shaft \n132\n.', 'Once clamped, the drive shaft \n132\n is driven by the prime mover of the top drive \n116\n and transmission or gearbox in a direction reverse from the drilling rotation to break out the connection between the drive shaft \n132\n and the drill string \n106\n.', 'The grabber of the top drive \n116\n may then release the tubular of the drill string \n106\n.', 'Multiple tubulars may be loaded on the rack of the catwalk \n166\n and individual tubulars may be transferred from the rack to the groove in the catwalk \n166\n, such as by the spinner unit.', 'A tubular positioned in the groove may be conveyed along the groove by the skate \n168\n as driven, e.g., by a rope and pulley system.', 'As the tubular is conveyed (e.g., pushed) along the groove by the skate \n168\n, an end of the tubular may reach the inclined portion of the catwalk \n166\n and be conveyed along the incline to the rig floor \n112\n.', 'After the tubular is conveyed such that the end of the tubular projects above the rig floor \n112\n, the elevator \n136\n may be able to grasp around the end of the tubular permitting the drawworks \n124\n to lift the tubular via the top drive \n116\n.', 'With the connection between the drill string \n106\n and the drive shaft \n132\n broken out and with the elevator \n136\n grasping the tubular, the hoisting equipment may raise the elevator \n136\n, e.g., the drawworks \n124\n reels in the drill line \n128\n to raise the traveling block \n118\n, and hence, the top drive \n116\n and the elevator \n136\n with the tubular.', 'The tubular suspended by the elevator \n136\n may be aligned with the upper portion of the drill string \n106\n.', 'The iron roughneck \n170\n may be moved toward the drill string \n106\n as indicated by arrow \n178\n, and the lower tong \n174\n may clamp onto the upper portion of the drill string \n106\n.', 'The spinning system \n172\n may then rotate the suspended tubular (e.g., a threaded male connector) into the upper portion of the drill string \n106\n (e.g., a threaded female connector).', 'Once the spinning system \n172\n has provided the low torque rotation to make up the connection between the suspended tubular and the upper portion of the drill string \n106\n, the upper tong \n176\n may clamp onto the suspended tubular and rotate the suspended tubular with a high torque to complete making up the connection between the suspended tubular and the drill string \n106\n.', 'In this manner, the suspended tubular becomes a part of the drill string \n106\n.', 'The iron roughneck \n170\n may then release the drill string \n106\n and move clear of the drill string \n106\n as indicated by arrow \n178\n.', 'The grabber of the top drive \n116\n may then clamp onto the drill string \n106\n.', 'The drive shaft \n132\n (e.g., a threaded male connector) may be brought into contact with the drill string \n106\n (e.g., a threaded female connector) and rotated by the prime mover to make up a connection between the drill string \n106\n and the drive shaft \n132\n.', 'The grabber may then release the drill string \n106\n, and the reciprocating slip \n180\n may be operated into the open position.', 'Drilling may then resume.', 'The tubular handling equipment by further include a tubular handling manipulator (PHM) \n182\n disposed in association with a fingerboard \n184\n.', 'Although the PHM \n182\n and the fingerboard \n184\n are shown supported on the rig floor \n112\n, it is to be understood that one or both of the PHM \n182\n and a fingerboard \n184\n may be located off of the rig floor \n112\n.', 'The fingerboard \n184\n provides storage (e.g., temporary storage) of tubulars \n194\n during various operations, such as during and between tripping out and tripping in the drill string \n106\n.', 'The PHM \n182\n may be operable to transfer tubulars between the drill string \n106\n and the fingerboard \n184\n.', 'The PHM \n182\n may include arms and clamps \n186\n, such as may be operable to grasp and/or clamp onto a tubular while the PHM \n182\n transfers the tubular.', 'The PHM \n182\n may be movable in one or more translation direction \n188\n and/or a rotational direction \n190\n around an axis of the PHM \n182\n.', 'The arms of the PHM \n182\n may extend and retract along direction \n192\n.', 'To trip out the drill string \n106\n, the hoisting equipment may raise the top drive \n116\n, the reciprocating slip \n180\n may close to clamp the drill string \n106\n, and the elevator \n136\n may close around the drill string \n106\n.', 'The grabber of the top drive \n116\n may then clamp the upper portion of the tubular made up to the drive shaft \n132\n.', 'Once clamped, the drive shaft \n132\n may be driven by the prime mover and transmission or gearbox of the top drive \n116\n in a direction reverse from the drilling rotation to break out the connection between the drive shaft \n132\n and the drill string \n106\n.', 'The grabber of the top drive \n116\n may then release the tubular of the drill string \n106\n, and the drill string \n106\n may be suspended, at least in part, by the elevator \n136\n.', 'The iron roughneck \n170\n may be moved \n178\n toward the drill string \n106\n.', 'The lower tong \n174\n may clamp onto a lower tubular at a connection of the drill string \n106\n, and the upper tong \n176\n may clamp onto an upper tubular at the connection of the drill string \n106\n.', 'The upper tong \n176\n may then rotate the upper tubular to provide a high torque to break out the connection between the upper and lower tubulars.', 'Once the high torque has been provided, the spinning system \n172\n may rotate the upper tubular to break out the connection, and the upper tubular may be suspended above the rig floor \n112\n by the elevator \n136\n.', 'The iron roughneck \n170\n may then release the drill string \n106\n and move clear of the drill string \n106\n.', 'The PHM \n182\n may then move (e.g., with movement along directions indicated by arrows \n188\n, \n190\n, and/or \n192\n) to grasp with the clamps \n186\n the tubular suspended from the elevator \n136\n.', 'Once the clamps \n186\n have grasped the suspended tubular, the elevator \n136\n may open to release the tubular.', 'The PHM \n182\n may then move (e.g., with movement along directions indicated by arrows \n188\n, \n190\n, and/or \n192\n) while grasping the tubular with the clamps \n186\n, place the tubular in the fingerboard \n184\n, and release the tubular to store the tubular in the fingerboard \n184\n.', 'Once the tubular that was suspended by the elevator \n136\n is clear from the top drive \n116\n, the top drive \n116\n may be lowered and the elevator \n136\n may be closed around and grasps the upper portion of the drill string \n106\n projecting above the reciprocating slip \n180\n and/or rig floor \n112\n.', 'The reciprocating slip \n180\n may then be opened and the elevator \n136\n raised utilizing the hoisting equipment to raise the drill string \n106\n.', 'Once raised, the reciprocating slip \n180\n may close to clamp the drill string \n106\n.', 'The iron roughneck \n170\n may move to the drill string \n106\n and break out a connection between tubulars, as described above.', 'The PHM \n182\n may then grasp the suspended tubular and place the tubular in the fingerboard \n184\n, as described above.', 'This process may be repeated until a full length of the drill string \n106\n is removed from the wellbore \n104\n.', 'To trip in the drill string \n106\n, the process described above for tripping out the drill string \n106\n may be reversed.', 'To summarize, the PHM \n182\n may grasp a tubular (e.g., tubular \n194\n) from the fingerboard \n184\n and transfer the tubular to the elevator \n136\n that closes around and grasps the tubular.', 'If no portion of the drill string \n106\n has been advanced into the wellbore \n104\n, the suspended tubular may be advanced into the wellbore \n104\n by lowering the elevator \n136\n.', 'If a portion of the drill string \n106\n has been advanced into the wellbore \n104\n, the drill string \n106\n may be projecting above the reciprocating slip \n180\n and/or rig floor \n112\n, and the reciprocating slip \n180\n may be in a closed position clamping the drill string \n106\n.', 'The iron roughneck \n170\n may then move to the drill string \n106\n and make up a connection between the drill string \n106\n and the suspended tubular, as described above.', 'The reciprocating slip \n180\n may then open and the elevator \n136\n may be lowered to advance the drill string \n106\n into the wellbore \n104\n.', 'Once the drill string \n106\n has been advanced into the wellbore \n104\n such that the upper portion of the drill string \n106\n is near to the reciprocating slip \n180\n, the reciprocating slip \n180\n may be closed to clamp the drill string \n106\n, and the elevator \n136\n may be opened to release the drill string \n106\n.', 'The process may be repeated until the drill string \n106\n is advanced into the wellbore \n104\n such that the drill bit \n110\n contacts the bottom of the wellbore \n104\n.', 'The grabber of the top drive \n116\n may clamp the upper tubular of the drill string \n106\n, and the drive shaft \n132\n may be driven to make up a connection with the drill string \n106\n.', 'The grabber may release the tubular, and drilling may resume.', 'A person of ordinary skill in the art will readily understand that a drilling system may include more or fewer components than what was described above and depicted in \nFIG.', '1\n.', 'Additionally, various components and/or systems of the drilling system \n100\n in \nFIG.', '1\n may include more or fewer components.', 'For example, various engines, motors, hydraulics, actuators, valves, or the like that were not described with respect to or depicted in \nFIG.', '1\n may be included in different components and/or systems; however, such components are within the scope of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of a control system \n200\n for the drilling system \n100\n according to one or more aspects of the present disclosure.', 'The control system \n200\n may include a rig computing resource environment \n205\n, which may be located onsite at the drilling rig \n111\n.', 'The rig computing resource environment \n205\n may include a coordinated control device \n204\n and/or a supervisory control system \n207\n.', 'The control system \n200\n may include a remote computing resource environment \n206\n, which may be located offsite from the drilling rig \n111\n.', 'The remote computing resource environment \n206\n may include computing resources locating offsite from the drilling rig \n111\n and accessible over a network.', 'A “cloud” computing environment is one example of a remote computing resource.', 'The cloud computing environment may communicate with the rig computing resource environment \n205\n via a network connection (e.g., a WAN or LAN connection).', 'Further, the drilling rig \n111\n may include various systems with different sensors and equipment for performing operations of the drilling rig \n111\n, and may be monitored and controlled via the control system \n200\n, e.g., the rig computing resource environment \n205\n.', 'Additionally, the rig computing resource environment \n205\n may provide for secured access to rig data to facilitate onsite and offsite user devices monitoring the rig, sending control processes to the rig, and the like.', 'The various systems of the drilling rig \n111\n may include a downhole system \n210\n, a fluid system \n212\n, and a central system \n214\n.', 'The drilling rig \n111\n may also include an information technology (IT) system \n216\n.', 'The downhole system \n210\n may include, for example, a BHA, mud motors, sensors, among other examples, disposed along the drill string, and/or other drilling equipment configured to be deployed into the wellbore.', 'Accordingly, the downhole system \n210\n may refer to tools disposed in the wellbore as part of the drill string utilized to drill the well.', 'The fluid system \n212\n may include, for example, drilling mud, pumps, valves, cement, mud-loading equipment, mud-management equipment, pressure-management equipment, separators, and other fluids equipment.', 'Accordingly, the fluid system \n212\n may perform fluid operations of the drilling rig \n111\n.', 'The central system \n214\n may include a hoisting and rotating platform, top drives, rotary tables, kellys, drawworks, pumps, generators, drill pipe handling equipment, derricks, masts, substructures, and other suitable equipment.', 'Accordingly, the central system \n214\n may perform power generation and drill pipe handling, hoisting, and rotation operations.', 'The central system \n214\n may also serve as a support platform for drilling equipment and staging ground for rig operation, such as connection make up operations, among other examples.', 'The IT system \n216\n may include software, computers, and other IT equipment for implementing IT operations of the drilling rig \n111\n.', 'The control system \n200\n, via the coordinated control device \n204\n of the rig computing resource environment \n205\n, may be operable to monitor various sensors of the multiple systems \n210\n, \n212\n, \n214\n, \n216\n of the drilling rig \n111\n and provide control commands to such systems \n210\n, \n212\n, \n214\n, \n216\n, such that sensor data generated by the various sensors may be utilized to provide control commands to the systems \n210\n, \n212\n, \n214\n, \n216\n and other systems of the drilling rig \n111\n.', 'Data may can be generated by both sensors and computation, which may be utilized for coordinated control, such as for depth control.', 'For example, the control system \n200\n may collect temporally and depth aligned surface data and downhole data from the drilling rig \n111\n, and store the collected data for access onsite at the drilling rig \n111\n or offsite via the rig computing resource environment \n205\n.', 'Thus, the control system \n200\n may provide monitoring capability.', 'Additionally, the control system \n200\n may include supervisory control via the supervisory control system \n207\n.\n \nOne or more of the downhole system \n210\n, the fluid system \n212\n, and/or the central system \n214\n may be manufactured and/or operated by different vendors.', 'Hence, certain systems may not be capable of unified control (e.g., due to different protocols, restrictions on control permissions, etc.).', 'A control system \n200\n that is unified, may, however, provide control over the drilling rig \n111\n and its various systems, including the downhole system \n210\n, fluid system \n212\n, and/or central system \n214\n.\n \nFIG.', '3\n is a schematic view of an example implementation of the control system \n200\n shown in \nFIG.', '2\n according to one or more aspects of the present disclosure.', 'The rig computing resource environment \n205\n may be operable to communicate with offsite devices and systems utilizing a network \n208\n (e.g., a wide area network (WAN) such as the internet).', 'The rig computing resource environment \n205\n may be further operable to communicate with the remote computing resource environment \n206\n via the network \n208\n.', 'FIG.', '3\n also shows the aforementioned systems of the drilling rig \n111\n, such as the downhole system \n210\n, the fluid system \n212\n, the central system \n214\n, and the IT system \n216\n.', 'An example implementation of the drilling rig \n111\n may include one or more onsite user devices \n218\n, such as may be communicatively connected or otherwise interact with the IT system \n216\n.', 'The onsite user devices \n218\n may be or comprise stationary user devices intended to be stationed at the drilling rig \n111\n and/or portable user devices.', 'For example, the onsite user devices \n218\n may include a desktop, a laptop, a smartphone, a personal data assistant (PDA), a tablet component, a wearable computer, or other suitable devices.', 'The onsite user devices \n218\n may be operable to communicate with the rig computing resource environment \n205\n of the drilling rig \n111\n and/or the remote computing resource environment \n206\n.', 'The control system \n200\n may further include one or more offsite user devices \n220\n.', 'The offsite user devices \n220\n may be or comprise a desktop, a laptop, a smartphone, a personal data assistant (PDA), a tablet component, a wearable computer, or other suitable devices.', 'The offsite user devices \n220\n may be operable to receive and/or transmit information (e.g., monitoring functionality) from and/or to the drilling rig \n111\n via communication with the rig computing resource environment \n205\n.', 'The offsite user devices \n220\n may provide control processes for controlling operation of the various systems \n210\n, \n212\n, \n214\n, \n216\n of the drilling rig \n111\n.', 'The offsite user devices \n220\n may be operable to communicate with the remote computing resource environment \n206\n via the network \n208\n.', 'The systems \n210\n, \n212\n, \n214\n, \n216\n of the drilling rig \n111\n may include various sensors, actuators, and controllers (e.g., programmable logic controllers (PLCs)), such as the processing device \n510\n shown in \nFIG.', '11\n.', 'The downhole system \n210\n may include sensors \n222\n, actuators \n224\n, and controllers \n226\n, the fluid system \n212\n may include sensors \n228\n, actuators \n230\n, and controllers \n232\n, and the central system \n214\n may include sensors \n234\n, actuators \n236\n, and controllers \n238\n.', 'The sensors \n222\n, \n228\n, \n234\n may include suitable sensors for operation of the drilling rig \n111\n.', 'For example, the sensors \n222\n, \n228\n, \n234\n may include cameras, position sensors, pressure sensors, temperature sensors, flow rate sensors, vibration sensors, current sensors, voltage sensors, resistance sensors, gesture detection sensors or devices, voice actuated or recognition devices or sensors, among other examples.', 'The sensors \n222\n, \n228\n, \n234\n may be operable to provide sensor data to the rig computing resource environment \n205\n (e.g., to the coordinated control device \n204\n).', 'For example, downhole system sensors \n222\n may provide sensor data \n240\n, the fluid system sensors \n228\n may provide sensor data \n242\n, and the central system sensors \n234\n may provide sensor data \n244\n.', 'The sensor data \n240\n, \n242\n, \n244\n may include, for example, signals or information indicative of equipment operation status (e.g., on or off, up or down, set or release, etc.), drilling parameters (e.g., depth, hook load, torque, etc.), auxiliary parameters (e.g., vibration data of a pump), among other examples.', 'The acquired sensor data \n240\n, \n242\n, \n244\n may include or be associated with a timestamp (e.g., date and/or time) indicative of when the sensor data was acquired.', 'Further, the sensor data \n240\n, \n242\n, \n244\n may be aligned with a depth or other drilling parameter.', 'Acquiring the sensor data \n240\n, \n242\n, \n244\n at the coordinated control device \n204\n may facilitate measurement of the same physical properties at different locations of the drilling rig \n111\n, wherein the sensor data \n240\n, \n242\n, \n244\n may be utilized for measurement redundancy to permit continued wellsite operations.', 'Measurements of the same physical properties at different locations may also be utilized for detecting equipment conditions among different physical locations at the wellsite surface or within the wellbore.', 'Variation in measurements at different wellsite locations over time may be utilized to determine equipment performance, system performance, scheduled maintenance due dates, and the like.', 'For example, slip status (e.g., in or out) may be acquired from the sensors and communicated to the rig computing resource environment \n205\n.', 'In another example implementation, acquisition of fluid samples may be measured by a sensor and related with bit depth and time measured by other sensors.', 'Acquisition of data from a camera sensor may facilitate detection of arrival and/or installation of materials or equipment at the drilling rig \n111\n.', 'The time of arrival and/or installation of materials or equipment may be utilized to evaluate degradation of material, scheduled maintenance of equipment, and other evaluations.', 'The coordinated control device \n204\n may facilitate control of individual systems (e.g., the central system \n214\n, the downhole system, or fluid system \n212\n) at the level of each individual system.', 'For example, in the fluid system \n212\n, sensor data \n228\n may be fed into the controller \n232\n, which may respond to control the actuators \n230\n.', 'However, for control operations that involve multiple systems, the control may be coordinated through the coordinated control device \n204\n.', 'For example, coordinated control operations may include the control of downhole pressure during tripping.', 'The downhole pressure may be affected by both the fluid system \n212\n (e.g., pump rate and choke position) and the central system \n214\n (e.g. tripping speed).', 'Thus, when it is intended to maintain certain downhole pressure during tripping, the coordinated control device \n204\n may be utilized to direct the appropriate control commands.', 'Control of the various systems \n210\n, \n212\n, \n214\n of the drilling rig \n111\n may be provided via a three-tier control system that includes a first tier of the controllers \n226\n, \n232\n, \n238\n, a second tier of the coordinated control device \n204\n, and a third tier of the supervisory control system \n207\n.', 'Coordinated control may also be provided by one or more controllers \n226\n, \n232\n, \n238\n of one or more of the drilling rig systems \n210\n, \n212\n, \n214\n without the use of a coordinated control device \n204\n.', 'In such implementations of the control system \n200\n, the rig computing resource environment \n205\n may provide control processes directly to these controllers \n226\n, \n232\n, \n238\n for coordinated control.', 'The sensor data \n240\n, \n242\n, \n244\n may be received by the coordinated control device \n204\n and utilized for control of the drilling rig \n111\n and the drilling rig systems \n210\n, \n212\n, \n214\n.', 'The sensor data \n240\n, \n242\n, \n244\n may be encrypted to produce encrypted sensor data \n246\n.', 'For example, in some embodiments, the rig computing resource environment \n205\n may encrypt sensor data from different types of sensors and systems to produce a set of encrypted sensor data \n246\n.', 'Thus, the encrypted sensor data \n246\n may not be viewable by unauthorized user devices (either offsite user device \n220\n or onsite user device \n218\n) if such devices gain access to one or more networks of the drilling rig \n111\n.', 'The encrypted sensor data \n246\n may include a timestamp and an aligned drilling parameter (e.g., depth) as described above.', 'The encrypted sensor data \n246\n may be communicated to the remote computing resource environment \n206\n via the network \n208\n and stored as encrypted sensor data \n248\n.', 'The rig computing resource environment \n205\n may provide the encrypted sensor data \n248\n available for viewing and processing offsite, such as via the offsite user devices \n220\n.', 'Access to the encrypted sensor data \n248\n may be restricted via access control implemented in the rig computing resource environment \n205\n.', 'The encrypted sensor data \n248\n may be provided in real-time to offsite user devices \n220\n such that offsite personnel may view real-time status of the drilling rig \n111\n and provide feedback based on the real-time sensor data.', 'For example, different portions of the encrypted sensor data \n246\n may be sent to the offsite user devices \n220\n.', 'The encrypted sensor data \n246\n may be decrypted by the rig computing resource environment \n205\n before transmission or decrypted on the offsite user device \n220\n after encrypted sensor data is received.', 'The offsite user device \n220\n may include a thin client (not shown) configured to display data received from the rig computing resource environment \n205\n and/or the remote computing resource environment \n206\n.', 'For example, multiple types of thin clients (e.g., devices with display capability and minimal processing capability) may be utilized for certain functions or for viewing various sensor data \n240\n, \n242\n, \n244\n.', 'The rig computing resource environment \n205\n may include various computing resources utilized for monitoring and controlling operations such as one or more computers having a processor and a memory.', 'For example, the coordinated control device \n204\n may include a processing device, such as the processing device \n510\n shown in \nFIG.', '11\n, having a processor and memory for processing sensor data, storing sensor data, and issuing control commands responsive to sensor data.', 'As described above, the coordinated control device \n204\n may control various operations of the various systems \n210\n, \n212\n, \n214\n of the drilling rig \n111\n via analysis of sensor data \n240\n, \n242\n, \n244\n from one or more drilling rig systems \n210\n, \n212\n, \n214\n to facilitate coordinated control between each of these systems \n210\n, \n212\n, \n214\n.', 'The coordinated control device \n204\n may execute control commands \n250\n (e.g., coded instructions) for control of the various systems of the drilling rig \n111\n (e.g., drilling rig systems \n210\n, \n212\n, \n214\n).', 'The coordinated control device \n204\n may send control signals or data determined by the execution of the control commands \n250\n to one or more systems of the drilling rig \n111\n.', 'For example, control data \n252\n may be sent to the downhole system \n210\n, control data \n254\n may be sent to the fluid system \n212\n, and control data \n254\n may be sent to the central system \n214\n.', 'The control data may include, for example, human operator commands (e.g., turn on or off a pump, switch on or off a valve, update a physical property set-point, etc.).', 'The coordinated control device \n204\n may include a fast control loop that directly obtains sensor data \n240\n, \n242\n, \n244\n and executes, for example, a control algorithm.', 'The coordinated control device \n204\n may include a slow control loop that obtains data via the rig computing resource environment \n205\n to generate control commands.', 'The coordinated control device \n204\n may intermediate between the supervisory control system \n207\n and the controllers \n226\n, \n232\n, \n238\n of the systems \n210\n, \n212\n, \n214\n, such as may permit the supervisory control system \n207\n to control the systems of the drilling rig \n111\n.', 'The supervisory control system \n207\n may include, for example, devices for entering control commands to perform operations of systems of the drilling rig \n111\n.', 'The coordinated control device \n204\n may receive commands from the supervisory control system \n207\n, process such commands according to a rule (e.g., an algorithm based upon the laws of physics for drilling operations), and provide control data to one or more systems of the drilling rig \n111\n.', 'The supervisory control system \n207\n may be provided by and/or controlled by a third party.', 'In such implementations, the coordinated control device \n204\n may coordinate control between discrete supervisory control systems and the systems \n210\n, \n212\n, \n214\n while utilizing control commands that may be generated based on the sensor data received from the systems \n210\n \n212\n, \n214\n and analyzed via the rig computing resource environment \n205\n.', 'The rig computing resource environment \n205\n may include a monitoring process \n241\n that may utilize sensor data \n240\n, \n242\n, \n244\n to determine information about the drilling rig \n111\n.', 'For example, the monitoring process \n241\n may determine a drilling state, equipment health, system health, a maintenance schedule, or combination thereof.', 'The rig computing resource environment \n205\n may also include a control process \n243\n that may utilize the sensor data \n240\n, \n242\n, \n244\n to optimize drilling operations, such as, for example, the control of drilling equipment to improve drilling efficiency, equipment reliability, and the like.', 'For example, the acquired sensor data \n242\n may be utilized to derive a noise cancellation scheme to improve electromagnetic and mud pulse telemetry signal processing.', 'The remote computing resource environment \n206\n may include a control process \n245\n substantially similar to the control process \n243\n that may be provided to the rig computing resource environment \n205\n.', 'The monitoring and control processes \n241\n, \n243\n, \n245\n may be implemented via, for example, a control algorithm, a computer program, firmware, or other suitable hardware and/or software.', 'The rig computing resource environment \n205\n may include various computing resources, such as, for example, a single computer or multiple computers.', 'The rig computing resource environment \n205\n may further include a virtual computer system and a virtual database or other virtual structure for collected data, such as may include one or more resource interfaces (e.g., web interfaces) that facilitate the submission of application programming interface (API) calls to the various resources through a request.', 'In addition, each of the resources may include one or more resource interfaces that facilitate the resources to access each other (e.g., to facilitate a virtual computer system of the computing resource environment to store data in or retrieve data from the database or other structure for collected data).', 'The virtual computer system may include a collection of computing resources configured to instantiate virtual machine instances.', 'A user may interface with the virtual computer system via the offsite user device \n220\n or the onsite user device \n218\n.', 'Other computer systems or computer system services may be utilized in the rig computing resource environment \n205\n, such as a computer system or computer system service that provides computing resources on dedicated or shared computers/servers and/or other physical devices.', 'The rig computing resource environment \n205\n may include a single server (in a discrete hardware component or as a virtual server) or multiple servers (e.g., web servers, application servers, or other servers).', 'The servers may be, for example, computers arranged in physical and/or virtual configuration.', 'The rig computing resource environment \n205\n may also include a database that may be or comprise a collection of computing resources that run one or more data collections.', 'Such data collections may be operated and managed by utilizing API calls.', 'The data collections, such as sensor data \n240\n, \n242\n, \n244\n, may be made available to other resources in the rig computing resource environment \n205\n or to user devices (e.g., onsite user device \n218\n and/or offsite user device \n220\n) accessing the rig computing resource environment \n205\n.', 'The remote computing resource environment \n206\n may include similar computing resources to those described above, such as a single computer or multiple computers (in discrete hardware components or virtual computer systems).', 'FIG.', '4\n is a schematic view of at least a portion of an example implementation of a tubular measuring system \n301\n of the drilling system \n100\n according to one or more aspects of the present disclosure.', 'The tubular measuring system \n301\n may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars, such as drill pipe, drill collars, and casing joints, among other examples.', 'The tubular measuring system \n301\n may be further operable to measure position, length, diameter, and/or other dimensions of one or more portions of BHA tools, such as jars, crossover tools, mud motors, among other examples.', 'The tubular measuring system \n301\n may comprise a stop or contact member \n310\n located at a distance \n314\n from a known reference position or datum \n315\n (e.g., a reference line) and configured to contact an end \n316\n of a tubular \n320\n (or a stand comprising two or more tubulars), and a contact member \n312\n configured to move toward the contact member \n310\n to contact opposing end \n318\n of the tubular \n320\n.', 'Although the end \n316\n of the tubular \n320\n is depicted as the box and the end \n318\n is depicted as the pin, it is to be understood that the tubular \n320\n may be positioned such that the pin of the tubular \n320\n may be in contact with the contact member \n310\n and the box of the tubular \n320\n may be in contact with the contact member \n312\n.', 'The tubular measuring system \n301\n may further comprise a sensor \n322\n operable to generate a signal indicative of a distance \n324\n between the datum \n315\n and the contact member \n312\n when the contact member \n310\n is in contact with the end \n316\n of the tubular \n320\n and the contact member \n312\n is in contact with the end \n318\n of the tubular \n320\n.', 'The sensor \n322\n may be or comprise a position sensor operable to generate a signal or information indicative of the distance \n324\n between the datum \n315\n and the contact member \n312\n.', 'The sensor \n322\n may be disposed in association with the datum \n315\n, the contact member \n312\n, extend between the datum \n315\n and the contact member \n312\n, or otherwise disposed such as may facilitate monitoring of the distance \n324\n.', 'The sensor \n322\n may be in signal communication with one or more processing devices (such as the processing device \n510\n shown in \nFIG.', '11\n) of the control system \n200\n.', 'The signal generated by the sensor \n322\n may be received by the processing device, which may be operable to determine length \n321\n of the tubular \n320\n based on the distance \n314\n and the signal indicative of the distance \n324\n generated by the sensor \n322\n.', 'The sensor \n322\n may be or comprise a linear encoder, a linear potentiometer, a capacitive sensor, an inductive sensor, a magnetic sensor, an optical sensor, a digital image camera, a linear variable-differential transformer (LVDT), a proximity sensor, a Hall effect sensor, and/or a reed switch, among other examples.\n \nFIG.', '5\n is an enlarged view of a portion of an example implementation of the tubular measuring system \n301\n shown in \nFIG.', '4\n according to one or more aspects of the present disclosure.', 'The tubular measuring system \n301\n may be further operable to measure the length \n326\n of a thread \n328\n of the end \n318\n of the tubular \n320\n and determine length \n323\n of the tubular \n320\n without the thread \n328\n.', 'For example, the tubular measuring system \n301\n may further comprise a contact member \n330\n operable to move into contact with a face \n332\n at the base of the thread \n328\n.', 'The tubular measuring system \n301\n may further comprise a sensor \n334\n operable to generate a signal indicative of the distance \n326\n between the contact member \n312\n and the contact member \n330\n when the contact member \n312\n is in contact with the end \n318\n of the tubular \n320\n and the contact member \n330\n is in contact with the face \n332\n.', 'The sensor \n334\n may be disposed in association with the contact member \n312\n or the datum \n315\n, the contact member \n330\n, extend between the contact member \n330\n and the contact member \n312\n, or otherwise disposed such as may facilitate monitoring of the distance \n326\n.', 'The sensor \n334\n may be or comprise a position sensor having a structure and/or mode of operation similar to the sensor \n322\n, and operable to generate a signal or information indicative of distance \n326\n between the contact member \n312\n and the contact member \n330\n.', 'The sensor \n334\n may be in signal communication with one or more processing devices (e.g., the processing device \n510\n shown in \nFIG.', '11\n) of the control system \n200\n.', 'The signal generated by the sensor \n334\n may be received by the processing device, which may be operable to determine the length \n326\n of the thread \n328\n and the length \n323\n of the tubular \n320\n by subtracting the distances \n324\n, \n326\n from the distance \n314\n.', 'In an example implementation of the tubular measuring system \n301\n, the contact member \n330\n may be omitted and the contact member \n312\n may be adapted to make contact with the face \n332\n of the tubular \n320\n, such as may permit determination of the length \n323\n without utilizing two contact members \n312\n, \n330\n.', 'From example, the contact member \n312\n may include a hole, an arm, or another structure, such as may permit the contact member \n312\n to move past the thread \n328\n and contact the face \n318\n.', 'The contact members \n310\n, \n312\n, \n330\n may be blocks, bars, or other structures supported on or along a tubular support surface \n336\n of tubular handling equipment of the drilling system \n100\n.', 'One or more of the contact members \n310\n, \n312\n, \n330\n may be selectively movable (e.g., retractable) above and below the tubular support surface \n336\n.', 'The tubular support surface \n336\n may be or form at least a portion of the catwalk \n166\n shown in \nFIG.', '1\n and/or the racks (not shown) adjoining the catwalk \n166\n, among other examples.', 'For example, the tubular support surface \n336\n may be or form at least a portion of the horizontal portion of the catwalk \n166\n, wherein the contact members \n310\n, \n312\n, \n330\n may be disposed along the groove of the horizontal portion of the catwalk \n166\n.', 'During operations of the drilling system \n100\n, after a tubular member \n320\n is transferred into the groove of the catwalk \n166\n, the stop member \n310\n may extend above the surface \n336\n on one side of the tubular member \n320\n and the contact member \n312\n may move toward the tubular member \n320\n on the opposing side of the tubular member \n320\n.', 'Initially, the distance between the contact members \n310\n, \n312\n may be larger than the expected maximum length \n321\n of the tubular \n320\n.', 'For example, the overall distance may initially be larger than the nominal length \n321\n of the tubular \n320\n plus a tolerance (e.g., between about 1% and about 10% of the length \n321\n).', 'Such tolerance may ensure that the tubular \n320\n is capable of being received between the contact members \n310\n, \n312\n.', 'If the end \n316\n of the tubular member \n320\n is not in contact with the contact member \n310\n, the contact member \n312\n may push the tubular member \n320\n until the end \n316\n contacts the contact member \n310\n.', 'Once the contact members \n310\n, \n312\n are in contact with opposing sides of the tubular \n320\n, one or more processing devices of the control system \n200\n may receive a signal from the sensor \n322\n to determine the length \n324\n.', 'The control system \n200\n may then determine the length \n321\n of the tubular \n320\n, by subtracting the length \n324\n from the known length \n314\n.', 'The control system \n200\n may also cause the contact member \n330\n to move into contact with the face \n332\n of the tubular \n320\n.', 'Once the contact member \n330\n is in contact with the face \n332\n, one or more processing devices of the control system \n200\n may receive a signal from the sensor \n334\n to determine the length \n326\n.', 'The control system \n200\n may then determine the length \n323\n of the tubular \n320\n, by subtracting the length \n326\n from the length \n321\n.', 'Once the length measurements are performed, the contact member \n310\n may be caused to retract below the surface \n336\n and the contact member \n312\n may push the tubular \n320\n further along the catwalk \n166\n, as described above.', 'In the example implementation of the tubular measuring system \n301\n, the skate \n168\n of the catwalk \n166\n may be or comprise the contact member \n312\n.', 'The distance \n314\n between the contact member \n310\n and the datum \n315\n may be measured with a high-degree of precision, as both the contact member \n310\n and the datum \n315\n may be set at fixed positions.', 'Furthermore, the distances \n324\n, \n326\n may be substantially less than the lengths \n321\n, \n323\n and the fixed distance \n314\n by an order of magnitude (e.g., 1-3 feet in comparison to 10-30 feet) or more such that the lengths \n321\n, \n323\n are substantially close in length to the distance \n314\n.', 'Thus, errors in the determined lengths \n321\n, \n323\n may be based on the distances \n324\n, \n326\n and may be an order of magnitude or more smaller than if the errors were based on measurements of the length \n321\n, \n323\n of the entire tubular \n320\n.', 'For example, the distance \n324\n, \n326\n may be between about 1% and about 20% (i.e., between about five and about one hundred times smaller than) of one or more of the distance \n314\n and lengths \n321\n, \n323\n.', 'Accordingly, errors in the determined lengths \n321\n, \n323\n may also be reduced by a factor ranging between about five and about one hundred.', 'It is to be understood that the tubular measurement system \n301\n may also be utilized to measure stands (such as stands \n340\n shown in \nFIGS.', '6-9\n) comprising two or more tubulars \n320\n.', 'The ability to measure the lengths \n321\n, \n323\n of individual tubulars \n320\n or stands \n340\n with increased accuracy may facilitate an increased accuracy in keeping track or otherwise measuring length of an entire tubular string as it is assembled and deployed downhole.', 'Although \nFIGS. 4 and 5\n show the tubular measuring system \n301\n utilized to measure the tubular \n320\n while oriented horizontally, it is to be understood that the tubular measuring system \n301\n may be utilized to measure the tubular \n320\n while oriented vertically.', 'For example, the tubular measuring system \n301\n may be incorporated into or form at least a portion of the fingerboard \n184\n, such as may permit the tubular measuring system \n301\n to measure the tubular \n320\n while stored vertically within the fingerboard \n184\n.', 'Another example implementation of the tubular measuring system may be incorporated within or form at least a portion of an earthen rat hole.', 'FIG.', '6\n is a schematic view of a portion of an example implementation of a tubular measuring system \n302\n located at least partially within a rat hole \n338\n of the drilling system \n100\n according to one or more aspects of the present disclosure.', 'The tubular measuring system \n302\n may comprise one or more similar features of the tubular measuring system \n301\n, including where indicated by like reference numbers.', 'A tubular or a tubular stand \n340\n, comprising two or more tubulars \n320\n, may be positioned in the rat hole \n338\n such that the end \n318\n (i.e., the pin end) may contact a pipe stop or another contact member \n342\n positioned at a known depth or position in the rat hole \n338\n.', 'The contact member \n342\n may include a central opening \n343\n, such as may receive the threads \n328\n and permit the face \n332\n to contact the contact member \n342\n.', 'A movable block \n346\n may engage the stand \n340\n at or above a top surface \n348\n of the rat hole \n338\n.', 'The movable bock \n346\n may be or comprise a pivotable cover, tongs, and/or another structure configured to engage the stand \n340\n at a set distance.', 'A distance \n344\n between the top surface \n348\n (or the movable block \n346\n) and the pipe stop \n342\n may be known with a high degree of precision (e.g., may be a generally fixed or static distance).', 'A distance \n350\n between top of end \n316\n (e.g., the box end) and the top surface \n348\n (or the movable block \n346\n) may then be determined.', 'One or more centralizers \n339\n may be utilized within the rat hole \n338\n to help maintain the stand \n340\n substantially vertical and/or centralized within the rat hole \n338\n.', 'The centralizers \n339\n may be or comprise biasing members, such as fingers, leafs springs, disks, or other flexible members, such as may be operable to bias the stand \n340\n toward a substantially vertical and/or central position within the rat hole \n338\n.', 'The distance \n350\n may be monitored via a sensor \n354\n disposed at a known position or distance \n351\n with respect to the top surface \n348\n (or the movable block \n346\n) and operable to generate a signal indicative of the distance \n350\n.', 'The distance \n351\n may be chosen or otherwise determined based on an estimated expected position of the end \n316\n (i.e., stick-up height) or otherwise disposed such as may facilitate monitoring of the distance \n350\n.', 'The sensor \n354\n may be in signal communication with one or more processing devices (such as the processing device \n510\n shown in \nFIG.', '11\n) of the control system \n200\n.', 'The signal generated by the sensor \n354\n may be received by the processing device, which may be operable to determine the distance \n350\n and, thus, length of the stand \n353\n, based on the received signal and the height \n351\n.', 'Similarly as described above with respect to the distance \n324\n, the distance \n350\n may be substantially less than the distances \n344\n, \n33\n.', 'The sensor \n354\n may be or comprise a position sensor having a structure and/or mode of operation similar to the sensor \n322\n and operable to generate a signal or information indicative of distance \n350\n between the surface \n348\n and the end \n316\n of the stand \n340\n.', 'The sensor \n354\n may also be a digital image camera utilized similarly as described below in association with tubular measuring systems \n304\n, \n305\n shown in \nFIGS.', '8 and 9\n, respectively.', 'Length \n353\n of the stand \n340\n may then be determined by adding together the distances \n344\n, \n350\n.', 'Because the measured distance \n350\n is a substantially shorter than the known distance \n344\n, errors in the determined length \n353\n may be based on the shorter measured distance \n350\n and may not include errors associated with measurement of the known distance \n344\n.', 'FIG.', '7\n is a schematic view of a portion of an example implementation of a tubular measuring system \n303\n of the drilling system \n100\n according to one or more aspects of the present disclosure.', 'The tubular measuring system \n303\n may comprise one or more similar features of the tubular measuring systems \n301\n, \n302\n, including where indicated by like reference numbers, except as described below.', 'The tubular measuring system \n303\n may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars \n320\n, stands \n340\n comprising two or more tubulars \n320\n, and other BHA tools.', 'The tubular measuring system \n303\n may comprise a contact member \n356\n operable to contact an end \n316\n of a stand \n340\n and a contact member \n358\n operable to move toward the contact member \n356\n to contact an end \n318\n of the stand \n340\n, which may be supported on or along a tubular support surface \n336\n of tubular handling equipment.', 'The contact member \n358\n may be operatively connected with or carry a sensor \n360\n operable to generate a signal indicative of a distance \n352\n between the contact members \n356\n, \n358\n when the contact member \n356\n is in contact with the end \n316\n of the stand \n340\n and the contact member \n358\n is in contact with the end \n318\n of the stand \n340\n.', 'The sensor \n360\n may be or comprise a position sensor operable to generate a signal or information indicative of the distance \n352\n between the contact members \n356\n, \n358\n.', 'The sensor \n360\n may be disposed in association with the contact member \n356\n, the contact member \n358\n, extend between the contact members \n356\n, \n358\n, or otherwise disposed such as may facilitate monitoring of the distance \n352\n.', 'The sensor \n360\n may be in signal communication with one or more processing devices (such as the processing device \n510\n shown in \nFIG.', '11\n) of the control system \n200\n.', 'The signal generated by the sensor \n360\n may be received by the processing device, which may be operable to determine the distance \n352\n and, thus, length of the stand \n340\n, based on the received signal.', 'The sensor \n360\n may be or comprise a position sensor having a structure and/or mode of operation similar to the sensor \n322\n and operable to generate a signal or information indicative of the distance \n352\n.', 'The sensor \n360\n may comprise multiple components.', 'For example, the sensor \n360\n may comprise a signal transceiver operable in conjunction with a reflector or another marker \n364\n.', 'The transceiver may be operable to transmit energy or a signal toward the marker \n364\n and receive the signal reflected by the marker \n364\n.', 'The transceiver may then generate a signal indicative of the distance \n352\n based on the received signal.', 'The sensor \n360\n may be or comprise an optical distance measurement device, such as a digital image camera.', 'The camera may be aimed at the marker \n364\n, which may contain a plurality of pixels or other images thereon.', 'The camera may be utilized to determine the distance \n352\n, for example, based on a count of the pixels occupied by the marker \n364\n in the digital image captured by the camera.', 'Similarly, the camera (or a second camera, or another optical distance measurement device) may be further utilized to determine a distance \n326\n between the face \n332\n and the contact member \n358\n.', 'For example, a captured digital image of the stand \n340\n, including the face \n332\n, may be analyzed and the distance \n326\n may be determined based on, for example, the size of the face \n332\n captured in the digital image.', 'Length \n353\n of the stand \n340\n may be determined by subtracting the length \n326\n of the threads \n328\n from the length \n352\n between the contact members \n356\n, \n358\n.', 'FIG.', '8\n is a schematic view of a portion of an example implementation of a tubular measuring system \n304\n of the drilling system \n100\n according to one or more aspects of the present disclosure.', 'The tubular measuring system \n304\n may comprise one or more similar features of the tubular measuring systems \n301\n, \n302\n, \n303\n including where indicated by like reference numbers.', 'The tubular measuring system \n304\n may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars \n320\n, stands \n340\n comprising two or more tubulars \n320\n, and other BHA tools.', 'The tubular measuring system \n304\n may comprise a contact member \n356\n operable to contact an end \n316\n of the stand \n340\n, which may be supported on or along a tubular support surface \n336\n of tubular handling equipment.', 'The tubular measuring system \n304\n may further comprise a digital image camera \n366\n positioned at a known reference position \n370\n (e.g., a reference line) at a known distance \n368\n with respect to the contact member \n356\n and directed or aimed toward the end \n318\n of the stand \n340\n, such as may permit the camera \n366\n to capture a digital image of the end \n318\n when the contact member \n356\n is in contact with the end \n316\n of the stand \n340\n.', 'The camera \n366\n may be in signal communication with one or more processing devices (such as the processing device \n510\n shown in \nFIG.', '11\n) of the control system \n200\n.', 'The digital image generated by the camera \n366\n may be received by the processing device, which may be operable to analyze the image to determine the lengths \n352\n, \n353\n of the stand \n340\n by determining the distance \n372\n between the position \n370\n and the tip of the end \n318\n and the distance \n373\n between the position \n370\n and the face \n332\n.', 'For example, a captured digital image of the end \n318\n may be analyzed by the control system \n200\n to determine an angle \n374\n between the tip of the threads \n328\n and the position \n370\n to determine the distance \n372\n and an angle \n376\n between the face \n332\n and the position \n370\n to determine the distance \n373\n.', 'Length \n352\n of the stand \n340\n may be determined by adding the distance \n368\n and the determined distance \n372\n, and the length \n353\n of the stand \n340\n may be determined by adding the distance \n368\n and the determined distance \n373\n.', 'The length \n326\n of the threads \n328\n may be determined by subtracting the distance \n373\n from the distance \n372\n.', 'Similarly as described above with respect to the relationship between the distance \n324\n and the distance \n314\n and lengths \n321\n, \n323\n, the measured distances \n372\n, \n373\n may be substantially less than the known distance \n368\n and lengths \n352\n, \n353\n.', 'Accordingly, errors in the determined lengths \n352\n, \n353\n may be based on the shorter measured distances \n372\n, \n373\n.', 'FIG.', '9\n is a schematic view of a portion of an example implementation of a tubular measuring system \n305\n of the drilling system \n100\n according to one or more aspects of the present disclosure.', 'The tubular measuring system \n305\n may comprise one or more similar features of the tubular measuring systems \n301\n, \n302\n, \n303\n, \n304\n including where indicated by like reference numbers.', 'The tubular measuring system \n305\n may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars \n320\n, stands \n340\n comprising two or more tubulars \n320\n, and other BHA tools.', 'The tubular measuring system \n305\n may comprise a contact member \n356\n operable to contact an end \n316\n of a stand \n340\n, which may be supported on or along a tubular support surface \n336\n of tubular handling equipment.', 'The tubular measuring system \n305\n may further comprise a source \n378\n of electromagnetic radiation or other signals or energy \n380\n positioned at a known reference position \n382\n (e.g., reference line) at a known distance \n384\n with respect to the contact member \n356\n.', 'The tubular measuring system \n305\n may further comprise a sensor surface or another receiver \n386\n located at the position \n382\n and operable to detect the radiation or signals transmitted by the source \n378\n.', 'The source \n378\n and the receiver \n386\n may be disposed on opposing sides of the end \n318\n of the stand \n340\n, such as may permit the radiation or signals \n380\n transmitted by the source \n378\n to be partially blocked by the end \n318\n and, thus, form a shadow image or profile \n388\n of the end \n318\n upon the receiver \n386\n.', 'The source \n378\n may be operable to emit and the receiver \n386\n may be operable to detect signals or energy such as electromagnetic radiation, light, infrared radiation, ultraviolet radiation, ultrasonic waves, electromagnetism, sonic waves, among other examples.', 'The receiver \n386\n may generate a signal or information indicative of the profile \n388\n and, thus, dimensions and/or relative positions of various portions of the end \n318\n when the contact member \n356\n is in contact with the end \n316\n of the stand \n340\n.', 'The receiver \n386\n may be in signal communication with one or more processing devices (such as the processing device \n510\n shown in \nFIG.', '11\n) of the control system \n200\n.', 'The signal generated by the receiver \n386\n may be received by the processing device, which may be operable to analyze the signal to determine the dimensions of the end \n318\n, including the length \n326\n of the thread \n328\n.', 'The processing device may further utilize the received signals to determine distance \n390\n between the position \n382\n and the tip of the thread \n328\n and distance \n392\n between the position \n382\n and the face \n332\n.', 'Length \n352\n of the stand \n340\n may be determined by subtracting the determined distance \n390\n from the known distance \n384\n, and length \n353\n of the stand \n340\n may be determined by subtracting the determined distance \n392\n from the known distance \n384\n.', 'Similarly as described above with respect to the relationship between the distances \n324\n, \n326\n and the distance \n314\n and lengths \n321\n, \n323\n, the measured distances \n390\n, \n392\n may be substantially less than the known distance \n384\n and lengths \n352\n, \n353\n.', 'Accordingly, errors in the determined lengths \n352\n, \n353\n may be based on the shorter measured distances \n390\n, \n392\n.', 'Instead of the receiver \n386\n being or comprising a sensor operable to generate a signal or information based on the profile \n388\n, the receiver \n386\n may be or comprise a simple screen or surface upon which the shadow image or profile \n388\n may be formed.', 'A digital image camera \n366\n may be positioned at a known reference position \n370\n at a known distance \n368\n with respect to the contact member \n356\n and directed or aimed toward the receiver \n386\n.', 'The camera \n366\n may be operated to capture a digital image of the profile \n388\n when the contact member \n356\n is in contact with the end \n316\n of the stand \n340\n.', 'The captured digital image of the profile \n388\n may then be analyzed by the control system \n200\n to determine the distances \n352\n, \n353\n of the stand \n340\n, as described above.', 'The length \n352\n of the stand \n340\n may be determined by adding the determined distance \n372\n to the known distance \n368\n, and the length \n353\n of the stand \n340\n may be determined by adding the determined distance \n373\n to the known distance \n368\n.', 'Similarly as described above with respect to the relationship between the distances \n324\n, \n326\n and the distance \n314\n and lengths \n321\n, \n323\n, the measured distances \n372\n, \n373\n may be substantially less than the known distance \n368\n and lengths \n352\n, \n353\n.', 'Accordingly, errors in the determined lengths \n352\n, \n353\n may be based on the shorter measured distances \n372\n, \n373\n.', 'Similarly to the tubular measuring system \n301\n shown in \nFIGS. 1 and 2\n, the tubular measuring systems \n303\n, \n304\n, \n305\n shown in \nFIGS.', '7-9\n may be incorporated as a part of or form at least a portion of a piece of tubular handling equipment of the drilling system \n100\n.', 'The contact members \n356\n may be blocks, bars, or other structures supported on or along a tubular support surface \n336\n of tubular handling equipment of the drilling system \n100\n.', 'The contact members \n356\n may be selectively movable (e.g., retractable) above and below the tubular support surface \n336\n.', 'The tubular support surface \n336\n may be or form at least a portion of the catwalk \n166\n shown in \nFIG.', '1\n and/or the racks (not shown) adjoining the catwalk \n166\n, among other examples.', 'For example, the tubular support surface \n336\n may be or form at least a portion of the horizontal portion of the catwalk \n166\n and the contact member \n356\n may be or form at least a portion of the skate \n168\n of the catwalk \n166\n.', 'During operations of the drilling system \n100\n, the tubular stand \n340\n may be transferred into the groove of the catwalk \n166\n such that the end \n316\n is in contact with the contact member \n356\n.', 'If the sensor \n360\n is utilized, the contact member \n358\n may move toward the tubular stand \n340\n into contact with the end \n318\n.', 'Once the contact members \n356\n and/or \n358\n are in contact with the tubular stand \n340\n, the sensor \n360\n, \n366\n and the processing device may be utilized to determine the length of the thread \n326\n and/or the lengths \n352\n, \n353\n of the stand \n340\n.', 'The tubular measuring systems \n303\n, \n304\n, \n305\n may also be utilized to measure the lengths \n326\n, \n352\n, \n353\n while the stand \n340\n is oriented vertically.', 'For example, the tubular measuring systems \n303\n, \n304\n, \n305\n may be incorporated as a part of or form at least a portion of the fingerboard \n184\n or another piece of the tubular handling equipment of the drilling system \n100\n.', 'FIG.', '10\n is a schematic view of a portion of an example implementation of a tubular measuring system \n400\n of the drilling system \n100\n according to one or more aspects of the present disclosure.', 'The tubular measuring system \n400\n may comprise one or more similar features of the tubular measuring systems \n301\n-\n305\n, including where indicated by like reference numbers, except as described below.', 'The tubular measuring system \n400\n may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars \n320\n or stands \n340\n comprising two or more tubulars \n320\n.', 'The tubular measuring system \n400\n may utilize one or more digital image cameras positioned at or along known reference positions \n402\n, \n404\n (e.g., reference lines) of the drilling system \n100\n at known distances \n406\n, \n408\n with respect to a predetermined datum, such as a rig floor \n112\n of the drilling system \n100\n.', 'For example, an upper camera \n366\n may be supported along a mast \n114\n (shown in \nFIG.', '1\n) and directed or aimed toward a top drive \n116\n, including the elevator \n136\n.', 'Such positioning and direction may permit the upper camera \n366\n to capture digital images of upper ends \n316\n of tubulars \n320\n (or stands \n340\n) and various portions of the top drive \n116\n as the tubulars \n320\n are lifted by the elevator \n116\n and the upper ends \n316\n are engaged by a drive shaft \n132\n to rotate the tubular \n320\n during tubular running (e.g., drilling) operations.', 'A lower camera \n367\n may also or instead be supported along the rig floor \n112\n and directed or aimed toward a lower end \n318\n of a suspended tubular \n320\n and an upper end \n316\n of a tubular \n320\n extending into a wellbore \n104\n and above the rig floor \n112\n (i.e., stick-up).', 'Such positioning and direction may permit the lower camera \n366\n to capture digital images of various portions of the ends \n316\n, \n318\n prior to and as the ends \n316\n, \n318\n are made up during tubular running operations.', 'The cameras \n366\n, \n367\n may be in signal communication with one or more processing devices (such as the processing device \n510\n shown in \nFIG.', '11\n) of the control system \n200\n.', 'The digital images generated by the cameras \n366\n, \n367\n may be received by the processing device, which may be operable to analyze the images to determine positions of various portions of the tubulars \n320\n and/or portions of the top drive \n116\n.', 'For example, the digital images captured by the upper camera \n366\n may be analyzed by the control system \n200\n to determine the position of the drive shaft \n132\n and/or the position of the upper end \n316\n of the tubular \n320\n.', 'Similarly as described above, the digital images captured by the upper camera \n366\n may be analyzed to determine an angle between the drive shaft \n132\n and the position \n402\n of the upper camera \n366\n to determine distance \n410\n, and to determine an angle between the upper end \n316\n and the position \n402\n to determine distance \n412\n.', 'Position of the drive shaft \n132\n, identified as distance \n414\n with respect to the rig floor \n112\n, may be determined by adding the determined distance \n410\n and the known distance \n406\n.', 'Position of the top end \n316\n, identified as distance \n416\n with respect to the rig floor \n112\n, may be determined by subtracting the determined distance \n412\n from the known distance \n406\n.', 'The digital images captured by the lower camera \n367\n may be analyzed by the control system \n200\n to determine the position of the lower end \n318\n of the tubular \n320\n being moved by the elevator \n136\n and/or the position of the upper end \n316\n of the tubular \n320\n partially deployed within the wellbore \n104\n.', 'Similarly as described above, a digital image captured by the lower camera \n367\n may be analyzed to determine an angle between the face \n332\n and the position \n404\n of the lower camera \n367\n to determine distance \n418\n, to determine an angle between the tip of the threads \n328\n and the position \n404\n to determine distance \n420\n, and to determine an angle between the upper end \n316\n and the position \n404\n to determine distance \n422\n.', 'Position of the face \n332\n of the lower end \n318\n, identified as distance \n423\n with respect to the rig floor \n112\n, may be determined by adding the determined distance \n418\n and the known distance \n408\n.', 'Position of the top end \n316\n, identified as distance \n424\n (i.e., stick-up height) with respect to the rig floor \n112\n, may be determined by subtracting the determined distance \n422\n from the known distance \n408\n.', 'The various distances described above may be continuously determined in real-time during trip-in and trip-out operations to monitor absolute and/or relative positions of the top drive \n116\n and the tubulars \n320\n.', 'The digital images captured by the upper camera \n366\n and/or the lower camera \n367\n may be further analyzed by the control system \n200\n to determine certain dimensions of the tubular \n320\n.', 'For example, the length of the threads \n328\n may be determined by subtracting the distances \n408\n, \n420\n from the distance \n423\n.', 'The length \n323\n of the tubular \n320\n may be determined by subtracting the distance \n423\n from the distance \n416\n.', 'Diameters of certain portions of the tubular \n320\n may be determined by analyzing the digital images captured by the upper camera \n366\n and/or the lower camera \n367\n to determine angles between side surfaces of the tubular \n320\n and the positions \n402\n, \n404\n of the upper camera \n366\n and/or the lower camera \n367\n.', 'The diameters of the tubular \n320\n may be determined based on the determined angles in a similar manner utilized to determine distances between portions of the tubular \n320\n, as described above.', 'The lengths of the tubulars \n320\n and/or stands \n340\n may be continuously determined in real-time during trip-in and trip-out operations to monitor weight of the tubular string (i.e., hook load) as it is being assembled and disassembled.', 'For example, the length \n323\n of the tubular \n320\n (or length \n353\n of a stand \n340\n) may be monitored before and after pick-up of the tubular string out of slips \n180\n and compared to determine the difference in length \n323\n (i.e., stretch or strain) before and after pick-up.', 'Accordingly, based on mechanical and material properties of the tubular \n320\n and the stretch after pick-up, the weight of the tubular string may be determined.', 'Although the tubular measuring systems \n301\n-\n305\n and \n400\n shown in \nFIGS.', '1-10\n are shown measuring lengths and other dimensions of the tubular members \n320\n and', 'tubular stands \n340\n, the tubular measuring systems \n301\n-\n305\n and \n400\n may be utilized to measure lengths and other dimensions of other downhole tools, including one or more portions of a BHA, such as described above.', 'Such measuring operations may be performed in a substantially similar manner to the measuring operations described above to measure the tubular members \n320\n and the tubular stands \n340\n.', 'Various portions of the apparatuses described above and shown in \nFIGS.', '1 and 4-10\n may collectively form at least a portion of and/or be controlled by the control system \n200\n shown in \nFIGS.', '2 and 3\n.', 'FIG.', '11\n is a schematic view of a portion of an example implementation of the control system \n200\n according to one or more aspects of the present disclosure.', 'The following description refers to one or more of \nFIGS.', '1-11\n.', 'The control system \n200\n may comprise one or more processing devices \n510\n, which may be in communication with various portions of the drilling system \n100\n, including various tubular handling equipment and sensors described within the scope of the present disclosure.', 'For example, the processing device \n510\n may be in signal communication with the catwalk \n166\n, the PHM \n182\n, the top drive \n116\n, the drawworks \n124\n, the tubular handling assembly \n134\n, the sensors \n322\n, \n334\n, \n354\n, \n360\n, \n386\n, including the emitter \n378\n and the digital image cameras \n366\n, \n367\n.', 'For clarity, these and other components in communication with the processing device \n510\n will be collectively referred to hereinafter as “sensor and operated equipment.”', 'The processing device \n510\n may be operable to receive coded instructions \n532\n from the human operator and signals generated by the sensors \n322\n, \n334\n, \n354\n, \n360\n, \n386\n and the digital image cameras \n366\n, \n367\n, process the coded instructions \n532\n and the signals, and communicate control signals to the tubular handling equipment to execute the coded instructions \n532\n to implement at least a portion of one or more example methods and/or processes described herein, and/or to implement at least a portion of one or more of the example systems described herein.', 'The processing device \n510\n may be or form at least a portion of one or more of the remote computing resource environment \n206\n, the coordinated control device \n204\n, the controllers \n226\n, \n232\n, \n238\n, or other portions of the control system \n200\n described above.', 'The processing device \n510\n may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers) personal digital assistant (PDA) devices, smartphones, internet appliances, and/or other types of computing devices.', 'The processing device \n510\n may comprise a processor \n512\n, such as a general-purpose programmable processor.', 'The processor \n512\n may comprise a local memory \n514\n, and may execute coded instructions \n532\n present in the local memory \n514\n and/or another memory device.', 'The processor \n512\n may execute, among other things, the machine-readable coded instructions \n532\n and/or other instructions and/or programs to implement the example methods and/or processes described herein.', 'The programs stored in the local memory \n514\n may include program instructions or computer program code that, when executed by an associated processor, facilitate the drilling system \n100\n to perform the example methods and/or processes described herein.', 'The processor \n512\n may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples.', 'Of course, other processors from other families are also appropriate.', 'The processor \n512\n may be in communication with a main memory \n517\n, such as may include a volatile memory \n518\n and a non-volatile memory \n520\n, perhaps via a bus \n522\n and/or other communication means.', 'The volatile memory \n518\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices.', 'The non-volatile memory \n520\n may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as read-only memory, flash memory, and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n518\n and/or non-volatile memory \n520\n.', 'The processing device \n510\n may also comprise an interface circuit \n524\n.', 'The interface circuit \n524\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others.', 'The interface circuit \n524\n may also comprise a graphics driver card.', 'The interface circuit \n524\n may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.).', 'One or more of the sensor and operated equipment may be connected with the processing device \n510\n via the interface circuit \n524\n, such as may facilitate communication between the sensor and operated equipment and the processing device \n510\n.', 'One or more input devices \n526\n may also be connected to the interface circuit \n524\n.', 'The input devices \n526\n may permit the human operators to enter the coded instructions \n532\n, including control commands, operational set-points, and/or other data for use by the processor \n512\n.', 'The input devices \n526\n may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples.', 'One or more output devices \n528\n may also be connected to the interface circuit \n524\n.', 'The output devices \n528\n may be, comprise, or be implemented by display devices (e.g., a liquid crystal display (LCD), a light-emitting diode (LED) display, or cathode ray tube (CRT) display), printers, and/or speakers, among other examples.', 'The processing device \n510\n may also communicate with one or more mass storage devices \n530\n and/or a removable storage medium \n534\n, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.', 'The coded instructions \n532\n may be stored in the mass storage device \n530\n, the main memory \n517\n, the local memory \n514\n, and/or the removable storage medium \n534\n.', 'Thus, the processing device \n510\n may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor \n512\n.', 'In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (e.g., software or firmware) thereon for execution by the processor \n512\n.', 'The coded instructions \n532\n may include program instructions or computer program code that, when executed by the processor \n512\n, may cause the drilling system \n100\n to perform methods, processes, and/or routines described herein.', 'For example, the processing device \n510\n may receive, process, and record the operational set-points entered by the human operator and the signals generated by the sensors \n322\n, \n334\n, \n354\n, \n360\n, \n386\n and/or the digital image cameras \n366\n, \n367\n.', 'Based on the received operational set-points and the generated signals, the processing device \n510\n may send control signals or information to the tubular handling equipment to automatically perform and/or undergo one or more operations or routines described herein or otherwise within the scope of the present disclosure.\n \nFIG.', '12\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n600\n) according to one or more aspects of the present disclosure.', 'The method (\n600\n) may be performed utilizing or otherwise in conjunction with at least a portion of one or more implementations of one or more instances of the apparatuses shown in one or more of \nFIGS.', '1-11\n and/or otherwise within the scope of the present disclosure.', 'The method (\n600\n) may be performed manually by the human operator and/or performed or caused, at least partially, by the processing device \n510\n executing the coded instructions \n532\n according to one or more aspects of the present disclosure.', 'Thus, the following description of the method (\n600\n) also refers to apparatuses shown in one or more of \nFIGS.', '1-11\n.', 'However, the method (\n600\n) may also be performed in conjunction with implementations of one or more apparatuses other than those depicted in \nFIGS.', '1-11\n that are also within the scope of the present disclosure.', 'The method (\n600\n) includes transferring (\n605\n) a tubular \n320\n via tubular handling equipment \n124\n, \n134\n, \n136\n, \n166\n, \n182\n during oil and gas drilling operations and operating (\n610\n) a sensor \n322\n, \n334\n, \n354\n, \n360\n, \n386\n located at a predetermined position with respect to a datum \n310\n, \n342\n, \n356\n, \n112\n to generate a signal indicative of a feature of the tubular \n320\n.', 'The method (\n600\n) may further include operating (\n615\n) a processing device \n510\n having a processor \n512\n and a memory \n517\n storing computer program code \n532\n to receive the signal from the sensor \n322\n, \n334\n, \n354\n, \n360\n, \n386\n and process the received signal to determine position of the feature of the tubular \n320\n with respect to the datum \n310\n, \n342\n, \n356\n, \n112\n.', 'The tubular handling equipment may be located in association with an oil and gas drilling rig \n111\n and the sensor \n322\n, \n334\n, \n354\n, \n360\n, \n386\n may be disposed in association with the tubular handling equipment \n124\n, \n134\n, \n136\n, \n166\n, \n182\n.', 'The sensor may be a digital image camera \n366\n, and operating (\n615\n) the sensor may include generating (\n620\n) a digital image of the feature of the tubular \n320\n.', 'The signal generated by the sensor \n322\n, \n334\n, \n354\n, \n360\n, \n386\n may be a first signal and the sensor may include an emitter \n360\n, \n378\n and a receiver \n360\n, \n386\n, such that operating (\n610\n) the sensor may include (\n625\n) emitting a second signal, receiving the second signal, and generating the first signal based on the second signal.', 'Operating (\n610\n) the sensor \n322\n, \n334\n, \n354\n, \n360\n, \n386\n may further comprise directing (\n630\n) the second signal toward the feature of the tubular \n320\n to form a shadow image \n388\n of the feature of the tubular \n320\n upon the receiver \n386\n, wherein the first signal may be based on the shadow image \n388\n of the feature of the tubular \n320\n.', 'The second signal may be or include electromagnetic radiation, light, infrared radiation, electromagnetism, or ultrasonic waves.', 'The feature of the tubular \n320\n may be or include a box \n316\n or pin \n318\n of the tubular \n320\n, such that operating (\n615\n) the processing device \n510\n may include processing (\n635\n) the received signal to determine dimensions of the box \n316\n or pin \n318\n of the tubular \n320\n.', 'Furthermore, the feature of the tubular \n320\n may be or include a first end \n316\n of the tubular \n320\n and a second end \n318\n of the tubular \n320\n may be positioned at the datum \n310\n, \n342\n, \n356\n, \n112\n, such that operating (\n615\n) the processing device \n510\n may include processing (\n640\n) the received signal to determine length \n321\n, \n323\n, \n352\n, \n353\n of the tubular \n320\n.', 'Within the scope of the method (\n600\n) the sensor \n322\n, \n334\n, \n354\n, \n360\n, \n386\n may be a first sensor, the feature of the tubular \n320\n may be a first end \n316\n of the tubular, the signal may be a first signal, the predetermined position \n402\n with respect to the datum \n112\n may be a first predetermined position \n402\n with respect to the datum \n112\n.', 'Such method (\n600\n) may further include operating (\n645\n) a second sensor \n322\n, \n334\n, \n354\n, \n360\n, \n386\n located at a second predetermined position \n404\n with respect to the datum \n112\n to generate a second signal indicative of a second end \n318\n of the tubular \n320\n.', 'The method (\n600\n) may further include operating (\n650\n) the processing device \n510\n to receive the second signal from the second sensor and process the received second signal to 1) determine position \n423\n of the face \n332\n of the second end \n318\n of the tubular \n320\n with respect to the datum \n112\n, and \n2\n) determine length \n323\n of the tubular \n320\n based on the determined positions \n416\n, \n423\n of the first and second ends \n316\n, \n318\n of the tubular \n320\n.\n \nFIG.', '13\n is a flow-chart diagram of at least a portion of an example implementation of a method (\n700\n) according to one or more aspects of the present disclosure.', 'The method (\n700\n) may be performed utilizing or otherwise in conjunction with at least a portion of one or more implementations of one or more instances of the apparatuses shown in one or more of \nFIGS.', '1-11\n and/or otherwise within the scope of the present disclosure.', 'The method (\n700\n) may be performed manually by the human operator and/or performed or caused, at least partially, by the processing device \n510\n executing the coded instructions \n532\n according to one or more aspects of the present disclosure.', 'Thus, the following description of the method (\n700\n) also refers to apparatuses shown in one or more of \nFIGS.', '1-11\n.', 'However, the method (\n700\n) may also be performed in conjunction with implementations of one or more apparatuses other than those depicted in \nFIGS.', '1-11\n that are also within the scope of the present disclosure.', 'The method (\n700\n) includes measuring (\n705\n) a first distance \n314\n, \n368\n between a first point \n310\n, \n356\n and a second point \n315\n, \n370\n, positioning (\n710\n) a first end \n316\n of a downhole tool \n320\n, \n340\n in alignment with the first point \n310\n, \n356\n measuring (\n715\n) a second distance \n324\n, \n373\n between the second point \n315\n, \n370\n and a second end \n318\n of the downhole tool \n320\n, \n340\n, and determining (\n720\n) length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n based on the first \n314\n, \n368\n and second \n324\n, \n373\n distances.', 'The downhole tool \n320\n, \n340\n may be or comprises a drill pipe, a drill collar, or a casing joint.', 'The downhole tool \n320\n, \n340\n may be or comprises a portion \n109\n of a bottom hole assembly \n108\n.', 'Within the scope of the method (\n700\n), the first \n310\n, \n356\n and second \n315\n, \n370\n points may be positionally fixed and/or the second distance \n324\n, \n373\n may be substantially smaller than the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n.', 'For example, the second distance \n324\n, \n373\n may be between 1% and 20% of the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n.', 'Furthermore, measuring (\n715\n) the second distance \n324\n, \n373\n between the second point \n315\n, \n370\n and the second end \n318\n of the downhole tool \n320\n, \n340\n may comprise operating (\n725\n) a sensor \n322\n, \n366\n to generate a signal indicative of the second distance \n324\n, \n373\n.', 'The sensor may be or comprises a digital image camera \n366\n.', 'Determining (\n720\n) the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n based on the first \n314\n, \n368\n and second \n324\n, \n373\n distances may comprise operating (\n730\n) a processing device \n510\n comprising a processor \n512\n and a memory storing computer program code \n532\n to determine the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n based on the first distance \n314\n, \n368\n and the signal generated by the sensor \n322\n, \n366\n.', 'The method (\n700\n) may be performed at an oil and/or gas drilling wellsite \n100\n.', 'Accordingly, positioning (\n710\n) the first end of the downhole tool \n316\n in alignment with the first point \n310\n, \n356\n and measuring (\n715\n) the second distance \n324\n, \n373\n between the second point \n315\n, \n370\n and the second end \n318\n of the downhole tool \n320\n, \n340\n may be performed in conjunction with tubular handling equipment \n116\n, \n124\n, \n134\n, \n166\n, \n182\n, such as a catwalk \n166\n, of an oil and/or gas drilling rig \n111\n at the wellsite \n100\n or in conjunction with a rat hole \n338\n at the wellsite \n100\n.', 'If the first distance \n314\n, \n368\n is greater than the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n, determining (\n720\n) the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n based on the first \n314\n, \n368\n and second \n324\n, \n373\n distances may comprise determining the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n by calculating (\n735\n) the difference between the first \n314\n, \n368\n and second \n324\n, \n373\n distances.', 'However, if the first distance \n314\n, \n368\n is less than the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n, determining (\n720\n) the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n based on the first \n314\n, \n368\n and second \n324\n, \n373\n distances comprises determining the length \n321\n, \n352\n of the downhole tool \n320\n, \n340\n by calculating (\n740\n) the sum of the first \n314\n, \n368\n and second \n324\n, \n373\n distances.', 'A contact member \n310\n, \n356\n may be aligned with the first point \n310\n, \n356\n, wherein positioning (\n710\n) the first end \n316\n of the downhole tool \n320\n, \n340\n in alignment with the first point \n310\n, \n356\n may comprise positioning (\n745\n) the first end \n316\n of the downhole tool \n320\n, \n340\n in contact with the contact member \n310\n, \n356\n.', 'The contact member \n310\n may be a first contact member \n310\n.', 'Accordingly, the method (\n700\n) may further comprise positioning (\n750\n) a second contact member \n312\n in contact with the second end \n318\n of the downhole tool \n320\n, \n340\n such that measuring (\n715\n) the second distance \n324\n between the second point \n315\n and the second end \n318\n of the downhole tool \n320\n, \n340\n comprises measuring (\n755\n) the second distance \n324\n between the second point \n315\n and the second contact member \n312\n.', 'The second end \n318\n of the downhole tool \n320\n, \n340\n may comprise a pin end \n318\n having a thread \n328\n and a face \n332\n at a base of the thread \n328\n.', 'Thus, positioning (\n750\n) the second contact member \n312\n in contact with the second end \n318\n of the downhole tool \n320\n, \n340\n may comprise positioning (\n760\n) the second contact member \n318\n in contact with the face \n332\n of the pin end \n318\n of the downhole tool \n320\n, \n340\n.', 'The method (\n700\n) may further comprise measuring (\n765\n) a length \n326\n of the thread \n328\n, such as by operating (\n770\n) a sensor \n334\n, \n366\n, \n378\n, \n386\n to generate a signal indicative of the length \n326\n of the thread \n328\n.', 'The sensor \n334\n, \n366\n, \n378\n, \n386\n may be or comprise a digital image camera \n366\n.', 'The signal may be a first signal and the sensor \n378\n, \n386\n may comprise an emitter \n378\n operable to emit a second signal \n380\n and a receiver \n386\n operable to receive the second signal \n380\n and generate the first signal based on the second signal \n380\n.', 'The second signal \n380\n may comprise one or more of light, electromagnetic radiation, infrared radiation, and ultrasonic waves.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art should readily recognize that the present disclosure introduces a method comprising: measuring a first distance between a first point and a second point; positioning a first end of a downhole tool in alignment with the first point; measuring a second distance between the second point and a second end of the downhole tool; and determining length of the downhole tool based on the first and second distances.', 'The downhole tool may be or comprise a drill pipe, a drill collar, or a casing joint.', 'The downhole tool may be or comprise a portion of a bottom hole assembly.', 'The first and second points may be positionally fixed.', 'The second distance may be substantially smaller than the length of the downhole tool.', 'The second distance may be between 1% and 20% of the length of the downhole tool.', 'Measuring the second distance between the second point and the second end of the downhole tool may comprise operating a sensor to generate a signal indicative of the second distance.', 'In such implementations, among others within the scope of the present disclosure, the sensor may be or comprise a digital image camera.', 'Determining the length of the downhole tool based on the first and second distances may comprise operating a processing device comprising a processor and a memory storing computer program code to determine the length of the downhole tool based on the first distance and the signal generated by the sensor.', 'The method may be performed at an oil and/or gas drilling wellsite.', 'For example, positioning the first end of the downhole tool in alignment with the first point and measuring the second distance between the second point and the second end of the downhole tool may be performed in conjunction with tubular handling equipment of an oil and/or gas drilling rig at the wellsite.', 'Positioning the first end of the downhole tool in alignment with the first point and measuring the second distance between the second point and the second end of the downhole tool may be performed in conjunction with a catwalk of an oil and/or gas drilling rig at the wellsite.', 'Positioning the first end of the downhole tool in alignment with the first point and measuring the second distance between the second point and the second end of the downhole tool may be performed in conjunction with a rat hole at the wellsite.', 'If the first distance is greater than the length of the downhole tool, determining the length of the downhole tool based on the first and second distances may comprise determining the length of the downhole tool by calculating the difference between the first and second distances.', 'If the first distance is less than the length of the downhole tool, determining the length of the downhole tool based on the first and second distances may comprise determining the length of the downhole tool by calculating the sum of the first and second distances.', 'A contact member may be aligned with the first point, and positioning the first end of the downhole tool in alignment with the first point may comprise positioning the first end of the downhole tool in contact with the contact member.', 'In such implementations, among others within the scope of the present disclosure, the contact member may be a first contact member, the method may further comprise positioning a second contact member in contact with the second end of the downhole tool, and measuring the second distance between the second point and the second end of the downhole tool may comprise measuring the second distance between the second point and the second contact member.', 'The second end of the downhole tool may comprise a pin end having a thread and a face at a base of the thread, and positioning the second contact member in contact with the second end of the downhole tool may comprise positioning the second contact member in contact with the face of the pin end of the downhole tool.', 'The second end of the downhole tool may comprise a pin end having a thread, and the method may further comprise measuring a length of the thread.', 'Measuring the length of the thread may comprise operating a sensor to generate a signal indicative of the length of the thread.', 'The sensor may be or comprise a digital image camera.', 'The signal may be a first signal, and the sensor may comprise: an emitter operable to emit a second signal; and a receiver operable to receive the second signal and generate the first signal based on the second signal.', 'The second signal may comprise light, electromagnetic radiation, infrared radiation, and/or ultrasonic waves.', 'The present disclosure also introduces an apparatus comprising a tubular measuring system comprising: a sensor disposed at a predetermined location with respect to a datum, wherein the sensor is operable to generate a signal indicative of a tubular feature position relative to the sensor; and a processing device comprising a processor and a memory storing computer program code, wherein the processing device is operable to receive and process the signal to determine position of the tubular feature with respect to the datum.', 'The tubular may be a drill pipe, a drill collar, or a casing joint.', 'The tubular may be or comprise a downhole tool.', 'The tubular measuring system may be located at an oil and/or gas drilling wellsite.', 'In such implementations, among others within the scope of the present disclosure, the sensor may be operable in conjunction with tubular handling equipment of an oil and/or gas drilling rig at the wellsite.', 'The sensor may be operable in conjunction with a catwalk of an oil and/or gas drilling rig at the wellsite.', 'The sensor may be operable in conjunction with a rat hole at the wellsite.', 'The sensor may be or comprise a digital image camera operable to generate a digital image of the tubular feature.', 'The signal may be a first signal, and the sensor may comprise: an emitter operable to emit a second signal; a receiver operable to receive a third signal resulting from interaction between the second signal and the tubular feature, wherein the first signal is or comprises the third signal.', 'The signal may be a first signal, and the sensor may comprise: an emitter operable to emit a second signal; a receiver operable to receive a third signal resulting from interaction between the second signal and the tubular feature; and a processor operable to generate the first signal based on the third signal.', 'The second and third signals may each comprise light.', 'In such implementations, among others within the scope of the present disclosure, the first signal may be not comprise light.', 'The emitter may be operable to direct the light toward the tubular feature such that the third signal comprises a shadow image of the tubular feature.', 'The second and third signals may each be electromagnetic radiation.', 'In such implementations, among others within the scope of the present disclosure, the first signal may not be electromagnetic radiation.', 'The second and third signals may each be infrared.', 'In such implementations, among others within the scope of the present disclosure, the first signal may not be infrared.', 'The second and third signals may each be ultrasonic.', 'In such implementations, among others within the scope of the present disclosure, the first signal may not be ultrasonic.', 'The tubular feature may be a box or pin end connector of the tubular, and the processing device may be further operable to process the signal to determine a dimension of the box or pin end connector.', 'The tubular feature may be a first end of the tubular, a second end of the tubular may be positioned at the datum, and the processing device may be further operable to process the signal to determine length of the tubular based on the determined position of the tubular feature with respect to the datum.', 'In such implementations, among others within the scope of the present disclosure, the first end of the tubular may be a pin end connector, and the second end of the tubular may be a box end connector.', 'The tubular feature may be a first end of the tubular, a second end of the tubular may be positioned at the datum, the sensor may be located a first distance from the datum, and the processing device may be further operable to: determine a second distance between the sensor and the tubular feature; and determine length of the tubular based on the first and second distances, wherein the first and second distances are measured with respect to a longitudinal axis of the tubular.', 'The sensor may be a first sensor, the predetermined location may be a first predetermined location, the signal may be a first signal, the tubular feature may be a first end of the tubular, the tubular feature position may be a first tubular end position, the position of the tubular feature with respect to the datum may be a first position of the first tubular end with respect to the datum, and the tubular sensing system may further comprise a second sensor at a second predetermined location with respect to the datum, wherein the second sensor may be operable to generate a second signal indicative of a second tubular end position of a second end of the tubular relative to the second sensor.', 'In such implementations, among others within the scope of the present disclosure, the processing device may be operable to receive and process the first and second signals to: determine the first position of the first tubular end with respect to the datum; determine a second position of the second tubular end with respect to the datum; and determine length of the tubular based on the determined first and second positions of the respective first and second tubular ends.', 'The tubular feature may be a first end of the tubular, and the apparatus may further comprise: a first contact member positionally fixed relative to the datum and configured to be physically contacted by a second end of the tubular; and a second contact member carrying the sensor and configured to move toward and physically contact the first end of the tubular.', 'In such implementations, among others within the scope of the present disclosure, the signal generated by the sensor may be indicative of a distance between the first and second contact members, and the processing device may be further operable to determine length of the tubular based on the signal generated by the sensor.', 'The processing device may be further operable to cause the second contact member to move toward and physically contact the first end of the tubular.', 'The present disclosure also introduces an apparatus comprising a measuring system operable to determine length of a tubular, wherein the measuring system comprises: a first contact member positionally fixed at a first distance from a datum and configured to contact a first end of the tubular; a second contact member configured to move toward the first contact member to contact a second end of the tubular; a sensor operable to generate a signal indicative of a second distance between the datum and the second contact member when the first contact member is in contact with the first end of the tubular and the second contact member is in contact with the second end of the tubular; and a processing device operable to determine the length of the tubular based on the first distance and the signal.', 'The measuring system may be located at an oil and/or gas drilling wellsite.', 'For example, the first contact member, the second contact member, and the sensor may collectively be operable in conjunction with tubular handling equipment of an oil and/or gas drilling rig at the wellsite.', 'The first contact member, the second contact member, and the sensor may collectively be operable in conjunction with a catwalk of an oil and/or gas drilling rig at the wellsite.', 'The first contact member, the second contact member, and the sensor may collectively be operable in conjunction with a rat hole at the wellsite.', 'The second end of the tubular may comprise a pin having a thread and a face at a base of the thread, and the second contact member may be operable to contact the face of the tubular.', 'The signal may be a first signal, the second end of the tubular may comprise a pin having a thread and a face at a base of the thread, and the measuring system may further comprise a third contact member operable to move into contact with the face.', 'In such implementations, among others within the scope of the present disclosure, the measuring system may be further operable to generate a second signal indicative of a third distance between the second and third contact members, and the processing device may be operable to determine the length of the tubular based on the second signal.', 'The processing device may be further operable to determine a thread length of the thread based on the second signal.', 'The measuring system may further comprise a second sensor operable to generate the second signal.', 'The sensor may be or comprise a digital image camera.', 'The signal may be a first signal, and the sensor may comprise: an emitter operable to emit a second signal; and a receiver operable to receive the second signal and generate the first signal based on the second signal.', 'The second signal may comprise light, electromagnetic radiation, infrared radiation, and/or ultrasonic waves.', 'The sensor may be operatively connected with at least one of the first and second contact members.', 'The present disclosure also introduces a method comprising: (A) transferring a tubular via tubular handling equipment disposed at an oil and/or gas drilling wellsite; (B) operating a sensor located at a predetermined location, relative to a datum at the wellsite, to generate a signal dependent upon a first characteristic of a feature of the tubular, wherein the first characteristic is a dimension or position of the tubular feature relative to the predetermined sensor location; and (C) operating a processing device comprising a processor and a memory storing computer program code to determine a second characteristic based on the signal, wherein the second characteristic is: (i) a dimension of the tubular or the tubular feature; or (ii) a position of the tubular or the tubular feature relative to the datum.', 'The tubular handling equipment may comprise the sensor.', 'The sensor may be or comprise a digital image camera, and operating the sensor may comprise generating a digital image of the tubular feature.', 'The signal may be a first signal, the sensor may comprise an emitter and a receiver, and operating the sensor may comprise: emitting a second signal; and receiving a third signal resulting from interaction between the second signal and the tubular feature, wherein the first signal is, comprises, or is based on the third signal.', 'In such implementations, among others within the scope of the present disclosure, the second and third signals may be light signals, electromagnetic signals, infrared signals, and/or ultrasonic signals.', 'The tubular feature may be a box or pin end connector of the tubular, and the second characteristic may be a dimension of the box or pin end connector.', 'The tubular feature may be a first end of the tubular, a second end of the tubular may be positioned at the datum, and the second characteristic may be length of the tubular.', 'The sensor may be a first sensor, the signal may be a first signal, the tubular feature may a first end of the tubular, the predetermined sensor location may be a first predetermined sensor location, and the method may further comprise: operating a second sensor located at a second predetermined sensor location, relative to the datum, to generate a second signal dependent upon position of a second end of the tubular relative to the second predetermined sensor location; operating the processing device to determine position of the second tubular end relative to the datum based on the second signal; and operating the processing device to determine length of the tubular based on the determined positions of the first and second tubular ends relative to the datum.', 'The second characteristic may be determined while a top drive suspends a drill string comprising the tubular.', 'The second characteristic may be determined while the tubular is supported by an upper end of a drill string extending above a rig floor, the drill string being supported by slips in the rig floor.', 'The second characteristic may be determined while the tubular is disposed in a fingerboard of a drilling rig at the wellsite.', 'The second characteristic may be determined while the tubular is substantially horizontal.', 'The second characteristic may be determined while the tubular is substantially vertical.', 'The tubular may be a single joint of drill pipe.', 'The tubular may be a pipe stand comprising a plurality of drill pipe members.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'A method comprising:\nmeasuring a first distance between a first point and a second point;\npositioning a first end of a downhole tool in alignment with the first point;\nmeasuring a second distance between the second point and a second end of the downhole tool; and\ndetermining length of the downhole tool based on the first and second distances.', '2.', 'The method of claim 1 wherein the downhole tool comprises a drill pipe, a drill collar, or a casing joint.', '3.', 'The method of claim 1 wherein the downhole tool comprises a portion of a bottom hole assembly.', '4.', 'The method of claim 1 wherein the first and second points are positionally fixed.', '5.', 'The method of claim 1 wherein the second distance is substantially smaller than the length of the downhole tool.', '6.', 'The method of claim 1 wherein the second distance is between 1% and 20% of the length of the downhole tool.', '7.', 'The method of claim 1 wherein measuring the second distance between the second point and the second end of the downhole tool comprises operating a sensor to generate a signal indicative of the second distance.', '8.', 'The method of claim 7 wherein the sensor comprises a digital image camera.', '9.', 'The method of claim 7 wherein determining the length of the downhole tool based on the first and second distances comprises operating a processing device comprising a processor and a memory storing computer program code to determine the length of the downhole tool based on the first distance and the signal generated by the sensor.', '10.', 'The method of claim 1 is performed at an oil and/or gas drilling wellsite.', '11.', 'The method of claim 10 wherein positioning the first end of the downhole tool in alignment with the first point and measuring the second distance are performed in conjunction with tubular handling equipment of an oil and/or gas drilling rig at the wellsite.', '12.', 'The method of claim 10 wherein positioning the first end of the downhole tool in alignment with the first point and measuring the second distance are performed in conjunction with a catwalk of an oil and/or gas drilling rig at the wellsite.', '13.', 'The method of claim 10 wherein positioning the first end of the downhole tool in alignment with the first point and measuring the second distance are performed in conjunction with a rat hole at the wellsite.', '14.', 'The method of claim 1 wherein the first distance is greater than the length of the downhole tool, and wherein determining the length of the downhole tool based on the first and second distances comprises determining the length of the downhole tool by calculating the difference between the first and second distances.', '15.', 'The method of claim 1 wherein the first distance is less than the length of the downhole tool, and wherein determining the length of the downhole tool based on the first and second distances comprises determining the length of the downhole tool by calculating the sum of the first and second distances.', '16.', 'The method of claim 1 wherein a contact member is aligned with the first point, and wherein positioning the first end of the downhole tool in alignment with the first point comprises positioning the first end of the downhole tool in contact with the contact member.', '17.', 'The method of claim 16 wherein the contact member is a first contact member, wherein the method further comprises positioning a second contact member in contact with the second end of the downhole tool, and wherein measuring the second distance comprises measuring the second distance between the second point and the second contact member.', '18.', 'The method of claim 17 wherein the second end of the downhole tool comprises a pin end having an external thread and a face at a base of the thread, and wherein positioning the second contact member in contact with the second end of the downhole tool comprises positioning the second contact member in contact with the face of the pin end of the downhole tool.', '19.', 'The method of claim 1 wherein the second end of the downhole tool comprises a pin end having an external thread, and wherein the method further comprises measuring a length of the thread.', '20.', 'The method of claim 19 wherein measuring the length of the thread comprises operating a sensor to generate a signal indicative of the length of the thread.', '21.', 'The method of claim 20 wherein the sensor comprises a digital image camera.', '22.', 'The method of claim 20 wherein the signal is a first signal, and wherein the sensor comprises:\nan emitter operable to emit a second signal; and\na receiver operable to receive the second signal and generate the first signal based on the second signal.', '23.', 'The method of claim 22 wherein the second signal comprises light.', '24.', 'The method of claim 22 wherein the second signal is electromagnetic radiation.', '25.', 'The method of claim 22 wherein the second signal comprises infrared radiation.', '26.', 'The method of claim 22 wherein the second signal comprises ultrasonic waves.', '27.', 'An apparatus comprising:\na tubular measuring system comprising: a sensor disposed at a predetermined location with respect to a datum, wherein the sensor is operable to generate a signal indicative of a tubular feature position relative to the sensor; and a processing device comprising a processor and a memory storing computer program code, wherein the processing device is operable to receive and process the signal to determine position of the tubular feature with respect to the datum, wherein the tubular feature is a box or pin end connector of a tubular, and wherein the processing device is further operable to process the signal to determine a dimension of the box or pin end connector.', '28.', 'The apparatus of claim 27 wherein the tubular comprises a drill pipe, a drill collar, a casing joint, and/or a downhole tool, and wherein the tubular measuring system is located at an oil and/or gas drilling wellsite.', '29.', 'The apparatus of claim 28 wherein the sensor is operable in conjunction with tubular handling equipment of an oil and/or gas drilling rig at the wellsite.\n\n\n\n\n\n\n30.', 'The apparatus of claim 28 wherein the sensor is operable in conjunction with a catwalk of an oil and/or gas drilling rig at the wellsite.\n\n\n\n\n\n\n31.', 'The apparatus of claim 27 wherein the sensor comprises a digital image camera operable to generate a digital image of the tubular feature.', '32.', 'An apparatus comprising:\na measuring system operable to determine length of a tubular, wherein the measuring system comprises: a first contact member positionally fixed at a first distance from a datum and configured to contact a first end of the tubular; a second contact member configured to move toward the first contact member to contact a second end of the tubular; a sensor operable to generate a signal indicative of a second distance between the datum and the second contact member when the first contact member is in contact with the first end of the tubular and the second contact member is in contact with the second end of the tubular; and a processing device operable to determine the length of the tubular based on the first distance and the signal.', '33.', 'The apparatus of claim 32 wherein:\nthe measuring system is located at an oil and/or gas drilling wellsite; and\nthe first contact member, the second contact member, and the sensor are collectively operable in conjunction with tubular handling equipment of an oil and/or gas drilling rig at the well site.', '34.', 'The apparatus of claim 32 wherein the second end of the tubular comprises a pin having an external thread and a face at a base of the thread, and wherein the second contact member is operable to contact the face of the tubular.\n\n\n\n\n\n\n35.', 'The apparatus of claim 32 wherein:\nthe signal is a first signal;\nthe second end of the tubular comprises a pin having an external thread and a face at a base of the thread;\nthe measuring system further comprises a third contact member operable to move into contact with the face;\nthe measuring system is further operable to generate a second signal indicative of a third distance between the second and third contact members; and\nthe processing device is operable to determine the length of the tubular based on the second signal.', '36.', 'The apparatus of claim 32 wherein the sensor is operatively connected with at least one of the first and second contact members.', '37.', 'A method comprising:\ntransferring a tubular via tubular handling equipment disposed at an oil and/or gas drilling wellsite;\noperating a sensor located at a predetermined location, relative to a datum at the wellsite, to generate a signal dependent upon a first characteristic of a feature of the tubular, wherein the first characteristic is a dimension or position of the tubular feature relative to the predetermined sensor location; and\noperating a processing device comprising a processor and a memory storing computer program code to determine a second characteristic based on the signal, wherein the second characteristic is: a dimension of the tubular or the tubular feature; or a position of the tubular or the tubular feature relative to the datum.\n\n\n\n\n\n\n38.', 'The method of claim 37 wherein the tubular handling equipment comprises the sensor.\n\n\n\n\n\n\n39.', 'The method of claim 37 wherein the sensor comprises a digital image camera, and wherein operating the sensor comprises generating a digital image of the tubular feature.', '40.', 'The method of claim 37 wherein the signal is a first signal, wherein the sensor comprises an emitter and a receiver, and wherein operating the sensor comprises:\nemitting a second signal; and\nreceiving a third signal resulting from interaction between the second signal and the tubular feature, wherein the first signal is, comprises, or is based on the third signal.', '41.', 'The method of claim 37 wherein the tubular feature is a box or pin end connector of the tubular, and wherein the second characteristic is a dimension of the box or pin end connector.', '42.', 'The method of claim 37 wherein the tubular feature is a first end of the tubular, wherein a second end of the tubular is positioned at the datum, and wherein the second characteristic is length of the tubular.', '43.', 'The method of claim 37 wherein:\nthe sensor is a first sensor;\nthe signal is a first signal;\nthe tubular feature is a first end of the tubular;\nthe predetermined sensor location is a first predetermined sensor location; and\nthe method further comprises: operating a second sensor located at a second predetermined sensor location, relative to the datum, to generate a second signal dependent upon position of a second end of the tubular relative to the second predetermined sensor location; operating the processing device to determine position of the second tubular end relative to the datum based on the second signal; and operating the processing device to determine length of the tubular based on the determined positions of the first and second tubular ends relative to the datum.', '44.', 'The method of claim 37 wherein the second characteristic is determined while a top drive suspends a drill string comprising the tubular.', '45.', 'The method of claim 37 wherein the second characteristic is determined while the tubular is supported by an upper end of a drill string extending above a rig floor, the drill string being supported by slips in the rig floor.', '46.', 'The method of claim 37 wherein the second characteristic is determined while the tubular is disposed in a fingerboard of a drilling rig at the wellsite.\n\n\n\n\n\n\n47.', 'The method of claim 37 wherein the second characteristic is determined while the tubular is substantially horizontal.\n\n\n\n\n\n\n48.', 'The method of claim 37 wherein the second characteristic is determined while the tubular is substantially vertical.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '4 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG. 5 is an enlarged view of a portion of the apparatus shown in FIG.', '4 according to one or more aspects of the present disclosure.', '; FIG.', '6 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG. 7 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG. 8 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '9 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '10 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG.', '11 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '12 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG. 13 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.; FIG.', '1 is a schematic view of at least a portion of an example implementation of a drilling system 100 operable to drill a wellbore 104 into one or more subsurface formations 102 in accordance with one or more aspects of the present disclosure, to which one or more aspects of the present disclosure may be applicable.', 'A drill string 106 penetrates the wellbore 104 and may include a bottom hole assembly (BHA) 108 that comprises or is mechanically coupled to a drill bit 110.', 'The BHA 108 may comprise various downhole tools 109, such as for measuring, processing, and storing information.', 'A telemetry device may be in the BHA 108 to facilitate communications with a control system 200 (shown in FIGS.', '2 and 3) of the drilling system 100.', 'The BHA 108 may have a modular construction with specific downhole tools 109 in certain modules.', 'However, the BHA 108 may be unitary or select downhole tools 109 may be modular.', 'The downhole tools 109 or modules may be positioned in a variety of configurations throughout the BHA 108.', 'The BHA 108 may comprise a measuring while drilling (MWD) downhole tool or module, such as may include tools operable to measure wellbore trajectory, wellbore temperature, wellbore pressure, and/or other example properties.', 'The BHA 108 may comprise a sampling while drilling (SWD) system comprising a sample downhole tool or module for communicating a formation fluid through the BHA 108 and obtaining a sample of the formation fluid.', 'The SWD system may comprise gauges, sensor, monitors and/or other devices that may also be utilized for downhole sampling and/or testing of a formation fluid.', 'The BHA 108 may comprise a logging while drilling (LWD) downhole tool or module that may include tools operable to measure formation parameters and/or fluid properties, such as resistivity, porosity, permeability, sonic velocity, optical density, pressure, temperature, and/or other example properties.; FIG. 2 is a schematic view of at least a portion of an example implementation of a control system 200 for the drilling system 100 according to one or more aspects of the present disclosure.', 'The control system 200 may include a rig computing resource environment 205, which may be located onsite at the drilling rig 111.', 'The rig computing resource environment 205 may include a coordinated control device 204 and/or a supervisory control system 207.', 'The control system 200 may include a remote computing resource environment 206, which may be located offsite from the drilling rig 111.', 'The remote computing resource environment 206 may include computing resources locating offsite from the drilling rig 111 and accessible over a network.', 'A “cloud” computing environment is one example of a remote computing resource.', 'The cloud computing environment may communicate with the rig computing resource environment 205 via a network connection (e.g., a WAN or LAN connection).', '; FIG.', '3 is a schematic view of an example implementation of the control system 200 shown in FIG.', '2 according to one or more aspects of the present disclosure.', 'The rig computing resource environment 205 may be operable to communicate with offsite devices and systems utilizing a network 208 (e.g., a wide area network (WAN) such as the internet).', 'The rig computing resource environment 205 may be further operable to communicate with the remote computing resource environment 206 via the network 208.', 'FIG.', '3 also shows the aforementioned systems of the drilling rig 111, such as the downhole system 210, the fluid system 212, the central system 214, and the IT system 216.', 'An example implementation of the drilling rig 111 may include one or more onsite user devices 218, such as may be communicatively connected or otherwise interact with the IT system 216.', 'The onsite user devices 218 may be or comprise stationary user devices intended to be stationed at the drilling rig 111 and/or portable user devices.', 'For example, the onsite user devices 218 may include a desktop, a laptop, a smartphone, a personal data assistant (PDA), a tablet component, a wearable computer, or other suitable devices.', 'The onsite user devices 218 may be operable to communicate with the rig computing resource environment 205 of the drilling rig 111 and/or the remote computing resource environment 206.; FIG.', '4 is a schematic view of at least a portion of an example implementation of a tubular measuring system 301 of the drilling system 100 according to one or more aspects of the present disclosure.', 'The tubular measuring system 301 may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars, such as drill pipe, drill collars, and casing joints, among other examples.', 'The tubular measuring system 301 may be further operable to measure position, length, diameter, and/or other dimensions of one or more portions of BHA tools, such as jars, crossover tools, mud motors, among other examples.', 'The tubular measuring system 301 may comprise a stop or contact member 310 located at a distance 314 from a known reference position or datum 315 (e.g., a reference line) and configured to contact an end 316 of a tubular 320 (or a stand comprising two or more tubulars), and a contact member 312 configured to move toward the contact member 310 to contact opposing end 318 of the tubular 320.', 'Although the end 316 of the tubular 320 is depicted as the box and the end 318 is depicted as the pin, it is to be understood that the tubular 320 may be positioned such that the pin of the tubular 320 may be in contact with the contact member 310 and the box of the tubular 320 may be in contact with the contact member 312.; FIG.', '5 is an enlarged view of a portion of an example implementation of the tubular measuring system 301 shown in FIG.', '4 according to one or more aspects of the present disclosure.', 'The tubular measuring system 301 may be further operable to measure the length 326 of a thread 328 of the end 318 of the tubular 320 and determine length 323 of the tubular 320 without the thread 328.', 'For example, the tubular measuring system 301 may further comprise a contact member 330 operable to move into contact with a face 332 at the base of the thread 328.', 'The tubular measuring system 301 may further comprise a sensor 334 operable to generate a signal indicative of the distance 326 between the contact member 312 and the contact member 330 when the contact member 312 is in contact with the end 318 of the tubular 320 and the contact member 330 is in contact with the face 332.', 'The sensor 334 may be disposed in association with the contact member 312 or the datum 315, the contact member 330, extend between the contact member 330 and the contact member 312, or otherwise disposed such as may facilitate monitoring of the distance 326.', 'The sensor 334 may be or comprise a position sensor having a structure and/or mode of operation similar to the sensor 322, and operable to generate a signal or information indicative of distance 326 between the contact member 312 and the contact member 330.', 'The sensor 334 may be in signal communication with one or more processing devices (e.g., the processing device 510 shown in FIG.', '11) of the control system 200.', 'The signal generated by the sensor 334 may be received by the processing device, which may be operable to determine the length 326 of the thread 328 and the length 323 of the tubular 320 by subtracting the distances 324, 326 from the distance 314.; FIG. 7 is a schematic view of a portion of an example implementation of a tubular measuring system 303 of the drilling system 100 according to one or more aspects of the present disclosure.', 'The tubular measuring system 303 may comprise one or more similar features of the tubular measuring systems 301, 302, including where indicated by like reference numbers, except as described below.', 'The tubular measuring system 303 may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars 320, stands 340 comprising two or more tubulars 320, and other BHA tools.; FIG.', '8 is a schematic view of a portion of an example implementation of a tubular measuring system 304 of the drilling system 100 according to one or more aspects of the present disclosure.', 'The tubular measuring system 304 may comprise one or more similar features of the tubular measuring systems 301, 302, 303 including where indicated by like reference numbers.', 'The tubular measuring system 304 may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars 320, stands 340 comprising two or more tubulars 320, and other BHA tools.; FIG.', '9 is a schematic view of a portion of an example implementation of a tubular measuring system 305 of the drilling system 100 according to one or more aspects of the present disclosure.', 'The tubular measuring system 305 may comprise one or more similar features of the tubular measuring systems 301, 302, 303, 304 including where indicated by like reference numbers.', 'The tubular measuring system 305 may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars 320, stands 340 comprising two or more tubulars 320, and other BHA tools.; FIG.', '10 is a schematic view of a portion of an example implementation of a tubular measuring system 400 of the drilling system 100 according to one or more aspects of the present disclosure.', 'The tubular measuring system 400 may comprise one or more similar features of the tubular measuring systems 301-305, including where indicated by like reference numbers, except as described below.', 'The tubular measuring system 400 may be operable to measure position, length, diameter, and/or other dimensions of one or more portions of oil and gas tubulars 320 or stands 340 comprising two or more tubulars 320.; FIG.', '12 is a flow-chart diagram of at least a portion of an example implementation of a method (600) according to one or more aspects of the present disclosure.', 'The method (600) may be performed utilizing or otherwise in conjunction with at least a portion of one or more implementations of one or more instances of the apparatuses shown in one or more of FIGS.', '1-11 and/or otherwise within the scope of the present disclosure.', 'The method (600) may be performed manually by the human operator and/or performed or caused, at least partially, by the processing device 510 executing the coded instructions 532 according to one or more aspects of the present disclosure.', 'Thus, the following description of the method (600) also refers to apparatuses shown in one or more of FIGS.', '1-11.', 'However, the method (600) may also be performed in conjunction with implementations of one or more apparatuses other than those depicted in FIGS.', '1-11 that are also within the scope of the present disclosure.', '; FIG. 13 is a flow-chart diagram of at least a portion of an example implementation of a method (700) according to one or more aspects of the present disclosure.', 'The method (700) may be performed utilizing or otherwise in conjunction with at least a portion of one or more implementations of one or more instances of the apparatuses shown in one or more of FIGS.', '1-11 and/or otherwise within the scope of the present disclosure.', 'The method (700) may be performed manually by the human operator and/or performed or caused, at least partially, by the processing device 510 executing the coded instructions 532 according to one or more aspects of the present disclosure.', 'Thus, the following description of the method (700) also refers to apparatuses shown in one or more of FIGS.', '1-11.', 'However, the method (700) may also be performed in conjunction with implementations of one or more apparatuses other than those depicted in FIGS.', '1-11 that are also within the scope of the present disclosure.'] |
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US11118422 | Automated system health check and system advisor | Aug 28, 2019 | Dinh Quy Nguyen, Carlos Urdaneta, Gang Qu, Rajnarayanan Balsamy | Schlumberger Technology Corporation | NPL References not found. | 4571993; February 25, 1986; St. Onge; 5320425; June 14, 1994; Stephenson et al.; 5355951; October 18, 1994; Allen et al.; 5455780; October 3, 1995; Nguyen et al.; 6125935; October 3, 2000; Shahin, Jr.; 8505625; August 13, 2013; Ravi et al.; 8636063; January 28, 2014; Ravi et al.; 20130166263; June 27, 2013; Shen; 20140309936; October 16, 2014; Abbassian et al.; 20150315898; November 5, 2015; Marland et al.; 20150322775; November 12, 2015; Marland et al.; 20170002622; January 5, 2017; De Bruijn et al.; 20170364607; December 21, 2017; Kaushik et al.; 20180073352; March 15, 2018; Potapenko et al.; 20180142544; May 24, 2018; Kolchanov et al.; 20180363414; December 20, 2018; Bogaerts et al.; 20190264517; August 29, 2019; Chong; 20200270963; August 27, 2020; Stralow | 2018033234; February 2018; WO | ['Systems and methods for monitoring system health of a well cementing operation are disclosed.', 'A well cementing system includes several fluid pathways and holding/mixing containers.', 'A series of sensors monitors the status of the fluid pathways and the holding/mixing containers.', 'There are redundancies in the fluid pathways, and a preferred order in which the fluid pathways are used.', 'Under normal conditions the fluid for the cementing operation is moved from place to place via the most desired pathway.', 'If the sensors detect a fault, the next-most desired fluid pathway is used.', 'If there are no available fluid pathways, an alarm is issued.'] | ['Description\n\n\n\n\n\n\nBACKGROUND', 'Well cementing is the process of placing cement slurry in a well to achieve several objectives including cementing the casing strings and liners, placing cement plugs, and performing remedial cement procedures.', 'There have been some systems developed to assist with this procedure that can check the status of various components, and can operate with system health check components (for valves, sensors, motors, pumps, etc.).', 'However, there are some drawbacks to these systems.', 'For example, they require an operator to manually check the system status within a few days before the actual cementing operation.', 'Also, if there is a hardware device that has malfunctioned, the operator does not know whether the malfunction will prevent the cementing operation or not.', 'SUMMARY\n \nEmbodiments of the present disclosure are directed to a system including a fluid delivery system configured to mix cement and deliver the cement into a well.', 'The fluid delivery system includes a plurality of fluid origins and fluid destinations.', 'The fluid delivery system is configured to move fluids between any one or more of the fluid origins to any one or more of the fluid destinations via one or more fluid pathways.', 'The system also includes a plurality of sensors configured to monitor a status of the fluid origins, fluid destinations, and fluid pathways, and a plurality of actuators configured to divert fluid into a desired fluid pathway between a fluid origin and a fluid destination.', 'The system also includes a control system configured to communicate with the sensors to record a status of the fluid origins, fluid destinations, and fluid pathways, and a system advisor component configured to store data pertaining to the fluid origins, fluid destinations, and fluid pathways.', 'The data for each fluid origin and fluid destination pair includes a most preferred fluid pathway and at least one lesser preferred fluid pathway.', 'The system advisor is configured to assess a status of the most preferred fluid pathway.', 'If the most preferred fluid pathway is available the system advisor is configured to execute fluid delivery via the most preferred fluid pathway using the actuators.', 'If the most preferred fluid pathway is not available the system advisor is configured to assess a status of a lesser preferred fluid pathway using the actuators.', 'If the lesser preferred fluid pathway is available the system advisor is configured to execute fluid delivery via the lesser preferred pathway using the actuators.', 'If there is no fluid pathway available the system advisor is configured to issue an alarm.', 'Further embodiments of the present disclosure are directed to a method for monitoring a well cementing operation, including providing a plurality of fluid handling systems that are interconnected by a plurality of fluid pathways that operate together to mix and deliver cement to a location in a well, and monitoring the fluid pathways to determine whether or not the fluid pathways are available to transmit fluid from a fluid origin to a fluid destination.', 'The fluid pathways comprise two or more different pathways between the fluid origin and the fluid destination.', 'The method also includes ranking the fluid pathways in an order from most desirable to least desirable.', 'When the well cementing operation is initiated, the method includes checking the availability of at least one of the fluid pathways, and transmitting the fluid from the fluid origin to the fluid destination via a fluid pathway that is available and most desirable.', 'In other embodiments the present disclosure is directed to a system including a cementing module comprising a plurality of fluid handling components configured to mix and deliver cement in a well.', 'The fluid handling components include at least one fluid origin, one fluid destination, and two or more fluid pathways configured to transmit fluid from the fluid origin to the fluid destination.', 'The system also includes a plurality of sensors configured to monitor an availability status of the fluid pathways, and an actuator configured to selectively divert fluid into a selected fluid pathway.', 'The system also includes a system advisor configured to store a ranked preference order of the fluid pathways from most desired to least desired, and to provide an availability status of the fluid pathways.', 'The system advisor also can cause the actuator to divert the fluid into a fluid pathway that is most desired and available.', 'BRIEF DESCRIPTION OF THE FIGURES\n \nFIG.', '1\n is a schematic block diagram of an automated system health check and system advisor according to embodiments of the present disclosure.', 'FIG.', '2\n is a schematic illustration of a system for performing automated system health checks and system advisors according to the present disclosure.', 'FIG.', '3\n is a schematic diagram of a system according to embodiments of the present disclosure.', 'FIG.', '4\n is a block diagram illustrating operation of methods of the present disclosure.', 'FIG.', '5\n is an illustration of how alternatives are cataloged according to embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'Below is a detailed description according to various embodiments of the present disclosure.', 'FIG.', '1\n is a schematic block diagram of an automated system health check and system advisor \n100\n according to embodiments of the present disclosure.', 'The system \n100\n includes a HMI PC \n102\n that itself includes a human machine interface (HMI) \n104\n and a KEPserver EX \n106\n that is configured to communicate with a network switch \n108\n.', 'The KEPserver EX \n106\n is a known component that is commercially available provided by PTC™.', 'Other, similar communication services and components can be used in place of the KEPserver EX \n106\n.', 'The system \n100\n also includes a cRIO Controller \n110\n that communicates with the network switch \n108\n and interfaces with external interfaces/hardware \n112\n.', 'The cRIO controller \n110\n can be a CompactRIO (or cRIO) that is a real-time embedded industrial controller made by National Instruments™ for industrial control systems.', 'The CompactRIO is a combination of a real-time controller, reconfigurable IO Modules (RIO), FPGA module and an Ethernet expansion chassis.', 'Other, similar components can be used with the system \n100\n without departing from the spirit of the present disclosure.', 'FIG.', '2\n is a schematic illustration of a system \n120\n for performing automated system health checks and system advisors according to the present disclosure.', 'The system \n120\n includes an instrumentation module \n122\n and a control system \n134\n.', 'The instrumentation module \n122\n includes sensors \n124\n and actuators \n126\n that are configured to communicate with a cRIO module \n136\n of the control system \n134\n.', 'The sensors \n124\n provide raw data \n130\n to the cRIO modules \n138\n within the cRIO chassis \n136\n.', 'The actuators \n126\n are configured to receive raw commands \n128\n from the cRIO chassis \n136\n.', 'The cRIO chassis \n136\n also includes a cRIO Controller \n140\n that contains basic \n10\n control \n142\n and advanced control algorithms \n144\n.', 'The control system \n134\n also includes kepware \n148\n that transmits data \n146\n to and from the cRIO chassis \n136\n.', 'The control system \n134\n also includes a HMI \n154\n that receives raw and engineering data \n150\n from the kepware \n148\n, and facilitates transmission of commands \n152\n to the kepware.', 'The commands \n152\n are eventually passed to the cRIO chassis \n136\n which then transmits the commands to the actuators \n126\n.', 'The sensors \n124\n and actuators \n126\n can be any of several possible types, such as pressure, temperature, position, chemical composition, accelerometers, or any other suitable type of sensor depending on the equipment that is to be monitored by the sensors.', 'Similarly, the actuators can be any of several possible actuators such as solenoids, valves, pumps, or any other suitable needful type of actuator.', 'In a cementing operation, there are certain fluids that need to be delivered to different locations within a system.', 'Water and cement are two readily understandable fluids that can be used in a cementing operation, although there may be others.', 'The systems and methods of the present disclosure can be used with any number of fluids and mechanical movements without departing from the scope of the present disclosure.', 'Many of the examples and illustrations herein are given using simplified examples.', 'It is to be appreciated that the systems and methods of the present disclosure can be used equally with different environments and with more diverse fluid compositions.', 'According to embodiments of the present disclosure, the system \n120\n can be used to monitor the status of various components of a cementing system.', 'As often as required, the system \n120\n can check to see if various pipes, pumps, valves, etc. are in an operable condition.', 'The system \n120\n can therefore maintain a recent status of the components of the system such that when the time comes to initiate a cementing operation it is known that there are no blockages or malfunctioning equipment.', 'Prior art systems would require a manual check of these components some time before the operation begins.', 'The systems and methods of the present disclosure can enable much more up-to-date information about the system which can save time and expense by identifying a problem with the system earlier.', 'FIG.', '3\n is a schematic diagram of a system \n180\n according to embodiments of the present disclosure.', 'The system \n180\n includes Tank \n1\n \n182\n, Tank \n2\n \n184\n, and Tank \n3\n \n186\n.', 'For purposes of illustration, these three tanks are interconnected via pipes and valves and a cementing operation can require fluid to be moved between any of the Tanks in a certain order.', 'The Tanks can represent holding tanks, mixing tanks, or any other vessel for use with a cementing operation.', 'It is to be appreciated that the system shown is simplified for purposes of explanation and not limitation.', 'In an actual cementing operation there may be many more such components and the system may be more complex.', 'A person of ordinary skill in the art will appreciate that the systems and methods shown and described here are equally applicable to a more complex system.', 'Tank \n1\n \n182\n and Tank \n2\n \n184\n are connected by a pipe \n196\n.', 'There is another route between Tanks \n1\n and \n2\n, via pipe \n198\n, valve \n202\n, and pipe \n204\n.', 'Tanks \n2\n and \n3\n are connected by a pipe \n194\n.', 'Tanks \n1\n and \n3\n are connected by a pipe \n188\n, a pump \n190\n, and a pipe \n192\n.', 'Each of these components can have a sensor/actuator \n200\n coupled thereto.', 'Each instance of the sensor/actuator \n200\n can be any type of sensor and any type of actuator.', 'In some cases there is a sensor without an actuator and vice versa.', 'The sensor/actuators \n200\n are coupled to the system \n120\n shown in \nFIG.', '2\n.\n \nSuppose for a cementing operation it is needed to store fluid in Tank \n1\n for a certain period of time, and then to transmit the fluid to Tank \n3\n.', 'There may be a primary path to execute this movement, and the most direct path is usually the most preferred.', 'In this case, the first path is pipe \n196\n between Tanks \n1\n and \n2\n and pipe \n194\n from Tank \n2\n to Tank \n3\n.', 'The sensor/actuators \n200\n can monitor and verify that there is no problem with this path.', 'If there is no problem, the system can execute the transmission directly.', 'On the other hand, if there is a problem with any of the components in the primary path, the system can search for an alternative path.', 'In the example shown, an alternate path may be to use pipe \n188\n, via pump \n190\n, and pipe \n192\n that reaches Tank \n3\n.', 'If the sensor/actuators \n200\n for these components report that there is no problem, the system can execute the transfer via this secondary route.', 'In some embodiments the secondary route is equally capable with the primary route; however, in some cases there is some diminished capacity associated with the secondary route.', 'The diminished capacity can be quantified and this information can be relayed to the system which can make a determination as to the viability of the secondary route.', 'Also, the system may need to make some adjustments to components of the route to accommodate for the diminished capacity.', 'For example, if a pipe segment in a secondary route has a higher pressure drop than the primary segment, a pump upstream of the secondary route can be operated at a higher or lower pressure to accommodate.', 'The sensor/actuators \n200\n can be operated by the controllers of the system at any desired rate.', 'In some embodiments the controllers operate at 10 hz, although higher or lower frequencies are possible.', 'This allows an operator to know in virtual real time if there is a problem with the system, and also provides an alternative route if there is a problem.', 'In some cases of course there will be no alternative route, in which case other accommodations must be made.', 'This system provides major advantages over prior art systems in which an operator must arrive at the cementing site sometimes days in advance to manually check the status of the cementing operation and hope that nothing materially changes between the time of the check and the time of the cementing job.\n \nFIG.', '4\n is a block diagram \n220\n illustrating operation of methods of the present disclosure.', 'At \n222\n an automated system health check is initiated.', 'This can be performed at any time, including long in advance of a cementing operation.', 'At \n224\n the method includes checking component operation, which can include control and/or feedback.', 'The component to be checked can be any component of the well cementing operation, and can include all major components of the operation.', 'Valves, pipes, pumps, are just a few examples of the components that are checked.', 'At \n226\n the condition of the components is recorded.', 'The condition can be a simple pass/fail, or it can include more information such as remaining capacity or battery life.', 'This checking and recording represented by \n224\n and \n226\n can repeat as often as is practical.', 'In some embodiments a controller operating this system health check can operate on a 10 hz frequency.', 'The status of the components of the cementing operation is therefore known in real time.', 'In some embodiments, if there is a problem an alert can be issued to an operator.', 'In other embodiments, the system simply records the status for a future time at which an operator desires the information.', 'At \n228\n a system advisor routine is initiated.', 'This can be an automated event based on the scheduling of the well cementing operation, or it can be initiated by a skilled operator at their discretion.', 'At \n230\n the method includes checking for any failed units.', 'For each failed component, the remainder of the method \n220\n can be executed.', 'If there is no failed unit, the cementing operation can be initiated at \n232\n and the operation carries out without issue.', 'If there is a failed unit, at \n234\n the system can check for an available redundancy.', 'This represents the secondary path described above.', 'If there are no available alternatives, the system can terminate the operation at \n236\n.', 'If there is an available redundancy, at \n238\n a check can be performed to identify whether or not the capacity of the secondary route is sufficiently high to carry out the job.', 'Also, the quantity of the diminished capacity can be communicated to allow for adjustments to be made to other components of the cementing operation.', 'Once a satisfactory alternative is identified, the cementing operation can be initiated at \n232\n.', 'FIG.', '5\n is an illustration of how alternatives are cataloged according to embodiments of the present disclosure.', 'A first tank \n280\n is connected to a second tank \n282\n via a primary connection \n284\n.', 'There are two alternative pathways, \n286\n and \n288\n, each of which achieve the same deliver of fluid from the first tank \n280\n to the second tank \n282\n.', 'Suppose for example that path \n288\n involves the use of a valve that can cause a pressure drop and therefore is a less-desirable option.', 'The system can maintain a database with entries for each component that list the available alternatives.', 'For each origin-destination pair, such as the first tank \n280\n and the second tank \n282\n, there can be a list of pathways, listed in order of preference.', 'When it is time to carry out the cementing operation, the first, most desired pathway can be analyzed.', 'If it is not available, the system can check pathway \n286\n.', 'If it is available, it is used.', 'If not, pathway \n288\n can be checked.', 'If it is available, it can be used and the diminished capacity of pathway \n288\n can be communicated to the system to make any necessary adjustments to the cementing operation.', 'In other embodiments, the system can maintain a list having entries for each pathway component that includes an identifier of the pathway, and a prioritized list of the alternate paths for the pathway.', 'The list for pathway \n284\n would include pathway \n286\n and then pathway \n288\n.', 'A list for pathway \n286\n may include the pathway \n288\n, and may also include a description of the lesser capacity of pathway \n288\n.', 'Pathway \n288\n may comprise the least-desirable alternative and as such the entry in the database can reflect this and if there is a problem with this pathway then a shut down or other remedy is required.', 'The foregoing disclosure hereby enables a person of ordinary skill in the art to make and use the disclosed systems without undue experimentation.', 'Certain examples are given to for purposes of explanation and are not given in a limiting manner.'] | ['1.', 'A system, comprising:\na fluid delivery system configured to mix cement and deliver the cement into a well, the fluid delivery system comprising a plurality of fluid origins and fluid destinations, wherein the fluid delivery system is configured to move fluids between any one or more of the fluid origins to any one or more of the fluid destinations via two or more fluid pathways;\na plurality of sensors configured to monitor a status of the fluid origins, fluid destinations, and fluid pathways;\na plurality of actuators configured to divert fluid into a desired fluid pathway between a fluid origin and a fluid destination;\na control system configured to communicate with the sensors to record a status of the fluid origins, fluid destinations, and fluid pathways; and\na system advisor component configured to store data pertaining to the fluid origins, fluid destinations, and fluid pathways, wherein the data for each fluid origin and fluid destination pair includes a most preferred fluid pathway and at least one lesser preferred fluid pathway;\nwherein: the system advisor is configured to assess a status of the most preferred fluid pathway; if the most preferred fluid pathway is available the system advisor is configured to execute fluid delivery via the most preferred fluid pathway using the actuators; if the most preferred fluid pathway is not available the system advisor is configured to assess a status of a lesser preferred fluid pathway using the actuators; if the lesser preferred fluid pathway is available the system advisor is configured to execute fluid delivery via the lesser preferred pathway using the actuators; and if there is no fluid pathway available the system advisor is configured to issue an alarm.', '2.', 'The system of claim 1 wherein the data includes a description of a difference in capacity between the most preferred fluid pathway and at least one of the lesser preferred fluid pathways.', '3.', 'The system of claim 2 wherein the system advisor is configured to adjust operation of at least one component in the fluid delivery system to accommodate the difference in capacity between the most preferred fluid pathway and the at least one of the lesser preferred fluid pathways.', '4.', 'The system of claim 1 wherein the plurality of sensors are configured to monitor the status of the fluid origins, fluid destinations, and fluid pathways at least once per minute.', '5.', 'The system of claim 1 wherein the fluid pathways comprise at least one of pipes, valves, pumps, mixing chambers, and holding containers.', '6.', 'The system of claim 1 wherein the system advisor is further configured to determine whether a fluid pathway has sufficient capacity to execute the fluid delivery.', '7.', 'A method for monitoring a well cementing operation, the method comprising:\nproviding a plurality of fluid handling systems that are interconnected by a plurality of fluid pathways that operate together to mix and deliver cement to a location in a well;\nmonitoring the fluid pathways to determine whether the fluid pathways are available to transmit fluid from a fluid origin to a fluid destination, wherein the fluid pathways comprise two or more different pathways between the fluid origin and the fluid destination;\nranking the fluid pathways in an order from most desirable to least desirable;\nwhen the well cementing operation is initiated, checking the availability of at least one of the fluid pathways; and\ntransmitting the fluid from the fluid origin to the fluid destination via a fluid pathway that is available and most desirable.\n\n\n\n\n\n\n8.', 'The method of claim 7 wherein the fluid comprises at least one of water and cement.', '9.', 'The method of claim 7 wherein monitoring the fluid pathways to determine whether the fluid pathways are available comprises a “go-no go” analysis.', '10.', 'The method of claim 7 wherein monitoring the fluid pathways comprises operating a plurality of sensors at a monitoring frequency of at least 1 hz.', '11.', 'The method of claim 7, further comprising storing a capability rating of the plurality of fluid pathways.', '12.', 'The method of claim 11, further comprising calculating a difference of capability rating between the most desirable pathway and the fluid pathway that is available and most desirable.', '13.', 'The method of claim 7 wherein the fluid pathways comprise at least one of pipes, pumps, valves, and containers.', '14.', 'The method of claim 7, further comprising issuing an alarm if there is no available fluid pathway.', '15.', 'A system, comprising:\na cementing module comprising a plurality of fluid handling components configured to mix and deliver cement in a well, wherein the fluid handling components include at least one fluid origin, one fluid destination, and two or more fluid pathways configured to transmit fluid from the fluid origin to the fluid destination;\na plurality of sensors configured to monitor an availability status of the fluid pathways;\nan actuator configured to selectively divert fluid into a selected fluid pathway; and\na system advisor configured to: store a ranked preference order of the fluid pathways from most desired to least desired; provide an availability status of the fluid pathways; cause the actuator to divert the fluid into a fluid pathway that is most desired and available.', '16.', 'The system of claim 15 wherein the plurality of sensors are configured to monitor availability status of the fluid pathways at a frequency of at least 1 hz.', '17.', 'The system of claim 15 wherein the system advisor is further configured to store a capability of the fluid pathways.', '18.', 'The system of claim 17 wherein the system advisor is further configured to alter operation of the cementing module according to a difference between the capability of the most desired fluid pathway and the fluid pathway into which the actuator is caused to divert the fluid.', '19.', 'The system of claim 15, the system advisor being further configured to issue an alarm if none of the fluid pathways is available.'] | ['FIG.', '1 is a schematic block diagram of an automated system health check and system advisor according to embodiments of the present disclosure.', '; FIG.', '2 is a schematic illustration of a system for performing automated system health checks and system advisors according to the present disclosure.', '; FIG.', '3 is a schematic diagram of a system according to embodiments of the present disclosure.', '; FIG.', '4 is a block diagram illustrating operation of methods of the present disclosure.; FIG.', '5 is an illustration of how alternatives are cataloged according to embodiments of the present disclosure.', '; FIG.', '2 is a schematic illustration of a system 120 for performing automated system health checks and system advisors according to the present disclosure.', 'The system 120 includes an instrumentation module 122 and a control system 134.', 'The instrumentation module 122 includes sensors 124 and actuators 126 that are configured to communicate with a cRIO module 136 of the control system 134.', 'The sensors 124 provide raw data 130 to the cRIO modules 138 within the cRIO chassis 136.', 'The actuators 126 are configured to receive raw commands 128 from the cRIO chassis 136.', 'The cRIO chassis 136 also includes a cRIO Controller 140 that contains basic 10 control 142 and advanced control algorithms 144.', 'The control system 134 also includes kepware 148 that transmits data 146 to and from the cRIO chassis 136.', 'The control system 134 also includes a HMI 154 that receives raw and engineering data 150 from the kepware 148, and facilitates transmission of commands 152 to the kepware.', 'The commands 152 are eventually passed to the cRIO chassis 136 which then transmits the commands to the actuators 126.; FIG.', '3 is a schematic diagram of a system 180 according to embodiments of the present disclosure.', 'The system 180 includes Tank 1 182, Tank 2 184, and Tank 3 186.', 'For purposes of illustration, these three tanks are interconnected via pipes and valves and a cementing operation can require fluid to be moved between any of the Tanks in a certain order.', 'The Tanks can represent holding tanks, mixing tanks, or any other vessel for use with a cementing operation.', 'It is to be appreciated that the system shown is simplified for purposes of explanation and not limitation.', 'In an actual cementing operation there may be many more such components and the system may be more complex.', 'A person of ordinary skill in the art will appreciate that the systems and methods shown and described here are equally applicable to a more complex system.; FIG.', '4 is a block diagram 220 illustrating operation of methods of the present disclosure.', 'At 222 an automated system health check is initiated.', 'This can be performed at any time, including long in advance of a cementing operation.', 'At 224 the method includes checking component operation, which can include control and/or feedback.', 'The component to be checked can be any component of the well cementing operation, and can include all major components of the operation.', 'Valves, pipes, pumps, are just a few examples of the components that are checked.', 'At 226 the condition of the components is recorded.', 'The condition can be a simple pass/fail, or it can include more information such as remaining capacity or battery life.', 'This checking and recording represented by 224 and 226 can repeat as often as is practical.', 'In some embodiments a controller operating this system health check can operate on a 10 hz frequency.', 'The status of the components of the cementing operation is therefore known in real time.', 'In some embodiments, if there is a problem an alert can be issued to an operator.', 'In other embodiments, the system simply records the status for a future time at which an operator desires the information.', '; FIG.', '5 is an illustration of how alternatives are cataloged according to embodiments of the present disclosure.', 'A first tank 280 is connected to a second tank 282 via a primary connection 284.', 'There are two alternative pathways, 286 and 288, each of which achieve the same deliver of fluid from the first tank 280 to the second tank 282.', 'Suppose for example that path 288 involves the use of a valve that can cause a pressure drop and therefore is a less-desirable option.', 'The system can maintain a database with entries for each component that list the available alternatives.', 'For each origin-destination pair, such as the first tank 280 and the second tank 282, there can be a list of pathways, listed in order of preference.', 'When it is time to carry out the cementing operation, the first, most desired pathway can be analyzed.', 'If it is not available, the system can check pathway 286.', 'If it is available, it is used.', 'If not, pathway 288 can be checked.', 'If it is available, it can be used and the diminished capacity of pathway 288 can be communicated to the system to make any necessary adjustments to the cementing operation.'] |
|
US11125912 | Geologic feature splitting | Nov 24, 2014 | Zhenhua Li, Qingrui Li, Ping Xu, Guang Xiong, Lina Xu, Paolo Saverio Damiani | Schlumberger Technology Corporation | Dershowitz, William S. et al; Fractured reservoir discrete feature network technologies. Final report, Mar. 7, 1996 to Sep. 30, 1998, report, Dec. 1998; United States. (https://digital.library.unt.edu/ark:/67531/metadc705669/), University of North Texas Libraries. pp. 341 (Year: 1996).; La Pointe, et al., “Compartmentalization Analysis using Discrete Fracture Network Models”, International reservoir characterization technical conference, Houston, TX; retrieved from the internet: http://www.osti.gov/scicech/biblio/570175-VnzseS/webviewable/, Mar. 2-4, 1997, pp. 7-8, 11.; Blocher, et al., “Three dimensional modelling of fractured and faulted reservoirs: Framework and implementation,” Chemie der Erde-Geochemistry, Elsevier, Amsterdam, NL, vol. 70, Aug. 1, 2010, pp. 145-153.; Search Report for the equivalent European patent application 14863440.5 dated Nov. 10, 2016.; Communication pursuant to Article 94(3) for the equivalent European patent application 14863440.5 dated Mar. 20, 2017.; Garland, et al., “Hierarchical face clustering on polygonal surfaces,” 13D '01 Proceedings of the 2001 symposium on Interactive 3D graphics, pp. 49-58, ACM New York, NY, USA 2001.; Cohen-Steiner, et al., “Variational Shape Approximation,” Institute National de Recherche En Informatique Et En Automatique (INRIA), No. 5371, Nov. 2004.; Roncella, et al., “Extraction of Planar Patches from Point Clouds to Retrieve Dip and Dip Direction of Rock Discontinuities,” ISPRS WG III/3 III/4, V/3 Workshop “Laser scanning 2005,” Enschede, the Netherlands, Sep. 12-14, 2005, pp. 162-167.; Graham, “An Efficient Algorithm for Determining the Convex Hull of the Finite Planar Set,” Information Processing Letters 1, 1972, pp. 132-133.; International Search Report and Written Opinion for the equivalent International patent application PCT/US2014/067391 dated Feb. 27, 2015.; LaPointe et al. “Reservoir Compartmentalization—Fractured Reservoir Discrete Feature Network Technologies,” Compartmentalization Research Report, Feb. 14, 1997, retrieved at http://www.fracturedreservoirs.com/niper/database/REPORTS/RES_CHAR/0212PRL1.htm on Nov. 17, 2017.; Wang, “New Technology of Fracture Modeling for DFN Model,” Fault-Block Oil & Gas Field, vol. No. 15, issue No. 6, Nov. 30, 2008.; Wang, et al. “Realization and Optimization of Random Discrete Fracture Network Model for Buried Hill Fractured Reservoir in Bohai C Oilfield,” Lithologic Reservoirs, Feb. 29, 2012.; Xu, et al., Reservoir Fracture Modeling Based on Discrete Crack Network Model, Journal of Daqing Petroleum Institute, vol. No. 35, issue No. 3.; Office Action for the equivalent Chinese patent application 2014800740606 dated May 26, 2017.; Communication pursuant to Article 94(3) for the equivalent European patent application 14863440.5 dated Dec. 22, 2020, 6 pages.; Communication pursuant to Article 94(3) for the equivalent European patent application 14863440.5 dated Jan. 3, 2019, 6 pages. | 5930730; July 27, 1999; Marfurt; 6014343; January 11, 2000; Graf; 6023656; February 8, 2000; Cacas; 8103493; January 24, 2012; Sagert; 9228415; January 5, 2016; Ingham; 9377546; June 28, 2016; Vallikkat Thachaparambil; 9665537; May 30, 2017; Khvoenkova; 20030112704; June 19, 2003; Goff; 20070168169; July 19, 2007; Neave; 20100191516; July 29, 2010; Benish; 20100250216; September 30, 2010; Narr; 20100274543; October 28, 2010; Walker; 20110106514; May 5, 2011; Omeragic; 20110211761; September 1, 2011; Wang; 20120185225; July 19, 2012; Onda; 20130144532; June 6, 2013; Williams; 20130294197; November 7, 2013; Vallikkat Thachaparambil; 20130332125; December 12, 2013; Suter; 20140058713; February 27, 2014; Thachaparambil; 20140188392; July 3, 2014; Aarre; 20140358510; December 4, 2014; Sarkar; 20150285950; October 8, 2015; Yarus; 20160123119; May 5, 2016; Tueckmantel; 20170343689; November 30, 2017; Dykstra; 20190011600; January 10, 2019; Malvesin | 2008086352; July 2008; WO; WO2013169620; November 2013; WO | ['A method includes receiving information that defines a three-dimensional subterranean structure; splitting the three-dimensional subterranean structure into portions; generating convex hulls for the portions; and generating a discrete fracture network based at least in part on the convex hulls.'] | ['Description\n\n\n\n\n\n\nRELATED APPLICATIONS', 'This application claims the benefit of and priority to a U.S. Provisional Application Ser.', 'No. 61/908,469, filed 25 Nov. 2013, which is incorporated by reference herein, and this application claims the benefit of and priority to a U.S. Provisional Application Ser.', 'No. 61/908,480, filed 25 Nov. 2013, which is incorporated by reference herein.', 'BACKGROUND\n \nData may be processed and interpreted, for example, to understand better composition, fluid content, extent and geometry of subsurface rocks.', 'SUMMARY', 'In accordance with some embodiments, a method is performed that includes: receiving information that defines a three-dimensional subterranean structure; splitting the three-dimensional subterranean structure into portions; generating convex hulls for the portions; and generating a discrete fracture network based at least in part on the convex hulls.', 'In some embodiments, an aspect of a method includes simulating phenomena associated with a subterranean formation based at least in part on a model that include a discrete fracture network.', 'In some embodiments, an aspect of a method includes generating convex hulls by applying a Graham scan algorithm.', 'In some embodiments, an aspect of a method includes splitting by implementing an angular splitting parameter.', 'In some embodiments, an aspect of a method includes splitting that generates line segments where, for example, each of the line segments includes respective end points.', 'In some embodiments, an aspect of a method includes splitting a curve where the curve is determined by intersection of a subterranean structure with a plane and, for example, repeating the splitting for a plurality of positions of the plane along a coordinate direction.', 'In some embodiments, an aspect of a method includes splitting by intersecting a three-dimensional subterranean structure by a plane to generate intersection points that form a curve and then splitting the curve into portions where, for example, splitting can include representing each of the portions by a line segment and where, for example, each of the line segments is associated with a respective area.', 'In some embodiments, an aspect of a method includes generating at least one convex hull by determining a best fit plane.', 'In some embodiments, an aspect of a method includes outputting a discrete fracture network as a model represented at least in part by a set of convex hulls.', 'In some embodiments, an aspect of a method includes tessellating at least a portion of a subterranean structure into polygons; computing a normal for each of the polygons; and determining one or more dip values based on the normals of the polygons.', 'In accordance with some embodiments, a computing system is provided that includes at least one processor, at least one memory, and one or more programs stored in the at least one memory, where the one or more programs are configured to be executed by the one or more processors, the one or more programs including instructions to: receive information that defines a three-dimensional subterranean structure; split the three-dimensional subterranean structure into portions; generate convex hulls for the portions; and generate a discrete fracture network based at least in part on the convex hulls.', 'In some embodiments, an aspect of a computing system includes instructions to simulate phenomena associated with a subterranean formation based at least in part on a model that includes a discrete fracture network.', 'In some embodiments, an aspect of a computing system includes instructions to generate a convex hull for at least one of a portion of a subterranean structure by, at least in part, by application of a Graham scan algorithm.', 'In accordance with some embodiments, a computer readable storage medium is provided, the medium having a set of one or more programs including instructions that when executed by a computing system cause the computing system to receive information that defines a three-dimensional subterranean structure; split the three-dimensional subterranean structure into portions; generate convex hulls for the portions; and generate a discrete fracture network based at least in part on the convex hulls.', 'In some embodiments, an aspect of a computer readable storage medium includes instructions to simulate phenomena associated with a subterranean formation based at least in part on a model that includes a discrete fracture network.', 'In some embodiments, an aspect of a computer readable storage medium includes instructions to generate a convex hull for at least one portion of a subterranean structure via application of a Graham scan algorithm.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFeatures and advantages of the described implementations can be more readily understood by reference to the following description taken in conjunction with the accompanying drawings.\n \nFIG.', '1\n illustrates an example system that includes various components for modeling a geologic environment;\n \nFIG.', '2\n illustrates examples of formations, an example of a convention for dip, an example of data acquisition, and an example of a system;\n \nFIG.', '3\n illustrates an example of a method;\n \nFIG.', '4\n illustrates an example of a method;\n \nFIG.', '5\n illustrates an example of a method;\n \nFIG.', '6\n illustrates examples of data and processed data;\n \nFIG.', '7\n illustrates an example of a method;\n \nFIG.', '8\n illustrates an example of a Graham scan technique;\n \nFIG.', '9\n illustrates an example of a method;\n \nFIG.', '10\n shows an example of a set of polygons;\n \nFIG.', '11\n illustrates examples of plots;\n \nFIG.', '12\n illustrates an example of a method;\n \nFIG.', '13\n illustrates an example of a method;\n \nFIG.', '14\n illustrates an example of a method;\n \nFIG.', '15\n illustrates an example of a method;\n \nFIG.', '16\n illustrates an example of a method;\n \nFIG.', '17\n illustrates examples of structures;\n \nFIG.', '18\n illustrates an example of a system, examples of modules and an example of a fracture network;\n \nFIG.', '19\n illustrates an example of an environment; and\n \nFIG.', '20\n illustrates example components of a system and a networked system.', 'DETAILED DESCRIPTION', 'The following description includes the best mode presently contemplated for practicing the described implementations.', 'This description is not to be taken in a limiting sense, but rather is made merely for the purpose of describing the general principles of the implementations.', 'The scope of the described implementations should be ascertained with reference to the issued claims.', 'As an example, structures in a subterranean environment may be understood better through acquisition of data and processing of acquired data.', 'As an example, data may be one or more of seismic data, imagery data and/or one or more other types of data.', 'As an example, data may be analyzed to uncover fractures, faults or other structures.', 'As an example, data may be analyzed to uncover a fracture network of multiple fractures that include intersections.', 'As an example, fractures of a fracture network may be formed when rock is stressed or strained, for example, responsive to forces associated with plate-tectonic activity.', 'Fractures may be formed, as an example, using artificial techniques, for example, via hydraulic fracturing.', 'As an example, a fracture network may include natural fractures, artificial fractures or natural fractures and artificial fractures.', "As an example, fracture networks may contribute a formations' storage (e.g., via porosity, etc.)", 'and/or fluid flow (e.g., via permeability or transmissibility).', 'As an example, a fracture network may exist in a so-called unconventional formation.', 'As an example, one or more factors may determine whether a formation may be classified as being unconventional.', 'For example, one or more of porosity, permeability, fluid trapping mechanisms, or other characteristics may be factors of a classification scheme for classifying a formation.', 'As an example, a shale gas formation may be classified as an unconventional formation.', 'Quality of a shale reservoir may depend, for example, on one or more of thickness and extent, organic content, thermal maturity, depth and pressure, fluid saturations, permeability, and/or one or more other factors.', 'As mentioned, a fracture network may include natural fractures, artificial fractures or natural fractures and artificial fractures.', 'For example, a fracture network in a formation that includes shale may include natural fractures, artificial fractures or natural fractures and artificial fractures.', 'As an example, a priori knowledge of natural fractures and/or existing artificial fractures may facilitate planning, performance, etc. of one or more operations (e.g., drilling, injection, extraction, fracturing, etc.).', 'Formation modeling may facilitate understanding, for example, as to how a formation may behave (e.g., static and/or dynamic behavior).', 'As an example, modeling may include generating a discrete fracture network (DFN), which may be characterized spatially by porosities, permeabilities, transmissibilities, etc.', 'As an example, one or more characteristics of a DFN may change with respect to time (e.g., consider a temporal model).', 'As an example, a DFN may help in understanding aspects of storage and/or fluid flow in a formation.', 'For example, a dynamic model may include a DFN where movement of fluid may occur at least in part via the DFN.', 'As an example, a DFN may include fractures, faults or fractures and faults.', 'As an example, a model may be a multidimensional model that includes vertices or nodes that define model elements, which may be, for example, polygons, polyhedra, etc.', 'As an example, a model that includes polygons may be subject to one or more rules, such as, for example, (a) polygons are convex, (b) polygons are connected with other polygons, and (c) polygons approximate structure and make geological sense.', 'For example, as to a fracture, it may be desirable to have a model that includes polygons that approximate the fracture, which may be part of a fracture network.', 'As an example, where a formation includes a relatively planar fracture, a model that includes polygons may be able to include polygons positioned in a manner that represents the planar fracture, for example, as a surface that may be an individual fracture in DFN.', 'However, where a fracture may differ from such a relatively planar fracture, as an example, an effort to model the fracture may violate one or more rules.', 'For example, a risk may exist that a fracture or fractures get modeled in incorrect positions, incorrect orientations, etc.', 'As an example, a single best fit plane may be insufficient to adequately represent a fracture (e.g., depending on the three-dimensional nature of the fracture).', 'As an example, a method can include applying a splitting algorithm to split a data-based representation of a fracture surface into parts.', 'In such an example, at least some of the parts may then be approximated, for example, by planes.', 'For example, a fracture surface may be split into parts where each of the parts is approximated by a plane.', 'As an example, adjacent planes may represent adjacent parts of a fracture and may be disposed at different angles, for example, with respect to a locus or loci.', 'As an example, a method may include transforming a fracture and/or a fault into a set of convex hulls.', 'A convex hull may be defined with respect to a set of points in a number of dimensions such that the convex hull is the intersection of convex sets containing the points.', 'As an example, a so-called Graham scan may be employed to determine a convex hull of a finite planar set of points.', 'For example, given a finite set of points in a plane, a method may include determining a convex hull of the finite set of points.', 'A Graham scan can determine which points in a set of points may be extreme points of a convex hull, which may define a convex hull (e.g., a boundary for a plane).', 'As an example, a method may include one or more procedures such as (i) finding a point P in a plane that is in the interior of a convex hull of a finite set of points, (ii) expressing each point in the finite set of points in polar coordinates with an origin at the point P and with a polar coordinate θ of approximately null in a direction of an arbitrary fixed half-line from the point P, (iii) ordering elements ρ\nk \nexp iθ\nk \nof the finite set of points in terms of increasing θ\nk\n, (iv) deleting points based on one or more criteria to arrive at a reduced set of points, and (v) processing the reduced set of points to arrive at a subset of the original finite set of points where the subset is made of so-called extreme points of the convex hull.', 'As an example, given a set of points, a Graham scan algorithm may compute a convex hull, for example, by finding an extreme point, which serves as a pivot point on the convex hull, which may be selected to be the point with the largest coordinate value (e.g., in a coordinate dimension), sorting the points in order of increasing angle about the pivot point to arrive at a star-shaped polygon (e.g., or a portion thereof) where the pivot point can “see” the segments and points of the star-shaped polygon (e.g., a convexity condition), and building the convex hull by marching around the star-shaped polygon (e.g., or portion thereof) and adding edges when making a left turn and back-tracking when making a right turn (e.g., or vice versa depending on coordinate system definition).', 'As an example, a fracture or a fault may be indicated by a curve, a line, points, etc.', 'As an example, the fracture or the fault may be split according to an angle criterion.', 'For example, the angle may be implemented to analyze the fracture or the fault with respect to one or more criteria.', 'In such an example, where a change exists that meets and/or exceeds a value of an angle criterion, a portion of the fracture or the fault may be split, for example, into two sub-portions.', 'As an example, processing may result in a number of sub-portions where each of the sub-portions may be adjacent to at least one other sub-portion.', 'As an example, one or more patches may exist, for example, between two sub-portions.', 'As an example, sub-portions may be defined by a finite set of points.', 'In such an example, an algorithm may be applied to generate a convex hull.', 'As an example, sub-portions may be processed to find a best fit plane for each of the sub-portions where an algorithm may be applied to generate a convex hull using points of the best fit plane.', 'As an example, a set of convex hulls may be used to form, at least in part, a DFN, for example, as part of a workflow.', 'As an example, a process may be implemented to generate one or more attribute cubes from raw of processed seismic data.', 'As an example, a process may be implemented to extract features (e.g., fractures, faults, etc.)', 'from one or more attribute cubes (e.g., optionally in an automated manner and/or a semi-automated manner).', 'As an example, a workflow may include interpreting one or more structures using processed data, optionally with further processing.', 'As an example, a workflow may include performing a DFN conversion to convert fractures into a DFN model.', 'As an example, a method may include performing one or more simulations using a DFN model.', 'As an example, a method may include performing one or more actions based at least in part on simulation results.\n \nFIG.', '1\n shows an example of a system \n100\n that includes various management components \n110\n to manage various aspects of a geologic environment \n150\n (e.g., an environment that includes a sedimentary basin, a reservoir \n151\n, one or more fractures \n153\n, etc.).', 'For example, the management components \n110\n may allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment \n150\n.', 'In turn, further information about the geologic environment \n150\n may become available as feedback \n160\n (e.g., optionally as input to one or more of the management components \n110\n).', 'In the example of \nFIG.', '1\n, the management components \n110\n include a seismic data component \n112\n, an additional information component \n114\n (e.g., well/logging data), a processing component \n116\n, a simulation component \n120\n, an attribute component \n130\n, an analysis/visualization component \n142\n and a workflow component \n144\n.', 'In operation, seismic data and other information provided per the components \n112\n and \n114\n may be input to the simulation component \n120\n.', 'In an example embodiment, the simulation component \n120\n may rely on entities \n122\n.', 'Entities \n122\n may include earth entities or geological objects such as wells, surfaces, reservoirs, etc.', 'In the system \n100\n, the entities \n122\n can include virtual representations of actual physical entities that are reconstructed for purposes of simulation.', 'The entities \n122\n may include entities based on data acquired via sensing, observation, etc. (e.g., the seismic data \n112\n and other information \n114\n).', 'An entity may be characterized by one or more properties (e.g., a geometrical pillar grid entity of an earth model may be characterized by a porosity property).', 'Such properties may represent one or more measurements (e.g., acquired data), calculations, etc.', 'In an example embodiment, the simulation component \n120\n may rely on a software framework such as an object-based framework.', 'In such a framework, entities may include entities based on pre-defined classes to facilitate modeling and simulation.', 'A commercially available example of an object-based framework is the MICROSOFT® .NET™ framework (Redmond, Wash.), which provides a set of extensible object classes.', 'In the .NET™ framework, an object class encapsulates a module of reusable code and associated data structures.', 'Object classes can be used to instantiate object instances for use in by a program, script, etc.', 'For example, borehole classes may define objects for representing boreholes based on well data.', 'In the example of \nFIG.', '1\n, the simulation component \n120\n may process information to conform to one or more attributes specified by the attribute component \n130\n, which may include a library of attributes.', 'Such processing may occur prior to input to the simulation component \n120\n (e.g., consider the processing component \n116\n).', 'As an example, the simulation component \n120\n may perform operations on input information based on one or more attributes specified by the attribute component \n130\n.', 'In an example embodiment, the simulation component \n120\n may construct one or more models of the geologic environment \n150\n, which may be relied on to simulate behavior of the geologic environment \n150\n (e.g., responsive to one or more acts, whether natural or artificial).', 'In the example of \nFIG.', '1\n, the analysis/visualization component \n142\n may allow for interaction with a model or model-based results.', 'As an example, output from the simulation component \n120\n may be input to one or more other workflows, as indicated by a workflow component \n144\n.', 'As an example, the simulation component \n120\n may include one or more features of a simulator such as the ECLIPSE™ reservoir simulator (Schlumberger Limited, Houston Tex.), the INTERSECT™ reservoir simulator (Schlumberger Limited, Houston Tex.), etc.', 'As an example, a reservoir or reservoirs may be simulated with respect to one or more enhanced recovery techniques (e.g., consider a thermal process such as SAGD, etc.).', 'In an example embodiment, the management components \n110\n may include features of a commercially available simulation framework such as the PETREL® seismic to simulation software framework (Schlumberger Limited, Houston, Tex.).', 'The PETREL® framework provides components that allow for optimization of exploration and development operations.', 'The PETREL® framework includes seismic to simulation software components that can output information for use in increasing reservoir performance, for example, by improving asset team productivity.', 'Through use of such a framework, various professionals (e.g., geophysicists, geologists, and reservoir engineers) can develop collaborative workflows and integrate operations to streamline processes.', 'Such a framework may be considered an application and may be considered a data-driven application (e.g., where data is input for purposes of simulating a geologic environment).', 'In an example embodiment, various aspects of the management components \n110\n may include add-ons or plug-ins that operate according to specifications of a framework environment.', 'For example, a commercially available framework environment marketed as the OCEAN® framework environment (Schlumberger Limited, Houston, Tex.) allows for integration of add-ons (or plug-ins) into a PETREL® framework workflow.', 'The OCEAN® framework environment leverages .NET® tools (Microsoft Corporation, Redmond, Wash.) and offers stable, user-friendly interfaces for efficient development.', 'In an example embodiment, various components may be implemented as add-ons (or plug-ins) that conform to and operate according to specifications of a framework environment (e.g., according to application programming interface (API) specifications, etc.).', 'FIG.', '1\n also shows an example of a framework \n170\n that includes a model simulation layer \n180\n along with a framework services layer \n190\n, a framework core layer \n195\n and a modules layer \n175\n.', 'The framework \n170\n may include the commercially available OCEAN® framework where the model simulation layer \n180\n is the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.', 'In an example embodiment, the PETREL® software may be considered a data-driven application.', 'The PETREL® software can include a framework for model building and visualization.', 'Such a model may include one or more grids.', 'The model simulation layer \n180\n may provide domain objects \n182\n, act as a data source \n184\n, provide for rendering \n186\n and provide for various user interfaces \n188\n.', 'Rendering \n186\n may provide a graphical environment in which applications can display their data while the user interfaces \n188\n may provide a common look and feel for application user interface components.', 'In the example of \nFIG.', '1\n, the domain objects \n182\n can include entity objects, property objects and optionally other objects.', 'Entity objects may be used to geometrically represent wells, surfaces, reservoirs, etc., while property objects may be used to provide property values as well as data versions and display parameters.', 'For example, an entity object may represent a well where a property object provides log information as well as version information and display information (e.g., to display the well as part of a model).', 'In the example of \nFIG.', '1\n, data may be stored in one or more data sources (or data stores, generally physical data storage devices), which may be at the same or different physical sites and accessible via one or more networks.', 'The model simulation layer \n180\n may be configured to model projects.', 'As such, a particular project may be stored where stored project information may include inputs, models, results and cases.', 'Thus, upon completion of a modeling session, a user may store a project.', 'At a later time, the project can be accessed and restored using the model simulation layer \n180\n, which can recreate instances of the relevant domain objects.', 'In the example of \nFIG.', '1\n, the geologic environment \n150\n may include layers (e.g., stratification) that include a reservoir \n151\n and that may be intersected by a fault \n153\n.', 'As an example, the geologic environment \n150\n may be outfitted with any of a variety of sensors, detectors, actuators, etc.', 'For example, equipment \n152\n may include communication circuitry to receive and to transmit information with respect to one or more networks \n155\n.', 'Such information may include information associated with downhole equipment \n154\n, which may be equipment to acquire information, to assist with resource recovery, etc.', 'Other equipment \n156\n may be located remote from a well site and include sensing, detecting, emitting or other circuitry.', 'Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.', 'For example, \nFIG.', '1\n shows a satellite in communication with the network \n155\n that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).', 'FIG.', '1\n also shows the geologic environment \n150\n as optionally including equipment \n157\n and \n158\n associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures \n159\n.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop the reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment \n157\n and/or \n158\n may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.', 'As mentioned, the system \n100\n may be used to perform one or more workflows.', 'A workflow may be a process that includes a number of worksteps.', 'A workstep may operate on data, for example, to create new data, to update existing data, etc.', 'As an example, a may operate on one or more inputs and create one or more results, for example, based on one or more algorithms.', 'As an example, a system may include a workflow editor for creation, editing, executing, etc. of a workflow.', 'In such an example, the workflow editor may provide for selection of one or more pre-defined worksteps, one or more customized worksteps, etc.', 'As an example, a workflow may be a workflow implementable in the PETREL® software, for example, that operates on seismic data, seismic attribute(s), etc.', 'As an example, a workflow may be a process implementable in the OCEAN® framework.', 'As an example, a workflow may include one or more worksteps that access a module such as a plug-in (e.g., external executable code, etc.).', 'FIG.', '2\n shows an example of a formation \n201\n, an example of a borehole \n210\n, an example of a convention \n215\n for dip, an example of a data acquisition process \n220\n, and an example of a system \n250\n.', 'As shown, the formation \n201\n includes a horizontal surface and various subsurface layers.', 'As an example, a borehole may be vertical.', 'As another example, a borehole may be deviated.', 'In the example of \nFIG.', '2\n, the borehole \n210\n may be considered a vertical borehole, for example, where the z-axis extends downwardly normal to the horizontal surface of the formation \n201\n.', 'As to the convention \n215\n for dip, as shown, the three dimensional orientation of a plane can be defined by its dip and strike.', 'Dip is the angle of slope of a plane from a horizontal plane (e.g., an imaginary plane) measured in a vertical plane in a specific direction.', 'Dip may be defined by magnitude (e.g., also known as angle or amount) and azimuth (e.g., also known as direction).', 'As shown in the convention \n215\n of \nFIG.', '2\n, various angles ϕ indicate angle of slope downwards, for example, from an imaginary horizontal plane (e.g., flat upper surface); whereas, azimuth refers to the direction towards which a dipping plane slopes (e.g., which may be given with respect to degrees, compass directions, etc.).', 'Another feature shown in the convention of \nFIG.', '2\n is strike, which is the orientation of the line created by the intersection of a dipping plane and a horizontal plane (e.g., consider the flat upper surface as being an imaginary horizontal plane).', 'Some additional terms related to dip and strike may apply to an analysis, for example, depending on circumstances, orientation of collected data, etc.', 'One term is “true dip” (see, e.g., Dip\nT \nin the convention \n215\n of \nFIG.', '2\n).', 'True dip is the dip of a plane measured directly perpendicular to strike (see, e.g., line directed northwardly and labeled “strike” and angle α\n90\n) and also the maximum possible value of dip magnitude.', 'Another term is “apparent dip” (see, e.g., Dip\nA \nin the convention \n215\n of \nFIG.', '2\n).', 'Apparent dip may be the dip of a plane as measured in any other direction except in the direction of true dip (see, e.g., ϕ\nA \nas Dip\nA \nfor angle α); however, it is possible that the apparent dip is equal to the true dip (see, e.g., α as Dip\nA\n=Dip\nT \nfor angle α\n90 \nwith respect to the strike).', 'In other words, where the term apparent dip is used (e.g., in a method, analysis, algorithm, etc.), for a particular dipping plane, a value for “apparent dip” may be equivalent to the true dip of that particular dipping plane.', 'As shown in the convention \n215\n of \nFIG.', '2\n, the dip of a plane as seen in a cross-section exactly perpendicular to the strike is true dip (see, e.g., the surface with ϕ as Dip\nA\n=Dip\nT \nfor angle α\n90 \nwith respect to the strike).', 'As indicated, dip observed in a cross-section in any other direction is apparent dip (see, e.g., surfaces labeled Dip\nA\n).', 'Further, as shown in the convention \n215\n of \nFIG.', '2\n, apparent dip may be approximately 0 degrees (e.g., parallel to a horizontal surface where an edge of a cutting plane runs along a strike direction).', 'In terms of observing dip in wellbores, true dip is observed in wells drilled vertically.', 'In wells drilled in any other orientation (or deviation), the dips observed are apparent dips (e.g., which are referred to by some as relative dips).', 'In order to determine true dip values for planes observed in such boreholes, as an example, a vector computation (e.g., based on the borehole deviation) may be applied to one or more apparent dip values.', 'As mentioned, another term that finds use in sedimentological interpretations from borehole images is “relative dip” (e.g., Dip\nR\n).', 'A value of true dip measured from borehole images in rocks deposited in very calm environments may be subtracted (e.g., using vector-subtraction) from dips in a sand body.', 'In such an example, the resulting dips are called relative dips and may find use in interpreting sand body orientation.', 'A convention such as the convention \n215\n may be used with respect to an analysis, an interpretation, an attribute, etc. (see, e.g., various blocks of the system \n100\n of \nFIG.', '1\n).', 'As an example, various types of features may be described, in part, by dip (e.g., sedimentary bedding, faults and fractures, cuestas, igneous dikes and sills, metamorphic foliation, etc.).', 'Seismic interpretation may aim to identify and classify one or more subsurface boundaries based at least in part on one or more dip parameters (e.g., angle or magnitude, azimuth, etc.).', 'As an example, various types of features (e.g., sedimentary bedding, faults and fractures, cuestas, igneous dikes and sills, metamorphic foliation, etc.) may be described at least in part by angle, at least in part by azimuth, etc.', 'As shown in the diagram \n220\n of \nFIG.', '2\n, a geobody \n225\n may be present in a geologic environment.', 'For example, the geobody \n225\n may be a salt dome.', 'A salt dome may be a mushroom-shaped or plug-shaped diapir made of salt and may have an overlying cap rock (e.g., or caprock).', 'Salt domes can form as a consequence of the relative buoyancy of salt when buried beneath other types of sediment.', 'Hydrocarbons may be found at or near a salt dome due to formation of traps due to salt movement in association evaporite mineral sealing.', 'Buoyancy differentials can cause salt to begin to flow vertically (e.g., as a salt pillow), which may cause faulting.', 'In the diagram \n220\n, the geobody \n225\n is met by layers which may each be defined by a dip angle ϕ.', 'As an example, seismic data may be acquired for a region in the form of traces.', 'In the example of \nFIG.', '2\n, the diagram \n220\n shows acquisition equipment \n222\n emitting energy from a source (e.g., a transmitter) and receiving reflected energy via one or more sensors (e.g., receivers) strung along an inline direction.', 'As the region includes layers \n223\n and the geobody \n225\n, energy emitted by a transmitter of the acquisition equipment \n222\n can reflect off the layers \n223\n and the geobody \n225\n.', 'Evidence of such reflections may be found in the acquired traces.', 'As to the portion of a trace \n226\n, energy received may be discretized by an analog-to-digital converter that operates at a sampling rate.', 'For example, the acquisition equipment \n222\n may convert energy signals sensed by sensor Q to digital samples at a rate of one sample per approximately 4 ms.', 'Given a speed of sound in a medium or media, a sample rate may be converted to an approximate distance.', 'For example, the speed of sound in rock may be of the order of around 5 km per second.', 'Thus, a sample time spacing of approximately 4 ms would correspond to a sample “depth” spacing of about 10 meters (e.g., assuming a path length from source to boundary and boundary to sensor).', 'As an example, a trace may be about 4 seconds in duration; thus, for a sampling rate of one sample at about 4 ms intervals, such a trace would include about 1000 samples where latter acquired samples correspond to deeper reflection boundaries.', 'If the 4 second trace duration of the foregoing example is divided by two (e.g., to account for reflection), for a vertically aligned source and sensor, the deepest boundary depth may be estimated to be about 10 km (e.g., assuming a speed of sound of about 5 km per second).', 'In the example of \nFIG.', '2\n, the system \n250\n includes one or more information storage devices \n252\n, one or more computers \n254\n, one or more networks \n260\n and one or more modules \n270\n.', 'As to the one or more computers \n254\n, each computer may include one or more processors (e.g., or processing cores) \n256\n and memory \n258\n for storing instructions (e.g., modules), for example, executable by at least one of the one or more processors.', 'As an example, a computer may include one or more network interfaces (e.g., wired or wireless), one or more graphics cards, a display interface (e.g., wired or wireless), etc.', 'In the example of \nFIG.', '2\n, the one or more memory storage devices \n252\n may store seismic data for a geologic environment that spans kilometers in length and width and, for example, around 10 km in depth.', 'Seismic data may be acquired with reference to a surface grid (e.g., defined with respect to inline and crossline directions).', 'For example, given grid blocks of about 40 meters by about 40 meters, a 40 km by 40 km field may include about one million traces.', 'Such traces may be considered 3D seismic data where time approximates depth.', 'As an example, a computer may include a network interface for accessing seismic data stored in one or more of the storage devices \n252\n via a network.', 'In turn, the computer may process the accessed seismic data via instructions, which may be in the form of one or more modules.', 'As an example, one or more attribute modules may be provided for processing seismic data.', 'As an example, attributes may include geometrical attributes (e.g., dip angle, azimuth, continuity, seismic trace, etc.).', 'Such attributes may be part of a structural attributes library (see, e.g., the attribute component \n130\n of \nFIG.', '1\n).', 'Structural attributes may assist with edge detection, local orientation and dip of seismic reflectors, continuity of seismic events (e.g., parallel to estimated bedding orientation), etc.', 'As an example, an edge may be defined as a discontinuity in horizontal amplitude continuity within seismic data and correspond to a fault, a fracture, etc.', 'Geometrical attributes may be spatial attributes and rely on multiple traces.', 'As mentioned, as an example, seismic data for a region may include one million traces where each trace includes one thousand samples for a total of one billion samples.', "Resources involved in processing such seismic data in a timely manner may be relatively considerable by today's standards.", 'As an example, a dip scan approach may be applied to seismic data, which involves processing seismic data with respect to discrete planes (e.g., a volume bounded by discrete planes).', 'Depending on the size of the seismic data, such an approach may involve considerable resources for timely processing.', 'Such an approach may look at local coherence between traces and their amplitudes, and therefore may be classified in the category of “apparent dip.”', 'As an example, imagery such as surface imagery (e.g., satellite, geological, geophysical, etc.) may be processed.', 'As an example, a method may analyze imagery using a splitting technique and may include generating a set of convex hulls, which may represent, for example, one or more structures (e.g., portions of a fracture, portions of a fault, etc.).', 'As an example, a framework may access surface imagery and may access sub-surface seismic data and generate a three-dimensional representation (e.g., for visualization) of surface structure and sub-surface structure, which may be joined via an interpolation process or other process.', 'For example, a latent structure may be captured by seismology and by satellite imagery and a model constructed based at least in part on analysis of seismic data and surface imagery.', 'As an example, ant-tracking may be performed as part of a workflow.', 'As an example, ant-tracking may generate an ant-tracking attribute, an ant-tracking surface, an ant-tracking volume (e.g., or cube), etc.', 'Ant-tracking may include using an algorithm that by analogy, involves “ants” finding the shortest path between their nest and their food source (e.g., by communicating using pheromones to attract other ants).', 'In such an example, the shortest path becomes marked with more pheromones than longer paths such that subsequent ants are more likely to choose the shortest path, and so on.', 'Where features may be latent (e.g., latent structure), for example, due to noise, acquisition footprint, etc., performing an analysis prior to ant-tracking may enhance the ability to track the latent features, particularly where the features have some amount of continuity (e.g., contiguous within a surface, a volume, etc.).', 'For example, fractures generated by a fracturing process (e.g., consider hydraulic fracturing) may tend to be relatively small (e.g., compared to faults) and contiguous.', 'As an example, data may be processed using one or more edge detection algorithms.', 'Various edge detection algorithms may include determining gradients (e.g., spatial derivatives of values in a data set).', 'Application of an edge detection algorithm may help uncover and highlight structures in a subterranean environment, for example, for a particular purpose.', 'For example, a workflow may aim to determine whether certain structures exist in a subterranean environment and whether those structures exist in some relationship with respect to other structures.', 'In various example embodiments, one or more analyses may be applied to data such as seismic data, data derived from seismic data, etc.', 'As an example, a method may include performing one or more analyses to detect features such as, for example, fractures, other latent structures, etc.', 'As an example, analyses may be implemented in a framework as a module, set of modules, etc., for example, to detect faults, fractures, and latent reflections.', 'As an example, one or more analyses may be performed to assist with detection of one or more features of interest in oil and gas exploration and production (E&P).', 'For example, results from an analysis may assist with well placement, geologic modeling, sill analyses, detection of fractured zones or fracture corridors, and in E&P for unconventional resources and carbonate fields (e.g., consider shale fields).', 'As an example, fracture corridors or subtle faults may give rise to seismic signals that may be exhibited in acquired seismic data as small-amplitude self-incoherent features, for example, in cross sections and as lineaments on slices or seismic surfaces.', 'Detection of such features may include processing seismic signals, seismic data or both to generate one or more edge detection attributes, for example, where an attribute may be considered a measurable “property” of seismic data (e.g., consider amplitude, dip, frequency, phase, polarity, etc.).', 'For example, an attribute may be a value or a set of values derived from seismic signals, seismic data, etc. and defined with respect to a coordinate system (e.g., one-dimensional, two-dimensional, three-dimensional, four-dimensional or of an even higher dimension).', 'As an example, a dimension may be a spatial dimension, a time dimension, a frequency dimension, etc.', 'As an example, consider providing seismic data as a “cube” where each voxel (volume element) in the cube has a value.', 'In such an example, an edge detection algorithm may process the values in a cube to generate new values where the new values are referred to collectively as an edge detection attribute (e.g., an attribute cube).', 'As an example, a seismic cube (e.g., a seismic volume or seismic data for a volume) may be processed to generate an attribute cube (e.g., an attribute volume or attribute values for a volume).', 'As another example, a seismic surface may be processed to generate an attribute surface.', 'As yet another example, a seismic line may be processed to generate an attribute line.', 'As an example, a seismic point may be processed to generate an attribute point.', 'Attributes may be derived, measured, etc., for example, at one instant in time, for multiple instances in time, over a time window, etc. and, for example, may be measured on a single trace, on a set of traces, on a surface interpreted from seismic data, etc.', 'Attribute analysis may include assessment of various parameters, for example, as to a reservoir, consider a hydrocarbon indicator derived from an amplitude variation with offset (AVO) analysis (e.g., or amplitude variation with angle (AVA), etc.).', 'As an example, a model may be a seismic discontinuity plane model (e.g., an “SDP” model), which may be derived from seismic data (e.g., raw data, one or more attributes, etc.).', 'As an example, a method may include using seismic discontinuity planes (SDP) for performing a discrete fracture network (DFN) conversion to generate a DFN model.', 'As an example, a method may be implemented where complex fracture surfaces may be represented, for example, by lists of points (e.g., at different depths).', 'As an example, one or more SDPs may be extracted from a seismic attribute cube or cubes.', 'In such an example, an SDP may “physically” (e.g., spatially) follow information derived from seismic data, which includes signal information that may zigzag, be wavy, etc.', 'Thus, an SDP may zigzag, be wavy, etc.', 'As to a DFN model, it may approximate an interpretation of natural and/or induced fractures.', 'For example, a DFN model can include a family of convex planar polygons that are amenable to one or more numerical modeling techniques.', 'A DFN model can include “patches” that represent fractures where an individual fracture may be represented by one or more convex planar polygons.', 'As an example, a method can include transforming an SDP model (e.g., with wavy surfaces, etc.) to a DFN model (e.g., with convex polygonal surfaces).', 'As an example, a transformation can include receiving a multi-faceted SDP model where such facets may be oriented differently.', 'In such an example, a method can include splitting the SDP model on a facet-by-facet basis, for example, based at least in part on facet orientation.', 'As an example, a method can aim to generate a set or sets of split facets that maintain fracture density and orientation relatively consistent with that of the SDP model being split.', 'Such a process may be implemented, for example, for purposes of quality control.', 'For example, an analysis may compare split facets to one or more SDPs (e.g., using one or more spatial criteria).', 'In such an example, one or more splitting parameters may be adjusted to achieve a desire level of consistency between the one or more SDPs and facets split therefrom.', 'Such a process may, for example, allow for tailoring a DFN model formed at least in part by facets split from a SDP model.', 'As an example, a DFN model may include patches that conform to one or more connectivity criteria.', 'For example, consider a connectivity criterion that states that adjacent patches in a DFN model are to be connected with each other, for example, where they belong to two adjacent parts of the same SDP before splitting.', 'As an example, a fracture network may be analyzed to generate a plurality of SDPs that may form one or more SDP models.', 'As an example, a SDP model may include of the order of thousands of SDPs (e.g., possibly one hundred thousand or more SDPs may be included in an SDP model of a fracture network).', 'As to transforming an SDP model to a DFN model, as an example, consider a model that includes 100,000 SDPs that are to be split to form patches for the DFN model.', 'In such an example, if an individual SDP takes about one second to process, the 100,000 SDPs may take about 100,000 seconds collectively (e.g., more than about 10 days).', 'As an example, a method can include transforming a SDP model to convex polygons suitable for use as DFN model patches.', 'Such a method may include one or more algorithms that can be implemented in serial and/or in parallel.', 'As an example, a method may include one or more branches, for example, to analyze a SDP, or a portion thereof, and then decide whether to process the SDP, or a portion thereof, using one or more techniques.', 'In such an example, an SDP, or a portion thereof, may be subject to one or more splitting process, which may vary in terms of demand of computational resources.', 'As an example, a method may decide to implement a best fit plane process as to an SDP to generate a convex planar polygon suitable for use as a patch in a DFN model.', 'As an example, a method may decide to implement a different process as to an SDP, or a portion thereof, where, for example, a reservoir may be a fractured, unconventional reservoir (e.g., such that multiple polygons approximate an SDP).', 'As an example, a method may include a polygon criterion, for example, consider a maximum polygon number per SDP, a maximum polygon density per SDP, etc.', 'For example, a maximum polygon number per SDP may be of the order of ten or tens of polygons per SDP.', 'As an example, a method may include a rose diagram analysis that may be applied to polygons resulting from a process that splits SDPs into polygons.', 'For example, a rose diagram analysis may show dip and azimuth distribution (e.g., of a fracture network).', 'As an example, one or more polygon criteria may be adjusted based at least in part on a rose diagram analysis.', 'FIG.', '3\n shows an example of a method \n310\n that includes a reception block \n314\n for receiving information that defines a three-dimensional subterranean structure, a split block \n318\n for splitting the subterranean structure into portions, a generation block \n322\n for generating convex hulls for the portions, a generation block \n326\n for generating a discrete fracture network (DFN) based at least in part on the convex hulls and a simulation block \n330\n for simulating phenomena associated with a subterranean formation based at least in part on a model that includes the discrete fracture network (DFN).', 'The method \n310\n is shown in \nFIG.', '3\n in association with various computer-readable medium (CRM) blocks \n315\n, \n319\n, \n323\n, \n327\n and \n331\n.', 'Such blocks generally include instructions suitable for execution by one or more processors (or processor cores) to instruct a computing device or system to perform one or more actions.', 'While various blocks are shown, a single medium may be configured with instructions to allow for, at least in part, performance of various actions of the method \n300\n.', 'As an example, a computer-readable medium (CRM) may be a computer-readable storage medium.', 'As an example, a computer-readable medium may be non-transitory and not a carrier wave.', 'As an example, the method \n310\n, or a portion thereof, may be optionally implemented as a plug-in to a framework.', 'For example, consider a plug-in to the OCEAN® framework that can generate convex hulls (e.g., per the generation block \n322\n of \nFIG.', '3\n).', 'In such an example, the framework may include one or more modules that can build at least a portion of a DFN based at least in part on such convex hulls.', 'As an example, a method may include converting complex fractures into a discrete fracture network (DFN), which may be in a data format suitable for fault and fracture modeling (e.g., in unconventional reservoir or other reservoir).', 'As an example, a fault and fracture model (e.g., represented by a DFN or DFNs) may assist with exploration and exploitation of a reservoir or reservoirs.', 'As an example, a seismic-to-simulation framework may be configured for input of a DFN or DFNs.', 'As an example, a reservoir may include many fractures.', 'For example, a reservoir may include of the order of tens of thousands of fractures.', 'As an example, a method that includes splitting may be implemented to split a fracture surface into parts where each part may, for example, be approximated by a best fit plane.', 'As an example, a splitting algorithm may include an adjustable angle parameter, which may have a default value, may be determined via a learning algorithm, may be set via a user interface (e.g., a graphical user interface, etc.).', 'As an example, a splitting method may assume that a complex surface may be split based on an angle.', 'In such an example, a trend change in a selected direction (e.g., horizontal direction) larger than the angle may call for splitting of the surface.', 'As an example, for a relatively smooth curved surface, parts resulting from splitting may retain connections with each other.', 'As an example, a Graham scan algorithm may be employed to determine a convex hull for each part (e.g., based on a best fit plane for each part of the split surface).', 'A set of convex hulls may be provided as a basis for forming a DFN model.', 'Accordingly, as an example, a method can include converting a complex fracture surface or surfaces to convex planar polygons that may be used to form at least part of a DFN model.\n \nFIG.', '4\n shows an example of a method \n410\n and approximate illustrations of information \n411\n that defines a subterranean structure, points in space \n415\n, an area \n419\n that is defined at least in part via points in space, and a convex hull \n423\n that may be defined at least in part via points in space associated with the area \n419\n.', 'As shown, the method \n410\n includes a reception block \n414\n for receiving information that defines a three-dimensional subterranean structure (e.g., consider the information \n411\n, which may be an SDP, etc.), a split block \n418\n for splitting at least a portion of the three-dimensional subterranean structure into areas (e.g., consider the area \n419\n, etc.)', 'and a generation block \n422\n for generating convex hulls for areas (e.g., consider the convex hull \n423\n of the area \n419\n).', 'As an example, a convex hull may be considered to be a type of proxy (e.g., a refined proxy).', 'As an example, a proxy may be defined by its vertices.', 'For example, a proxy that is a convex pentagon may be defined by five points in space.', 'Thus, an area that is defined by a plurality of points in space such as the points \n415\n may be represented by a reduced amount of information (e.g., vertices in space of a convex polygon, etc.).', 'In the example of \nFIG.', '4\n, the received information may be split using a partitioning process that can define, at least in part, one or more areas.', 'As an example, a proxy may be defined as an area that represents a portion of a subterranean structure (e.g., a fracture that may be part of a fracture network).', 'Such a proxy may be a “lightweight” representation of information such as, for example, seismic data, attribute data, etc. (e.g., spatial data stemming from one or more data acquisition techniques).', 'As an example, seismic data may be processed, interpreted, etc. to form, for example, a set of points in space.', 'As an example, a proxy may be represented spatially (e.g., in a multi-dimensional space) by a set of points that collectively define a convex hull (e.g., a convex planar polygon).', 'As an example, a proxy may be based at least in part on a set of points in space.', 'In such an example, the set of points may be projected within an area, for example, a set of points may be projected onto a plane (e.g., a planar area, etc.).', 'As an example, a generation process that can generate a convex hull may process a set of points associated with an area (e.g., a planar area, etc.).', 'As an example, a method may include an automatically processing information that, for example, approximates individual areas based at least in part on points in space (e.g., via groupings of points, etc.).', 'For example, in \nFIG.', '4\n, the points \n415\n may be used to define one or more areas (e.g., the area \n419\n and its neighbor, etc.).', 'As an example, a proxy may be such an area or, for example, a proxy may be determined using a best fit plane to a set of points (e.g., via a least squares or other type of fitting technique).', 'As to how a proxy is defined, as an example, a method may include assessing a fit of an area to points in space (e.g., with respect to one or more criteria).', 'As an example, an assessment may consider fit with respect to one or more adjacent areas and/or proxies (e.g., as to connectivity, etc.).', 'As an example, a method can include receiving an SDP and partitioning the SDP via an area partition process.', 'Such a method may further include looping over areas where, for example, for an individual area, a process may fine tune the area, which may be considered a proxy.', 'For example, consider a process that includes projecting points within an area onto a plane and finding a convex polygon that is within the plane.', 'Such a process may, for example, include an analysis that helps to ensure connectivity.', 'For example, such an analysis may aim to connect adjacent convex polygons (e.g., to adhere to a patch criterion of a DFN model).', 'FIG.', '5\n shows an example of a method \n510\n that includes a reception block \n512\n for receiving information (e.g., an SDP, an SDP model, etc.), an identification block \n516\n for identifying a structure based at least in part on a portion of the information, and a split block \n520\n for splitting the identified structure.', 'In the example of \nFIG.', '5\n, the split block \n520\n may perform splitting in one or more directions.', 'For example, a horizontal split block \n522\n may provide for splitting via an analysis that assesses a structure with respect to a horizon, horizons, a reference horizontal line or lines, etc.; whereas a vertical split block \n524\n may provide for splitting via an analysis that assesses a structure with respect to a vertical well, a vertical structure, a reference vertical line or lines, etc.', 'In the example of \nFIG.', '5\n, the method \n510\n includes a commencement block \n530\n for commencing a loop that can process a plurality of individual areas resulting from a splitting process (e.g., per the split block \n520\n).', 'As shown, the method \n510\n includes a decision block \n534\n for deciding whether a last area (e.g., of N areas resulting from splitting a structure) has been processed.', 'Where the decision block \n534\n decides that a last area has been processed, the method \n510\n may continue to a termination block \n542\n (e.g., or other block, workflow, etc.).', 'Where the decision block \n534\n decides that a last area has not been processed, the method \n510\n continues to a determination block \n538\n for determining a proxy as to an area (e.g., current area being processed), which may include determining a proxy according to one or more connectivity criteria that can connect a proxy to a proxy of an adjacent area.', 'In the example of \nFIG.', '5\n, the method \n510\n includes a decision block \n542\n for deciding whether a proxy achieves an adequate fit with respect to that proxy being part of the identified structure (e.g., per the identification block \n516\n).', 'For example, one or more criteria may be provided for purposes of assessing how well a proxy fits a structure.', 'Such one or more criteria may include spatial criteria, optionally based at least in part on one or more statistically calculated values (e.g., mean, standard deviation, etc.).', 'As an example, the decision block \n542\n may include assessing fit with respect to one or more connectivity criteria.', 'For example, where a prior proxy exists adjacent to a current proxy, the decision block \n542\n may determine whether the current proxy is “connected” to the prior proxy.', 'Such a determination may include analyzing an edge of the prior proxy with respect to an edge of the current proxy, for example, as to coincidence, overlap, etc.', 'As shown, where the decision block \n542\n decides that the proxy fit is “OK”, the method \n510\n can continue to a determination block \n550\n for determining a convex hull on the current proxy.', 'As an example, points may be analyzed via a Graham scan technique that can identify “outermost” points within which other may points exist.', 'In such an example, the outermost points can define a convex hull (e.g., a planar, convex polygon).', 'As shown, where the decision block \n542\n decides that the proxy fit is not “OK”, the method \n510\n can continue to a determination block \n546\n that can determine a convex hull of a “best” fit plane (e.g., a best fit plane of the current proxy) and that may also include insertion of fill, for example, for purposes of complying with one or more connectivity criteria.', 'In the example of \nFIG.', '5\n, where a convex hull or a convex hull and one or more insert fills have been determined, the method \n510\n may continue at an addition block \n554\n for adding at least a convex hull to a result (e.g., as a first convex hull or as a subsequent convex hull, optionally with one or more fills).', 'The method \n510\n may then iterate by selecting another area to process.', 'For example, as shown, a selection block \n558\n may be included for selecting a next area to process.', 'The method \n510\n may therefore include a loop with one or more paths, for example, depending on whether one or more fit criteria are met.', 'In the example of \nFIG.', '5\n, one path may be more computationally demanding than another path.', 'As an example, a ratio of proxies to one path or to another path may depend on received information of the reception block \n512\n, a structure identified per the identification block \n516\n, an identification technique applied by the identification block \n516\n, a splitting technique per the splitting block \n520\n, one or more fit criteria, etc.', 'As an example, a parameter such as a polygon limit parameter, a polygon density parameter, etc. (e.g., of a splitting process, etc.) may be selected and/or adjusted in a manner that can have an effect as to a path taken for a proxy.', 'In the example of \nFIG.', '5\n, the reception block \n512\n may include receiving an SDP.', 'As an example, the method \n510\n may include outputting (e.g., upon termination per the termination block \n542\n) convex planar polygons, which may be used, for example, as patches of a DFN model.', 'The method \n510\n may include automatically splitting one or more SDPs of an SDP set (e.g., an SDP model) one-by-one.', 'As an example, a method may be implemented at least in part in parallel.', 'For example, where a SDP model includes a plurality of SDPs, at least a portion of the SDPs may be processed in parallel.', 'As an example, where “patches” are connected, a structure may be processed in serial, for example, in a manner that successively generates convex planar polygons that are added together, optionally with fill to help meet one or more connectivity criteria.\n \nFIG.', '6\n shows an example of data \n630\n and processed data \n650\n that includes a set of convex hulls.', 'As an example, the set of convex hulls may be used to form, at least in part, a DFN model, for example, where individual portions of a fracture network are represented as convex planar polygons.', 'As an example, a method can include receiving data and processing the data to generate a DFN (e.g., a DFN model).\n \nFIG.', '7\n shows an example of a method \n710\n that includes providing a surface in a plane (e.g., an I, J plane of an I, J, K coordinate or index system), which may be represented as a curve, and splitting the curve based on an angle criterion (see block \n714\n).', 'Splitting may include forming line segments, for example, as shown in a block \n718\n.', 'In such an example, the curve of the surface in the plane may be represented by segments where each of the segments includes end points.', 'As an example, splitting may occur in one or more other planes (e.g., of the I, J, K coordinate or index system).', 'For example, splitting may include horizontal splitting and vertical splitting (e.g., splitting in an I, J plane and splitting in a plane that extends in the K coordinate direction).', 'Where splitting occurs in multiple planes, as an example, the planes may be orthogonal.', 'A result of splitting can be areas defined by points, lines, etc. (e.g., in a multidimensional space).', 'FIG.', '7\n also shows an example diagram \n720\n of three segments with points and a split angle (θ).', 'As shown, a neighbor count may be a parameter or metric with respect to points that may be defined spatially with respect to information such as, for example, information of an SDP.', 'As to a split angle, it may be defined with respect to lines that may be, for example, fit to points.', 'As an example, a split angle may be defined with respect to a reference.', 'For example, given a locus, a first line may define a first tangent to the locus and a second line may define a second tangent to the locus.', 'In such an example, the first and second tangents may define an angle therebetween that can be compared to a split angle.', 'In such an example, where the angle is less than the split angle, the first and the second lines may be considered part of a common line of an area; whereas, where the angle meets or exceeds the split angle, the first and the second lines may be considered to be part of two different areas (e.g., two adjacent areas).', 'As to selection of a curve, as the shape of intersection lines of a fracture and slices in depth may be structurally similar, a method may include selecting a longest slice to represent a shape of a fracture (e.g., from a top view as in the block \n714\n and \n718\n).', 'In such an example, each segment of the longest slice may be estimated by a best fit line segment S\ni \nwhich may be written in the form: \n \nS\ni\n:y\n=(tan α\ni\n)\nx+b,x\ni\n θ\u2003\u2003(2)', 'In such an example, the fracture may be split into several areas (e.g., from a top view).', 'As an example, each bisector plane denoted by b\ni\n, which can be the border of a pair of two areas, may be stored.', 'As an example, where one or more vertical gaps exist between different parts of a mesh within a region, the mesh may be further split into several isolated meshes.', 'As an example, as part of a DFN conversion process, a method may commence with an area (e.g., Area_0) of a plurality of areas and process each area one-by-one.', 'As an example, for Area_0, if meshes can be approximated by a single best fit plane c\n0\n, then there may be an intersection line of b\n0 \nand c\n0\n, which may be called a connection line and be denoted by con\ni\n.', 'Otherwise, meshes within this area may be approximated respectively by their own best fit plane.', 'As an example, after proxies of meshes in an area are determined, points on the boundary of each fracture mesh may be determined and input to a Graham scan algorithm to generate respective convex hulls.', 'In such an example, each fracture mesh may be represented by a convex polygon p\ni,j \non its own proxy.', 'As an example, prior to consideration of an Area i (i>0), if con\n0 \nexists, a method may help to ensure that two points of a final convex polygon are on con\n0\n.', 'As an example, if meshes within an Area i can be approximated by a single best fit plane c\ni\n, then an intersection line con\ni \nof b\ni \nand c\ni \nmay be formed.', 'For example, consider that two points may be found on con\ni−1 \nand another two points may be found on con\ni\n.', 'With other boundary points, a convex hull may also be found using a Graham scan algorithm.', 'In such an example, as the proxy convex polygons of the meshes on both sides of the bisector plane ({p\ni−1,j\n} and {p\ni,j\n}) include points on the same connection line, split meshes may be connected through the connection lines (see, e.g., the processed data \n650\n of \nFIG.', '6\n and hulls \n954\n and \n955\n of \nFIG.', '9\n).', 'If meshes within an Area i are not approximated well by a single best fit plane, the meshes within this area may be approximated respectively by their own best fit plane.', 'As an example, meshes in each area may be converted in such a manner.', 'As an example, after processing areas, a method may output a convex polygon set {p\ni,j\n}, which may be used to form, at least in part, a DFN model.', 'Such a model may be used for one or more purposes.', 'For example, a simulator may receive a DFN model as input for purposes of simulation of fluid flow in one or more fractures of the DFN model (e.g., as may be represented by a patch or patches).', 'As an example, information received may include points.', 'For example, an SDP may be specified according to a data structure that includes points (e.g., a list of points, which may be numbered, etc.).', 'Such points may be defined in space, for example, using an appropriate coordinate system (e.g., Cartesian coordinate system, etc.).', 'As an example, a method can include scanning one or more point lists horizontally and/or vertically to detect one or more split points.', 'As shown in \nFIG.', '7\n, points of a point list (e.g., of an SDP) may be at an approximate depth.', 'During scanning through the point list, a method may employ a plurality of parameters, for example, consider a split angle parameter and a neighbor count parameters (see, e.g., the diagram \n720\n of \nFIG.', '7\n).', 'As an example, a split angle may optionally be a parameter that can be set and/or selected via a graphical user interface, a batch file, etc.', 'As an example, a splitting process may determine that a split occurs when a change of trend is larger than an angle value as given by a split angle parameter.', 'In such an example, points to either side of the split (e.g., a split location or split point) can be divided into two different areas.', 'As an example, a neighbor count parameter value may be dependent on received information.', 'For example, a neighbor count may depend at least in part on one or more characteristics of an SDP.', 'As an example, in an SDP model that includes a plurality of SPD, neighbor count may differ for at least one of the SPDs.', 'As an example, an algorithm may compute a neighbor count parameter value adaptively, which may, for example, depends on one or more of SDP size, standard deviation of SDP, etc.\n \nFIG.', '8\n shows a graphical illustration \n810\n that corresponds to a Graham scan technique, which may be employed to determine a convex hull, for example, given a set of points.', 'In the example of \nFIG.', '8\n, a set of points numbered from 0 to 12 are illustrated where of those points, the points 0, 1, 3, 10 and 12 can spatially define vertexes of a convex hull (e.g., a convex polygon).', 'In the example of \nFIG.', '8\n, the convex hull includes five vertexes and five sides (e.g., a pentagon), noting that other types of hulls may be determined for a give set of points.', 'As an example, a Graham scan technique may be used to find a convex hull for a finite point set on “2D” panel.', 'As an example, a convex hull of a set of points S in n dimensions may be defined as the intersection of convex sets including S. As an example, a convex hull may be defined by properties.', 'For example, consider the following: a convex hull is a convex polygon; a convex hull planar; and a convex hull includes projection points on a proxy (e.g., a proxy that corresponds to data such as SDP data, etc.).', 'As an example, one or more connectivity criteria may be employed with respect to an algorithm that can determine a convex hull.', 'For example, a criterion may act to include those points of a previously determined convex hull (e.g., of a proxy or area) that are vertices on an intersection line with a current proxy (e.g. current area).', 'In such an example, an algorithm may commence with those points as part of a set that defines, in part, a convex hull to be determined.', 'As to a first proxy or area, such a criterion may not apply (e.g., unless an intersection line is provided, etc.).', 'As an example, a method may employ a Graham scan technique where at least one point that defines a convex hull is predetermined based at least in part on a border of a convex hull that is to be adjacent to the convex hull that is to be determined.', 'In such an example, at least some amount of connectivity between the existing convex hull and the “to be determined” convex hull may be assured.', 'For example, in the illustration \n810\n of \nFIG. 8\n, the points P3 and P10 are points that are vertices of a pre-existing convex polygon.\n \nFIG.', '9\n shows a method \n910\n that includes a data block \n930\n and a processed data block \n950\n.', 'As shown in the data block \n930\n, data may be processed, for example, at various depths (e.g., along a depth coordinate) using one or more angle criteria.', 'Such an approach may split a structure into segments, for example, where each segment includes end points.', 'In such an example, at each depth, segments may be generated via splitting of a line, curve, etc. of a structure in a plane (e.g., a horizontal plane).', 'In the example of \nFIG.', '9\n, areas may be formed (see, e.g., the block \n714\n of \nFIG.', '7\n) and segments may be formed (see, e.g., the block \n718\n of \nFIG.', '7\n).', 'As shown in the block \n950\n of \nFIG.', '9\n, information generated in the block \n930\n may be used to determine extreme points, per a Graham scan or other type of algorithm that may find a convex hull.', 'As shown, the surface indicated by the data of the block \n930\n may be split into eight convex hulls \n951\n, \n952\n, \n953\n, \n954\n, \n955\n, \n956\n, \n957\n and \n958\n.', 'Collectively, the eight convex hulls may be used to form a part of a DFN model.', 'In such an example, the DFN model may honor one or more rules, for example, as to polygons.\n \nFIG.', '10\n shows an example of a set of polygons \n1030\n that includes a polygon \n1031\n and a polygon \n1033\n with a gap \n1034\n and a set of polygons \n1050\n that includes a polygon \n1052\n positioned at least in part in the gap \n1032\n.', 'In such an example, the polygon \n1052\n may be inserted to meet one or more connectivity criteria as to the polygon \n1033\n with respect to the polygon \n1031\n.', 'As mentioned with respect to the method \n510\n of \nFIG.', '5\n, one or more fit criteria (e.g., which may include one or more connectivity criteria) may not be met, for example, where a proxy does not adequately “match” an area of a received data set (e.g., SDP data).', 'In such an example, a gap may exist between two adjacent polygons (e.g., due to some amount of mismatch).', 'As an example, where a proxy does not fit an SDP well enough, a method may include discarding the proxy and determining, for example, a best fit plane.', 'For example, in the set of polygons \n1030\n, the polygon \n1031\n may be a proxy and the polygon \n1033\n may be a best fit plane.', 'In such an example, the best fit plane as represented by the polygon \n1033\n does not adequately connect to the polygon \n1031\n.', 'For example, a connection line may not be shared between the polygon \n1031\n and the polygon \n1033\n (e.g., connectivity may be lost).', 'As illustrated with respect to the set of polygons \n1050\n, a polygon \n1052\n may be inserted between the polygon \n1031\n and the polygon \n1033\n such that connectivity exists.', 'As an example, an inserted polygon may be a triangle with appropriate dimensions and orientation to provide for connectivity.', 'As an example, a criterion may be a normalized average distance of points to a proxy, which may be defined as a parameter “d”.', 'In such an example, a threshold value may be set where, for example, if d is greater than the threshold value, a method may consider a proxy fit inadequate.', 'In such an example, a method may determine a best fit plane and use the best fit plane as an alternative to the proxy.', 'As a best fit plane may not assure connectivity to a neighboring polygon, a method may include inserting one or more triangles as fill.', 'As an example, a threshold value may be defined by a user, for example, via a graphical user interface, a batch file, etc.', 'As an example, a threshold value may depend on one or more characteristics of a geologic formation, an SDP, an SDP model, a DFN, a portion of a DFN, etc.\n \nFIG.', '11\n shows a series of examples of plots \n1110\n, \n1130\n, \n1152\n and \n1154\n.', 'As an example, polygons may be analyzed, for example, to assess a subterranean region.', 'For example, polygons generated via a method such as the method \n410\n of \nFIG.', '4\n, the method \n510\n of \nFIG.', '5\n, etc. may be analyzed as to dip angle.', 'For example, the plot \n1110\n shows number of samples (e.g., number of polygons) with respect to dip angle.', 'As shown, a distribution exists where the number of samples generally increases as dip angle approaches 90 degrees.', 'As an example, polygons may be analyzed with respect to strike and, for example, plotted via a rose diagram.', 'In \nFIG.', '11\n, the plot \n1130\n shows strike information for over 40,000 samples where, as may be ascertained via the plot \n1110\n, a large portion of the samples run across the rose diagram plot \n1130\n from about 90 degrees to about 270 degrees.', 'The plots \n1152\n and \n1154\n of \nFIG.', '11\n correspond to fractures extending approximately north-south and fractures extending approximately east-west, respectively.', 'As shown, the north-south fractures tend to be shorter in length than the east-west fractures.', 'As an example, a method can include performing one or more statistical analyses based at least in part on polygon data (e.g., convex hull data).', 'As an example, statistics may be computed for one or more of fracture dip, orientation and fracture length.', 'As illustrated in \nFIG.', '11\n, the fractures may be classified as being high angle with a portion having an approximately east-west orientation.', 'As an example, a method may compute a statistical distribution for fractures based at least in part on polygons, which may uncover additional information such as existence of a portion of alternatively directed fractures.', 'For example, while observations from the field may indicate approximately east-west fractures, a statistical analysis may uncover an anticline or other features.', 'For example, an anticline may be indicated by a portion of approximately north-south fractures, which may be smaller in scale than the approximate east-west fractures (see, e.g., the plots \n1152\n and \n1154\n).', 'FIG.', '12\n shows an example of a method \n1200\n that includes a reception block \n1210\n for receiving seismic and/or attribute information and a generation block \n1230\n for generating a seismic discontinuity plane (SDP) model.', 'In such an example, the method \n1200\n may optionally include a reception block \n1240\n for receiving one or more other types of information such as, for example, log information, which may be used, at least in part, by the generation block \n1230\n for generating the SDP model.', 'As shown in the example of \nFIG.', '12\n, the method \n1200\n includes a determination block \n1250\n for determining convex hulls based at least in part on the SDP model.', 'For example, an SDP model may include points in space where such points may be analyzed to determine convex hulls.', 'For example, consider the method \n410\n of \nFIG.', '4\n, which is illustrated along with approximate graphical representations of points in space.', 'As an example, the determination block \n1250\n may include filling, for example, filling one or more regions between convex hulls with one or more polygons to help to assure connectivity where adjacent convex hulls, where appropriate.', 'The method \n1200\n also includes a generation block \n1270\n for generating a discrete fracture network (DFN) model based at least in part on a portion of the convex hulls (e.g., an optionally fill, if present).', 'In such an example, the DFN model may be input to a simulator, for example, per a simulation block \n1290\n, for simulating physical phenomena in a geologic environment.', 'As an example, such a simulator may be a reservoir simulator that can solve for pressure values, saturation values, etc., which may indicate how one or more fluids flow in the geologic environment.', 'As an example, a method may include determining a dip for a subterranean structure.', 'As an example, a subterranean structure may be a fault, faults, a fracture, fractures or other structure.', 'As an example, a structure may be or include a fracture network (e.g., fractures that include intersections).', 'As an example, dip may be defined as the magnitude of the inclination of a plane from horizontal.', 'As an example, true, or maximum, dip may be measured perpendicular to a strike.', 'As an example, apparent dip may be measured in a direction other than perpendicular to a strike.', 'As an example, dip may be defined as an angle between a planar feature, such as a sedimentary bed, a fault, a fracture, etc. and a plane (e.g., a horizontal plane).', 'As an example, dip (e.g., dip information) may facilitate analysis of a subterranean formation.', 'For example, dip information may facilitate fault and/or fracture analysis.', 'Where a structure may be represented as a planar surface, dip may be based on the angle of that planar surface with respect to another surface (e.g., a horizontal surface).', 'As an example, where a structure includes a curve or one or more curved portion (e.g., or other shapes, etc.), dip determination may be more challenging.', 'As an example, consider a reservoir classified as an unconventional reservoir.', 'In such an example, a seismic survey or surveys may be conducted that acquire seismic data (e.g., seismic signals that may be represented as values in a seismic data set).', 'In such an example, shapes of surfaces extracted from seismic data that may represent fractures may be more complex than, for example, a single planar surface.', 'As an example, an analysis may include plotting information on a rose diagram (see, e.g., the rose diagram plot \n1130\n of \nFIG.', '11\n).', 'For example, a rose diagram may illustrate one or more fracture strike orientations and may visually indicate that more than one fracture set may exist.', 'As an example, a rose diagram may illustrate dip information (e.g., consider dip azimuth directions; noting that various relationships may exist between strike information and dip information).', 'As an example, a method may include determining dip of a complex fracture in a manner that may reduce influence of data that may lead to low dip estimates.', 'For example, a fracture may be expected to have a dip value that is relatively high.', 'For example, a fracture may be expected to have an angle that is not close to zero (e.g., where zero represents a horizontal plane).', 'As an example, a method may include determining a dip for a complex surface based in part on an average unit normal vector in a local triangular mesh that represents the complex surface (e.g., or a portion of the complex surface).', 'For example, such a method may include triangulation of the complex surface.', 'As an example, a triangulation process may be a tessellation process that includes using triangles that may differ in shape to fill a region (e.g., a surface).', 'In such an example, the unit normal vector of each triangle in the triangular mesh may be computed.', 'As an example, the unit normal vectors may be summed, for example, using areas of each of the triangles as weights.', 'A method may then determine a dip based on an average unit normal vector (e.g., the dip of the complex surface may be estimated from the average unit normal).', 'As an example, a tessellation process may include using one or more types of polygons.', 'In such an example, each of the polygons may include associated information from which a unit normal and an area may be determined.', 'In such an example, areas may be applied as weights for normal in a process that may determine an average normal (e.g., an average unit normal).', 'As an example, a method that employs tessellation for polygon filling of a surface together with normal and area computation may be robust with respect to variations that may exist in the surface.', 'For example, such an approach may be robust where some portions may differ from a suitable, realistic dip for the surface.', 'FIG.', '13\n shows an example of a method \n1310\n that includes a reception block \n1314\n for receiving information that defines a three-dimensional subterranean structure; a tessellation block \n1318\n for tessellating the subterranean structure into triangles (e.g., based at least in part on the provided information); a computation block \n1322\n for computing a normal for each of the triangles; a computation block \n1326\n for computing an area for each of the triangles; and a determination block \n1330\n for determining a dip for the subterranean structure based on the normals and the areas of the triangles.', 'As an example, such a method may include simulating phenomena associated with a subterranean formation based at least in part on the dip.', 'The method \n1310\n is shown in \nFIG.', '13\n in association with various computer-readable medium (CRM) blocks \n1315\n, \n1319\n, \n1323\n, \n1327\n and \n1331\n.', 'Such blocks generally include instructions suitable for execution by one or more processors (or processor cores) to instruct a computing device or system to perform one or more actions.', 'While various blocks are shown, a single medium may be configured with instructions to allow for, at least in part, performance of various actions of the method \n1310\n.', 'As an example, a computer-readable medium (CRM) may be a computer-readable storage medium.', 'As an example, the method \n1310\n, or a portion thereof, may be optionally implemented as a plug-in to a framework.', 'For example, consider a plug-in to the OCEAN® framework that can determine dip information (e.g., per the determination block \n1330\n of \nFIG.', '13\n).', 'As an example, a method such as the method \n1310\n of \nFIG.', '13\n may be performed as part of a workflow that may include at least a portion of a method such as the method \n310\n of \nFIG.', '3\n.', 'For example, where tessellation is performed per the tessellation block \n1316\n, tessellated shapes (e.g., polygons) may be analyzed via a partitioning process and/or a splitting process (see, e.g., the split block \n318\n of the method \n310\n of \nFIG.', '3\n).', 'For example, a plurality of tessellated shapes may be combined to define an area, which may be processed to define a proxy.', 'As an example, information from a method such as the method \n310\n of \nFIG.', '3\n and information from a method such as the method \n1310\n of \nFIG.', '13\n may be analyzed.', 'For example, consider the plots \n1110\n, \n1130\n, \n1152\n and \n1154\n of \nFIG.', '11\n.', 'In particular, consider the plot \n1110\n, which shows number of samples versus dip angle.', 'As an example, convex hulls may be analyzed as to dip angle and tessellated polygons may be analyzed as to dip angle.', 'As an example, orientations may be plotted for convex hulls and/or tessellated polygons, for example, using a rose diagram (see, e.g., the rose diagram \n1130\n of \nFIG.', '11\n).', 'As an example, a method may include performing a workflow where the workflow includes triangulation of a complex surface; computation of the unit normal of each triangle; computation of the area of each triangle; summing the unit normal with the areas as the weights; calculating the dip of a plane that is perpendicular to the weighted average normal; and using the calculated dip in a subsequent process (e.g., plotting a rose diagram, simulating phenomena, etc.).', 'As an example, a complex surface may be organized as several point lists, for example, at different depths.', 'In such an example, a method may include looping over the points in two adjacent point lists to form triangles where, after performing such an operation to various adjacent point lists for the complex surface, the triangulation of the complex surface may be completed.', 'As an example, a method may include computing a normal (e.g., a unit normal) for individual triangles in a triangular mesh.', 'As an example, given a triangle, two of its edges may be denoted by {right arrow over (e)}\n1 \nand {right arrow over (e)}\n2 \nand the normal {right arrow over (n)} of the triangle may be determined, for example, using the cross product of {right arrow over (e)}\n1 \nand {right arrow over (e)}\n2\n: \n \n{right arrow over (n)}={right arrow over (e)}\n1', '×{right arrow over (e)}\n2\n\u2003\u2003(1)', 'In such an example, the normal may be normalized to be a unit vector.', 'In such an example, the unit normal vector may have a direction that may, for example, be defined with respect to a coordinate system.', 'As an example, a method may include computing the area of individual triangles in a triangular mesh.', 'For example, given three vertices of a triangle, the length of its edges may be determined, which may be denoted by a, b and c.', "In such an example, Heron's formula may be used to compute the area S of the triangle: \n \nS\n=√{square root over (\np\n(\np−a\n)(\np−b\n)(\np−c\n))}, where \np\n=(\na+b+c\n)/2\u2003\u2003(2)", 'In the foregoing formula, p may be referred to as the semiperimeter.', 'As an example, the area of a triangle may be computed as the product of its inradius (radius of an inscribed circle) and its semiperimeter.', 'As an example, depending on angles of a triangle, an equation may include ordering the lengths a, b and c and using a formula that includes terms based these values as ordered (e.g., a formula that may add numerical stability where small internal angles may exist).', "As an example, various formulas such as Brahmagupta's formula, Bretschneider's formula, etc. may be applied (e.g., optionally depending on tessellation shapes, etc.).", 'As an example, a method may include using individual areas of triangles in a triangular mesh as weights, for example, when summing to arrive at a unit normal (e.g., unit normal vector) for a region.', 'As an example, a method may include summing with weights.', 'For example, assume areas {S\ni\n} for triangles of a triangular mesh and corresponding unit normal vectors {{right arrow over (n)}\ni\n}, in such an example, the following formula may be used to determine a final vector {right arrow over (d)}, which may represent the orientation of a complex surface:\n \n \n \n \n \n \n \n \n \nd\n \n→\n \n \n=\n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n \n(\n \n \n \nS\n \ni\n \n \n\u2062\n \n \n \nn\n \n→\n \n \ni\n \n \n \n)\n \n \n/\n \n \n \n∑\n \ni\n \n \n\u2062\n \n \nS\n \ni\n \n \n \n \n \n \n \n \n \n(\n \n3\n \n)', 'In such an example, the dip of the complex surface may be estimated using {right arrow over (d)}.', 'As an example, the dip may be used in one or more subsequent processes, for example, rose diagram plotting, simulation, etc.\n \nFIG.', '14\n shows an example of a method \n1410\n that includes providing data, for example, as shown in a block \n1414\n.', 'Such data may include data that represents a surface \n1416\n where the surface may include an orientation or orientations, for example, that may be expressed with respect to a rose diagram \n1417\n (see also, e.g., the rose diagram plot \n1130\n of \nFIG.', '11\n).', 'As an example, the method \n1410\n may include tessellating at least a portion of the surface \n1416\n, for example, using triangles that may vary in shape (e.g., with respect to a coordinate system).\n \nFIG.', '15\n shows an example of a method \n1510\n that includes providing data, for example, as shown in a block \n1514\n.', 'Such data may include coordinates of vertices, for example, vertices that can define triangles.', 'In such an example, the method \n1510\n may include computing values for individual triangles.', 'For example, as shown in a block \n1518\n, the method \n1510\n may include computing a normal and computing an area.\n \nFIG.', '16\n shows an example of a method \n1610\n that includes receiving data, for example, as shown in a block \n1614\n (see also, e.g., the data \n630\n of \nFIG.', '6\n).', 'Such data may include data that represents a surface \n1616\n in a three-dimensional space.', 'As an example, the surface \n1616\n may be tessellated to form a mesh, for example, a collection of nodes or vertices that may define polygons such as triangles.', 'In such an example, as shown in a block \n1618\n, for individual polygons, the method \n1610\n may include computing normals and area and determining an overall normal for a region represented by the individual polygons.', 'For example, where the polygons are triangles, a number of triangles from 1 to N may be considered where a normal and an area are computed, which, in turn, are used to determine an overall normal for a region represented by the triangles.', 'In such an example, the overall normal may be an average unit normal determined using a weighted sum of individual unit normals, for example, where the weights are areas corresponding to the individual unit normals.\n \nFIG.', '17\n shows three examples of structures represented as surfaces \n1710\n, \n1720\n and \n1730\n.', 'For example, the surface \n1710\n may be a thin and long surface, the surface \n1720\n may be a curved surface and the surface \n1730\n may be a zigzag surface.', 'As an example, the surfaces \n1710\n, \n1720\n and \n1730\n may be complex surfaces that represent fractures.', 'As an example, a method such as the method \n1310\n of \nFIG.', '13\n may be applied to one or more of such surfaces, for example, to determine one or more corresponding dip values.', 'As an example, such an approach may provide a dip or dip values representative of a fracture, a fault, etc.', 'As an example, an approach that uses a best fit plane to fit the surface \n1710\n may be suboptimal as the surface is thin and long and may result in a vertical plane rather than a horizontal plane.', 'As an example, an approach may be suboptimal for the surface \n1730\n as dips of most of the points of the zigzag surface \n1730\n tend to be approximately 45 degrees such that an average may not result in a high dip value as a user may expect.', 'As an example, a method such as the method \n1310\n of \nFIG.', '13\n may be applied to one or more of the surfaces \n1710\n, \n1720\n and \n1730\n and provide corresponding dips that may be more meaningful geologically (e.g., representative of the structures giving rise to the surfaces).', 'As an example, a method may include receiving information in the form of a model (e.g., model information).', 'As an example, a model may be a seismic discontinuity plane model (e.g., an “SDP” model), which may be derived from seismic data (e.g., raw data, one or more attributes, etc.).', 'As an example, a method may include using a seismic discontinuity planes (SDP) model for dip calculation.', 'As an example, a method may be used for the dip calculation of a point set in 3D space.', 'As an example, a method may be implemented where complex fracture surfaces may be represented, for example, by point sets.', 'As an example, a system may include one or more modules, which may be provided to analyze data, control a process, perform a task, perform a workstep, perform a workflow, etc.\n \nAs an example, a method can include receiving information that defines a three-dimensional subterranean structure; tessellating the subterranean structure into triangles; computing a normal for each of the triangles; computing an area for each of the triangles; and determining a dip for the subterranean structure based on the normals and the areas of the triangles.', 'As an example, such a method may include simulating phenomena associated with a subterranean formation based at least in part on the dip.', 'As an example, a subterranean structure may be or include a fracture.', 'As an example, a fracture may include an aspect ratio that differs from unity by at least one order of magnitude (e.g., 10 or 0.1).', 'As an example, a fracture may be or include a curved fracture.', 'As an example, a fracture may be or include a zigzag fracture.', 'As an example, a method may include computing a normal by computing a cross product of two vectors.', "As an example, a method may include computing an area by applying Heron's formula.", 'As an example, a method may include determining a dip by computing a weighted sum of the normals.', 'In such an example, a method may include using areas as weights to weight corresponding normals.', 'As an example, a method may include normalizing a normal (e.g., normalizing normals).', 'As an example, a method may include plotting a rose diagram based at least in part on a determined dip.', 'As an example, computing an area may include computing a semiperimeter, computing an inradius or computing one or more other parameters.', 'As an example, a system may include a processor; memory operatively coupled to the processor; one or more modules stored in the memory and including processor executable instructions to instruct the system to: receive information that defines a three-dimensional subterranean structure; tessellate the subterranean structure into triangles; compute a normal for each of the triangles; compute an area for each of the triangles; and determine a dip for the subterranean structure based on the normals and the areas of the triangles.', 'As an example, such a system may include instructions to simulate phenomena associated with a subterranean formation based at least in part on a model that includes the dip.', 'As an example, a system may include instructions to determine a dip by computing a weighted sum of normals (e.g., using areas as weights).', 'As an example, one or more computer-readable storage media may include processor-executable instructions to instruct a computer to: receive information that defines a three-dimensional subterranean structure; tessellate the subterranean structure into triangles; compute a normal for each of the triangles; compute an area for each of the triangles; and determine a dip for the subterranean structure based on the normals and the areas of the triangles.', 'As an example, one or more computer-readable storage media may include processor-executable instructions to instruct a computer to simulate phenomena associated with a subterranean formation based at least in part on a model that includes a determined dip.', 'As an example, one or more computer-readable storage media may include processor-executable instructions to instruct a computer to compute a weighted sum of normals (e.g., using areas as weights).\n \nFIG.', '18\n shows an example of a system \n1800\n, examples of various modules \n1810\n and an example of an approximate illustration of a fracture network \n1880\n (e.g., as part of a DFN model, etc.).', 'In the example of \nFIG.', '18\n, the system \n1800\n includes one or more processors \n1802\n operatively coupled to memory \n1804\n.', 'As an example, the memory \n1804\n may store modules such as one or more of the modules \n1810\n, which may provide for modeling storage, flow, etc., in a subterranean environment.', 'In the example of \nFIG.', '18\n, the modules \n1810\n include a fluid reservoir module \n1812\n, a dry reservoir module \n1814\n, a module for existing wells \n1822\n, a module for prospective wells \n1824\n, a natural fracture module \n1842\n, an artificial fracture module \n1844\n and one or more solver modules \n1860\n.', 'In the example of \nFIG.', '18\n, the modules \n1810\n may include instructions suitable for execution by one or more of the processors (e.g., processor cores) to instruct a computing device or system to perform one or more actions.', 'For example, the system \n1800\n may be instructed by instructions of one or more of the modules \n1810\n.', 'As an example, a method can include implementing one or more of the modules \n1810\n to represent a network such as the fracture network \n1880\n.', 'In the example of \nFIG.', '18\n, the fracture network \n1880\n may include natural fractures and artificial fractures.', 'As an example, creation of a hydraulic fracture may be impacted by one or more natural fractures.', 'For example, hydraulic fracture growth may proceed in a northeast-southwest direction that reactivates natural fractures (dashed lines) trending in another direction or directions (see, e.g., arrows indicate possible propagation directions of hydraulic fractures).', 'As an example, a method can include modeling of natural fractures in an environment using a model and simulating behavior of the environment using the model (e.g., for storage, flow, etc.), for example, with respect to a reservoir or reservoirs.', 'In turn, a solution may be analyzed for prospective artificial fractures.', 'Such an analysis may, for example, include positioning of one or more wells for creating one or more prospective artificial fractures with respect to one or more natural fractures to generate a network that acts to reactivate natural fractures as conduits for flow of fluid.', 'As an example, such an analysis may aim to avoid certain natural fractures and reactivate (e.g., utilize) other natural fractures.', 'In such an example, refinement of natural fracture locations, properties, etc., may occur using a model (e.g., a DFN model, etc.), optionally in conjunction with a 3D grid model that models one or more reservoirs.', 'As an example, a model may account for stress or one or more other factors that may relate to fracturing.', 'As an example, a natural fracture model may be mathematically linked to a stress model for a 3D environment.', 'As an example, a model may account for a chemical process (e.g., acidizing).', 'As an example, a natural fracture model may be mathematically linked to a chemical reaction model for modeling a chemical process (e.g., with respect to one or more fracture characteristics).', 'Where history matching is performed for flow based at least in part on a solution to a natural fracture model, refinements to the natural fracture model may act to update one or more parameters associated with stress (e.g., direction, etc.).', 'As an example, a system can include one or more processors for processing information, memory operatively coupled to the one or more processors and modules that include instructions storable in the memory and executable by at least one of the one or more processors.', 'Such modules may include a reservoir module for modeling a reservoir in a subterranean three-dimensional environment via a three-dimensional grid model, a natural fracture module for modeling a natural fracture via a model (e.g., a DFN), a well module for modeling a well via a well model, and one or more solver modules for solving for values of fluid flow in a fracture network based at least in part on modeling a natural fracture via a model.', 'As an example, a system may include an artificial fracture module for modeling an artificial fracture via a model.', 'As an example, a system may include a solver module for solving for values of fluid flow in a fracture network that includes at least one natural fracture and at least one artificial fracture.', 'As mentioned, boundary conditions may be defined (e.g., imposed) on one or more portions of a model that models a natural fracture, natural fractures, etc. \nFIG.', '19\n shows an example of an environment \n1910\n that includes various formations, a wellbore and natural fractures.', 'As indicated, the formations include fluid such as oil, gas and/or water, which may define various zones.', 'As to boundary conditions, a natural fracture may include a natural fracture to natural fracture boundary condition, a natural fracture to oil filled formation boundary condition, a natural fracture to wellbore boundary condition, a natural fracture to a gas-filled formation boundary condition, a natural fracture to a water filled formation boundary condition, etc.', 'As an example, a natural fracture may include multiple boundary conditions, for example, for both a wellbore and a fluid filled formation.', 'As an example, a formation may be considered fluid filled or void (e.g., “dry”) depending on type of fluid.', 'For example, a gas filled formation may be considered void with respect oil where a goal is to produce oil.', 'As indicated by the example environment \n1910\n of \nFIG.', '19\n, oil and water may coexist within a formation and a strategy may be formulated to produce oil with minimal water content.', 'As an example, such a strategy may be honed via use of a model that models one or more natural fractures with respect to an environment (e.g., to avoid activation of a natural fracture that may lead to increase of water content in oil).', 'As an example, a method can include receiving information that defines a three-dimensional subterranean structure; splitting the subterranean structure (e.g., a fracture, fractures, a fault, faults, etc.) into portions; generating convex hulls for the portions; and generating a discrete fracture network based at least in part on the convex hulls.', 'Such a method may further include simulating phenomena associated with a subterranean formation based at least in part on a model that includes the discrete fracture network.', 'As an example, a method can include tessellating at least a portion of a subterranean structure into polygons; computing a normal for each of the polygons; and determining one or more dip values based on the normals of the polygons.', 'In such an example, the polygons may be triangles and the method may also include computing areas for each of the triangles.', 'As an example, a method may include determining a dip (e.g., a dip value) for a subterranean structure based at least in part on a plurality of normals of tessellated polygons and, for example, based at least in part on areas of the tessellated polygons.', 'As an example, a method may include generating one or more convex hulls by applying a Graham scan algorithm.', 'As an example, a method may include splitting by implementing an angular splitting parameter.', 'As an example, splitting may include generating areas in at least one plane intersected by a subterranean structure.', 'As an example, splitting may generate line segments, for example, where each of the line segments includes end points.', 'As an example, a method may include splitting a curve where the curve is determined by intersection of a structure with a plane.', 'As an example, a method may include repeating splitting for a plurality of positions of the plane along a coordinate direction.', 'As an example, splitting can include intersecting a subterranean structure by a plane to generate intersection points that form a curve and then splitting the curve into portions.', 'In such an example, splitting may include representing each of the portions by a line segment where, for example, each of the line segments has an associated area.', 'As an example, a method may include generating a convex hull by providing a best fit plane.', 'As an example, a method may include outputting a discrete fracture network as a model represented at least in part by a set of convex hulls.', 'As an example, a system can include a processor; memory operatively coupled to the processor; one or more modules stored in the memory and including processor executable instructions to instruct the system to: receive information that defines a three-dimensional subterranean structure; split the subterranean structure into portions; generate convex hulls for the portions; and generate a discrete fracture network based at least in part on the convex hulls.', 'As an example, such a system may include instructions to simulate phenomena associated with a subterranean formation based at least in part on a model that includes the discrete fracture network.', 'As an example, instructions to generate a convex hull for at least one of the portions may include instructions to apply a Graham scan algorithm.', 'As an example, one or more computer-readable storage media can include processor-executable instructions to instruct a computer to: receive information that defines a three-dimensional subterranean structure; split the subterranean structure into portions; generate convex hulls for the portions; and generate a discrete fracture network based at least in part on the convex hulls.', 'As an example, one or more computer-readable storage media may include processor-executable instructions to instruct a computer to simulate phenomena associated with a subterranean formation based at least in part on a model that includes a discrete fracture network.', 'As an example, one or more computer-readable storage media may include processor-executable instructions to instruct a computer to generate a convex hull for at least one portion of a split structure, for example, by applying a Graham scan algorithm.\n \nFIG.', '20\n shows components of an example of a computing system \n2000\n and an example of a networked system \n2010\n.', 'The system \n2000\n includes one or more processors \n2002\n, memory and/or storage components \n2004\n, one or more input and/or output devices \n2006\n and a bus \n2008\n.', 'In an example embodiment, instructions may be stored in one or more computer-readable media (e.g., memory/storage components \n2004\n).', 'Such instructions may be read by one or more processors (e.g., the processor(s) \n2002\n) via a communication bus (e.g., the bus \n2008\n), which may be wired or wireless.', 'The one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g., as part of a method).', 'A user may view output from and interact with a process via an I/O device (e.g., the device \n2006\n).', 'In an example embodiment, a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc. (e.g., a computer-readable storage medium).', 'In an example embodiment, components may be distributed, such as in the network system \n2010\n.', 'The network system \n2010\n includes components \n2022\n-\n1\n, \n2022\n-\n2\n, \n2022\n-\n3\n, . . .', '2022\n-N.', 'For example, the components \n2022\n-\n1\n may include the processor(s) \n2002\n while the component(s) \n2022\n-\n3\n may include memory accessible by the processor(s) \n2002\n.', 'Further, the component(s) \n2002\n-\n2\n may include an I/O device for display and optionally interaction with a method.', 'The network may be or include the Internet, an intranet, a cellular network, a satellite network, etc.', 'As an example, a device may be a mobile device that includes one or more network interfaces for communication of information.', 'For example, a mobile device may include a wireless network interface (e.g., operable via IEEE 802.11, ETSI GSM, BLUETOOTH®, satellite, etc.).', 'As an example, a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio/video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery.', 'As an example, a mobile device may be configured as a cell phone, a tablet, etc.', 'As an example, a method may be implemented (e.g., wholly or in part) using a mobile device.', 'As an example, a system may include one or more mobile devices.', 'As an example, a system may be a distributed environment, for example, a so-called “cloud” environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc.', 'As an example, a device or a system may include one or more components for communication of information via one or more of the Internet (e.g., where communication occurs via one or more Internet protocols), a cellular network, a satellite network, etc.', 'As an example, a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).', 'As an example, information may be input from a display (e.g., consider a touchscreen), output to a display or both.', 'As an example, information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed.', 'As an example, information may be output stereographically or holographically.', 'As to a printer, consider a 2D or a 3D printer.', 'As an example, a 3D printer may include one or more substances that can be output to construct a 3D object.', 'For example, data may be provided to a 3D printer to construct a 3D representation of a subterranean formation.', 'As an example, layers may be constructed in 3D (e.g., horizons, etc.), geobodies constructed in 3D, etc.', 'As an example, holes, fractures, etc., may be constructed in 3D (e.g., as positive structures, as negative structures, etc.).', 'Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” together with an associated function.'] | ['1.', 'A method comprising:\nreceiving information that defines a three-dimensional subterranean structure wherein the information is at least in part derived from seismic data of at least a portion of the three-dimensional subterranean structure acquired via sensors and wherein the three-dimensional subterranean structure comprises a curved surface;\nautomatically splitting the three-dimensional subterranean structure into portions wherein the splitting implements a top view, split angle criterion to generate a series of horizontal line segments that represent the curved surface from the top view, wherein each of the horizontal line segment comprises end points;\nbased at least in part on the end points, generating planar convex hulls for the portions;\ngenerating a three-dimensional discrete fracture network based at least in part on the planar convex hulls; and\nbased at least in part on the three-dimensional discrete fracture network, positioning one or more wells.', '2.', 'The method of claim 1 further comprising simulating phenomena associated with a subterranean formation based at least in part on a model that comprises the discrete fracture network.', '3.', 'The method of claim 1 wherein the generating planar convex hulls comprises applying a Graham scan algorithm.', '4.', 'The method of claim 1 wherein each of the line segments is associated with an area.', '5.', 'The method of claim 1 wherein the generating planar convex hulls comprises determining a best fit plane.', '6.', 'The method of claim 1 further comprising outputting that outputs the three-dimensional discrete fracture network as a model represented at least in part by a set of planar convex hulls.', '7.', 'The method of claim 1 further comprising tessellating at least a portion of the three-dimensional subterranean structure into polygons; computing a normal for each of the polygons; and determining one or more dip values based on the normals of the polygons.', '8.', 'A system comprising:\na processor;\nmemory operatively coupled to the processor;\nprocessor executable instructions stored in the memory and executable to instruct the system to; receive information that defines a three-dimensional subterranean structure wherein the information is at least in part derived from seismic data of at least a portion of the three-dimensional subterranean structure acquired via sensors and wherein the three-dimensional subterranean structure comprises a curved surface; automatically split the three-dimensional subterranean structure into portions via implementation of a top view, split angle criterion to generate a series of horizontal line segments that represent the curved surface from the top view, wherein each of the horizontal line segments comprises end points; based at least in part on the end points, generate planar convex hulls for the portions; generate a three-dimensional discrete fracture network based at least in part on the planar convex hulls; and based at least in part on the three-dimensional discrete fracture network, positioning one or more wells.\n\n\n\n\n\n\n9.', 'The system of claim 8 wherein the processor executable instructions to instruct the system comprise instructions to simulate phenomena associated with a subterranean formation based at least in part on a model that includes the discrete fracture network.', '10.', 'The system of claim 8 wherein the instructions to generate a planar convex hull for at least one of the portions comprises instructions to apply a Graham scan algorithm.', '11.', 'One or more non-transitory computer-readable storage media comprising processor-executable instructions to instruct a computer to:\nreceive information that defines a three-dimensional subterranean structure wherein the information is at least in part derived from seismic data of at least a portion of the three-dimensional subterranean structure acquired via sensors and wherein the three-dimensional subterranean structure comprises a curved surface;\nautomatically split the three-dimensional subterranean structure into portions via implementation of a top view, split angle criterion to generate a series of horizontal line segments that represent the curved surface from the top view, wherein each of the horizontal line segments comprises end points;\nbased at least in part on the end points, generate planar convex hulls for the portions;\ngenerate a three-dimensional discrete fracture network based at least in part on the planar convex hulls; and\nbased at least in part on the three-dimensional discrete fracture network, positioning one or more wells.\n\n\n\n\n\n\n12.', 'The one or more non-transitory computer-readable storage media of claim 11 comprising processor-executable instructions to instruct the computer to simulate phenomena associated with a subterranean formation based at least in part on a model that includes the three-dimensional discrete fracture network.', '13.', 'The one or more non-transitory computer-readable storage media of claim 11 comprising processor-executable instructions to instruct the computer to generate a planar convex hull for at least one of the portions by applying a Graham scan algorithm.'] | ['FIG. 1 illustrates an example system that includes various components for modeling a geologic environment;; FIG. 2 illustrates examples of formations, an example of a convention for dip, an example of data acquisition, and an example of a system;; FIG.', '3 illustrates an example of a method;; FIG.', '4 illustrates an example of a method;; FIG.', '5 illustrates an example of a method;; FIG.', '6', 'illustrates examples of data and processed data;; FIG.', '7 illustrates an example of a method;; FIG. 8 illustrates an example of a Graham scan technique;; FIG. 9 illustrates an example of a method;; FIG.', '10 shows an example of a set of polygons;; FIG.', '11 illustrates examples of plots;; FIG.', '12 illustrates an example of a method;; FIG.', '13 illustrates an example of a method;; FIG.', '14 illustrates an example of a method;; FIG.', '15 illustrates an example of a method;; FIG.', '16 illustrates an example of a method;; FIG.', '17 illustrates examples of structures;; FIG.', '18 illustrates an example of a system, examples of modules and an example of a fracture network;; FIG.', '19 illustrates an example of an environment; and; FIG.', '20 illustrates example components of a system and a networked system.; FIG.', '1 shows an example of a system 100 that includes various management components 110 to manage various aspects of a geologic environment 150 (e.g., an environment that includes a sedimentary basin, a reservoir 151, one or more fractures 153, etc.).', 'For example, the management components 110 may allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment 150.', 'In turn, further information about the geologic environment 150 may become available as feedback 160 (e.g., optionally as input to one or more of the management components 110).; FIG.', '1 also shows an example of a framework 170 that includes a model simulation layer 180 along with a framework services layer 190, a framework core layer 195 and a modules layer 175.', 'The framework 170 may include the commercially available OCEAN® framework where the model simulation layer 180 is the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.', 'In an example embodiment, the PETREL® software may be considered a data-driven application.', 'The PETREL® software can include a framework for model building and visualization.', 'Such a model may include one or more grids.; FIG. 1 also shows the geologic environment 150 as optionally including equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop the reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment 157 and/or 158 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.; FIG.', '2 shows an example of a formation 201, an example of a borehole 210, an example of a convention 215 for dip, an example of a data acquisition process 220, and an example of a system 250.; FIG.', '3 shows an example of a method 310 that includes a reception block 314 for receiving information that defines a three-dimensional subterranean structure, a split block 318 for splitting the subterranean structure into portions, a generation block 322 for generating convex hulls for the portions, a generation block 326 for generating a discrete fracture network (DFN) based at least in part on the convex hulls and a simulation block 330 for simulating phenomena associated with a subterranean formation based at least in part on a model that includes the discrete fracture network (DFN).; FIG.', '4 shows an example of a method 410 and approximate illustrations of information 411 that defines a subterranean structure, points in space 415, an area 419 that is defined at least in part via points in space, and a convex hull 423 that may be defined at least in part via points in space associated with the area 419.', 'As shown, the method 410 includes a reception block 414 for receiving information that defines a three-dimensional subterranean structure (e.g., consider the information 411, which may be an SDP, etc.), a split block 418 for splitting at least a portion of the three-dimensional subterranean structure into areas (e.g., consider the area 419, etc.)', 'and a generation block 422 for generating convex hulls for areas (e.g., consider the convex hull 423 of the area 419).', 'As an example, a convex hull may be considered to be a type of proxy (e.g., a refined proxy).', 'As an example, a proxy may be defined by its vertices.', 'For example, a proxy that is a convex pentagon may be defined by five points in space.', 'Thus, an area that is defined by a plurality of points in space such as the points 415 may be represented by a reduced amount of information (e.g., vertices in space of a convex polygon, etc.).; FIG.', '5 shows an example of a method 510 that includes a reception block 512 for receiving information (e.g., an SDP, an SDP model, etc.), an identification block 516 for identifying a structure based at least in part on a portion of the information, and a split block 520 for splitting the identified structure.', 'In the example of FIG.', '5, the split block 520 may perform splitting in one or more directions.', 'For example, a horizontal split block 522 may provide for splitting via an analysis that assesses a structure with respect to a horizon, horizons, a reference horizontal line or lines, etc.; whereas a vertical split block 524 may provide for splitting via an analysis that assesses a structure with respect to a vertical well, a vertical structure, a reference vertical line or lines, etc.; FIG.', '6 shows an example of data 630 and processed data 650 that includes a set of convex hulls.', 'As an example, the set of convex hulls may be used to form, at least in part, a DFN model, for example, where individual portions of a fracture network are represented as convex planar polygons.', 'As an example, a method can include receiving data and processing the data to generate a DFN (e.g., a DFN model).', '; FIG.', '7 shows an example of a method 710 that includes providing a surface in a plane (e.g., an I, J plane of an I, J, K coordinate or index system), which may be represented as a curve, and splitting the curve based on an angle criterion (see block 714).', 'Splitting may include forming line segments, for example, as shown in a block 718.', 'In such an example, the curve of the surface in the plane may be represented by segments where each of the segments includes end points.', '; FIG. 7 also shows an example diagram 720 of three segments with points and a split angle (θ).', 'As shown, a neighbor count may be a parameter or metric with respect to points that may be defined spatially with respect to information such as, for example, information of an SDP.', 'As to a split angle, it may be defined with respect to lines that may be, for example, fit to points.', 'As an example, a split angle may be defined with respect to a reference.', 'For example, given a locus, a first line may define a first tangent to the locus and a second line may define a second tangent to the locus.', 'In such an example, the first and second tangents may define an angle therebetween that can be compared to a split angle.', 'In such an example, where the angle is less than the split angle, the first and the second lines may be considered part of a common line of an area; whereas, where the angle meets or exceeds the split angle, the first and the second lines may be considered to be part of two different areas (e.g., two adjacent areas).', '; FIG.', '8 shows a graphical illustration 810 that corresponds to a Graham scan technique, which may be employed to determine a convex hull, for example, given a set of points.', 'In the example of FIG. 8, a set of points numbered from 0 to 12 are illustrated where of those points, the points 0, 1, 3, 10 and 12 can spatially define vertexes of a convex hull (e.g., a convex polygon).', 'In the example of FIG. 8, the convex hull includes five vertexes and five sides (e.g., a pentagon), noting that other types of hulls may be determined for a give set of points.', '; FIG.', '9 shows a method 910 that includes a data block 930 and a processed data block 950.', 'As shown in the data block 930, data may be processed, for example, at various depths (e.g., along a depth coordinate) using one or more angle criteria.', 'Such an approach may split a structure into segments, for example, where each segment includes end points.', 'In such an example, at each depth, segments may be generated via splitting of a line, curve, etc. of a structure in a plane (e.g., a horizontal plane).', 'In the example of FIG.', '9, areas may be formed (see, e.g., the block 714 of FIG.', '7) and segments may be formed (see, e.g., the block 718 of FIG. 7).; FIG.', '10 shows an example of a set of polygons 1030 that includes a polygon 1031 and a polygon 1033 with a gap 1034 and a set of polygons 1050 that includes a polygon 1052 positioned at least in part in the gap 1032.', 'In such an example, the polygon 1052 may be inserted to meet one or more connectivity criteria as to the polygon 1033 with respect to the polygon 1031.', 'As mentioned with respect to the method 510 of FIG.', '5, one or more fit criteria (e.g., which may include one or more connectivity criteria) may not be met, for example, where a proxy does not adequately “match” an area of a received data set (e.g., SDP data).', 'In such an example, a gap may exist between two adjacent polygons (e.g., due to some amount of mismatch).', '; FIG.', '11 shows a series of examples of plots 1110, 1130, 1152 and 1154.', 'As an example, polygons may be analyzed, for example, to assess a subterranean region.', 'For example, polygons generated via a method such as the method 410 of FIG. 4, the method 510 of FIG. 5, etc. may be analyzed as to dip angle.', 'For example, the plot 1110 shows number of samples (e.g., number of polygons) with respect to dip angle.', 'As shown, a distribution exists where the number of samples generally increases as dip angle approaches 90 degrees.', '; FIG.', '12 shows an example of a method 1200 that includes a reception block 1210 for receiving seismic and/or attribute information and a generation block 1230 for generating a seismic discontinuity plane (SDP) model.', 'In such an example, the method 1200 may optionally include a reception block 1240 for receiving one or more other types of information such as, for example, log information, which may be used, at least in part, by the generation block 1230 for generating the SDP model.; FIG.', '13 shows an example of a method 1310 that includes a reception block 1314 for receiving information that defines a three-dimensional subterranean structure; a tessellation block 1318 for tessellating the subterranean structure into triangles (e.g., based at least in part on the provided information); a computation block 1322 for computing a normal for each of the triangles; a computation block 1326 for computing an area for each of the triangles; and a determination block 1330 for determining a dip for the subterranean structure based on the normals and the areas of the triangles.', 'As an example, such a method may include simulating phenomena associated with a subterranean formation based at least in part on the dip.; FIG.', '14 shows an example of a method 1410 that includes providing data, for example, as shown in a block 1414.', 'Such data may include data that represents a surface 1416 where the surface may include an orientation or orientations, for example, that may be expressed with respect to a rose diagram 1417 (see also, e.g., the rose diagram plot 1130 of FIG. 11).', 'As an example, the method 1410 may include tessellating at least a portion of the surface 1416, for example, using triangles that may vary in shape (e.g., with respect to a coordinate system).', '; FIG.', '15 shows an example of a method 1510 that includes providing data, for example, as shown in a block 1514.', 'Such data may include coordinates of vertices, for example, vertices that can define triangles.', 'In such an example, the method 1510 may include computing values for individual triangles.', 'For example, as shown in a block 1518, the method 1510 may include computing a normal and computing an area.', '; FIG.', '16 shows an example of a method 1610 that includes receiving data, for example, as shown in a block 1614 (see also, e.g., the data 630 of FIG. 6).', 'Such data may include data that represents a surface 1616 in a three-dimensional space.', 'As an example, the surface 1616 may be tessellated to form a mesh, for example, a collection of nodes or vertices that may define polygons such as triangles.', 'In such an example, as shown in a block 1618, for individual polygons, the method 1610 may include computing normals and area and determining an overall normal for a region represented by the individual polygons.', 'For example, where the polygons are triangles, a number of triangles from 1 to N may be considered where a normal and an area are computed, which, in turn, are used to determine an overall normal for a region represented by the triangles.', 'In such an example, the overall normal may be an average unit normal determined using a weighted sum of individual unit normals, for example, where the weights are areas corresponding to the individual unit normals.; FIG.', '17 shows three examples of structures represented as surfaces 1710, 1720 and 1730.', 'For example, the surface 1710 may be a thin and long surface, the surface 1720 may be a curved surface and the surface 1730 may be a zigzag surface.', 'As an example, the surfaces 1710, 1720 and 1730 may be complex surfaces that represent fractures.', '; FIG.', '18 shows an example of a system 1800, examples of various modules 1810 and an example of an approximate illustration of a fracture network 1880 (e.g., as part of a DFN model, etc.).', 'In the example of FIG.', '18, the system 1800 includes one or more processors 1802 operatively coupled to memory 1804.', 'As an example, the memory 1804 may store modules such as one or more of the modules 1810, which may provide for modeling storage, flow, etc., in a subterranean environment.', 'In the example of FIG.', '18, the modules 1810 include a fluid reservoir module 1812, a dry reservoir module 1814, a module for existing wells 1822, a module for prospective wells 1824, a natural fracture module 1842, an artificial fracture module 1844 and one or more solver modules 1860.', 'In the example of FIG.', '18, the modules 1810 may include instructions suitable for execution by one or more of the processors (e.g., processor cores) to instruct a computing device or system to perform one or more actions.', 'For example, the system 1800 may be instructed by instructions of one or more of the modules 1810.; FIG.', '20 shows components of an example of a computing system 2000 and an example of a networked system 2010.', 'The system 2000 includes one or more processors 2002, memory and/or storage components 2004, one or more input and/or output devices 2006 and a bus 2008.', 'In an example embodiment, instructions may be stored in one or more computer-readable media (e.g., memory/storage components 2004).', 'Such instructions may be read by one or more processors (e.g., the processor(s) 2002) via a communication bus (e.g., the bus 2008), which may be wired or wireless.', 'The one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g., as part of a method).', 'A user may view output from and interact with a process via an I/O device (e.g., the device 2006).', 'In an example embodiment, a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc. (e.g., a computer-readable storage medium).'] |
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US11118414 | Tubular delivery arm for a drilling rig | May 1, 2017 | Melvin Alan Orr, Mark W. 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April 2015; CN; 0979924; February 2000; EP; 2100565; December 1997; RU; 2541972; February 2015; RU; 1730422; April 1992; SU; 9315303; August 1993; WO; 0111181; February 2001; WO; 0218742; March 2002; WO; 2006059910; June 2006; WO; 2010141231; December 2010; WO; 2011016719; February 2011; WO; 2011056711; May 2011; WO; 2012148286; November 2012; WO; 2014029812; February 2014; WO; 2016204608; December 2016; WO; 2017087200; May 2017; WO; 2017087349; May 2017; WO; 2017087350; May 2017; WO | ['A tubular delivery arm that travels vertically along a rail on the front of a drilling mast in generally parallel orientation to the travel of a top drive.', 'The tubular delivery arm has a dolly vertically translatably connected to a mast of the drilling rig.', 'An arm is rotatably and pivotally connected to the dolly at its upper end.', 'A tubular clasp is pivotally connected to the arm at its lower end.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'The present document claims the benefit of and priority to U.S. Provisional Application Ser.', 'No. 62/330,012, filed Apr. 29, 2016, and International Application Number PCT/US2016/061956, filed Nov. 15, 2016, both of which are incorporated herein by reference in their entireties.', 'BACKGROUND', 'In the exploration of oil, gas and geothermal energy, drilling operations are used to create boreholes, or wells, in the earth.', 'Modern drilling rigs may have two, three, or even four mast sections for sequential connection and raising above a substructure.', 'The drilling rigs are transported to the locations where drilling activity is to be commenced.', 'Once transported, large rig components are moved from a transport trailer into engagement with the other components located on the drilling pad.\n \nMoving a full-size drilling rig requires significant disassembly and reassembly of the substructure, mast, and related component.', 'Speed of disassembly and reassembly impacts profitability but safety is the primary concern.', 'A reduction in disassembly reduces errors and delay in reassembly.', 'Transportation constraints and cost limit many of the design opportunities for building drilling rigs that can drill a well faster.', 'Conventional drilling involves having a drill bit on the bottom of the well.', 'A bottom-hole assembly is located immediately above the drill bit where directional sensors and communications equipment, batteries, mud motors, and stabilizing equipment are provided to help guide the drill bit to the desired subterranean target.', 'A set of drill collars are located above the bottom-hole assembly to provide a non-collapsible source of weight to help the drill bit crush the formation.', 'Heavy weight drill pipe is located above the drill collars for safety.', 'The remainder of the drill string is mostly drill pipe, designed to be under tension.', 'Each drill pipe is roughly 30 feet long, but lengths vary based on the style.', 'It is common to store lengths of drill pipe in “doubles” (two connected lengths) or “triples” (three connected lengths) or even “fourables” (four connected lengths).', 'A “tubular stand” refers to connected sections of drill pipe, drill collars, or casing.', 'When the drill bit wears out, or when service, repairs or adjustments need to be made to the bottom-hole assembly, the drill string (drill pipe and other components) is removed from the wellbore and setback.', 'When removing the entire drill string from the well, it is typically disconnected and setback in doubles or triples until the drill bit is retrieved and exchanged.', 'This process of pulling everything out of the hole and running it all back in the hole is known as “tripping.”', 'Tripping is non-drilling time and, therefore, an expense.', 'Efforts have long been made to devise ways to avoid it or at least speed it up.', 'Running triples is faster than running doubles because it reduces the number of threaded connections to be disconnected and then reconnected.', 'Triples are longer and therefore more difficult to handle due to their length and weight and the natural waveforms that occur when moving them around.', 'Manually handling moving pipe in the derrick and at the drill floor level can be dangerous.', 'It is desirable to have a drilling rig with the capability to increase safety and reduce trip time.', 'It is desirable to have a drilling rig with the capability of handing stands of drilling tubulars to devices alternative to conventional elevators and top drives.', 'Most attempts to automate pipe handling are found offshore.', 'However, solutions for pipe delivery on offshore drilling rigs are seldom transferable to onshore land rigs, due to the many differences in economic viability, size, weight, and transportation considerations.', 'SUMMARY\n \nThe disclosed subject matter of the application relates to an independent secondary hoisting machine that is adaptable for use on a conventional drilling rig, or on a specialized drilling rig in combination with other equipment designed to take advantage of the auxiliary hoisting capability.', 'In some embodiments, a tubular delivery arm is provided that independently travels vertically along a connection to the drilling mast with lifting capacity limited to that of a stand of tubulars, (connected sections of drill collars, drill pipe, or drill casing).', 'The tubular delivery arm has a tilt capability to move the tubular stands horizontally in the drawworks to V-door direction, reaching positions that include the centerlines for the wellbore, stand hand-off position, mousehole, and/or the catwalk.', 'In some embodiments, the tubular delivery arm comprises a dolly vertically translatably connected to a front side of a mast of the drilling rig.', 'An arm extends below the dolly.', 'A tubular clasp is pivotally connected to a lower end of the arm to engage an upper portion of a tubular stand to raise or lower the tubular stand by the translation of the dolly.', 'An upper end of the arm is rotatably and pivotally connected to the dolly to move the clasp engaging the upper portion of the tubular stand between a well center position and a position forward of the well center position.', 'The tubular clasp is positionable on the tubular stand below an upper end of the tubular stand to secure the upper portion of the tubular stand in the well center position, e.g., for connection and disconnection of the top drive.', 'In some embodiments, the clasp is slidable along the tubular stand between a position to engage an upper end of the tubular stand, e.g., for raising, lowering and/or horizontal movement, and a position below the upper end to secure the stand in the well center position, e.g., for connection or disconnection of the top drive.', 'As used herein, an end of a tubular stand includes a diametral upset such as a box connection, and/or a threaded portion of the tubular stand for connecting tubulars.', 'In embodiments, the clasp is engageable with a diametral upset at the upper end of the tubular stand, and is slidable or otherwise moveable along the tubular stand below the diametral upset at the upper end for coincident attachment by a top drive at the well center position.', 'In an embodiment, the clasp comprises a gripper to grip the tubular stand below a diametral upset at the upper end for coincident attachment by a top drive at the well center position.', 'In any embodiment, the tubular clasp can secure the tubular stand below the upper end for coincident attachment by a top drive at the well center position.', 'In one embodiment, the tubular delivery arm comprises a dolly vertically translatably connected to a drilling mast.', 'The connection may be sliding as with slide pads or a roller connection or other means.', 'An arm bracket is attached to the dolly.', 'An arm, or pair of arms, extends below the dolly and is pivotally and rotationally connected to the arm bracket of the dolly.', 'An actuator bracket is connected between the arms, or to the arm.', 'A tilt actuator is pivotally connected between the actuator bracket and the dolly or arm bracket.', 'A clasp is pivotally connected to the lower end of the arm, below the dolly.', 'The tilt actuator permits the clasp to swing below the dolly over the centerlines of at least the wellbore and a position forward of the wellbore, e.g., a stand hand-off position.', 'The dolly vertically translates the mast in response to actuation of a hoist at the crown of the mast such as by wireline.', 'In one embodiment, a centerline of a drill pipe secured in the clasp, e.g., suspended at the upper end or box connection or upset of the pipe, is located between the clasp pivot connections at the lower ends of each arm.', 'In another embodiment, an extendable incline actuator is pivotally connected between each arm and the tubular clasp.', 'Extension of the incline actuators inclines the clasp to permit tilting of heavy tubular stands, such as large collars.', 'In another embodiment, a rotary actuator is mounted to the arm bracket and has a drive shaft extending through the arm bracket.', 'A drive plate is rotatably connected to the arm bracket and connected to the drive shaft to provide rotation between the dolly and the arm.', 'In another embodiment, a grease dispenser is attached to the tubular delivery arm proximate to the clasp for dispensing grease into the box connection of a tubular stand secured by the clasp of the tubular delivery arm.', 'This embodiment permits automatic greasing (conventionally known as “doping”) the box connection positioned above the clasp.', 'The tubular delivery arm provides a mechanism for use in a new drilling rig configuration or for adaptation to a conventional drilling rig system to reduce the time for tripping drilling tubulars.', 'In some embodiments, a method to deliver tubular stands to and from well center comprises: connecting a dolly of a tubular delivery arm to a front side of a mast; rotatably and pivotally connecting an upper end of an arm to extend below the dolly; pivotally connecting a tubular clasp at a lower end of the arm; securing an upper portion of a tubular stand in the clasp; vertically translating the dolly on the front side of the mast to raise or lower the tubular stand secured in the clasp; rotating and tilting the arm to move the tubular stand secured in the clasp between a well center position and a position forward of the well center position; and positioning the tubular clasp below an upper end of the tubular stand to secure the upper portion of the tubular stand in the well center position.', 'In some embodiments, the method may further comprise connecting or disconnecting a top drive and the tubular stand secured by the clasp in the well center position, and removing the clasp from the tubular stand; and/or connecting or disconnecting a drill string and a lower end of the tubular stand secured by the clasp in the well center position.', 'In some embodiments, the method may further comprise engaging the clasp with a diametral upset at the upper end of the tubular stand for the vertical translation of the dolly.', 'In some embodiments, the positioning of the tubular clasp below the upper end to secure the upper portion of the tubular stand in the well center position comprises moving the clasp along the tubular stand below the diametral upset.', 'In some embodiments, the positioning of the tubular clasp below the upper end to secure the upper portion of the tubular stand in the well center position comprises engaging the clasp and the tubular stand below the diametral upset, followed by moving the clasp along the tubular stand to engage the diametral upset.', 'In these embodiments, the movement of the clasp along the tubular stand may comprise sliding.', 'In some embodiments, the method may comprise gripping the tubular stand at or below a diametral upset with the clasp for the vertical translation of the dolly.', 'In embodiments, the positioning of the tubular clasp below the upper end to secure the upper portion of the tubular stand in the well center position comprises gripping the tubular stand with the clasp below a diametral upset.', 'In some embodiments, the method may further comprise gripping the tubular stand below a diametral upset with the clasp for the vertical translation of the dolly and the securing of the upper portion of the tubular stand in the well center position.', 'As will be understood by one of ordinary skill in the art, the assembly disclosed may be modified and the same advantageous result obtained.', 'It will also be understood that as described, the mechanism can be operated in reverse to remove drill stand lengths of a drill string from a wellbore for orderly bridge crane stacking.', 'Although a configuration related to triples is being described herein, a person of ordinary skill in the art will understand that such description is by example only and would apply equally to doubles and fourables.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is an isometric view of an embodiment of a tubular delivery arm for a drilling rig.\n \nFIG.', '2\n is an isometric exploded view of the embodiment of the tubular delivery arm illustrated in \nFIG.', '1\n.', 'FIG.', '3\n is a side view of another embodiment of the tubular delivery arm illustrated, illustrating the range of the tubular delivery arm to position a suspended tubular stand pipe relative to positions of use on a drilling rig.\n \nFIG.', '4\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position to receive a section of drill pipe from the catwalk.\n \nFIG.', '5\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '4\n, illustrating the tubular delivery arm receiving a section of drill pipe from the catwalk.', 'FIG.', '6\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned to receive a tubular stand from, or deliver a section of pipe to, the mousehole.\n \nFIG.', '7\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position at a height below the top drive to receive (or deliver) a tubular stand at the stand hand-off position at the racking module.\n \nFIG.', '8\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '7\n, illustrating the tubular delivery arm positioned over the stand hand-off position between the racking module and the mast, and having the upset of a tubular stand secured in the clasp.\n \nFIG.', '9\n is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned over a mousehole.\n \nFIG.', '10\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '9\n, illustrating the tubular delivery arm articulated over well center after delivering a tubular stand into a stump at the well center, with the clasp moved down the tubular stand, readied to release and hand off the tubular stand when secured by the top drive (or ready to slide or otherwise move up the tubular stand to the upset and hoist it away from well center after disconnection of the top drive).', 'FIG.', '11\n is an isometric exploded view of an alternative embodiment of the tubular delivery arm.\n \nFIG.', '12\n a fully assembled isometric view of the alternative embodiment of the tubular delivery arm illustrated in \nFIG.', '11\n.\n \nFIG.', '13\n is an isometric view of the embodiment of the tubular delivery arm of \nFIGS.', '11 and 12\n, illustrating the arms rotated and in position over the well center.', 'FIG.', '14\n is a side view of the embodiment of the tubular delivery arm illustrated in \nFIGS.', '11-13\n, illustrating the range of the tubular delivery arm to position a tubular stand.\n \nFIG.', '15\n is an isometric view of the embodiment of the tubular delivery arm of \nFIGS.', '11-14\n, illustrating the tubular delivery arm articulated to the stand hand-off position between the racking module and the mast, and having a tubular stand secured in the clasp.\n \nFIG.', '16\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '15\n, illustrating the tubular delivery arm articulated over the well center and handing a tubular stand to the top drive, or receiving the tubular stand from the top drive.\n \nFIG.', '17\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '16\n, illustrating the tubular delivery arm articulated to reach an upper end of a tubular stand held by an upper stand constraint component at the stand hand-off position.\n \nFIG.', '18\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '17\n, illustrating the upper stand constraint having released (or ready to receive) the tubular stand and the tubular delivery arm hoisting the tubular stand at the box connection as the grease dispenser is lowered to spray grease into the box end of the tubular stand being lifted.', 'The objects and features of the disclosed embodiments will become more readily understood from the following detailed description and appended claims when read in conjunction with the accompanying drawings in which like numerals represent like elements.', 'The drawings constitute a part of this specification and include exemplary embodiments which may be embodied in various forms.', 'It is to be understood that in some instances various aspects of the disclosed embodiments may be shown exaggerated or enlarged to facilitate an understanding of the principles and features of the disclosed embodiments.', 'DETAILED DESCRIPTION', 'The following description is presented to enable any person skilled in the art to make and use the tubular delivery arm, and is provided in the context of a particular application and its requirements.', 'Various modifications to the disclosed embodiments will be readily apparent to those skilled in the art, and the general principles defined herein may be applied to other embodiments and applications without departing from their spirit and scope.', 'Thus, the disclosure is not intended to be limited to the embodiments shown, but is to be accorded the widest scope consistent with the principles and features disclosed herein.\n \nFIG.', '1\n is an isometric view of an embodiment of a tubular delivery arm \n500\n.', 'FIG.', '2\n is an isometric exploded view of this embodiment of tubular delivery arm \n500\n.', 'As best seen in \nFIG.', '2\n, tubular delivery arm \n500\n comprises a dolly \n510\n.', 'Dolly \n510\n is configured for vertically translatable connection to a mast \n10\n of a drilling rig \n1\n (see \nFIG.', '4\n).', "Dolly \n510\n has a driller's side end \n511\n and an opposite off-driller's side end \n512\n.", 'In the embodiment illustrated, dolly \n510\n is configured for sliding connection to mast \n10\n.', 'An adjustment pad \n514\n may be attached to each end \n511\n and \n512\n of dolly \n510\n.', 'A slide pad \n516\n is located on each adjustment pad \n514\n.', 'Slide pads \n516\n are configured for sliding engagement with mast \n10\n of drilling rig \n1\n or a rail set affixed to mast \n10\n for that purpose.', 'Adjustment pads \n514\n permit precise centering and alignment of dolly \n510\n on mast \n10\n.', 'Similar slide assemblies or roller assemblies may be substituted for this purpose.', 'Alternatively, a rack and gear arrangement may be provided.', 'An arm bracket \n520\n extends outward from dolly \n510\n in the V-door direction.', 'An arm \n532\n (or pair of arms \n532\n) is pivotally and rotatably connected to extend below an arm bracket \n520\n.', 'Although the embodiments illustrated depict a pair of arms, they are connected in a manner to function as a single arm, and it will be understood that a single arm \n532\n could be depicted having an opening above clasp \n550\n for clearance of tubular stand \n80\n.', 'An actuator bracket \n542\n is connected to arm \n532\n, or as between arms \n532\n.', 'In one embodiment, a tilt actuator \n540\n is pivotally connected between actuator bracket \n542\n and one of either dolly \n510\n or arm bracket \n520\n.', 'Pivot connection \n534\n is located on the lower end of each arm \n532\n (or on a bifurcated end of arm \n532\n).', 'Clasp \n550\n is pivotally connected to the pivot connections \n534\n at the lower end of each arm \n532\n.', 'In one embodiment, pivot connections \n534\n are located on the center of the lower end of arms \n532\n and clasp \n550\n is likewise pivotally connected at its center.', 'In this embodiment, a centerline of tubular stand \n80\n is secured in clasp \n550\n and located between pivot connections \n534\n at the lower ends of each arm \n532\n.', 'In this configuration, clasp \n550\n is self-balancing to suspend tubular stand \n80\n or a tubular section (drill pipe or drill collar) \n2\n vertically, without additional inclination controls or adjustments.', 'Clasp \n550\n can secure a tubular stand \n80\n at the upper end, e.g., at the box connection or other upset, so that the tubular stand is suspended from the clasp.', 'Clasp \n550\n in one embodiment is slidable along the tubular stand \n80\n below the upset so that it can be moved down on the stand in the well center position to make room for the top drive to connect or disconnect the upper end of the tubular stand while maintaining the upper end of the tubular stand in the well center position.', 'In another embodiment, the clasp \n550\n may comprise a gripper to grip the tubular stand at or below the upper end.', 'For example, the clasp \n550\n may grip the tubular stand \n80\n below the upper end sufficiently to permit the top drive to connect or disconnect above, and this same gripping position may also be used to move the tubular stand in and out of well center.', "In the embodiment illustrated, a first pair of slide pads \n516\n is located on the driller's side end \n511\n of dolly \n510\n, and a second pair of slide pads \n516\n is located on the off-driller's side end \n512\n of dolly \n510\n.", 'In one embodiment, a rotary actuator \n522\n is mounted to arm bracket \n520\n and has a drive shaft (not shown) extending through arm bracket \n520\n.', 'A drive plate \n530\n is rotatably connected to arm bracket \n520\n, e.g., to the underside of the bracket, and connected to the drive shaft of rotary actuator \n522\n.', 'Rotary actuator \n522\n provides control of the rotational connection between dolly \n510\n and arm \n532\n.', 'In this embodiment, tilt actuator \n540\n is pivotally connected between actuator bracket \n542\n and drive plate \n530\n to provide control of the pivotal relationship between dolly \n510\n and arm \n532\n below the dolly.', 'FIG.', '3\n is a side view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '1\n and \nFIG.', '2\n, illustrating the lateral range of the motion of tubular delivery arm \n500\n to position a tubular stand \n80\n relative to positions of use on a drilling rig \n1\n.', 'Illustrated is the capability of tubular delivery arm \n500\n to retrieve and deliver a tubular stand \n80\n as between a well center \n30\n, a mousehole \n40\n, and a stand hand-off position \n50\n, passing the clasp \n550\n and the suspended tubular stand below the dolly \n510\n.', 'Also illustrated is the capability of tubular delivery arm \n500\n to move to a catwalk position \n60\n and incline clasp \n550\n for the purpose of retrieving or delivering a tubular section \n2\n from a catwalk \n600\n.\n \nFIG.', '4\n is a side view of the embodiment of tubular delivery arm \n500\n shown connected to drilling mast \n10\n of drilling rig \n1\n in catwalk position \n60\n (see \nFIG.', '3\n) to receive a tubular section \n2\n from catwalk \n600\n.', 'For this purpose, it is advantageous to have inclination control of clasp \n550\n, as disclosed in an embodiment shown in \nFIGS.', '11-14\n.', 'FIG.', '5\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '4\n, receiving a tubular section \n2\n (drill pipe \n2\n) from catwalk \n600\n.', 'As seen in this view, tubular delivery arm \n500\n is articulated outwards by tilt actuator \n540\n to permit clasp \n550\n to attach to tubular section \n2\n.', 'From this position, tubular delivery arm \n500\n can be used to deliver tubular section \n2\n to the well center for make-up with the drill string in the well by an iron roughneck \n750\n shown positioned by a drill floor manipulating arm \n700\n.', 'Alternatively, tubular delivery arm \n500\n can be used to build a stand with another drill pipe \n2\n secured in a mousehole \n40\n having a mousehole center (see \nFIGS.', '3 and 6\n).', 'FIG.', '6\n is a side view of an embodiment of tubular delivery arm \n500\n connected to a drilling mast \n10\n in position to receive or deliver tubular stand \n80\n to mousehole \n40\n.\n \nFIG.', '7\n is a side view of an embodiment of tubular delivery arm \n500\n connected to a drilling mast \n10\n and in position near the upper end to receive (or deliver) tubular stand \n80\n from stand hand-off position \n50\n at racking module \n300\n.\n \nFIG.', '8\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '7\n, illustrating tubular delivery arm \n500\n articulated to stand hand-off position \n50\n between racking module \n300\n and mast \n10\n, and having tubular stand \n80\n secured in clasp \n550\n.', 'In one embodiment, slide pads \n516\n are slidably engageable with the front side (V-door side) \n12\n of drilling mast \n10\n to permit tubular delivery arm \n500\n to travel up and down front side \n12\n of mast \n10\n, raising or lowering a tubular stand \n80\n secured at its upper end to the clasp \n550\n.', 'Rails may be attached to mast \n10\n for receiving slide pads \n516\n.', 'Tilt actuator \n540\n permits clasp \n550\n to swing over at least well center \n30\n and mousehole \n40\n, to move the tubular stand \n80\n, secured in the clasp \n550\n, horizontally to pass below the dolly \n510\n, e.g., by rotating the arm \n532\n.\n \nFIG.', '9\n is a side view of an embodiment of tubular delivery arm \n500\n connected to drilling mast \n10\n and in position to deliver tubular stand \n80\n to or from mousehole \n40\n.\n \nFIG.', '10\n is an isometric view of an embodiment of tubular delivery arm \n500\n connected to drilling mast \n10\n and in position to deliver tubular stand \n80\n to or from well center \n30\n to stab into (or be disconnected from) a stump secured at well center \n30\n.', 'After stabbing (or disconnection), tubular delivery arm \n500\n can hand tubular stand \n80\n off to top drive \n200\n (or move up the tubular stand \n80\n to secure it at the upset and hoist it away).', 'Tubular delivery arm \n500\n is articulated by expansion of tilt actuator \n540\n (best seen in \nFIG.', '13\n) which inclines arm \n532\n into position such that the centerline of tubular stand \n80\n in clasp \n550\n is properly over well center \n30\n, and raised or lowered by translating the dolly \n510\n along the mast to position the clasp \n550\n at the desired elevation, e.g., by sliding the clasp along the tubular stand \n80\n secured in the clasp below the upper end, by releasing a grip on the tubular stand and articulating the arm to grip another position, etc.\n \nFIG.', '11\n is an isometric exploded view of another embodiment of tubular delivery arm \n500\n.', 'Tubular delivery arm \n500\n comprises a dolly \n510\n.', 'Adjustment pads \n514\n (not shown) may be attached to ends \n511\n, \n512\n of dolly \n510\n.', 'A slide pad \n516\n is located on each adjustment pad \n514\n.', 'Slide pads \n516\n are configured for sliding engagement with mast \n10\n of drilling rig \n1\n (see \nFIG.', '15\n).', 'Translatable engagement with mast \n10\n is intended to reference translatable engagement with rails affixed to mast \n10\n for that purpose as detailed further below.', 'Adjustment pads \n514\n permit precise centering and alignment of dolly \n510\n on mast \n10\n.', 'Similar slide assemblies or roller assemblies may be substituted for this purpose.', 'An arm bracket \n520\n extends from dolly \n510\n away from the mast \n10\n.', 'A drive plate \n530\n is rotatably connected to arm bracket \n520\n, e.g., underneath it.', 'One or more arms \n532\n are pivotally and rotationally connected to extend below arm bracket \n520\n.', 'An actuator bracket \n542\n is connected to arms \n532\n.', 'A rotary actuator \n522\n is mounted to arm bracket \n520\n for controlled rotation of the drive plate \n530\n and arms \n532\n relative to dolly \n510\n.', 'A tilt actuator \n540\n is pivotally connected between actuator bracket \n542\n and drive plate \n530\n.', 'Extension of tilt actuator \n540\n provides controlled pivoting of arms \n532\n below dolly \n510\n.', 'A tubular clasp \n550\n is pivotally connected to the pivot connections \n534\n at the lower end of arms \n532\n.', 'In this embodiment, one or more extendable incline actuators \n552\n are pivotally connected to arms \n523\n at pivot connections \n554\n, and to opposing pivot connections \n534\n on clasp \n550\n.', 'Extension of the incline actuators \n552\n inclines clasp \n550\n and tilts any tubular stand \n80\n held in clasp \n550\n.', 'This embodiment permits tilting of heavy tubular stands \n80\n, such as large collars.', 'In another embodiment, a grease dispenser \n560\n is extendably connected to a lower end of arm \n532\n and extendable to position grease dispenser \n560\n at least partially inside of a box connection of tubular stand \n80\n secured by clasp \n550\n.', 'A grease supply line is connected between grease dispenser \n560\n and a grease reservoir \n570\n (see \nFIG.', '12\n).', 'In this position, grease dispenser \n560\n may be actuated to deliver grease, such as by pressurized delivery to the interior of the pin connection by either or both of spray nozzles or contact wipe application.', 'In another embodiment illustrated in \nFIG.', '12\n, a guide \n564\n is attached to arm \n532\n proximate to clasp \n550\n.', 'A grease dispenser \n560\n is connected to guide \n564\n.', 'An actuator \n566\n extends grease dispenser \n560\n to position it at least partially inside of a box connection of tubular stand \n80\n secured by clasp \n550\n.', 'In this position, grease dispenser \n560\n delivers grease to the interior of the pin connection by spray or contact application.', 'A grease supply line (not shown) connects grease dispenser \n560\n to a grease reservoir \n570\n that may be mounted on dolly \n510\n or otherwise on transfer delivery arm \n500\n.', 'Alternatively, grease reservoir \n570\n may be located at the drill floor or other convenient location and the grease supplied along the grease supply line under pressure.', 'The automatic greasing (doping) procedure improves safety by eliminating the manual application at the elevated position of tubular stand \n80\n.', 'The procedure adjusts to the height of the tubular stand \n80\n length automatically and is centered automatically by its connectivity to tubular delivery arm \n500\n.', 'The procedure may improve the efficiency of the distribution of the grease as well as cleanliness, thereby further improving safety by reducing splatter, spills, and over-application.\n \nFIG.', '12\n is a fully assembled isometric view of the embodiment of the tubular delivery arm \n500\n illustrated in \nFIG.', '11\n, illustrating arms \n532\n rotated and tilted to position clasp \n550\n over stand hand-off position \n50\n (see also \nFIG.', '3\n).', 'FIG.', '13\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIGS.', '11 and 12\n, illustrating arms \n532\n rotated and tilted to position clasp \n550\n over well center \n30\n.\n \nFIG.', '14\n is a side view of the embodiment of tubular delivery arm \n500\n illustrated in \nFIGS.', '11-13\n, illustrating the range of tubular delivery arm \n500\n to position a tubular stand \n80\n (not shown) with clasp \n550\n.\n \nFIG.', '15\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIGS.', '11-14\n, illustrating tubular delivery arm \n500\n articulated to stand hand-off position \n50\n between racking module \n300\n and mast \n10\n, and having tubular stand \n80\n secured in clasp \n550\n.\n \nFIG.', '16\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '15\n, illustrating tubular delivery arm \n500\n articulated to well center \n30\n under mast \n10\n, and having tubular stand \n80\n secured in clasp \n550\n.\n \nFIG.', '17\n is an isometric view of the embodiment of the tubular delivery arm of \nFIG.', '16\n, illustrating tubular delivery arm \n500\n connected to tubular stand \n80\n at stand hand-off position \n50\n.', 'Tubular stand \n80\n is shown secured in the stand hand-off position by clasp \n408\n of upper stand constraint \n420\n beneath racking module \n300\n.', 'In this position, tubular delivery arm \n500\n may activate grease dispenser \n560\n to apply an appropriate amount of grease inside the box end of tubular stand \n80\n.\n \nFIG.', '18\n is an isometric view of the embodiment of tubular delivery arm \n500\n of \nFIG.', '17\n, illustrating tubular delivery arm \n500\n hoisting tubular stand \n80\n released by upper stand constraint \n420\n away from stand hand-off position \n50\n adjacent to racking module \n300\n.', 'In this manner, tubular delivery arm \n500\n is delivering and centering tubular stands \n80\n for top drive \n200\n.', 'This design allows independent and simultaneous movement of tubular delivery arm \n500\n and top drive \n200\n.', 'This combined capability provides accelerated trip speeds.', 'The limited capacity of tubular delivery arm \n500\n to lift tubular stands \n80\n of drill pipe drill collars allows the weight of tubular delivery arm \n500\n and mast \n10\n to be minimized.', 'Tubular delivery arm \n500\n can be raised and lowered along the front \n12\n of mast \n10\n with an electronically controlled, hydraulic or electric variable frequency powered winch, e.g., a crown winch.', 'Alternatively, tubular delivery arm \n500\n can be raised and lowered along mast \n10\n by means of a rack and pinion arrangement, with drive motors.', 'In an embodiment, the top drive \n200\n and the tubular delivery arm \n500\n can be translated along the mast \n10\n independently, e.g., the top drive \n200\n and the tubular delivery arm \n500\n can be translated in opposite directions past one another, either above or below the other on the mast \n10\n.', 'For example, with the clasp \n550\n articulated away from the well center position \n30\n, e.g., to deliver a stand \n80\n to the stand hand-off position \n50\n as seen in \nFIG.', '15\n, the top drive \n200\n can operate along well center \n30\n to concurrently raise or lower the tubular stand \n80\n connected to the drill string.', 'In another example, in an embodiment where the top drive \n200\n is retractable from the well center position \n30\n, the top drive \n200\n can be raised or lowered in a retracted position while tubular delivery arm \n500\n operates with the clasp \n550\n in the well center \n30\n (see \nFIG.', '10\n) to deliver, retrieve, and/or secure a tubular stand \n80\n in the well center position \n30\n for connection or disconnection from the drill string held in the rotary table.', 'As a further example, by moving the tubular delivery arm \n500\n to position the clasp \n550\n below the box connection at the upper end of the stand \n80\n, the tubular delivery arm \n500\n is moved to make room for access of the top drive \n200\n above the tubular stand \n80\n as seen in \nFIG.', '10\n.', 'In this embodiment, the tubular delivery arm \n500\n and the top drive \n200\n can both operate at well center \n30\n to hand off the tubular stand \n80\n as between them.', 'For tripping in, the tubular delivery arm \n500\n engages the tubular stand \n80\n at the upper end to suspend it below the upset from the clasp \n550\n for transfer from the stand hand-off position \n50\n, for example, into well center position \n30\n to stab into the drill string stump, and then the clasp \n550\n and the dolly \n510\n can slide or otherwise move down the tubular stand \n80\n and the mast \n10\n, maintaining stabilization or the upper portion of the tubular stand \n80\n for the top drive \n200\n to connect to the box before disengaging the clasp \n550\n and returning the tubular delivery arm to the stand hand-off position \n50\n to retrieve another stand while the top drive \n200\n lowers the stand \n80\n and drill string into the well.', 'For tripping out, after the top drive \n200\n raises the string and it is suspended with a stand \n80\n above the well, the tubular delivery arm \n500\n is articulated to engage the clasp \n550\n and the tubular stand \n80\n below the top drive \n200\n and box connection, as shown in \nFIG.', '10\n.', 'While the clasp \n550\n stabilizes the upper end of the stand \n80\n below the box connection, the top drive \n200\n is disconnected and moved away from the upper end of the stand \n80\n.', 'This can allow room for the tubular delivery arm \n500\n to raise the clasp \n550\n to engage the box connection and, after disconnection of the lower end of the stand \n80\n from the drill string, hoist the tubular stand \n80\n away and over to be set down in the stand hand-off position \n50\n for racking, or in another location.', 'At the same time, the top drive \n200\n is moved into position to connect to the upper end of the drill string and hoist another stand for removal.', 'If the top drive \n200\n is retractable, it can be translated down the mast \n10\n while the stand \n80\n is disconnected from the string and the tubular delivery arm \n500\n hoists it away.', 'If the top drive \n200\n is not retractable it can be raised up on the mast \n10\n until the tubular delivery arm hoists the disconnected stand \n80\n away, and then lowered to connect to the next stand at the top of the drill string.', 'If used herein, the term “substantially” is intended for construction as meaning “more so than not.”', 'Having thus described the various embodiments, it is noted that the embodiments disclosed are illustrative rather than limiting in nature and that a wide range of variations, modifications, changes, and substitutions are contemplated in the foregoing disclosure and, in some instances, some features may be employed without a corresponding use of the other features.', 'Many such variations and modifications may be considered desirable by those skilled in the art based upon a review of the foregoing description of embodiments.', 'Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the disclosure.'] | ['1.', 'A tubular delivery arm for a drilling rig, the tubular delivery arm comprising:\na dolly vertically translatably connected to a front side of a mast of the drilling rig;\nan arm extending below the dolly; and\na tubular clasp pivotally connected to a lower end of the arm and configured to engage an upper portion of a tubular stand to enable the tubular delivery arm to adjust a vertical position of the tubular stand by vertical translation of the dolly when the tubular clasp is engaged with the tubular stand;\nwherein an upper end of the arm is rotatably connected to the dolly to enable the arm to rotate about a first axis and pivotally connected to the dolly to enable the arm to pivot about a second axis that is transverse to the first axis to enable the tubular delivery arm to move the tubular clasp, and the tubular stand when the tubular clasp is engaged with the tubular stand, between a well center position and a position forward of the well center position;\nwherein the tubular clasp is positionable on the tubular stand below an upper end of the tubular stand to secure the upper portion of the tubular stand in the well center position.', '2.', 'The tubular delivery arm of claim 1, wherein the tubular clasp is engageable with a diametral upset at the upper end of the tubular stand.', '3.', 'The tubular delivery arm of claim 1 or claim 2, wherein the tubular clasp is slidable along the tubular stand below a diametral upset at the upper end of the tubular stand to enable coincident attachment by a top drive at the well center position.', '4.', 'The tubular delivery arm of claim 1 or claim 2, wherein the tubular clasp is moveable along the tubular stand below a diametral upset at the upper end of the tubular stand to enable coincident attachment by a top drive at the well center position.', '5.', 'The tubular delivery arm of claim 1, wherein the tubular clasp comprises a gripper configured to grip the tubular stand below a diametral upset at the upper end of the tubular stand to enable coincident attachment by a top drive at the well center position.', '6.', 'The tubular delivery arm of claim 1, wherein the tubular clasp is configured to secure the tubular stand below the upper end of the tubular stand to enable coincident attachment by a top drive at the well center position.', '7.', 'The tubular delivery arm of claim 1, wherein the position forward of the well center position is selected from a mousehole position, a stand hand-off position, a catwalk position, or a combination thereof.', '8.', 'The tubular delivery arm of claim 1, wherein the tubular delivery arm has sufficient capacity to hoist a stand of drilling tubulars.', '9.', 'The tubular delivery arm of claim 1, further comprising:\nan arm bracket connected to the dolly;\na horizontally-oriented drive plate rotatably connected to the arm bracket; and\na rotary actuator connected to the arm bracket and the horizontally-oriented drive plate;\nwherein the upper end of the arm is pivotally connected to the horizontally-oriented drive plate to enable the arm to pivot about the second axis;\nwherein the rotary actuator is configured to drive the arm to rotate about the first axis.', '10.', 'The tubular delivery arm of claim 9, further comprising:\nan actuator bracket connected to the arm; and\na tilt actuator pivotally connected between the horizontally-oriented drive plate and the actuator bracket;\nwherein the tilt actuator is configured to drive the arm to rotate about the second axis.', '11.', 'The tubular delivery arm of claim 9 or claim 10, further comprising:\nan incline actuator pivotally connected between the arm and the tubular clasp, wherein the incline actuator provides a pivotal connection between the tubular clasp and the arm.\n\n\n\n\n\n\n12.', 'The tubular delivery arm of claim 1, further comprising a hoist connected to raise and lower the dolly.', '13.', 'The tubular delivery arm of claim 1, wherein the vertical translation of the tubular delivery arm is independent of a top drive on the mast.', '14.', "The tubular delivery arm of claim 1, further comprising:\na first rail connected to a driller's side of the mast;\na second rail connected to an off-driller's side of the mast;\nslide pads connected to the dolly and engaged with the first rail; and\nslide pads connected to the dolly and engaged with the second rail.\n\n\n\n\n\n\n15.", 'The tubular delivery arm of claim 14, further comprising a respective adjustment pad attached to each slide pad of the slide pads.', '16.', 'The tubular delivery arm of claim 1, wherein a centerline of the tubular stand secured in the tubular clasp is located between a pair of pivot connections between the tubular clasp and the lower end of the arm.\n\n\n\n\n\n\n17.', 'The tubular delivery arm of claim 1, wherein the tubular clasp is self-balancing.', '18.', 'The tubular delivery arm of claim 1, further comprising:\na grease dispenser extendably connected to the lower end of the arm; and\na grease supply line connected between the grease dispenser and a grease reservoir;\nwherein extension of the grease dispenser is configured to position the grease dispenser at least partially inside of a box connection of the tubular stand engaged by the clasp;\nwherein the grease dispenser is configured to deliver grease to the interior of the box connection.', '19.', 'The tubular delivery arm of claim 18, wherein the grease reservoir is mounted on the dolly, and the grease reservoir is pressurized to facilitate delivery of grease through the grease supply line and the grease dispenser.', '20.', 'The tubular delivery arm of claim 1, further comprising:\nan articulated rail attached to the arm proximate the tubular clasp; and\na grease dispenser translatably mounted to the articulated rail;\nwherein translation of the grease dispenser along the articulated rail is configured to position the grease dispenser to deliver grease to a box connection of the tubular stand when the tubular stand is engaged by the tubular clasp.', '21.', 'A method to deliver a tubular stand to and from a well center position, the method comprising:\nconnecting a dolly of a tubular delivery arm to a front side of a mast;\nrotatably and pivotally connecting an upper end of an arm to extend below the dolly;\npivotally connecting a tubular clasp at a lower end of the arm;\nsecuring an upper portion of the tubular stand in the tubular clasp;\nvertically translating the dolly on the front side of the mast to adjust a vertical position of the tubular stand secured in the tubular clasp;\nrotating the arm about a first axis and tilting the arm about a second axis that is transverse to the first axis to move the tubular stand secured in the tubular clasp between the well center position and a position forward of the well center position; and\npositioning the tubular clasp below an upper end of the tubular stand to secure the upper portion of the tubular stand in the well center position.\n\n\n\n\n\n\n22.', 'The method of claim 21, further comprising:\nconnecting or disconnecting a top drive to the tubular stand secured by the tubular clasp in the well center position; and\nremoving the tubular clasp from the tubular stand.', '23.', 'The method of claim 22, further comprising connecting or disconnecting a drill string and a lower end of the tubular stand secured by the tubular clasp in the well center position.', '24.', 'The method of claim 21, further comprising engaging the tubular clasp with a diametral upset at the upper end of the tubular stand while vertically translating the dolly.', '25.', 'The method of claim 24, wherein the positioning of the tubular clasp below the upper end of the tubular stand to secure the upper portion of the tubular stand in the well center position comprises moving the tubular clasp along the tubular stand below the diametral upset.\n\n\n\n\n\n\n26.', 'The method of claim 24, wherein the positioning of the tubular clasp below the upper end of the tubular stand to secure the upper portion of the tubular stand in the well center position comprises engaging the tubular clasp and the tubular stand below the diametral upset, and further comprises moving the tubular clasp along the tubular stand to engage the diametral upset.', '27.', 'The method of claim 25 or claim 26, wherein the moving the tubular clasp along the tubular stand comprises sliding.', '28.', 'The method of claim 21, further comprising gripping the tubular stand at or below a diametral upset with the tubular clasp while vertically translating the dolly.\n\n\n\n\n\n\n29.', 'The method of claim 21 or claim 28, wherein the positioning of the tubular clasp below the upper end of the tubular stand to secure the upper portion of the tubular stand in the well center position comprises gripping the tubular stand with the tubular clasp below a diametral upset.', '30.', 'The method of claim 21, further comprising gripping the tubular stand below a diametral upset with the tubular clasp while vertically translating the dolly and while securing the upper portion of the tubular stand in the well center position.'] | ['FIG.', '1 is an isometric view of an embodiment of a tubular delivery arm for a drilling rig.; FIG.', '2 is an isometric exploded view of the embodiment of the tubular delivery arm illustrated in FIG.', '1.; FIG. 3 is a side view of another embodiment of the tubular delivery arm illustrated, illustrating the range of the tubular delivery arm to position a suspended tubular stand pipe relative to positions of use on a drilling rig.; FIG.', '4 is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position to receive a section of drill pipe from the catwalk.; FIG.', '5 is an isometric view of the embodiment of the tubular delivery arm of FIG. 4, illustrating the tubular delivery arm receiving a section of drill pipe from the catwalk.; FIG.', '6 is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned to receive a tubular stand from, or deliver a section of pipe to, the mousehole.; FIG. 7 is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and in position at a height below the top drive to receive (or deliver) a tubular stand at the stand hand-off position at the racking module.; FIG. 8 is an isometric view of the embodiment of the tubular delivery arm of FIG. 7, illustrating the tubular delivery arm positioned over the stand hand-off position between the racking module and the mast, and having the upset of a tubular stand secured in the clasp.; FIG.', '9 is a side view of an embodiment of the tubular delivery arm connected to a drilling mast and positioned over a mousehole.; FIG.', '10 is an isometric view of the embodiment of the tubular delivery arm of FIG.', '9, illustrating the tubular delivery arm articulated over well center after delivering a tubular stand into a stump at the well center, with the clasp moved down the tubular stand, readied to release and hand off the tubular stand when secured by the top drive (or ready to slide or otherwise move up the tubular stand to the upset and hoist it away from well center after disconnection of the top drive).', '; FIG.', '11 is an isometric exploded view of an alternative embodiment of the tubular delivery arm.; FIG.', '12 a fully assembled isometric view of the alternative embodiment of the tubular delivery arm illustrated in FIG.', '11.; FIG. 13 is an isometric view of the embodiment of the tubular delivery arm of FIGS.', '11 and 12, illustrating the arms rotated and in position over the well center.', '; FIG.', '14 is a side view of the embodiment of the tubular delivery arm illustrated in FIGS.', '11-13, illustrating the range of the tubular delivery arm to position a tubular stand.', '; FIG.', '15 is an isometric view of the embodiment of the tubular delivery arm of FIGS.', '11-14, illustrating the tubular delivery arm articulated to the stand hand-off position between the racking module and the mast, and having a tubular stand secured in the clasp.; FIG.', '16 is an isometric view of the embodiment of the tubular delivery arm of FIG.', '15, illustrating the tubular delivery arm articulated over the well center and handing a tubular stand to the top drive, or receiving the tubular stand from the top drive.; FIG.', '17 is an isometric view of the embodiment of the tubular delivery arm of FIG.', '16, illustrating the tubular delivery arm articulated to reach an upper end of a tubular stand held by an upper stand constraint component at the stand hand-off position.; FIG.', '18 is an isometric view of the embodiment of the tubular delivery arm of FIG.', '17, illustrating the upper stand constraint having released (or ready to receive) the tubular stand and the tubular delivery arm hoisting the tubular stand at the box connection as the grease dispenser is lowered to spray grease into the box end of the tubular stand being lifted.; FIG. 1 is an isometric view of an embodiment of a tubular delivery arm 500.', 'FIG.', '2 is an isometric exploded view of this embodiment of tubular delivery arm 500.', 'As best seen in FIG.', '2, tubular delivery arm 500 comprises a dolly 510.', 'Dolly 510 is configured for vertically translatable connection to a mast 10 of a drilling rig 1 (see FIG. 4).', "Dolly 510 has a driller's side end 511 and an opposite off-driller's side end 512.; FIG.", '3 is a side view of the embodiment of tubular delivery arm 500 of FIG.', '1 and FIG.', '2, illustrating the lateral range of the motion of tubular delivery arm 500 to position a tubular stand 80 relative to positions of use on a drilling rig 1.', 'Illustrated is the capability of tubular delivery arm 500 to retrieve and deliver a tubular stand 80 as between a well center 30, a mousehole 40, and a stand hand-off position 50, passing the clasp 550 and the suspended tubular stand below the dolly 510.', 'Also illustrated is the capability of tubular delivery arm 500 to move to a catwalk position 60 and incline clasp 550 for the purpose of retrieving or delivering a tubular section 2 from a catwalk 600.; FIG.', '4 is a side view of the embodiment of tubular delivery arm 500 shown connected to drilling mast 10 of drilling rig 1 in catwalk position 60 (see FIG.', '3) to receive a tubular section 2 from catwalk 600.', 'For this purpose, it is advantageous to have inclination control of clasp 550, as disclosed in an embodiment shown in FIGS.', '11-14.; FIG.', '5 is an isometric view of the embodiment of tubular delivery arm 500 of FIG.', '4, receiving a tubular section 2 (drill pipe 2) from catwalk 600.', 'As seen in this view, tubular delivery arm 500 is articulated outwards by tilt actuator 540 to permit clasp 550 to attach to tubular section 2.', 'From this position, tubular delivery arm 500 can be used to deliver tubular section 2 to the well center for make-up with the drill string in the well by an iron roughneck 750 shown positioned by a drill floor manipulating arm 700.', 'Alternatively, tubular delivery arm 500 can be used to build a stand with another drill pipe 2 secured in a mousehole 40 having a mousehole center (see FIGS.', '3 and 6).;', 'FIG. 6 is a side view of an embodiment of tubular delivery arm 500 connected to a drilling mast 10 in position to receive or deliver tubular stand 80 to mousehole 40.; FIG. 7 is a side view of an embodiment of tubular delivery arm 500 connected to a drilling mast 10 and in position near the upper end to receive (or deliver) tubular stand 80 from stand hand-off position 50 at racking module 300.; FIG. 8 is an isometric view of the embodiment of tubular delivery arm 500 of FIG. 7, illustrating tubular delivery arm 500 articulated to stand hand-off position 50 between racking module 300 and mast 10, and having tubular stand 80 secured in clasp 550.; FIG.', '9 is a side view of an embodiment of tubular delivery arm 500 connected to drilling mast 10 and in position to deliver tubular stand 80 to or from mousehole 40.; FIG.', '10 is an isometric view of an embodiment of tubular delivery arm 500 connected to drilling mast 10 and in position to deliver tubular stand 80 to or from well center 30 to stab into (or be disconnected from) a stump secured at well center 30.', 'After stabbing (or disconnection), tubular delivery arm 500 can hand tubular stand 80 off to top drive 200 (or move up the tubular stand 80 to secure it at the upset and hoist it away).', 'Tubular delivery arm 500 is articulated by expansion of tilt actuator 540 (best seen in FIG.', '13) which inclines arm 532 into position such that the centerline of tubular stand 80 in clasp 550 is properly over well center 30, and raised or lowered by translating the dolly 510 along the mast to position the clasp 550 at the desired elevation, e.g., by sliding the clasp along the tubular stand 80 secured in the clasp below the upper end, by releasing a grip on the tubular stand and articulating the arm to grip another position, etc.; FIG.', '11 is an isometric exploded view of another embodiment of tubular delivery arm 500.', 'Tubular delivery arm 500 comprises a dolly 510.', 'Adjustment pads 514 (not shown) may be attached to ends 511, 512 of dolly 510.', 'A slide pad 516 is located on each adjustment pad 514.', 'Slide pads 516 are configured for sliding engagement with mast 10 of drilling rig 1 (see FIG.', '15).', 'Translatable engagement with mast 10 is intended to reference translatable engagement with rails affixed to mast 10 for that purpose as detailed further below.', 'Adjustment pads 514 permit precise centering and alignment of dolly 510 on mast 10.', 'Similar slide assemblies or roller assemblies may be substituted for this purpose.; FIG.', '12 is a fully assembled isometric view of the embodiment of the tubular delivery arm 500 illustrated in FIG.', '11, illustrating arms 532 rotated and tilted to position clasp 550 over stand hand-off position 50 (see also FIG. 3).; FIG.', '13 is an isometric view of the embodiment of tubular delivery arm 500 of FIGS.', '11 and 12, illustrating arms 532 rotated and tilted to position clasp 550 over well center 30.; FIG.', '14 is a side view of the embodiment of tubular delivery arm 500 illustrated in FIGS.', '11-13, illustrating the range of tubular delivery arm 500 to position a tubular stand 80 (not shown) with clasp 550.; FIG.', '15 is an isometric view of the embodiment of tubular delivery arm 500 of FIGS.', '11-14, illustrating tubular delivery arm 500 articulated to stand hand-off position 50 between racking module 300 and mast 10, and having tubular stand 80 secured in clasp 550.; FIG.', '16 is an isometric view of the embodiment of tubular delivery arm 500 of FIG.', '15, illustrating tubular delivery arm 500 articulated to well center 30 under mast 10, and having tubular stand 80 secured in clasp 550.; FIG.', '17 is an isometric view of the embodiment of the tubular delivery arm of FIG.', '16, illustrating tubular delivery arm 500 connected to tubular stand 80 at stand hand-off position 50.', 'Tubular stand 80 is shown secured in the stand hand-off position by clasp 408 of upper stand constraint 420 beneath racking module 300.', 'In this position, tubular delivery arm 500 may activate grease dispenser 560 to apply an appropriate amount of grease inside the box end of tubular stand 80.; FIG.', '18 is an isometric view of the embodiment of tubular delivery arm 500 of FIG.', '17, illustrating tubular delivery arm 500 hoisting tubular stand 80 released by upper stand constraint 420 away from stand hand-off position 50 adjacent to racking module 300.'] |
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US11118095 | Compositions and methods for servicing subterranean wells | Sep 15, 2016 | Diankui Fu, Kong Teng Ling, Daniel Thomas Melice | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in International Patent Appl. No. PCT/MY2016/000058 dated Jun. 13, 2017; 12 pages.; Zamora M and Stephens M: “Drilling Fluids,” in Economides MJ, Watters LT and Dunn-Norman S (eds): Petroleum Well Construction, Wiley, Chichester (1998) 119-142.; International Preliminary Report on Patentability issued in International Patent Appl. No. PCT/MY2016/000058 dated Mar. 28, 2019; 9 pages. | 6886635; May 3, 2005; Hossaini et al.; 20010036905; November 1, 2001; Parlar; 20050252659; November 17, 2005; Sullivan; 20060166837; July 27, 2006; Lin et al.; 20110186293; August 4, 2011; Gurmen; 20140367091; December 18, 2014; Tour; 20160053160; February 25, 2016; Nguyen et al.; 20160122616; May 5, 2016; Fu; 20160130497; May 12, 2016; Liu; 20160152884; June 2, 2016; Ravitz; 20160177162; June 23, 2016; Nguyen et al.; 20160208157; July 21, 2016; Vo; 20170088763; March 30, 2017; Sui; 20170096592; April 6, 2017; Misra; 20180223180; August 9, 2018; Hall | 2013160334; October 2013; WO; 2014165347; October 2014; WO | No images available | ['Treatment fluids containing salts, surfactants, mutual solvents and fibers may be used to remove wellbore filter cakes that have been deposited by drilling fluids.', 'The drilling fluids may be water-base, oil-base, synthetic-base or emulsions.', 'The fibers may be selected from polylactic acid, celluloses, polyesters, polyvinyl alcohols and polyethylene terephthalates.', 'A combination of straight and crimped fibers is present in the treatment fluid.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThe statements in this section merely provide background information related to the present disclosure and may not constitute prior art.', 'This disclosure relates to compositions and methods for removing drilling fluid filtercakes from subterranean wellbores.', 'Drilling fluids, also referred to as drilling muds, facilitate the drilling process by suspending cuttings, controlling pressure, stabilizing exposed rock, providing buoyancy and cooling and lubricating the drill bit.', 'As drilling fluid circulates in the wellbore, a filter cake often forms along the formation rock surface.', 'The filter cake may be beneficial in that it provides fluid-loss control, preventing the liquid phase of the drilling fluid from escaping into the formation-rock matrix.', 'This helps preserve the designed chemical and rheological properties of the drilling fluid, and also minimizes near-wellbore formation damage (i.e., a permeability loss that may impair subsequent production of hydrocarbons).', 'Before well production begins, particularly in openhole completions that are not perforated, it is desirable to remove the filtercake and maximize well productivity.', 'Drilling fluid filter cake contains a mixture of inorganic and organic solids.', 'The permeability of the filter cake may be low enough to impair production.', 'Filter cake removal is often enhanced by fluid treatments that contain a suite of chemicals (e.g., acids, chelating agents and enzyme breakers) designed to dissolve and break down the solids and polymers.', 'Such treatments may involve long soaking times, up to a few days, to achieve the desired result.', 'Effective dissolution and removal of mineral solids within the filter cake may be particularly problematic.', 'When the organic fraction of the filtercake is removed, the filter cake permeability may be higher and the treatment fluid may bypass the minerals and leak into the formation rock.', 'Removal of a common drilling fluid weighting material, barite (BaSO\n4\n), may be particularly challenging because the mineral has limited solubility in almost many chemical solvents.', 'SUMMARY\n \nThe present disclosure describes improved compositions for removing drilling fluid filter cakes from formation rock surfaces.', 'The drilling fluid may be water-base, oil-base or an emulsion.', 'In an aspect, embodiments relate to well cleaning compositions.', 'The composition comprise a carrier fluid, a salt, a surfactant, a mutual solvent and at least two fibers selected from the group consisting of polylactic acid, natural celluloses, polyesters, polyvinyl alcohol and polyethylene terephthalate.', 'The fibers have lengths between 1 mm and 20 mm, and diameters between 10 μm and 50 μm.', 'A first fiber is a straight fiber and a second fiber is a crimped fiber.', 'In a further aspect, embodiments relate to methods for cleaning a wellbore.', 'A well is drilled with an oil-base mud, a water-base mud, a synthetic-base mud or an emulsion mud.', 'A mud filter cake is deposited on a wellbore wall.', 'A well cleaning composition is prepared that comprises a carrier fluid, a salt, a surfactant, a mutual solvent and at least two fibers selected from the group consisting of polylactic acid, natural celluloses, polyesters, polyvinyl alcohol and polyethylene terephthalate.', 'The fibers have lengths between 1 mm and 20 mm, and diameters between 10 μm and 50 μm.', 'The well cleaning composition is placed in the wellbore, thereby removing the mud filter cake from the wellbore wall.', 'A first fiber is a straight fiber and a second fiber is a crimped fiber.', 'In yet a further aspect, embodiments relate to methods for treating a well.', 'A well is drilled with an oil-base mud, a water-base mud, a synthetic-base mud or an emulsion mud.', 'A mud filter cake is deposited on a wellbore wall.', 'A well cleaning composition is prepared that comprises a carrier fluid, a salt, a surfactant, a mutual solvent and at least two fibers selected from the group consisting of polylactic acid, natural celluloses, polyesters, polyvinyl alcohol and polyethylene terephthalate.', 'The fibers have lengths between 1 mm and 20 mm, and diameters between 10 μm and 50 μm.', 'The well cleaning composition is circulated in the well, thereby removing the mud filtercake from the wellbore wall.', 'A first fiber is a straight fiber and a second fiber is a crimped fiber.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify primary features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'DETAILED DESCRIPTION', 'In the following description, numerous details are set forth to provide an understanding of the present disclosure.', 'However, it may be understood by those skilled in the art that the methods of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.', "At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions are made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another.", 'Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.', 'In addition, the composition used/disclosed herein can also comprise some components other than those cited.', 'In the summary of the disclosure and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context.', 'The term about should be understood as any amount or range within 10% of the recited amount or range (for example, a range from about 1 to about 10 encompasses a range from 0.9 to 11).', 'Also, in the summary and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any concentration within the range, including the end points, is to be considered as having been stated.', 'For example, “a range of from 1 to 10” is to be read as indicating each possible number along the continuum between about 1 and about 10.', 'Furthermore, one or more of the data points in the present examples may be combined together, or may be combined with one of the data points in the specification to create a range, and thus include each possible value or number within this range.', 'Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to a few specific, it is to be understood that inventors appreciate and understand that any data points within the range are to be considered to have been specified, and that inventors possessed knowledge of the entire range and the points within the range.', 'Embodiments relate to compositions and methods for removing drilling fluid filter cake from formation rock surfaces in a wellbore.', 'As mentioned earlier, drilling fluids may be water-base, oil-base, synthetic-base or emulsions.', 'The emulsions may be water-in-oil emulsions.', 'The drilling fluids contain both organic and inorganic components.', 'For example, water-base fluids may contain a plethora of materials for various purposes.', 'Weighting agents include barite, hematite and calcium carbonate.', 'Viscosifiers include bentonite, attapulgite, sepiolite, beneficiated bentonite, biopolymers (xanthan and welan gum), guar gum, hydroxyethyl cellulose (HEC) and mixed-metal hydroxides (MMH).', 'Filtration control agents include starch, cellulose polysaccharide, carboxymethyl cellulose (CMC) and polyacrylates.', 'Salts include sodium chloride, potassium chloride, calcium chloride.', 'Lost circulation materials include nut shells, mica and cellophane flakes.', 'Petroleum oils are used for the continuous phase of oil-base muds.', 'Crude oil may be employed; however, the use of diesel oil and low-toxicity mineral oils is more commonplace today.', 'Oil-base fluids may contain the same inorganic weighting materials and lost circulation materials as water-base fluids.', 'Synthetic-base fluids are composed of man-made nonaqueous fluids with lower toxicity than oil-base fluids.', 'Such fluids include esters, ethers, polyalphaolefins and acetals.', 'Synthetic-base fluids may contain the same inorganic weighting materials and lost circulation materials as water-base fluids.', 'A complete description of drilling fluids and their use may be found in the following publication.', 'Zamora M and Stephens M: “Drilling Fluids,” in Economides M J, Watters L T and Dunn-Norman S (eds): \nPetroleum Well Construction\n, Wiley, Chichester (1998) 119-142.', 'For each aspect, the carrier fluid of the composition may be composed solely of water.', 'The water may be fresh water, sea water, produced water or a brine.', 'The salt may be a halide salt.', 'Halide salts may include sodium chloride, potassium chloride, cesium chloride, calcium chloride, sodium bromide, potassium bromide and cesium bromide.', 'The salt may be present in the composition at a concentration between 0.5 wt % and 35 wt %, or 2.0 wt % and 20 wt %, or 5.0 wt % and 15 wt %.', 'For each aspect, the mud filter cake may comprise barite.', 'For each aspect, the fibers may comprise one or more members or the group consisting of natural celluloses, polyesters, polyvinyl alcohol and polyethylene terephthalate.', 'The fibers may further comprise polylactic acid.', 'The natural celluloses may include fibers made from wood pulp, bamboo, cotton, flax, hemp, jute and ramie.', 'The fibers may be present in the composition at a concentration between 0.2 wt % and 2 wt %, or 0.4 wt % and 1.8 wt %, or 0.6 wt % and 1.4 wt %.', 'For each aspect, the fiber length may be between 1 mm and 20 mm, or between 3 mm and 10 mm.', 'The fiber diameter may be between 10 μm and 50 μm, or between 10 μm and 20 μm.', 'For each aspect, the fibers may be crimped.', 'For this disclosure, crimps are defined as undulations, waves or a succession of bends, curls and waves in a fiber strand.', 'The crimps may occur naturally, mechanically or chemically.', 'Crimp has many characteristics, among which are its amplitude, frequency, index and type.', 'For this disclosure, crimp is characterized by a change in the directional rotation of a line tangent to the fiber as the point of tangent progresses along the fiber.', 'Two changes in rotation constitute one unit of crimp.', 'Crimp frequency is the number of crimps or waves per unit length of extended or straightened fiber.', 'Another parameter is the crimping ratio, K1 (Eq. 1).', 'K\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n=\n \n \n \nLv\n \n-\n \nLk\n \n \nLv\n \n \n \n,\n \n \n \n \n \n(\n \n \nEq\n \n.\n \n \n \n \n\u2062\n \n1\n \n \n)\n \n \n \n \n \n \n \n where Lk is the length of the crimped fiber in the relaxed, released state; and Lv is the length of the same fiber in the stretched state (i.e., the fiber is practically rectilinear without any bends).', 'Mixtures of crimped fibers and straight fibers may also be employed.', 'The concentration ratio between crimped and straight fibers may vary from about 10:90 to 90:10, or between 25:75 and 75:25, or between 40:60 and 60:40 by weight.', 'For this disclosure, the fibers may have a crimp frequency between 1/cm and 6/cm, or 1/cm and 5/cm or 1/cm and 4/cm.', 'The K1 value may be between 2 and 15, or between 2 and 10 or between 2 and 6.', 'For each aspect, the surfactant may be non-ionic, anionic or zwitterionic or combinations thereof.', 'Suitable non-ionic surfactants may include nonionic surfactants may comprise long chain alcohols, ethoxylated alcohols, polyoxyethylene glycol alkyl ethers, polyoxypropylene glycol alkyl ethers, glucoside alkyl ethers, polyoxyethylene glycol octylphenol ethers, polyoxyethylene glycol alkylphenol ethers, glycerol alkyl esters, polyoxyethylene glycol sorbitan alkyl esters, sorbitan alkyl esters, cocamide DEA, cocamide MEA, dodecyldimethylamine oxide, block copolymers of polyethylene glycol or polypropylene glycol, or polyethoxylated tallow amine or combinations thereof.', 'Suitable anionic surfactants may include ammonium lauryl sulfate, sodium lauryl sulfate, sodium laureth sulfate, sodium myreth sulfate, dioctyl sodium sulfosuccinate, perfluorooctane sulfonates, perfluorobutanesulfonates, alkylbenzene sulfonates, alkyl-aryl ether phosphates, alkyl ether phosphates, alkyl carboxylates, sarcosinates, perfluorononanoates, or perfluorooctanoates or combinations thereof.', 'Suitable zwitterionic surfactants may include sultaines or betaines or combinations thereof.', 'The surfactant may be 3-[(3-Cholamidopropyl)dimethylammonio]-1-propanesulfonate, cocamidopropyl hydroxysultaine, or cocamidopropyl betaine or a combination thereof.', 'The surfactant may be present in the composition at a concentration between 0.2 wt % and 15 wt %, or between 1.0 wt % and 10 wt %, or between 2.0 wt % and 5.0 wt %.', 'For each aspect, suitable mutual solvents may include methanol, ethanol, ethylene glycol, propylene glycol, isopropanol or 2-butoxyethanol or a combination thereof.', 'The mutual solvent may be 2-butoxyethanol.', 'The mutual solvent may be present at a concentration between 1.0 wt % and 20 wt %, or between 3.0 wt % and 15 wt %, or between 5.0 wt % and 10 wt %.', 'For each aspect, the composition may further comprise a corrosion inhibitor.', 'Suitable corrosion inhibitors may include acetylenic alcohols.', 'The corrosion inhibitor may be an organic acid, including formic acid.', 'The corrosion inhibitor may be present in the composition at a concentration between 0.1 wt % and 5.0 wt %, or 0.2 wt % and 2.5 wt %, or 0.5% and 2.0 wt %.', 'For the aspect pertaining to well cleaning and well treatment methods, the composition may remain stationary in the well for a period between 0.5 hr and 24 hr, or 2.0 hr and 12 hr, or 3.0 hr and 6.0 hr.', 'For the aspects pertaining to the well cleaning and well treatment methods, the composition may be circulated out of the well.', 'The foregoing is further illustrated by reference to the following examples, which are presented for purposes of illustration and are not intended to limit the scope of the present disclosure.', 'EXAMPLES', 'The following examples serve to further illustrate the disclosure.', 'The following test method was employed in each of the following examples.', 'A dynamic fluid-loss cell was employed to simulate the filtration process that takes place in a wellbore during drilling.', 'The fluid-loss cell was a Model 7120 Stirred Fluid Loss Tester, available from Chandler Engineering, Broken Arrow, Okla., USA.', 'A porous ceramic disk was employed to simulate the formation rock.', 'The dimensions of the disk were 6.30 cm (2.48 in.)', 'in diameter and 0.64 cm (0.25 in.)', 'thick.', 'The ceramic disk was saturated in 2% KCl solution for one hour, then weighed.', 'The weight was recorded as W1.', 'The disk was then placed in the test cell.', 'The heating jacket of the apparatus was set to 50° C. 200 mL of drilling fluid was stirred before being poured into the test cell.', 'The test cell was sealed and pressured to 300 psi [2.1 MPa] for a period of 2 hours.', 'Then, the cell was allowed to cool and the pressure was released.', 'The remaining drilling fluid was carefully removed from the test cell.', 'The ceramic disk, upon which a filter cake had been deposited was weighed and the result was recorded as W2.', 'The ceramic disk was then reinserted into the test cell.', '200 mL of treatment fluid was then carefully added along the inner wall of the test cell, ensuring that the flow of treatment fluid did not disturb the filter cake.', 'The test cell was resealed and reheated to 50° C.', 'The cell was repressurized to 100 psi [0.7 MPa].', 'The paddle stirrer inside the test cell was then turned on at a rotational speed of 500 RPM.', 'The stirring period was 10 min.', 'Following the stirring period, the test cell was opened and the ceramic disk was removed and reweighed.', 'The result was recorded as W3.', 'The percentage of drilling fluid removed from the ceramic disk was then calculated by the following equation.', 'Mud\n \n\u2062\n \n \n \n \n\u2062\n \nRemoval\n \n\u2062\n \n \n \n \n\u2062\n \n \n(\n \n%\n \n)\n \n \n \n=\n \n \n1\n \n-\n \n \n \n(\n \n \n \n \nW\n \n\u2062\n \n \n \n \n\u2062\n \n3\n \n \n-\n \n \nW\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n \nW\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n-\n \n \nW\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n)\n \n \n×\n \n100\n \n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n2\n \n \n)', 'Example 1\n \nA water-base drilling fluid was prepared with the composition presented in Table 1.', 'The fluid density was 11.5 lbm/gal (1,380 kg/m\n3\n).', 'TABLE 1\n \n \n \n \n \n \n \n \nWater-base drilling fluid formulation.', 'Concentration \n \n \n \n \nIngredient\n \n(kg/m\n3\n)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nWater\n \n366\n \n \n \n \nKCl\n \n81.2\n \n \n \n \n8 wt % NaBr Brine\n \n763\n \n \n \n \nXanthan Gum\n \n3.6\n \n \n \n \nStarch\n \n17.1\n \n \n \n \nShale Stabliizer\n \n29.9\n \n \n \n \nMgO\n \n1.4\n \n \n \n \nBiocide\n \n0.6\n \n \n \n \nCaCO\n3 \n(6-15 microns)\n \n57.0\n \n \n \n \nCaCO\n3 \n(16-29 microns)\n \n57.0', 'The drilling fluid contained additives that are available from MI-SWACO, Houston, Tex., USA.', 'The xanthan gum was FLOVIS PLUS, the starch was FLO-TROL, the shale stabilizer was KLAGARD and the CaCO\n3 \nwas SAFECARB 10 and SAFECARB 20.', 'A base cleaning composition was prepared with the composition presented in Table 2.\n \n \n \n \n \n \n \n \nTABLE 2\n \n \n \n \n \n \n \n \nBase cleaning composition.', 'Concentration \n \n \n \n \nIngredient\n \n(vol %)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nNaBr Brine (11.5 lbm/gal \n \n92.3\n \n \n \n \n[1,380 kg/m\n3\n])\n \n \n \n \n \nnon-ionic surfactant \n \n5.0\n \n \n \n \n(amine oxide)\n \n \n \n \n \n2-butoxyethanol\n \n2.5\n \n \n \n \norganic acid \n \n0.2\n \n \n \n \ncorrosion inhibitor\n \n \n \n \n \n \n \n \n \n \n \nVarious fibers were added to the base cleaning composition at a concentration of 60 lbm/1,000 gal (7.17 kg/m\n3\n).', 'The fibers are listed in Table 3.\n \n \n \n \n \n \n \n \nTABLE 3\n \n \n \n \n \n \n \n \nTest fibers.', 'Fiber\n \nComposition\n \nDimensional Information\n \n \n \n \n \n \n1\n \nPolylactic Acid (crimped)\n \n6 mm length; 13 μm diameter\n \n \n \n2\n \nPolylactic Acid (straight)\n \n6 mm length; 12 μm diameter\n \n \n \n3\n \nPolyethylene Terephthalate\n \n6 mm length; 12 μm diameter\n \n \n \n4\n \nPolyvinyl Alcohol\n \n1.5 mm length; 12 μm diameter\n \n \n \n5\n \nCellulose (Bamboo)\n \n10 μm diameter\n \n \n \n6\n \nNylon-6\n \n6 mm length; 13 μm diameter\n \n \n \n7\n \nPolylactic Acid (straight)\n \n6 mm length; 40 μm diameter\n \n \n \n8\n \nPolylactic Acid (straight)\n \n6 mm length; 40 μm diameter\n \n \n \n \n \n \n \n \n \n \nExperiments were conducted with the fibers of Table 3 according to the procedure described above.', 'The results are shown in Table 4.\n \n \n \n \n \n \n \n \nTABLE 4\n \n \n \n \n \n \n \n \nMud removal results-water base drilling fluid.', 'Fiber\n \nMud Removal (%)', 'No Fiber (control)\n \n0.0\n \n \n \n \n1\n \n40.8\n \n \n \n \n2\n \n59.0\n \n \n \n \n3\n \n39.1\n \n \n \n \n4\n \n52.4\n \n \n \n \n5\n \n13.1\n \n \n \n \n6\n \n35.0\n \n \n \n \n7\n \n13.6\n \n \n \n \n8\n \n25.0\n \n \n \n \n1 (50 wt %); 7 (50 wt %)\n \n64.0\n \n \n \n \n1 (50 wt %); 8 (50 wt %)\n \n59.8', 'It is notable that a synergistic effect was observed when mixtures of crimped and straight polylactic acid fibers were tested (e.g., Fiber 1 and Fiber 7, and Fiber 1 and Fiber 8).', 'Compared to Fiber 1 alone, the mud removal performance improvement resuiting from using a mixture of crimped and straight fibers varied from about 50% to 60%.', 'Without wishing to be held to any particular theory, the improved mud removal performance may be due to a scrubbing action of the fiber combination.', 'Example 2\n \nAn oil-base drilling fluid was prepared with the composition presented in Table 5.', 'The mud density was 1,320 kg/m\n3 \n(11.0 lbm/gal) and barite was employed as a weighting material.', 'The base cleaning composition of Table 2 was employed in the mud removal experiments.', 'TABLE 5\n \n \n \n \n \n \n \n \nOil-base drilling fluid formulation.', 'Concentration \n \n \n \n \nIngredient\n \n(vol %)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nCrystalline silica, Quartz\n \n0.3\n \n \n \n \nCalcium Hydroxide\n \n0.3\n \n \n \n \nCalcium Chloride\n \n8.0\n \n \n \n \nParaffin based petroleum oil\n \n60.0\n \n \n \n \nBarium Sulfate\n \n11.4\n \n \n \n \n \n \n \n \n \n \n \nMud removal tests were performed with the cleaning composition of Table 2 containing no fibers (as a control) and 60 lbm/1,000 gal (7.17 kg/m\n3\n) of Fiber 1.', 'The mud removal achieved by the control fluid was 0.00%, while that achieved by the fluid containing fibers was 95.50%.', 'Example 3\n \nThe ability of the disclosed compositions to remove a mud filter cake containing was also investigated by measuring the regained permeability of ceramic disks.', 'A porous ceramic disk was employed to simulate the formation rock.', 'The dimensions of the disk were 6.30 cm (2.48 in.)', 'in diameter and 0.64 cm (0.25 in.)', 'thick.', 'The ceramic disk was saturated in 2% KCl solution under vacuum for one hour.', 'The disk was then loaded into a Chandler dynamic fluid-loss cell filled with 2% KCl.', 'The KCl solution was pumped through the ceramic disk at various flow rates and the differential pressure in the cell was recorded.', "The initial permeability of the disk was than calculated by Darcy's Law.", 'Next, the fluid-loss cell was heated to 50° C. and filled with a drilling fluid described.', 'The ceramic disk remained in the cell.', 'The cell was pressurized to 2.1 MPa (300 psi), and mud filtrate was collected over a 4-hr period.', 'The cell was cooled to ambient temperature, the pressure was released, and residual mud was carefully removed.', 'The ceramic disk was then reinserted into the fluid-loss cell.', '200 mL of treatment fluid, containing 60 lbm/1,000 gal (7.17 kg/m3) of Fiber 1, was then carefully added along the inner wall of the test cell, ensuring that the flow of treatment fluid did not disturb the filter cake.', 'The test cell was resealed and reheated to 50° C.', 'The cell was repressurized to 0.7 Mpa (100 psi).', 'The paddle stirrer inside the test cell was then turned on at a rotational speed of 500 RPM.', 'The stirring period was 10 min.', 'The ceramic disk was replaced in the fluid-loss cell and the fluid-loss cell was then filled with 2% KCl solution.', 'The final permeability of the disk was determined as described above by flowing the KCl solution through the disk at various rates and measuring the differential pressure.', 'The regained permeability was then calculated by the following equation.', 'Regained\n \n\u2062\n \n \n \n \n\u2062\n \nPermeability\n \n\u2062\n \n \n \n \n\u2062\n \n \n(\n \n%\n \n)\n \n \n \n=\n \n \n \n(\n \n \n \nFinal\n \n\u2062\n \n \n \n \n\u2062\n \nPermeabiility\n \n \n \nInitial\n \n\u2062\n \n \n \n \n\u2062\n \nPermeabiility\n \n \n \n)\n \n \n×\n \n100\n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n3\n \n \n)', 'This test was performed with the water-base mud described in Table 1 and the oil-base mud described in Table 5.', 'The results, shown in Table 6, show that the fibers in the cleaning solution effectively removed the filter cake containing barite.\n \n \n \n \n \n \n \n \nTABLE 6\n \n \n \n \n \n \n \n \nRegained permeabilities from ceramic \n \n \n \ndisks treated with drilling muds.', 'Water-base \n \nOil-base \n \n \n \n \n \nMud\n \nMud\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nInitial Permeability, mD\n \n136\n \n124\n \n \n \n \nFinal Permeability, mD\n \n22\n \n116\n \n \n \n \nRegained Permeability, %\n \n16\n \n94\n \n \n \n \n \n \n \n \n \n \n \nAlthough just a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this disclosure.', 'Accordingly, each modification is intended to be included within the scope of this disclosure as defined in the following claims.'] | ['1.', 'A method for cleaning a wellbore, comprising:\n(i) drilling a well with a water-base mud, oil-base mud, a synthetic-base mud or an emulsion mud;\n(ii) depositing a mud filtercake on a wellbore wall;\n(iii) preparing a well cleaning composition that comprises a carrier fluid, a salt, a surfactant, a mutual solvent, and at least two fibers selected from the group consisting of natural celluloses, polylactic acid, polyesters, polyvinyl alcohol and polyethylene terephthalate, wherein the at least two fibers have lengths between 1 mm and 20 mm and diameters between 10 μm and 50 μm; and\n(iv) placing the well cleaning composition in the well, thereby removing the mud filtercake from the wellbore wall; wherein a first fiber of the at least two fibers is a straight fiber and a second fiber of the at least two fibers is a crimped fiber, and wherein a first length of the straight fiber is about equal to a second length of the crimped fiber, and a first diameter of the straight fiber is substantially larger than a second diameter of the crimped fiber.', '2.', 'The method of claim 1, wherein the crimped fiber has a crimping ratio, K1, between 2 and 15.\n\n\n\n\n\n\n3.', 'The method of claim 1, wherein a straight fiber: crimped fiber weight ratio varies between 10:90 and 90:10.', '4.', 'The method of claim 1, wherein the filtercake removal arises from a scrubbing action performed by the at least two fibers.', '5.', 'The method of claim 1, wherein the mud filtercake comprises barite.', '6.', 'The method of claim 1, wherein the carrier fluid consists of water.', '7.', 'The method of claim 1, wherein the salt is a halide salt, and wherein the halide salt is present at a concentration between 0.5 wt % and 35 wt %.', '8.', 'The method of claim 1, wherein the mutual solvent is 2-butoxyethanol.', '9.', 'The method of claim 1, wherein the well cleaning composition further comprises a corrosion inhibitor, and wherein the corrosion inhibitor comprises an organic acid.', '10.', 'The method of claim 1, wherein the at least two fibers are present at a concentration between 0.2 wt % and 2 wt %.', '11.', 'The method of claim 1, wherein the well cleaning composition remains stationary in the well for a period between 0.5 hr and 24 hr.\n\n\n\n\n\n\n12.', 'The method of claim 1, wherein the well cleaning composition is circulated out of the well.\n\n\n\n\n\n\n13.', 'The method of claim 1, wherein the straight fiber and the crimped fiber are both polyester fibers.', '14.', 'The method of claim 13, wherein the straight fiber and the crimped fiber are both polylactic acid fibers.', '15.', 'The method of claim 1, wherein the second diameter of the crimped fiber is about one third of the first diameter of the straight fiber, and wherein the first length of the straight fiber and the second length of the crimped fiber is about 6 mm.\n\n\n\n\n\n\n16.', 'The method of claim 3, wherein the straight fiber: crimped fiber weight ratio is between 25:75 and 75:25.', '17.', 'The method of claim 16, wherein the straight fiber: crimped fiber weight ratio is between 40:60 and 60:40.\n\n\n\n\n\n\n18.', 'The method of claim 17, wherein the straight fiber: crimped fiber weight ratio is about 50:50.\n\n\n\n\n\n\n19.', 'A method for treating a well, comprising:\n(i) drilling a well with a water-base mud, oil-base mud, a synthetic-base mud or an emulsion mud;\n(ii) depositing a mud filtercake on a wellbore wall;\n(iii) preparing a well cleaning composition that comprises a carrier fluid, a salt, a surfactant, a mutual solvent, and at least two fibers selected from the group consisting of natural celluloses, polylactic acid, polyesters, polyvinyl alcohol and polyethylene terephthalate, wherein the at least two fibers have lengths between 1 mm and 20 mm and diameters between 10 μm and 50 μm; and\n(iv) circulating the well cleaning composition in the well, thereby removing the mud filtercake from the wellbore wall;\nwherein a first fiber of the at least two fibers is a straight fiber and a second fiber of the at least two fibers is a crimped fiber, and wherein a first length of the straight fiber is about equal to a second length of the crimped fiber, and a first diameter of the straight fiber is substantially larger than a second diameter of the crimped fiber, wherein the straight fiber and the crimped fiber are both polyester fibers, and wherein the filtercake removal arises from a scrubbing action performed by the at least two fibers.', '20.', 'The method of claim 19, wherein the surfactant is one or more members of the group consisting of long chain alcohols, polyoxyethylene glycol alkyl ethers, polyoxypropylene glycol alkyl ethers, glucoside alkyl ethers, polyoxyethylene glycol octylphenol ethers, polyoxyethylene glycol alkylphenol ethers, glycerol alkyl esters, polyoxyethylene glycol sorbitan alkyl esters, sorbitan alkyl esters, cocamide DEA, cocamide MEA, dodecyldimethylamine oxide, block copolymers of polyethylene glycol or polypropylene glycol, polyethoxylated tallow amine, ammonium lauryl sulfate, sodium lauryl sulfate, sodium laureth sulfate, sodium myreth sulfate, dioctyl sodium sulfosuccinate, perfluorooctane sulfonates, perfluorobutanesulfonates, alkylbenzene sulfonates, alkyl-aryl ether phosphates, alkyl ether phosphates, alkyl carboxylates, sarcosinates, perfluorononanoates, perfluorooctanoates, 3-[(3-Cholamidopropyl)dimethylammonio]-1-propanesulfonate, cocamidopropyl hydroxysultaine, and cocamidopropyl betaine.'] | ['No Captions Available'] |
US11118406 | Drilling systems and methods | Jul 2, 2018 | Mauro Caresta, Fabio Cappi, Hans Seehuus, Kjell Haugvaldstad, Riadh Boualleg, Joachim Sihler, Ashley Bernard Johnson | SCHLUMBERGER TECHNOLOGY CORPORATION | Combined Search and Exam Report under Sections 17 and 18(3) United Kingdom Patent Application No. 1705424.8 dated Jul. 27, 2017, 5 pages.; International Search Report and Written Opinion issued in International Patent Application No. PCT/US2018/025986 dated Jul. 27, 2018, 16 pages.; Office Action issued in U.S. Appl. No. 15/945,158 dated Jan. 18, 2019, 8 pages.; Office Action issued in U.S. Appl. No. 16/025,523 dated Mar. 10, 2020, 11 pages.; International Preliminary Report on Patentability issued in International Patent Application No. PCT/US2018/025986 dated Oct. 17, 2019, 14 pages.; Office Action issued in U.S. Appl. No. 16/025,480 dated Jan. 14, 2020, 8 pages.; Office Action issued in U.S. Appl. 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No. 16/826,976 dated Mar. 3, 2021. | 1635593; July 1927; Wadsworth; 2142859; January 1939; McMahan; 2179567; November 1939; Strength; 2197227; April 1940; Strength; 2212594; August 1940; Evans; 3297100; January 1967; Crews; 4083415; April 11, 1978; Kita; 4106823; August 15, 1978; Bassinger; 4947944; August 14, 1990; Coltman et al.; 4948925; August 14, 1990; Winters et al.; 5601151; February 11, 1997; Warren; 5931239; August 3, 1999; Schuh; 5941323; August 24, 1999; Warren; 8534380; September 17, 2013; Sheppard et al.; 8727036; May 20, 2014; Johnson et al.; 8899352; December 2, 2014; Johnson et al.; 9109402; August 18, 2015; Lasater; 9714543; July 25, 2017; Downie et al.; 20020179336; December 5, 2002; Schaaf et al.; 20060144623; July 6, 2006; Ollerensaw et al.; 20080115974; May 22, 2008; Johnson et al.; 20090044980; February 19, 2009; Sheppard et al.; 20100116551; May 13, 2010; Southard; 20100139983; June 10, 2010; Hallworth et al.; 20110139513; June 16, 2011; Downton; 20120080235; April 5, 2012; Sheppard et al.; 20130213713; August 22, 2013; Smith et al.; 20140262507; September 18, 2014; Marson et al.; 20160060959; March 3, 2016; Lehr et al.; 20160060960; March 3, 2016; Parkin; 20170002608; January 5, 2017; Davis; 20170058617; March 2, 2017; Bartel; 20180283103; October 4, 2018; Caresta; 20200003010; January 2, 2020; Bittleston et al.; 20200003011; January 2, 2020; Sihler et al. | 2015127345; August 2015; WO; 2016187373; November 2016; WO | ['A directional drilling system that includes a drill bit that drills a bore through rock.', 'The drill bit includes an outer portion of a first material and an inner portion coupled to the outer portion.', 'The inner portion includes a second material.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'The present disclosure generally relates to a steering assembly for directionally drilling a borehole in an earth formation.', 'Directional drilling is the intentional deviation of a borehole from the path it would naturally take, which may include the steering of a drill bit so that it travels in a predetermined direction.', 'In many industries, it may be desirable to directionally drill a borehole through an earth formation in order to, for example, circumvent an obstacle and/or to reach a predetermined location in a rock formation.', "In the oil and gas industry, boreholes are drilled into the earth to access natural resources (e.g., oil, natural gas, water) below the earth's surface.", 'These boreholes may be drilled on dry land or in a subsea environment.', 'In order to drill a borehole for a well, a rig is positioned proximate the natural resource.', 'The rig suspends and powers a drill bit coupled to a drill string that drills a bore through one or more layers of sediment and/or rock.', 'After accessing the resource, the drill string and drill bit are withdrawn from the well and production equipment is installed.', 'The natural resource(s) may then flow to the surface and/or be pumped to the surface for shipment and further processing.', 'Directional drilling techniques have been developed to enable drilling of multiple wells from the same surface location with a single rig, and/or to extend wellbores laterally through their desired target formation(s) for improved resource recovery.', 'Each borehole may change direction multiple times at different depths between the surface and the target reservoir by changing the drilling direction.', 'The wells may access the same underground reservoir at different locations and/or different hydrocarbon reservoirs.', 'For example, it may not be economical to access multiple small reservoirs with conventional drilling techniques because setting up and taking down a rig(s) can be time consuming and expensive.', 'However, the ability to drill multiple wells from a single location and/or to drill wells with lateral sections within their target reservoir(s) may reduce cost and environmental impact.', 'SUMMARY\n \nA summary of certain embodiments disclosed herein is set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'The present disclosure relates generally to systems and methods for directionally drilling a borehole, including without limitation those of U.S. patent application Ser.', 'No. 15/945,158, which is hereby incorporated by reference in entirety and for all purposes.', 'In embodiments, a directional drilling system includes a drill bit that drills a bore through rock.', 'The drill bit includes an outer portion of a first material and an inner portion, coupled to the outer portion, that includes a second material.', 'In embodiments, a directional drilling system includes a drill bit, a drive shaft coupled to the drill bit and configured to transfer rotational power from a motor to the drill bit, and a bearing system coupled to the drive shaft, where the bearing system includes an inner bearing that surrounds and axially couples to the drive shaft and an outer bearing that surrounds the inner bearing.', 'In embodiments, a directional drilling system includes a steering system that controls a drilling direction of a drill bit.', 'The steering system includes a sleeve with a channel.', 'A steering pad couples to the sleeve, and axial movement of the steering pad with respect to the drill bit changes the drilling direction by changing a steering angle.', 'The steering pad couples to the sleeve with a coupling feature that enables the steering pad to move axially within the channel.', 'Additional details regarding operations of the drilling systems and methods of the present disclosure are provided below with reference to \nFIGS.', '1-17\n.', 'Various refinements of the features noted above may be made in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may be made individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n schematically illustrates a rig coupled to a plurality of wells for which the drilling systems and methods of the present disclosure can be employed to directionally drill the boreholes;\n \nFIG.', '2\n schematically illustrates an exemplary directional drilling system coupled to a rig according to an embodiment of the present disclosure;\n \nFIG.', '3\n is a cross-sectional view of a directional drilling system with a steering system according to an embodiment of the present disclosure;\n \nFIG.', '4\n is a cross-sectional view of a steering pad coupled to a directional drilling system within line \n4\n-\n4\n of \nFIG.', '3\n according to an embodiment of the present disclosure;\n \nFIG.', '5\n is a cross-sectional view of a steering pad coupled to a directional drilling system within line \n4\n-\n4\n of \nFIG.', '3\n according to an embodiment of the present disclosure;\n \nFIG.', '6\n is a cross-sectional view of a steering pad coupled to a directional drilling system according to an embodiment of the present disclosure;\n \nFIG.', '7\n is a cross-sectional view of a steering pad coupled to a directional drilling system according to an embodiment of the present disclosure;\n \nFIG.', '8\n is a perspective view of a steering pad coupling to a directional drilling system according to an embodiment of the present disclosure;\n \nFIG.', '9\n is a perspective view of a drive shaft of a directional drilling system according to an embodiment of the present disclosure;\n \nFIG.', '10\n is a cross-sectional view of a drill bit according to an embodiment of the present disclosure;\n \nFIG.', '11\n is a cross-sectional view of a directional drilling system according to an embodiment of the present disclosure;\n \nFIG.', '12\n is a perspective view of a drill bit threadingly coupled to a drive shaft according to an embodiment of the present disclosure;\n \nFIG.', '13\n is a perspective view of an inner bearing according to an embodiment of the present disclosure;\n \nFIG.', '14\n is a perspective view of an inner bearing coupled to a drive shaft according to an embodiment of the present disclosure;\n \nFIG.', '15\n is a partial cross-sectional view of a directional drilling system according to an embodiment of the present disclosure;\n \nFIG.', '16\n is a cross-sectional view of a drive shaft according to an embodiment of the present disclosure; and\n \nFIG.', '17\n is a side view of a bearing with lubrication grooves according to an embodiment of the present disclosure.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'The drawing figures are not necessarily to scale.', 'Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.', 'Although one or more embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims.', 'It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results.', 'In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “including” and “having” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.”', 'Any use of any form of the terms “couple,” “connect,” “attach,” “mount,” or any other term describing an interaction between elements is intended to mean either a direct or an indirect interaction between the elements described.', 'Moreover, any use of “top,” “bottom,” “above,” “below,” “upper,” “lower,” “up,” “down,” “vertical,” “horizontal,” “left,” “right,” and variations of these terms is made for convenience but does not require any particular orientation of components.', 'Certain terms are used throughout the description and claims to refer to particular features or components.', 'As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names.', 'This document does not intend to distinguish between components or features that differ in name but not function, unless specifically stated.', 'The discussion below describes drilling systems and methods for controlling the orientation of a drill bit while drilling a borehole.', 'The assemblies of the present disclosure are disposed above the drill bit and may include one or more over-gauge pads, where “over-gauge” refers to the pad having one or more points of extension greater than a nominal full-gauge or “gauge” as defined by a maximum drill bit cutter tip extension in a radial direction.', 'Thus, for example, the radius of an over-gauge pad at a particular point is greater than the full-gauge radius of the drill bit in that radial direction.', 'In embodiments, an over-gauge pad may include full-gauge and/or under-gauge area(s), where under-gauge refers to having one or more points of extension less than gauge as defined by a maximum drill bit cutter tip extension in that radial direction.', 'Over-gauge pads will be referred to as “steering pads” below.', 'FIG.', '1\n schematically illustrates an exemplary drill site \n10\n in which the systems and methods of the present disclosure can be employed.', 'The drill site \n10\n may be located either offshore (as shown) or onshore, near one or multiple hydrocarbon-bearing rock formations or reservoirs \n12\n (e.g., for the production of oil and/or gas), or near one or more other subsurface earth zone(s) of interest.', 'Using directional drilling and the systems and methods presently described, a drilling rig \n14\n with its related equipment can drill multiple subsurface boreholes for wells \n16\n beginning from a single surface location for a vertical bore.', 'Once completed, these wells \n16\n may fluidly connect to the same hydrocarbon reservoir \n12\n at different locations and/or to different reservoirs \n12\n in order to extract oil and/or natural gas.', 'As illustrated, each well \n16\n may define a different trajectory, including for example different degrees and/or lengths of curvature, in order to access and/or maximize surface area for production within the hydrocarbon reservoir(s) \n12\n.', 'The trajectory of a well \n16\n may depend on a variety of factors, including for example the distance between target reservoir(s) \n12\n and the rig \n14\n, horizontal extension of a reservoir for hydrocarbon capture, as well as predicted and/or encountered rock stratigraphy, drilling obstacles, etc. between the surface and the subsurface drilling target(s).', 'There may varying rock formation layers \n18\n between the rig \n14\n and a hydrocarbon reservoir \n12\n, with some of layers \n18\n easily and relatively quickly drilled through, and other layers \n18\n time consuming and subject to increased wear on drilling components.', 'The optimal trajectory to access a hydrocarbon reservoir \n12\n therefore may not be the shortest distance between the rig \n14\n and the hydrocarbon reservoir \n12\n.', 'A drilling plan may be developed to include a trajectory for each proposed well \n16\n that takes into account properties (e.g., thicknesses, composition) of the layers \n18\n.', 'Following the drilling plan, borehole(s) for the well(s) \n16\n may be drilled to avoid certain layers \n18\n and/or drill through thinner portions of difficult layers \n18\n using directional drilling and/or to extend a substantially horizontal section through a reservoir \n12\n.', 'Directional drilling may therefore reduce drill time, reduce wear on drilling components, and fluidly connect the well \n16\n at or along a desired location in the reservoir \n12\n, among other factors.', 'In \nFIG.', '1\n, the rig \n14\n is an offshore drilling rig using directional drilling to drill the wells \n16\n below a body of water.', 'It should be understood that directional drilling may be done with onshore rigs as well.', 'Moreover, while the wells \n16\n may be wells for oil and gas production from hydrocarbon-bearing reservoirs, directional drilling is and can be performed for a variety of purposes and with a variety of targets within and outside of the oil and gas industry, including without limitation in water, geothermal, mineral, and exploratory applications.', 'Additionally, while \nFIG.', '1\n illustrates multiple well \n16\n trajectories extending from one rig \n14\n surface location, the number of wells extending from the same or similar surface location may be one or otherwise may be more or less than shown.\n \nFIG.', '2\n schematically illustrates an exemplary directional drilling system \n30\n coupled to a rig \n14\n.', 'The directional drilling system \n30\n includes at bottom a drill bit \n32\n designed to break up rock and sediments into cuttings.', 'The drill bit \n32\n couples to the rig \n14\n using a drill string \n34\n.', 'The drill string \n34\n is formed with a series of conduits, pipes or tubes that couple together between the rig \n14\n and the drill bit \n32\n.', 'In order to carry the cuttings away from the drill bit \n32\n during a drilling operation, drilling fluid, also referred to as drilling mud or mud, is pumped from surface through the drill string \n34\n and exits the drill bit \n32\n.', 'The drilling mud then carries the cuttings away from the drill bit \n32\n and toward the surface through an annulus \n35\n between an inner wall of the borehole \n37\n formed by the drill bit \n32\n and an outer wall of the drill string \n34\n.', 'By removing the cuttings from the borehole \n37\n for a well \n16\n, the drill bit \n32\n is able to progressively drill further into the earth.', 'In addition to carrying away the cuttings, the drilling mud may also power a hydraulic motor \n36\n also referred to as a mud motor.', 'Drilling mud is pumped into the borehole \n37\n at high pressures in order to carry the cuttings away from the drill bit \n32\n, which may be at a significant lateral distance and/or vertical depth from the rig \n14\n.', 'As the mud flows through the drill string \n34\n, it enters a hydraulic motor \n36\n.', 'The flow of mud through the hydraulic motor \n36\n drives rotation of the hydraulic motor \n36\n, which in turn rotates a shaft coupled to the drill bit \n32\n.', 'As the shaft rotates, the drill bit \n32\n rotates, enabling the drill bit \n32\n to cut through rock and sediment.', 'In some embodiments, the hydraulic motor \n36\n may be replaced with an electric motor that provides power to rotate the drill bit \n32\n.', 'In still other embodiments, the directional drilling system \n30\n may not include a hydraulic motor or electric motor on the drill string \n34\n.', 'Instead, the drill bit \n32\n may rotate in response to rotation of the drill string \n34\n from at or near the rig \n14\n, for example by a top drive \n38\n on the rig \n14\n, or a kelly drive and rotary table, or by any other device or method that provides torque to and rotates the drill string \n34\n.', 'In order to control a drilling direction \n39\n of the drill bit \n32\n, the directional drilling system \n30\n may include a steering system \n40\n of the present disclosure.', 'As will be discussed in detail below, the steering system \n40\n includes a steering sleeve with one or more steering pads that can change and control the drilling direction \n39\n of the drill bit \n32\n.', 'The steering system \n40\n may be controlled by an operator and/or autonomously using feedback from a measurement-while-drilling system \n42\n.', 'The measurement-while-drilling system \n42\n uses one or more sensors to determine the well path or borehole drilling trajectory in three-dimensional space.', 'The sensors in the measurement-while-drilling system \n42\n may provide measurements in real-time and/or may include accelerometers, gyroscopes, magnetometers, position sensors, flow rate sensors, temperature sensors, pressure sensors, vibration sensors, torque sensors, and/or the like, or any combination of them.\n \nFIG.', '3\n is a cross-sectional view of an embodiment of a directional drilling system \n30\n with a steering system \n40\n of the present disclosure.', 'As explained above with reference to \nFIG.', '2\n, the directional drilling system \n30\n includes at bottom a drill bit \n32\n capable of cutting through rock and/or sediment to drill a borehole for a well \n16\n.', 'The drill bit \n32\n may be powered by a motor (e.g., hydraulic or mud motor, electric motor) that in operation transfers torque to the drill bit \n32\n through a drive shaft \n60\n.', 'The drill bit \n32\n may couple to the drive shaft \n60\n with one or more bolts \n62\n enabling power transfer from the motor.', 'As the drive shaft \n60\n rotates, torque drives rotation of the drill bit \n32\n, enabling cutters or teeth \n64\n (e.g., polycrystalline diamond teeth) to grind into the rock face \n66\n.', 'As the teeth \n64\n grind against the rock face \n66\n, the rock face \n66\n breaks into pieces called cuttings.', 'The cuttings are then carried away from the rock face \n66\n with drilling mud \n68\n.', 'The drilling mud \n68\n flows through a conduit or passageway \n70\n in the drive shaft \n60\n and through openings, nozzles or apertures \n72\n in the drill bit \n32\n, carrying cuttings around the drill bit \n32\n and back through the recently drilled bore.', 'In order to steer the directional drilling system \n30\n and more specifically control the orientation of the drill bit \n32\n, the directional drilling system \n30\n of the present disclosure includes the steering system \n40\n.', 'The steering system \n40\n in \nFIG.', '3\n includes one or more steering pads \n74\n (e.g., one, two, three, four, five, six or more steering pads).', 'The steering pad \n74\n forms a steering angle \n80\n between the drill bit \n32\n (e.g., outermost surface of a cutter \n64\n of the drill bit \n32\n) and an edge \n82\n of the steering pad \n74\n.', 'For example, the angle \n80\n may be formed between the outermost cutters \n64\n and the edge \n82\n of the steering pad \n74\n.', 'As illustrated, the steering pad \n74\n extends a radial distance \n84\n beyond the outermost radial surface as defined by the outermost cutter extension in the radial direction of the drill bit \n32\n, which places the steering pad(s) \n74\n into contact with the rock face \n66\n surrounding the bore.', 'In other words, the steering pad \n74\n is over-gauge, and the radial distance \n84\n is an over-gauge radial distance.', 'For example, the over-gauge radial distance \n84\n may be in a range between about 0.1 to 20 mm, 0.1 to 10 mm, and/or 0.1 to 5 mm.', 'In embodiments, the steering sleeve also may include an under-gauge section opposite the over-gauge section, as described in U.S. patent application Ser.', 'No. 15/945,158, incorporated by reference herein in entirety for all purposes.', 'As illustrated, the steering pad(s) \n74\n may couple to a bearing system \n108\n that enables the drive shaft \n60\n to rotate while blocking rotation of the steering pads \n74\n.', 'The bearing system \n108\n includes an inner bearing \n110\n and an outer bearing \n112\n (e.g., a sleeve).', 'The inner bearing \n110\n couples to and rotates with the drive shaft \n60\n, while the outer bearing \n112\n couples to a housing \n114\n (e.g., a mud motor housing or motor collar) and also to the steering pad(s) \n74\n.', 'In the circumferential position shown in \nFIG.', '3\n, the steering pad \n74\n drives the drilling direction of the drill bit \n32\n from an axial direction \n39\n toward a lateral direction \n116\n.', 'However, after drilling to a particular depth, and/or according to a drill plan or encountered obstacle or the like, it may be desirable to adjust the drilling direction of the drill bit \n32\n to a different direction, e.g. from the lateral direction \n116\n toward the axial direction \n39\n.', 'In order to adjust the drilling direction from 116 to 39 (e.g. axial direction relative to the drive shaft \n60\n from a substantially lateral direction), the steering pad(s) \n74\n are rotated about the drive shaft \n60\n from the first circumferential position to a second circumferential position.', 'As the outer bearing \n112\n is coupled to both the motor housing \n114\n and the steering pad \n74\n, the motor housing \n114\n may be rotated in order to rotate the outer bearing \n112\n and thus the steering pad \n74\n.', 'The motor housing \n114\n may be rotated through rotation of the drill string \n34\n using a top drive \n38\n on the rig \n14\n (as schematically shown in \nFIG.', '2\n), by kelly and rotary table, or by any other device or method that provides torque to and rotates the drill string \n34\n.', 'Once the steering pad \n74\n is repositioned to the second circumferential position, the steering pad \n74\n drives the drill bit \n32\n to the adjusted drilling direction \n39\n.\n \nFIG.', '4\n is a cross-sectional view of an embodiment of a steering pad \n74\n coupled to an outer bearing \n112\n or sleeve of a directional drilling system \n30\n, within line \n4\n-\n4\n′ of \nFIG.', '3\n.', 'The steering pad \n74\n includes a body \n140\n made out of a first material (e.g., carbides, including without limitation tungsten or other transition metal carbides).', 'The body \n140\n defines a curvilinear surface \n142\n configured to engage the rock face \n66\n described above.', 'The body \n140\n may also include a plurality of counterbores \n144\n in the curvilinear surface \n142\n.', 'Although they are shown to be parallel, the counterbores \n144\n may be in other orientations, including without limitation perpendicular to the surface steering pad \n74\n, aligned radially from the center of the tool, and/or spaced evenly or unevenly in either or both of the radial and axial directions relative to the drive shaft \n60\n.', 'The counterbores \n144\n enable the steering pad \n74\n to receive a plurality of inserts \n146\n.', 'The inserts \n146\n may include diamond inserts, boron nitride inserts, carbide inserts (e.g., tungsten or other transition metal carbide inserts), or a combination thereof.', 'The inserts could be conventional polycrystalline diamond cutters (PDC or PCD cutters).', 'These inserts \n146\n provide abrasion resistance as the steering pad \n74\n engages the rock face \n66\n.', 'A coupling feature \n148\n enables the steering pad \n74\n to couple to the outer bearing \n112\n or sleeve surrounding the drive shaft \n60\n (described above).', 'In some embodiments, the coupling feature \n148\n may also enable the steering pad \n74\n to move axially or circumferentially with respect to the drill bit \n32\n.', 'Once coupled with the steering pad \n74\n, the outer bearing \n112\n blocks removal of the steering pad \n74\n from the directional drilling system \n30\n in a radial direction \n156\n with respect to a longitudinal axis of the directional drilling system \n30\n.', 'In \nFIG.', '4\n, the coupling feature \n148\n includes a protrusion \n150\n that extends from a surface \n152\n of the steering pad \n74\n and engages a recess \n154\n in a surface \n155\n of the outer bearing \n112\n.', 'As illustrated, the protrusion \n150\n defines a dovetail shape that engages a dovetail-shaped recess \n154\n, however, the protrusion \n150\n and recess \n154\n of the coupling feature \n148\n may be or include any corresponding shapes or forms.', 'In some embodiments, the steering pad \n74\n may define a recess that is configured to receive a protrusion on the outer bearing \n112\n.', 'While \nFIG.', '4\n illustrates a single protrusion \n150\n and a single recess \n154\n, in some embodiments the coupling feature \n148\n may include multiple protrusions \n150\n configured to engage multiple respective recesses \n154\n.', 'In embodiments, there may be at least one protrusion \n150\n on both the steering pad \n74\n and on the outer bearing \n112\n that engage respective recesses \n154\n on the outer bearing \n112\n and on the steering pad \n74\n.\n \nFIG.', '5\n is a cross-sectional view of an embodiment of a steering pad \n74\n coupled to an outer bearing \n112\n or sleeve of a directional drilling system \n30\n, within line \n4\n-\n4\n′ of \nFIG.', '3\n.', 'In some embodiments, the body \n140\n of the steering pad \n74\n may form a coupling feature \n170\n.', 'As illustrated, a section \n172\n of the body \n140\n of steering pad \n74\n defines a dovetail shape that engages a corresponding recess \n174\n on the outer bearing \n112\n (e.g., sleeve).', 'Once coupled with the steering pad \n74\n, the outer bearing \n112\n blocks removal of the steering pad \n74\n from the directional drilling system \n30\n in a radial direction \n176\n with respect to a longitudinal axis of the directional drilling system \n30\n.', 'In some embodiments, the steering pad \n74\n may define a recess (e.g., like recess \n174\n) that receives a protrusion (e.g., like section \n172\n) on the outer bearing \n112\n. \nFIG.', '6\n is a cross-sectional view of an embodiment of a steering pad \n74\n coupled to an outer bearing \n112\n or sleeve of a directional drilling system \n30\n.', 'As illustrated, a portion \n190\n of the steering pad \n74\n sits within a cavity \n192\n.', 'To facilitate insertion and retention, the steering pad \n74\n defines a curved end portion \n194\n (e.g., retention feature).', 'During installation, the curved end portion \n194\n is inserted into a corresponding curved section \n196\n of the cavity \n192\n.', 'The steering pad \n74\n may then be rotated in direction \n198\n until the rest of the steering pad \n74\n rests within the cavity \n192\n.', 'In order to block removal of the steering pad \n74\n from the cavity \n192\n, the steering pad \n74\n may be welded or brazed about an exposed portion \n200\n of the steering pad \n74\n.', 'In some embodiments, one or more fasteners (e.g., threaded fasteners) may secure the steering pad \n74\n within the cavity \n192\n.\n \nFIG.', '7\n is a cross-sectional view of an embodiment of a steering pad \n74\n coupled to an outer bearing \n112\n or sleeve of a directional drilling system \n30\n.', 'As illustrated, the steering pad \n74\n (e.g., circular steering pad) may be threadingly coupled to the directional drilling system \n30\n.', 'For example, the steering pad \n74\n may include threads \n210\n that engage threads \n212\n about a cavity \n214\n.', 'To block removal of the steering pad \n74\n from the cavity \n214\n, the steering pad \n74\n may be welded or brazed \n216\n about an exposed portion \n218\n of the steering pad \n74\n.', 'In some embodiments, one or more fasteners (e.g., threaded fasteners) may also be used to secure the steering pad \n74\n within the cavity \n214\n.\n \nFIG.', '8\n is a perspective view of an embodiment of a steering pad \n74\n coupling to an outer bearing \n112\n or sleeve of a directional drilling system \n30\n.', 'The steering pad \n74\n includes a body \n220\n made out of a first material (e.g., carbides, including without limitation tungsten or other transition metal carbides).', 'The body \n220\n defines a curvilinear surface \n222\n configured to engage the rock face \n66\n described above.', 'The body \n220\n may also include a plurality of counterbores \n224\n in the curvilinear surface \n222\n.', 'The counterbores \n224\n enable the steering pad \n74\n to receive a plurality of inserts \n226\n.', 'The inserts \n226\n may include diamond inserts, boron nitride inserts, carbide inserts (e.g., tungsten or other transition metal carbide inserts), or a combination thereof.', 'The inserts may be conventional polycrystalline diamond cutters (PDC or PCD cutters).', 'These inserts \n226\n provide abrasion resistance as the steering pad \n74\n engages the rock face \n66\n.', 'As illustrated, the steering pad \n74\n includes one or more flanges \n228\n.', 'The flange(s) \n228\n are configured to slide beneath protrusions \n230\n in a recess \n229\n on the outer bearing \n112\n or sleeve as the steering pad \n74\n slides axially in direction \n232\n.', 'Once coupled the protrusions \n230\n block removal of the steering pad \n74\n in a radial direction \n234\n with respect to a longitudinal axis of the directional drilling system \n30\n.', 'In some embodiments, the steering pad \n74\n may define recesses instead of flanges that are configured to engage the protrusions \n230\n to block movement of the steering pad \n74\n in radial direction \n234\n.', 'In some embodiments, the steering pad may be held geostationary (non-rotationary with respect to the borehole/earth) and/or substantially geostationary.', 'In order to block removal of the steering pad \n74\n in axial direction \n236\n from the cavity \n229\n the steering pad \n74\n may include one or more apertures \n238\n.', 'The apertures \n238\n may receive threaded fasteners \n240\n (e.g., bolts or the like) that engage the outer bearing \n112\n or sleeve to block axial movement of the steering pad \n74\n in axial direction \n236\n.', 'In some embodiments, additional fasteners \n242\n may pass through walls \n244\n of the outer bearing \n112\n or sleeve that defines the recess \n229\n.', 'These fasteners \n242\n may engage apertures and/or may rest within notches \n246\n on the steering pad \n74\n to block axial movement of the steering pad \n74\n in axial direction \n236\n.', 'In some embodiments, one or more shims \n248\n may be inserted into the recess \n229\n to lift the steering pad \n74\n in radial direction \n234\n.', 'For example, a shim \n248\n may be used to ensure that the curvilinear surface \n222\n extends a desired distance from the exterior surface of the outer bearing \n112\n or sleeve.', 'In some embodiments, the shims \n248\n may also include apertures \n250\n, which may be configured to receive the threaded fasteners \n240\n to block axial removal or shifting of the shims \n248\n during drilling operations.', 'In some embodiments, the inner bearing \n110\n may include one or more (e.g., one, two, three or more) protrusions \n252\n that extend radially outward from an exterior surface \n254\n.', 'The protrusions \n252\n are configured to engage respective recesses or notches \n256\n on an interior surface \n258\n of the outer bearing or sleeve \n112\n.', 'During operation of the directional drilling system \n30\n, the protrusions \n252\n are configured to block or reduce relative motion between the inner bearing \n110\n and the outer bearing \n112\n.', 'FIG.', '9\n is a perspective view of an embodiment of a drive shaft \n60\n of the directional drilling system \n30\n.', 'The drive shaft \n60\n defines a first end \n270\n and a second end \n272\n opposite the first end \n270\n.', 'The first end \n270\n is configured to couple to a drill motor (e.g., hydraulic motor or mud motor, electric motor), while the second end \n272\n is configured to couple to the drill bit \n32\n.', 'In order to couple to the drill bit \n32\n, the second end \n272\n includes an exterior surface \n273\n that defines a plurality of protrusions \n274\n separated by recesses \n276\n.', 'In some embodiments, this pattern may be a cloverleaf pattern.', 'Once coupled to the drill bit \n32\n, the plurality of protrusions \n274\n may engage recesses in the drill bit \n32\n, enabling torque transfer from the drive shaft \n60\n to the drill bit \n32\n.', 'In some embodiments, the end face \n278\n may define one or more apertures \n280\n that enable the drill bit \n32\n to be coupled to (e.g., bolted onto) the drive shaft \n60\n.', 'In some embodiments, there is a minimum defined radius in the surface transitions between the protrusions (e.g., 1 mm, 5 mm, 10 mm, 15 mm, or 20 mm) to minimize stress concentrations in the surface.', 'In other embodiments, the surface may be continuously curved, minimizing any section of constant radius from the center of the shaft (e.g., to less than 30, 20, or 10 degrees).', 'FIG.', '10\n is a perspective rear view of an embodiment of a drill bit \n32\n.', 'As illustrated, the drill bit \n32\n includes an exterior portion or body \n300\n and an interior portion or body \n302\n.', 'The exterior portion \n300\n and the interior portion \n302\n may be formed from the same or different materials.', 'Because the interior portion \n302\n does not contact the rock face \n66\n while drilling, the interior portion \n302\n may be made from a different material.', 'For example, the exterior portion \n300\n may be formed from carbide (e.g., tungsten or other transition metal carbide) and may include teeth or cutters \n304\n (e.g., diamond) embedded in the carbide, while the interior portion \n302\n may be formed from steel (e.g., steel alloy).', 'Moreover, because the interior portion \n302\n couples the drill bit \n32\n to the drive shaft \n60\n, the interior portion \n302\n may be made out of a material capable of manufacturing with tighter tolerances (e.g., steel, steel alloy).', 'As illustrated, the interior portion \n302\n may be a ring \n306\n with an interior surface \n308\n defining a plurality of protrusions \n310\n separated by recesses \n312\n.', 'The interior portion \n302\n rests within a cavity \n314\n of the drill bit \n32\n and may couple to the drill bit \n32\n, for example, with a press fit, brazing, welding, gluing, and/or fasteners.', 'The shape of the interior portion \n302\n exposes a plurality of apertures \n315\n in the exterior portion \n300\n.', 'As will be explained below, these apertures \n315\n enable drilling mud to flow through the drill bit \n32\n or to enable the drill bit \n32\n to couple to the drive shaft \n60\n with fasteners.', 'In some embodiments, the exterior portion \n300\n and interior portion \n302\n may be formed from the same material.', 'In some embodiments, the exterior portion \n300\n and interior portion \n302\n may be one piece and/or integrally formed.', 'As illustrated, the drill bit \n32\n includes a plurality of blades \n316\n with multiple teeth or cutters \n304\n.', 'The teeth or cutters \n304\n facilitate the breaking of rock and/or sediment into cuttings as the drill bit \n32\n rotates.', 'In some embodiments, each blade \n316\n may include an end tooth or cutter \n318\n at the same axial position as the end tooth or cutters \n318\n of the other blades \n316\n proximate to an end of the drill bit \n32\n.', 'The end teeth or cutters \n318\n may form the angle \n80\n between the steering pad \n74\n and the drill bit \n32\n that enables the steering pad \n74\n to change the drilling direction \n39\n, \n116\n to any other direction.', 'By including an end tooth or cutter \n318\n for each of the blades \n316\n, the drill bit \n32\n may also provide redundancy in the event that one of the other end teeth or cutters \n318\n separates from the drill bit \n32\n during operation.\n \nFIG.', '11\n is a cross-sectional side view of an embodiment of a directional drilling system \n30\n with the drive shaft \n60\n coupled to the drill bit \n32\n.', 'As explained above with reference to \nFIG.', '9\n, the second end \n272\n of the drive shaft \n60\n includes an exterior surface \n273\n with a plurality of protrusions \n274\n separated by recesses \n276\n.', 'As explained above with reference to \nFIG.', '10\n, this exterior surface \n273\n of the drive shaft \n60\n matches the protrusions \n310\n and recesses \n312\n on the interior surface \n308\n of the interior portion \n302\n (ring \n306\n) of the drill bit \n32\n.', 'The drive shaft \n60\n may therefore slide into and couple to the drill bit \n32\n by aligning the protrusions \n274\n on the drive shaft \n60\n with the recesses \n312\n on the ring \n306\n, and the protrusions \n310\n on the ring \n306\n with the recesses \n276\n on the drive shaft \n60\n.', 'Once coupled, the drive shaft \n60\n is configured to transfer torque from the drive shaft \n60\n to the drill bit \n32\n.', 'Returning now to \nFIG.', '11\n, to reduce or block axial movement of the drive shaft \n60\n with respect to the drill bit \n32\n, one or more fasteners \n330\n couple the drill bit \n32\n to the drive shaft \n60\n.', 'For example, the fasteners \n330\n may extend through apertures \n332\n and into apertures \n280\n in the end face \n278\n of the drive shaft \n60\n.', 'In some embodiments, the drive shaft \n60\n may define an annular groove \n334\n in the end face \n278\n that receives an annular seal \n336\n.', 'In operation, the annular seal \n336\n forms a seal with the drill bit \n32\n to focus the flow of drilling mud through apertures \n338\n.\n \nFIG.', '12\n is a perspective view of an embodiment of a drill bit \n32\n threadingly coupled to a drive shaft \n358\n.', 'As illustrated, the drill bit \n32\n may define a counterbore \n360\n with a surface \n362\n.', 'In order to couple to the drive shaft \n358\n, the surface \n362\n of the drill bit \n32\n may include threads \n364\n that engage threads \n366\n on the drive shaft \n358\n.', 'In some embodiments, the drive shaft \n358\n may include one or more (e.g., one, two, three, four, five, or more) protrusions \n368\n.', 'For example, a protrusion \n368\n may be an annular protrusion that extends about the circumference of the drive shaft \n358\n.', 'In operation, the protrusion(s) \n368\n enable an increase in torque when coupling the drill bit \n32\n to the drive shaft \n358\n.', 'The drive shaft \n358\n may also include threads \n370\n that enable the drive shaft \n358\n to threadingly couple to threads \n372\n on the inner bearing \n110\n.', 'The protrusion(s) \n368\n may also enable an increase in torque when coupling the inner bearing \n110\n to the drive shaft \n358\n.\n \nFIG.', '13\n is a perspective view of an embodiment of an inner bearing \n390\n.', 'The inner bearing \n390\n may or may not include threads for coupling to the drive shaft \n60\n described above.', 'However, to block relative motion between the inner bearing \n390\n and the drive shaft \n60\n, the inner bearing \n390\n may include one or more protrusions or tabs \n392\n spaced evenly (as shown) or unevenly about an end face \n394\n of the inner bearing \n390\n.', 'In operation, these protrusions \n392\n are configured to axially engage the drive shaft \n60\n to block rotation of the inner bearing \n390\n relative to the drive shaft \n60\n.', 'FIG.', '14\n is a perspective view of an embodiment of an inner bearing \n390\n coupled to the drive shaft \n60\n of \nFIG.', '9\n.', 'As explained above, the second end \n272\n of the drive shaft \n60\n is configured to couple to the drill bit \n32\n.', 'In order to couple to the drill bit \n32\n, the second end \n272\n includes an exterior surface \n273\n that defines a plurality of protrusions \n274\n separated by recesses \n276\n.', 'These protrusions \n274\n and recesses \n276\n enable the drive shaft \n60\n to couple to and transfer torque to the drill bit \n32\n.', 'The protrusions \n274\n and recesses \n276\n may also axially receive the protrusions \n392\n on the inner bearing \n390\n to block relative motion of the inner bearing \n390\n with respect to the drive shaft \n60\n.\n \nFIG.', '15\n is a partial cross-sectional view of an embodiment of the directional drilling system \n30\n.', 'During operation of the directional drilling system \n30\n, an axial force is transferred through the drill string to the drill bit \n32\n.', 'This axial force compresses the drill bit \n32\n against the rock face.', 'Accordingly, as the drill bit \n32\n rotates, the drill bit \n32\n is able to grind against and break up rock.', 'This axial force may be transferred at least partially through the inner bearing \n110\n to the drive shaft \n60\n.', 'By including a shoulder \n410\n (e.g., an annular shoulder) with a width \n412\n that is equal to or at least 50% of the width \n416\n of the inner bearing \n110\n, the contact area between the end face \n414\n of the inner bearing \n110\n and the shoulder \n410\n increases.', 'An increase in the contact area enables an increase in the force applied to the drill bit \n32\n through the drive shaft \n60\n.\n \nFIG.', '16\n is a cross-sectional view of an embodiment of a drive shaft \n428\n.', 'In \nFIG.', '16\n the drive shaft \n428\n includes a plurality of shoulders \n430\n (e.g., annular shoulders) and a plurality of recesses \n432\n (e.g., annular recesses).', 'The shoulders \n430\n provide a plurality of loading points for coupling to and absorbing axial force transmitted through an inner bearing (e.g., inner bearing \n110\n).', 'More specifically, the plurality of shoulders \n430\n and plurality of recesses \n432\n increase the available contact area between an inner bearing and the drive shaft \n428\n, enabling the drive shaft \n428\n to absorb more axial force.', 'In some embodiments, the shoulders \n430\n may progressively increase in thickness and height along the axis \n434\n toward an end \n436\n of the drive shaft \n428\n.', 'The recesses \n432\n between the shoulders \n430\n may also increase in both width along the axis \n434\n towards the end \n436\n as well as increase in depth in radial direction \n438\n.\n \nFIG.', '17\n is a side view of an embodiment of a bearing system \n450\n for use in the directional drilling system \n30\n.', 'As illustrated, the bearing system \n450\n includes lubrication grooves or channels \n452\n in an outer bearing \n454\n and in an inner bearing \n456\n.', 'During operation, the bearing system \n450\n may be lubricated with drilling fluid (e.g., drilling mud \n68\n) that is pumped through a drill string.', 'To facilitate lubrication, the inner bearing \n456\n and/or outer bearing \n454\n of the bearing system \n450\n may include lubricating grooves \n452\n that increase flow and/or distribution of the drilling fluid between them.', 'The lubricating grooves \n452\n may wrap around the inner and outer bearings \n456\n, \n454\n in a spiral pattern.', 'For example, if the lubricating grooves \n452\n are on the inner bearing \n456\n, the lubricating grooves \n452\n may wrap around an exterior surface of the inner bearing \n456\n.', 'Likewise, if the lubricating grooves \n452\n are on an outer bearing \n454\n, the lubricating grooves \n452\n may extend along an interior surface of the outer bearing \n454\n.', 'In some embodiments, both the outer and inner bearings \n454\n, \n456\n may include one or more lubricating grooves \n452\n (e.g., spiral grooves) that facilitate the flow and distribution of the drilling fluid in the bearing system \n450\n.', 'In addition, the lubricating grooves \n452\n may be sized to enable any solid particles carried in the drilling fluid (e.g., drilling mud \n68\n) to pass through the bearing system \n450\n.', 'Considering the particles must pass through other flow restrictions in the drilling motor to get to this point, the minimum dimension of a lubricating groove \n452\n should be larger (e.g., 1.2, 1.5, 2, 3 or more times larger) than the minimum flow restriction further up the motor, e.g. an upper radial bearing in the motor.', 'The embodiments discussed above are susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.'] | ['1.', 'A directional drilling system, comprising:\na drill bit configured to drill a bore through rock, wherein the drill bit comprises: an outer portion comprising a first material; and an inner portion coupled to the outer portion, wherein the inner portion comprises a second material, and wherein the first material and the second material are different; wherein the inner portion is a ring, and wherein an inner surface of the ring comprises a first plurality of protrusions that extend circumferentially about the inner surface;\na drive shaft configured to transfer torque from a motor to the drill bit, wherein the drive shaft comprises a second plurality of protrusions that extend circumferentially about the drive shaft, and wherein the first plurality of protrusions are configured to interlock with the second plurality of protrusions, wherein the drive shaft includes a drive shaft aperture in an end face of the drive shaft, wherein the outer portion of the drill bit couples to the drive shaft with at least one fastener inserted through the drive shaft aperture in the end face of the drive shaft, wherein the at least one fastener is inserted into a respective drill bit aperture in the body of the drill bit and the drive shaft aperture in the end face of the drive shaft; and\na steering system configured to control a drilling direction of the drill bit, wherein the steering system comprises: a sleeve coupled to the drive shaft; and a steering pad coupled to the sleeve, wherein the steering pad is configured to form a steering angle with the drill bit.', '2.', 'The directional drilling system of claim 1, wherein the first material comprises carbide.', '3.', 'The directional drilling system of claim 1, wherein the second material comprises steel.', '4.', 'The directional drilling system of claim 1, wherein the first plurality of protrusions define a cloverleaf pattern.', '5.', 'The directional drilling system of claim 1, comprising:\nan annular seal configured to rest within an annular groove in an end face of the drive shaft, wherein the annular seal is configured to seal against the outer portion of the drill bit.', '6.', 'The directional drilling system of claim 1, wherein the outer portion comprises a plurality of teeth.', '7.', 'The directional drilling system of claim 1, wherein the first plurality of protrusions and the second plurality of protrusions have a minimum defined radius in surface transitions between protrusions of 20 mm.\n\n\n\n\n\n\n8.', 'The directional drilling system of claim 1, wherein a surface of the first plurality of protrusions and the second plurality of protrusions is continuously curved, minimizing any section of constant radius from to center of the shaft to less than 30 degrees.', '9.', 'The directional drilling system of claim 1, wherein the inner portion does not contact a rock face while drilling.', '10.', 'A directional drilling system, comprising:\na drill bit configured to drill a bore through rock;\na drive shaft coupled to the drill bit, wherein the drive shaft is configured to transfer rotational power from a motor to the drill bit using a first plurality of protrusions that extend radially from and circumferentially about the drive shaft;\na bearing system coupled to the drive shaft, wherein the bearing system comprises: an inner bearing configured to surround and axially couple to the drive shaft wherein the inner bearing comprises a second plurality of protrusions that extend from an end face of the inner bearing, and wherein the second plurality of protrusions are configured to interlock with the first plurality of protrusions to axially couple the inner bearing to the drive shaft; and an outer bearing surrounding the inner bearing; and\na steering system configured to control a drilling direction of the drill bit, wherein the steering system comprises a steering pad coupled to the outer bearing, wherein the steering pad is configured to form a steering angle with the drill bit.', '11.', 'The directional drilling system of claim 10, wherein the inner bearing comprises a lubrication groove on an exterior surface of the inner bearing, and wherein the lubrication groove is configured to carry a drilling fluid between the inner bearing and the outer bearing.', '12.', 'The directional drilling system of claim 11, wherein the lubrication groove spirals around the inner bearing from a first end of the inner bearing to a second end of the inner bearing.', '13.', 'The directional drilling system of claim 10, wherein the outer bearing comprises a lubrication groove on an interior surface of the outer bearing, and wherein the lubrication groove is configured to carry a drilling fluid between the inner bearing and the outer bearing.', '14.', 'The directional drilling system of claim 13, wherein the lubrication groove spirals from a first end of the outer bearing to a second end of the outer bearing.', '15.', 'The directional drilling system of claim 10, wherein the drill bit is configured to connect to the drive shaft with the first plurality of protrusions.', '16.', 'The directional drilling system of claim 15, wherein the drive shaft includes an aperture in an end face of the drive shaft and the drill bit is coupled to the drive shaft with a fastener inserted into the aperture.', '17.', 'A directional drilling system, comprising:\na steering system configured to control a drilling direction of a drill bit, wherein the steering system comprises: a sleeve comprising a recess; a steering pad coupled to the recess of the sleeve, wherein rotation of the steering pad with respect to the drill bit is configured to change the drilling direction, and wherein the steering pad is configured to couple to the sleeve with a coupling feature configured to allow axial movement of the steering pad relative to the drill bit and the sleeve during installation to change a steering angle of the drill bit, and wherein the steering pad comprises one or more apertures through an outer radial surface; and one or more fasteners coupled to the steering pad and the sleeve, wherein the one or more fasteners is configured to extend through the one or more apertures to block removal of the steering pad in an axial direction.', '18.', 'The directional drilling system of claim 17, wherein the coupling feature comprises a dovetail protrusion configured to engage the recess of the sleeve.'] | ['FIG.', '1 schematically illustrates a rig coupled to a plurality of wells for which the drilling systems and methods of the present disclosure can be employed to directionally drill the boreholes;; FIG.', '2 schematically illustrates an exemplary directional drilling system coupled to a rig according to an embodiment of the present disclosure;; FIG. 3 is a cross-sectional view of a directional drilling system with a steering system according to an embodiment of the present disclosure;; FIG.', '4 is a cross-sectional view of a steering pad coupled to a directional drilling system within line 4-4 of FIG.', '3 according to an embodiment of the present disclosure;; FIG. 5 is a cross-sectional view of a steering pad coupled to a directional drilling system within line 4-4 of FIG.', '3 according to an embodiment of the present disclosure;; FIG. 6 is a cross-sectional view of a steering pad coupled to a directional drilling system according to an embodiment of the present disclosure;; FIG. 7 is a cross-sectional view of a steering pad coupled to a directional drilling system according to an embodiment of the present disclosure;; FIG. 8 is a perspective view of a steering pad coupling to a directional drilling system according to an embodiment of the present disclosure;; FIG.', '9 is a perspective view of a drive shaft of a directional drilling system according to an embodiment of the present disclosure;; FIG.', '10 is a cross-sectional view of a drill bit according to an embodiment of the present disclosure;; FIG.', '11 is a cross-sectional view of a directional drilling system according to an embodiment of the present disclosure;; FIG.', '12 is a perspective view of a drill bit threadingly coupled to a drive shaft according to an embodiment of the present disclosure;; FIG.', '13 is a perspective view of an inner bearing according to an embodiment of the present disclosure;; FIG.', '14 is a perspective view of an inner bearing coupled to a drive shaft according to an embodiment of the present disclosure;; FIG.', '15 is a partial cross-sectional view of a directional drilling system according to an embodiment of the present disclosure;; FIG.', '16 is a cross-sectional view of a drive shaft according to an embodiment of the present disclosure; and; FIG.', '17 is a side view of a bearing with lubrication grooves according to an embodiment of the present disclosure.; FIG.', '1 schematically illustrates an exemplary drill site 10 in which the systems and methods of the present disclosure can be employed.', 'The drill site 10 may be located either offshore (as shown) or onshore, near one or multiple hydrocarbon-bearing rock formations or reservoirs 12 (e.g., for the production of oil and/or gas), or near one or more other subsurface earth zone(s) of interest.', 'Using directional drilling and the systems and methods presently described, a drilling rig 14 with its related equipment can drill multiple subsurface boreholes for wells 16 beginning from a single surface location for a vertical bore.', 'Once completed, these wells 16 may fluidly connect to the same hydrocarbon reservoir 12 at different locations and/or to different reservoirs 12 in order to extract oil and/or natural gas.; FIG.', '2 schematically illustrates an exemplary directional drilling system 30 coupled to a rig 14.', 'The directional drilling system 30 includes at bottom a drill bit 32 designed to break up rock and sediments into cuttings.', 'The drill bit 32 couples to the rig 14 using a drill string 34.', 'The drill string 34 is formed with a series of conduits, pipes or tubes that couple together between the rig 14 and the drill bit 32.', 'In order to carry the cuttings away from the drill bit 32 during a drilling operation, drilling fluid, also referred to as drilling mud or mud, is pumped from surface through the drill string 34 and exits the drill bit 32.', 'The drilling mud then carries the cuttings away from the drill bit 32 and toward the surface through an annulus 35 between an inner wall of the borehole 37 formed by the drill bit 32 and an outer wall of the drill string 34.', 'By removing the cuttings from the borehole 37 for a well 16, the drill bit 32 is able to progressively drill further into the earth.; FIG.', '3 is a cross-sectional view of an embodiment of a directional drilling system 30 with a steering system 40 of the present disclosure.', 'As explained above with reference to FIG.', '2, the directional drilling system 30 includes at bottom a drill bit 32 capable of cutting through rock and/or sediment to drill a borehole for a well 16.', 'The drill bit 32 may be powered by a motor (e.g., hydraulic or mud motor, electric motor) that in operation transfers torque to the drill bit 32 through a drive shaft 60.', 'The drill bit 32 may couple to the drive shaft 60 with one or more bolts 62 enabling power transfer from the motor.', 'As the drive shaft 60 rotates, torque drives rotation of the drill bit 32, enabling cutters or teeth 64 (e.g., polycrystalline diamond teeth) to grind into the rock face 66.', 'As the teeth 64 grind against the rock face 66, the rock face 66 breaks into pieces called cuttings.', 'The cuttings are then carried away from the rock face 66 with drilling mud 68.', 'The drilling mud 68 flows through a conduit or passageway 70 in the drive shaft 60 and through openings, nozzles or apertures 72 in the drill bit 32, carrying cuttings around the drill bit 32 and back through the recently drilled bore.;', 'FIG. 4 is a cross-sectional view of an embodiment of a steering pad 74 coupled to an outer bearing 112 or sleeve of a directional drilling system 30, within line 4-4′ of FIG.', '3.', 'The steering pad 74 includes a body 140 made out of a first material (e.g., carbides, including without limitation tungsten or other transition metal carbides).', 'The body 140 defines a curvilinear surface 142 configured to engage the rock face 66 described above.', 'The body 140 may also include a plurality of counterbores 144 in the curvilinear surface 142.', 'Although they are shown to be parallel, the counterbores 144 may be in other orientations, including without limitation perpendicular to the surface steering pad 74, aligned radially from the center of the tool, and/or spaced evenly or unevenly in either or both of the radial and axial directions relative to the drive shaft 60.; FIG.', '5 is a cross-sectional view of an embodiment of a steering pad 74 coupled to an outer bearing 112 or sleeve of a directional drilling system 30, within line 4-4′ of FIG.', '3.', 'In some embodiments, the body 140 of the steering pad 74 may form a coupling feature 170.', 'As illustrated, a section 172 of the body 140 of steering pad 74 defines a dovetail shape that engages a corresponding recess 174 on the outer bearing 112 (e.g., sleeve).', 'Once coupled with the steering pad 74, the outer bearing 112 blocks removal of the steering pad 74 from the directional drilling system 30 in a radial direction 176 with respect to a longitudinal axis of the directional drilling system 30.', 'In some embodiments, the steering pad 74 may define a recess (e.g., like recess 174) that receives a protrusion (e.g., like section 172) on the outer bearing 112. FIG.', '6 is a cross-sectional view of an embodiment of a steering pad 74 coupled to an outer bearing 112 or sleeve of a directional drilling system 30.', 'As illustrated, a portion 190 of the steering pad 74 sits within a cavity 192.', 'To facilitate insertion and retention, the steering pad 74 defines a curved end portion 194 (e.g., retention feature).', 'During installation, the curved end portion 194 is inserted into a corresponding curved section 196 of the cavity 192.', 'The steering pad 74 may then be rotated in direction 198 until the rest of the steering pad 74 rests within the cavity 192.', 'In order to block removal of the steering pad 74 from the cavity 192, the steering pad 74 may be welded or brazed about an exposed portion 200 of the steering pad 74.', 'In some embodiments, one or more fasteners (e.g., threaded fasteners) may secure the steering pad 74 within the cavity 192.; FIG.', '7 is a cross-sectional view of an embodiment of a steering pad 74 coupled to an outer bearing 112 or sleeve of a directional drilling system 30.', 'As illustrated, the steering pad 74 (e.g., circular steering pad) may be threadingly coupled to the directional drilling system 30.', 'For example, the steering pad 74 may include threads 210 that engage threads 212 about a cavity 214.', 'To block removal of the steering pad 74 from the cavity 214, the steering pad 74 may be welded or brazed 216 about an exposed portion 218 of the steering pad 74.', 'In some embodiments, one or more fasteners (e.g., threaded fasteners) may also be used to secure the steering pad 74 within the cavity 214.; FIG. 8 is a perspective view of an embodiment of a steering pad 74 coupling to an outer bearing 112 or sleeve of a directional drilling system 30.', 'The steering pad 74 includes a body 220 made out of a first material (e.g., carbides, including without limitation tungsten or other transition metal carbides).', 'The body 220 defines a curvilinear surface 222 configured to engage the rock face 66 described above.', 'The body 220 may also include a plurality of counterbores 224 in the curvilinear surface 222.', 'The counterbores 224 enable the steering pad 74 to receive a plurality of inserts 226.', 'The inserts 226 may include diamond inserts, boron nitride inserts, carbide inserts (e.g., tungsten or other transition metal carbide inserts), or a combination thereof.', 'The inserts may be conventional polycrystalline diamond cutters (PDC or PCD cutters).', 'These inserts 226 provide abrasion resistance as the steering pad 74 engages the rock face 66.; FIG.', '9 is a perspective view of an embodiment of a drive shaft 60 of the directional drilling system 30.', 'The drive shaft 60 defines a first end 270 and a second end 272 opposite the first end 270.', 'The first end 270 is configured to couple to a drill motor (e.g., hydraulic motor or mud motor, electric motor), while the second end 272 is configured to couple to the drill bit 32.', 'In order to couple to the drill bit 32, the second end 272 includes an exterior surface 273 that defines a plurality of protrusions 274 separated by recesses 276.', 'In some embodiments, this pattern may be a cloverleaf pattern.', 'Once coupled to the drill bit 32, the plurality of protrusions 274 may engage recesses in the drill bit 32, enabling torque transfer from the drive shaft 60 to the drill bit 32.', 'In some embodiments, the end face 278 may define one or more apertures 280 that enable the drill bit 32 to be coupled to (e.g., bolted onto) the drive shaft 60.', 'In some embodiments, there is a minimum defined radius in the surface transitions between the protrusions (e.g., 1 mm, 5 mm, 10 mm, 15 mm, or 20 mm) to minimize stress concentrations in the surface.', 'In other embodiments, the surface may be continuously curved, minimizing any section of constant radius from the center of the shaft (e.g., to less than 30, 20, or 10 degrees).; FIG.', '10 is a perspective rear view of an embodiment of a drill bit 32.', 'As illustrated, the drill bit 32 includes an exterior portion or body 300 and an interior portion or body 302.', 'The exterior portion 300 and the interior portion 302 may be formed from the same or different materials.', 'Because the interior portion 302 does not contact the rock face 66 while drilling, the interior portion 302 may be made from a different material.', 'For example, the exterior portion 300 may be formed from carbide (e.g., tungsten or other transition metal carbide) and may include teeth or cutters 304 (e.g., diamond) embedded in the carbide, while the interior portion 302 may be formed from steel (e.g., steel alloy).', 'Moreover, because the interior portion 302 couples the drill bit 32 to the drive shaft 60, the interior portion 302 may be made out of a material capable of manufacturing with tighter tolerances (e.g., steel, steel alloy).', '; FIG.', '11 is a cross-sectional side view of an embodiment of a directional drilling system 30 with the drive shaft 60 coupled to the drill bit 32.', 'As explained above with reference to FIG.', '9, the second end 272 of the drive shaft 60 includes an exterior surface 273 with a plurality of protrusions 274 separated by recesses 276.', 'As explained above with reference to FIG.', '10, this exterior surface 273 of the drive shaft 60 matches the protrusions 310 and recesses 312 on the interior surface 308 of the interior portion 302 (ring 306) of the drill bit 32.', 'The drive shaft 60 may therefore slide into and couple to the drill bit 32 by aligning the protrusions 274 on the drive shaft 60 with the recesses 312 on the ring 306, and the protrusions 310 on the ring 306 with the recesses 276 on the drive shaft 60.', 'Once coupled, the drive shaft 60 is configured to transfer torque from the drive shaft 60 to the drill bit 32.; FIG.', '12 is a perspective view of an embodiment of a drill bit 32 threadingly coupled to a drive shaft 358.', 'As illustrated, the drill bit 32 may define a counterbore 360 with a surface 362.', 'In order to couple to the drive shaft 358, the surface 362 of the drill bit 32 may include threads 364 that engage threads 366 on the drive shaft 358.', 'In some embodiments, the drive shaft 358 may include one or more (e.g., one, two, three, four, five, or more) protrusions 368.', 'For example, a protrusion 368 may be an annular protrusion that extends about the circumference of the drive shaft 358.', 'In operation, the protrusion(s) 368 enable an increase in torque when coupling the drill bit 32 to the drive shaft 358.', 'The drive shaft 358 may also include threads 370 that enable the drive shaft 358 to threadingly couple to threads 372 on the inner bearing 110.', 'The protrusion(s) 368 may also enable an increase in torque when coupling the inner bearing 110 to the drive shaft 358.; FIG.', '13 is a perspective view of an embodiment of an inner bearing 390.', 'The inner bearing 390 may or may not include threads for coupling to the drive shaft 60 described above.', 'However, to block relative motion between the inner bearing 390 and the drive shaft 60, the inner bearing 390 may include one or more protrusions or tabs 392 spaced evenly (as shown) or unevenly about an end face 394 of the inner bearing 390.', 'In operation, these protrusions 392 are configured to axially engage the drive shaft 60 to block rotation of the inner bearing 390 relative to the drive shaft 60.; FIG.', '14 is a perspective view of an embodiment of an inner bearing 390 coupled to the drive shaft 60 of FIG.', '9.', 'As explained above, the second end 272 of the drive shaft 60 is configured to couple to the drill bit 32.', 'In order to couple to the drill bit 32, the second end 272 includes an exterior surface 273 that defines a plurality of protrusions 274 separated by recesses 276.', 'These protrusions 274 and recesses 276 enable the drive shaft 60 to couple to and transfer torque to the drill bit 32.', 'The protrusions 274 and recesses 276 may also axially receive the protrusions 392 on the inner bearing 390 to block relative motion of the inner bearing 390 with respect to the drive shaft 60.; FIG.', '15 is a partial cross-sectional view of an embodiment of the directional drilling system 30.', 'During operation of the directional drilling system 30, an axial force is transferred through the drill string to the drill bit 32.', 'This axial force compresses the drill bit 32 against the rock face.', 'Accordingly, as the drill bit 32 rotates, the drill bit 32 is able to grind against and break up rock.', 'This axial force may be transferred at least partially through the inner bearing 110 to the drive shaft 60.', 'By including a shoulder 410 (e.g., an annular shoulder) with a width 412 that is equal to or at least 50% of the width 416 of the inner bearing 110, the contact area between the end face 414 of the inner bearing 110 and the shoulder 410 increases.', 'An increase in the contact area enables an increase in the force applied to the drill bit 32 through the drive shaft 60.; FIG.', '16 is a cross-sectional view of an embodiment of a drive shaft 428.', 'In FIG.', '16 the drive shaft 428 includes a plurality of shoulders 430 (e.g., annular shoulders) and a plurality of recesses 432 (e.g., annular recesses).', 'The shoulders 430 provide a plurality of loading points for coupling to and absorbing axial force transmitted through an inner bearing (e.g., inner bearing 110).', 'More specifically, the plurality of shoulders 430 and plurality of recesses 432 increase the available contact area between an inner bearing and the drive shaft 428, enabling the drive shaft 428 to absorb more axial force.', 'In some embodiments, the shoulders 430 may progressively increase in thickness and height along the axis 434 toward an end 436 of the drive shaft 428.', 'The recesses 432 between the shoulders 430 may also increase in both width along the axis 434 towards the end 436 as well as increase in depth in radial direction 438.; FIG.', '17 is a side view of an embodiment of a bearing system 450 for use in the directional drilling system 30.', 'As illustrated, the bearing system 450 includes lubrication grooves or channels 452 in an outer bearing 454 and in an inner bearing 456.', 'During operation, the bearing system 450 may be lubricated with drilling fluid (e.g., drilling mud 68) that is pumped through a drill string.', 'To facilitate lubrication, the inner bearing 456 and/or outer bearing 454 of the bearing system 450 may include lubricating grooves 452 that increase flow and/or distribution of the drilling fluid between them.', 'The lubricating grooves 452 may wrap around the inner and outer bearings 456, 454 in a spiral pattern.', 'For example, if the lubricating grooves 452 are on the inner bearing 456, the lubricating grooves 452 may wrap around an exterior surface of the inner bearing 456.', 'Likewise, if the lubricating grooves 452 are on an outer bearing 454, the lubricating grooves 452 may extend along an interior surface of the outer bearing 454.', 'In some embodiments, both the outer and inner bearings 454, 456 may include one or more lubricating grooves 452 (e.g., spiral grooves) that facilitate the flow and distribution of the drilling fluid in the bearing system 450.', 'In addition, the lubricating grooves 452 may be sized to enable any solid particles carried in the drilling fluid (e.g., drilling mud 68) to pass through the bearing system 450.', 'Considering the particles must pass through other flow restrictions in the drilling motor to get to this point, the minimum dimension of a lubricating groove 452 should be larger (e.g., 1.2, 1.5, 2, 3 or more times larger) than the minimum flow restriction further up the motor, e.g. an upper radial bearing in the motor.'] |
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US11118408 | Downhole steering system and methods | Jun 26, 2018 | Jonathan D. Marshall, Edward George Parkin, Geoffrey Charles Downton, David C. Hoyle, Nalin Weerasinghe, Dennis Patrick Chestnutt | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in International Patent application PCT/US2019/039376 dated Oct. 29, 2018, 19 pages.; First Office Action and Search Report issued in Chinese Patent Application 201880051550.2 dated Mar. 29, 2021, 7 pages. | 6116354; September 12, 2000; Buytaert; 20130032401; February 7, 2013; Edbury et al.; 20150008045; January 8, 2015; Downton; 20160060960; March 3, 2016; Parkin et al.; 20160160567; June 9, 2016; Downton | Foreign Citations not found. | ['A downhole steering system includes a substantially tubular housing, a shaft positioned within the substantially tubular housing, a first bearing and a second bearing, the first and second bearings being configured to support rotation of the shaft relative to the housing.', 'The first bearing, the second bearing, the shaft, and the housing at least partially define a chamber therebetween.', 'The system also includes at least one structure positioned axially between a the first and second bearing and being configured to extend from an exterior of the housing in response to pressure communicated to the chamber.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThis application claims priority to U.S. Provisional Patent Applications having Ser.', 'Nos. 62/525,121; 62/525,140; 62/525,143; and 62/525,148, each of which was filed on Jun. 26, 2017.', 'The entire contents of each these priority provisional applications is incorporated herein by reference.', 'BACKGROUND\n \nExploring for and extracting oil, gas, or geothermal energy deposits from the earth often involves boring subterranean holes.', 'To do so, it is common to secure a drill bit to the end of a drill string suspended from a derrick.', 'The drill bit may be rotated to engage and degrade the earth forming a wellbore therein and allowing the drill bit to advance.', 'It may often be desirable to direct a drill bit toward a deposit or away from an obstruction as it advances through the earth.', 'To do so, a rotational axis of the drill bit must typically be offset from a centerline of its respective borehole such that the drill bit engages one side of the borehole more than another.', 'Furthermore, it is not uncommon for a rotational axis of a drill bit to deviate from a centerline of a borehole on its own, causing the borehole to diverge from its intended path.', 'Thus, it may be advantageous to steer a drill bit back toward the centerline of its respective borehole.', 'Accordingly, various downhole steering systems have been developed for the purpose of actively shifting a drill bit axis from a borehole centerline or returning it thereto.', 'Such downhole steering systems have utilized a variety of different techniques.', 'One common technique is to push off of an inner wall of a wellbore through which a drill bit is traveling in a direction opposite from where the drill bit is intended to go.', 'For example, a structure may be extended radially from a side of a drill string, push against an inner wall of a wellbore and urge a drill bit in an opposite radial direction.', 'As the drill bit is urged radially, it may tend to degrade the wellbore unevenly causing it to veer in a desired direction.', 'It has been found that the closer an extendable structure is placed to a drill bit, the greater affect its extension may have on the drill bit.', 'Thus, several attempts have been made to place extendable structures as close as possible to their respective drill bits.', 'However, such placement often leaves little room for other equipment, such as control systems and the like.', 'In many instances, positioning of control systems or other equipment far from extendable structures complicates electrical wiring and/or fluid channeling.', 'SUMMARY\n \nEmbodiments of the disclosure may provide a downhole steering system including a substantially tubular housing, a shaft positioned within the substantially tubular housing, a first bearing and a second bearing, the first and second bearings being configured to support rotation of the shaft relative to the housing.', 'The first bearing, the second bearing, the shaft, and the housing at least partially define a chamber therebetween.', 'The system also includes at least one structure positioned axially between the first and second bearing and being configured to extend from an exterior of the housing in response to pressure communicated to the chamber.', 'Embodiments of the disclosure may also provide a drilling system including a drill bit, a shaft coupled to the drill bit, wherein rotation of the shaft causes the drill bit to rotate, and a substantially tubular housing positioned around at least a portion of the shaft.', 'The shaft and the drill bit are rotatable relative to the housing.', 'The system also includes a first bearing and a second bearing, the first and second bearings being configured to support rotation of the shaft relative to the housing.', 'The first bearing, the second bearing, the shaft, and the housing at least partially define a chamber therebetween.', 'The system further includes one or more radially-extendable pistons positioned axially between the first and second bearings and in pressure communication with the chamber, the one or more pistons being configured to extend outward of an exterior of the housing in response to pressure communicated to the chamber, and a valve configured to control pressure communication between the chamber and the radially-extendable pistons.', 'Embodiments of the disclosure may also provide a method for steering a drill bit, including deploying drill bit and a downhole steering system into a wellbore.', 'The system includes a substantially tubular housing, a shaft positioned within the substantially tubular housing, a first bearing and a second bearing, the first and second bearings being configured to support rotation of the shaft relative to the housing.', 'The first bearing, the second bearing, the shaft, and the housing at least partially define a chamber therebetween.', 'The system also includes at least one structure positioned axially between the first and second bearing and being configured to extend from an exterior of the housing in response to pressure communicated to the chamber.', 'The method also includes flowing drilling fluid into the downhole steering system such that the shaft is rotated relative to the tubular housing, wherein rotation of the shaft causes the drill bit to rotate, and actuating a valve so as to allow pressure communication between the chamber and the at least one structure, such that the at least one extendable structure extends radially outward and engages a wellbore.', 'Embodiments of the disclosure may provide a method for steering a downhole system including placing a drill string in a well, the drill string including a drill bit and a motor, the motor including a shaft connected to the drill bit and a stator housing in which the shaft is positioned.', 'At least one structure is radially extendable from the stator housing.', 'The method also includes passing drilling fluid from an inlet of the wellbore along the drill string and between the shaft and the stator housing.', 'Passing the drilling fluid between the shaft and the stator housing causes the shaft to rotate the drill bit relative to the stator housing.', 'The method further includes holding the stator housing rotationally stationary, and selectively communicating a pressure of the drilling fluid to the structure via a port extending radially through the stator, so as to extend the structure radially outward against a wall of the wellbore, and alter a trajectory of the drill bit.', 'Embodiments of the disclosure may provide a downhole steering system including a substantially tubular housing comprising a longitudinal axis and an exterior, a shaft coupled to a drill bit, extending through the housing, and rotatable relative to the housing, and a first structure, a second structure, and a third structure.', 'The first, second, and third structures are extendable outward of the exterior of the housing.', 'The first structure is circumferentially offset from the second and third structures.', 'The first, second, and third structures are positioned along an angular interval of less than about 120 degrees as proceeding around the housing.', 'Embodiments of the disclosure may also provide a drilling system including a drill bit, a substantially tubular housing comprising a longitudinal axis and an exterior, a shaft coupled to the drill bit, extending through the housing, and rotatable relative to the housing, wherein rotation of the shaft causes the drill bit to rotate, and a first structure, a second structure, and a third structure.', 'The first, second, and third structures are extendable outward of the exterior of the housing, the first structure being circumferentially offset from the second and third structures.', 'The first, second, and third structures are positioned along an angular interval of less than about 120 degrees as proceeding around the housing.', 'Embodiments of the disclosure may further provide A method for steering a drill bit, which includes flowing a drilling fluid between a housing and a shaft, such that the shaft is caused to rotate relative to the housing, with rotating the shaft causing the drill bit to rotate.', 'The method also includes holding the housing rotationally stationary with respect to a rock formation, and while holding the housing rotationally stationary, selectively communicating pressure to at least three extendable structures coupled to the housing.', 'Communicating pressure to the at least three extendable structures causes the structures to extend outwards and engage the rock formation.', 'The at least three extendable structures each define central axes, the central axes being angularly offset from one another.', 'The at least three extendable structures are positioned along an angular interval of less than about 120 degrees as proceeding around the housing.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is an orthogonal view of an embodiment of an earth-boring operation.\n \nFIG.', '2\n is a perspective view of an embodiment of a drill bit and a downhole steering system.\n \nFIG.', '3\n is a longitude-sectional view of an embodiment of a drill bit, a motor, and a downhole steering system.\n \nFIG.', '4-1\n is a cross-sectional view of an embodiment of a downhole steering system.\n \nFIG.', '4-2\n is perspective view of another embodiment of a downhole steering system.\n \nFIG.', '4-3\n is a longitude-sectional view of an embodiment of a drill bit and a downhole steering system.\n \nFIG.', '5-1\n is a longitude-sectional view of an embodiment of a drill string wherein a mass may block and unblock an opening leading to a pressurized chamber based on rotation of the drill string.\n \nFIG.', '5-2\n is a longitude-sectional view of an embodiment of a drill string wherein a mass may block and unblock an opening leading to a pressurized chamber based on a flow rate of drilling fluid passing through the drill string.\n \nFIG.', '5-3\n is a longitude-sectional view of an embodiment of a drill string wherein a plurality of balls traveling within drilling fluid passing through the drill string may get caught in a slidable trap that may block an opening leading to a pressurized chamber.\n \nFIG.', '5-4\n is a schematic view of an embodiment of a pin that may travel in a cam slot to index between blocking and unblocking positions.\n \nFIG.', '5-5\n is a longitude-sectional view of an embodiment of a drill string wherein a disk may be ruptured by an increase in drilling fluid pressure to bypass a pressurized chamber.\n \nFIG.', '6-1\n is a longitude-sectional view of an embodiment of a control mechanism comprising a direction and inclination sensor.\n \nFIG.', '6-2\n is a longitude-sectional view of an embodiment of a control mechanism including a formation property sensor.\n \nFIG.', '6-3\n is a longitude-sectional view of an embodiment of a control mechanism including an acoustic receiver.', 'FIG.', '6-4\n is a longitude-sectional view of an embodiment of a control mechanism including a pressure sensor.\n \nFIG.', '6-5\n is a schematic representation of an embodiment of a control mechanism including a communications wire.', 'FIGS.', '7-1, 7-2 and 7-3\n are perspective views of different embodiments of bearings.', 'FIGS.', '8-1 and 8-2\n are perspective views of embodiments of a three-dimensional printing operation and coating operation, respectively.', 'FIGS.', '9-1 and 9-2\n are orthogonal views of different embodiments of bearings while \nFIG.', '9-3\n is a longitude-sectional view of an embodiment of another type of bearing.', 'FIG.', '10-1\n is a magnified longitude-sectional view of an embodiment of an axial support ring while \nFIG.', '10-2\n is a longitude-sectional view of an embodiment of a flow restrictor and filter.\n \nFIG.', '11\n is a longitude-sectional view of an embodiment of oil lubricated bearings.\n \nFIG.', '12\n is a longitude-sectional view of an embodiment of a shaft including a cavity therein sized to receive proximal ends of extendable pads.\n \nFIG.', '13\n is an orthogonal view of an embodiment of a downhole steering system including a combination of both extendable pads and a bent sub.\n \nFIG.', '14\n is a perspective view of an embodiment of a downhole steering system including a combination of both extendable pads and a mating whipstock.\n \nFIG.', '15-1\n illustrates a sectional view of an embodiment of a ratcheting valve device.\n \nFIG.', '15-2\n illustrates a perspective view of an embodiment of a valve element for the ratcheting valve device.\n \nFIG.', '15-3\n illustrates a perspective view of an embodiment of a downhole steering system including the ratcheting valve device.\n \nFIG.', '16\n illustrates a conceptual end view of an embodiment of a cam-piston valve actuator.', 'FIGS.', '17-1 and 17-2\n illustrate perspective views of two other embodiments of a steering system.', 'DETAILED DESCRIPTION\n \nFIG.', '1\n shows an embodiment of an earth-boring operation \n110\n that may be used when exploring for or extracting oil, gas or geothermal energy deposits from the earth.', 'The earth-boring operation \n110\n may include a drill bit \n111\n secured to one end of a drill string \n112\n suspended from a derrick \n113\n.', 'The drill bit \n111\n may be rotated to degrade subterranean formations \n114\n, forming a wellbore \n115\n therein and allowing the drill bit \n111\n to advance.', 'The drill string \n112\n may be formed from a plurality of drill pipe sections \n116\n fastened together end-to-end, each configured to pass a drilling fluid \n117\n therethrough.', 'The drilling fluid \n117\n may be pumped through the drill string \n112\n from an inlet of the wellbore \n115\n and expelled from nozzles on the drill bit \n111\n.', 'The drilling fluid \n117\n may serve a variety of purposes, including carrying earthen debris away from the drill bit \n111\n, cooling and lubricating the drill bit \n111\n and powering a variety of downhole tools.\n \nFIG.', '2\n shows an embodiment of a drill bit \n211\n secured on an end of a drill string \n212\n.', 'The drill bit \n211\n may comprise a plurality of cutters \n220\n arranged on distal edges of a plurality of blades \n221\n extending from and spaced about the drill bit \n211\n.', 'As the drill bit \n211\n is rotated the cutters \n220\n may engage and degrade an earthen formation.', 'A variety of known drill bit styles may be swapped for the style shown and perform similarly.', 'The drill bit \n211\n may be rotated by a motor.', 'FIG.', '3\n shows an embodiment of a motor, which may be powered by drilling fluid, including a shaft \n330\n positioned within a substantially tubular housing \n331\n.', 'As is typical in progressive cavity positive displacement type motors, the shaft \n330\n may have a helical exterior geometry with two or more lobes disposed thereon.', 'The housing \n331\n may have a helical interior geometry also with two or more lobes disposed thereon.', 'If the housing \n331\n includes more lobes than the shaft \n330\n, then drilling fluid passing along a drill string passing between the exterior geometry of the shaft \n330\n and the interior geometry of the housing \n331\n may cause the shaft \n330\n to rotate eccentrically relative to the housing \n331\n.', 'In this way the shaft \n330\n may act as a rotor and the housing \n331\n may act as a stator of the motor.', 'While a progressive cavity positive displacement motor is shown in this embodiment, other types of motors, such as a turbine motor, may produce a similar result.', 'The housing \n331\n may be provided as two or more tubular members that are secured together, or as one integral piece.', 'Similarly, the shaft \n330\n may be one integral piece, or two or more cylinders that are rigidly or otherwise coupled together.', 'Another example of a downhole tool that may be powered by drilling fluid is a steering system.', 'FIG.', '3\n also shows an embodiment of steering system including a shaft \n332\n positioned within a substantially tubular housing \n333\n, similar to the motor.', 'First and second bearings \n334\n, \n335\n may be axially spaced from one another, disposed between an exterior of the shaft \n332\n and an interior of the housing \n333\n.', 'The first and second bearings \n334\n, \n335\n may support the shaft \n332\n within the housing \n333\n allowing the shaft \n332\n to rotate relative thereto while reducing friction and wear therebetween.', 'Together, the first and second bearings, \n334\n, \n335\n, shaft \n332\n and housing \n333\n may define the boundaries of a chamber \n336\n configured to maintain pressurized drilling fluid therein.', 'Fluid within the chamber \n336\n may be channeled through a valve \n337\n and a passage \n338\n to a plurality of pads \n339\n (or other radially-extendable structures) configured to extend from an exterior of the housing \n333\n when adequately pressurized from within.', 'When extended, the plurality of pads \n339\n may push against a wall of a wellbore in which the housing \n333\n is positioned, thus shifting a rotational axis of a drill bit \n311\n away from or toward a wellbore centerline.', 'Such pushing may be timed and executed to change or maintain a trajectory of advancement of the drill bit \n311\n.', 'The pads \n339\n may be rotationally fixed to the tubular housing \n333\n, such that they may be positioned by rotation of a drill string at an inlet to a wellbore.', 'In such a configuration, the drill bit \n311\n may be rotatable relative to the pads \n339\n and the tubular housing \n333\n.', 'The pads \n339\n may be positioned in a variety of arrangements.', 'For instance, in one embodiment shown in \nFIG.', '4-1\n, at least three pads \n439\n-\n1\n may be extendable from an exterior of a substantially tubular housing \n433\n-\n1\n such that each of the pads \n439\n-\n1\n remains within an angular range \n440\n-\n1\n of one-third of a full rotation about an axis of the housing \n433\n-\n1\n (e.g., about 120 degrees), whether the pads \n439\n-\n1\n are extended or retracted.', 'While an angular range of one-third is shown, other embodiments may define ranges of one-quarter (80 degrees) to one-half (180 degrees).', 'Such an arrangement of pads \n439\n-\n1\n may allow for sufficient force to be applied by the pads \n439\n-\n1\n to an adjacent wellbore without blocking drilling fluid flow down the housing \n433\n-\n1\n or up an annulus surrounding the housing \n433\n-\n1\n.', 'A cylindrical orifice \n447\n-\n1\n within the housing \n433\n-\n1\n and configured to carry drilling fluid may extend longitudinally through the housing \n433\n-\n1\n, uninterrupted by the pads \n439\n-\n1\n.', 'Also, at least one fluid channel \n441\n-\n1\n may run longitudinally along the exterior of the housing \n433\n-\n1\n configured to carry drilling fluid through the wellbore.', 'This particular embodiment includes two such fluid channels, each disposed between the pads \n439\n-\n1\n and a point on the exterior of the housing \n433\n-\n1\n opposite the pads \n439\n-\n1\n relative to the axis, e.g., along flattened sections of the exterior of the housing \n433\n-\n1\n.', 'A distance \n450\n-\n1\n, between respective nadirs of the two fluid channels, may be greater than a widest span of the pads \n439\n-\n1\n.', 'Due to the spacing of the pads \n439\n-\n1\n, a sum of such fluid channels may be an angular range of over two-fifths of a full rotation about the housing \n433\n-\n1\n axis and over 8% of a cross-sectional footprint area of the housing \n433\n-\n1\n allowing for adequate fluid flow.', 'In some embodiments, the angular range may be between three-tenths and one-half, and the percentage of the cross-sectional footprint area over 6%.', 'A surface \n442\n-\n1\n forming the fluid channel \n441\n-\n1\n may be substantially perpendicular to a radius of the housing \n433\n-\n1\n and parallel to the axis thereof.', 'As also shown in the embodiment of \nFIG.', '4-1\n, at least two of the pads \n439\n-\n1\n may define axes disposed substantially on a single plane (the cross-section shown) perpendicular to the axis of the housing \n433\n-\n1\n.', 'For example, three pads sharing a single perpendicular plane are shown in \nFIG.', '2\n.', 'The axes of the at least two pads \n439\n-\n1\n may be disposed within an angular range \n443\n-\n1\n of one-fifth (about 72 degrees) of a full rotation about the housing \n433\n-\n1\n axis.', 'In some embodiments, such an angular range may fall between one-tenth (36 degrees) and three-tenths (108 degrees) of a full rotation.', 'Furthermore, one pad \n444\n-\n1\n defines an axis disposed perpendicular to the axis of the housing \n433\n-\n1\n and substantially midway between the axes of the other two pads \n439\n-\n1\n.', 'These respective pads \n439\n-\n1\n, \n444\n-\n1\n may include a distal end shaped generally as a circular arc when viewed in a plane (the cross section shown) perpendicular to the axis of the housing \n433\n-\n1\n.', 'Furthermore, the circular arcs of each of the pads \n439\n-\n1\n, \n444\n-\n1\n may share the same radius and center.', 'In the embodiment shown, the circular-arc distal-end geometry of the center pad \n444\n-\n1\n may be generally symmetrical about its axis.', 'This distal end shape may differ from distal ends of the other two pads \n439\n-\n1\n that may be asymmetrical about their respective axes when viewed in the same plane.', 'More specifically, the distal ends of the other two pads \n439\n-\n1\n may extend farther from the axis of the housing \n433\n-\n1\n on sides facing each other \n445\n-\n1\n than on opposite sides \n446\n-\n1\n.', 'This may be because the center of the circular arcs of each of the pads \n439\n-\n1\n, \n444\n-\n1\n is offset from the axis of the housing \n433\n-\n1\n.', 'In the embodiment shown, this offset equals the length of maximum extension of the pads \n439\n-\n1\n, \n444\n-\n1\n from the exterior.', 'In some embodiments, such an offset may result in less wear, especially on peripheral edges of the pads \n439\n-\n1\n, \n444\n-\n1\n.', 'As also shown in this embodiment, the exterior of the housing \n433\n-\n1\n immediately adjacent the pads \n439\n-\n1\n may extend a greater distance \n448\n-\n1\n from the axis than a distance \n449\n-\n1\n to a point on the exterior opposite from the axis, and a lesser distance \n448\n-\n1\n than a length of a radius of a drill bit secured to a shaft passing through the housing \n433\n-\n1\n.', 'In some embodiments, the housing \n433\n-\n1\n may be configured such that a difference, between this greater distance \n448\n-\n1\n and the distance \n449\n-\n1\n to the opposite point, is substantially equal to a length of maximum extension of the pads \n439\n-\n1\n; however, other designs may also be employed.', 'Also, in some embodiments, the housing \n433\n-\n1\n may be designed such that a sum of these two distances \n448\n-\n1\n, \n449\n-\n1\n is less than a diameter of a drill bit secured to an end of a shaft passing through the housing \n433\n-\n1\n.\n \nFIG.', '4-2\n shows one embodiment of the pads \n439\n-\n2\n arranged on an exterior of a substantially tubular housing \n433\n-\n2\n.', 'As shown, sets \n451\n-\n2\n of three pads \n439\n-\n2\n, each extendable from the exterior, may be spaced longitudinally along the housing \n433\n-\n2\n.', 'Each of the sets \n451\n-\n2\n may include one pad positioned equidistant and axially displaced, in a staggered configuration, between pairs of double pads spaced longitudinally along the housing \n433\n-\n2\n.', 'In other embodiments, other configurations are possible, such as rows of double pads without center pads.', 'While the illustrated embodiment includes eight extendable pads, other embodiments may have from one to twelve pads, such as three, nine (such as shown in \nFIG.', '2\n), eleven or any other suitable number of pads.', 'In addition, while two specific configurations have been shown in \nFIG.', '2\n and \nFIG.', '4-2\n, any suitable configuration may be used.', 'For example, pads could be located on any suitable number (such as one to four or more) of axial rows and (one to five or more) circumferential rows.', 'FIG.', '4-3\n shows an embodiment of a drill bit \n411\n-\n3\n secured to a shaft \n432\n-\n3\n positioned within a housing \n433\n-\n3\n.', 'The housing \n433\n-\n3\n may include a plurality of extendable pads \n439\n-\n3\n disposed on the same side of the housing \n433\n-\n3\n as a control mechanism \n401\n-\n3\n.', 'Specifically, the control mechanism \n401\n-\n3\n may be positioned within the same angular range, one-third of a full rotation about the housing \n433\n-\n3\n, as the pads \n439\n-\n3\n.', 'As also can be seen in this embodiment, to make space for the housing \n433\n-\n3\n when located within a curved wellbore, an exterior of the housing \n433\n-\n3\n may taper longitudinally from a diameter \n459\n-\n3\n adjacent the drill bit \n411\n-\n3\n to a diameter \n458\n-\n3\n closer to a drill string secured to the housing \n433\n-\n3\n opposite the drill bit \n411\n-\n3\n.', 'As described, timing and execution of pad extension may be performed by a control mechanism (also referred to herein as a “control device”) \n301\n disposed axially between the first bearing \n334\n and the second bearing \n335\n, as shown in \nFIG.', '3\n.', 'Various embodiments of control mechanisms may incorporate different control regimen, as will be described in more detail below.', 'For example, the control mechanism \n301\n may actuate the valve \n337\n to affect the timing and duration of pressure on or stroke length of the pads \n339\n.', 'This could be done by the control mechanism \n301\n without the aid of external information.', 'In some embodiments, all pads may be actuated together, groups of pads may be actuated together, or individual pads may be actuated.', 'To determine how much pressure or stroke length is desirable, a variety of sensors may gather information and feed it to such a control mechanism.', 'For instance, some embodiments of sensors, such as inclinometers and magnetometers, may determine position or orientation of a drill string or pads.', 'A control mechanism may then use this information in deciding when and how to actuate a valve.', 'Other embodiments of sensors may detect formation properties of a wellbore surrounding the drill string.', 'Such information may provide addition layers of information to assist a control mechanism.', 'As such, a control mechanism may manipulate a valve with proportional, nonlinear, or on/off actuation in order to achieve a chosen outcome.', 'In various embodiments, a resting position of such pads, before extending, may be either generally flush with our sunken within an exterior of the housing.', 'In other embodiments, however, the pads at rest may protrude from the exterior of the housing to provide a resting outward offset, such that the pads may be either extended or retracted from that position to provide additional steering control.', 'Also, in assorted embodiments, such a plurality of pads may extend together, at least one of the pads may extend separately from the rest, or at least one of the pads may remain continuously extended.', 'In this configuration, pressurized drilling fluid may be channeled to the plurality of pads \n339\n without needing to bypass either of the first or second bearings \n334\n, \n335\n.', 'Specifically, the pressurized drilling fluid traveling from the chamber \n336\n to the pads \n339\n may be continuously maintained axially between the first bearing \n334\n and the second bearing \n335\n.', 'Even without the valve \n337\n, a downhole steering system of the type shown may be operated by holding the housing \n333\n rotationally stationary at an inlet of a wellbore, passing drilling fluid from the inlet along a drill string until it reaches the plurality of pads \n339\n, and pressing the pads \n339\n outwards with pressure from the drilling fluid.', 'Because the housing \n333\n is held, the pads \n339\n may generally extend in a constant orientation thus altering a trajectory of the drill bit \n311\n.', 'A rate of alteration may be controlled by adjusting a pressure of the drilling fluid at the inlet.', 'When straight drilling is desired, the drill string may be rotated at the inlet.', 'Even with the pads \n339\n extended, rotation may generally balance out or negate their effect on drilling direction.', 'One steering plan includes may include generally vertically drilling, for a first distance, then drilling in a curve for a second distance, and then drilling generally horizontally for a third distance.', 'To achieve this steering plan, drilling fluid pressure at an inlet to a wellbore may be increased to extend at least some of the pads when it is desirable to start curving.', 'To stop curving when horizontal is reached, drilling fluid may be blocked from passing to the pads or the pads may be bypassed by the drilling fluid.', 'This may be accomplished by any of a variety of devices.', 'For example, drilling fluid may be blocked by shifting a mass radially within the drill string by adjusting rotation of the drill string.', 'FIG.', '5-1\n shows an embodiment of a drill string \n512\n-\n1\n including a passage \n547\n-\n1\n positioned longitudinally therethrough with an opening \n551\n-\n1\n to a chamber \n536\n-\n1\n.', 'Drilling fluid traveling through the passage \n547\n-\n1\n may pass through the opening \n551\n-\n1\n into the chamber \n536\n-\n1\n to extend at least one extendable pad \n539\n-\n1\n.', 'When the drill string \n512\n-\n1\n is rotated at a certain speed, a mass \n552\n-\n1\n, rotatable about a hinge, may overcome a spring by centrifugal force to block the opening \n551\n-\n1\n from allowing drilling fluid to pass therethrough.', 'Blocking drilling fluid from reaching extendable pads may also be achieved by shifting a mass longitudinally within a drill string.', 'For example, \nFIG.', '5-2\n shows an embodiment of a mass \n552\n-\n2\n that may overcome a spring and shift longitudinally when a flow rate of drilling fluid passing along a drill string \n512\n-\n2\n is sufficient.', 'As it does so, it may block an opening \n551\n-\n2\n preventing drilling fluid from entering a chamber \n536\n-\n2\n and extending a pad \n539\n-\n2\n.', 'In other embodiments, drilling fluid may be blocked by passing one or more objects through a drill string along with the drilling fluid.', 'For example, \nFIG.', '5-3\n shows an embodiment of a plurality of balls \n553\n-\n3\n that may be dropped into a drill string \n512\n-\n3\n and travel with drilling fluid flowing through the drill string \n512\n-\n3\n until they reach a slidable trap \n552\n-\n3\n.', 'The plurality of balls \n553\n-\n3\n may be sufficiently small and durable to pass through a downhole mud motor (not shown).', 'Each of the balls \n553\n-\n3\n may be received within apertures formed in the slidable trap \n552\n-\n3\n.', 'When the apertures are obstructed by the balls \n553\n-\n3\n, the drilling fluid may push the slidable trap \n552\n-\n3\n to block an opening \n551\n-\n3\n into a chamber \n536\n-\n3\n.', 'In other embodiments, drilling fluid may be blocked by a ratcheting device.', 'For example, \nFIG.', '5-4\n shows an embodiment of a cam slot \n554\n-\n4\n that may wrap around a drill string and receive a pin \n555\n-\n4\n that may travel therein.', 'The cam slot \n554\n-\n4\n may be biased by a spring which may index the pin \n555\n-\n4\n relative to the cam slot \n554\n-\n4\n when compressed by weight-on-bit of the drill string.', 'Indexing of the pin \n555\n-\n4\n to a subsequent location relative to the cam slot \n554\n-\n4\n may then block or unblock an opening leading to a chamber as described previously.', 'With such a design, the opening may be blocked and unblocked repeatedly.', 'FIGS.', '15-1, 15-2, and 15-3\n provide an additional example of such a ratcheting device, described below.', 'In yet another embodiment, drilling fluid may bypass an opening leading to a chamber.', 'For example, in \nFIG.', '5-5\n an embodiment of a rupture disk \n557\n-\n5\n may be positioned adjacent an opening \n551\n-\n5\n to a chamber \n536\n-\n5\n.', 'An increase in pressure of drilling fluid passing by the rupture disk \n557\n-\n5\n may cause it to burst, thus causing drilling fluid to bypass outward rather than into the chamber \n536\n-\n5\n.', 'Referring back to \nFIG.', '3\n, while extendable pads \n339\n are shown, other embodiments may include different structures such as rings or stabilizer blades that may extend to produce a similar result.', 'The pads \n339\n may be extendable from an exterior of the housing \n333\n based upon an amount of fluid pressure maintained within the chamber \n336\n.', 'For instance the pads \n339\n may extend a certain distance or with certain force based on the chamber \n336\n pressure.', 'In the embodiment shown, this relationship is maintained by each pad \n339\n forming a piston that may slide axially along a cylinder based on a difference of pressure experienced between either end thereof.', 'In some embodiments other configurations are possible, such as hinged pads actuated by pistons.', 'Additionally, a pressure gauge \n305\n may be disposed between the valve \n337\n and the pads \n339\n.', 'This pressure gauge \n305\n may provide feedback to the control mechanism \n301\n that may control actuation of the valve \n337\n to allow for a desirable fluid pressure to be achieved at the pads \n339\n.', 'This fluid pressure may be used to determine a distance extended or force exerted by the pads \n339\n.', 'Another approach may be to measure fluid pressure within the chamber.', 'In some embodiments, the control mechanism \n301\n may be configured to receive communications from the wellbore inlet to adjust the valve \n337\n to reach a target fluid pressure at the pads \n339\n.', 'For instance, a pressure wave, originating at the wellbore inlet, may be transmitted via drilling fluid along the drill string to the control mechanism \n301\n.', 'The pressure wave may include a signal discernible by the control mechanism \n301\n that may inform the control mechanism \n301\n of a desirable pressure for the pads \n339\n.', 'The control mechanism \n301\n may then realize that desirable pressure based on feedback from the pressure gauge \n305\n.', 'In some situations, the pressure wave may include instructions to the control mechanism \n301\n to not actuate the valve \n337\n at all.', 'This override mode, where the pads \n339\n remain retracted, may be helpful in situations where the drill string is to be removed from a wellbore or has become stuck therein.', 'In either case, it may be desirable to keep drilling fluid flowing through a drill string without extending the pads \n339\n.', 'In the embodiment shown, the valve \n337\n is sized to allow between 5 and 30 gallons per minute of drilling fluid to flow therethrough.', 'In other embodiments, this range may be between 0 and 50 gallons or more.', 'A method of operating the downhole steering system utilizing the valve \n337\n may include rotating the drill string, including the pads \n339\n, from the wellbore inlet at one speed and the drill bit \n311\n via the motor at a different speed.', 'A trajectory of the drill bit \n311\n may be altered by repeatedly extending the pads \n339\n as the drill string continues to turn.', 'Such repeated extensions may be timed to carry out a set well plan or return the drill bit \n311\n to its intended trajectory if it begins to stray.', 'Specifically, as a drill string rotates, the pads \n339\n may rotate therewith.', 'As the pads \n339\n pass through an angular range of the drill string circumference, facing generally opposite a lateral direction in which it is desirable to steer, the pads \n339\n may be extended by actuating the valve \n337\n to push off of a wellbore wall.', 'As the pads \n339\n exit that angular range, they may be retracted to disengage from the wellbore wall.', 'In some embodiments, the pads \n339\n may be extended without any communication from the inlet.', 'For example, the control mechanism \n301\n controlling the valve \n337\n may include one or more sensors configured to sense direction, inclination, angular position, rotation and/or lateral displacement of the drill bit \n311\n.', 'As another example, the control mechanism \n301\n may include one or more sensors configured to measure a property of a formation surrounding the housing \n333\n.', 'Actuation of the valve \n337\n may be based on the direction, inclination, angular position, rotation and/or lateral displacement sensed or the formation property measured.', 'To avoid destabilizing drilling behaviors that may be caused by repetitive cyclical pad extensions, it may be desirable for these repeating pad extensions to occur for a brief moment every several rotations or for a full rotation every several rotations.', 'One method of operating the downhole steering system utilizing this downhole rotation sensor may be to rotate the drill string or hold it rotationally stationary at the inlet, sense this rotation or lack thereof downhole and then actuate the valve \n337\n and extend or retract the pads \n339\n based thereon.', 'By so doing, the control mechanism \n301\n might not be configured to communicate axially beyond the first and second bearings \n334\n, \n335\n.', 'Torque from the rotor shaft \n330\n of the motor may be passed through the shaft \n332\n to rotate the drill bit \n311\n.', 'This rotation of the drill bit \n311\n via the motor may allow the drill bit \n311\n to continue its advance regardless of whether it is being rotated from the inlet.', 'Extending or retracting the pads \n339\n may include holding the valve \n337\n in one state, either open or closed, while the drill string is rotating and in an opposite state while the drill string is rotationally stationary.', 'In some situations, a specified rate of change of drill bit trajectory may be achieved by alternating between rotating the drill string at the inlet and holding it rotationally stationary in particular amounts.', 'More specifically, to produce a certain rate of change of trajectory, a specific ratio of time may be spent rotating versus holding rotationally stationary.', 'A defined drill plan may be followed.', 'For example, the drill string may be rotated at the inlet to drill substantially straight in a generally vertical direction for a first distance.', 'The drill string may then be held rotationally stationary at the inlet to drill at a curve for a second distance.', 'Finally, the drill string may be rotated again at the inlet to drill substantially straight again, this time generally horizontally, for a third distance.', 'In some embodiments, the closer extendable pads are placed to a downhole drill bit, the more effect they may have on a trajectory of the drill bit.', 'For instance, in the present embodiment, the pads \n339\n may be positioned axially along the housing \n333\n a distance from a distal end of the drill bit \n311\n equal to or less than two times a diameter of the drill bit \n311\n.', 'Unlike prior attempts to place extendable structures as close as possible to their respective drill bits, however, the structure shown need not bypass either of the first or second bearings \n334\n, \n335\n.', 'To get the pads \n339\n as close as possible to the drill bit \n311\n, a pin and box combination may be used.', 'In some configurations, a drill string generally includes a threaded box into which a threaded pin of a drill bit may be fastened to secure the drill bit to the drill string in a manner configured to transfer rotation therebetween.', 'In the present embodiment, however, the shaft \n332\n includes a pin \n302\n that may be received and fastened within a box \n303\n of the drill bit \n311\n.', 'This configuration may position the pads \n339\n even closer to the drill bit \n311\n than the other configuration, where the threaded pin of the drill bit is secured to the box of the drill string.', 'Another component that may have a similar effect to positioning the pads \n339\n as close as possible to the drill bit \n311\n is to locate one or more cutting elements \n304\n on the shaft \n332\n itself adjacent to the drill bit \n311\n as shown.', 'In some embodiments, it may be desirable to pass at least some drilling fluid to a chamber and pads regardless of whether a valve is actuated or not.', 'Also, in some situations, such a valve may be or include a proportional valve configured to proportionally control of fluid pressure within a chamber.', 'A variety of different bearing designs may be used in conjunction with a downhole steering system of the type described.', 'One variety of bearings may allow drilling fluid flowing along a drill string to pass through the bearings themselves to lubricate the bearings as well as control fluid pressure within the chamber.', 'For example, the first bearing \n334\n may include an internal journal and an external housing, with the internal journal and the external housing being movable with respect to one another.', 'A gap between the journal and the housing may allow drilling fluid to pass by.', 'In various embodiments, the gap may be sized to allow sufficient drilling fluid to pass to pressurize the chamber \n336\n while blocking larger particulate matter from entering the chamber \n336\n.', 'The second bearing \n335\n may also allow some drilling fluid to pass through a gap therein sufficient to lubricate the second bearing \n335\n while not overly reducing fluid pressure within the chamber \n336\n.', 'In this manner, the second bearing \n335\n may maintain a greater pressure differential thereacross than across the first bearing \n334\n.', 'Such dissimilarity in pressure differentials may aid in maintaining a desired pressure within the chamber \n336\n.\n \nFIG.', '6-1\n shows an embodiment of a control mechanism \n601\n-\n1\n configured to actuate a valve \n637\n-\n1\n.', 'The control mechanism \n601\n-\n1\n includes a sensor \n660\n-\n1\n configured to measure direction and inclination of the control mechanism \n601\n-\n1\n via a three-axis accelerometer that may measure accelerations in x, y and z directions, respectively.', 'While a three-axis accelerometer is illustrated, those of skill in the art will recognize that a variety of other sensor types could additionally or alternately be used.', 'Further, in some embodiments, other characteristics of a substantially tubular housing, such as angular position or rotation, may be measured by such a sensor device.', 'Other embodiments may measure a lateral displacement of a substantially tubular housing relative to a wellbore.', 'Such measurements may be made by a caliper-like sensor or by a determination of pad stroke length.', 'In various embodiments, such a control mechanism may be powered by batteries or a generator configured to convert energy from a flowing drilling fluid to electricity to energize a valve and/or sensor.\n \nFIG.', '6-2\n shows another embodiment of a control mechanism \n601\n-\n2\n configured to actuate a valve \n637\n-\n2\n.', 'This control mechanism \n601\n-\n2\n includes a series of sensors \n660\n-\n2\n configured to measure a property of a formation proximate the sensors \n660\n-\n2\n.', 'In this embodiment, the sensors \n660\n-\n2\n are configured to measure electrical resistivity of an adjacent formation.', 'This may be accomplished by injecting current into the formation via a first electrode, surrounded by an insulating ring, of one of the sensors \n660\n-\n2\n and receiving current from the formation via a second electrode of another of the sensors \n660\n-\n2\n.', 'While resistivity sensors are featured in the embodiment shown, those of skill in the art will recognize that a variety of other sensor types could alternately be used to measure any of a variety of formation properties.', 'FIG.', '6-3\n shows an embodiment of a control mechanism \n601\n-\n3\n housed within a sidewall of a portion of a substantially tubular housing \n633\n-\n3\n.', 'The control mechanism \n601\n-\n3\n includes an acoustic receiver \n660\n-\n3\n configured to detect acoustic waves propagating through the housing \n633\n-\n3\n.', 'Specifically, the acoustic receiver \n660\n-\n3\n may include a plurality of piezoelectric crystals positioned such that they contact the housing \n633\n-\n3\n.', 'Acoustic waves propagating through the housing \n633\n-\n3\n may apply mechanical stress to the piezoelectric crystals causing an electric charge to accumulate therein.', 'These acoustic waves may carry information or directions to the control mechanism to guide it in its actuation of a valve \n637\n-\n3\n and be sent from another downhole tool or from a surface of a wellbore.', 'While piezoelectric crystals have been shown in this embodiment, those of skill in the art will recognize that a selection of other sensor types may alternately be used and produce similar results.', 'FIG.', '6-4\n shows another embodiment of a control mechanism \n601\n-\n4\n housed within a sidewall of a portion of a substantially tubular housing \n633\n-\n4\n.', 'The control mechanism \n601\n-\n4\n includes a pressure sensor \n660\n-\n4\n configured to measure pressure waves propagating through a fluid flowing through the housing \n633\n-\n4\n.', 'Such pressure waves may originate from a wellbore inlet or a downhole device, such as a measurement-while-drilling unit disposed axially beyond first or second bearings, and/or a mud motor, from a control mechanism.', 'Pressure waves generated by a measurement-while-drilling unit and intended for a wellbore inlet may be received and comprehended by a control mechanism as described.', 'In some embodiments, actuation of a valve of the sort shown may create pressure waves in fluid that may be discernible at a wellbore inlet or another downhole device, allowing for two-way communication.', 'As shown, the control mechanism \n601\n-\n4\n includes a piezoelectric crystal facing an opening \n661\n-\n4\n in the housing \n633\n-\n4\n.', 'This opening \n661\n-\n4\n may expose the piezoelectric crystal to fluid flowing through the housing \n633\n-\n4\n.', 'Changes in pressure of that fluid may apply mechanical stress to the piezoelectric crystals causing an electric charge to accumulate therein as described in regards to other embodiments.', 'While piezoelectric crystals have been shown in this embodiment, those of skill in the art will recognize that a selection of other sensor types may alternately be used and produce similar results.', 'FIG.', '6-5\n shows yet another embodiment of a control mechanism \n601\n-\n5\n housed within a sidewall of a substantially tubular housing \n633\n-\n5\n.', 'In this embodiment, a downhole device \n662\n-\n5\n, such as a measurement-while-drilling unit, may be disposed on an opposite side of a mud motor \n663\n-\n5\n from the control mechanism \n601\n-\n5\n.', 'The downhole device \n662\n-\n5\n may comprise its own detection and measurement equipment, separate from any sensors forming part of the control mechanism \n601\n-\n5\n.', 'Such detection and measurement equipment, of the downhole device \n662\n-\n5\n, may be larger and more sophisticated due to it being positioned axially farther from a drill bit than the control mechanism \n601\n-\n5\n.', 'Thus, more detailed and complex information may be gathered by the downhole device \n662\n-\n5\n.', 'The downhole device \n662\n-\n5\n may transmit at least some of this data to the control mechanism \n601\n-\n5\n.', 'In the embodiment shown, this data is transmitted to the control mechanism \n601\n-\n5\n via a communications wire \n664\n-\n5\n that may bypass the mud motor \n663\n-\n5\n through a sidewall thereof.', 'The control mechanism \n601\n-\n5\n may actuate a valve \n637\n-\n2\n based on this transmitted information.', 'In other embodiments, a measurement-while-drilling unit, or other downhole device, may transmit data past a mud motor to a valve control mechanism via acoustic waves propagating through a housing or pressure waves propagating through a fluid.', 'FIGS.', '7-1 and 7-2\n show embodiments of bearings \n734\n-\n1\n and \n734\n-\n2\n, respectively, including journals \n770\n-\n1\n, \n770\n-\n2\n that are movable with respect to housings \n771\n-\n1\n, \n771\n-\n2\n.', 'The bearings \n734\n-\n1\n, \n734\n-\n2\n include fluid passages, such as clearances \n772\n-\n1\n, \n772\n-\n2\n formed between the journals \n770\n-\n1\n, \n770\n-\n2\n and housings \n771\n-\n1\n, \n771\n-\n2\n that may allow drilling fluid to flow therebetween while restricting larger particulates.', 'Tolerances in the clearances \n772\n-\n1\n, \n772\n-\n2\n provided to maintain concentricity of the journals \n770\n-\n1\n, \n770\n-\n2\n and housings \n771\n-\n1\n, \n771\n-\n2\n, may impede the ability to establish and maintain sufficient fluid pressure within a chamber.', 'Accordingly, the bearing \n734\n-\n1\n, \n734\n-\n2\n may define flow passage geometries through which additional drilling fluid may pass.\n \nFIG.', '7-1\n shows a geometry including a plurality of grooves \n773\n-\n1\n disposed on an exterior of the journal \n770\n-\n1\n sitting parallel to a rotational axis \n774\n-\n1\n thereof.', 'Another plurality of grooves \n775\n-\n1\n may be disposed on an interior of the housing \n771\n-\n1\n.', 'The combination of grooves \n773\n-\n1\n, \n775\n-\n1\n may include a total cross-sectional area sufficient to allow up to 30 gallons per minute or 5% of a total flow of drilling fluid flowing through a drill string to pass the bearing \n734\n-\n1\n.', 'In other embodiments, this area may allow up to 60 gallons per minute, or 10% of a total, or more to pass.\n \nFIG.', '7-2\n shows another geometry including a plurality of grooves \n773\n-\n2\n disposed on an exterior of the journal \n770\n-\n2\n and another plurality of grooves \n775\n-\n2\n disposed on an interior of the housing \n771\n-\n2\n.', 'Each of these grooves \n773\n-\n2\n, \n775\n-\n2\n may curve around a rotational axis \n774\n-\n2\n of the bearing \n734\n-\n2\n to form a helical path.', 'Such curved grooves \n773\n-\n2\n, \n775\n-\n2\n may aid in cleaning the exterior of the journal \n770\n-\n2\n and the interior of the housing \n771\n-\n2\n.\n \nFIG.', '7-3\n shows an embodiment of a bearing \n734\n-\n3\n including a journal \n770\n-\n3\n rotatable within a housing \n771\n-\n3\n.', 'The housing \n771\n-\n3\n includes a plurality of conduits \n776\n-\n3\n extending along a length thereof and allowing a drilling fluid to flow therethrough.', 'In other embodiments, conduits may be disposed within a journal as well or forming helical paths.', 'Various manufacturing methods may be used to create bearings including such intricate geometries.', 'Specifically, it may not be possible to form a nonlinear conduit using a drill.', 'Thus, for example, one manufacturing technique that has been used is three-dimensionally printing a base structure having the desired geometry as shown in \nFIG.', '8-1\n.', 'As commonly available three-dimensionally printable materials are not generally suited to withstand abrasive conditions, the three-dimensionally printed base may be coated in materials chosen to withstand abrasion as shown in \nFIG.', '8-2\n.\n \nFIG.', '9-1\n shows an embodiment of a bearing \n934\n-\n1\n including a plurality of grooves \n975\n-\n1\n disposed on an interior of a housing \n971\n-\n1\n and sitting parallel to a rotational axis \n974\n-\n1\n thereof.', 'As can be seen, each of the grooves \n975\n-\n1\n may extend only part way along an axial length of the bearing \n934\n-\n1\n.', 'Additionally, each of the grooves \n975\n-\n1\n may extend from opposing ends alternatingly.', 'Grooves of this and similar geometries may increase an area for fluid flow between a journal and housing.', 'Such grooves may also allow for cleaning and lubrication while blocking large particulate.\n \nFIG.', '9-2\n shows another embodiment of a bearing \n934\n-\n2\n including a plurality of grooves \n975\n-\n2\n disposed on an interior of a housing \n971\n-\n2\n.', 'In this embodiment, the grooves \n975\n-\n2\n are cross-sectionally larger on a first end \n990\n-\n2\n than on an opposing second end \n991\n-\n2\n.', 'Positioning the second end \n991\n-\n2\n facing toward a chamber and second bearing may allow the bearing \n934\n-\n2\n to act like a compressor in that large amounts of drilling fluid may enter the grooves \n975\n-\n2\n at the first end \n990\n-\n2\n and then be forced into a smaller space at the second end \n991\n-\n2\n as the housing \n971\n-\n2\n rotates relative to a journal.', 'By so doing, a fluid pressure within the chamber may be greater than before entering through the bearing \n934\n-\n2\n.', 'Additionally, the fluid pressure within the chamber may be dependent and at least somewhat regulated by a rotational speed of the housing \n971\n-\n2\n relative to the journal.', 'FIG.', '9-3\n shows another embodiment of a bearing \n935\n-\n3\n including discrete superhard elements \n993\n-\n3\n (e.g., polycrystalline diamond, cubic boron nitride, carbon nitride or boron-nitrogen-carbon structures) secured within cavities on an internal surface \n992\n-\n3\n thereof.', 'The internal surface \n992\n-\n1\n may include hard cladding (e.g., tungsten and tungsten carbide) brazed thereto.', 'Such features may prolong the life of these types of bearings.\n \nFIG.', '10-1\n shows an embodiment of a ring \n1094\n-\n1\n that may be disposed between a shaft \n1032\n-\n1\n and a substantially tubular housing \n1033\n-\n1\n.', 'The ring \n1094\n-\n1\n rests axially between a second bearing \n1035\n-\n1\n and an internal ledge formed in the housing \n1033\n-\n1\n, although other configurations are possible.', 'This ring \n1094\n-\n1\n may allow the second bearing \n1035\n-\n1\n and an axially spaced first bearing (not shown) to support the shaft \n1032\n-\n1\n axially relative to the housing \n1033\n-\n1\n as well as radially.\n \nFIG.', '10-2\n shows an embodiment of another type of ring, this time forming a flow restrictor \n1094\n-\n2\n.', 'The ring forming this flow restrictor \n1094\n-\n2\n may be retained axially, but otherwise float freely between a shaft \n1032\n-\n2\n and a housing \n1033\n-\n2\n.', 'In this configuration, the flow restrictor \n1094\n-\n2\n may impede fluid flow passing between the shaft \n1032\n-\n2\n and the housing \n1033\n-\n2\n.', 'Restricting or impeding this fluid flow may reduce wear on a second bearing \n1035\n-\n2\n that also interacts with the flow.\n \nFIG.', '10-2\n also shows an embodiment of a filter \n1010\n-\n2\n that may screen particulate matter of a given size traveling with the fluid flow from reaching a valve \n1037\n-\n2\n or extentable pads \n1039\n-\n2\n there beyond.', 'Thus, this filter \n1010\n-\n2\n may reduce wear on the valve \n1037\n-\n2\n, pads \n1039\n-\n2\n and internal fluid channels.', 'Bearing designs described thus far have generally been lubricated by drilling fluid passing through the bearing.', 'However, other lubrication methods are also possible.', 'For example, \nFIG.', '11\n shows an embodiment of a chamber \n1136\n defined by a shaft \n1132\n, a substantially tubular housing \n1133\n, and first and second bearings \n1134\n, \n1135\n.', 'The chamber \n1136\n may be filled and pressurized by at least one port \n1195\n passing from a hollow interior \n1196\n of the shaft \n1132\n, through which drilling fluid may be flowing, to the chamber \n1136\n.', 'The first and second bearings \n1134\n, \n1135\n may be lubricated by oil released from first and second reservoirs \n1197\n, \n1198\n, respectively.', 'While not specifically shown, various embodiments of ports may include screens or filters to keep larger particulate matter traveling down a hollow interior of a shaft from entering a pressure chamber.', 'Further, similar to bearing designs described previously, pressurized drilling fluid may be channeled from the chamber \n1136\n to a plurality of extendable pads \n1139\n without needing to bypass either of the first or second bearings \n1134\n, \n1135\n.', 'FIG.', '12\n shows an embodiment of a shaft \n1232\n positioned within a substantially tubular housing \n1233\n.', 'The shaft \n1232\n may include a cavity \n1210\n disposed on an external surface thereof.', 'The cavity \n1210\n may surround the shaft \n1232\n and be sufficiently sized to allow proximal ends of a plurality of extendable pads \n1239\n to fit therein.', 'Allowing the pads \n1239\n to retract into the cavity \n1210\n may provide for a longer pad stroke in general, thus increasing how far they may extend from an exterior of the housing \n1233\n.', 'Moreover, the embodiment shown includes a plurality of elastic members \n1211\n, such as springs, each individually urging one of the pads \n1239\n to retract into the cavity \n1210\n.', 'These elastic members \n1211\n may allow for active retraction of the pads \n1239\n rather than relying completely on pressure from outside the housing \n1233\n.', 'Retraction of the pads \n1239\n requires removing some fluid from within the cavity \n1210\n.', 'Without removing fluid, rather than retracting, the pads \n1239\n would generally hydraulically lock when a valve \n1237\n leading to the cavity \n1210\n was shut.', 'In some embodiments, hydraulic locking of pads may be avoided by allowing some fluid to leak past the pads to exhaust from a cavity.', 'In this embodiment, however, exhausting may be amplified by at least one port \n1212\n passing from the cavity \n1210\n to an exterior of the housing \n1233\n.', 'This port \n1212\n may be sized relative to the valve \n1237\n such as to have a minor effect on fluid pressure within the cavity \n1210\n when the valve \n1237\n is open but allow pressure within the cavity \n1210\n to decrease when the valve \n1237\n is closed.', 'Pressure within the cavity \n1210\n may decrease to a point where it is overcome by pressure outside of the housing \n1233\n which may cause the pads \n1239\n to retract.', 'So far, embodiments of pads pressurized by drilling fluid have primarily been discussed.', 'Additional embodiments of downhole steering systems, however, may include pads extendable by a variety of alternate means.', 'For example, in some embodiments, pressurized hydraulic fluid, such as oil, may be channeled within a closed circuit from a reservoir to a plurality of extendable pads.', 'Such hydraulic fluid may pass through a valve to a chamber positioned adjacent the pads to urge them outward from a substantially tubular housing.', 'In some embodiments, an electrical screw may be used to extend pads from such a housing.', 'For instance, in some embodiments, a control mechanism may rotate a nut engaged with a screw such that the screw translates axially with respect to the nut.', 'As the screw translates it may urge at least one pad outward from the housing.', 'Those of skill in the art will recognize that an assortment of additional devices could be interchanged with those described herein and function in a similar manner.\n \nFIG.', '13\n shows an embodiment of a downhole steering system including a plurality of pads \n1339\n extendable from an exterior thereof that may push off a wall of a wellbore to aid in steering a drill bit \n1311\n.', 'In combination with the extendable pads \n1339\n, the steering system may also include a bent sub \n1310\n portion of a drill string \n1312\n.', 'In this configuration, force applied by the pads \n1339\n against a wall of a wellbore may either add to or take away from the already bent section of the drill string \n1312\n allowing for greater severity when altering trajectory of advancement of the drill bit \n1311\n.\n \nFIG.', '14\n shows an embodiment of a whipstock \n1410\n which is a device, often shaped generally as a ramp, which may be disposed in a wellbore \n1415\n to alter a trajectory of a drill bit \n1411\n as it drills.', 'In use, when engaged by the drill bit \n1411\n, the whipstock \n1410\n may push the drill bit \n1411\n sideways, off its current trajectory.', 'In the present embodiment, a pad \n1439\n, extendable from an exterior of a drill string \n1412\n secured to the drill bit \n1411\n, may include a geometry \n1430\n configured to be slidably received within a mating geometry \n1431\n of the whipstock \n1410\n.', 'In this configuration, the geometry \n1430\n of the pad \n1439\n may align with the geometry \n1431\n of the whipstock \n1410\n when in proximity thereto to combine the force exerted by extension of the pads \n1439\n with push of the whipstock \n1410\n for greater severity when altering trajectory of advancement of the drill bit \n1411\n.', 'FIGS.', '15-1, 15-2, and 15-3\n illustrate another embodiment of a ratcheting device \n1500\n, similar to the embodiment described above with reference to \nFIG.', '5-4\n.', 'As shown, the ratcheting device \n1500\n may include a valve element \n1502\n and a valve housing \n1504\n.', 'The valve element \n1502\n may be positioned in the valve housing \n1504\n and may define an indexing slot \n1506\n.', 'The indexing slot \n1506\n may be similar in shape to the slot \n554\n-\n5\n (\nFIG.', '5-4\n), and may extend partially or entirely around the circumference of the valve element \n562\n.', 'The valve element \n1502\n may further include one or more fingers \n1507\n.', 'Ports \n1509\n may be defined between the fingers \n1507\n.', 'The ratcheting device \n1500\n may also include a biasing member \n1508\n, such as a spring that is coiled around or within the valve element \n1502\n (or both, as shown).', 'The biasing member \n1508\n may be configured to bear against the valve housing \n1504\n, either directly or via connection with another member, and the valve element \n1502\n, so as to push the valve element \n1502\n in an axial direction (e.g., to the right, as shown) with respect to the valve housing \n1504\n.', 'The ratcheting device \n1500\n may further include an indexing pin \n1510\n, which may extend inwards from the valve housing \n1504\n, and may be received into the indexing slot \n1506\n.', 'When the valve element \n1502\n moves with respect to the valve housing \n1504\n, the indexing pin \n1510\n advances in the indexing slot \n1506\n, and translates some of the axial motion of the valve element \n1502\n into rotational movement thereof.', 'The housing \n1504\n may define openings \n1520\n therein and an inlet opening \n1521\n.', 'Drilling fluid pressure acts on the valve element \n1502\n through the inlet opening \n1521\n.', 'When the ratcheting device (valve) \n1500\n is in an open position, the ports \n1509\n of the valve element \n1502\n may be aligned with the openings \n1520\n, allowing fluid communication through the ratcheting device \n1500\n.', 'When the ratcheting device \n1500\n is in a closed position, whether caused by the fingers \n1507\n being rotationally aligned with and thereby blocking the openings \n1520\n or the valve element \n1502\n being pushed axially toward the right, such that the ports \n1509\n are axially misaligned from the openings \n1520\n, fluid is prevented from proceeding through the openings \n1520\n.', 'Referring now specifically to \nFIG.', '15-3\n, but with continuing reference to \nFIGS.', '15-1 and 15-2\n, there is shown an embodiment of the ratcheting device \n1500\n positioned in a housing \n1550\n.', 'Similar to the embodiment described above, radially extendable structures (e.g., pistons) \n1552\n may be positioned on or in the exterior of the housing \n1550\n.', 'The structures \n1552\n may be extendable in response to and propelled outwards by pressure selectively communicated thereto from the interior of the housing \n1550\n.', 'In order to control the communication of such pressure, the ratcheting device \n1500\n is provided.', 'Drilling fluid pressure acts on the valve element \n1502\n via the inlet opening \n1521\n, pushing the valve element \n1502\n (e.g., to the left in \nFIG.', '15-2\n) in the housing \n1504\n.', 'The axial motion of the valve element \n1502\n, as it overcomes the biasing member \n1508\n, is partially converted to rotational movement by the interaction between the slot \n1506\n and the pin \n1510\n, thereby causing the ports \n1509\n to align with the openings \n1520\n.', 'Thus, fluid pressure communicates to the structures \n1552\n, which extend outwards.', 'When the pressure is released, the valve element \n1502\n is pushed axially back to the right, and rotates again by interaction with between the slot \n1506\n and the pin \n1510\n back to closed, thereby allowing the structures \n1552\n to retract.', 'FIG.', '16\n illustrates a steering system \n1600\n which employs a mechanical actuation for radially extendable structures \n1604\n (e.g., pistons or pads), according to an embodiment.', 'The structures may be oriented relative to the tool-face angle of the drill bit.', 'While sliding, the structures can be actuated using drilling mud pressure to bias the drill string causing the system to drill a desired direction and dog leg (curve).', 'The structures can be deactivated for periods when the drill string is rotating.', 'A valve may be employed, and may be changed mechanical between open and closed.', 'The change in state of the valve can be achieved via axial or rotational movement.', 'The change in valve state may be achieved by temporarily increasing mud pressure above a certain value to trigger the switching.', 'One mechanism that may achieve this is a cam-piston system, as shown, which includes a rotatable cam \n1602\n and a plurality of internal pistons \n1604\n.', 'When circulating, pressure may act against an internal piston \n1604\n and cam system, which stops in a pre-defined location.', 'Depending upon the location of the cam \n1602\n, ports either align with ports to the piston chamber to activate the tool, or do not align with those ports, and no activation takes place.', 'The tool is indexed through a sequence of pressures, which change the track upon which the cam piston is guided.\n \nFIG.', '17\n illustrates a downhole steering system \n1700\n, according to an embodiment.', 'In this embodiment, a connector block \n1702\n of the system \n1700\n, which may be a full ring, is attached to the lower end of a housing \n1704\n of the steering system \n1700\n.', 'The connector block \n1702\n can be connected in any suitable manner, such as by bolts, threaded in a way that the main ring body does not need to rotate so it can align with the exposed components, or another retention feature.', 'The connector block \n1702\n contains the connectors and wiring as well as the radially-extendable structures \n1706\n.', 'The structures \n1706\n may be pistons (\nFIG.', '17-1\n) or pads (\nFIG.', '17-2\n).', 'Whereas certain embodiments have been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present disclosure.'] | ['1.', 'A downhole steering system, comprising:\na substantially tubular housing;\na shaft positioned within the substantially tubular housing and rotatable with respect thereto;\na first bearing and a second bearing, the first and second bearings being configured to support rotation of the shaft relative to the housing, wherein the first bearing, the second bearing, the shaft, and the housing at least partially define a chamber therebetween;\nat least one extendable structure positioned axially between the first and second bearing and being configured to extend from an exterior of the housing in response to pressure communicated to the chamber; and\na control device configured to control pressure communication between the chamber and the at least one extendable structure, wherein the control device is positioned axially between the first and second bearings.', '2.', 'The downhole steering system of claim 1, wherein pressure is communicated to the chamber via one or more flow passages defined in the first bearing.', '3.', 'The downhole steering system of claim 2, wherein the first bearing comprises an inner journal and an outer housing, the inner journal and the outer housing defining a clearance therebetween that provides at least a portion of the one or more flow passages.', '4.', 'The downhole steering system of claim 2, wherein the second bearing defines one or more flow passages extending therethrough, so as to allow pressure communication with the chamber across the second bearing.', '5.', 'The downhole steering system of claim 4, wherein the first bearing is positioned uphole of the chamber, the second bearing is positioned downhole of the chamber, the first bearing is configured to maintain a first pressure differential, and wherein the second bearing is configured to maintain a second differential, the second differential being greater than the first differential.', '6.', 'The downhole steering system of claim 5, wherein the first bearing is positioned uphole of the chamber, and wherein the second bearing is positioned downhole of the chamber.', '7.', 'The downhole steering system of claim 2, wherein the one or more flow passages of the first bearing comprise a groove on a surface of the first bearing, the groove extending at least partially axially across the first bearing.', '8.', 'The downhole steering system of claim 1, wherein the control device is configured to communicate or block pressure communication between the chamber and the at least one extendable structure in response to a drilling fluid flow rate, a drill bit rotation speed, or both.\n\n\n\n\n\n\n9.', 'The downhole steering system of claim 1, wherein the control device comprises a biasing member and a valve element configured to block or allow communication between the chamber and the at least one extendable structure.', '10.', 'The downhole steering system of claim 9, wherein the valve element comprises an indexing slot, such that a downward stroke of the valve element causes a pin to advance in the indexing slot and rotate the valve, and wherein the biasing member is configured to force the valve element in an upstroke, so as to further advance the pin in the indexing slot and again rotate the valve.', '11.', 'The downhole steering system of claim 1, wherein the control device comprises one or more sensors configured to receive a communication from uphole of the control device, and wherein the control device is configured to actuate a valve in response to the communication to block or allow communication between the chamber and the at least one extendable structure.', '12.', 'The downhole steering system of claim 1, wherein the control device comprises one or more sensors configured to measure one or more of:\na distance extended or force exerted by the at least one extendable structure;\ndirection, inclination, angular position, rotation, lateral displacement, or a combination thereof, of the housing; or\na property of a formation surrounding the housing.', '13.', 'The downhole steering system of claim 1, wherein the at least one structure comprises a piston that is located axially between the first and second bearings.', '14.', 'The downhole steering system of claim 1, wherein the shaft is secured to a drill bit and at least one cutting element is exposed on the shaft adjacent to the drill bit.', '15.', 'The downhole steering system of claim 1, wherein the shaft at least partially defines a hole extending radially from a hollow interior of the shaft to the chamber.', '16.', 'The downhole steering system of claim 1, wherein the shaft is secured to a drill bit, and the at least one extendable structure is axially positioned a distance from a distal end of the drill bit equal to or less than two times a diameter of the drill bit.', '17.', 'A drilling system, comprising:\na drill bit;\na shaft coupled to the drill bit, wherein rotation of the shaft causes the drill bit to rotate;\na substantially tubular housing positioned around at least a portion of the shaft between the drill bit and a mud motor of the drilling system, wherein the shaft and the drill bit are rotatable relative to the housing;\na first bearing and a second bearing, the first and second bearings being configured to support rotation of the shaft relative to the housing, wherein the first bearing, the second bearing, the shaft, and the housing at least partially define a chamber therebetween;\none or more radially-extendable pistons positioned axially between the first and second bearings and in pressure communication with the chamber, the one or more pistons being configured to extend outward of an exterior of the housing in response to pressure communicated to the chamber; and\na valve configured to control pressure communication between the chamber and the radially-extendable pistons, wherein the valve is configured to actuate in response to a rotation speed of the housing, a drilling fluid pressure or velocity, or both, wherein the valve comprises: a valve element, comprising an indexing slot, such that a downward stroke of the valve element causes a pin to advance in the indexing slot and rotate the valve; and a biasing member configured to force the valve element in an upstroke, so as to further advance the pin in the indexing slot and again rotate the valve.', '18.', 'A method for steering a drill bit, comprising:\ndeploying the drill bit and a downhole steering system into a wellbore, the downhole steering system comprising: a substantially tubular housing; a shaft positioned within the substantially tubular housing; a first bearing and a second bearing, the first and second bearings being configured to support rotation of the shaft relative to the housing, wherein the first bearing, the second bearing, the shaft, and the housing at least partially define a chamber therebetween; at least one extendable structure positioned axially between the first and second bearing and being configured to extend from an exterior of the housing in response to pressure communicated to the chamber;\nflowing drilling fluid into the downhole steering system, between the shaft and the tubular housing, such that the shaft is rotated relative to the tubular housing, wherein rotation of the shaft causes the drill bit to rotate; and\nactuating a valve so as to allow pressure communication between the chamber and the at least one structure, such that the at least one extendable structure extends radially outward and engages a wellbore, wherein the valve is positioned axially between the first and second bearing.'] | ['FIG.', '1 is an orthogonal view of an embodiment of an earth-boring operation.; FIG.', '2 is a perspective view of an embodiment of a drill bit and a downhole steering system.; FIG.', '3 is a longitude-sectional view of an embodiment of a drill bit, a motor, and a downhole steering system.; FIG.', '4-1 is a cross-sectional view of an embodiment of a downhole steering system.; FIG.', '4-2 is perspective view of another embodiment of a downhole steering system.; FIG.', '4-3 is a longitude-sectional view of an embodiment of a drill bit and a downhole steering system.; FIG.', '5-1 is a longitude-sectional view of an embodiment of a drill string wherein a mass may block and unblock an opening leading to a pressurized chamber based on rotation of the drill string.; FIG.', '5-2 is a longitude-sectional view of an embodiment of a drill string wherein a mass may block and unblock an opening leading to a pressurized chamber based on a flow rate of drilling fluid passing through the drill string.; FIG.', '5-3 is a longitude-sectional view of an embodiment of a drill string wherein a plurality of balls traveling within drilling fluid passing through the drill string may get caught in a slidable trap that may block an opening leading to a pressurized chamber.; FIG.', '5-4 is a schematic view of an embodiment of a pin that may travel in a cam slot to index between blocking and unblocking positions.; FIG.', '5-5 is a longitude-sectional view of an embodiment of a drill string wherein a disk may be ruptured by an increase in drilling fluid pressure to bypass a pressurized chamber.; FIG.', '6-1 is a longitude-sectional view of an embodiment of a control mechanism comprising a direction and inclination sensor.; FIG.', '6-2 is a longitude-sectional view of an embodiment of a control mechanism including a formation property sensor.; FIG.', '6-3 is a longitude-sectional view of an embodiment of a control mechanism including an acoustic receiver.; FIG.', '6-4 is a longitude-sectional view of an embodiment of a control mechanism including a pressure sensor.; FIG.', '6-5 is a schematic representation of an embodiment of a control mechanism including a communications wire.; FIGS.', '7-1, 7-2 and 7-3 are perspective views of different embodiments of bearings.; FIGS. 8-1 and 8-2 are perspective views of embodiments of a three-dimensional printing operation and coating operation, respectively.; FIGS.', '9-1 and 9-2 are orthogonal views of different embodiments of bearings while FIG.', '9-3 is a longitude-sectional view of an embodiment of another type of bearing.', '; FIG.', '10-1 is a magnified longitude-sectional view of an embodiment of an axial support ring while FIG.', '10-2 is a longitude-sectional view of an embodiment of a flow restrictor and filter.; FIG.', '11 is a longitude-sectional view of an embodiment of oil lubricated bearings.; FIG.', '12 is a longitude-sectional view of an embodiment of a shaft including a cavity therein sized to receive proximal ends of extendable pads.; FIG. 13 is an orthogonal view of an embodiment of a downhole steering system including a combination of both extendable pads and a bent sub.; FIG.', '14 is a perspective view of an embodiment of a downhole steering system including a combination of both extendable pads and a mating whipstock.; FIG.', '15-1 illustrates a sectional view of an embodiment of a ratcheting valve device.; FIG.', '15-2 illustrates a perspective view of an embodiment of a valve element for the ratcheting valve device.; FIG.', '15-3 illustrates a perspective view of an embodiment of a downhole steering system including the ratcheting valve device.', '; FIG.', '16 illustrates a conceptual end view of an embodiment of a cam-piston valve actuator.; FIGS.', '17-1 and 17-2 illustrate perspective views of two other embodiments of a steering system.; FIG.', '1 shows an embodiment of an earth-boring operation 110 that may be used when exploring for or extracting oil, gas or geothermal energy deposits from the earth.', 'The earth-boring operation 110 may include a drill bit 111 secured to one end of a drill string 112 suspended from a derrick 113.', 'The drill bit 111 may be rotated to degrade subterranean formations 114, forming a wellbore 115 therein and allowing the drill bit 111 to advance.', '; FIG.', '2 shows an embodiment of a drill bit 211 secured on an end of a drill string 212.', 'The drill bit 211 may comprise a plurality of cutters 220 arranged on distal edges of a plurality of blades 221 extending from and spaced about the drill bit 211.', 'As the drill bit 211 is rotated the cutters 220 may engage and degrade an earthen formation.', 'A variety of known drill bit styles may be swapped for the style shown and perform similarly.; FIG.', '4-2 shows one embodiment of the pads 439-2 arranged on an exterior of a substantially tubular housing 433-2.', 'As shown, sets 451-2 of three pads 439-2, each extendable from the exterior, may be spaced longitudinally along the housing 433-2.', 'Each of the sets 451-2 may include one pad positioned equidistant and axially displaced, in a staggered configuration, between pairs of double pads spaced longitudinally along the housing 433-2.', 'In other embodiments, other configurations are possible, such as rows of double pads without center pads.', 'While the illustrated embodiment includes eight extendable pads, other embodiments may have from one to twelve pads, such as three, nine (such as shown in FIG. 2), eleven or any other suitable number of pads.', 'In addition, while two specific configurations have been shown in FIG.', '2 and FIG.', '4-2, any suitable configuration may be used.', 'For example, pads could be located on any suitable number (such as one to four or more) of axial rows and (one to five or more) circumferential rows.; FIG.', '4-3 shows an embodiment of a drill bit 411-3 secured to a shaft 432-3 positioned within a housing 433-3.', 'The housing 433-3 may include a plurality of extendable pads 439-3 disposed on the same side of the housing 433-3 as a control mechanism 401-3.', 'Specifically, the control mechanism 401-3 may be positioned within the same angular range, one-third of a full rotation about the housing 433-3, as the pads 439-3.', 'As also can be seen in this embodiment, to make space for the housing 433-3 when located within a curved wellbore, an exterior of the housing 433-3 may taper longitudinally from a diameter 459-3 adjacent the drill bit 411-3 to a diameter 458-3 closer to a drill string secured to the housing 433-3 opposite the drill bit 411-3.; FIG.', '6-1 shows an embodiment of a control mechanism 601-1 configured to actuate a valve 637-1.', 'The control mechanism 601-1 includes a sensor 660-1 configured to measure direction and inclination of the control mechanism 601-1 via a three-axis accelerometer that may measure accelerations in x, y and z directions, respectively.', 'While a three-axis accelerometer is illustrated, those of skill in the art will recognize that a variety of other sensor types could additionally or alternately be used.', 'Further, in some embodiments, other characteristics of a substantially tubular housing, such as angular position or rotation, may be measured by such a sensor device.', 'Other embodiments may measure a lateral displacement of a substantially tubular housing relative to a wellbore.', 'Such measurements may be made by a caliper-like sensor or by a determination of pad stroke length.', 'In various embodiments, such a control mechanism may be powered by batteries or a generator configured to convert energy from a flowing drilling fluid to electricity to energize a valve and/or sensor.; FIG.', '6-2 shows another embodiment of a control mechanism 601-2 configured to actuate a valve 637-2.', 'This control mechanism 601-2 includes a series of sensors 660-2 configured to measure a property of a formation proximate the sensors 660-2.', 'In this embodiment, the sensors 660-2 are configured to measure electrical resistivity of an adjacent formation.', 'This may be accomplished by injecting current into the formation via a first electrode, surrounded by an insulating ring, of one of the sensors 660-2 and receiving current from the formation via a second electrode of another of the sensors 660-2.', 'While resistivity sensors are featured in the embodiment shown, those of skill in the art will recognize that a variety of other sensor types could alternately be used to measure any of a variety of formation properties.', '; FIG.', '6-3 shows an embodiment of a control mechanism 601-3 housed within a sidewall of a portion of a substantially tubular housing 633-3.', 'The control mechanism 601-3 includes an acoustic receiver 660-3 configured to detect acoustic waves propagating through the housing 633-3.', 'Specifically, the acoustic receiver 660-3 may include a plurality of piezoelectric crystals positioned such that they contact the housing 633-3.', 'Acoustic waves propagating through the housing 633-3 may apply mechanical stress to the piezoelectric crystals causing an electric charge to accumulate therein.', 'These acoustic waves may carry information or directions to the control mechanism to guide it in its actuation of a valve 637-3 and be sent from another downhole tool or from a surface of a wellbore.', 'While piezoelectric crystals have been shown in this embodiment, those of skill in the art will recognize that a selection of other sensor types may alternately be used and produce similar results.', '; FIG.', '6-4 shows another embodiment of a control mechanism 601-4 housed within a sidewall of a portion of a substantially tubular housing 633-4.', 'The control mechanism 601-4 includes a pressure sensor 660-4 configured to measure pressure waves propagating through a fluid flowing through the housing 633-4.', 'Such pressure waves may originate from a wellbore inlet or a downhole device, such as a measurement-while-drilling unit disposed axially beyond first or second bearings, and/or a mud motor, from a control mechanism.', 'Pressure waves generated by a measurement-while-drilling unit and intended for a wellbore inlet may be received and comprehended by a control mechanism as described.', 'In some embodiments, actuation of a valve of the sort shown may create pressure waves in fluid that may be discernible at a wellbore inlet or another downhole device, allowing for two-way communication.; FIG.', '6-5 shows yet another embodiment of a control mechanism 601-5 housed within a sidewall of a substantially tubular housing 633-5.', 'In this embodiment, a downhole device 662-5, such as a measurement-while-drilling unit, may be disposed on an opposite side of a mud motor 663-5 from the control mechanism 601-5.', 'The downhole device 662-5 may comprise its own detection and measurement equipment, separate from any sensors forming part of the control mechanism 601-5.', 'Such detection and measurement equipment, of the downhole device 662-5, may be larger and more sophisticated due to it being positioned axially farther from a drill bit than the control mechanism 601-5.', 'Thus, more detailed and complex information may be gathered by the downhole device 662-5.', 'The downhole device 662-5 may transmit at least some of this data to the control mechanism 601-5.', 'In the embodiment shown, this data is transmitted to the control mechanism 601-5 via a communications wire 664-5 that may bypass the mud motor 663-5 through a sidewall thereof.', 'The control mechanism 601-5 may actuate a valve 637-2 based on this transmitted information.', 'In other embodiments, a measurement-while-drilling unit, or other downhole device, may transmit data past a mud motor to a valve control mechanism via acoustic waves propagating through a housing or pressure waves propagating through a fluid.; FIGS.', '7-1 and 7-2 show embodiments of bearings 734-1 and 734-2, respectively, including journals 770-1, 770-2 that are movable with respect to housings 771-1, 771-2.', 'The bearings 734-1, 734-2 include fluid passages, such as clearances 772-1, 772-2 formed between the journals 770-1, 770-2 and housings 771-1, 771-2 that may allow drilling fluid to flow therebetween while restricting larger particulates.', 'Tolerances in the clearances 772-1, 772-2 provided to maintain concentricity of the journals 770-1, 770-2 and housings 771-1, 771-2, may impede the ability to establish and maintain sufficient fluid pressure within a chamber.', 'Accordingly, the bearing 734-1, 734-2 may define flow passage geometries through which additional drilling fluid may pass.; FIG.', '7-1 shows a geometry including a plurality of grooves 773-1 disposed on an exterior of the journal 770-1 sitting parallel to a rotational axis 774-1 thereof.', 'Another plurality of grooves 775-1 may be disposed on an interior of the housing 771-1.', 'The combination of grooves 773-1, 775-1 may include a total cross-sectional area sufficient to allow up to 30 gallons per minute or 5% of a total flow of drilling fluid flowing through a drill string to pass the bearing 734-1.', 'In other embodiments, this area may allow up to 60 gallons per minute, or 10% of a total, or more to pass.; FIG.', '7-2 shows another geometry including a plurality of grooves 773-2 disposed on an exterior of the journal 770-2 and another plurality of grooves 775-2 disposed on an interior of the housing 771-2.', 'Each of these grooves 773-2, 775-2 may curve around a rotational axis 774-2 of the bearing 734-2 to form a helical path.', 'Such curved grooves 773-2, 775-2 may aid in cleaning the exterior of the journal 770-2 and the interior of the housing 771-2.; FIG.', '7-3 shows an embodiment of a bearing 734-3 including a journal 770-3 rotatable within a housing 771-3.', 'The housing 771-3 includes a plurality of conduits 776-3 extending along a length thereof and allowing a drilling fluid to flow therethrough.', 'In other embodiments, conduits may be disposed within a journal as well or forming helical paths.; FIG.', '9-1 shows an embodiment of a bearing 934-1 including a plurality of grooves 975-1 disposed on an interior of a housing 971-1 and sitting parallel to a rotational axis 974-1 thereof.', 'As can be seen, each of the grooves 975-1 may extend only part way along an axial length of the bearing 934-1.', 'Additionally, each of the grooves 975-1 may extend from opposing ends alternatingly.', 'Grooves of this and similar geometries may increase an area for fluid flow between a journal and housing.', 'Such grooves may also allow for cleaning and lubrication while blocking large particulate.', '; FIG.', '9-2 shows another embodiment of a bearing 934-2 including a plurality of grooves 975-2 disposed on an interior of a housing 971-2.', 'In this embodiment, the grooves 975-2 are cross-sectionally larger on a first end 990-2 than on an opposing second end 991-2.', 'Positioning the second end 991-2 facing toward a chamber and second bearing may allow the bearing 934-2 to act like a compressor in that large amounts of drilling fluid may enter the grooves 975-2 at the first end 990-2 and then be forced into a smaller space at the second end 991-2 as the housing 971-2 rotates relative to a journal.', 'By so doing, a fluid pressure within the chamber may be greater than before entering through the bearing 934-2.', 'Additionally, the fluid pressure within the chamber may be dependent and at least somewhat regulated by a rotational speed of the housing 971-2 relative to the journal.', '; FIG.', '9-3 shows another embodiment of a bearing 935-3 including discrete superhard elements 993-3 (e.g., polycrystalline diamond, cubic boron nitride, carbon nitride or boron-nitrogen-carbon structures) secured within cavities on an internal surface 992-3 thereof.', 'The internal surface 992-1 may include hard cladding (e.g., tungsten and tungsten carbide) brazed thereto.', 'Such features may prolong the life of these types of bearings.; FIG.', '10-1 shows an embodiment of a ring 1094-1 that may be disposed between a shaft 1032-1 and a substantially tubular housing 1033-1.', 'The ring 1094-1 rests axially between a second bearing 1035-1 and an internal ledge formed in the housing 1033-1, although other configurations are possible.', 'This ring 1094-1 may allow the second bearing 1035-1 and an axially spaced first bearing (not shown) to support the shaft 1032-1 axially relative to the housing 1033-1 as well as radially.; FIG.', '10-2 shows an embodiment of another type of ring, this time forming a flow restrictor 1094-2.', 'The ring forming this flow restrictor 1094-2 may be retained axially, but otherwise float freely between a shaft 1032-2 and a housing 1033-2.', 'In this configuration, the flow restrictor 1094-2 may impede fluid flow passing between the shaft 1032-2 and the housing 1033-2.', 'Restricting or impeding this fluid flow may reduce wear on a second bearing 1035-2 that also interacts with the flow.', '; FIG.', '10-2 also shows an embodiment of a filter 1010-2 that may screen particulate matter of a given size traveling with the fluid flow from reaching a valve 1037-2 or extentable pads 1039-2 there beyond.', 'Thus, this filter 1010-2 may reduce wear on the valve 1037-2, pads 1039-2 and internal fluid channels.; FIG.', '12 shows an embodiment of a shaft 1232 positioned within a substantially tubular housing 1233.', 'The shaft 1232 may include a cavity 1210 disposed on an external surface thereof.', 'The cavity 1210 may surround the shaft 1232 and be sufficiently sized to allow proximal ends of a plurality of extendable pads 1239 to fit therein.', 'Allowing the pads 1239 to retract into the cavity 1210 may provide for a longer pad stroke in general, thus increasing how far they may extend from an exterior of the housing 1233.', '; FIG.', '13 shows an embodiment of a downhole steering system including a plurality of pads 1339 extendable from an exterior thereof that may push off a wall of a wellbore to aid in steering a drill bit 1311.', 'In combination with the extendable pads 1339, the steering system may also include a bent sub 1310 portion of a drill string 1312.', 'In this configuration, force applied by the pads 1339 against a wall of a wellbore may either add to or take away from the already bent section of the drill string 1312 allowing for greater severity when altering trajectory of advancement of the drill bit 1311.', '; FIG.', '14 shows an embodiment of a whipstock 1410 which is a device, often shaped generally as a ramp, which may be disposed in a wellbore 1415 to alter a trajectory of a drill bit 1411 as it drills.', 'In use, when engaged by the drill bit 1411, the whipstock 1410 may push the drill bit 1411 sideways, off its current trajectory.', 'In the present embodiment, a pad 1439, extendable from an exterior of a drill string 1412 secured to the drill bit 1411, may include a geometry 1430 configured to be slidably received within a mating geometry 1431 of the whipstock 1410.', 'In this configuration, the geometry 1430 of the pad 1439 may align with the geometry 1431 of the whipstock 1410 when in proximity thereto to combine the force exerted by extension of the pads 1439 with push of the whipstock 1410 for greater severity when altering trajectory of advancement of the drill bit 1411.; FIGS.', '15-1, 15-2, and 15-3 illustrate another embodiment of a ratcheting device 1500, similar to the embodiment described above with reference to FIG.', '5-4.', 'As shown, the ratcheting device 1500 may include a valve element 1502 and a valve housing 1504.', 'The valve element 1502 may be positioned in the valve housing 1504 and may define an indexing slot 1506.', 'The indexing slot 1506 may be similar in shape to the slot 554-5 (FIG.', '5-4), and may extend partially or entirely around the circumference of the valve element 562.', 'The valve element 1502 may further include one or more fingers 1507.', 'Ports 1509 may be defined between the fingers 1507.; FIG.', '16 illustrates a steering system 1600 which employs a mechanical actuation for radially extendable structures 1604 (e.g., pistons or pads), according to an embodiment.', 'The structures may be oriented relative to the tool-face angle of the drill bit.', 'While sliding, the structures can be actuated using drilling mud pressure to bias the drill string causing the system to drill a desired direction and dog leg (curve).', 'The structures can be deactivated for periods when the drill string is rotating.; FIG.', '17 illustrates a downhole steering system 1700, according to an embodiment.', 'In this embodiment, a connector block 1702 of the system 1700, which may be a full ring, is attached to the lower end of a housing 1704 of the steering system 1700.', 'The connector block 1702 can be connected in any suitable manner, such as by bolts, threaded in a way that the main ring body does not need to rotate so it can align with the exposed components, or another retention feature.', 'The connector block 1702 contains the connectors and wiring as well as the radially-extendable structures 1706.', 'The structures 1706 may be pistons (FIG.', '17-1) or pads (FIG.', '17-2).'] |
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US11118428 | Construction of digital representation of complex compositional fluids | Nov 25, 2014 | John Ratulowski, Denis Klemin, Mark Andersen, Oleg Dinariev, Nikolay Vyacheslavovich Evseev, Evgeny Ivanov, Sergey Sergeevich Safonov, Dmitry Anatolievich Koroteev | SCHLUMBERGER TECHNOLOGY CORPORATION | Walas, S.M., “Phase Equilibria in Chemical Engineering. Boston,” Butterworth Publ., 1985 (109 pages).; Reid R.C., et al., “The Properties of Gases and Liquids. New York: Mc-Graw Hill,” 1987 (10 pages).; Firoozabadi, A., “Thermodynamics of Hydrocarbon Reservoirs,” McGraw-Hill, 1998 (83 pages).; Demianov et al., “Introduction to the density functional method in hydrodynamics”, Fizmatlit, Moscow, 2014 (4 pages).; H.B. Callen, Thermodynamics and an introduction to thermostatics, 2nd edition, John Wiley & Sons, New York, 1985 (5 pages).; Examination Report issued in the related AU application 2014357460, dated Apr. 11, 2018 (5 pages).; Dinariev, O. Yu., “A Hydrodynamic Description of a Multicomponent Multiphase Mixture in Narrow Pores and Thin Layers,” J. Appl. Math. Mech. 59, No. 5, 745-752 (1995).; Dinariev, O. Yu., “Thermal Effects in the Description of a Multicomponent Mixture Using the Density Functional Method,” J. Appl. Math. Mech. 62, No. 3, 397-405 (1998).; Demianov et al., “Density Functional Modelling in Multiphase Compositional Hydrodynamics”, 89 Can. J. Chem. Eng., 206, 211-12 (Apr. 2011).; D. Koroteev, et al,. “Application of Digital Rock Technology for Chemical EOR Screening”, SPE-165258, Kuala Lumpur, Malaysia, Jul. 2-4, 2013 (12 pages).; Sengers, Johanna Levelt, “How Fluids unmix: discoveries by the school of Van der Waals and Kamerlingh Onnes”, Amsterdam: Koninklijke NederLandse Akademie van Wetenschappen, Jan. 1, 2002 (320 pages).; International Search and Written Opinion issued in the related PCT application PCT/US2014/067462, dated Mar. 27, 2015 (14 pages).; International Preliminary Report on patentability issued in the related PCT application PCT/US2014/067462, dated Jun. 7, 2016 (10 pages).; Extended Search report issued in the related EP Application 14868095.2, dated Dec. 12, 2017 (9 pages).; Han W.S.et al., “Comparison of two different equations of state for application of carbon dioxide sequestration”, Advances in Water Resources, CML Publications, Southampton, GB, vol. 31, No. 6, Jun. 1, 2008-Dec. 1, 2017, pp. 877-890.; Examination Report issued in the related AU application 2014357460, dated Mar. 5, 2019 (5 pages). | 20090071239; March 19, 2009; Rojas et al.; 20100287123; November 11, 2010; Verma; 20110066380; March 17, 2011; Hager; 20120150519; June 14, 2012; Bang; 20120203515; August 9, 2012; Pita et al.; 20120232859; September 13, 2012; Pomerantz et al. | WO2012012126; January 2012; WO | ['A method for performing a simulation of a field having a subterranean formation is described.', 'The method includes obtaining phase behavior data of subterranean fluids of the field, generating an equation of state (EOS) model of the fluids based on the phase behavior data, generating a Helmholtz free energy model that reproduces predictions of the EOS model over a pre-determined pressure and temperature range, and performing the simulation of the field using the Helmholtz free energy model.', 'The method may further include reducing the EOS model to a reduced EOS model having a reduced number of components to represent the EOS model over a pre-determined pressure and temperature range, generating the Helmholtz free energy model based on the reduced EOS model, and obtaining and using phase behavior data of injection fluids used.', 'A computer system data.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'The present application claims priority from U.S. Provisional Application 61/911,949, filed Dec. 4, 2013, which is incorporated herein by reference in its entirety.', 'BACKGROUND\n \nOperations, such as geophysical surveying, drilling, logging, well completion, and production, are typically performed to locate and gather valuable downhole fluids.', 'Surveys are often performed using acquisition methodologies, such as seismic mapping, or resistivity mapping, to generate images of underground formations.', 'These formations are often analyzed to determine the presence of subterranean assets, such as valuable fluids or minerals, or to determine if the formations have characteristics suitable for storing fluids.', 'Although the subterranean assets are not limited to hydrocarbons such as oil, throughout this document, the terms “oilfield” and “oilfield operation” may be used interchangeably with the terms “field” and “field operation” to refer to a site where any types of valuable fluids or minerals can be found and the activities required to extract such fluids or minerals.', 'The terms may also refer to sites where substances are deposited or stored by injecting them into the surface using boreholes and the operations associated with this process.', 'Further, the term “field operation” refers to a field operation associated with a field, including activities related to field planning, wellbore drilling, wellbore completion, and/or production using the wellbore.', 'Simulations are commonly used in the oil industry and other industries to model processes and predict behaviors.', 'Each type of simulation is relevant to a certain scale of process.', 'A common example in the oil industry is the use of reservoir flow models to predict dynamic behavior at the scale of a reservoir, which can be from a few meters to hundreds of meters thick and can be thousands of meters in lateral extent.', 'The volume elements in these models are typically on the order of meters or tens of meters on a side.', 'Reservoir scale processes, such as developed miscibility, can develop within the model.', 'At the other extreme, micromodels of porous media represent small pieces of the media, typically with volume elements on the order of a few microns or less on a side and full models that are on the order of millimeters or less in extent.', 'In these models, the small size means the residence time of fluids within the model is too short for many processes to develop fully.', 'The present disclosure is within the domain of these small models.', 'Static micromodels representing pore and grain geometry can be obtained in several ways at different scales.', 'Thin sections of rocks are formed by injecting a colored epoxy into a rock and then slicing an optically thin section and mounting it onto a glass slide.', 'This is optically analyzed to obtain images of the pores and grains.', 'Multiple thin sections can be used to create a micromodel, typically using statistical distributions rather than making an image directly from stacked thin sections.', 'Alternatively, a small rock volume can be scanned using X-rays in a micro computed tomography (microCT) machine.', 'The tomographic inversion of the X-ray scans is used to create a static model of a rock with resolution ranging from tens of microns to tens of nanometers.', 'This computed tomography (CT) image is processed and segmented into grains and pores.', 'A third method uses ion beam milling and scanning electron microscopy to create a series of images with nanometer-scale resolution.', 'These images can be analyzed and used to construct a static three-dimensional (3D) model of a tiny portion of the rock.', 'Micromodels for flow-dynamic behavior in porous media are of a few types.', 'Pore network models substitute a complex network of nodes and connectors to represent the pores and pore throats, respectively.', 'The network is based on a static representation rock model, and flow dynamics are applied to the pore network.', 'Lattice Boltzmann models are based on movement of particles on a three-dimensional grid, which can be placed within a static rock model.', 'A third method uses microhydrodynamical modeling in a static rock model to represent simple or complex fluid-fluid and fluid-rock interactions during flow or while a chemical process develops.', 'The density functional theory for the compositional multiphase hydrodynamics has been disclosed in Dinariev, O. Yu., “A Hydrodynamic Description of a Multicomponent Multiphase Mixture in Narrow Pores and Thin Layers,” Journal of Applied Mathematics and Mechanics 59, No. 5, 745-752 (1995) and Dinariev, O. Yu., “Thermal Effects in the Description of a Multicomponent Mixture Using the Density Functional Method,” Journal of Applied Mathematics and Mechanics 62, No. 3, 397-405 (1998).', 'In particular, isothermal theory based on the Helmholtz energy functional is disclosed in Dinariev, 1995, and nonisothermal theory based on entropy functional is disclosed in Dinariev, 1998.', 'The up to date review of the density functional theory in compositional hydrodynamics and its applications can be found in Demianov et al., “Introduction to the density functional method in hydrodynamics”, Fizmatlit, Moscow, 2014.', 'ISBN 978-5-9221-1539-1.', 'The Helmholtz energy functional, which is also known as the Helmholtz free energy functional, is more convenient for practical applications than the entropy functional, because: a) a range of isothermal problems is wide, and b) in case of variable temperature the entropy functional can be easily derived from the Helmholtz energy functional.', 'At present, the mainstream approach in thermodynamics of multiphase fluid systems is based on the equation of state (EOS) approach described in Walas, S. M., “Phase Equilibria in Chemical Engineering”, Boston, Butterworth Publ., 1985; Reid R. C., et al., “The Properties of Gases and Liquids”, New York: Mc-Graw Hill, 1987, and Firoozabadi, A., “Thermodynamics of Hydrocarbon Reservoirs”, McGraw-Hill, 1998.', 'In the EOS workflow, a certain semi-empirical expression for pressure is postulated, while the existing free parameters are used to obtain the fit with experiment.', 'Then relevant thermodynamic potentials can be reconstructed from the EOS with the use of additional information.', 'BRIEF SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'The subject matter of the present application includes a method for performing a simulation of a field having a subterranean formation.', 'The method includes obtaining phase behavior data of subterranean fluids of the field, generating an equation of state (EOS) model of the fluids based on the phase behavior data, generating a Helmholtz free energy model that reproduces predictions of the EOS model over a pre-determined pressure and temperature range, and performing the simulation of the field using the Helmholtz free energy model.', 'The method may further include reducing the EOS model to a reduced EOS model having a reduced number of components to represent the EOS model over a pre-determined pressure and temperature range, generating the Helmholtz free energy model based on the reduced EOS model.', 'The present application further describes a computer system including a processor and memory having a reservoir production (RP) tool stored in the memory.', 'The RP tool executes on the processor and includes an input module configured to obtain phase behavior data of fluids, an EOS model generator configured to generate an EOS model of the fluids based on the phase behavior data, a free energy model generator configured to generate a Helmholtz free energy model that reproduces predictions of the EOS model over a pre-determined temperature and pressure range, and a simulator configured to perform simulation of the field using the Helmholtz free energy model.', 'The computer system further includes a repository configured to store the phase behavior data, the EOS model, and the Helmholtz free energy model.', 'In a further embodiment the present application describes a method for performing a simulation of a field having a subterranean formation, the method including obtaining phase behavior data of subterranean fluids of the field, obtaining phase behavior data of injection fluids used in the field, generating a Helmholtz free energy model that reproduces the phase behavior data of the fluids of the field over a pre-determined pressure and temperature range, and performing the simulation of the field using the Helmholtz free energy model.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The appended drawings illustrate several embodiments of construction of Helmholtz free energy or entropy functional describing thermodynamics of complex compositional fluids and are not to be considered limiting of its scope, for construction of digital representation of complex compositional fluids describing their thermodynamics may admit to other equally effective embodiments.', 'FIG.', '1\n is a schematic view, partially in cross-section, of a field in which one or more embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics may be implemented.\n \nFIG.', '2\n shows a reservoir production computer system in accordance with one or more embodiments.\n \nFIG.', '3\n shows a flowchart of a method in accordance with one or more embodiments.\n \nFIG.', '4\n depicts a computer system on which one or more embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics may be implemented.', 'DETAILED DESCRIPTION\n \nAspects of the present disclosure are shown in the above-identified drawings and described below.', 'In the description, like or identical reference numerals are used to identify common or similar elements.', 'The drawings are not necessarily to scale and certain features may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.', 'The term fluid, as used in this application, refers to a complex compositional fluid that, depending on pressure and temperature, can form one or more phases, i.e. gaseous or liquid.', 'The fluid can be either natural or manufactured.', 'A mixture of different fluids can also be referred to as fluid.', 'The term phase, as used in this application, refers to a homogeneous state of fluid having uniform properties inside of a certain spatial region.', 'Depending on the physical nature of the considered problem, the term phase can also refer to an effective phase, which has uniform properties on an appropriately larger scale.', 'For example, in many cases microemulsion can be considered an effective phase.', 'The term digital rock model, as used in this application, refers to pore and grain level models of a porous medium.', 'The resolution of these models is typically in the range of a few microns or less.', 'The digital rock model is generated based on a 3D porous solid image of a core sample.', 'A 3D porous solid image is a 3D digital representation of the core sample that is generated using computed tomography (X-ray, NMR, or other), scanning electron microscopy, focused ion beam scanning electron microscopy, confocal microscopy, or other suitable scanning means.', 'Specifically, the 3D porous solid image is an image of each portion of the core sample including pores and solid surfaces.', 'Thus, the 3D porous solid image may show pores and rock boundaries of the core sample for each layer of the core sample.', 'While the 3D porous solid image may show the physical structure of the core sample, the digital rock model may include the lithology of the core sample.', 'For example, the lithographic properties of the core sample may include pore size distribution, rock type, and tortuosity measurements.', 'Fluid flow processes may be simulated in a digital rock model using various techniques.', 'These flow processes are related to: a) subterranean fluids that are native to a rock formation, b) fluids, either natural or manufactured, injected into the rock formation from an external source, or c) a combination of the native and the external fluids (natural or/and manufactured).', 'The term core sample, as used in this application, refers to a 3D porous medium representing a portion of the oilfield, or a manufactured porous sample.', 'In particular, a core sample refers to a physical sample obtained from a portion of the oilfield or artificially manufactured.', 'For example, the core sample may be obtained by drilling into the portion of the oilfield with a core drill to extract the core sample from the portion.', 'The core sample may contain subterranean fluids, such as multiphase compositional fluids.', 'The term equation of state, as used in this application, refers to a thermodynamic equation describing the state of the fluids under a given set of physical conditions.', 'The equation of state is a constitutive equation which provides a mathematical relationship between two or more state functions associated with the fluids.', 'For example, the state functions may include temperature, pressure, volume, or internal energy.', 'The term Helmholtz free energy, as used in this application, refers to a thermodynamic potential that measures the useful work obtainable from a closed thermodynamic system at a constant temperature.', 'Similar definition is given by, for example, H. B. Callen, \nThermodynamics and an introduction to thermostatics, \n2nd edition, John Wiley & Sons, New York, 1985; or Bazarov I., \nThermodynamics\n, Oxford:', 'Pergamon Press, 1964.', 'For example, the closed thermodynamic system may be the core sample and the fluids contained in the core sample.', 'The Helmholtz free energy model refers to a mathematical model of the natural or manufactured compositional fluids based on the Helmholtz free energy.', 'Helmholtz free energy contains information describing equilibrium properties of the fluid.', 'One or more aspects of construction of a digital representation of complex compositional fluids describing their thermodynamics provide a method of laboratory fluid characterization to construct comprehensive fluid formulation for the fluid under study (e.g., the subterranean fluids extracted from a core sample).', 'The constructed fluid formulation is referred to as the fluid description and may be used in digital rock modeling, multiphase flow simulations, fluid analysis, reservoir simulation, etc.', 'In one or more embodiments, the fluid description is based on Helmholtz energy approach and is applied within the framework of the density functional (DF) method for complex pore-scale hydrodynamics.', 'In one or more embodiments, this fluid description is used to represent chemical and thermodynamic behavior of formation fluids, enhanced oil recovery (EOR) fluids, and improved oil recovery (IOR) fluids in a consistent way.', 'In order to perform mathematical modeling of fluid flow processes, tabulated functions or analytical expressions that are dependent on local temperature and local molar densities may be used for calculating the following quantities at arbitrary fluid compositions: bulk Helmholtz energy density, volume and shear viscosity (or other rheological properties including effects such as elongation viscosity and viscoelasticity), thermal and diffusion transport coefficients, surface tension between fluid and rock, and between different fluids, adsorption at fluid-rock and fluid-fluid interfaces, etc.', 'For these quantities, experimental values or experimentally validated correlations in respect to temperature and molar densities are used in one or more embodiments.', 'In order to obtain material parameters experimentally, standard and well-established laboratory methods are used such as mass density obtained by buoyancy or acoustic principles; shear viscosity being obtained from the drag force of a fluid moving past a surface also dependent on shear rate (shear rheology); advanced rheological characterization of non-Newtonian reservoir and EOR fluids (e.g., may be done by means of rotary viscometers, core flooding, measurements of adsorption, flooding within channels of controlled geometry); pendant drop tensiometers and drop shape analysis can be used to determine the interfacial tension and contact angle between fluid/fluid and fluid/fluid/solid.', 'FIG.', '1\n depicts a schematic view, partially in cross section, of a field \n100\n in which one or more embodiments of a digital representation of complex compositional fluids may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in \nFIG.', '1\n may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of a digital representation of complex compositional fluids should not be considered limited to the specific arrangements of modules shown in \nFIG.', '1\n.', 'As shown in \nFIG.', '1\n, the subterranean formation \n104\n includes several geological structures (\n106\n-\n1\n through \n106\n-\n4\n).', 'As shown, the formation includes a sandstone layer \n106\n-\n1\n, a limestone layer \n106\n-\n2\n, a shale layer \n106\n-\n3\n, and a sand layer \n106\n-\n4\n.', 'A fault line \n107\n extends through the formation.', 'One or more of the geological structures (\n106\n-\n1\n through \n106\n-\n4\n) may be part of a reservoir (e.g., reservoir \n106\n-\n5\n) of subterranean fluids.', 'In one or more embodiments, various survey tools and/or data acquisition tools (e.g., data acquisition tool \n109\n) are adapted to measure the formation and detect the characteristics of the geological structures of the formation and/or subterranean fluids contained in the geological structures.', 'Further, as shown in \nFIG.', '1\n, the wellsite system \n110\n is associated with a rig \n101\n, a wellbore \n103\n, and other wellsite equipment and is configured to perform wellbore operations, such as logging, drilling, fracturing, production, or other applicable operations.', 'Generally, survey operations and wellbore operations are referred to as field operations of the field \n100\n.', 'These field operations may be performed as directed by the surface unit \n112\n.', 'In one or more embodiments, the surface unit \n112\n is operatively coupled to a reservoir production (RP) computer system \n208\n and/or the wellsite system \n110\n.', 'In particular, the surface unit \n112\n is configured to communicate with the RP computer system \n208\n and/or the wellsite system \n110\n to send commands to the RP computer system \n208\n and/or the wellsite system \n110\n and to receive data therefrom.', 'For example, the wellsite system \n110\n may be adapted for measuring downhole properties using logging-while-drilling (LWD) tools and for obtaining core samples.', 'In one or more embodiments, the surface unit \n112\n may be located at the wellsite system \n110\n and/or remote locations.', 'The surface unit \n112\n may be provided with computer facilities for receiving, storing, processing, and/or analyzing data from the RP computer system \n208\n, the wellsite system \n110\n, or other part of the field \n100\n.', 'The surface unit \n112\n may also be provided with functionality for actuating mechanisms at the field \n100\n.', 'The surface unit \n112\n may then send command signals to the field \n100\n in response to data received, for example to control and/or optimize various field operations described above.', 'In one or more embodiments, the data received by the surface unit \n112\n represents characteristics of the subterranean formation \n104\n and may include seismic data and/or information related to porosity, saturation, permeability, natural fractures, stress magnitude and orientations, elastic properties, etc. during a drilling, fracturing, logging, or production operation of the wellbore \n103\n at the wellsite system \n110\n.', 'In one or more embodiments, the surface unit \n112\n is communicatively coupled to the RP computer system \n208\n.', 'Generally, the RP computer system \n208\n is configured to analyze, model, control, optimize, or perform other management tasks of the aforementioned field operations based on the data provided from the surface unit \n112\n.', 'Although the surface unit \n112\n is shown as separate from the RP computer system \n208\n in \nFIG.', '1\n, in other examples, the surface unit \n112\n and the RP computer system \n208\n may also be combined.', 'While a specific subterranean formation \n104\n with specific geological structures is described above, it will be appreciated that the formation may contain a variety of geological structures.', 'Fluid, rock, water, oil, gas, and other geomaterials may also be present in various portions of the formation \n104\n.', 'Further, one or more types of measurement may be taken at one or more locations across one or more fields or other locations for comparison and/or analysis using one or more acquisition tools.', 'Although many wells (e.g., hundreds of wells) are typically present in a field, only a single well with a single well log is explicitly shown in the field \n100\n for clarity of illustration.\n \nFIG.', '2\n shows more details of the RP computer system \n208\n in which one or more embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in \nFIG.', '2\n may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics should not be considered limited to the specific arrangements of modules shown in \nFIG.', '2\n.', 'As shown in \nFIG.', '2\n, the RP computer system \n208\n includes RP tool \n230\n, data repository \n234\n, and display \n233\n.', 'Each of these elements is described below.', 'In one or more embodiments, the RP computer system \n208\n includes the RP tool \n230\n having software instructions stored in a memory and executing on a processor to communicate with the surface unit \n112\n for receiving data (e.g., phase behavior data \n235\n) therefrom and to manage (e.g., analyze, model, control, optimize, or perform other management tasks) the aforementioned field operations based on the received data.', 'In one or more embodiments, the phase behavior data \n235\n is received by the input module \n221\n and stored in the data repository \n234\n to be processed by the RP tool \n230\n.', 'One or more field operation management tasks (e.g., analysis task, modeling task, control task, optimization task, etc.) may be performed using the RP tool \n230\n.', 'In particular, the phase behavior data \n235\n are manipulated to generate, continuously or intermittently, preliminary and final results that are stored and displayed to the user.', 'For example, the RP tool \n230\n may be used to perform Helmholtz free energy model generation, multiphase flow simulation, fluid analysis, reservoir simulation, etc. where the EOS model generator \n222\n, Helmholtz free energy model generator \n223\n, and/or simulator \n224\n process the phase behavior data \n235\n to generate the EOS model \n236\n, Helmholtz free energy model \n237\n, and/or simulation results \n238\n, that are selectively displayed to the user using the display \n233\n.', 'In one or more embodiments, the display \n233\n may be a two-dimensional (2D) display, a 3D display, or other suitable display device.', 'The processor and memory of the RP computer system \n208\n are not explicitly depicted in \nFIG.', '2\n so as not to obscure other elements of the RP computer system \n208\n.', 'An example of such processor and memory is described in reference to \nFIG.', '4\n below.', 'In one or more embodiments, the RP tool \n230\n includes the input module \n221\n that is configured to obtain the phase behavior data \n235\n of subterranean fluids extracted from a core sample obtained in a portion of the field \n104\n shown in \nFIG.', '1\n above.', 'In particular, the phase behavior data \n235\n represents measured properties of the subterranean fluids.', 'For example, the phase behavior data \n235\n may be obtained from laboratory fluid characterization based on the specific protocols complemented by the workflows for laboratory data processing.', 'Laboratory fluid measurements may include different measurement techniques, laboratory equipment, and operating protocols to measure properties that include but are not limited with the following:\n \n(i) Pressure/volume/temperature (PVT) behavior in a multiphase system, such as a two-phase compositional system (e.g., gas-oil system, oil-water-solvent system, etc.), a three-phase compositional system (e.g., gas-water-hydrate system, water-oil-microemulsion system, etc.), etc.;\n \n(ii) Fluid-fluid and fluid-solid surface phenomena, such as interfacial tension (IFT), surfactants, adsorption, wetting angles, etc.;\n \n(iii) Rheological properties, such as shear and volume viscosity, non-linear viscous effects, viscoelasticity, viscoelasticity, etc.\n \nTABLE 1 lists example laboratory analyses that may be performed to generate these measured properties that are saved in the data repository \n234\n as the phase behavior data \n235\n.', 'TABLE 1\n \n \n \n \n \n \n \n \nStandard PVT Tests\n \n \n \n\u2003\u2003\u2003\u2003Composition, molecular weight, and density\n \n \n \n\u2003\u2003\u2003\u2003Multiple and single stage flash data (separator tests)\n \n \n \n\u2003\u2003\u2003\u2003Density, compressibility, and viscosity measurements\n \n \n \n\u2003\u2003\u2003\u2003Constant composition expansion\n \n \n \n\u2003\u2003\u2003\u2003Differential liberation\n \n \n \n\u2003\u2003\u2003\u2003Constant volume depletion\n \n \n \nSolvent/Gas Studies\n \n \n \n\u2003\u2003\u2003\u2003Swelling test (P-x Diagram)', 'Single contact vapor-liquid equilibrium (VLE) experiments\n \n \n \n\u2003\u2003\u2003\u2003including phase compositions\n \n \n \n\u2003\u2003\u2003\u2003Forward and backward multi-contact experiments\n \n \n \n\u2003\u2003\u2003\u2003Slimtube, rising bubble or other developed miscibility tests\n \n \n \n\u2003\u2003\u2003\u2003Density, compressibility, and viscosity measurements\n \n \n \n\u2003\u2003\u2003\u2003Interfacial tension measurements\n \n \n \nChemical/Polymer Studies\n \n \n \n\u2003\u2003\u2003\u2003Surfactant/brine/oil phase behavior studies\n \n \n \n\u2003\u2003\u2003\u2003Interfacial tension measurements\n \n \n \n\u2003\u2003\u2003\u2003Rheological measurements\n \n \n \n\u2003\u2003\u2003\u2003Density and compressibility measurements', 'In one or more embodiments, the phase behavior data \n235\n (e.g., laboratory data obtained from the laboratory analyses listed in TABLE 1) is used directly as input for the construction of the Helmholtz free energy model \n237\n.', 'In one or more embodiments, the phase behavior data \n235\n is used to tune appropriate correlations or the EOS model \n236\n, which are then used to generate the input data for construction of the Helmholtz free energy model \n237\n.', 'In one or more embodiments, un-tuned correlations and/or un-tuned EOS model \n236\n are used to generate the input data for construction of the Helmholtz free energy model \n237\n.', 'Components in the input data for the Helmholtz free energy models may be represented in several ways.', 'Several, but not all, of these representations are described below.', 'In one or more embodiments, the fluids include well-defined chemical species, such as methane, water, carbon dioxide, etc.', 'In such embodiments, known and/or measured properties (e.g., phase behavior data \n235\n) of these well defined chemical species are used as input for the construction of the Helmholtz free energy model \n237\n.', 'In one or more embodiments, the fluids include lumped pseudo components, such as C\n7\n+ (oil components with normal boiling points greater than n-hexane), C\n10\n-C\n16 \n(oil components with normal boiling points between n-nonane and n-hexadecane), etc.', 'In such embodiments, properties of these components (used as the input data for the Helmholtz free energy models) are calculated through a combination of correlations and mixing rules, and are tuned to laboratory measured data (i.e., phase behavior data \n235\n).', 'In one or more embodiments, the fluids include process-specific pseudo components, such as the gas and oil components in a black oil model, the gas, light and heavy components in a ternary description of a gas injection process, etc.', 'These components are defined through a specific process path.', 'For example, the oil and gas for the black oil model components are defined through a differential liberation and separator test.', 'In such embodiments, properties of these components (used as the input data for the Helmholtz free energy models) are generated from a tuned EOS model \n236\n.', 'In one or more embodiments, the RP tool \n230\n includes the EOS model generator configured to generate thermodynamic and rheological models (e.g., the EOS model \n236\n) of the fluids based on the phase behavior data \n235\n.', 'In one or more embodiments, the EOS model \n236\n is a true compositional model or a pseudo-compositional model similar to the ternary diagram known to those skilled in the art.', 'In one or more embodiments, the EOS model generator \n222\n is further configured to reduce the EOS model \n236\n to a reduced EOS model having a reduced number of components to represent the EOS model \n236\n over a pre-determined pressure and temperature range.', 'For example, techniques known to those skilled in the art may be used to reduce the EOS model \n236\n.', 'In one or more embodiments, the RP tool \n230\n includes the Helmholtz free energy model generator \n223\n that is configured to generate the Helmholtz free energy model \n237\n that reproduces predictions of the EOS model \n236\n, or a reduced version of the EOS model \n236\n, over a pre-determined temperature and pressure range.', 'The Helmholtz energy functional is able to cover all aspects of the equilibrium fluid behavior including the fluid thermodynamics (phase diagram, calorimetry) and chemical reactions.', 'This helps to avoid splitting of the physical and chemical fluid behavior, as is currently done today in the PVT laboratory activity based on EOS fluid analysis and geochemical analysis.', 'Helmholtz energy obtained directly from the conventional EOSs (with the use of the required additional information) is usually very complex mathematically (e.g., involves many rational expressions and logarithmic functions) and thus is not suitable for the numerical simulations.', 'Further, the conventional EOS is required to be applicable for any molar volume or any molar density to uniquely reconstruct the Helmholtz energy.', 'In other words, if the EOS describes the considered fluid only in a certain restricted range of molar volumes or molar densities, then the Helmholtz energy cannot be uniquely reconstructed.', 'In one or more embodiments, thermodynamic models of the fluid systems are then correlated to the suitable form of Helmholtz energy approximation around the relevant pressures and temperatures.', 'In one or more embodiments, this approximation includes analytical rational expressions having coefficients that are adjusted automatically to the experimental points using curve fitting techniques, such as the geometrical approach.', 'In one or more embodiments, the Helmholtz free energy model \n237\n is constructed as a function of molar densities of chemical components and temperature of the fluids.', 'For example, the Helmholtz free energy model \n237\n may be calculated as a sum of two terms, which are constructed separately.', 'In one or more embodiments, the first term of the Helmholtz free energy model \n237\n is calculated by the following steps: \n \n \n \n(a) The set of respective affine subspaces (tie-lines for 2-phase mixtures, 2D planes for 3-phase mixtures, etc.) is analytically parameterized by auxiliary parameters for multiphase states of the subterranean fluids.', '(b) The envelope of this set of affine subspaces is calculated.', 'The result is the first Helmholtz energy term.', 'The auxiliary parameters are eliminated at this step.', 'In one or more embodiments, the second term of the Helmholtz free energy model \n237\n is calculated by the following steps: \n \n \n \n(c)', 'The respective nodal surfaces are approximated by analytic manifolds for multiphase states of the fluids.', '(d)', 'The constitutive functions of these manifolds are used to construct the function, which has these manifolds as a minimum set.', 'The result is the second Helmholtz energy term.', 'The remaining free parameters are used for the fit of compressibility, heat capacity, etc.', 'In one or more embodiments, the RP tool \n230\n includes the simulator \n224\n that is configured to perform the simulation of the field \n104\n using the Helmholtz free energy model \n237\n.', 'For example, the simulation may include multiphase flow simulation, fluid analysis, reservoir simulation, etc. of the geological structures (\n106\n-\n1\n through \n106\n-\n4\n) and/or the reservoir \n106\n-\n5\n depicted in \nFIG.', '1\n.', 'In particular, the multiphase flow simulation may include 2-phase (e.g., oil-water, gas-water, gas-oil), 3-phase (e.g., oil-water-gas) immiscible, near-miscible, and miscible flow simulations, and the fluid analysis may include surface phase and thin film dynamics at multiphase flow, chemical EOR (e.g., polymer, solvent, surfactant lowering IFT and macroemulsion, microemulsion), low salinity flow analysis, etc.', 'As noted above, a field operation may then be performed based on the simulation result.', 'For example, the simulation results may be used to predict downhole conditions, and make decisions concerning oilfield operations.', 'Such decisions may involve well planning, well targeting, well completions, operating levels, production rates, and other operations and/or conditions.', 'Often this information is used to determine when to drill new wells, re-complete existing wells, or alter wellbore production.', 'The data repository \n234\n may be a data store such as a database, a file system, one or more data structures (e.g., arrays, link lists, tables, hierarchical data structures, etc.) configured in a memory, an extensible markup language (XML) file, any other suitable medium for storing data, or any suitable combination thereof.', 'The data repository \n234\n may be a device internal to the RP computer system \n208\n.', 'Alternatively, the data repository \n234\n may be an external storage device operatively connected to the RP computer system \n208\n.', 'In one or more embodiments, a method is provided for construction of a digital representation of complex compositional fluids for the description of their thermodynamics.', 'The fluids include both subterranean fluids and fluids used in EOR processes.', 'The method includes (i) obtaining phase behavior data of subterranean fluids of the field and fluids used in EOR processes, (ii) generating an EOS model of the fluids based on the phase behavior data, (iii) generating a Helmholtz free energy model that reproduces predictions of the EOS model, and (iv) performing the simulation of the field using the Helmholtz free energy model.', 'In one or more embodiments, a method is provided for construction of a digital representation of complex compositional fluids for the description of their thermodynamics.', 'The method includes (i) obtaining phase behavior data of subterranean fluids of the field and fluids used in EOR processes, (ii) generating a Helmholtz free energy model using phase behavior data directly as input, and (iii) performing the simulation of the field using the Helmholtz free energy model.\n \nFIG.', '3\n depicts an example method for construction of digital representation of complex compositional fluids describing their thermodynamics in accordance with one or more embodiments.', 'For example, the method depicted in \nFIG.', '3\n may be practiced using the RP computer system \n208\n described in reference to \nFIGS.', '1 and 2\n above.', 'In one or more embodiments, one or more of the elements shown in \nFIG.', '3\n may be omitted, repeated, and/or performed in a different order.', 'Accordingly, embodiments of horizontal well log curve grids workflow should not be considered limited to the specific arrangements of elements shown in \nFIG.', '3\n.', 'Initially in element \n301\n, phase behavior data of subterranean fluids of the field are obtained.', 'In one or more embodiments, the subterranean fluids are extracted from a core sample obtained in a portion of the field.', 'In particular, the phase behavior data represent measured properties of the subterranean fluids and fluids used in EOR processes, which may be part of a multiphase compositional fluid system.', 'For example, the phase behavior data may be obtained from laboratory fluid characterization based on the specific protocols complemented by the workflows for laboratory data processing.', 'Examples of the phase behavior data are listed in TABLE 1.', 'In element \n302\n, an EOS model of the fluids is generated based on the phase behavior data.', 'In element \n303\n, the EOS model may be optionally reduced to a reduced EOS model having a reduced number of components to represent the EOS model over a pre-determined pressure and temperature range.', 'In element \n304\n, a Helmholtz free energy model is generated that reproduces predictions of the EOS model (or reduced EOS model) over the aforementioned pre-determined pressure and temperature range.', 'In element \n305\n, simulation of the field is performed using the Helmholtz free energy model.', 'In one or more embodiments, the simulation is performed using the density functional hydrodynamic equations found in Demianov et al., “Density Functional Modelling in Multiphase Compositional Hydrodynamics”, 89 Canadian Journal of Chemical Engineering, 206, 211-12, April 2011, Demianov et al., “Introduction to the density functional method in hydrodynamics”, Fizmatlit, Moscow, 2014.', 'ISBN 978-5-9221-1539-1., and D. Koroteev, et al., “Application of Digital Rock Technology for Chemical EOR Screening”, SPE-165258, 2013.', 'Embodiments of automated construction of Helmholtz free energy describing thermodynamics of complex compositional fluids may be implemented on virtually any type of computer regardless of the platform being used.', 'For example, the computing system may be one or more mobile devices (e.g., laptop computer, smart phone, personal digital assistant, tablet computer, or other mobile device), desktop computers, servers, blades in a server chassis, or any other type of computing device or devices that includes at least the minimum processing power, memory, and input and output device(s) to perform one or more embodiments of construction of a digital representation of complex \n4\n, the computing system \n400\n may include one or more computer processor(s) \n402\n, associated memory \n404\n (e.g., random access memory (RAM), cache memory, flash memory, etc.), one or more storage device(s) \n406\n (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities.', 'The computer processor(s) \n402\n may be an integrated circuit for processing instructions.', 'For example, the computer processor(s) may be one or more cores, or micro-cores of a processor.', 'The computing system \n400\n may also include one or more input device(s) \n410\n, such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.', 'Further, the computing system \n400\n may include one or more output device(s) \n408\n, such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device.', 'One or more of the output device(s) may be the same or different from the input device.', 'The computing system \n400\n may be connected to a network \n412\n (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) via a network interface connection.', 'The input and output device(s) may be locally or remotely (e.g., via the network \n412\n) connected to the computer processor(s) \n402\n, memory \n404\n, and storage device(s) \n406\n.', 'Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.', 'Software instructions in the form of computer readable program code to perform embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium.', 'Specifically, the software instructions may correspond to computer readable program code that when executed by computer processor(s), is configured to perform embodiments of a workflow that constructs a digital representation of complex compositional fluids.', 'Further, one or more elements of the aforementioned computing system \n400\n may be located at a remote location and connected to the other elements over a network \n412\n.', 'Further, embodiments of construction of a digital representation of complex compositional fluids describing their thermodynamics may be implemented on a distributed system having a plurality of nodes, where each portion of workflow that constructs a digital representation of complex compositional fluids may be located on a different node within the distributed system.', 'In one embodiment of construction of a digital representation of complex compositional fluids describing their thermodynamics, the node corresponds to a distinct computing device.', 'The node may correspond to a computer processor with associated physical memory.', 'The node may correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.', 'The systems and methods provided relate to the acquisition of hydrocarbons from an oilfield.', 'It will be appreciated that the same systems and methods may be used for performing subsurface operations, such as mining, water retrieval, and acquisition of other underground fluids or other geomaterials from other fields.', 'Further, portions of the systems and methods may be implemented as software, hardware, firmware, or combinations thereof.', 'While construction of a digital representation of complex compositional fluids describing their thermodynamics has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of construction of a digital representation of complex compositional fluids describing their thermodynamics as disclosed herein.', 'Accordingly, the scope of construction of a digital representation of complex compositional fluids describing their thermodynamics should be limited only by the attached claims.'] | ['1.', 'A method for improving hydrocarbon recovery by performing a simulation of a field having a subterranean formation, comprising:\nobtaining phase behavior data of subterranean fluids of the field;\ngenerating an equation of state (EOS) model of the fluids based on the phase behavior data;\ngenerating, by a processor of a computer system, a Helmholtz free energy model that reproduces predictions of the EOS model over a pre-determined pressure and temperature range;\nperforming, by the processor, the simulation of the field using the Helmholtz free energy model; and\nperforming or modifying a field operation based on the simulation results, wherein the field operation is well planning, well targeting, well completion, operating levels, or production rates.', '2.', 'The method of claim 1, wherein the subterranean fluids comprise injection fluids.', '3.', 'The method of claim 1, further comprising:\nreducing the EOS model to a reduced EOS model having a reduced number of components to represent the EOS model over a pre-determined pressure and temperature range, and\nwherein the Helmholtz free energy model is generated based on the reduced EOS model.', '4.', 'The method of claim 1, wherein the phase behavior data represents at least one property of the fluids selected from a group consisting of pressure, volume, temperature, fluid-fluid interface phenomenon, fluid-solid interface phenomenon, and rheological property.', '5.', 'The method of claim 4, wherein the fluids comprise a multiphase compositional fluid system.', '6.', 'A computer system comprising:\na processor and memory; and\na reservoir production (RP) tool stored in the memory, executing on the processor, and comprising: an input module configured to obtain phase behavior data of fluids; an equation of state (EOS) model generator configured to generate an EOS model of the fluids based on the phase behavior data; a free energy model generator configured to generate a Helmholtz free energy model that reproduces predictions of the EOS model over a predetermined temperature and pressure range; and a simulator configured to perform simulation of the field using the Helmholtz free energy model; and\na repository configured to store the phase behavior data, the EOS model, and the Helmholtz free energy model\nwherein the processor further configured to perform or modify a field operation based on the simulation result, wherein the field operation is well planning, well targeting, well completion, operating levels, or production rates.', '7.', 'The system of claim 6, the EOS model generator further configured to:\nreduce the EOS model to a reduced EOS model having a reduced number of components to represent the EOS model over a pre-determined pressure and temperature range, and\nwherein the Helmholtz free energy model is generated based on the reduced EOS model.', '8.', 'The system of claim 6, wherein the phase behavior data represents at least one property of the fluids selected from a group consisting of pressure, volume, temperature, fluid-fluid interface phenomenon, fluid-solid interface phenomenon, and rheological property.', '9.', 'The system of claim 6, wherein the fluids comprise a multiphase compositional fluid system.', '10.', 'A non-transitory computer-readable medium comprising instructions for improving hydrocarbon recovery by performing a simulation of a field having a subterranean formation, the instructions when executed by a computer processor comprising functionality for:\nobtaining phase behavior data of subterranean fluids of the field;\nobtaining phase behavior data of injection fluids used in the field;\ngenerating an equation of state (EOS) model of the subterranean and injection fluids based on the phase behavior data;\ngenerating a Helmholtz free energy model that reproduces predictions of the EOS model over a pre-determined pressure and temperature range;\nperforming the simulation of the field using the Helmholtz free energy model; and\nperforming or modifying a field operation based on the simulation result, wherein the field operation is well planning, well targeting, well completion, operating levels, or production rates.', '11.', 'The non-transitory computer readable medium of claim 10, the instructions when executed by the computer processor further comprising functionality for:\nreducing the EOS model to a reduced EOS model having a reduced number of components to represent the EOS model over a pre-determined pressure and temperature range, and\nwherein the Helmholtz free energy model is generated based on the reduced EOS model.\n\n\n\n\n\n\n12.', 'The non-transitory computer readable medium of claim 10, wherein the phase behavior data of the subterranean and injection fluids represents at least one property of the fluids selected from a group consisting of pressure, volume, temperature, fluid-fluid interface phenomenon, fluid-solid interface phenomenon, and rheological property.', '13.', 'The non-transitory computer readable medium of claim 10, wherein the subterranean and injection fluids comprise a multiphase compositional fluid system.', '14.', 'A method for improving hydrocarbon recovery by performing a simulation of a field having a subterranean formation, comprising:\nobtaining phase behavior data of subterranean fluids of the field;\nobtaining phase behavior data of injection fluids used in the field;\ngenerating, by a processor of a computer system, a Helmholtz free energy model that reproduces the phase behavior data of the fluids of the field over a predetermined pressure and temperature range;\nperforming, by the processor, the simulation of the field using the Helmholtz free energy model; and\nperforming or modifying a field operation based on the simulation result, wherein the field operation is well planning, well targeting, well completion, operating levels, or production rates.', '15.', 'The method of claim 14, further comprising:\nderiving an equation of state (EOS) model of the subterranean and injection fluids based on the Helmholtz free energy model.\n\n\n\n\n\n\n16.', 'The method of claim 14, wherein the phase behavior data of the subterranean and injection fluids represents at least one property of the fluids selected from a group consisting of pressure, volume, temperature, fluid-fluid interface phenomenon, fluid-solid interface phenomenon, and rheological property.', '17.', 'The method of claim 14, wherein the subterranean and injection fluids comprise a multiphase compositional fluid system.', '18.', 'A computer system comprising:\na processor and memory; and\na reservoir production (RP) tool stored in the memory, executing on the processor, and comprising: an input module configured to obtain phase behavior data of subterranean fluids of a field; an input module configured to obtain phase behavior data of injection fluids used in the field; a free energy model generator configured to generate a Helmholtz free energy model that reproduces the phase behavior data of the subterranean and injection fluids over a pre-determined pressure and temperature range; and a simulator configured to perform a simulation of the field using the Helmholtz free energy model; and\na repository configured to store the phase behavior data and the Helmholtz free energy model;\nwherein the processor further configured to perform or modify a field operation based on the simulation result, wherein the field operation is well planning, well targeting, well completion, operating levels, or production rates.', '19.', 'The system of claim 18, wherein the phase behavior data of the subterranean and injection fluids represents at least one property of the fluids selected from a group consisting of pressure, volume, temperature, fluid-fluid interface phenomenon, fluid-solid interface phenomenon, and rheological property.', '20.', 'The system of claim 18, wherein the subterranean and injection fluids comprise a multiphase compositional fluid system.', '21.', 'A non-transitory computer readable medium comprising instructions for performing a simulation of a field having a subterranean formation, the instructions when executed by a computer processor comprising functionality for:\nobtaining phase behavior data of subterranean fluids of the field;\nobtaining phase behavior data of injection fluids used in the field;\ngenerating a Helmholtz free energy model that reproduces the phase behavior data of the subterranean and injection fluids over a pre-determined pressure and temperature range; performing the simulation of the field using the Helmholtz free energy model; and\nperforming or modifying a field operation based on the simulation result, wherein the field operation is well planning, well targeting, well completion, operating levels, or production rates.', '22.', 'The non-transitory computer readable medium of claim 21, wherein the phase behavior data of the subterranean and injection fluids represents at least one property of the fluids selected from a group consisting of pressure, volume, temperature, fluid-fluid interface phenomenon, fluid-solid interface phenomenon, and rheological property.', '23.', 'The non-transitory computer readable medium of claim 21, wherein the subterranean and injection fluids comprise a multiphase compositional fluid system.'] | ['FIG.', '1 is a schematic view, partially in cross-section, of a field in which one or more embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics may be implemented.', '; FIG.', '2 shows a reservoir production computer system in accordance with one or more embodiments.; FIG.', '3 shows a flowchart of a method in accordance with one or more embodiments.; FIG.', '4 depicts a computer system on which one or more embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics may be implemented.', '; FIG. 1 depicts a schematic view, partially in cross section, of a field 100 in which one or more embodiments of a digital representation of complex compositional fluids may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in FIG.', '1 may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of a digital representation of complex compositional fluids should not be considered limited to the specific arrangements of modules shown in FIG.', '1.; FIG.', '2 shows more details of the RP computer system 208 in which one or more embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics may be implemented.', 'In one or more embodiments, one or more of the modules and elements shown in FIG.', '2 may be omitted, repeated, and/or substituted.', 'Accordingly, embodiments of construction of digital representation of complex compositional fluids describing their thermodynamics should not be considered limited to the specific arrangements of modules shown in FIG.', '2.; FIG.', '3 depicts an example method for construction of digital representation of complex compositional fluids describing their thermodynamics in accordance with one or more embodiments.', 'For example, the method depicted in FIG.', '3 may be practiced using the RP computer system 208 described in reference to FIGS.', '1 and 2 above.', 'In one or more embodiments, one or more of the elements shown in FIG.', '3 may be omitted, repeated, and/or performed in a different order.', 'Accordingly, embodiments of horizontal well log curve grids workflow should not be considered limited to the specific arrangements of elements shown in FIG.', '3.'] |
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US11112513 | Method and device for estimating sonic slowness in a subterranean formation | Mar 21, 2017 | Bassem Khadhraoui, Saad Kisra | Schlumberger Technology Corporation | Alford, Jeff, et al. “Sonic logging while drilling-shear answers.” Oilfield Review 24.1 (2012). pp. 4-15. (Year: 2012).; Akaike, “A new look at the statistical model identification,” IEEE Transactions on Automatic Control, 1974, 19 (6): pp. 716-723.; Kimball et al. 1984, “Semblance processing of borehole acoustic array data,” Geophysics vol. 49, No. 3, p. 274-281.; Kuperkoch et al., “Automated determination of P-phase arrival times at regional and local distances using higher order statistics,” Geophysical Journal International 2009.; Schwarz, “Estimating the dimension of a model,” Annals of Statistics vol. 6, No. 2, Mar. 1978, pp. 461-464.; Search Report for the equivalent French patent application 1652596 dated Feb. 23, 2017.; International Search Report and Written Opinion for the equivalent International patent application PCT/US2017/023296 dated Jun. 23, 2017.; International Preliminary Report on Patentability for the International patent application PCT/US2017/023296 dated Sep. 25, 2018.; Extended Search Report for the European patent application 17770937.5 dated Jan. 2, 2020. | 5081611; January 14, 1992; Hornby; 6205087; March 20, 2001; Fukuhara; 7675813; March 9, 2010; Valero; 7764572; July 27, 2010; Wu et al.; 7970544; June 28, 2011; Tang et al.; 8379483; February 19, 2013; Tang; 9175559; November 3, 2015; Dowla et al.; 20020183930; December 5, 2002; Plona; 20040001389; January 1, 2004; Tang; 20060233047; October 19, 2006; Zeroug; 20090168597; July 2, 2009; Wu et al.; 20120120767; May 17, 2012; Vu; 20150036460; February 5, 2015; Kinoshita et al.; 20150081223; March 19, 2015; Williams | 2424708; October 2006; GB | ['A method for estimating sonic slowness comprising: obtaining (700) a plurality of sonic waveforms are received by a plurality of receivers of a logging tool after emission of a source sonic wave by a transmitter, obtaining (710) slowness models of the subterranean formation, a slowness model being defined by a at least one cell of constant slowness for at least one wave energy mode, computing (720), for each slowness model, a set of candidate travel times, a candidate travel time of a set of candidate travel times being computed for a wave energy mode and a position of a receiver of the plurality of receivers, computing (730) a relevance indicator for each set of candidate travel times based on the recorded sonic waveforms; searching (740) a match between the sets of candidate travel times and the recorded sonic waveforms by searching a relevance indicator which is optimum, computing (750) a sonic slowness estimate for the subterranean formation from a set of candidate travel times for which the relevance indicator is optimum.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nSonic logging may be performed in a subterranean formation using a logging tool, for example a wireline tool and/or while drilling logging tool.', 'A logging tool is placed in the subterranean formation (for example a borehole) and includes at least one transmitter for transmitting a reference sonic wave.', 'The logging tool may include multiple receivers receiving and registering arrival sonic waves after propagation of the source wave through the subterranean formation.', 'Sonic logging provides sonic data that may be used to characterize physical properties of the subterranean formation, such as properties of the rocks inside the subterranean formation.', 'The sonic data may be used to estimate the sonic slownesses (e.g., inverse of velocity) in different parts of the subterranean formation.', 'The slowness may be defined as an amount of time for a wave to travel a certain distance and may be measured in microseconds per foot.', 'A sonic slowness may be estimated using either motion detection algorithms or using semblance processing algorithms such as the Slowness Time Coherence (STC) algorithm.', 'A first motion detection algorithm is disclosed for example in U.S. Pat.', 'No. 6,205,087 B1.', 'This first motion detection algorithm operates on a single waveform basis by applying a waveform amplitude comparison with a given user defined amplitude threshold over a time window.', 'When the waveform amplitude reaches for the first time, over the considered time window, the detection threshold, the corresponding time value is computed.', "The time values computed for the waveforms recorded for the different receivers of the logging tool may be compared one which each other's.", 'False time values may be identified and rectified accordingly.', 'A second motion detection algorithm is described in document entitled “Improved first-motion algorithm to computed high resolution sonic log” by H P Valero, M. Tejada, D. Murray, 2004, Society of Petroleum Engineers, 90995.', 'This algorithm operates on a single waveform basis.', 'An energy criterion is applied to each single waveform to identify the waveform portion of arrival of the first wave component (P-wave component).', 'After applying an energy criterion, a time window is defined to extract the waveform portion of interest.', 'One or more criteria may be applied to the extracted waveform portions.', 'As an example the Akaike Information Criterion (hereafter AIC) or the Bayes Information Criterion (hereafter BIC) are then applied to the extracted waveform portion in order to provide an estimate of the arrival time of the P-wave component of the considered waveform.', 'The AIC operator is based on the detection of an energy change in a waveform but when it is used on a single waveform basis.', 'The AIC operator has thus a high sensitivity to undesired early arrivals and may thus lead to false detection of arrival times.', 'When the waveforms recorded by the receivers of the logging tool have been processed, a statistical analysis may be applied to detect false arrival times and adjust the false arrival times.', 'The detection of false arrival time may be performed either on a global basis by comparing the arrival times for different receivers taking into account the regular spacing of the receivers and/or on a single receiver basis.', 'An example STC algorithm is disclosed in the document entitled “Semblance processing of borehole acoustic array data”, Geophysics, vol.', '49, no 3, p 274-281, by C. V. Kimball and T. Marzetta, 1984.', 'While motion detection algorithms rely on the estimate the arrival times for the P-wave components, the STC algorithm may estimate the velocity of multiple wave components (e.g. P-waves, S-waves, etc) of the arrival waves.', 'The STC algorithm relies on a comparative analysis of multiple arrival waves received by regularly spaced receivers of a logging tool for a single firing of a source sonic wave by a transmitter of the logging tool.', 'The STC algorithm identifies similarity (semblance analysis) between portions of the received waveforms taking into account the regular spacing of the receivers.', 'The STC output is then provided to an automatic post-processing algorithm referred to as “slowness relabeling”.', 'These algorithms may be not robust enough so that the slowness output log computed by the latter has to be quality controlled by users in order for example to detect erroneous detection of arrival time.', 'When the quality of the recorded arrival waves is poor, for example because of acoustic noise in the borehole, users often proceed to the editing of the slowness log outputs based on the waveform semblance analysis.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'Embodiments of the disclosure may include one or more devices, apparatus, systems, methods, computer program products, computer readable media.', 'According to yet other aspects, disclosed is a method for estimating sonic slowness including recording multiple sonic waveforms received by multiple receivers after emission of a source sonic wave by a transmitter through the subterranean formation to obtain multiple recorded sonic waveforms, the multiple receivers are located at different positions in the subterranean formation.', 'The method further includes obtaining at least two slowness models of the subterranean formation, a slowness model being defined by a at least one cell of constant slowness; and computing, for each slowness model, a set of candidate travel times.', 'A candidate travel time of a set of candidate travel times corresponds to a wave energy mode and a position of the receivers.', 'The method further includes computing a relevance indicator for each set of candidate travel times based on the recorded sonic waveforms; searching a match between the sets of candidate travel times and the recorded sonic waveforms by searching the maximal relevance indicator; and computing a sonic slowness estimate for the subterranean formation from a set of candidate travel times for which the relevance indicator is maximal.', 'According to yet other aspects, disclosed is a computer program product or a computer readable medium including computer-executable instructions that when executed by a processor causes said processor to perform a method for estimating sonic slowness according to any embodiment disclosed herein.', 'According to yet other aspects, disclosed is a computing system including one or more processors for processing data; memory operatively coupled to the one or more processors that includes program instructions for causing said one or more processors to perform a method for estimating sonic slowness according to any embodiment disclosed herein.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFeatures and advantages of the described implementations can be more readily understood by reference to the following description taken in conjunction with the accompanying drawings.\n \nFIG.', '1\n illustrates a first embodiment of a system with a logging tool for generating sonic data;\n \nFIG.', '2\n illustrates a second embodiment of a system with a logging tool for generating sonic data;\n \nFIG.', '3\n illustrates a third embodiment of a system with a logging tool for generating sonic data;\n \nFIGS.', '4A and 4B\n illustrate an example of an embodiment of a computing system for processing sonic data;\n \nFIG.', '4C\n illustrate an example system for processing sonic data;\n \nFIGS.', '5A and 5C\n illustrate some aspects of the processing of sonic data;\n \nFIG.', '5D\n illustrates some aspects of the processing of sonic waveforms;\n \nFIG.', '6\n illustrates an example of a flowchart of a method for processing of sonic data;\n \nFIGS.', '7A and 7B\n illustrate an example of a flowchart of a method for estimating sonic slowness;\n \nFIG.', '8\n illustrates some aspects of the processing of sonic waveforms;\n \nFIG.', '9\n illustrates some aspects of the processing of sonic waveforms; and\n \nFIG.', '10\n illustrates some aspects of the processing of sonic waveforms.', 'DETAILED DESCRIPTION', 'The examples disclosed herein relate to the acquisition of sonic data for a subterranean formation and the analysis of these sonic data for characterizing physical (e.g. petrophysical, geophysical, mechanical, structural) properties of the subterranean formation, in order for example to enable accurate and/or reliable slowness estimation for at least one part of the subterranean formation.', 'The subterranean formation may be a natural formation or artificial formation.', 'A subterranean formation is in an underground geological region.', 'An underground geological region is a geographic area that exists below land or ocean.', 'In one or more embodiments, the underground geological region includes the subsurface formation in which a borehole is or may be drilled and any subsurface region that may affect the drilling of the borehole, such as because of stresses and strains existing in the subsurface region.', 'In other words, the underground geological region may not just include the area immediately surrounding a borehole or where a borehole may be drilled, but also any area that affects or may affect the borehole or where the borehole may be drilled.', 'One or more embodiments of the technology may be directed to slowness estimation for the formation around a borehole.', 'A slowness estimate may be used to identify natural gas entry points in the borehole.', 'A slowness estimate may also be used to estimate the porosity of a rock or of another material forming the borehole, to characterize the induced or natural anisotropies or orientations of the rock, to characterize the geomechanical properties of the rock in order for example to define a weight of fluid to be used while drilling the borehole.', 'A slowness estimate may also be used to establish a time/depth relationship for the borehole, thus enabling a conversion of seismic data acquired for the borehole into depth data and to generate a cartography of the borehole properties.', 'One or more embodiments of the technology may be directed to real-time management of drilling operations.', 'In particular, a drilling model is calibrated.', 'Simulations are continually performed on using the calibrated drilling model.', 'A predicted measurement value from the simulations is compared against an actual measurement value acquired from the field.', 'If the actual measurement value matches the simulated measurement value, then the simulations may be used to determine a simulated state of the drilling operation.', 'Based on the simulated state, a condition of the drilling operation is determined and one or more signals for controlling the drilling operations is performed.', 'One or more embodiments of the technology may be directed to a drilling simulation-based real time system for drilling operation monitoring, diagnostics and optimization.', 'In particular, one or more embodiments may perform diagnostics and optimization for drilling.', 'For example, one or more embodiments may perform real-time vibration mitigation, real-time rate of penetration (ROP) optimization, real-time trajectory monitoring and directional drilling recommendation, real-time borehole quality optimization, real-time logging while drilling/measurement while drilling (LWD/WMD) measurement quality assurance, real-time fatigue life monitoring, real-time bit-reamer load balancing, real-time bit and reamer wear monitoring, and real-time buckling and weight on bit (WOB) transfer monitoring.', 'Trajectory monitoring may include ensuring that trajectory is within a threshold of the desired planned direction.', 'Borehole quality is the degree of straightness of the hole.', 'Fatigue life managing is managing stress on equipment, such as when rotating while drilling the hole.\n \nFIG.', '1\n illustrates a wellsite system in which the examples disclosed herein can be employed.', 'The wellsite can be onshore or offshore.', 'In this example system, a borehole \n11\n is formed in subsurface formations by rotary drilling.', 'However, the examples described herein can also use directional drilling, as will be described hereinafter.', 'A drill string \n12\n may be suspended within the borehole \n11\n and has a bottom hole assembly \n100\n that includes a drill bit \n105\n at its lower end.', 'The surface system may include a platform and derrick assembly \n10\n positioned over the borehole \n11\n.', 'The assembly \n10\n may include a rotary table \n16\n, a kelly \n17\n, a hook \n18\n and a rotary swivel \n19\n.', 'The drill string \n12\n may be rotated by the rotary table \n16\n.', 'The rotatory table \n16\n may be energized by a device or system not shown.', 'The rotary table \n16\n may engage the kelly \n17\n at the upper end of the drill string \n12\n.', 'The drill string \n12\n may be suspended from the hook \n18\n, which is attached to a traveling block (also not shown).', 'The drill string \n12\n may be positioned through the kelly \n17\n and the rotary swivel \n19\n, which permits rotation of the drill string \n12\n relative to the hook \n18\n.', 'A top drive system may be used to impart rotation to the drill string \n12\n.', 'In this example, the surface system further includes drilling fluid or mud \n26\n stored in a pit \n27\n formed at the well site.', 'A pump \n29\n delivers the drilling fluid \n26\n to the interior of the drill string \n12\n via a port in the swivel \n19\n, causing the drilling fluid \n26\n to flow downwardly through the drill string \n12\n as indicated by the directional arrow \n8\n.', 'The drilling fluid \n26\n exits the drill string \n12\n via ports in the drill bit \n105\n, and then circulates upwardly through the annulus region between the outside of the drill string \n12\n and the wall of the borehole \n11\n, as indicated by the directional arrows \n9\n.', 'In this manner, the drilling fluid \n26\n lubricates the drill bit \n105\n and carries formation cuttings up to the surface as it is returned to the pit \n27\n for recirculation.', 'The bottom hole assembly \n100\n of the example illustrated in \nFIG.', '1\n includes a logging-while-drilling (LWD) module \n120\n, a measuring-while-drilling (MWD) module \n130\n, a roto-steerable system and motor \n150\n, and the drill bit \n105\n.', 'The LWD module \n120\n may be housed in a special type of drill collar and may include one or more logging tools.', 'In some examples, the bottom hole assembly \n100\n may include additional LWD and/or MWD modules.', 'The LWD module \n120\n may include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment.', 'The LWD module \n120\n may include a sonic measuring device.', 'The MWD module \n130\n may also be housed in a drill collar and may include one or more devices for measuring characteristics of the drill string \n12\n and/or drill bit \n105\n.', 'The MWD module \n130\n further may include an apparatus (not shown) for generating electrical power for at least portions of the bottom hole assembly \n100\n.', 'The apparatus for generating electrical power may include a mud turbine generator powered by the flow of the drilling fluid.', 'However, other power and/or battery systems may be employed.', 'In this example, the MWD module \n130\n includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device and/or an inclination measuring device.', 'Although the components of \nFIG.', '1\n are shown and described as being implemented in a particular conveyance type, the examples disclosed herein are not limited to a particular conveyance type but, instead, may be implemented in connection with different conveyance types including, for example, coiled tubing, wireline wired drill pipe and/or any other conveyance types known in the industry.', 'FIG.', '2\n illustrates a sonic logging-while-drilling tool that can be used to implement the LWD tool \n120\n or may be a part of an LWD tool suite \n120\nA. An offshore rig \n210\n having a sonic transmitting source or array \n214\n may be deployed near the surface of the water.', 'In at least some embodiments, any other type of uphole or downhole source or transmitter may be provided to transmit sonic signals.', 'In some examples, an uphole processor controls the firing of the transmitter \n214\n.', 'Uphole equipment may also include acoustic receivers (not shown) and a recorder (not shown) for capturing reference signals near the source of the signals (e.g., the transmitter \n214\n).', 'The uphole equipment may also include telemetry equipment (not shown) for receiving MWD signals from the downhole equipment.', 'The telemetry equipment and the recorder are may be coupled to a processor (not shown) so that recordings may be synchronized using uphole and downhole clocks.', 'A downhole LWD module \n200\n includes at least acoustic receivers \n230\n and \n231\n, which are coupled to a signal processor so that recordings may be made of signals detected by the receivers in synchronization with the firing of the signal source.', 'In operation, the transmitter \n214\n transmits signals and/or waves that are received by one or more of the receivers \n230\n, \n231\n.', 'The received signals may be recorded and/or logged to generate associated waveform data.', 'The waveform data may be processed by processors \n232\n and/or \n234\n to determine slowness values as disclosed herein.', 'FIG.', '3\n depicts an example an apparatus which can be used in implement the examples disclosed herein.', 'In some examples, subsurface formations \n331\n are traversed by a borehole \n332\n.', 'The borehole \n332\n may be filled with drilling fluid and/or mud.', 'In the illustrated example, a logging tool \n310\n is suspended on an armored cable \n312\n and may have optional centralizers.', 'The cable \n312\n extends up the borehole \n332\n, over a sheave wheel \n320\n on a derrick \n321\n to a winch forming part of surface equipment \n350\n.', 'A depth gauging apparatus may be provided to measure cable displacement over the sheave wheel \n320\n and the depth of the logging tool \n310\n in the borehole \n332\n.', 'In some examples, a device is included in the logging tool \n310\n to produce a signal indicative of an orientation of the body of the logging tool \n310\n.', "Processing and interface circuitry within the logging tool \n310\n amplifies, samples and/or digitizes the tool's information signals for transmission and communicates the signals to the surface equipment \n350\n via, for example, the cable \n312\n.", 'Electrical power and control signals for coordinating operation of the logging tool \n310\n are generated by the surface equipment \n350\n and communicated via the cable \n312\n to circuitry provided within the logging tool \n310\n.', 'The surface equipment includes a processor \n370\n, peripheral equipment and/or a recorder \n326\n.', 'The present description is made by reference to functions, engines, block diagrams and flowchart illustrations of the methods, systems, and computer program according to one or more example embodiments.', 'Each described function, engine, block of the block diagrams and flowchart illustrations can be implemented in hardware, software, firmware, middleware, microcode, or any suitable combination thereof.', 'If implemented in software, the functions, engines, blocks of the block diagrams and/or flowchart illustrations can be implemented by computer program instructions or software code, which may be stored or transmitted over a computer-readable medium, or loaded onto a general purpose computer, special purpose computer or other programmable data processing apparatus to produce a machine, such that the computer program instructions or software code which execute on the computer or other programmable data processing apparatus, create the means for implementing the functions described therein.', 'Embodiments of computer-readable media includes, but are not limited to, both computer storage media and communication media including any medium that facilitates transfer of a computer program from one place to another.', 'Specifically, software instructions or computer readable program code to perform embodiments described therein may be stored, temporarily or permanently, in whole or in part, on a non-transitory computer readable medium of a local or remote storage device including one or more storage media.', 'As used herein, a computer storage medium may be any physical media that can be read, written or more generally accessed by a computer.', 'Examples of computer storage media include, but are not limited to, a flash drive or other flash memory devices (e.g. memory keys, memory sticks, key drive), CD-ROM or other optical storage, DVD, magnetic disk storage or other magnetic storage devices, memory chip, RAM, ROM, EEPROM, smart cards, or any other suitable medium from that can be used to carry or store program code in the form of instructions or data structures which can be read by a computer processor.', 'Also, various forms of computer-readable medium may be used to transmit or carry instructions to a computer, including a router, gateway, server, or other transmission device, wired (coaxial cable, fiber, twisted pair, DSL cable) or wireless (infrared, radio, cellular, microwave).', 'The instructions may include code from any computer-programming language, including, but not limited to, assembly, C, C++, Basic, HTML, PHP, Java, Javascript, etc.', 'The computing system \n100\n may be implemented as a single hardware device, for example in the form of a desktop personal computer (PC), a laptop, a personal digital assistant (PDA), a smart phone or may be implemented on separate interconnected hardware devices connected one to each other by a communication link, with wired and/or wireless segments.', 'In one or more embodiments, the computing system \n100\n operates under the control of an operating system and executes or otherwise relies upon various computer software applications, components, programs, objects, modules, data structures, etc.', 'As illustrated schematically by \nFIG.', '4A\n, the computing system \n400\n includes a processing unit \n410\n, memory \n411\n, one or more computer storage media \n412\n, and other associated hardware such as input/output interfaces (e.g. device interfaces such as USB interfaces, etc., network interfaces such as Ethernet interfaces, etc.) and a media drive \n413\n for reading and writing the one or more compute storage media.', 'The memory \n411\n may be a random access memory (RAM), cache memory, non-volatile memory, backup memory (e.g., programmable or flash memories), read-only memories, or any combination thereof.', 'The processing unit \n410\n may be any suitable microprocessor, integrated circuit, or central processing unit (CPU) including at least one hardware-based processor or processing core.', 'In one or more embodiments, the computer storage medium or media \n412\n includes computer program instructions which, when executed by the computing system \n400\n, cause the computing system \n400\n to perform one or more method described herein.', 'The processing unit \n410\n is a hardware processor that processes instructions.', 'For example, the processing unit \n410\n may be an integrated circuit for processing instructions.', 'For example, the processing unit may be one or more cores or micro-cores of a processor.', 'The processing unit \n410\n of the computing system \n400\n may be configured to access to said one or more computer storage media \n412\n for storing, reading and/or loading computer program instructions or software code that, when executed by the processor, causes the processor to perform the blocks of a method described herein.', 'The processing unit \n410\n may be configured to use the memory \n411\n when executing the blocks of a method described herein for the computing system \n400\n, for example for loading computer program instructions and for storing data generated during the execution of the computer program instructions.', 'In one or more embodiments, the computing system \n400\n receives a number of inputs and outputs for communicating information externally.', 'For interface with a user or operator, the computing system \n400\n generally includes a user interface \n414\n incorporating one or more user input/output devices, such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.', 'Otherwise, user input may be received, e.g., over a network interface coupled to a communication network, from one or more external computer devices or systems.', 'The computing system \n400\n in \nFIG.', '4A\n may be connected to or be a part of a network.', 'For example, as shown in \nFIG.', '4B\n, the network \n420\n may include multiple nodes (e.g., node X \n422\n, node Y \n424\n).', 'Each node may correspond to a computing system, such as the computing system shown in \nFIG.', '4A\n, or a group of nodes combined may correspond to the computing system shown in \nFIG.', '4A\n.', 'By way of an example, embodiments may be implemented on a node of a distributed system that is connected to other nodes.', 'By way of another example, embodiments may be implemented on a distributed computing system having multiple nodes, where each portion of one or more embodiments may be located on a different node within the distributed computing system.', 'Further, one or more elements of the aforementioned computing system \n400\n may be located at a remote location and connected to the other elements over a network.', 'Although not shown in \nFIG.', '4B\n, the node may correspond to a blade in a server chassis that is connected to other nodes via a backplane.', 'By way of another example, the node may correspond to a server in a data center.', 'By way of another example, the node may correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.', 'The nodes (e.g., node X \n422\n, node Y \n424\n) in the network \n420\n may be configured to provide services for a client device \n426\n.', 'For example, the nodes may be part of a cloud computing system.', 'The nodes may include functionality to receive requests from the client device \n426\n and transmit responses to the client device \n426\n.', 'The client device \n426\n may be a computing system, such as the computing system shown in \nFIG.', '4A\n.', 'Further, the client device \n426\n may include and/or perform at least a portion of one or more embodiments.', 'The computing system \n400\n (\nFIG.', '4A\n), a node X \n422\n or Y \n424\n (\nFIG.', '4B\n) of a computing system or the surface equipment \n350\n (\nFIG.', '3\n) may further include a data repository for storing sonic data, intermediate data and/or resultant data.', 'A data repository is any type of storage unit and/or device (e.g., a file system, database, collection of tables, or any other storage mechanism) for storing data.', 'Further, the data repository may include multiple different storage units and/or storage devices.', 'The multiple different storage units and/or storage devices may or may not be of the same type or located at the same physical site and/or on the same physical device.', 'FIG.', '4C\n illustrates a system including a data repository \n440\n for storing sonic data and related data.', 'The data repository \n440\n may be used for storing recorded sonic waveforms \n452\n, preprocessed sonic waveforms \n459\n, receiver and transmitter positions \n453\n, slowness models \n454\n, including geological cells \n456\n, energy mode indexes \n460\n and slowness values \n455\n.', 'The data repository \n440\n may be used for storing other sonic related data, for example, relevance indicators \n450\n, candidate travel times \n451\n, matching travel times \n458\n, slowness maps \n457\n.', 'The data repository \n440\n may be operatively connected to a field application \n470\n for performing field operations and/or for implementing a method disclosed herein.', 'The field application may be executed by a device operatively connected to a logging tool, for example by the computing system \n400\n (\nFIG.', '4A\n), by one or more nodes X \n422\n, Y \n424\n (\nFIG.', '4B\n) of a computing system or by the surface equipment \n350\n (\nFIG.', '3\n) or any other device for controlling a field operation.', 'Methods for processing sonic waveform data acquired for a subterranean formation will now be described in detail.', 'The methods may be implemented by a device operatively connected to a logging tool \n310\n, for example by the computing system \n400\n (\nFIG.', '4A\n), by one or more nodes X \n422\n, Y \n424\n (\nFIG.', '4B\n) of a computing system or by the surface equipment \n350\n (\nFIG.', '3\n) or any other device for controlling a field operation.', 'In one or more embodiment, the logging tool \n310\n includes one or more transmitters and one or more receivers.', 'The different receivers may or may not be of the same type.', 'More generally, in the present disclosure, the word “different” with respect to receivers is used to refer to receiver instances which may or may not be the same type.', 'Each transmitter of the logging tool is configured to emit a source sonic wave.', 'A sonic wave may correspond to a sound wave in the frequency range of 1 to 25 kHz.', 'The source wave is an oscillating wave, for example a sinusoidal wave.', 'The transmitter may be a monopole transmitter or a dipole transmitter.', 'With a monopole transmitter the energy of the source wave is emitted in each direction away from a center position, while a dipole transmitter emits energy in a particular direction.', 'The emitted source wave may be received and recorded by the different receivers after propagation through the subterranean formation, i.e. after propagation through the borehole (e.g. through the fluid present in the borehole or through empty areas of the borehole)', 'and/or', 'after reflection on the walls of the borehole and/or after propagation along the borehole walls and/or after refraction through the walls of the borehole and propagation through solid materials of the subterranean formation (e.g. the rock or the materials in which the borehole is drilled).', 'The direction of the wave propagation is perpendicular to the wavefront.', 'A wave received and recorded by a receiver may thus include different types of wave components depending on the propagation path followed by the source wave before arriving at the receiver.', 'The received wave may for example include wave components like a P-wave component, a S-wave component, a Stoneley wave component, a mud wave component, a Rayleigh wave component, etc.', 'For a given geologic material (e.g. a given rock, a given fluid), each of these wave components has a specific propagation speed.', 'A P-wave (also called compressional wave) is an elastic wave which oscillates in the direction the wave propagates.', 'A S-wave (also called shear-wave) is an elastic wave which oscillates perpendicular to the direction in which the wave propagates.', 'A Stoneley wave is a wave that propagates along a solid/fluid interface, for example along the wall of a fluid-filled borehole.', 'A P-wave may be produced by reflection on a wall of the borehole of a source wave.', 'A P-wave or S-wave may be produced when a source wave propagates through a wall of the borehole of a source wave and enters in the subterranean formation in which the borehole is drilled while being refracted (the direction of propagation is changed when crossing the wall).', 'A Rayleigh wave is a surface wave that travels near the surface of solid materials.', 'A mud wave is a compressional wave transmitted by a fluid in a borehole.', 'When considering a single receiver, the different types of wave components produced by a source wave emitted by a transmitter after propagation through the subterranean formation arrive at the receiver at different arrival times.', 'Thus the waveform recorded by this receiver has different types of waveform components.', 'FIG.', '5D\n illustrates this aspect.', 'After emission of the source wave at time T\n0\n, the P-wave component arrives at time T\n1\n, the S-wave component arrives at time T\n2\n, the Rayleigh-wave component arrives at time T\n3\n, the mud wave component arrives at time T\n4\n and the Stoneley wave component arrives at time T\n5\n.', 'It is to be noticed that the different types of wave components may have different amplitudes, different frequencies or more generally different waveform attributes.', 'Each wave component corresponds to a given energy mode and a way the acoustic energy of a wave propagates in one or more directions.', 'For example, a first energy mode E1 corresponds to the P-waves.', 'A second energy mode E2 corresponds to the S-waves.', 'A third energy mode E3 corresponds to the Stoneley waves.', 'In one or more embodiment, slowness models are used for estimating the slowness in a subterranean formation.', 'The slowness model is a model of the slowness of sonic waves through a subterranean formation.', 'A slowness model is used to predict the travel time of a sonic wave through a subterranean formation.', 'A slowness model may predict travel time of one or more wave components/wave energy modes of sonic waves.', 'A slowness model S\nm \nmay be defined by geological cells of constant slowness for a given energy mode/wave component.', 'A geological cell has thus a constant slowness value for at least one energy mode/wave component.', 'Without loss of generality, the slowness model may be defined such that each geological cell has a constant slowness value for each energy mode.', 'Therefore the slowness model may be common to the various multiple energy modes.', 'In at least some embodiments, a slowness model may be defined for a single energy mode and several slowness models may be defined for the several energy modes/wave components.', 'A geological cell may correspond to a volume area in the subterranean formation.', 'Each geological cell may for example correspond to a given geological material or to an empty area.', 'A geological cell may for example have the form of a three-dimensional (3D) parallelepipedic cell or any other suitable form.', 'For each geological cell of a slowness model S\nm \nand for each energy mode E\nj \na slowness value may be associated and stored in a memory, for example in the data repository \n440\n.', 'For each slowness model S\nm\n, a ray tracing technique may be used to model the propagation paths of the waves in the multiple geological cells of the subterranean formation.', 'The ray tracing technique is based on ray paths representing the propagation paths of the different types of wave components and is usable for predicting or determining travel times or arrival time of the wave components at receivers after propagation along the represented propagation paths.', 'For simplification reasons, the time at which the firing of the source sonic wave occurs may be used as a time reference and arbitrary set to zero.', 'Thus, the travel time of a wave component (i.e. the time period to travel from a transmitter to a given receiver) is equal to the arrival time (i.e. the time value or timestamp of the arrival of the wave component) of this wave component.', 'FIGS.', '5A to 5C\n illustrate several slowness models for a given subterranean formation in which a borehole is drilled.', 'The slowness model illustrated by \nFIG.', '5A\n corresponds to a slowness model with four geological cells \n500\n-\n503\n, the geological cell \n500\n corresponding to the borehole itself, including for example a fluid, and the geological cells \n501\n-\n503\n corresponding to different types of rocks or materials forming the subterranean formation in which the borehole is drilled.', 'With this first slowness model, according to a ray tracing technique, a wave emitted by the transmitter T propagates through the geological cell \n500\n and are then reflected back by the wall of the borehole at the level of the geological cell \n502\n and/or propagates along the wall of the borehole at the interface between the geological cell \n500\n and the geological cell \n502\n and finally propagates again through the geological cell \n500\n before reaching one of the receivers R\n1\n to R\n3\n.', 'The slowness model illustrated by \nFIG.', '5B\n corresponds to a slowness model with seven geological cells \n510\n-\n516\n, the geological cell \n510\n corresponding to the borehole itself, including for example a fluid and the geological cells \n511\n-\n516\n corresponding to different types of rocks or materials forming the subterranean formation in which the borehole is drilled.', 'With this second slowness model, according to a ray tracing technique, a wave emitted by the transmitter T propagates through the geological cell \n510\n, is refracted by the wall of the borehole at the interface between the geological cell \n510\n and the geological cell \n515\n, is transmitted successively through one or more geological cells \n515\n, \n514\n, \n513\n and/or \n512\n, is refracted again by the wall of the borehole at the interface between the geological cell \n510\n and one of the geological cells \n512\n, \n513\n or \n514\n, and finally propagates again through the geological cell \n510\n before reaching one of the receivers R\n1\n to R\n3\n.', 'The slowness model illustrated by \nFIG.', '5C\n corresponds to a slowness model with ten geological cells \n520\n-\n529\n, the geological cell \n520\n corresponding to the borehole itself, including for example a fluid and the geological cells \n521\n-\n529\n corresponding to different types of rocks or materials forming the subterranean formation in which the borehole is drilled.', 'With this third slowness model, according to a ray tracing technique, a wave emitted by the transmitter T propagates through the geological cell \n520\n, is refracted by the wall of the borehole at the interface between the geological cell \n520\n and the geological cell \n528\n, is transmitted successively through one or more geological cells \n527\n, \n528\n, \n525\n, \n526\n, \n524\n, \n522\n and/or \n523\n, is refracted again by the wall of the borehole at the interface between the geological cell \n520\n and one or the geological cells \n522\n, \n524\n, \n525\n or \n527\n, and finally propagates again through the geological cell \n520\n before reaching one of the receivers R\n1\n to R\n3\n.', 'Using a slowness model having geological cells of constant slowness for a given wave component enables the computation of the travel time of a wave component in a given geological cell of the slowness model on the basis of the slowness value associated to the given geological cell and of the length of the portion of the propagation path inside the given geological cell.', 'A travel time for a given wave component between a transmitter at a given position and a receiver at a given position may then be computed for each propagation path by summing up the different travel times in the different geological cells computed for the different portions of the propagation path.', 'For each slowness model, a travel time may thus be computed, for a given transmitter position, for a given receiver position and a given wave component.', 'FIG.', '6\n show a flowchart in accordance with one or more embodiments of a method for processing sonic data acquired for a subterranean formation.', 'While the various blocks in the flowchart are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'In at least one embodiment, the method may be performed by the computing system \n400\n (\nFIG.', '4A\n), by one or more nodes X \n422\n, node Y \n424\n (\nFIG.', '4B\n) of a computing system or by the surface equipment \n350\n (\nFIG.', '3\n) operatively connected to a logging tool, for example the logging tool \n310\n, or by any other device for controlling a field operation.', 'In the example embodiment described by reference to \nFIG.', '6\n, the subterranean formation includes a borehole.', 'The method described by reference to \nFIG.', '6\n will be referred to below as the forward modelling.', 'This forward modelling is applicable for any configuration of receivers, i.e. whether the receivers are regularly spaced in the logging tool or irregularly spaced in the logging tool.', 'At block \n600\n, the positions of at least one transmitter and one or more receiver of a logging tool placed in the borehole are obtained.', 'The position of a transmitter or receiver may be defined in a one-dimensional (1D) space corresponding to a straight line of the logging tool along which the transmitter and the receivers are placed.', 'When the logging tool is placed vertically in the borehole, the position of a transmitter or a receiver may be defined as a depth value d in the borehole.', 'For example one transmitter and N=4 receivers are used.', 'Assuming the logging includes one transmitter the transmitter position is noted T(d) where d is the depth of the transmitter.', 'Similarly a receiver position is noted R(d\nn\n) where n is an integer value that varies from 1 to N=4.', 'The distance TR between a receiver at position R(d\nn\n) and the transmitter at position T(d) is thus TR=|d\nn\n−d|.', 'At block \n610\n, several slowness models are generated for the subterranean formation.', 'For each slowness model, a set of geological cells of constant slowness value are defined.', 'A slowness value associated to the geological cell for each possible energy mode is stored in memory, for example in the data repository \n440\n.', 'At block \n620\n, one or more energy modes and/or wave components are selected from the energy modes/wave components used in the slowness models generated at block \n610\n.', 'For example three energy modes E\n1 \nto E\n3 \nare selected that correspond respectively to three wave components: the P-wave component, the S-wave component and the Stoneley wave component.', 'An energy mode index j=1 to 3 is associated to each energy mode E\nj\n.', 'At block \n630\n, several slowness models are selected from the set of generated slowness models.', 'For example, M=10 slowness models are selected.', 'A model index m=1 to M is associated to each slowness model S\nm\n.', 'At block \n640\n, for each slowness model selected at block \n630\n and each energy mode selected at block \n620\n, a travel time is computed for each receiver position received at block \n600\n, taking into account the transmitter position.', 'Therefore, for a given slowness model, a set of travel times are computed, where each travel time corresponds to an energy mode and a position of a receiver of the logging tool.', 'At block \n650\n, each of the travel times computed at block \n640\n are stored in a memory, for example in the data repository \n440\n, in association with a slowness model index m, an energy mode index j, a receiver position R(d\nn\n) for a receiver index n and a transmitter position T(d).', 'A travel time computed for a slowness model index m, an energy mode index j, a receiver position R(d\nn\n) and a transmitter position T(d) will be noted: \n TT(T(d),R(d\nn\n))', 'FIG.', '7A\n shows a flowchart in accordance with one or more embodiments of a method for estimating slowness for a subterranean formation.', 'While the various blocks in the flowchart are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'In at least one embodiment, the method may be performed by a device operatively connected to a logging tool, for example by the computing system \n400\n (\nFIG.', '4A\n), by one or more nodes X \n422\n, node Y \n424\n (\nFIG.', '4B\n) of a computing system, by the surface equipment \n350\n (\nFIG.', '3\n) or by any other device for controlling a field operation.', 'At block \n700\n, sonic waveforms received by receivers after emission of a source sonic wave by a transmitter through the subterranean formation are obtained.', 'The receivers are located at different positions in the subterranean formation.', 'The sonic waveforms may be obtained directly or indirectly from the receivers.', 'For example, the sonic waveforms may be obtained from the sensors and stored in the data repository.', 'The sonic waveforms may then be obtained from the data repository.', 'At block \n710\n, one or more slowness models of the subterranean formation are obtained.', 'A slowness model may be defined by one or more cells of constant slowness for one or more wave energy modes.', 'For example, the slowness models may be obtained from the data repository \n440\n.', 'The slowness models may be defined for one or more energy modes of sonic waveforms.', 'At block \n720\n, a set of candidate travel times is computed for each slowness model obtained at block \n710\n.', 'A candidate travel time of a set of candidate travel times is computed for a wave energy mode and a position of a receiver of the multiple receivers.', 'At block \n730\n, a relevance indicator for each set of candidate travel times is computed on the basis of the obtained sonic waveforms.', 'At block \n740\n a match between the sets of candidate travel times and the recorded sonic waveforms is searched by searching a relevance indicator that is optimum.', 'At block \n750\n one or more slowness estimates are computed for the subterranean formation from a set of candidate travel times for which the relevance indicator is optimum.', 'FIG.', '7B\n shows a flowchart in accordance with one or more embodiments of a method for estimating slowness for a subterranean formation on the basis of waveform data recorded by the receivers of a logging tool.', 'While the various blocks in the flowchart are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'In at least one embodiment, the method may be performed by a device operatively connected to a logging tool, for example, by the computing system \n400\n (\nFIG.', '4A\n), by one or more nodes X \n422\n, node Y \n424\n (\nFIG.', '4B\n) of a computing system, by the surface equipment \n350\n (\nFIG.', '3\n) or by any other device for controlling a field operation.', 'In the example embodiment described by reference to \nFIG.', '7B\n, the subterranean formation is the same as the one considered for the forward modelling.', 'In addition, the logging tool is the same and the receiver and transmitter positions used for the forward modelling.', 'The travel times stored at block \n650\n are used as candidate travel times for the slowness estimation on the basis of waveform data recorded by the receivers.', 'The slowness estimation is performed according to a method that will now be described by reference to \nFIG.', '7B\n.', 'For real-time purposes, the forward modelling may be performed in advance in order to be ready for the processing of first waveform data recorded by the receivers.', 'According to another example, the forward modelling may be updated on the basis of the result of the slowness estimation performed on the basis of the waveform data recorded by the receivers and the updated candidate travel times used for estimating slowness values for the subterranean formation on the basis of second waveform data newly recorded by the receivers.', 'At block \n800\n, a source wave is emitted by a transmitter of a sonic logging tool at a depth d and waves are received by the N receivers of the sonic logging tool at depth d\nn \nwhere n is an integer value that varies from 1 to N are recorded.', 'The sonic logs generated by the sonic logging tool include waveform data representing a sonic wave received by a receiver.', 'Each receiver n records at least one waveform noted wf\nn\n.', 'The waveform data may include data representing monopole P-waves and S-waves, dipole flexural waves and/or monopole Stoneley waves, for example.', 'The waveform data may be obtained while drilling (\nFIG.', '1\n)', 'and/or via wireline (\nFIG.', '2\n.)', 'using a multimode sonic tool.', 'Monopole waveform data, dipole waveform data, quadrupole waveform data, pseudo-Rayleigh waveform data, and Stoneley waveform data may be obtained from the sonic logs.', 'The waveform data representing the recorded sonic waveforms \n452\n may be stored in the data repository \n440\n, or be directly sent through a communication link to a device operatively connected to a logging tool \n310\n or to a data repository \n440\n.', 'Multiple sonic waveforms may then be obtained for the multiple receivers.', 'For example, the multiple sonic waveforms may be read or obtained from the data repository \n440\n, received by a field application \n470\n operatively connected to the data repository or to a logging tool, received by the computing system \n400\n (\nFIG.', '4A\n), by one or more nodes X \n422\n, node Y \n424\n (\nFIG.', '4B\n) of a computing system or by the surface equipment \n350\n (\nFIG.', '3\n).', 'At block \n810\n, one or more energy modes are selected.', 'The number of selected energy modes is noted P.', 'For example P=3 and three energy modes E\n1\n, E\n2\n, E\n3 \nare chosen which correspond respectively to the P-waves, the S-waves and the Stoneley waves.', 'The selected energy modes and corresponding wave components used for slowness estimation may include the energy modes/wave components selected at block \n620\n in the forward modelling or a subset thereof.', 'The selection may be performed manually by a user or automatically from the set of energy modes selected at block \n620\n in the forward modelling.', 'According to another example, P=1 for slowness estimation on monopole data of P-waves or for slowness estimation on dipole data of S-waves.', 'At block \n820\n, a pre-processing is performed on the waveform data.', 'This pre-processing operation is optional.', 'It improves the performance of the slowness estimation method.', 'For each energy mode selected at block \n810\n, a pre-processing specific to that energy mode is applied to each recorded waveform.', 'Each waveform component corresponding to a wave component may have specific characteristics that the other waveform components do not have: a specific amplitude, a specific frequency spectrum or other specific waveform attribute.', 'Thus pre-processing performed for a given energy mode on a recorded waveform may be performed on the basis of one or more criteria (amplitude, amplitude standard deviation, frequency band, or others criteria which may be extracted from a waveform) so as to extract from the processed waveforms a given wave component, and therefore mitigate (e.g., reduce or eradicate) the other waveform components that do not have the known specific characteristic(s) of the given energy mode.', 'A pre-processed waveform, resulting from a pre-processing of the waveform wf\nn \nreceived by receiver n that extracts the waveform component corresponding to the energy mode Ej, will be noted wf\nR\nE\nj\n.', 'For example, as illustrated by \nFIG.', '5D\n, the Stoneley wave component has an amplitude which is higher than the other waveform components and a lower frequency.', 'Therefore by filtering a recorder waveform so as to extract—by means for example of a low pass filter—the Stoneley wave component, the other waveform components of lower amplitude and/or of higher frequency are mitigated.', 'According to another example illustrated by \nFIG.', '5D\n, the Rayleigh wave component has a frequency which is higher than the other waveform components.', 'Therefore by filtering a recorder waveform so as to extract—by means for example of a high pass filter—the Rayleigh wave component, the other waveform components of lower frequency are mitigated.', 'According to another example illustrated by \nFIG.', '5D\n, the P-wave component has an amplitude which is much lower than the other waveform components.', 'Therefore by filtering a recorder waveform so as to extract—by means for example of an amplitude filter—the P-wave component, the other waveform components of higher amplitude are mitigated.', 'At block \n830\n, one or more slowness models are selected.', 'The selected slowness models used for slowness estimation may include the slowness models selected at block \n630\n in the forward modelling or a subset thereof.', 'The selection may be performed manually by a user or automatically from the set of slowness models selected at block \n630\n in the forward modelling.', 'At block \n840\n, the travel times computed for the slowness models selected at block \n830\n and or the energy modes selected at block \n810\n are obtained for example from the data repository \n440\n in which the travel times have been stored at block \n650\n during forward modelling.', 'These travel times are used as candidate travel time for the slowness estimation.', 'For each slowness model S\nm\n, a set of N*P candidate travel times is thus obtained, where N is the receiver number for which waveform data are available and P the number of energy modes selected at block \n810\n.', 'A candidate travel time computed for a slowness model S\nm\n, an energy mode E\nj\n, a receiver position R(d\nn\n) and a transmitter position T(d) is noted: \n TT(T(d),R(d\nn\n) \n where j varies from 1 to P, n varies from 1 to N and m varies from 1 to M. \n \nAt block \n850\n, an objective function is selected.', 'The selection may be performed manually by a user or automatically from a set of available objective functions.', 'An objective function is a function that is applied to a set of candidate travel times of a given slowness model and to a set of waveforms (with the preprocessing according to block \n820\n or without the preprocessing) recorded by one or more receivers so as to generate a relevance indicator for the given slowness model.', 'The relevance indicator of a slowness model is also referred to therein as the model relevance indicator.', 'The purpose of the objective function is to provide a numerical tool for automatically identifying which slowness model best matches with a set of recorded waveforms.', 'A model relevance indicator is generated on the basis of the candidate travel times computed for that given slowness model and by comparison with the recorded waveforms (whether preprocessed or not).', 'The model relevance indicator is a numerical value that is globally assigned to the given slowness model considered as a whole and represent a level of relevance of this slowness model.', 'In one or more embodiments, the objective function is configured to take into account several energy modes for the waveforms recorded by the various receivers of the logging tool.', 'The objective function is an analysis tool that is much more robust to erroneous detection of an arrival time compared to a waveform operator applied to a single waveform and a single energy mode.', 'In one or more embodiments, the objective function relies on the application of a non-linear Radon transform to waveform attributes computed by means of one or more waveform operators.', 'In one or more embodiments, the objective function relies on one or more waveform operators that operate on a single waveform basis.', 'A waveform operator may be applied on a single recorded waveform to compute an operator output value representing a relevance indicator for a given candidate travel time computed for a given receiver and a given energy mode.', 'The relevance indicator of a candidate travel time is also referred to therein as the travel time relevance indicator.', 'The waveform operator is selected in such a way that the travel time relevance indicator or operator output value is optimum for a candidate travel time which, for a given waveform, is the best candidate travel time under a given criteria represented by the waveform operator itself.', 'An operator output value for a candidate travel time is optimum for example if the operator output value reaches a maximum, a minimum or verify an optimality criteria for the candidate travel time.', 'The objective function defines how the travel time relevance indicators are numerically combined to generate the model relevance indicator.', 'The model relevance indicator of a given slowness model is a numerical combination of the travel time relevance indicators of the candidate travel times computed for the given slowness model.', 'The numerical combination defined by the objective function may rely on a sum, a weighted sum, a multiplication, a weighted multiplication or any mathematical function that combines the travel time relevance indicators in such a way that the output of the objective function (i.e. the model relevance indicator) increases when any of the travel time relevance indicator increases.', 'Examples of objective functions and waveform operators are described below.', 'The waveform operator may be the so called “Short Term Average/Long Term Average” (hereafter STALTA) operator, the “Akaike Information Criterion” (hereafter AIC), the “Bayes Information Criterion” (hereafter BIC) or a high-order statistics operators.', 'The STALTA operator may be defined on the basis of a positive function g(t) applicable to a waveform.', 'For example the function g(t) may extract the Hilbert envelop of the waveform or a squared waveform amplitude.', 'In the below equation (eq1), t is a candidate travel time for which the operator output value/travel time relevance indicator is computed, sw and lw define a temporal window around the candidate travel time t, and ε is a small real number used for the purposes of the stabilization of the division process:\n \n \n \n \n \n \n \n \n \n \nSTALTA\n \ng\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n=\n \n \n \nlw\n \nsw\n \n \n·\n \n \n \n \n∫\n \nt\n \n \nt\n \n+\n \nsw\n \n \n \n\u2062\n \n \n \ng\n \n\u2061\n \n \n(\n \nu\n \n)\n \n \n \n·\n \ndu\n \n \n \n \n \nɛ\n \n2\n \n \n+\n \n \n \n∫\n \n \nt\n \n-\n \nlw\n \n \nt\n \n \n\u2062\n \n \n \ng\n \n\u2061\n \n \n(\n \nu\n \n)\n \n \n \n·\n \ndu\n \n \n \n \n \n \n \n \n \n \n(\n \n \neq\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n)\n \n \n \n \n \n \n \n where u is a variable that represents the time.', 'The timestamp or time value t at which the STALTA function reaches a maximum over a temporal zone of interest is often considered to be the arrival time of the energy mode of interest.', 'The STALTA function presents a peak around that time value.', 'The STALTA operator is widely used in global seismology data processing for the computation of arrival times of P-wave and S-wave.', 'According to the equation (eq1) above, the operator output value is computed from a portion of the recorded sonic waveform corresponding to a temporal window [t−lw, t+sw] defined relatively to the given candidate travel time t.', 'The AIC operator is defined for example in the document entitled “A new look at the statistical model identification”, by Akaike H., 1974, IEEE Transactions on Automatic Control, 19 (6), p 716-723.', 'The AIC operator aims at detecting changes in a recorded waveform and the AIC operator output increases notably when a change is detected.', 'The most noticeable change observed in the AIC output is often associated to the arrival time of the first energy mode, e.g. the arrival of the P-wave component.', 'The Bayes Information Criterion is defined for example in the document entitled “Estimating the dimension of a model”, by Schwarz G. E., 1978, Annals of Statistics 6.', 'In one or more embodiment, the objective function is called the CSM function (CSM, for Combined Sonic Mapping) and is defined by equation (eq2) below:\n \n \n \n \n \n \n \n \n \n \nCSM\n \nOp\n \n \n\u2061\n \n \n(\n \n \n \ns\n \nm\n \n \nE\n \n1\n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \n2\n \n \n \n,\n \n…\n \n\u2062\n \n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \nP\n \n \n \n \n)\n \n \n \n=\n \n \n \n∑\n \nn\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nK\n \nn\n \n \n·\n \n \n[\n \n \n \n∏\n \n \nj\n \n=\n \n1\n \n \nP\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nOp\n \n \nwf\n \nn\n \n \nE\n \nj\n \n \n \n \n(\n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n)\n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \neq2\n \n)\n \n \n \n \n \n \n \n where: \n \n \n \nK\nn \nis a scaling factor for the receiver of index n; by default this scaling factor can be set to one; and\n \nOp is a waveform operator applicable to an input waveform (e.g. AIC, BIC, STALTA).', 'In view of the above notations,\n \n \n \n \n \n \nOp\n \n \nwf\n \nR\n \n \nE\n \nj\n \n \n \n \n(\n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n)\n \n \n \n \n is the operator output for the preprocessed waveform wf\nR\nE\nj \nand for the candidate travel time \n \n \n \n \n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n,\n \n \n \n \n i.e. \n \n \n \n \n \n \nOp\n \n \nwf\n \nR\n \n \nE\n \nj\n \n \n \n \n(\n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n)\n \n \n \n \n is the travel time relevance indicator, based on the waveform operator Op, of the candidate travel time \n \n \n \n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n \n \n corresponding to the receiver R(d\nn\n) at a position d\nn\n.', 'Similarly CSM\nOp\n(s\nm\nE\n1\n, s\nm\nE\n2\n, . . .', ', s\nm\nE\nP\n) is the model relevance indicator, based on the waveform operator Op, of the slowness model Sm for energy modes E\n1 \nto E\nP\n.', 'When choosing STALTA as the waveform operator, we obtain the expression of CSM\nSTALTA \nas given by equation (eq3).', 'CSM\n \nSTALTA\n \n \n\u2061\n \n \n(\n \n \n \ns\n \nm\n \n \nE\n \n1\n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \n2\n \n \n \n,\n \n…\n \n\u2062\n \n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \np\n \n \n \n \n)\n \n \n \n=\n \n \n \n∑\n \nn\n \n \n\u2062\n \n \n \nK\n \nn\n \n \n·\n \n \n[\n \n \n \n∏\n \n \nj\n \n=\n \n1\n \n \nP\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nSTALTA\n \n \nwf\n \nn\n \n \nE\n \nj\n \n \n \n \n(\n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n)\n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \n \neq\n \n\u2062\n \n \n \n \n\u2062\n \n3\n \n \n)\n \n \n \n \n \n \n \n \nLikewise, when choosing AIC as the waveform operator for CSM, we obtain the expression of CSM\nAIC \nas given by equation (eq4).', 'CSM\n \nAIC\n \n \n\u2061\n \n \n(\n \n \n \ns\n \nm\n \n \nE\n \n1\n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \n2\n \n \n \n,\n \n…\n \n\u2062\n \n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \np\n \n \n \n \n)\n \n \n \n=\n \n \n \n∑\n \nn\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nK\n \nn\n \n \n·\n \n \n[\n \n \n \n∏\n \n \nj\n \n=\n \n1\n \n \nP\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nAIC\n \n \nwf\n \nn\n \n \nE\n \nj\n \n \n \n \n(\n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n)\n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \neq4\n \n)', 'In one or more embodiment, the objective function is called the GSTC function (GSTC, for General Slowness Time Coherence) and is defined by equation (eq5) below:\n \n \n \n \n \n \n \n \n \n \nGSTC\n \nOp\n \n \n\u2061\n \n \n(\n \n \n \ns\n \nm\n \n \nE\n \n1\n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \n2\n \n \n \n,\n \n…\n \n\u2062\n \n \n \n \n,\n \n \ns\n \nm\n \n \nE\n \np\n \n \n \n \n)\n \n \n \n=\n \n \n \n∏\n \n \nj\n \n=\n \n1\n \n \nP\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n∫\n \n \nt\n \n=\n \n0\n \n \n \nt\n \n=\n \n \nT\n \nw\n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \n∑\n \nn\n \n \n\u2062\n \n \n \nwf\n \nn\n \n \nE\n \nj\n \n \n \n(\n \n \nt\n \n+\n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n \n)\n \n \n \n]\n \n \n2\n \n \n·\n \ndt\n \n \n \n \nN\n \n·\n \n \n \n∑\n \nn\n \n \n\u2062\n \n \n \n∫\n \n \nt\n \n=\n \n0\n \n \n \nt\n \n=\n \n \nT\n \nw\n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \nwf\n \nn\n \n \nE\n \nj\n \n \n \n(\n \n \nt\n \n+\n \n \n \nTT\n \n \ns\n \nm\n \n \nE\n \nj\n \n \n \n \n\u2061\n \n \n(\n \n \n \nT\n \n\u2061\n \n \n(\n \nd\n \n)\n \n \n \n,\n \n \nR\n \n\u2061\n \n \n(\n \n \nd\n \nn\n \n \n)\n \n \n \n \n)\n \n \n \n \n)\n \n \n]\n \n \n2\n \n \n·\n \ndt\n \n \n \n \n \n \n \n \n \n \n \n(\n \n \neq\n \n\u2062\n \n \n \n \n\u2062\n \n5\n \n \n)\n \n \n \n \n \n \n \n Where: \n \n \n \nT\nw \nis a window length used to extract a portion of the waveforms.', 'As it comes out from equation (eq6) below, the GSTC function would be equivalent to the STC operator under the additional following conditions: \n \n \n \np is equal to one;\n \nAll the receivers are regularly spaced in the sonic tool;\n \nA refraction model is used in the ray-tracing of the forward modelling;\n \nA constant slowness model value is assumed for the borehole portion where the selected receivers are located.', 'STC\n \nOperator\n \n \n\u2061\n \n \n(\n \n \ns\n \nm\n \n \n)\n \n \n \n=\n \n \n \n \n∫\n \n \nt\n \n=\n \n0\n \n \n \nt\n \n=\n \n \nT\n \nw\n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \n∑\n \nR\n \n \n\u2062\n \n \n \nwf\n \nR\n \n \nE\n \nj\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n+\n \n \n \ns\n \nm\n \n \n·\n \n \n(\n \n \nd\n \n-\n \n \nd\n \nR\n \n \n \n)\n \n \n \n \n)\n \n \n \n \n]\n \n \n2\n \n \n·\n \ndt\n \n \n \n \nN\n \n·\n \n \n \n∑\n \nR\n \n \n\u2062\n \n \n \n∫\n \n \nt\n \n=\n \n0\n \n \n \nt\n \n=\n \n \nT\n \nw\n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \nwf\n \nR\n \n \nE\n \nj\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n+\n \n \n \ns\n \nm\n \n \n·\n \n \n(\n \n \nd\n \n-\n \n \nd\n \nR\n \n \n \n)\n \n \n \n \n)\n \n \n \n]\n \n \n2\n \n \n·\n \ndt\n \n \n \n \n \n \n \n \n \n \n(\n \n \neq\n \n\u2062\n \n \n \n \n\u2062\n \n6\n \n \n)', 'With the objective functions defined therein it is no more a constraint to have a constant spacing between the receivers of a logging tool.', 'There is also no constraint as to the wave propagation mode as different propagation modes may be considered simultaneously.', 'Moreover, the objective function works also with any kind of slowness model, therefore even if there is no constant slowness in the borehole portion where the selected receivers are located.', 'In addition, the different arrival times of different energy modes may be considered simultaneously in order to reduce the risk of false travel time computation.', 'For example, considering jointly the arrival of P-waves, S-waves and Stoneley-waves reduces the risk of erroneous detection of P-wave arrival.', 'The objective function may also operate on a global analysis of the waveforms recorded by the receivers rather than on a single waveform basis.', 'Referring back to \nFIG.', '7B\n, at block \n860\n, a model relevance indicator is computed for each slowness model from the set of waveforms (whether preprocessed or not) recorded by one or more receivers of the logging tool.', 'At block \n870\n, a search for the relevance indicator which is optimum is performed based on the model relevance indicators computed at block \n860\n.', 'At block \n880\n, the set of candidate travel times corresponding to the slowness model for which the objective function is optimum, (e.g. the slowness model for which the model relevance indicator is maximum), are obtained from the search performed at block \n870\n.', 'The objective function is optimum for example when the output value of the objective function reaches a maximum, a minimum or verify a given optimality criteria for a set of candidate travel times corresponding to a slowness model.', 'The candidate travel times corresponding to the slowness model for which the objective function is optimum are referred to therein as the “matching travel times”.', 'At block \n885\n, a time-picking algorithm may be used to compare the matching travel times with travel times determined on a single waveform basis with a given waveform operator applied directly to a recorded waveform (without forward modelling).', 'FIG.', '8\n illustrates the principles of the time-picking using the STALTA operator.\n \nFIG.', '8\n shows example input waveforms together with the associated STALTA output curves.', 'The output of the STALTA waveform operator may include peaks (maximum values) corresponding to the best candidate travel times for P-waves (PP) and S-waves (SP) respectively.', 'A set of candidate arrival times obtained at block \n650\n as the result of the forward modelling are also represented, both for the P-waves (circles PC) and for the S-waves (circles SC).', 'A maximum of the objective function is achieved for the most relevant or optimum slowness model and the matching travel times would in this example match those generated by the STALTA operator.', 'FIG.', '8\n illustrates the situation of non-matching travel times for the purpose of illustration.', 'By applying locally a time-picking refining approach based on a waveform operator (STALTA, AIC or BIC) that operates on a single waveform basis, the results obtained at block \n880\n may thus be evaluated.', 'In some embodiments, time delay techniques can be used to refine the time-picks.', 'The forward modelling and the operations of blocks \n830\n to \n880\n or \n830\n to \n885\n may be performed several times before the operations of block \n890\n are performed.', 'At block \n890\n, one or more slowness estimate is obtained for the subterranean formation on the basis of the matching travel times.', 'A slowness estimate is one of the slowness values of a geological cells of the most relevant slowness model or a combination of these slowness values.', 'The slowness estimate may be computed for one or more energy mode.', 'A slowness map may be generated and displayed on a screen of a device.', 'A slowness map represents relevance indicators of slowness values computed for a given energy mode at different depths with a given function.', 'The given function may be an objective function described therein or a waveform operator.', 'FIGS.', '9 and 10\n show examples of slowness maps resulting from the processing of the waveforms acquired by an acoustic tool with an array of 13 receivers in two different situations.', 'In order to be able to compare the output of different functions, the processing has been performed under the following conditions: the slowness is assumed to be constant over the area covered by the logging tool; the receivers are regularly spaced so that the STC method can be used as a reference method; the travel time between the transmitter and the nearest receiver is measured.', 'These two \nFIGS.', '9 and 10\n are made of four panels.', 'Panel \n1\n, on the left, displays the waveforms recorded by the receivers with the associated estimated arrival-times.', 'On this panel a straight line PL or SL may be drawn between the arrival times of the P-wave or respectively the S-waves, and this straight line intersects with the horizontal axis.', 'This straight line illustrates the linear relationship that exists between the depth (or receiver position) and the corresponding travel time when the slowness is uniform in the borehole.', 'Panel \n2\n shows a slowness map according to the STC output for P-waves.', 'Panel \n3\n shows a slowness map according to the CSM\nSTALTA \noutput for P-waves.', 'Panel \n4\n, on the right, shows a slowness map according to the CSM\nAIC \noutput for P-waves.', 'The grey level of a point of these slowness maps is representative of the relevance of the slowness value at the corresponding depth/time value.', 'In each panels 2 to 4 a dark circle SV\n1\n, SV\n2\n, SV\n3\n or respectively SV\n4\n, SV\n5\n, SV\n6\n is represented that corresponds to the higher relevance indicator corresponding to the most relevant slowness value at the corresponding depth.', 'FIG.', '9\n shows that both CS\nSTALTA \nand CSM\nAIC \nestimate the adequate P-waves slowness (SV\n2\n, SV\n3\n).', 'Instead, STC is subject to a cycle skipping effect and returns the S-waves slowness value (SV\n1\n).', 'FIG.', '10\n shows that the three tested methods provide comparable P-waves slowness estimates (SV\n4\n, SV\n5\n, SV\n6\n).', 'It is, however, clear that the STC map is much more subject to false alarms (much more noisy and irregular) than the two other CSM\nSTALTA \nmap or the CSM\nAIC \nmap.', 'A sonic slowness estimation algorithm has been described.', 'The described algorithm may be used to process the data of acoustic logging tools with any receiver configuration, i.e. no restriction is needed for the acoustic receivers to be regularly spaced.', 'The method for estimating sonic slowness described therein may be used for monopole data, dipole data acquired with wireline sonic tools or with Logging While Drilling (LWD) sonic tools.', 'Thanks to its flexibility, the described method may be applied to sonic tools regardless of their receiver configuration.', 'More specifically there is no constraint about having a constant receiver spacing in the data acquisition tool.', 'Thanks to the non-linear Radon transform, the slowness estimation method described therein combines the use of information criteria such as STALTA, AIC or BIC with forward modelling based on ray-tracing, in order to get the best match between model and observed data on a shot gather basis.', 'Additionally, the method allows for the joint detection of several energy modes.', "The method generates travel times from several slowness models for the subterranean formation thus ensuring that the computed travel times are consistent with a slowness model, and therefore consistent one with each other's.", 'This provides a more robust approach for estimating sonic slowness, with less false detections of arrival times.', 'A reduction of user intervention on the computed travel times or slownesses may be achieved.', 'The slowness estimation method described therein is applicable both to in-field and post-processing of sonic logging data.', 'Although the preceding description has been done herein with reference to particular means, materials, and embodiments, it is not intended to be limited to the particular disclosed herein.', 'By way of further example, embodiments may be utilized in conjunction with a handheld system (i.e., a phone, wrist or forearm mounted computer, tablet, or other handheld device), portable system (i.e., a laptop or portable computing system), a fixed computing system (i.e., a desktop, server, cluster, or high performance computing system), or across a network (i.e., a cloud-based system).', 'As such, embodiments extend to functionally equivalent structures, methods, uses, program products, and compositions as are within the scope of the appended claims.'] | ['1.', 'A method for estimating sonic slowness in a subterranean formation, comprising:\nobtaining a plurality of sonic waveforms received by a plurality of receivers after emission of a source sonic wave by a transmitter through the subterranean formation to obtain a plurality of recorded sonic waveforms, the plurality of receivers located at different positions in the subterranean formation;\nobtaining at least two slowness models of the subterranean formation, a slowness model being defined by at least one cell of constant slowness for at least one wave energy mode;\ncomputing, for each slowness model, a set of candidate travel times, each candidate travel time of a set of candidate travel times being computed for one said wave energy mode and a position of the transmitter and a position of a receiver in the plurality of receivers;\ncomputing a relevance indicator for each set of candidate travel times based on the recorded sonic waveforms by extracting from at least one of the recorded sonic waveforms at least two wave components corresponding respectively to at least two wave energy modes and computing the relevance indicator for the corresponding set of candidate travel times by numerically combining operator output values corresponding to the at least two wave energy modes;\nsearching a match between the sets of candidate travel times and the recorded sonic waveforms by searching the relevance indicators for a relevance indicator that is optimum; and\ncomputing a sonic slowness estimate for the subterranean formation from a set of candidate travel times for which the relevance indicator is optimum.', '2.', 'The method according to claim 1, wherein each of the operator output values is computed by applying at least one waveform operator to a recorded sonic waveform received by the receiver at a position corresponding to one of the candidate travel times, the operator output value being indicative of a relevance of the one of the candidate travel times.', '3.', 'The method according to claim 2, further comprising:\npreprocessing each recorded sonic waveform to extract at least one wave component corresponding to a wave energy mode; and\ncomputing each of the operator output values for each of the candidate travel times corresponding to a given energy mode by applying the waveform operator to the extracted wave component corresponding to the given energy mode.', '4.', 'The method according to claim 3, wherein each set of candidate travel times comprises, for each position of a receiver in the subterranean formation, at least two candidate travel times corresponding to two respective distinct wave energy modes.', '5.', 'The method according to claim 4, wherein the preprocessing of each recorded sonic waveform is performed to extract from each recorded sonic waveform the at least two wave components corresponding respectively to the at least two wave energy modes.', '6.', 'The method according to claim 2, wherein each of the operator output values is computed from a portion of the recorded sonic waveform corresponding to a temporal window defined relatively to a given candidate travel time.', '7.', 'The method according to claim 1, wherein each set of candidate travel times comprises, for each wave energy mode, at least two candidate travel times corresponding to at least two respective distinct positions of a receiver in the subterranean formation.', '8.', 'The method according to claim 1, comprising utilizing a waveform operator to compute operator output values wherein the wavefrom operator is based on a criterion selected from the group consisting of the Akaike Information Criterion (AIC), the Bayes Information Criterion (BIC) and the Short Term Average/Long Term Average (STALTA).', '9.', 'The method according to claim 1, wherein each of the wave energy modes represents an energy mode corresponding to a wave component selected from the group consisting of a compressional wave component, a shear wave component, a Stoneley wave component, a Rayleigh wave component, and a mud wave component.', '10.', 'The method of claim 1, wherein the plurality of receivers and the transmitter are arranged along a logging tool.', '11.', 'The method of claim 10, wherein each of the plurality of receivers comprises an axial position along the logging tool, wherein the axial positions differ.', '12.', 'The method of claim 1, wherein the slowness model comprises geological cells.', '13.', 'The method of claim 12, wherein the slowness model models a wave emitted by a transmitter position as propagating through one or more of the geological cells.', '14.', 'The method of claim 13, wherein the slowness model models the wave as being at least one of reflected back by a wall of a borehole at a geological cell level and propagated along the wall of the borehole at a geological cell interface and out of one or more of the geological cells before reaching a receiver position of one of the plurality of receivers.', '15.', 'The method of claim 1, wherein the slowness model comprises geological cells arranged in layers.', '16.', 'The method of claim 15, wherein at least one of the layers comprises at least two geological cells.', '17.', 'A computing system comprising:\none or more processors for processing data; and\none or more memories operatively coupled to the one or more processors that comprise program instructions for causing said one or more processors to perform a method for estimating sonic slowness that comprises: obtaining a plurality of sonic waveforms received by a plurality of receivers after emission of a source sonic wave by a transmitter through the subterranean formation to obtain a plurality of recorded sonic waveforms, the plurality of receivers located at different positions in the subterranean formation; obtaining at least two slowness models of the subterranean formation, a slowness model being defined by at least one cell of constant slowness for at least one wave energy mode; computing, for each slowness model, a set of candidate travel times, each candidate travel time of a set of candidate travel times being computed for one said wave energy mode and a position of the transmitter and a position of a receiver in the plurality of receivers; computing a relevance indicator for each set of candidate travel times based on the recorded sonic waveforms by extracting from at least one of the recorded sonic waveforms at least two wave components corresponding respectively to at least two wave energy modes and computing the relevance indicator for the corresponding set of candidate travel times by numerically combining operator output values corresponding to the at least two wave energy modes; searching a match between the sets of candidate travel times and the recorded sonic waveforms by searching the relevance indicators for a relevance indicator that is optimum; and computing a sonic slowness estimate for the subterranean formation from a set of candidate travel times for which the relevance indicator is optimum.', '18.', 'One or more non-transitory computer-readable media comprising processor-executable instructions executable to cause a computing system to:\nobtain a plurality of sonic waveforms received by a plurality of receivers after emission of a source sonic wave by a transmitter through the subterranean formation to obtain a plurality of recorded sonic waveforms, the plurality of receivers located at different positions in the subterranean formation;\nobtain at least two slowness models of the subterranean formation, a slowness model being defined by at least one cell of constant slowness for at least one wave energy mode;\ncompute, for each slowness model, a set of candidate travel times, each candidate travel time of a set of candidate travel times being computed for one said wave energy mode and a position of the transmitter and a position of a receiver in the plurality of receivers;\ncompute a relevance indicator for each set of candidate travel times based on the recorded sonic waveforms by extracting from at least one of the recorded sonic waveforms at least two wave components corresponding respectively to at least two wave energy modes and computing the relevance indicator for the corresponding set of candidate travel times by numerically combining operator output values corresponding to the at least two wave energy modes;\nsearch a match between the sets of candidate travel times and the recorded sonic waveforms by searching the relevance indicators for a relevance indicator that is optimum; and\ncompute a sonic slowness estimate for the subterranean formation from a set of candidate travel times for which the relevance indicator is optimum.'] | ['FIG. 1 illustrates a first embodiment of a system with a logging tool for generating sonic data;; FIG.', '2 illustrates a second embodiment of a system with a logging tool for generating sonic data;; FIG.', '3 illustrates a third embodiment of a system with a logging tool for generating sonic data;; FIGS.', '4A and 4B illustrate an example of an embodiment of a computing system for processing sonic data;; FIG.', '4C illustrate an example system for processing sonic data;; FIGS.', '5A and 5C illustrate some aspects of the processing of sonic data;; FIG.', '5D illustrates some aspects of the processing of sonic waveforms;; FIG.', '6 illustrates an example of a flowchart of a method for processing of sonic data;; FIGS.', '7A and 7B illustrate an example of a flowchart of a method for estimating sonic slowness;; FIG. 8 illustrates some aspects of the processing of sonic waveforms;; FIG.', '9', 'illustrates some aspects of the processing of sonic waveforms; and; FIG.', '10 illustrates some aspects of the processing of sonic waveforms.; FIG.', '1 illustrates a wellsite system in which the examples disclosed herein can be employed.', 'The wellsite can be onshore or offshore.', 'In this example system, a borehole 11 is formed in subsurface formations by rotary drilling.', 'However, the examples described herein can also use directional drilling, as will be described hereinafter.; FIG.', '2 illustrates a sonic logging-while-drilling tool that can be used to implement the LWD tool 120 or may be a part of an LWD tool suite 120A.', 'An offshore rig 210 having a sonic transmitting source or array 214 may be deployed near the surface of the water.', 'In at least some embodiments, any other type of uphole or downhole source or transmitter may be provided to transmit sonic signals.', 'In some examples, an uphole processor controls the firing of the transmitter 214.; FIG.', '3 depicts an example an apparatus which can be used in implement the examples disclosed herein.', 'In some examples, subsurface formations 331 are traversed by a borehole 332.', 'The borehole 332 may be filled with drilling fluid and/or mud.', 'In the illustrated example, a logging tool 310 is suspended on an armored cable 312 and may have optional centralizers.', 'The cable 312 extends up the borehole 332, over a sheave wheel 320 on a derrick 321 to a winch forming part of surface equipment 350.', 'A depth gauging apparatus may be provided to measure cable displacement over the sheave wheel 320 and the depth of the logging tool 310 in the borehole 332.; FIG.', '4C illustrates a system including a data repository 440 for storing sonic data and related data.', 'The data repository 440 may be used for storing recorded sonic waveforms 452, preprocessed sonic waveforms 459, receiver and transmitter positions 453, slowness models 454, including geological cells 456, energy mode indexes 460 and slowness values 455.', 'The data repository 440 may be used for storing other sonic related data, for example, relevance indicators 450, candidate travel times 451, matching travel times 458, slowness maps 457.; FIGS.', '5A to 5C illustrate several slowness models for a given subterranean formation in which a borehole is drilled.', '; FIG.', '6 show a flowchart in accordance with one or more embodiments of a method for processing sonic data acquired for a subterranean formation.', 'While the various blocks in the flowchart are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'In at least one embodiment, the method may be performed by the computing system 400 (FIG. 4A), by one or more nodes X 422, node Y 424 (FIG.', '4B) of a computing system or by the surface equipment 350 (FIG. 3) operatively connected to a logging tool, for example the logging tool 310, or by any other device for controlling a field operation.', 'In the example embodiment described by reference to FIG.', '6, the subterranean formation includes a borehole.;', 'FIG.', '7A shows a flowchart in accordance with one or more embodiments of a method for estimating slowness for a subterranean formation.', 'While the various blocks in the flowchart are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'In at least one embodiment, the method may be performed by a device operatively connected to a logging tool, for example by the computing system 400 (FIG. 4A), by one or more nodes X 422, node Y 424 (FIG.', '4B) of a computing system, by the surface equipment 350 (FIG. 3) or by any other device for controlling a field operation.', '; FIG.', '7B shows a flowchart in accordance with one or more embodiments of a method for estimating slowness for a subterranean formation on the basis of waveform data recorded by the receivers of a logging tool.', 'While the various blocks in the flowchart are presented and described sequentially, one of ordinary skill will appreciate that at least some of the blocks may be executed in different orders, may be combined or omitted, and at least some of the blocks may be executed in parallel.', 'In at least one embodiment, the method may be performed by a device operatively connected to a logging tool, for example, by the computing system 400 (FIG. 4A), by one or more nodes X 422, node Y 424 (FIG.', '4B) of a computing system, by the surface equipment 350 (FIG. 3) or by any other device for controlling a field operation.', '; FIG.', '8 shows example input waveforms together with the associated STALTA output curves.', 'The output of the STALTA waveform operator may include peaks (maximum values) corresponding to the best candidate travel times for P-waves (PP) and S-waves (SP) respectively.', 'A set of candidate arrival times obtained at block 650 as the result of the forward modelling are also represented, both for the P-waves (circles PC) and for the S-waves (circles SC).', 'A maximum of the objective function is achieved for the most relevant or optimum slowness model and the matching travel times would in this example match those generated by the STALTA operator.', 'FIG.', '8 illustrates the situation of non-matching travel times for the purpose of illustration.; FIGS. 9 and 10 show examples of slowness maps resulting from the processing of the waveforms acquired by an acoustic tool with an array of 13 receivers in two different situations.', 'In order to be able to compare the output of different functions, the processing has been performed under the following conditions: the slowness is assumed to be constant over the area covered by the logging tool; the receivers are regularly spaced so that the STC method can be used as a reference method; the travel time between the transmitter and the nearest receiver is measured.; FIG.', '9 shows that both CSSTALTA and CSMAIC estimate the adequate P-waves slowness (SV2, SV3).', 'Instead, STC is subject to a cycle skipping effect and returns the S-waves slowness value (SV1).', '; FIG.', '10 shows that the three tested methods provide comparable P-waves slowness estimates (SV4, SV5, SV6).', 'It is, however, clear that the STC map is much more subject to false alarms (much more noisy and irregular) than the two other CSMSTALTA map or the CSMAIC map.'] |
|
US11121722 | Compression and timely delivery of well-test data | Mar 18, 2019 | Clement Probel, Carlos Merino, Andriy Gelman, Julius Kusuma | SCHLUMBERGER TECHNOLOGY CORPORATION | Allen Gersho and Robert M. Gray, “Vector Quantization and Signal Compression,” The Springer International Series in Engineering and Computer Science, Nov. 30, 1991. (9 pages).; A.Y. Djourik, et al, “Siberian Solar Radiotelescope: the PCA format of the SSRT data compressor”, Sep. 21, 2003, pp. 278-282.; M. Hans, et al, “Lossless Compression of Digital Audio,” Hewlett Packard Technical Report, CSIP TR-97-07, Nov. 1999. (37 pages).; T. Robinson, “Shorten: Simple lossless and near-lossless waveform compression,” Cambridge University Engineering Department Technical Report, CUED/F-INFENG/TR.156, Dec. 1994. (16 pages).; R.F. Rice, “Some practical universal noiseless coding techniques,” JetPropulsion Laboratory Technical Report, JPL-79-22, Pasadena, Mar. 15, 1979 (130 pages).; G. 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Breton et al., “Well Positioned Seismic Measurements,” Oilfield Review, pp. 32-45, Spring, 2002.; Pistre et al., “A New Sonic Modular Tool Provides Complete Acoustic Formation Characterization”, 2005 Society of Exploration Geophysicists International Exposition and Annual Meeting Proceedings, SEG, Houston, Nov. 6-11, 2005 (5 pages).; International Preliminary Report on Patentability issued in the related PCT Application PCT/US2014/016162, dated Aug. 18, 2015 (5 pages).; International search report and written opinion for the equivalent PCT patent application No. PCT/US2014/016162, dated May 20, 2014. 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includes receiving, by the processor, one or more data from one or more sensors in response to the one or more queries, and storing, by the processor, the one or more data in a buffer coupled to the downhole modem.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a continuation of U.S. patent application Ser.', 'No. 14/060,590 filed Oct. 22, 2013, now U.S. Pat.', 'No. 10,236,906, which is herein incorporated by reference.', 'BACKGROUND\n \nThis disclosure relates to downhole tools, and more particularly to methods and apparatuses for downhole communication between tools.\n \nDESCRIPTION OF THE RELATED ART\n \nOne of the more difficult problems associated with any borehole is to communicate measured data between one or more locations down a borehole and the surface, or between downhole locations themselves.', 'For example, in the oil and gas industry it is desirable to communicate data generated downhole to the surface during operations such as drilling, perforating, fracturing, and drill stem or well testing; and during production operations such as reservoir evaluation testing, pressure and temperature monitoring.', 'Communication is also desired to transmit intelligence from the surface to downhole tools, equipment, or instruments to effect, control or modify operations or parameters.', 'Accurate and reliable downhole communication is desired when complex data comprising a set of measurements or instructions is to be communicated, i.e., when more than a single measurement or a simple trigger signal has to be communicated.', 'For the transmission of complex data it is often desirable to communicated encoded digital signals.', 'Communication, between downhole locations and the surface, or between downhole locations themselves, often employs compression methods to compress data transmitted between the locations.', 'U.S. Pat.', 'No. 7,107,153 describes a compression method for sonic waveforms where multiple compression schemes are tested and chosen based on certain parameters.', 'PAQ data compression may also be used providing a lossless compression package which tests multiple compression schemes and chooses one based on certain parameters.', 'In some existing systems, a downhole modem serves as a relay for user commands from the surface.', 'Data points transmitted by the downhole modem may be equally distributed in order to save bandwidth, where a time of a first point and a time-span between points are included as side information in a message transmitted by the downhole modem.', 'In some existing systems, a number of points per message is constrained.', 'A maximal number of points per message is derived from a worst case, such as a number of bits used to encode a point with full precision and without compression.', 'In existing systems, periodic requests are sent from the surface downhole, and for each request, the time span is calculated such that the points are well-distributed between a time of a last point received and a present time.', 'It may be beneficial to have a method for data compression and a downhole modem configured to perform lossless or near-lossless compression, constrained by a parameter specified by a surface user, where multiple compression schemes may be tested and the compression scheme in compliance with the parameter specified by the user is chosen for encoding the message.', 'It may also be beneficial to interrogate sensors with a downhole modem, continuously performing dynamic mapping of sensor data, such that upon receiving a query from the surface, the sensor data is available and ready for compression.', 'SUMMARY\n \nIn one aspect, some embodiments of the present disclosure are directed to a modem.', 'The modem is described having a transceiver assembly, a non-transitory processor readable medium coupled to the transceiver assembly, transceiver electronics coupled to the transceiver and the non-transitory processor readable medium, and a power supply supplying power to the transceiver assembly and the transceiver electronics.', 'The non-transitory processor readable medium has a buffer storing data from a downhole sensor.', 'The transceiver electronics calculate a size of an output bit stream based on an encoding scheme to encode for transmission data stored in the non-transitory processor readable medium, decimate the data stored in the buffer if the size of the output bit stream exceeds a predetermined size, recalculate the size of the output bit stream, after decimation of the data stored in the buffer, based on the encoding scheme to encode for transmission the decimated data stored in the buffer, and encode the data stored in the buffer using the encoding scheme.', 'In some embodiments, a modem is described for communication in a network via a communication channel.', 'The modem is described as having a transceiver assembly, a non-transitory processor readable medium coupled to the transceiver assembly, transceiver electronics coupled to the transceiver and the non-transitory processor readable medium, and a power supply supplying power to the transceiver assembly and the transceiver electronics.', 'The non-transitory processor readable medium has a buffer storing data from a downhole sensor.', 'The transceiver electronics calculate a size of an output bit stream based on an encoding scheme to encode for transmission data stored in the non-transitory processor readable medium.', 'The transceiver electronics decimate the data stored in the buffer if the size of the output bit stream exceeds a predetermined size; recalculate the size of the output bit stream, after decimation, based on the encoding scheme to encode for transmission the decimated data stored in the buffer; and encode the data stored in the buffer using the encoding scheme.', 'In some embodiments a modem is described for communication in a network via a communication channel.', 'The modem is described as having a transceiver assembly, a non-transitory processor readable medium coupled to the transceiver assembly, transceiver electronics coupled to the transceiver and the non-transitory processor readable medium, and a power supply supplying power to the transceiver assembly and the transceiver electronics.', 'The non-transitory processor readable medium has a buffer storing data samples indicative of measurements from a downhole sensor in communication with the transceiver assembly.', 'The transceiver electronics calculate a number of data samples stored in the buffer able to be encoded into a predetermined budget by a first encoding scheme and a second encoding scheme.', 'The transceiver electronics determine which of the first encoding scheme and the second encoding scheme enables encoding of a larger number of the number of data samples within the predetermined budget.', 'The transceiver electronics then select the encoding scheme enabling encoding of the larger number of the number of data samples within the predetermined budget and encode the number of data samples stored in the buffer using a selected encoding scheme of the first encoding scheme and the second encoding scheme.', 'In another aspect, some embodiments of the present disclosure are directed to a method for encoding and compression of data.', 'The method includes a processor calculating a size of an output bit stream based on an encoding scheme to encode for transmission data stored in a buffer.', 'The data is indicative of measurements of a downhole environment by a downhole sensor.', 'The method is further performed by the processor decimating the data stored in the buffer if the size of the output bit stream exceeds a predetermined size.', 'The processor then recalculates the size of the output bit stream, after decimation of the data stored in the buffer, based on the encoding scheme to encode for transmission the decimated data stored in the buffer.', 'The processor then encodes the data stored in the buffer using the encoding scheme.', 'In some embodiments, the method includes a processor calculating a first size of a first output bit stream based on a first encoding scheme to encode, for transmission, data stored in a buffer.', 'The data is indicative of measurements of a downhole environment by a downhole sensor.', 'The processor calculates a second size of a second output bit stream based on a second encoding scheme to encode, for transmission, the data stored in the buffer.', 'The method is further performed by the processor selecting a selected encoding scheme based upon relative sizes of the first bit stream and the second bit stream.', 'The selected encoding scheme is either the first encoding scheme or the second encoding scheme.', 'The processor then encodes the data stored in the buffer using the selected encoding scheme.', 'In some embodiments, the method is performed by the processor calculating a number of data samples stored in a buffer able to be encoded into a predetermined budget by a first encoding scheme and a second encoding scheme.', 'The data samples are indicative of measurements of a downhole environment by a downhole sensor.', 'The processor determines which of the first encoding scheme and the second encoding scheme enables encoding a larger number of the number of data samples within the predetermined budget.', 'The processor then selects the first encoding scheme or the second encoding scheme enabling encoding of the larger number of the number of data samples within the predetermined budget.', 'The processor then encodes the number of data samples stored in the buffer using a selected encoding scheme of the first encoding scheme and the second encoding scheme.', 'In yet another aspect, some embodiments of the present disclosure are directed to methods for sensor interrogation.', 'As such, a method is described in which a processor performs a query on a sensor, for data collected by the sensor, at predetermined instants of time by a downhole modem operably coupled to the sensor, prior to receiving a request for transmission of the data from a surface modem.', 'The method is further performed by the processor receiving data from the sensor in response to the query and storing the data in a buffer coupled to the downhole modem.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nSo that the manner in which the above recited features can be understood in detail, a more particular description may be had by reference to embodiments, some of which are illustrated in the appended drawings, wherein like reference numerals denote like elements.', 'It should be understood, however, that the appended drawings illustrate some embodiments and are therefore not to be considered limiting of its scope, and may admit to other equally effective embodiments.', 'FIG.', '1\n shows a schematic view of a downhole telemetry system in accordance with the present disclosure.\n \nFIG.', '2\n shows a partial block diagram of a modem constructed in accordance with the present disclosure.\n \nFIG.', '3\n shows a partial schematic view of the downhole telemetry system of \nFIG.', '1\n.', 'FIG.', '4\n shows a diagrammatic representation of a method of sensor interrogation performed by a downhole modem in accordance with the present disclosure.\n \nFIG.', '5\n shows a diagrammatic representation of an encoding and compression scheme performed by a downhole modem in accordance with the present disclosure.\n \nFIG.', '6\n shows a diagrammatic representation of an encoding and compression scheme performed by a downhole modem in accordance with some embodiments of the present disclosure.\n \nFIG.', '7\n shows a diagrammatic representation of another embodiment of the encoding and compression scheme shown in \nFIG.', '6\n.\n \nFIG.', '8\n shows a diagrammatic representation of an encoding and compression scheme performed by a downhole modem in accordance with some embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'In the following description, numerous details are set forth to provide an understanding of the present disclosure.', 'It will be understood by those skilled in the art, however, that the embodiments of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.', 'In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.', 'In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”.', 'Further, the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”.', 'As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure.', 'The terminology and phraseology used herein is for descriptive purposes and should not be construed as limiting in scope.', 'Language such as “including,” “comprising,” “having,” “containing,” or “involving,” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited or inherently present therein.', 'Unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or.', 'For example, a condition A or B is satisfied by anyone of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).', 'In addition, use of the “a” or “an” are employed to describe elements and components of the embodiments herein.', 'This is done merely for convenience and to give a general sense of the inventive concepts.', 'This description should be read to include one or at least one and the singular also includes the plural unless it is obvious that it is meant otherwise.', 'Further, as used herein any reference to “one embodiment” or “an embodiment” means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment.', 'The appearances of the phrase “in one embodiment” in various places in the specification are not necessarily all referring to the same embodiment, although the inventive concepts disclosed herein are intended to encompass any and all combinations and permutations of the features of the embodiments described herein.', 'The present disclosure generally involves a system and methodology to perform lossless or near-lossless data compression and sensor interrogation.', 'The methodology may be used in conjunction with a modem and/or in the context of wireless downhole testing telemetry.', 'The system may compress data measured by a downhole sensor before sending the data to the surface.', 'In some embodiments, the compression system and methodology may be stored on a downhole modem.', 'The data compression may be constrained by a parameter specified by a surface user.', 'In some embodiments, multiple compression schemes may be tested and the compression scheme with the highest quality performance may be used for encoding the data to be sent to the surface.', 'In some embodiments, multiple-scheme compression may be particularly suited for bandwidth-constrained environments.', 'The sensor interrogation system and method may be employed on a downhole modem coupled to one or more sensor.', 'The sensor interrogation method may continuously, or at intervals, perform dynamic mapping of sensor data with limited space allocated to the storage of the sensor data within memory of the modem.', 'Upon receiving a command from the surface, the data queried is available and ready for compression.', 'The combination of the compression system and methodology and the sensor interrogation system and methodology may increase bandwidth usage and efficient real-time reconstruction of sensor curve data at the surface.', 'Referring now to \nFIG.', '1\n, shown therein is a schematic view of a well \n10\n, such as an oil and gas production well, testing well, or other well \n10\n.', 'Once the well \n10\n has been drilled to form a borehole, the drilling apparatus is removed from the well \n10\n and test may be performed to determine properties of a formation through which the well \n10\n has been drilled.', 'In the example of \nFIG.', '1\n, the well \n10\n has been drilled and lined with a steel casing \n12\n (cased hole) in a conventional manner.', 'However, it should be understood that similar systems may be used in unlined (open hole) environments.', 'In order to test the formation, one or more testing apparatus may be placed in the well \n10\n close to one or more regions to be tested, in this case the formation.', 'Placing the one or more testing apparatus proximate to one of the regions to be tested enables isolation of sections or intervals of the well \n10\n, and enables conveyance of fluids from regions of interest to a surface; certain of the regions of interest may be the region to be tested.', 'Conveying fluids to the surface may be performed using an elastic media \n14\n, such as a drill pipe \n16\n.', 'The drill pipe \n16\n may be a jointed tubular drill pipe extending from well head equipment \n18\n at the surface (or sea bed in subsea environments) down inside the well \n10\n to a zone of interest, which may coincide with the formation or one of the regions of interest.', 'Although the elastic media \n14\n will be described herein with respect to the drill pipe \n16\n, it should be understood that the elastic media \n14\n may take other forms, such as production tubing, a drill string, a tubular casing, or the like.', 'The well head equipment \n18\n may include blow-out preventers and connections for fluid, power, and data communication.', 'A packer \n20\n may be positioned on the drill pipe \n16\n and may be actuated to seal the borehole around the drill pipe \n16\n at one of the regions of interest.', 'Various pieces of downhole equipment \n22\n for testing and the like may be connected to the drill pipe \n16\n at varying locations, above or below the packer \n20\n, such as a sampler \n24\n or a tester valve \n26\n.', 'The downhole equipment \n22\n may also be referred to herein as a “downhole tool.”', 'Other examples of downhole equipment \n22\n may include: further packers, circulation valves, downhole chokes, firing heads, TCP (tubing conveyed perforator) gun drop subs, pressure gauges, downhole flow meters, downhole fluid analyzers, etc.', 'As shown in \nFIG.', '1\n, the sampler \n24\n and the tester valve \n26\n may be located above the packer \n20\n.', 'In order to support signal transmission along the drill pipe \n16\n between a downhole location and the surface, a series of modems \n28\n may be positioned along the drill pipe \n16\n and mounted to the drill pipe \n16\n via any suitable method, such as clamps \n30\n or gauge carriers to form a telemetry system \n32\n.', 'As shown in \nFIG.', '1\n, the telemetry system is provided with a first modem \n28\n-\n1\n, a second modem \n28\n-\n2\n, a third modem \n28\n-\n3\n, and a fourth modem \n28\n-\n4\n connected to the drill pipe.', 'In some embodiments, the series of modems \n28\n may be connected to the drill pipe \n16\n via clamps \n30\n such as a first clamp \n30\n-\n1\n, a second clamp \n30\n-\n2\n, a third clamp \n30\n-\n3\n, and a fourth clamp \n30\n-\n4\n, respectively.', 'In some embodiments, certain of the series of modems \n28\n may be connected to the drill pipe \n16\n via clamps \n30\n and certain of the series of modems \n28\n may be connected to the drill pipe \n16\n via gauge carriers.', 'For example, the fourth modem \n28\n-\n4\n representing the modem furthest downhole of the series of modems \n28\n may be connected to the drill pipe via a gauge carrier, while the first, second, and third modems \n28\n-\n1\n, \n28\n-\n2\n, and \n28\n-\n3\n, respectively, are connected to the drill pipe \n16\n via clamps \n30\n.', 'The downhole equipment \n22\n is shown to be connected to the fourth modem \n28\n-\n4\n positioned between the sampler \n24\n and the tester valve \n26\n.', 'However, it should be understood that downhole equipment \n22\n may be connected to one or more of the series of modems \n28\n.', 'The series of modems \n28\n may be of varying types and may be configured to communicate with each other via at least one communication channel \n34\n using one or more protocols.', 'For example.', 'The series of modems \n28\n may be wireless modems such as acoustic modems.', 'Acoustic modems may be implemented as electro-mechanical devices adapted to convert one type of energy or physical attribute to another, and may also transmit and receive at least one type of energy, thereby allowing electrical signals received from the downhole equipment \n22\n to be converted into acoustic signals for transmission to the surface, or for transmission to other locations of the drill pipe \n16\n.', 'In some embodiments, the series of modems \n28\n may be wired modems communicating through a wired network connection extending between the series of modems \n28\n.', 'In some embodiments, the series of modems \n28\n may be wireless modems which do not operate as acoustic modems.', 'Where implemented as acoustic modems, the series of modems \n28\n may be configured to transmit data between one or more of the series of modems \n28\n along an acoustic wireless network including the at least one communication channel \n34\n.', 'In this embodiment, the series of modems \n28\n may transmit signals along the drill pipe \n16\n by creating vibrations within the drill pipe \n16\n.', 'The signals radiating from a transmitting modem of the series of modems \n28\n may emanate omnidirectionally from the transmitting modem along the drill pipe \n16\n to be received by a receiving modem of the series of modems \n28\n for which the signal was intended or as a next hop toward a destination modem of the series of modems \n28\n.', 'In this example, the at least one communication channel \n34\n is formed along the drill pipe \n16\n, although it should be understood that the communication channel \n34\n may take other forms, such as production tubing and/or casing.', 'In addition, the series of modems \n28\n, implemented as acoustic modems, may operate to convert acoustic tool control signals from the surface into electrical signals for operating the downhole equipment \n22\n, as well as transmitting to and receiving signals from the downhole equipment \n22\n.', 'As shown, the first modem \n28\n-\n1\n is provided as a surface modem and may be provided as part of the well head equipment \n18\n or separate therefrom.', 'The first modem \n28\n-\n1\n may be coupled via a connection \n36\n to a control system \n38\n.', 'The connection \n36\n may be a wired connection, such as a data cable, or wireless connection.', 'The well head equipment \n18\n, in some embodiments, may provide a connection between the drill pipe \n16\n and the connection \n36\n.', 'The control system \n38\n may be configured to receive data from and transmit signals to the downhole equipment \n22\n, via the telemetry system \n32\n, for example to provide signals for control and operation of the downhole equipment \n22\n.', 'In some embodiments, the control system \n38\n may be implemented as a computer system and the wireless connection \n36\n as a WiFi or other wireless network through which the computer system may receive information.', 'In this embodiment, the control system \n38\n may be provided with a processor (not shown), a non-transitory processor readable medium (not shown), an input (not shown), an output (not shown), and a communications device (not shown).', 'As such, the control system \n38\n may be implemented as any suitable computer system such as a desktop computer, a laptop, a tablet, a smart phone, a portable digital assistant, a server, a distributed computing system, a server network, a cloud computing system, or any other suitable computer system.', 'In some embodiments, the telemetry system \n32\n may be used to provide communication between the control system \n38\n and one or more of the series of modems \n28\n and/or downhole equipment \n22\n coupled to one or more of the series of modems \n28\n.', 'In some embodiments, acoustic telemetry may be used for communication between the downhole equipment \n22\n in multi-zone testing.', 'In this case, two or more zones of the well \n10\n are isolated by means of one or more packers \n20\n.', 'Certain of the downhole equipment \n22\n used for testing is located in each isolated zone and coupled to one or more of the series of modems \n28\n corresponding with the isolated zone in which the downhole equipment \n22\n is located.', 'Operation of the series of modems \n28\n allows the downhole equipment \n22\n in each zone to communicate with each other as well as the downhole equipment \n22\n in other zones.', 'The series of modems \n28\n may also allow communication from the control system \n38\n with control data and signals in the manner described above, which will be described in more detail below.', 'In general, in some embodiments where the series of modems \n28\n are acoustic modems, acoustic signals generated by the series of modems \n28\n may pass along the drill pipe \n16\n as longitudinal and/or flexural waves.', 'Each wave may optionally include information indicative of data received from one or more sensor, such as the downhole equipment \n22\n, information indicative of a request for sensor data from the downhole equipment \n22\n, control signals, and other information.', 'The information within the waves may be compressed using encoding schemes, as discussed in more detail below.', 'The waves may further be modulated such that the acoustic signal may have a frequency in the range between about 100 Hz-1 MHz and may be configured to pass data at a rate of between about 1 bps and about 10 kbps.', 'Data rates may be dependent on conditions such as noise levels, carrier frequencies, acoustic channel properties, distances between any two of the series of modems \n28\n, and other factors.', 'In some embodiments, certain of the series of modems \n28\n may be configured as repeaters, for example the first, second, and third modems \n28\n-\n1\n, \n28\n-\n2\n, and \n28\n-\n3\n.', 'The data and/or control signals may be transmitted from the control system \n38\n initially to the first modem \n28\n-\n1\n acting as a surface modem to be repeated and thereby transmitted to the second and third modems \n28\n-\n2\n and \n28\n-\n3\n as acoustic signals.', 'Similarly, data may be transmitted by the fourth modem \n28\n-\n4\n via the first, second, and third modems \n28\n-\n1\n, \n28\n-\n2\n, and \n28\n-\n3\n to the control system \n38\n in response to data requests, for example.', 'As repeater modems, the first, second, and third modems \n28\n-\n1\n, \n28\n-\n2\n, and \n28\n-\n3\n are capable of receiving an acoustic signal generated in the drill pipe \n16\n by a preceding modem and to amplify and retransmit the signal for further propagation along the drill pipe \n16\n, or to the control system \n38\n via the connection \n36\n.', 'The number and spacing of the series of modems \n28\n may depend on the particular installation selected, for example, or the distance that a signal travels.', 'Spacing between the series of modems \n28\n may be around 1,000 ft (about 304 m), but may be much more or much less in order to accommodate a variety of testing tool configurations.', 'In some embodiments, the role of the repeater modem, for example the first, second, and third modems \n28\n-\n1\n, \n28\n-\n2\n, and \n28\n-\n3\n, may be to detect an incoming signal, decode the signal, interpret the signal, and subsequently rebroadcast the signal.', 'In some implementations the repeater modem may not decode the signal, but merely amplify the signal (and the noise) and retransmit the signal.', 'In this case, the first, second, and third modems \n28\n-\n1\n, \n28\n-\n2\n, and \n28\n-\n3\n may act as simple signal boosters.', 'In some embodiments, the repeater modems may listen continuously for any incoming signal, while in other embodiments, the repeater modems may listen intermittently.', 'Acoustic wireless signals, conveying commands or messages, may propagate in the transmission medium (the drill pipe \n16\n, fluid within the well \n10\n, or the like) in an omnidirectional fashion.', 'The series of modems \n28\n may not know whether the acoustic signal is coming from another of the series of modems \n28\n above or below within the telemetry system \n32\n.', 'Each message may contain one or more network address, for example an address of a modem which initially transmitted the message, an address of a modem which last transmitted the message, an address of a modem which is the next hop in the communications channel \n34\n, and/or an address of a destination modem which is the intended recipient of the message, for example the fourth modem \n28\n-\n4\n connected to the downhole equipment \n22\n.', 'Based on the one or more network address embedded in the message, the repeater modems may interpret the message and construct a new message with updated information with regards to the one or more network address, for example by changing the address of the next hop modem in the communication channel \n34\n and/or the destination address.', 'Messages being sent from the surface may be transmitted from the first modem, \n28\n-\n1\n, to the second modem \n28\n-\n2\n, to the third modem \n28\n-\n3\n, and to the fourth modem \n28\n-\n4\n, and at least partially modified along the way to include new network addresses.', 'Referring now to \nFIG.', '2\n, therein shown is a partial schematic drawing of some embodiments of one of the series of modems \n28\n.', 'For clarity, the series of modems \n28\n will be described in reference to a single modem, in this case the fourth modem \n28\n-\n4\n.', 'The fourth modem \n28\n-\n4\n may include a transceiver assembly \n40\n, transceiver electronics \n42\n coupled to the transceiver assembly \n40\n, a non-transitory processor readable medium \n44\n coupled to the transceiver electronics \n42\n, and a power supply \n46\n supplying power to the transceiver assembly \n40\n, transceiver electronics \n42\n, and the non-transitory processor readable medium \n44\n.', 'As shown in \nFIG.', '2\n, the fourth modem \n28\n-\n4\n may be provided with multiple transceiver assemblies \n40\n-\n1\n and \n40\n-\n2\n.', 'The transceiver electronics \n42\n may include transmitter electronics \n48\n and receiver electronics \n50\n configured to perform the functions of the transceiver electronics \n42\n, which will be described in more detail below.', 'The transceiver assembly \n40\n, the transceiver electronics \n42\n, the non-transitory processor readable medium \n44\n, and the power supply \n46\n may be located in a single housing \n52\n.', 'The series of modems \n28\n may be of similar construction and function except as described below.', 'For example, certain of the series of modems \n28\n may be coupled to one or more sensor to receive one or more sensor data stored as data samples on the non-transitory processor readable medium \n44\n, as will be discussed in more detail below.', 'The transceiver assembly \n40\n may be a wired transceiver assembly or a wireless transceiver assembly.', 'For example, in some embodiments the transceiver assembly \n40\n may be an acoustic wireless transceiver assembly.', 'In this embodiment, the transceiver assembly \n40\n may convert electrical signals to acoustic signals and vice-versa.', 'The transceiver assembly \n40\n may thereby generate acoustic signals in the material of the drill pipe \n16\n to transmit data to another of the series of modems \n28\n.', 'However, it should be understood that the transceiver assembly \n40\n may be embodied as other forms including an electromagnetic transceiver assembly; a pressure-type transceiver assembly using technologies such as mud-pulse telemetry, pressure-pulse telemetry, or the like; or a wired transceiver assembly transmitting and receiving signals via a wired connection traveling between the series of modems \n28\n.', 'The transceiver assembly \n40\n will be described herein by way of example as an acoustic type of transceiver assembly, however, it should be understood that the transceiver assembly \n40\n may be implemented in other ways, while performing the same or similar functions.', 'The transceiver electronics \n42\n, as described above, may include the transmitter electronics \n48\n and the receiver electronics \n50\n.', 'In general, the transceiver electronics \n42\n may be adapted to vary parameters of wired or wireless signals transmitted into the communication channel \n34\n by the transceiver assembly \n40\n.', 'For example, the transceiver electronics \n42\n may vary the frequency, bit rate, timing, amplitude, and the like of the signals being sent into the communication channel \n34\n.', 'Two or more variable parameters of the signal generally define a transmission pair for the signal.', 'The transmitter electronics \n48\n may be implemented with a processing unit \n54\n configured to perform functions related to preparing signals for transmission by the transceiver assembly \n40\n.', 'In some embodiments, the transmitter electronics \n48\n may include an amplifier \n56\n, such as a linear amplifier or a non-linear amplifier, to amplify a signal prepared by the processing unit \n54\n.', 'The fourth modem \n28\n-\n4\n may be coupled to one or more sensor \n58\n such that the transmitter electronics \n48\n may initially receive an output signal from the one or more sensor \n58\n, for example from the downhole equipment \n22\n provided from an electrical or electro/mechanical interface.', 'Such signals may be digital signals which may be provided to the one or more processing unit \n54\n.', 'The processing unit \n54\n may modulate the signal in one of a number of known ways, such as FM, PSK, QPSK, QAM, and the like.', 'The resulting modulated signal may then be amplified by the amplifier \n56\n and transmitted to the transceiver assembly \n40\n.', 'In some embodiments, transmitting the modulated signal to the transceiver assembly \n40\n generates a wireless, e.g., acoustic, signal in the material of the drill pipe \n16\n.', 'The receiver electronics \n50\n may be configured to receive the signal produced by and transmitted by another one of the series of modems \n28\n.', 'The receiver electronics \n50\n are capable of converting the signal, such as an acoustic signal, into an electrical signal.', 'In some embodiments, an acoustic signal passing along the drill pipe \n16\n excites the transceiver assembly \n40\n so as to generate an electrical output signal (voltage) to be received by the receiver electronics \n50\n.', 'However, it is contemplated that the acoustic signal may excite an accelerometer (not shown) or an additional transceiver assembly \n40\n so as to generate an electrical output signal (voltage).', 'This signal may be an analog signal carrying digital information.', 'In this embodiment, the receiver electronics \n50\n may be provided with a signal conditioner \n60\n, an ND (analog-to-digital) converter \n62\n, and a processing unit \n64\n.', 'The analog signal may be applied to the signal conditioner \n60\n, which may operate to filter/condition the analog signal to be digitized by the A/D converter \n62\n.', 'The A/D converter \n62\n provides a digitalized signal which may be applied to the processing unit \n64\n.', 'The processing unit \n64\n may be adapted to demodulate the digital signal in order to recover data provided by the one or more sensor \n58\n connected to another one of the series of modems \n28\n, or provided by the surface.', 'The type of signal processing depends on the applied modulation (i.e. FM, PSK, QPSK, QAM, and the like).', 'In some embodiments, data may be provided by any of the series of modems \n28\n with or without the one or more sensor \n58\n.', 'The processing units \n54\n and \n64\n may be implemented as a single processor or multiple processors working together or independently to execute processor executable instructions, described in more detail below.', 'Embodiments of the processing units \n54\n and \n64\n may include one or more micro-controllers, digital signal processors, central processing units, application specific integrated circuits, microprocessors, multi-core processors, or the like.', 'In some embodiments, the processing units \n54\n and \n64\n may be contained within one or more computer, network device, manufacturing tool, or the like, or any device with a set of one or more processors, or multiple devices having one or more processors that work together.', 'The non-transitory processor readable medium \n44\n may be implemented as RAM, ROM, flash memory, or the like, and may take the form of a magnetic device, optical device, or the like.', 'The non-transitory processor readable medium \n44\n may be a single non-transitory processor readable medium or multiple non-transitory processor readable media functioning logically together or independently.', 'The non-transitory processor readable medium \n44\n may be coupled to and configured to communicate the transceiver electronics \n42\n, or the processing units \n54\n and \n64\n within the transceiver electronics \n42\n, via one or more path such as a data bus, for example.', 'The non-transitory processor readable medium \n44\n may store processor executable instructions, as will be described below in more detail, and may also store data structures, such as a database, for example.', 'The data structures on the non-transitory processor readable medium \n44\n may store data such as sensor data from the one or more sensor \n58\n indicative of one or more measurement of a downhole environment, or a parameter within the downhole environment, to which the one or more sensor \n58\n may be exposed.', 'The power supply \n46\n may be configured to supply power to the transceiver assembly \n40\n; the transceiver electronics \n42\n, including the transmitter electronics \n48\n and the receiver electronics \n50\n; and the non-transitory processor readable medium \n44\n.', 'The power supply \n46\n may be implemented as one or more battery, such as a lithium battery, for example.', 'It should be understood that the power supply \n46\n may be implemented as any suitable battery capable of powering the transceiver assembly \n40\n, the transceiver electronics \n42\n, and the non-transitory processor readable medium \n44\n.', 'Referring now to \nFIG.', '3\n, shown therein is a diagrammatic representation of the telemetry system \n32\n, showing the first and fourth modems \n28\n-\n1\n and \n28\n-\n4\n positioned at either end of the communication channel \n34\n in a downhole environment.', 'The first modem \n28\n-\n1\n may be operably coupled to the control system \n38\n to transmit/receive information between the control system \n38\n and the fourth modem \n28\n-\n4\n.', 'The first modem \n28\n-\n1\n may communicate with the fourth modem \n28\n-\n4\n via the communications channel \n34\n, for example through acoustic vibrations across the drill pipe \n16\n.', 'The fourth modem \n28\n-\n4\n may be operably coupled to one or more sensor \n70\n via a communication path \n72\n.', 'As shown the fourth modem \n28\n-\n4\n is connected to a first sensor \n70\n-\n1\n, a second sensor \n70\n-\n2\n, and a third sensor \n70\n-\n3\n via a first communication path \n72\n-\n1\n, a second communication path \n72\n-\n2\n, and a third communication path \n72\n-\n3\n, respectively.', 'The first, second, and third sensors \n70\n-\n1\n, \n70\n-\n2\n, and \n70\n-\n3\n may be implemented similarly to the sensor \n58\n, as the downhole equipment \n22\n.', 'The first, second, and third communication path \n72\n-\n1\n, \n72\n-\n2\n, and \n72\n-\n3\n may be implemented as a data bus, a wired connection, or a wireless connection, for example.', 'As shown, the non-transitory processor readable medium \n44\n may store a buffer \n74\n and processor executable instructions \n76\n.', 'As will be explained below in more detail, the fourth modem \n28\n-\n4\n may interrogate the one or more sensor \n70\n for data, such as one or more measurement of the downhole environment, for example.', 'The processing unit \n54\n or the processing unit \n64\n may store the data received from the one or more sensor \n70\n in the buffer \n74\n.', 'The fourth modem \n28\n-\n4\n may communicate with the first modem \n28\n-\n1\n via the transceiver assembly \n40\n transmitting and receiving at least a portion of the data stored in the buffer \n74\n which may be encoded for transmission, at least in part.', 'The processor executable instructions \n76\n may be configured to be read and/or to be executed by the processing unit \n54\n and/or \n64\n.', 'The processor executable instructions \n76\n may include a sensor interrogation program \n76\n-\n1\n, a compression program \n76\n-\n2\n, and other processor executable instructions \n76\n-\n3\n, such as firmware, an operating system, encoding instructions, and decoding instructions, for example.', 'The processor executable instructions \n76\n may be written in any suitable programming language, such as C++, C#, Java, Python, Basic, or any other high-level or low-level programming languages, for example.', 'Referring now to \nFIG.', '4\n, shown therein is a diagrammatic representation of one embodiment of the sensor interrogation program \n76\n-\n1\n stored in the non-transitory processor readable medium \n44\n.', 'In use, the processing unit \n54\n, executing the processor executable instructions for the sensor interrogation program \n76\n-\n1\n, may perform a first set of one or more queries \n80\n on the one or more sensor \n70\n for one or more data \n82\n collected by the one or more sensor \n70\n, as indicated by block \n84\n.', 'The one or more data \n82\n may be data samples indicative of one or more measurement from one or more sensor \n70\n.', 'The processing unit \n54\n may then receive the one or more data \n82\n from the one or more sensor \n70\n in response to the one or more queries \n80\n, as indicated by block \n88\n.', 'The processing unit \n54\n may receive a command \n90\n from the first modem \n28\n-\n1\n, indicative of a request for the one or more data \n82\n from the fourth modem \n28\n-\n4\n, as indicated by block \n92\n.', 'The command \n90\n may be transmitted via the first modem \n28\n-\n1\n from the control system \n38\n, and may be initiated by a user or be performed automatically based on one or more of a plurality of parameters, such as a predetermined period of time, an event, or the like.', 'As shown in \nFIG.', '4\n, in some embodiments, the buffer \n74\n may be divided into a first buffer portion \n74\n-\n1\n and a second buffer portion \n74\n-\n2\n.', 'The buffer \n74\n may be a fixed size buffer and the first and second buffer portions \n74\n-\n1\n and \n74\n-\n2\n may be mobile within the fixed size buffer \n74\n.', 'Boundaries of the first and second buffer portions \n74\n-\n1\n and \n74\n-\n2\n may change as sensor interrogation proceeds.', 'The first buffer portion \n74\n-\n1\n may be configured to store at least a portion of the one or more data \n82\n when received from the one or more sensor \n70\n.', 'The second buffer portion \n74\n-\n2\n may be configured to store at least a portion of the one or more data \n82\n which has been transmitted to the first modem \n28\n-\n1\n in response to a command \n90\n, but which may or may not yet have been received by the first modem \n28\n-\n1\n.', 'For example, the first and second buffer portions \n74\n-\n1\n and \n74\n-\n2\n may store a portion of the one or more data \n82\n along with a timestamp of a first sample of the one or more data \n82\n stored within the respective buffer portion, a time-span between samples stored within the respective buffer, and an index of the next sample to be stored within the respective buffer.', 'When the processing unit \n54\n receives a first data \n82\n-\n1\n of the one or more data \n82\n, the processing unit \n54\n may store the first data \n82\n-\n1\n in the first buffer portion \n74\n-\n1\n, as indicated in block \n88\n.', 'The first data \n82\n-\n1\n may be indicative of one of the one or more queries \n80\n.', 'The one or more queries \n80\n may be performed in an initial predetermined rate until the first buffer portion \n74\n-\n1\n is full, as will be explained below in more detail.', 'Once full, if the second buffer portion \n74\n-\n2\n is empty and if the processing unit \n54\n has not yet received the command \n90\n, the processing unit \n54\n may decimate the first data \n82\n-\n1\n stored in the first buffer portion \n74\n-\n1\n, as will be explained more fully below.', 'After decimation, the processing unit \n54\n may continue the one or more queries \n80\n at a rate having a time period in between queries larger than an initial time period between queries.', 'For example, the time period in between queries after decimation may be twice that of the initial predetermined rate.', 'Upon receiving the command \n90\n, the processing unit \n54\n may cause the transceiver assembly \n40\n to transmit the first data \n82\n-\n1\n to the first modem \n28\n-\n1\n, as indicated by block \n94\n.', 'The processing unit \n54\n may perform an encoding operation, discussed below in more detail, prior to causing the transceiver assembly \n40\n to transmit the first data \n82\n-\n1\n.', 'The processing unit \n54\n may then transfer the first data \n82\n-\n1\n to the second buffer portion \n74\n-\n2\n, as indicated by block \n96\n.', 'For example, in some embodiments, the position of the first data \n82\n-\n1\n in the buffer \n74\n may not change.', 'In this embodiment, the boundaries of the first buffer portion \n74\n-\n1\n and the second buffer portion \n74\n-\n2\n may change such that the second buffer portion \n74\n-\n2\n contains the first data \n82\n-\n1\n and the first buffer portion \n74\n-\n1\n is indicated as empty and ready to receive new data sample.', 'In some embodiments, after the boundary change, data found in the new boundary of the first buffer \n74\n-\n1\n may be marked or otherwise indicated as free space within the buffer \n74\n suitable to be overwritten with subsequent data.', 'The boundaries of the first buffer portion \n74\n-\n1\n and second buffer portion \n74\n-\n2\n may be implemented using pointers and/or addresses within the buffer \n74\n.', 'The first data \n82\n-\n1\n, having been subject to the command \n90\n and transmitted to the first modem \n28\n-\n1\n may be stored in the second buffer portion \n74\n-\n2\n until the processing unit \n54\n has received confirmation that the first modem \n28\n-\n1\n received the first data \n82\n-\n1\n.', 'The processing unit \n54\n may then receive a second data \n82\n-\n2\n of the one or more data \n82\n, in response to a second set of queries of the one or more queries \n80\n, and store the second data \n82\n-\n2\n in the first buffer portion \n74\n-\n1\n, as indicated by block \n98\n.', 'In some embodiments, the processing unit \n54\n may perform the second set of queries of the one or more queries \n80\n at the initial predetermined rate.', 'As before, once the first buffer portion \n74\n-\n1\n is full of the second data \n82\n-\n2\n, the processing unit \n54\n may perform a decimation of the data stored on either the first buffer portion \n74\n-\n1\n or the buffer \n74\n, as will be described in more detail below.', 'The processing unit \n54\n may overwrite data stored in the first buffer portion \n74\n-\n1\n after receiving subsequent data, or may erase and/or mark for deletion data stored in the first buffer portion \n74\n-\n1\n after transmitting the data stored in the first buffer portion \n74\n-\n1\n and transferring a copy of the data to the second buffer portion \n74\n-\n2\n.', 'As previously noted, in some embodiments, the processing unit \n54\n may change the boundaries of the first and second buffer portions \n74\n-\n1\n and \n74\n-\n2\n instead of transferring a copy of the data to the second buffer portion \n74\n-\n2\n.', 'When the processing unit \n54\n receives confirmation that the first data \n82\n-\n1\n has been received by the first modem \n28\n-\n1\n, and receives a second command of the one or more command \n90\n for the second data \n82\n-\n2\n, the processing unit \n54\n may remove, overwrite, and/or mark for deletion the first data \n82\n-\n1\n and store a copy of the second data \n82\n-\n2\n in the second buffer portion \n74\n-\n2\n, as indicated by block \n100\n.', 'The processing unit \n54\n may also change the boundaries of the first and second buffer portion \n74\n-\n1\n and \n74\n-\n2\n such that the second buffer portion \n74\n-\n2\n contains the second data \n82\n-\n2\n and the first buffer portion \n74\n-\n1\n is indicated as empty.', 'The processing unit \n54\n may continue to query the one or more sensor \n70\n, receive portions of the one or more data \n82\n, transmit portions of the one or more data \n82\n upon receipt of the one or more command \n90\n, and transfer portions of the one or more data \n82\n from the first buffer portion \n74\n-\n1\n to the second buffer portion \n74\n-\n2\n for a period of time, based on a set of parameters, user interaction, or other suitable factors in the same manner as previously described.', 'After each subsequent command of the one or more command \n90\n, the processing unit \n54\n may reinitiate the one or more queries at the initial predetermined rate.', 'The processing unit \n54\n may perform the queries \n80\n at the predetermined rate at predetermined instants of time prior to receiving the command \n90\n from the first modem \n28\n-\n1\n.', 'For example, the processing unit \n54\n may perform an initial set of the one or more queries \n80\n at predetermined instants of time when filling the first buffer portion \n74\n-\n1\n with sensor data before the buffer \n74\n is full.', 'In some embodiments, when the buffer \n74\n or the first buffer portion \n74\n-\n1\n is full, the data stored on the buffer \n74\n or the first buffer portion \n74\n-\n1\n may be decimated and the queries \n80\n performed at a rate half as large as the initial predetermined rate, i.e., the time periods between queries is twice as large as the initial time periods between queries.', 'The predetermined instants of time for performing the initial set of the one or more queries \n80\n, the first set or the second set described above, may be spaced apart by a predetermined constant time interval.', 'By way of illustration, the initial set of the one or more queries \n80\n may be performed at a rate of a query \n80\n conducted at four second intervals.', 'Once the buffer \n74\n or the first buffer portion \n74\n-\n1\n is full and the data stored therein is decimated, the one or more queries \n80\n may be performed at a rate of a query \n80\n conducted at eight second intervals.', 'In some embodiments, the instants of time, predetermined or otherwise, may be divided based on one or more parameter, such as a size of the buffer \n74\n, a size of the first buffer portion \n74\n-\n1\n, the amount of data stored in the buffer \n74\n or the first buffer portion \n74\n-\n1\n, or a time span represented in the first buffer portion \n74\n-\n1\n versus the second buffer portion \n74\n-\n2\n, for example.', 'In one embodiment, the processing unit \n54\n may perform the one or more queries \n80\n in such a way that, at any time, the first buffer portion \n74\n-\n1\n contains as much of the one or more data \n82\n as is possible, from a time when a last portion of the one or more data \n82\n was sent to the surface to a present time, so long as the time span represented by the one or more data \n82\n in the first buffer portion \n74\n-\n1\n does not exceed the time span represented by the one or more data \n82\n in the second buffer portion \n74\n-\n2\n, as will be explained in more detail below.', 'The one or more data \n82\n, in this embodiment, may be discrete sensor data points stored in the first buffer portion \n74\n-\n1\n in a predetermined data format such as a database, a relational database, or a temporal database, for example.', 'Decimation of the data \n82\n may be performed by downsampling the rate of the one or more queries \n80\n, as previously discussed, by two and/or downsampling the data \n82\n by two.', 'In either event, decimation includes the processing unit \n54\n updating the properties of the first and/or second buffer portions \n74\n-\n1\n and \n74\n-\n2\n.', 'For example, after decimation, as noted above, the one or more queries \n80\n may be performed at a rate of one query per eight seconds.', 'Where decimation is performed on the data \n82\n stored in the buffer \n74\n, the data \n82\n may be downsampled by two thereby deleting and/or marking as usable space previously occupied by half of the data \n82\n, representing alternating samples of the data \n82\n.', 'In this manner, the data \n82\n stored in the buffer \n74\n represents the same rate of sampling as the one or more queries \n80\n after decimation.', 'Decimation of the data \n82\n may be performed based on one or more of a plurality of elements.', 'For example, in some embodiments, when the first buffer portion \n74\n-\n1\n is full, the processing unit may determine whether the second buffer portion \n74\n-\n2\n is empty.', 'If the second buffer portion \n74\n-\n2\n is empty, the processing unit \n54\n may decimate the data stored in the first buffer portion \n74\n-\n1\n.', 'When the second buffer portion \n74\n-\n2\n is not empty, the processing unit \n54\n may determine whether the data stored in the first buffer portion \n74\n-\n1\n represents a time span that is less than the time span of the data stored in the second buffer portion \n74\n-\n2\n.', 'Where the time span of the data in the first buffer portion \n74\n-\n1\n is less than that in the second buffer portion \n74\n-\n2\n, the processing unit \n54\n may decimate the data in the first buffer portion \n74\n-\n1\n.', 'Where the time span of the data in the first buffer portion \n74\n-\n1\n is not less than that in the second buffer portion \n74\n-\n2\n, the processing unit \n54\n may decimate the data stored in the buffer \n74\n, i.e., the data stored in each of the first and second buffer portions \n74\n-\n1\n and \n74\n-\n2\n.', 'In some embodiments, when a command \n90\n arrives downhole, the processing unit \n54\n may determine whether a message containing the first data \n82\n-\n1\n was received by the first modem \n28\n-\n1\n in response to the command \n90\n.', 'At this time, the first data \n82\n-\n1\n (already sent) is in the second buffer portion \n74\n-\n2\n and the buffer \n74\n may or may not be full.', 'If the first data \n82\n-\n1\n was received by the first modem \n28\n-\n1\n, the second buffer portion \n74\n-\n2\n is emptied.', 'If the first data \n82\n-\n1\n was not received by the first modem \n28\n-\n1\n, the first buffer portion \n74\n-\n1\n and the second buffer portion \n74\n-\n2\n are merged.', 'In this event, the processing unit \n54\n may determine whether the time span of the data contained in the first buffer portion \n74\n-\n1\n is less than the time span of the data contained in the second buffer portion \n74\n-\n2\n.', 'Where the time span of the data contained in the first buffer portion \n74\n-\n1\n is less than that contained in the second buffer portion \n74\n-\n2\n, the processing unit \n54\n may decimate the data stored in the first buffer portion \n74\n-\n1\n until the time spans of the data stored in the first buffer portion \n74\n-\n1\n and the second buffer portion \n74\n-\n2\n are equal.', 'Where the time span of the data in the first buffer portion \n74\n-\n1\n is equal to that in the second buffer portion \n74\n-\n2\n, the data from the first buffer portion \n74\n-\n1\n is transferred into the second buffer portion \n74\n-\n2\n to be stored along with the data previously contained in the second buffer portion \n74\n-\n2\n.', 'The processing unit \n54\n may, in effect, transfer the data from the first buffer portion \n74\n-\n1\n to the second buffer portion \n74\n-\n2\n to be stored along with the data previously contained in the second buffer portion \n74\n-\n2\n by changing the boundaries of the first buffer portion \n74\n-\n1\n and the second buffer portion \n74\n-\n2\n.', 'As will be explained below in more detail, prior to or after decimation, the data stored in the second buffer portion \n74\n-\n2\n may be encoded to fit within a predetermined communication size or bit budget.', 'In some embodiments, if the data stored in the second buffer portion \n74\n-\n2\n may not be encoded or otherwise compressed into the predetermined communication size, the processing unit \n54\n may decimate the data stored in the second buffer portion \n74\n-\n2\n one or more times in order to enable an encoding scheme to transmit the data in the predetermined communication size.', 'In some embodiments, when the first buffer portion \n74\n-\n1\n has been emptied and the second buffer portion \n74\n-\n2\n has data amounting to greater than half the total size of the buffer \n74\n, the processing unit \n54\n may decimate the data stored in the second buffer portion \n74\n-\n2\n such that the first buffer portion \n74\n-\n1\n has at least half of the space of the buffer \n74\n for the samples that the first buffer portion \n74\n-\n1\n is going to receive.', 'After the processing unit has transmitted the first data \n82\n-\n1\n, or any other portion of the one or more data \n82\n, the processing unit \n54\n may resume the one or more queries \n80\n at the initial predetermined rate, for example a query \n80\n conducted at four second intervals to receive portions of the one or more data \n82\n and store the portions in the first buffer portion \n74\n-\n1\n.', 'It should be noted, that the decimation process of the processing unit \n54\n may be independent of the one or more command \n90\n.', 'The decimation process may be performed without regard to receipt of the one or more command \n90\n and without regard to the rate at which the one or more commands \n90\n are received.', 'The processing unit \n54\n may calculate the time of the next one or more queries \n80\n, store the corresponding portions of the one or more data \n82\n in the first buffer portion \n71\n-\n4\n, and decimate either the first buffer portion \n74\n-\n1\n or the buffer \n74\n, independently of the one or more command \n90\n.', 'As noted above, the buffer \n74\n can be a fixed size.', 'The size of the buffer \n74\n may be based in part on an expected round-trip time for a message sent using the communications channel \n34\n between the first modem \n28\n-\n1\n and the fourth modem \n28\n-\n4\n and a minimal modem-to-sensor query interval.', 'By way of further example, if command \n90\n is expected to arrive downhole at four minute intervals (round trip time), and if the one or more queries \n80\n are to be performed each four seconds, making sixty data points in four minutes, the buffer \n74\n may be sized to enable storage of at least 120 data points as well as a time reference for each point in the first and second portions \n74\n-\n1\n and \n74\n-\n2\n (e.g. a time of a first point and a time span for each of the first and second portions \n74\n-\n1\n and \n74\n-\n2\n).', 'When the buffer \n74\n, the first buffer portion \n74\n-\n1\n, and/or the second buffer portion \n74\n-\n2\n is full, the processing unit \n54\n may perform a buffer decimation, discussed in greater detail below, to continue to perform the one or more queries \n80\n on the one or more sensor \n70\n with the size of the first buffer portion \n74\n-\n1\n and/or the second buffer portion \n74\n-\n2\n effectively half that of the original size prior to decimation.', 'For example, either the buffer \n74\n or the first buffer portion \n74\n-\n1\n may be decimated, depending on the time spans between points in the first buffer portion \n74\n-\n1\n and the second buffer portion \n74\n-\n2\n.', 'Requests from the first modem \n28\n-\n1\n, for the one or more data \n82\n, may include whether a previous request was satisfied, a precision parameter for a determination of a desired precision of the one or more data \n82\n, and other information related to the transmission of the one or more data \n82\n stored in the buffer \n74\n.', 'Referring now to \nFIG.', '5\n, shown therein is a diagrammatic representation of one embodiment of the compression program \n76\n-\n2\n stored in the non-transitory processor readable medium \n44\n.', 'In use, the processing unit \n54\n may calculate a size \n102\n of an output bit stream \n104\n based on an encoding scheme \n106\n for transmission of the data \n82\n stored in the buffer \n74\n, as indicated by block \n108\n.', 'The processing unit \n54\n may decimate the data \n82\n stored in the buffer \n74\n if the size \n102\n of the output bit stream \n104\n exceeds a predetermined size \n110\n, as indicated by block \n112\n.', 'The processing unit \n54\n may then recalculate the size \n102\n of the output bit stream \n104\n, after decimation of the data \n82\n stored in the buffer \n74\n, based on the encoding scheme \n106\n to encode for transmission a decimated data \n114\n, formed from decimating the data \n82\n, as indicated by block \n116\n.', 'In some embodiments, the processing unit \n54\n may then encode the data \n82\n or the decimated data \n114\n using the encoding scheme \n106\n, as indicated by block \n116\n.', 'Encoding the data \n82\n or the decimated data \n114\n may generate a message \n118\n for transmission to the first modem \n28\n-\n1\n and thereby the control system \n38\n, as indicated by block \n120\n.', 'The encoding scheme \n106\n may be stored in the non-transitory processor readable medium \n44\n.', 'The encoding scheme \n106\n may be any encoding scheme capable of encoding data into an electrical, analog, wired, wireless, and/or acoustic signal for transmission between the series of modems \n28\n in the downhole environment.', 'The encoding scheme \n106\n may compress the data \n82\n or the decimated data \n114\n into a lossless or near-lossless encoded signal, the message \n118\n, such that a distortion is constrained.', 'The distortion, in this case, is a difference between the data \n82\n or the decimated data \n114\n and the data decoded from the encoded signal.', 'The distortion may be a fixed distortion or be at or below a predetermined allowable error.', 'The encoding scheme \n106\n may have a compression rate, for compressing the data \n82\n or the decimated data \n114\n, which may depend on the data \n82\n or the decimated data \n114\n, whichever is being compressed, since by nature the performance of a lossless or near-lossless encoding scheme depends on the statistics/distribution of the data \n82\n or the decimated data \n114\n.', 'The encoding scheme \n106\n may not encode the data \n82\n for calculating the size \n102\n of the output bit stream \n104\n.', 'Instead, the encoding scheme \n106\n may be provided with a test function, associated with the encoding scheme, to indicate a number of bits the encoding scheme \n106\n would take to encode an error signal with the encoding scheme \n106\n or a number of points, of the error signal that the encoding scheme \n106\n may fit into a bit-budget.', 'The error signal may be a value indicative of the data \n82\n or the decimated data \n114\n when the compression algorithm is applied.', 'Referring now to \nFIG.', '6\n, shown therein is a diagrammatic representation of another embodiment of the compression program \n76\n-\n2\n stored in the non-transitory processor readable medium \n44\n.', 'In use, the processing unit \n54\n may calculate a first size \n130\n of a first output bit stream \n132\n based on a first encoding scheme \n134\n to encode for transmission the data \n82\n, as indicated by block \n136\n.', 'The processing unit \n54\n may then calculate a second size \n138\n of a second output bit stream \n140\n based on a second encoding scheme \n142\n to encode for transmission the data \n82\n, as indicated by block \n144\n.', 'The processing unit \n54\n may then select a selected encoding scheme \n146\n based on the relative sizes, the first size \n130\n and the second size \n138\n, of the first output bit stream \n132\n and the second output bit stream \n140\n, as indicated by block \n148\n.', 'The selected encoding scheme \n146\n may be either the first encoding scheme \n134\n or the second encoding scheme \n142\n.', 'The processing unit \n54\n may then encode the data \n82\n stored in the buffer \n74\n using the selected encoding scheme \n146\n to produce a message \n150\n for transmission to the first modem \n28\n-\n1\n, as indicated by block \n152\n.', 'In some embodiments, the first encoding scheme \n134\n and the second encoding scheme \n142\n may be members of a group of n encoding schemes where n>two.', 'As such, the processing unit \n54\n may calculate a plurality of sizes of a plurality of output bit streams based on a plurality of encoding schemes represented by the group of n encoding schemes.', 'Referring now to \nFIG.', '7\n, shown therein is a diagrammatic representation of another embodiment of the compression program \n76\n-\n2\n, similar to the embodiments shown in \nFIG.', '6\n.', 'However, prior to selecting an encoding scheme, the processing unit \n54\n may determine if a smaller bit stream \n160\n of the first output bit stream \n132\n and the second output bit stream \n140\n exceeds a predetermined size, as indicated by block \n162\n.', 'If the smaller bit stream \n160\n exceeds the predetermined size, the processing unit \n54\n may decimate the data \n82\n stored in the buffer \n74\n to form a decimated data \n164\n, as indicated by block \n166\n.', 'The processing unit \n54\n may then recalculate the first size \n130\n and the second size \n138\n of the first output bit stream \n132\n and the second output bit stream \n140\n, respectively, for transmitting the decimated data \n164\n in the buffer \n74\n, as indicated by block \n168\n.', 'The processing unit \n54\n may determine if the size of a smaller bit stream \n170\n of the first bit stream \n132\n and the second bit stream \n140\n, calculated from the decimated data \n164\n, exceeds a predetermined size, as indicated by block \n172\n.', 'The processing unit \n54\n may then further decimate the decimated data \n164\n one or more times, to form a second decimated data \n174\n, if the size of a smaller bit stream \n170\n of the first bit stream \n132\n and the second bit stream \n140\n is greater than the predetermined size, as indicated by block \n176\n.', 'In some embodiments, the processing unit \n54\n may further decimate the decimated data \n164\n if the size of the first and second output bit streams \n132\n and \n140\n, after being recalculated based on the decimated data \n164\n, is greater than a predetermined size, without determining which is smaller.', 'Shown below is a table of multiple decimation levels and calculations of first and second bit streams \n132\n and \n140\n.', 'TABLE 1\n \n \n \n \n \n \nDecimation level\n \nEncoding scheme 1 (bits)\n \nEncoding scheme 2 (bits)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n1\n \n500\n \n280\n \n \n \n2\n \n220\n \n90\n \n \n \n3\n \n100\n \n110\n \n \n \n \n \n \n \n \n \n \nIn some embodiments, the encoding scheme of a set of n which minimizes the number of bits over a set of a certain number of decimation levels is selected.', 'As shown, the size of the second bit stream \n140\n at the second decimation level is smaller than the sizes of the first and second bit streams \n132\n and \n140\n at the other decimation levels.', 'In this case, encoding scheme 2 at decimation level 2 would be selected since the combination of encoding scheme 2 at the decimation level 2 minimizes the number of bits relative to the possible combinations set forth above.', 'The number of the bits in the second bit stream \n140\n at decimation level 3 increases over the number of the bits in the second bit stream \n140\n at decimation level 2.', 'It should be understood that decimating the input data may not decrease the number of bits in the first and second bit streams \n132\n and \n140\n.', 'Referring now to \nFIG.', '8\n, shown therein is a diagrammatic representation of an embodiment of the compression program \n76\n-\n2\n stored in the non-transitory processor readable medium \n44\n.', 'In use, the processing unit \n54\n may calculate a number of data samples \n180\n, of the data \n82\n stored in the buffer \n74\n, able to be encoded into a predetermined budget \n182\n by a first encoding scheme \n184\n and a second encoding scheme \n186\n, as indicated by block \n188\n.', 'It is generally possible to calculate the number of samples encoded in the predetermined budget \n182\n when the encoding scheme works “chronologically,” i.e., when the values are encoded one after the other from the first one.', 'The data samples may be indicative of one or more measurement of the downhole environment by the one or more downhole sensor \n70\n.', 'The processing unit \n54\n may then determine which of the first encoding scheme \n184\n and the second encoding scheme \n186\n may enable encoding a larger number of the number of data samples \n180\n within the predetermined budget \n182\n, as indicated by block \n190\n.', 'The processing unit \n54\n may select the first encoding scheme \n184\n or the second encoding scheme \n186\n enabling encoding of the larger number of the number of data samples \n180\n within the predetermined budget \n182\n, as indicated by block \n192\n.', 'The processing unit \n54\n may then encode the number of data samples \n180\n using a selected encoding scheme \n184\n of the first encoding scheme \n184\n and the second encoding scheme \n186\n to generate a message \n196\n for transmission to the first modem \n28\n-\n1\n, as indicated by block \n198\n.', 'Although the compression program \n76\n-\n2\n has been described herein for purposes of clarity with two encoding schemes \n184\n and \n186\n, it should be understood that more than two encoding schemes can be used.', 'Further, although some embodiments of the present disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of the present disclosure.', 'Accordingly, such modifications are intended to be included within the scope of the present disclosure as defined in the claims.', 'Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.'] | ['1.', 'A method, comprising:\nperforming, by a processor, one or more queries on one or more sensors, for one or more data collected by the one or more sensors, at predetermined instants of time by a downhole modem operably coupled to the one or more sensors, prior to receiving a request for transmission of the one or more data from a surface modem;\nreceiving, by the processor, the one or more data from the one or more sensors in response to the one or more queries;\nstoring, by the processor, the one or more data in a buffer coupled to the downhole modem,\nreceiving, by the processor, the request for transmission from the surface modem; and\ntransmitting the one or more data from the downhole modem to the surface modem, in response to the request for transmission\nin response to the one or more data filling a storage space of the buffer so that it exceeds a threshold space, decimating, via the processor, the one or more data in the buffer.', '2.', 'The method of claim 1, wherein any two of the predetermined instants of time are spaced apart by a predetermined constant time interval.', '3.', 'The method of claim 1, wherein the buffer is a fixed-size buffer.', '4.', 'The method of claim 1, wherein transmitting the one or more data from the downhole modem to the surface modem comprises passing at least a portion of the one or more data in the buffer to the surface modem.', '5.', 'The method of claim 4, wherein the buffer is stored in a non-transitory processor readable medium of the downhole modem.', '6.', 'The method of claim 1, wherein the buffer has a first section and a second section, wherein the one or more data that have been previously passed to the surface modem are stored in the first section and the one or more data queried from the one or more sensors but not passed to the surface modem are stored in the second section.', '7.', 'The method of claim 1, wherein the downhole modem is an acoustic modem.', '8.', 'A downhole device comprising:\none or more processors coupled to a downhole modem configured to:\nquery one or more sensors for one or more sensor data at a first periodic interval; and receive the one or more sensor data from the one or more sensors,\nreceive a request for transmission from a surface modem and transmit the one or more sensor data to the surface modem, in response to the request for transmission,\nwherein the one or more processors configured so that it queries the one or more sensors independent of receiving the request for transmission; and\na buffer coupled to the downhole modem configured to store the one or more sensor data, wherein, in response to the one or more sensor data filling a storage space of the buffer so that it exceeds a threshold space, the one or more processors are configured to decimate the one or more sensor data in the buffer.', '9.', 'The downhole device of claim 8, wherein in response to the one or more sensor data filling the storage space of the buffer so that it exceeds the threshold space, the one or more processors are configured to query the one or more sensors for the one or more sensor data at a second periodic interval.', '10.', 'The downhole device of claim 9, wherein the second periodic interval is longer than the first periodic interval.', '11.', 'The downhole device of claim 8, wherein the downhole device comprises an acoustic modem.', '12.', 'The downhole device of claim 8, further comprising a transceiver assembly configured to transmit the one or more sensor data by generating acoustic signals in a material of a drill pipe.', '13.', 'The downhole device of claim 8, wherein the one or more sensors comprise a pressure gauge, a fluid flow meter, a downhole fluid analyzer, or a combination thereof.', '14.', 'A system comprising:\none or more sensors configured to take measurements in a wellbore and generate sensor data based at least in part on the measurements;\none or more processors configured to query the one or more sensors for the sensor data;\na transceiver assembly configured to send the sensor data to a surface controller; and a buffer comprising a first buffer and a second buffer, wherein the first buffer is configured to store the sensor data before the sensor data is sent to the surface controller, wherein the second buffer is configured to store the sensor data after the sensor data is sent to the surface controller, and wherein, in response to the second buffer being non-empty, the one or more processors are configured to decimate the sensor data in the first buffer to maintain a first amount of the sensor data in the first buffer less than a second amount of the sensor data in the second buffer.\n\n\n\n\n\n\n15.', 'The system of claim 14, wherein maintaining the first amount of the sensor data less than the second amount of the sensor data comprises maintaining a first time span corresponding to the first amount of the sensor data in the first buffer less than a second time span corresponding to the second amount of the sensor data in the second buffer.', '16.', 'The system of claim 14, wherein the one or more processors are configured to empty the second buffer in response to receiving a reception confirmation from the surface controller.', '17.', 'The system of claim 16, wherein the one or more processors are configured to move the sensor data in the first buffer to the second buffer in response to receiving a data request from the surface controller, wherein moving the sensor data in the first buffer to the second buffer comprises redefining the first buffer as the second buffer.', '18.', 'The system of claim 14, wherein the transceiver assembly is configured to be coupled to a drill pipe or a casing of the wellbore.\n\n\n\n\n\n\n19.', 'The system of claim 14, wherein the one or more processors are configured to decimate the first amount of the sensor data in the first buffer and the second amount of the sensor data in the second buffer in response to the second buffer being non-empty and the first amount of the sensor data in first buffer reaching a threshold.'] | ['FIG.', '1 shows a schematic view of a downhole telemetry system in accordance with the present disclosure.', '; FIG.', '2 shows a partial block diagram of a modem constructed in accordance with the present disclosure.', '; FIG.', '3 shows a partial schematic view of the downhole telemetry system of FIG.', '1.; FIG. 4 shows a diagrammatic representation of a method of sensor interrogation performed by a downhole modem in accordance with the present disclosure.', '; FIG.', '5 shows a diagrammatic representation of an encoding and compression scheme performed by a downhole modem in accordance with the present disclosure.; FIG.', '6 shows a diagrammatic representation of an encoding and compression scheme performed by a downhole modem in accordance with some embodiments of the present disclosure.', '; FIG.', '7 shows a diagrammatic representation of another embodiment of the encoding and compression scheme shown in FIG.', '6.; FIG.', '8 shows a diagrammatic representation of an encoding and compression scheme performed by a downhole modem in accordance with some embodiments of the present disclosure.'] |
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US11112516 | Data fusion technique to compute reservoir quality and completion quality by combining various log measurements | Apr 30, 2018 | Tuanfeng Zhang, Richard E. Lewis, Helena Gamero Diaz | SCHLUMBERGER TECHNOLOGY CORPORATION | Cipolla, C. et al., “Appraising Unconventional Resource Plays: Separating Reservoir Quality from Completion Effectiveness”, IPTC 14677, presented at the 2011 International Petroleum Technology Conference, Bankok, Thailand, 27 pages.; Cipolla, C. et al., “New Algorithms and Integrated Workflow for Tight Gas and Shale Completions”, SPE 146872, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, U.S.A., 2001, 18 pages.; Gamero-Diaz, H. et al., “Evaluating the Impact of Mineralogy on Reservoir Quality and Completion Quality of Organic Shale Plays”, AAPG, Search and Discovery Article #41221, 2013, 5 pages. | 4327412; April 27, 1982; Timmons; 5444619; August 22, 1995; Hoskins; 20050228590; October 13, 2005; Jeffryes; 20070016389; January 18, 2007; Ozgen; 20110099132; April 28, 2011; Fruehbauer; 20110261648; October 27, 2011; Hennenfent; 20110272161; November 10, 2011; Kumaran et al.; 20130270011; October 17, 2013; Akkurt; 20140126328; May 8, 2014; Hirabayashi; 20140129149; May 8, 2014; Gzara et al.; 20150088424; March 26, 2015; Burlakov; 20150106018; April 16, 2015; Robinson; 20150346384; December 3, 2015; Kalyanaraman; 20160326845; November 10, 2016; Djikpesse; 20170192115; July 6, 2017; Baker; 20180010443; January 11, 2018; Lu; 20190170897; June 6, 2019; Zhang; 20190243025; August 8, 2019; Wlodarczyk; 20190302307; October 3, 2019; Arbus | Foreign Citations not found. | ['Methods may include normalizing two or more wellbore logs obtained from the output of two or more wellbore tool surveys of a wellbore in a formation of interest; inputting two or more wellbore logs into a correlation matrix; assigning each of the two or more wellbore logs a positive or negative value based on the impact on a selected wellbore quality; performing a principal component analysis of the two or more wellbore logs to obtain one or more loading vectors; computing weighting factors for each of the two or more wellbore logs from the one or more loading vectors; and generating a quality index by linearly combining the two or more wellbore logs using the computed weighting factors.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nIdentification of regions in a formation that contain hydrocarbons is one of the primary goals of oil and gas exploration.', 'One way to identify the hydrocarbon reservoirs within a subterranean formation, also referred to as hydrocarbon pay, is from differential responses of various logging tools along a wellbore.', 'Wellbore tools may also identify other qualities of interest such as rock composition, anisotropic structures, water saturation, and other features that can aid wellbore operations such as completions, stimulation, production, and the like.', 'Common logging tools may include electrical tools, electromagnetic tools, acoustic tools, nuclear tools, and nuclear magnetic resonance (NMR) tools, and a number of others.', 'As the number of wellbore tools used to study a formation increases, more data is generated that must be sorted and analyzed, which can impart additional time and expense in order to evaluate the information from each tool.', 'In addition to sheer data volume, individual tools may be more or less susceptible to error and methods are needed to identify and correct for data redundancy across multiple wellbore logs in order to efficiently identify wellbore zones that may contain economically viable pay and potential completion zones.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'In one aspect, embodiments disclosed herein relate to methods that may include normalizing two or more wellbore logs obtained from the output of two or more wellbore tool surveys of a wellbore in a formation of interest; inputting two or more wellbore logs into a correlation matrix; assigning each of the two or more wellbore logs a positive or negative value based on the impact on a selected wellbore quality; performing a principal component analysis of the two or more wellbore logs to obtain one or more loading vectors; computing weighting factors for each of the two or more wellbore logs from the one or more loading vectors; and generating a quality index by linearly combining the two or more wellbore logs using the computed weighting factors.', 'In another aspect, embodiments disclosed herein relate to methods that may include normalizing two or more wellbore logs obtained from the output of two or more wellbore tool surveys of a wellbore in a formation of interest; inputting two or more wellbore logs into a correlation matrix; assigning each of the two or more wellbore logs a positive or negative sign based on the impact on a selected wellbore quality; performing a principal component analysis of the two or more wellbore logs to obtain one or more loading vectors; computing weighting factors for each of the two or more wellbore logs from the one or more loading vectors; generating a reservoir quality log by linearly combining the two or more wellbore logs using the computed weighting factors; generating a completion quality log by linearly combining the two or more wellbore logs using the computed weighting factors; and preparing a composite reservoir quality index from the product of the reservoir quality log and the completion quality log.', 'Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nFIG.', '1\n is a flow diagram depicting a method in accordance with embodiments of the present disclosure;\n \nFIG.', '2\n is an illustration depicting an example of a pair-wise correlation matrix used to analyze wellbore measurements in accordance with embodiments of the present disclosure.', 'The bar on the right indicates the level of positive or negative correlation between measurement pairs;\n \nFIG.', '3.1\n is a correlation map for a number of logs in accordance with embodiments of the present disclosure;\n \nFIG.', '3.2\n is a correlation matrix for a number of logs that are used as example input for reservoir quality (RQ) in accordance with embodiments of the present disclosure;\n \nFIG.', '3.3\n is a graphical representation of the first three principal components for a number of logs that are used as example input in accordance with embodiments of the present disclosure;\n \nFIGS.', '4.1 and 4.2\n are graphical representations depicting the projection of data measurements and loading vectors in principal component space represented in two dimensions and three dimensions, respectively, in accordance with embodiments of the present disclosure;\n \nFIG.', '5\n is a graphical representation showing a continuous RQ index generated by linearly combining four well log measurements in accordance with embodiments of the present disclosure;\n \nFIG.', '6\n is a graphical representation showing a continuous RQ index with appended pay flags generated by linearly combining four well log measurements with weighting factors applied and followed by applying an optimal thresholding value in accordance with embodiments of the present disclosure;\n \nFIG.', '7.1\n is a correlation map for a number of logs that are used as example input for completion quality (CQ) index computation in accordance with embodiments of the present disclosure;\n \nFIG.', '7.2\n is a correlation matrix for a number of logs as example input in accordance with embodiments of the present disclosure;\n \nFIG.', '7.3\n is a graphical representation of the first three principal components for a number of logs as example input in accordance with embodiments of the present disclosure;\n \nFIGS.', '8.1 and 8.2\n are graphical representations depicting projection of data measurements in principal component space represented in two dimensions and three dimensions, respectively, in accordance with embodiments of the present disclosure;\n \nFIG.', '9\n is a graphical representation showing a continuous CQ index generated by linearly combining four example well log measurements in accordance with embodiments of the present disclosure; and\n \nFIG.', '10\n is a schematic showing an example of a computer system for executing methods in accordance with the present disclosure.', 'DETAILED DESCRIPTION', 'In one aspect, embodiments in accordance with the present disclosure are directed to a data analytic approach to compute a continuous quality index from a linear combination of available log measurements from an interval of interest in a wellbore traversing a subterranean formation that accounts for data redundancy across multiple information sources.', 'In another aspect, embodiments disclosed herein relate to data fusion techniques that combine multiple wellbore log measurements and/or other digital data to compute wellbore quality indices automatically.', 'In one or more embodiments, wellbore quality indices may include continuous reservoir quality (RQ), completion quality (CQ), and composite quality indices (QI), and the like.', 'Methods in accordance with the present disclosure may be used to quantify, improve, and automate computation of reservoir quality and completion quality evaluation, interpretation, and mapping by combining multiple log measurements.', 'Previous approaches have used arbitrary binary threshold cutoffs of independent wellbore measurements to compute flags for specified wellbore qualities (often reservoir quality) that may be applied to other wellbore log measurements over the same interval.', 'However, approaches that generate binary flags from a series of single source of wellbore information are susceptible to the propagation of errors from individual wellbore logs, which can lead to fewer identified intervals of interest and less certainty of specified quality within the flagged interval.', 'The major limitation of applying binary thresholds to individual wellbore logs is that intervals within the wellbores are labeled as “good” or “bad” quality and then the “good” intervals are flagged if they are “good” across all logs.', 'This leads to smaller and fewer “good” reservoir intervals as more measurements become available, which is counterintuitive and unreasonable for reservoir interpretation.', 'In one or more embodiments, methods may include generating one or more continuous wellbore quality indices by assigning optimal weights to a grouping of wellbore measurements for an interval or reservoir of interest, such that highly correlated logs share weighting factors, while more independent logs are assigned higher weighting factors.', 'This method is contrasted with prior approaches to evaluate RQ and CQ that apply binary threshold cutoffs to logs to denote “good” or “bad” qualities without taking log dependence/redundancy for multiple log measurements into account.', 'With respect to \nFIG.', '1\n a general flow diagram is shown for a method to generate continuous wellbore quality indices through linear combination of available log measurements and/or other digital data, which utilizes weighting factors to minimize data redundancy.', 'Beginning at \n102\n, wellbore measurements are collected from available wellbore logs from any number of wellbore tools and other digital data.', 'At \n104\n, the wellbore measurements are input into a correlation matrix during exploratory data analysis (EDA).', 'The correlation matrix is established by organizing available wellbore data using a diagnostic tool that computes and displays a color-coded pair-wise matrix to aid user classification of the available wellbore measurements into groupings that provide information for a given wellbore quality being studied.', 'The established correlation matrix may provide users with an intuitive visualization that allows the separation of available wellbore measurements into distinct groups for subsequent analysis based on the degree of cross correlation for subsequent analysis.', 'In some embodiments, wellbore logs may be grouped based on the criteria of minimizing variation within individual well log groups, while maximizing the variation across different groups.', 'At \n106\n, wellbore measurements may be grouped according to user-defined criteria to generate quality indices that are tailored to a particular application, such as RQ and/or CQ.', 'During EDA, wellbore logs are assigned positive “+” and “−” negative signs depending on whether they contribute to the wellbore quality of interest positively or negatively.', 'General petrophysical understanding and local knowledge about the studied reservoir may also help the determination of the signs.', 'In some embodiments, the correlation matrix may prompt users to determine sign selection in sequence.', 'For example, a user may be prompted to assign signs to sequential logs based on the order of confidence in the accuracy of the log data; the sequential logs may then be assigned a positive or negative sign dependent on the degree of correlation to the first log.', 'Positive correlations suggest that the compared wellbore logs have the same sign, while negative signs may be applied to negative correlations.', 'The grouped wellbore measurements are then processed by principal component analysis (PCA) at \n108\n.', 'In one or more embodiments, wellbore logs that have been assigned signs may then be processed by PCA to determine the principal components (PC) and corresponding loading vectors for the data set.', 'PCA transforms the wellbore data from the original axes to principal axes.', 'The first principal axis is the direction in which the data are primarily distributed, or the “long” axis of the distribution in n-dimensional space.', 'In one or more embodiments, the number of principal components may be varied.', 'In some embodiments, a PCA may retain the first three PCs, and the respective loading vectors may be displayed to show the redundancy among the logs.', 'PCA results may be plotted in 2D or 3D in PC space.', 'The plotted data may be used to generate loading vectors for the input wellbore measurements, which are used for data dimension reduction and/or characterization of variance.', 'While embodiments of the present disclosure are discussed using linear PCA, there are other methods that could be substituted for linear PCA, including, but not limited to, non-linear or kernel PCA, and similar other dimension reduction tools.', 'Following PCA, estimation tools such as the Kriging estimator may be applied in PC loading space to measures the redundancy of the logs and compute weighting factors at \n110\n.', 'Kriging estimators are known from use as a fundamental estimation tool in geostatistics, and is described, for example, in E. H. Isaaks and R. M. Srivastava, 1989\n, An Introduction to Applied Geostatistics\n, Oxford University Press.', 'In one or more embodiments, a Kriging estimator is used and applied to the loading vectors of log measurements using a covariance model with spatial anisotropy determined by the variance of each individual PC identified, which is then used to generate weighting factors for all available logs.', 'After weighting factors for each of the wellbore logs are calculated, the logs may be combined linearly to generate the continuous wellbore quality index at \n112\n, such as an RQ log or CQ log.', 'In one or more embodiments, users can apply a threshold cutoff at \n114\n to a generated wellbore quality index to designate intervals having specified characteristics, such as indicating the presence of pay zones or intervals suitable as completion targets.\n \nMethods in accordance with the present disclosure may be automated in some embodiments using supervised learning (machine learning) from previous log results.', 'For example, if a user wants to employ a continuous quality index resulting from the analysis of multiple well logs to interpret various intervals of interest such as pay zones or completion targets, an interactive method may be employed to assist the optimization of a threshold for a given quality index.', 'Automated methods may be trained by setting a user-defined optimal threshold value for a wellbore quality such as RQ, and the target intervals may be computed.', 'Thus, a binary solution can be created from one or two quality indices, while retaining the continuous estimates of wellbore quality (RQ and CQ, for example).', 'If a flagged interval of interest is known and a well log already exists in a well, the threshold values used to flag the interval may be used for machine learning, which may minimize the misclassification rate by an iterative process with user input or automatically optimizing the threshold value for generated quality indices.', 'The misclassification rate is the ratio between the number of data points that are classified incorrectly when comparing with the known pay flagged values and the total number of samples in the studied zone.', 'In one or more embodiments, optimized threshold values computed in the training well containing a flagged interval of interest may be applied to neighboring wells or wells in similar formations.', 'EXAMPLES', 'The following examples are presented to illustrate the overall method of generating a wellbore quality index for a number of wellbore qualities, and should not be construed to limit the scope of the disclosure, unless otherwise expressly indicated in the appended claims.', 'Even though the methodology is explained by logs in vertical wells, it can be applied to logs or measurements from wells in any orientation.', 'The method can be similarly applied to the analysis of real-time drilling measurement data when the data are acquired in sequential time frames.', 'Example 1: Reservoir Quality Analysis\n \nIn this example, nine log measurements were obtained from a vertical well and used to establish a continuous log of reservoir quality (RQ).', 'The sample logs include gamma ray (GR, gAPI), deep resistivity (AT90, ohm*m), bulk density (RHOZ, g/cm3), thermal neutron porosity (NPHI, v/v), carbon weight fraction (WCAR, lbf/lbf), clay weight fraction (WCLA, lbf/lbf), pyrite weight fraction (WPYR, lbf/lbf), quartz-feldspar-mica weight fraction (WQFM, lbf/lbf), and total organic carbon weight fraction (WSM, lbf/lbf).', 'The studied interval is 500 feet in measured depth.', 'Other logs which may be used for reservoir quality are neutron (TNPH); spectroscopy mineralogy logs: Anhydrite (WANH), Calcite (WCLC), Dolomite (WDOL), Evaporite (WDOL), Pyrite (WPYR), Matrix Grain Density (RHGE); and NMR: NMR porosity (MRP), permeability (KSDR)', 'Generating Correlation Matrix\n \nWith particular respect to \nFIG.', '2\n, a pair-wise correlation matrix was calculated and generated as a map for all available wellbore logs as a visualization tool to depict the correlation between the values in pairs of the respective logs.', 'In the correlation matrix, the bar legend shows the correlation among the logs from negatively correlated values (−1) to positively correlated values (+1).', 'The correlation matrix was used to separate the logs into two groups based on the strength of the correlation between the groups.', 'Based on common petrophysical understanding about reservoirs, the logs in the first group \n202\n are examples of logs that can be good indicators of reservoir quality and were used to generate a continuous log of reservoir quality (RQ): GR, AT90, RHOZ, and NPHI.', 'The second group \n204\n, is directed to logs of mineral concentrations that were used to generate a continuous log of completion quality (CQ), which indicates regions of the wellbore that may be good targets for stimulation and completion operations: WCLA, WPYR, WQFM, and WSM.', 'In addition to the mineralogy logs, sonic log and other logs relating to rock geomechanics properties could be used.', 'In this example, the groups selected were representative of the respective quality logs RQ or CQ, however, highly redundant logs could be removed and remaining logs can be regrouped and reordered to form a new correlation matrix depending on the job requirements.', 'The correlations between the logs for RQ and logs for CQ lie inside the dashed box \n206\n.', 'Principal Component Analysis\n \nThe next step is to pick the groups of logs for either RQ or CQ computation.', 'As an illustration of RQ computation, we chose four logs (GR, AT90, RHOZ, NPHI).', 'Principal component analysis (PCA) is applied to determine the principal component (PC) vectors that explain most of the total variance in the dataset.', 'PCA is a technique that is widely used for applications such as dimension reduction, data compression, feature extraction, and data visualization.', 'Before applying PCA, a positive sign “+” or a negative sign “−” needs to be specified for each individual log measurement to indicate whether the corresponding measurement contributes to a composite index positively or negatively.', 'In this example, three of the four logs have a positive sign “+”, while the density log (RHOZ) has a negative sign “−”.', 'The physical reason for the negative correlation of density to RQ is that hydrocarbon in pore space of a rock is less dense than the surrounding rock and reduces the rock bulk density.', 'Negatively correlated logs are flipped by subtracting the original log measurements from their maximum values.', 'Next, all log measurements are converted into dimensionless values through Z-score transformation.', 'This is required since different types of logs commonly have different units and different ranges of measurement.', 'Z-score transformation of a data vector x is defined in Eq.', '(1), in which the mean is subtracted from the data vector and then divided by the standard deviation of the data.', 'It is worth noting that for resistivity log AT90, a logarithmic transformation is applied first before Z-score transformation to reduce skewness in the resistivity data measurements.', 'Z\n \n=\n \n \n \nx\n \n-\n \n \nmean\n \n\u2062\n \n \n \n \n\u2062\n \n \n(\n \nx\n \n)\n \n \n \n \n \nstd\n \n\u2061\n \n \n(\n \nx\n \n)\n \n \n \n \n \n \n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n \nPCA involves evaluating the correlation matrix R of the data set first, which are defined in Eq.', '(2), where zn (n=1, N) is the Z-score transformed log using equation (1) and each contains L measurements, which usually corresponds to the total samples in studied depth interval.', 'R\n \n=\n \n \n \n1\n \nN\n \n \n\u2062\n \n \n \n∑\n \n \nn\n \n-\n \n1\n \n \nN\n \n \n\u2062\n \n \n \nz\n \nn\n \n \n\u2062\n \n \nz\n \nn\n \nT\n \n \n \n \n \n \n \n \n \n(\n \n2\n \n)', 'The dimension of the correlation matrix R is N×N.', 'In our example, N=4 and L is the total measurement data points, and z\nn\nT \nis the transpose of z\nn\n.', 'Next, PCA is performed to find the M(M WSM>WPYR>WCLA.', 'Note that the computed CQ \n910\n in \nFIG.', '9\n has more variation than the RQ index \n610\n in \nFIG.', '6\n, and the CQ intervals seem to be independent of RQ.', 'The upper (lower MD) layer contains poorer RQ and better CQ, while the lower layer (higher MD) contains better RQ and poor CQ.', 'This suggests that the selection of sweet spots (good RQ+good CQ) may require a trade-off between the two computed quality indices.', 'In one or more embodiments, composite quality indices may be generated from multiple quality indices.', 'For example, a composite quality index (QI) curve can be defined as a product of the RQ and CQ, QI=RQ*CQ, or weighted using the weights assigned by interpreters.', 'The resulting continuous QI index could then be modified by the thresholding process discussed above, leading to the identification of “sweet spot” intervals to guide the engineering completion.', 'Using RQ, CQ or QI computed for single wells, interpolating it in 3D using any spatial interpolators such as Geostatistics tools can generate spatial 3D models of RQ, CQ or QI for more accurate reservoir delineation and characterization.', 'If the pay flag is provided in one well, the optimal thresholding value of continuous RQ/CQ index can be determined by supervised classification methods.', 'Later, the same threshold value can be applied to cutoff RQ/CQ indices curves for other wells to get pay/completable flags if their log characteristics are similar and the corresponding weighting factors are comparable.', 'RQ, CQ or a composite QI can be further used to perform interpolation or mapping of RQ, CQ, or QI in 3D.', 'The computed RQ, CQ or QI at wells can be considered as known data and interpolation tools, such as geostatistical methods, can be used to build 3D models to either estimate or simulate the RQ, CQ or QI values between wells.', 'The resulting RQ, CQ, QI predictions in 3-dimensional space can help operators to select locations for optimal exploration or production target areas or for infill drilling.', 'Applications\n \nWhile the methods in accordance with the present disclosure may be adapted to data analysis in the wellbore context, it is also envisioned that the method may be applied more broadly as a data analytics tool used to combine data from different sources to generate single continuous indices for interpretation and decision-making.', 'In one or more embodiments, methods in accordance with the present disclosure may be automated or partially automated.', 'In some embodiments, a user-guided iterative interpretation process can be conducted by thresholding the continuous quality index to generate quality flags to assist optimal reservoir development, or guide the decision-making process.', 'In one or more embodiments, methods may be applied to any deviated or horizontal wells provided a set of log measurements are available and registered to their position in a well or in space, either for real-time analysis of drilling measurements, geosteering, or post-drill mode measurement analysis.', 'Computing System\n \nEmbodiments of the present disclosure may be implemented on a computing system.', 'Any combination of mobile, desktop, server, embedded, or other types of hardware may be used.', 'For example, as shown in \nFIG.', '10\n, the computing system (\n1000\n) may include one or more computer processor(s) (\n1002\n), associated memory (\n1004\n) (e.g., random access memory (RAM), cache memory, flash memory, etc.), one or more storage device(s) (\n1006\n) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities.', 'The computer processor(s) (\n1002\n) may be an integrated circuit for processing instructions.', 'For example, the computer processor(s) may be one or more cores, or micro-cores of a processor configured to perform methods described above, including normalizing two or more wellbore logs obtained from the output of two or more wellbore tool surveys of a wellbore in a formation of interest; inputting two or more wellbore logs into a correlation matrix; assigning each of the two or more wellbore logs a positive or negative value based on the impact on a selected wellbore quality; performing a principal component analysis of the two or more wellbore logs to obtain one or more loading vectors; computing weighting factors for each of the two or more wellbore logs from the one or more loading vectors; and generating a quality index by linearly combining the two or more wellbore logs using the computed weighting factors.', 'The computing system (\n1000\n) may also include one or more input device(s) (\n1010\n), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.', 'Further, the computing system (\n1000\n) may include one or more output device(s) (\n1008\n), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device.', 'One or more of the output device(s) may be the same or different from the input device(s).', 'The computing system (\n1000\n) may be connected to a network (\n1012\n) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) via a network interface connection (not shown).', 'The input and output device(s) may be locally or remotely (e.g., via the network (\n1012\n)) connected to the computer processor(s) (\n1002\n), memory (\n1004\n), and storage device(s) (\n1006\n).', 'Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.', 'Software instructions in the form of computer readable program code to perform embodiments of the disclosure may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium.', 'Specifically, the software instructions may correspond to computer readable program code that when executed by a processor(s), is configured to perform embodiments of the disclosure.', 'Further, one or more elements of the aforementioned computing system (\n1000\n) may be located at a remote location and connected to the other elements over a network (\n1012\n).', 'Further, embodiments of the disclosure may be implemented on a distributed system having a plurality of nodes, where each portion of the disclosure may be located on a different node within the distributed system.', 'In one embodiment of the disclosure, the node corresponds to a distinct computing device.', 'Alternatively, the node may correspond to a computer processor with associated physical memory.', 'The node may alternatively correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.', 'Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples without materially departing from this subject disclosure.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112 (f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A method, comprising:\nnormalizing two or more wellbore logs obtained from the output of two or more wellbore tool surveys of a wellbore in a formation of interest to provide two or more normalized wellbore logs;\ninputting the two or more normalized wellbore logs into a correlation matrix;\nassigning each of the two or more normalized wellbore logs a positive or negative value based on the impact on a selected wellbore quality;\nperforming a principal component analysis of the two or more normalized wellbore logs to obtain one or more loading vectors;\ncomputing weighting factors for each of the two or more normalized wellbore logs from the one or more loading vectors;\ngenerating a quality index by linearly combining the two or more normalized wellbore logs using the computed weighting factors;\ninputting a user-defined threshold for the selected quality being indexed, wherein the quality index is a reservoir quality log;\ndesignating one or more wellbore intervals in a reservoir quality log as pay regions based on the user-defined threshold; and\ntransitioning the wellbore to production and producing hydrocarbons from the one or more wellbore intervals designated as pay regions.', '2.', 'The method of claim 1, wherein the two or more wellbore logs comprise at least gamma ray, deep resistivity, bulk rock density, and thermal neutron porosity.', '3.', 'The method of claim 1, wherein the quality index further comprises a completion quality log, and wherein the method further comprises:\ndesignating one or more regions in the completion quality log as completion targets.', '4.', 'The method of claim 3, further comprising:\ncompleting one or more regions designated as completion targets.', '5.', 'The method of claim 3, wherein the two or more wellbore logs comprise at least clay, pyrite, quartz-feldspar-mica, and total organic carbon.', '6.', 'The method of claim 1, wherein computing weighting factors for each of the two or more normalized wellbore logs comprises analyzing each of the normalized wellbore logs with a Kriging estimator that analyzes the loading vectors of the normalized wellbore logs from the principal component analysis.', '7.', 'The method of claim 1, further comprising:\nperforming interpolation or mapping of the quality index in 3D.\n\n\n\n\n\n\n8.', 'The method of claim 1, wherein the user-defined threshold is optimized to minimize the misclassification rate of one or more wellbore intervals in the quality log.', '9.', 'The method of claim 8, wherein the optimized threshold is applied to quality logs obtained from other wells.', '10.', 'The method of claim 1, wherein the principal component analysis comprises kernel principal component analysis.', '11.', 'The method of claim 1, wherein performing the principal component analysis comprises plotting principal component analysis results in 2D or 3D, and wherein the plotted data is used to generate the loading vectors.', '12.', 'The method of claim 1, wherein the two or more wellbore logs comprises at least four wellbore logs selected from a group consisting of: gamma ray, deep resistivity, bulk density, thermal neutron porosity, carbon weight fraction, clay weight fraction, pyrite weight fraction, quartz-feldspar-mica weight fraction, total organic carbon weight fraction, neutron, spectroscopy mineralogy, anhydrite, calcite, dolomite, evaporite, matrix grain density, NMR porosity, and permeability.', '13.', 'The method of claim 3, wherein the two or more wellbore logs comprises at least four wellbore logs selected from a group consisting of: clay, pyrite, quartz-feldspar-mica, total organic carbon, gamma ray, resistivity, density, neutron, compressional slowness, fast shear, quartz, dolomite, clay, calcite, evaporite, anhydrite, and matrix grain density.', '14.', 'A method, comprising:\nnormalizing two or more wellbore logs obtained from the output of two or more wellbore tool surveys of a wellbore in a formation of interest to provide two or more normalized wellbore logs;\ninputting the two or more normalized wellbore logs into a correlation matrix;\nassigning each of the two or more normalized wellbore logs a positive or negative sign based on the impact on a selected wellbore quality;\nperforming a principal component analysis of the two or more normalized wellbore logs to obtain one or more loading vectors;\ncomputing weighting factors for each of the two or more normalized wellbore logs from the one or more loading vectors;\ngenerating a reservoir quality log by linearly combining the two or more normalized wellbore logs using the computed weighting factors;\ngenerating a completion quality log by linearly combining the two or more normalized wellbore logs using the computed weighting factors;\npreparing a composite reservoir quality index from the product of the reservoir quality log and the completion quality log;\ninputting a user-defined threshold for the composite reservoir quality log;\ndesignating one or more wellbore intervals in a composite reservoir quality log as regions of interest based on the user-defined threshold; and\ntransitioning the wellbore to production or completion and producing hydrocarbons from or completing the one or more wellbore intervals designated as regions of interest.', '15.', 'The method of claim 14, wherein the two or more wellbore logs are selected from a group consisting of: gamma ray, deep resistivity, bulk rock density, thermal neutron porosity, clay, pyrite, quartz-feldspar-mica, and total organic carbon.', '16.', 'The method of claim 14, wherein computing weighting factors for each of the two or more normalized wellbore logs comprises analyzing each of the normalized wellbore logs with a Kriging estimator that analyzes the loading vectors of the normalized wellbore logs from the principal component analysis.', '17.', 'The method of claim 14, further comprising performing interpolation or mapping of the composite reservoir quality index in 3D.\n\n\n\n\n\n\n18.', 'The method of claim 14, wherein the user-defined threshold is optimized to minimize the misclassification rate of one or more wellbore intervals in the composite reservoir quality log.', '19.', 'The method of claim 14, wherein the principal component analysis comprises kernel principal component analysis.', '20.', 'The method of claim 14, wherein performing the principal component analysis comprises plotting principal component analysis results in 2D or 3D, and wherein the plotted data is used to generate the loading vectors.'] | ['FIG.', '1 is a flow diagram depicting a method in accordance with embodiments of the present disclosure;; FIG.', '2 is an illustration depicting an example of a pair-wise correlation matrix used to analyze wellbore measurements in accordance with embodiments of the present disclosure.', 'The bar on the right indicates the level of positive or negative correlation between measurement pairs;; FIG.', '3.1 is a correlation map for a number of logs in accordance with embodiments of the present disclosure;; FIG.', '3.2 is a correlation matrix for a number of logs that are used as example input for reservoir quality (RQ) in accordance with embodiments of the present disclosure;; FIG.', '3.3 is a graphical representation of the first three principal components for a number of logs that are used as example input in accordance with embodiments of the present disclosure;; FIGS.', '4.1 and 4.2 are graphical representations depicting the projection of data measurements and loading vectors in principal component space represented in two dimensions and three dimensions, respectively, in accordance with embodiments of the present disclosure;; FIG.', '5 is a graphical representation showing a continuous RQ index generated by linearly combining four well log measurements in accordance with embodiments of the present disclosure;; FIG.', '6 is a graphical representation showing a continuous RQ index with appended pay flags generated by linearly combining four well log measurements with weighting factors applied and followed by applying an optimal thresholding value in accordance with embodiments of the present disclosure;; FIG.', '7.1 is a correlation map for a number of logs that are used as example input for completion quality (CQ) index computation in accordance with embodiments of the present disclosure;; FIG.', '7.2 is a correlation matrix for a number of logs as example input in accordance with embodiments of the present disclosure;; FIG.', '7.3 is a graphical representation of the first three principal components for a number of logs as example input in accordance with embodiments of the present disclosure;; FIGS. 8.1 and 8.2 are graphical representations depicting projection of data measurements in principal component space represented in two dimensions and three dimensions, respectively, in accordance with embodiments of the present disclosure;; FIG.', '9 is a graphical representation showing a continuous CQ index generated by linearly combining four example well log measurements in accordance with embodiments of the present disclosure; and; FIG.', '10 is a schematic showing an example of a computer system for executing methods in accordance with the present disclosure.'] |
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US11111764 | Wellbore annular safety valve and method | Feb 14, 2020 | Oystein Molstre | SCHLUMBERGER TECHNOLOGY CORPORATION | EP Application No. 1411745.2, Extended European Search Report, dated Nov. 27, 2015, 8 pgs. | 2798558; July 1957; Mcculloch; 2896547; July 1959; Franey; 3659961; May 1972; Lamb; 3746089; July 1973; Vencil; 4398555; August 16, 1983; Taylor; 4545731; October 8, 1985; Canalizo; 4589482; May 20, 1986; Bayh, III; 4632184; December 30, 1986; Renfroe, Jr. et al.; 4708595; November 24, 1987; Maloney et al.; 5022427; June 11, 1991; Churchman et al.; 5040606; August 20, 1991; Hopper; 5875852; March 2, 1999; Floyd et al.; 6745844; June 8, 2004; Henderson; 20040129433; July 8, 2004; Krawiec et al.; 20090095467; April 16, 2009; Phoi-montri et al.; 20100032153; February 11, 2010; Phloi-montri et al.; 20100155077; June 24, 2010; Jardim De Azevedo et al.; 20110132593; June 9, 2011; Phloi-montri et al.; 20110303419; December 15, 2011; Maier; 20120175108; July 12, 2012; Foubister et al. | 2241722; September 1991; GB; WO2001044619; June 2001; WO; WO2013062566; May 2013; WO | ['A method includes deploying a tubing having a tubing bore in a casing in a wellbore, the tubing including a cup packer forming an annular barrier across a tubing-casing annulus separating the tubing-casing annulus into an upper annulus and a lower annulus, the cup packer having a fluid conduit extending substantially parallel to the tubing bore, and a barrier valve coupled with the fluid conduit to permit one-way fluid flow from the upper annulus to the lower annulus, communicating a fluid from the upper annulus through the barrier valve to the lower annulus, and closing the barrier valve in response to pressure in the upper annulus being less than pressure in the lower annulus.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'This application is a divisional of U.S. Patent Application Publication No. 2015/0053416, filed Aug. 22, 2013, the disclosure of which is hereby incorporated by reference.', 'BACKGROUND\n \nThis section provides background information to facilitate a better understanding of the various aspects of the disclosure.', 'It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.', 'Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geological formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation.', 'Forms of well completion components may be installed in the wellbore to control and enhance efficiency of producing fluids from the reservoir.', 'SUMMARY\n \nA well system in accordance to one or more embodiments includes an annular barrier disposed in a tubing-casing annulus of a wellbore separating the tubing-casing annulus into an upper annulus and a lower annulus and a barrier valve coupled with the annular barrier, the barrier valve permitting one-way fluid communication from the upper annulus to the lower annulus.', 'An annular safety valve in accordance with an embodiment includes dual cup packers oriented in opposite direction disposed about a mandrel having a tubing bore, a fluid conduit extending through the dual cup packers substantially parallel to the tubing bore, and a barrier valve in connection with the fluid conduit to permit one-way fluid flow through the fluid conduit.', 'A method includes deploying tubing having a tubing bore in casing in a wellbore, the tubing having a cup packer forming an annular barrier across a tubing-casing annulus, the cup packer having a fluid conduit extending substantially parallel to the tubing bore, and a barrier valve coupled with the fluid conduit to permit one-way fluid flow from the upper annulus to the lower annulus, communicating a fluid from the upper annulus through the barrier valve to the lower annulus, and closing the barrier valve in response to pressure in the upper annulus being less than pressure in the lower annulus.', 'The foregoing has outlined some of the features and technical advantages in order that the detailed description of the annular safety valves, systems, and methods that follow may be better understood.', 'Additional features and advantages of the annular safety valve system and method will be described hereinafter which form the subject of the claims of the invention.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nEmbodiments of annular safety valves and methods are described with reference to the following figures.', 'The same numbers are used throughout the figures to reference like features and components.', 'It is emphasized that, in accordance with standard practice in the industry, various features are not necessarily drawn to scale.', 'In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n illustrates a well system in which an annular safety valve in accordance to one or more embodiments is incorporated.\n \nFIG.', '2\n illustrates an annular safety valve in accordance to one or more embodiments.\n \nFIG.', '3\n illustrates an annular barrier in accordance to one or more embodiments.\n \nFIG.', '4\n is a bottom view illustration of an annular barrier in accordance to one or more embodiments.\n \nFIG.', '5\n illustrates a side pocket mandrel in accordance to one or more embodiments.\n \nFIG.', '6\n illustrates a side pocket mandrel along the line I-I of \nFIG.', '5\n.', 'FIG.', '7\n illustrates a barrier valve in accordance to one or more embodiments.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'As used herein, the terms “connect,” “connection,” “connected,” “in connection with,” and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element.”', 'Further, the terms “couple,” “coupling,” “coupled,” “coupled together,” and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements.”', 'As used herein, the terms “up” and “down,” “upper” and “lower,” “top” and “bottom,” and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements.', 'Commonly, these terms relate to a reference point as the surface from which drilling operations are initiated as being the top point and the total depth being the lowest point, wherein the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface.', 'Generally, a well consists of a wellbore drilled through one or more reservoir production zones.', 'Conductor casing serves as support during drilling operations and provides support for a wellhead and Christmas tree.', 'In offshore wells, a riser may extend the wellbore from the sea floor to the surface platform.', 'One or more strings of casing with diminishing inside diameters will be run inside of the conductor.', 'The well may then be completed with a tubing string extending to the one or more reservoir production zones.', 'The annulus between the tubing and the smallest diameter casing, i.e., the A-annulus, extends from the producing zones to the surface.', 'The surface barrier seals the tubing-casing annulus from the environment.', 'The tubing may be landed for example in a production packer located above the upper most production zone to isolate the annulus from the producing zones.', 'The tubing-casing annulus may extend thousands of feet from the surface to the production packer.', 'The tubing-casing annulus may be utilized for example for gas-injection into the tubing to reduce the density of the fluid in the tubing to facilitate production to the surface.', 'The tubing-casing annulus may be exposed to the surrounding formations via perforations or loss of casing integrity.', 'In the case of failure of the surface annular barrier, for example located at the wellhead, wellbore fluid in the tubing-casing annulus will be in communication with the environment.', 'In accordance to one or more embodiments, an annular safety valve is integrated in the tubing to provide an annular safety barrier in the upper completion.', 'In accordance with embodiments, the annular safety valve provides one-way fluid flow from the upper annulus to the lower annulus.', 'In accordance to one or more embodiments, the annular safety valve provides one or more control line bypasses to operationally connect devices in the lower completion below the annular safety valve to surface control systems at the surface or in the upper completion above the annular safety valve.', 'In accordance to one or more embodiments, the annular safety valve is not surface controlled.', 'FIG.', '1\n illustrates a well system \n5\n in which a subsurface annular safety valve (“ASV”), generally denoted by the numeral \n10\n, may be incorporated and utilized.', 'Annular safety valve \n10\n includes a one-way barrier valve \n12\n coupled with an annular barrier \n14\n.', 'In accordance with embodiments, annular barrier \n14\n is packer, for example a dual cup packer.', 'Annular barrier \n14\n provides a sealed annular barrier between the tubing and casing.', 'Barrier valve \n12\n is illustrated as being located above annular barrier \n14\n in \nFIG.', '1\n, however, as will be understood by those skilled in the art with benefit of this disclosure, barrier valve \n12\n may be locate below annular barrier \n14\n.', 'Barrier valve \n12\n provides one-way fluid flow in the direction from the upper completion or upper annulus across annular barrier \n14\n to the lower completion or lower annulus.', 'In accordance to one or more embodiments, barrier valve \n12\n is normally closed, fail safe close, and actuated to the open position in response to pressure in the upper annulus being greater than pressure in the lower annulus.', 'Similarly, barrier valve \n12\n is actuated to the closed position in response to pressure in the lower annulus exceeding pressure in the upper annulus.', 'Well system \n5\n is illustrated as a gas lift completion that includes tubing \n16\n that extends from an upper or surface barrier \n18\n into a wellbore \n20\n.', 'A portion of wellbore \n20\n is completed with casing \n22\n.', 'The tubing-casing annulus, generally denoted by the numeral \n24\n, between tubing \n16\n and casing \n22\n may be referred to as the A-annulus.', 'Surface barrier \n18\n, for example a tubing hanger, is depicted in \nFIG.', '1\n located at a water surface \n26\n, for example at a platform, e.g., tension leg platform, or ship, positioned above a sea floor \n28\n.', 'Surface barrier \n18\n may be located in the wellhead area.', 'Reference to the surface of the well is not limited to the sea surface or sea floor.', 'Annular safety valve \n10\n is set in the upper completion and separates tubing-casing annulus \n24\n into an upper annulus \n23\n and a lower annulus \n25\n.', 'Tubing \n16\n may be landed at a production packer \n9\n located isolating lower annulus \n25\n from a production zone \n7\n, i.e., reservoir formation.', 'Production packer \n9\n may be utilized to anchor tubing \n16\n and annular safety valve \n10\n with casing \n22\n.', 'Tubing \n16\n incorporates one or more gas lift valves \n30\n which are located in the lower tubing section \n17\n below annular safety valve \n10\n in wellbore \n20\n.', 'For purposes of gas injection, well system \n5\n includes a gas compressor \n32\n located at the surface to pressurize gas that is communicated to tubing-casing annulus \n24\n.', 'The pressurized gas \n34\n is communicated from upper annulus \n23\n through annular safety valve \n10\n to lower annulus \n25\n.', 'The pressurized gas \n34\n is communicated from lower annulus \n25\n into tubing bore \n36\n through gas lift valves \n30\n.', 'One or more control lines \n38\n may extend from a surface system \n40\n, for example an electronic controller and or pressurized fluid source, to downhole devices, generally denoted by the numeral \n42\n, located below annular safety valve \n10\n.', 'Downhole devices \n42\n may include devices such as, and without limitation to, pressure, temperature, and flow rate sensors \n43\n, chemical injection valves \n45\n, and flow control valves \n47\n.', 'In accordance to one or more embodiments, annular safety valve \n10\n provides control line bypasses from the upper completion or surface to the lower completion while maintaining an annular barrier.', 'Together, annular safety valve \n10\n and tubing \n16\n can serve as a primary barrier to maintain well integrity.', 'In the depicted embodiment, a downhole safety valve \n44\n is located in the upper section \n15\n of tubing \n16\n, for example proximate to annular barrier \n14\n, to provide a vertical barrier through tubing bore \n36\n.', 'In this example, downhole safety valve \n44\n is a surface controlled subsurface safety valve (“SCSSV”) connected to the surface via a control line \n38\n.', 'Subsurface safety valve \n44\n may be a wireline or tubing set type.', 'Annular safety valve \n10\n serves as a safety barrier in A-annulus \n24\n in the event that surface barrier \n18\n is lost.', 'Lower annulus \n25\n although located above production packer \n9\n in \nFIG.', '1\n, may be in communication with formation fluids and pressure.', 'For example, perforations or loss integrity of casing \n22\n may expose tubing-casing annulus \n24\n to the surrounding formation \n46\n.', 'In \nFIG.', '1\n, gas lift injection through lower annulus \n25\n may temporarily supercharge formation \n46\n.\n \nFIG.', '2\n illustrates a retrievable annular safety valve \n10\n integrated in tubing \n16\n and deployed in casing \n22\n.', 'FIG.', '3\n illustrates annular barrier \n14\n in isolation and \nFIG.', '4\n illustrates a bottom end view of an annular barrier \n14\n.', 'Annular barrier \n14\n is illustrated as a dual cup packer having a top cup packer \n48\n or downstream cup packer and a bottom cup packer \n50\n or upstream cup packer.', 'Top packer \n48\n has an open end \n68\n oriented toward upper annulus \n23\n and bottom packer \n50\n has an open end \n68\n oriented toward lower annulus \n25\n.', 'Pressure in upper annulus \n23\n expands top cup packer \n48\n against casing \n22\n and pressure in lower annulus \n25\n expands bottom cup packer \n50\n against casing \n22\n.', 'Cup packers \n48\n, \n50\n are disposed about a feed-through mandrel \n52\n having a thick side \n51\n.', 'Bypass ports, generally denoted by the reference number \n60\n, are formed longitudinally through thick side \n51\n of annular barrier \n14\n, for example substantially parallel to tubing bore \n36\n, to pass or form a portion of an annular fluid conduit \n54\n.', 'Barrier valve \n12\n is coupled with fluid conduit \n54\n to provide one-way upper annulus \n23\n to lower annulus \n25\n fluid flow.', 'In \nFIG.', '2\n, barrier valve \n12\n is located in a side pocket mandrel \n56\n integrated, i.e., connected, with tubing \n16\n.', 'Annular safety valve \n10\n is illustrated in \nFIG.', '2\n eccentrically disposed in casing \n22\n with side pocket \n62\n aligned longitudinally with thick side \n51\n of annular barrier \n14\n.', 'One or more additional bypass ports \n60\n are formed through annular barrier \n14\n, for example feed-through mandrel \n52\n, to pass control lines \n38\n.', 'The annular barrier \n14\n depicted in \nFIG.', '4\n forms eight bypasses \n60\n communicating control lines \n38\n.', 'Control lines \n38\n include without limitation, electrical, optic, and hydraulic lines.', 'With reference in particular to \nFIGS.', '1-2 and 5-6\n, barrier valve \n12\n is a one-way valve providing fluid connection across annular barrier \n14\n from upper annulus \n23\n to lower annulus \n25\n through passage or conduit \n54\n.', 'Although barrier valve \n12\n is illustrated located above annular barrier \n14\n in \nFIGS.', '1 and 2\n, it will be understood by those skilled in the art with benefit of this disclosure that barrier valve \n12\n can be located below annular barrier \n14\n to provide fluid communication in the direction from upper annulus \n23\n to lower annulus \n25\n.', 'In accordance to one or more embodiments, barrier valve \n12\n is located in a side pocket mandrel \n56\n.', 'Barrier valve \n12\n is disposed in pocket \n62\n to provide one-way annulus to annulus fluid communication.', 'Fluid, such as gas \n34\n, flows from upper annulus \n23\n through port(s) \n64\n into pocket \n62\n and through barrier valve \n12\n into conduit \n54\n and lower annulus \n25\n.', 'Side pocket mandrel \n56\n may not include a port between tubing-casing annulus \n24\n and tubing bore \n36\n or the tubing bore may not be in communication with tubing-casing annulus \n24\n through barrier valve \n12\n.', 'Side pocket mandrel \n56\n may be a single or a dual pocket mandrel.', 'FIG.', '7\n illustrates a gas lift type barrier valve \n12\n in accordance to one or more embodiments.', 'Barrier valve \n12\n includes a reverse flow check valve \n66\n suited for barrier applications.', 'For example, barrier valve \n12\n is a barrier-qualified, reverse flow check valve that provides positive seal between the lower annulus side and the upper annulus side.', 'In accordance to one or more embodiments, barrier valve \n12\n has metal-to-meal seal surfaces without elastomers.', 'Some embodiments may have elastomer seal surfaces.', 'A non-limiting example of barrier valve \n12\n is a NOVA 15-B type of gas lift valve available from Schlumberger.', 'In accordance to one or more embodiments, a surface control system is not required for operation of annular safety valve \n10\n.', 'Barrier valve \n12\n may be retrieved, for example via wireline or slickline, eliminating the need to retrieve the completion, e.g., tubing, to maintain the well integrity.', 'If the pressure in lower annulus \n25\n exceeds the pressure in upper annulus \n23\n, barrier valve \n12\n closes.', 'Accordingly, barrier valve \n12\n fails safe closed if the surface barrier is lost.', 'Annular safety valve \n10\n is insensitive to setting depth.', 'In accordance with one or more embodiments, barrier valve \n12\n may be eliminated for example by eliminating or plugging conduit \n54\n.', 'For example, a dummy valve may be landed in pocket \n62\n to plug conduit \n54\n.', 'A method in accordance to one or more embodiments is now described with reference to \nFIGS.', '1-7\n.', 'When running the completion, tubing \n16\n is made-up at the surface to include annular safety valve \n10\n located above gas-lift valves \n30\n.', 'Side-pocket mandrel \n56\n and annular barrier \n14\n are aligned such that side pocket \n62\n and thick side \n51\n are aligned longitudinally.', 'Fluid conduit \n54\n is connected with or passed through a bypass port \n60\n of annular barrier \n14\n.', 'Control lines \n38\n are connected with or passed through bypass ports \n60\n.', 'Annular safety valve \n10\n is run into the wellbore and pressure in tubing-casing annulus \n24\n acts to seal cup packers \n48\n, \n50\n with casing \n22\n separating tubing-casing annulus \n24\n into an upper annulus \n23\n and a lower annulus \n25\n.', 'Fluid, for example gas \n34\n, is communicated from upper annulus \n23\n through barrier valve \n12\n and across annular barrier \n14\n in response to pressure in the upper annulus being greater than pressure in lower annulus \n25\n.', 'Gas \n34\n is injected from lower annulus \n25\n through gas lift valves \n30\n into tubing bore \n36\n.', 'Barrier valve closes in response to the pressure in upper annulus \n23\n being less than the pressure in lower annulus \n25\n.', 'The foregoing outlines features of several embodiments of annular safety valves, systems, and methods so that those skilled in the art may better understand the aspects of the disclosure.', 'Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the disclosure.', 'The scope of the invention should be determined only by the language of the claims that follow.', 'The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group.', 'The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.'] | ['1.', 'A method, comprising:\ndeploying a tubing having a tubing bore in a casing in a wellbore, the tubing comprising a cup packer forming an annular barrier across a tubing-casing annulus separating the tubing-casing annulus into an upper annulus and a lower annulus, the cup packer having a fluid conduit extending substantially parallel to the tubing bore, and a barrier valve coupled with the fluid conduit to permit one-way fluid flow from the upper annulus to the lower annulus;\ncommunicating a fluid from the upper annulus through the barrier valve to the lower annulus; and\nclosing the barrier valve in response to pressure in the upper annulus being less than pressure in the lower annulus,\nwherein the barrier valve is located in a side pocket of a side pocket mandrel integrated in the tubing,\nwherein the cup packer is disposed about a feed-through mandrel having a first side and a second side, the first side being thicker than the second side, and\nwherein the side pocket mandrel and the annular barrier are aligned such that the side pocket and the first side of the feed-through mandrel are aligned longitudinally.', '2.', 'The method of claim 1, wherein the fluid is a pressurized gas and further comprising injecting the pressurized gas from the lower annulus through a gas lift valve into the tubing bore.', '3.', 'The method of claim 1, further comprising a control line extending from the upper annulus through the annular barrier to the lower annulus.', '4.', 'The method of claim 1, wherein the barrier valve is normally closed and the barrier valve is opened in response to pressure in the upper annulus being greater than pressure in the lower annulus.', '5.', 'The method of claim 3, wherein:\nthe barrier valve is located in a side pocket mandrel integrated in the tubing;\nthe fluid is a pressurized gas; and\nfurther comprising injecting the pressurized gas from the lower annulus through a gas lift valve into the tubing bore.', '6.', 'The method of claim 1, wherein the feed-through mandrel comprises a port to pass a control line across the annular barrier of the cup packer.', '7.', 'The method of claim 1, wherein the cup packer is a dual cup packer.', '8.', 'The method of claim 1, wherein the barrier valve is located above the annular barrier.'] | ['FIG. 1 illustrates a well system in which an annular safety valve in accordance to one or more embodiments is incorporated.', '; FIG.', '2 illustrates an annular safety valve in accordance to one or more embodiments.; FIG.', '3 illustrates an annular barrier in accordance to one or more embodiments.; FIG.', '4 is a bottom view illustration of an annular barrier in accordance to one or more embodiments.; FIG.', '5 illustrates a side pocket mandrel in accordance to one or more embodiments.; FIG.', '6 illustrates a side pocket mandrel along the line I-I of FIG.', '5.; FIG. 7 illustrates a barrier valve in accordance to one or more embodiments.; FIG.', '1 illustrates a well system 5 in which a subsurface annular safety valve (“ASV”), generally denoted by the numeral 10, may be incorporated and utilized.', 'Annular safety valve 10 includes a one-way barrier valve 12 coupled with an annular barrier 14.', 'In accordance with embodiments, annular barrier 14 is packer, for example a dual cup packer.', 'Annular barrier 14 provides a sealed annular barrier between the tubing and casing.', 'Barrier valve 12 is illustrated as being located above annular barrier 14 in FIG.', '1, however, as will be understood by those skilled in the art with benefit of this disclosure, barrier valve 12 may be locate below annular barrier 14.', 'Barrier valve 12 provides one-way fluid flow in the direction from the upper completion or upper annulus across annular barrier 14 to the lower completion or lower annulus.', 'In accordance to one or more embodiments, barrier valve 12 is normally closed, fail safe close, and actuated to the open position in response to pressure in the upper annulus being greater than pressure in the lower annulus.', 'Similarly, barrier valve 12 is actuated to the closed position in response to pressure in the lower annulus exceeding pressure in the upper annulus.; FIG. 2 illustrates a retrievable annular safety valve 10 integrated in tubing 16 and deployed in casing 22.', 'FIG.', '3 illustrates annular barrier 14 in isolation and FIG.', '4 illustrates a bottom end view of an annular barrier 14.', 'Annular barrier 14 is illustrated as a dual cup packer having a top cup packer 48 or downstream cup packer and a bottom cup packer 50 or upstream cup packer.', 'Top packer 48 has an open end 68 oriented toward upper annulus 23 and bottom packer 50 has an open end 68 oriented toward lower annulus 25.', 'Pressure in upper annulus 23 expands top cup packer 48 against casing 22 and pressure in lower annulus 25 expands bottom cup packer 50 against casing 22.; FIG.', '7 illustrates a gas lift type barrier valve 12 in accordance to one or more embodiments.', 'Barrier valve 12 includes a reverse flow check valve 66 suited for barrier applications.', 'For example, barrier valve 12 is a barrier-qualified, reverse flow check valve that provides positive seal between the lower annulus side and the upper annulus side.', 'In accordance to one or more embodiments, barrier valve 12 has metal-to-meal seal surfaces without elastomers.', 'Some embodiments may have elastomer seal surfaces.', 'A non-limiting example of barrier valve 12 is a NOVA 15-B type of gas lift valve available from Schlumberger.'] |
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US11111757 | System and methodology for controlling fluid flow | Mar 16, 2018 | Bryan Stamm, Michael Dean Langlais, John R. Whitsitt | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion of PCT Application No. PCT/US2018/022773 dated Jun. 27, 2018, 14 pages.; International Preliminary Report on Patentability of PCT Application No. PCT/US2018/022773 dated Sep. 26, 2019, 12 pages.; Office Action received in Russian Patent Application No. 2019132603 dated Mar. 30, 2021, 14 pages with English Translation.; International Search Report and Written Opinion of PCT Application No. PCT/US2020/021658 dated Jul. 2, 2020, 14 pages. | 6333699; December 25, 2001; Zierolf; 6333700; December 25, 2001; Thomeer et al.; 6536524; March 25, 2003; Snider; 6759968; July 6, 2004; Zierolf; 6915848; July 12, 2005; Thomeer et al.; 6989764; January 24, 2006; Thomeer et al.; 7014100; March 21, 2006; Zierolf; 7063148; June 20, 2006; Jabusch; 7283061; October 16, 2007; Snider et al.; 7385523; June 10, 2008; Thomeer et al.; 7400263; July 15, 2008; Snider et al.; 7677439; March 16, 2010; Zierolf; 7708068; 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Langlais | 1479627; May 1989; SU; 2009098512; August 2009; WO; 2012082304; June 2012; WO; 2020185655; September 2020; WO | ['A technique facilitates formation of a gravel pack.', 'A well completion is provided to facilitate improved gravel packing during a gravel packing operation and subsequent production.', 'The well completion is constructed to freely return a gravel pack carrier fluid through a base pipe during gravel packing.', 'A valve system is positioned to enable restriction of fluid flow into the base pipe following the gravel packing operation.', 'The valve system may be selectively actuated to restrict the fluid flow into the base pipe via a signal such as a pressure signal or timed electric signal.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'The present document is based on and claims priority to U.S. Provisional Application Ser.', 'No. 62/472,459, filed Mar. 16, 2017, which is incorporated herein by reference in its entirety.', 'BACKGROUND\n \nGravel packs are used in wells for removing particulates from inflowing hydrocarbon fluids.', 'In a variety of applications gravel packing is performed in long horizontal wells by pumping gravel suspended in a carrier fluid down the annulus between the wellbore and a screen assembly.', 'The carrier fluid is returned to the surface after depositing the gravel in the wellbore annulus.', 'To return to the surface, the carrier fluid flows through the screen assembly, through base pipe perforations, and into a production tubing which routes the returning carrier fluid back to the surface.', 'Additionally, some applications utilize alternate path systems having various types of shunt tubes which help distribute the gravel slurry.', 'In some applications, inflow control devices have been combined with screen assemblies to provide control over the subsequent inflow of production fluids.', 'However, the combination of inflow control devices and alternate path systems provide technical complications regarding flow of the returning carrier fluid back into the production tubing.', 'SUMMARY', 'In general, a system and methodology are provided for facilitating formation of a gravel pack and subsequent production.', 'A well completion is provided to facilitate improved gravel packing during a gravel packing operation and subsequent production through an inflow control device (ICD).', 'The well completion is constructed to freely return a gravel pack carrier fluid through a base pipe during gravel packing.', 'A valve system is positioned to enable restriction of fluid flow into the base pipe following the gravel packing operation.', 'The valve system is readily actuated to restrict the fluid flow into the base pipe via a signal, e.g. a pressure signal or a timed electrical signal.', 'However, many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nCertain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements.', 'It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:\n \nFIG.', '1\n is a schematic illustration of an example of a completion system deployed in a wellbore, according to an embodiment of the disclosure;\n \nFIG.', '2\n is a schematic illustration similar to that of \nFIG.', '1', 'but following a gravel packing operation, according to an embodiment of the disclosure;\n \nFIG.', '3\n is a schematic illustration similar to that of \nFIG.', '2\n following initiation of production flow, according to an embodiment of the disclosure;\n \nFIG.', '4A\n is a cross-sectional illustration showing operation of a valve assembly operable to control fluid flow with respect to the completion system, according to an embodiment of the disclosure;\n \nFIG.', '4B\n is a cross-sectional illustration similar to that of \nFIG.', '4A\n but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '5A\n is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '5B\n is a cross-sectional illustration similar to that of \nFIG.', '5A', 'but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '6A\n is a cross-sectional illustration showing another embodiment of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '6B\n is an enlarged illustration of an example of a cutter mechanism which may be used in the valve assembly illustrated in \nFIG.', '6A\n, according to an embodiment of the disclosure;\n \nFIG.', '6C\n is an enlarged illustration of an example of a locking mechanism which may be used in the valve assembly illustrated in \nFIG.', '6A\n, according to an embodiment of the disclosure;\n \nFIG.', '6D\n is a cross-sectional illustration similar to that of \nFIG.', '6A\n but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '7\n is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '8A\n is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '8B\n is a cross-sectional illustration similar to that of \nFIG.', '8A\n but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '8C\n is an enlarged illustration of an example of a retainer mechanism which may be used in the valve assembly illustrated in \nFIG.', '8A\n, according to an embodiment of the disclosure;\n \nFIG.', '8D\n is an illustration similar to that of \nFIG.', '8C', 'but after release of the retainer mechanism, according to an embodiment of the disclosure;\n \nFIG.', '9\n is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '10A\n is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '10B\n is a cross-sectional illustration similar to that of \nFIG.', '10A\n but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '10C\n is an enlarged illustration of an example of a retainer mechanism which may be used in the valve assembly illustrated in \nFIG.', '10A\n, according to an embodiment of the disclosure;\n \nFIG.', '10D\n is an illustration similar to that of \nFIG.', '10C\n but after release of the retainer mechanism, according to an embodiment of the disclosure;\n \nFIG.', '11A\n is an illustration of another embodiment of the valve assembly having a backup triggering system for actuating the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '11B\n is an illustration of the backup triggering system from a different angle, according to an embodiment of the disclosure;\n \nFIG.', '11C\n is an illustration of the backup triggering system from a different angle, according to an embodiment of the disclosure;\n \nFIG.', '11D\n is a cross-sectional illustration of the backup triggering system for actuating the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '12\n is a schematic illustration showing another application of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '13\n is a schematic illustration showing another application of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '14\n is a schematic illustration showing another embodiment of an actuator system of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '15\n is a cross-sectional illustration showing another embodiment of an actuator system usable in various embodiments of the valve assembly, according to an embodiment of the disclosure;\n \nFIG.', '16\n is a cross-sectional illustration similar to that of \nFIG.', '15\n but showing the actuator system in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '17\n is a schematic illustration of another example of a completion system deployed in a wellbore, according to an embodiment of the disclosure;\n \nFIG.', '18A\n is a schematic illustration of another example of a completion system deployed in a wellbore, according to an embodiment of the disclosure; and\n \nFIG.', '18B\n is a schematic illustration similar to that of \nFIG.', '18A\n but in a different operational position, according to an embodiment of the disclosure.', 'DETAILED DESCRIPTION', 'In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure.', 'However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.', 'The disclosure herein generally involves a system and methodology useful for controlling fluid flow.', 'The system and methodology may be used, for example, to facilitate formation of gravel packs in wellbores and subsequent production of well fluids.', 'The well completion system is constructed to freely return a gravel pack carrier fluid through a base pipe of the completion system during gravel packing.', 'A valve system is positioned to enable restriction of fluid flow into the base pipe following the gravel packing operation.', 'For example, the valve system may be used to convert the completion system from allowing free-flowing return of carrier fluids to restricted flow through an inflow control device.', 'The valve system actuates in response to a predetermined signal to restrict the fluid flow into the base pipe.', 'In some embodiments, the well completion is provided with a shunt tube system for carrying gravel slurry along an alternate path so as to facilitate improved gravel packing during a gravel packing operation.', 'For example, the valve system may be operatively coupled with the shunt tube system and selectively actuated to restrict the fluid flow into the base pipe via a pressure signal applied in the shunt tube system.', 'In other embodiments, however, the signal may be in the form of a timed electric signal or other suitable signal.', 'However, pressure signals, timed electric signals, or other suitable signals may be used with a variety of well completions, including well completions which do not employ the alternate path type shunt tube systems.', 'Inflow control devices (ICDs) have been used in completion systems having screen assemblies deployed along, for example, horizontal wells.', 'ICDs enable production maximization throughout longer wells by restricting production from the heel of the well and from high permeability zones, thus allowing flow contribution in hard-to-reach regions of the well, e.g. regions at the toe of the well and lower permeability zones.', 'In various applications, gravel packs are formed along the screen assemblies of the completion system to help filter sand from the inflowing well fluid.', 'Shunt tube systems can be used to provide alternate paths for the gravel slurry during the gravel packing operation to ensure a more uniform gravel pack.', 'The completion systems described herein use valve assemblies controlled by signals, e.g. pressure signals provided via the shunt tube system.', 'The valve assemblies may be selectively actuated between a flow position enabling a freer flow of returning gravel slurry carrier fluid and a subsequent flow position restricting flow.', 'For example, the subsequent flow position may restrict flow of fluid during production to flow through ICDs at desired well zones.', 'Because gravel packing operations often take place at significant flow rates through the shunt tube system, return of the carrier fluid at this rate involves providing relatively large flow areas through the base pipe wall.', 'This allows the returning carrier fluid to flow into an interior of the base pipe for return to the surface.', 'The ICDs used in many types of production operations, however, do not enable a desirable level of flow with respect to directing the carrier fluid to an interior of the base pipe.', 'In embodiments described herein, a valve assembly is used in a screen assembly of the completion system to enable increased flow of carrier fluid into the base pipe during the gravel packing operation.', 'However, the valve assembly may be actuated via a signal, e.g. pressure signals or timed electric signals, to restrict the inflow of fluid to a desired ICD level flow during subsequent production of well fluids.', 'In some embodiments, multiple valve assemblies may be used in multiple corresponding screen assemblies disposed along the completion system.', 'According to an embodiment, the completion system utilizes at least one valve assembly having a valve member shiftable between operational positions.', 'By way of example, the valve member may comprise a gravel pack-to-ICD transition dart shiftable between operational positions.', 'In some embodiments, a pressure signal applied through the shunt tube system may be used to trigger actuation of the transition dart in the valve assembly.', 'For example, a screen-out shunt tube pressure within the alternate path system transport tubes may be used to trigger the transition dart or darts from a free flow position to a restricted (ICD) flow position.', 'In various gravel packing operations, a screen-out pressure spike occurs at completion of the gravel packing operation.', 'This pressure spike may be utilized to activate transition of the valve assemblies from a gravel pack configuration to an ICD configuration.', 'It should be noted that if valve assembly activation pressure settings are below friction pressures experienced while gravel packing at far distances downhole, then friction pressures may transition some valve assemblies during the gravel pack operation while the remaining valve assemblies activate upon experiencing the screen-out pressure spike.', 'However, other types of pressure signals may be provided through the shunt tube system for actuation of the valve assembly or assemblies from one operational position to another.', 'Additionally, other types of signals may be used to initiate actuation of the valve assembly, e.g. electric signals automatically initiated after a predetermined time period.', 'Referring generally to \nFIG.', '1\n, an example of a completion system \n20\n is illustrated as deployed in a wellbore \n22\n.', 'In this example, completion system \n20\n comprises a screen assembly \n24\n having a base pipe \n26\n which may be formed by joining a plurality of base pipe joints.', 'The completion system \n20\n may comprise a plurality of the screen assemblies \n24\n connected together sequentially.', 'As illustrated, each screen assembly \n24\n may comprise a tubular member \n28\n having a filter section \n30\n and a non-permeable section \n32\n.', 'The base pipe \n26\n is disposed within the tubular member \n28\n and creates an annulus \n34\n therebetween.', 'In this embodiment, the base pipe \n26\n has a perforated base pipe section \n36\n generally radially inward of non-permeable section \n32\n and a non-perforated base pipe section \n38\n generally radially inward of filter section \n30\n.', 'A bulkhead \n40\n may extend between tubular member \n28\n and base pipe \n26\n at a location dividing the perforated base pipe section \n36\n from the non-perforated base pipe section \n38\n.', 'The bulkhead \n40\n comprises a passage \n42\n, e.g. a plurality of passages \n42\n, extending therethrough and of sufficient size to avoid substantial pressure loss as a clean carrier fluid \n44\n is returned during a gravel packing operation.', 'As illustrated, the clean, gravel slurry carrier fluid \n44\n returns through filter section \n30\n, flows along annulus \n34\n, through passage(s) \n42\n, through openings \n46\n of perforated base pipe section \n36\n, and into the interior of base pipe \n26\n for return to a surface location.', 'In this embodiment, the screen assembly \n24\n further comprises an alternate path, shunt tube system \n48\n deployed externally of tubular member \n28\n.', 'The shunt tube system \n48\n may comprise a plurality of tubes for carrying and distributing gravel slurry during a gravel packing operation.', 'For example, the shunt tube system \n48\n may comprise at least one transport tube \n50\n and at least one packing tube \n52\n used to transport and disperse the gravel slurry, respectively.', 'For example, one or more packing tubes \n52\n may be used in each well zone \n54\n to distribute gravel slurry into the well zone \n54\n.', 'The carrier fluid \n44\n flows back into the base pipe \n26\n leaving a gravel pack \n56\n, as illustrated in FIG.', '2\n.', 'The shunt tube system \n48\n also may comprise a manifold or manifolds \n58\n disposed along the base pipe \n26\n for fluidly connecting the transport tube \n50\n to the packing tubes \n52\n.', 'Referring again to \nFIG.', '1\n, the completion system \n20\n further comprises at least one valve assembly \n60\n.', 'By way of example, one or more valve assemblies \n60\n may be combined into each screen assembly \n24\n as illustrated.', 'Each valve assembly \n60\n is positioned in cooperation with a corresponding passage \n42\n.', 'In some embodiments, a single valve assembly \n60\n may be positioned in cooperation with a single passage \n42\n while other embodiments may utilize a plurality of valve assemblies \n60\n positioned for cooperation with corresponding passages \n42\n in bulkhead \n40\n.', 'Each valve assembly \n60\n may be activated, e.g. triggered, via an actuator system \n61\n, e.g. a pressure based actuator system, an electrical actuation system, and/or other suitable actuation system, actuatable to enable transmission of the valve assembly \n60\n between operational positions.', 'The actuation system \n61\n actuates in response to a suitable signal which may be in the form of a pressure signal, a timed electrical signal, or another suitable signal.', 'In some embodiments, each valve assembly \n60\n may be coupled with a flow line \n62\n extending to the shunt tube system \n48\n.', 'By way of example, the flow line \n62\n may be placed into communication with the shunt tube system \n48\n in manifold \n58\n.', 'In some applications, the flow line \n62\n may be placed in communication with transport tube \n50\n.', 'In this type of embodiment, the valve assembly \n60\n is actuatable via a suitable pressure signal applied in the shunt tube system \n48\n and communicated to the valve assembly \n60\n via the flow line \n62\n.', 'By way of example, the actuation system \n61\n may comprise a pressure release mechanism \n64\n.', 'The pressure release mechanism \n64\n may be positioned along the flow line \n62\n to prevent communication of pressure along the flow line \n62\n until the desired pressure signal is applied to flow line \n62\n via shunt tube system \n48\n.', 'According to an example, each valve assembly \n60\n may comprise a valve member \n66\n oriented for selective engagement with the corresponding passage \n42\n so as to limit flow through the bulkhead \n40\n.', 'The limitation of flow through bulkhead \n40\n also serves to limit the flow into base pipe \n26\n through perforated base pipe section \n36\n once the valve assembly \n60\n is triggered via a suitable pressure signal applied to shunt tube system \n48\n and flow line \n62\n.', 'In some embodiments, the valve member \n66\n is in the form of a dart.', 'The valve member/dart \n66\n may comprise an ICD \n68\n which provides the desired flow into base pipe \n26\n once the valve assembly \n60\n is actuated.', 'It should be noted the valve member/dart \n66\n also may comprise a plug; and the ICD \n68\n or ICDs \n68\n may be located along the wall forming base pipe \n26\n as described in greater detail below.', 'By shifting the valve member/dart \n66\n during actuation of valve assembly \n60\n, the corresponding screen assembly may be transitioned from gravel packing mode to production flow mode.', 'In the illustrated embodiment, the dart \n66\n is slidably mounted in a valve assembly structure \n70\n.', 'The dart \n66\n may be selectively released upon application of the appropriate pressure signal via shifting of, for example, a piston \n72\n into engagement with the dart \n66\n in a manner which releases the dart \n66\n for movement into engagement with the corresponding passage \n42\n.', 'In some embodiments, the dart \n66\n may be shifted via pressurized fluid delivered through flow line \n62\n and in other applications the dart \n66\n may be shifted via other suitable mechanisms, such as a spring \n74\n.', 'For example, the piston \n72\n may be moved into engagement with a spring release pin \n75\n which releases spring \n74\n so as to shift dart \n66\n and ICD \n68\n into engagement with corresponding passage \n42\n.', 'The spring release pin \n75\n may operate to release a catch, ball, or other feature holding dart \n66\n and/or spring \n74\n in a retracted position.', 'The pressure release mechanism \n64\n also may be constructed in various configurations.', 'By way of example, the pressure release mechanism \n64\n may comprise a piston \n76\n sealably retained in a corresponding cylinder \n78\n by a retainer \n80\n, e.g. a necked tension bolt, as illustrated in \nFIG.', '1\n.', 'It should be noted the pressure release mechanism \n64\n may comprise various other components to retain pressure until a desired pressure level is applied.', 'Such components may include a rupture disc, an electric rupture disc (ERD), or other suitable devices which release upon application of a pressure level trigger or other suitable trigger, e.g. an electric signal.', 'One embodiment of an ERD which is responsive to an electric signal is described below with reference to \nFIGS.', '15 and 16\n.', 'Upon application of sufficient pressure in shunt tube system \n48\n, the retainer \n80\n releases piston \n76\n from corresponding cylinder \n78\n so that fluid may flow through the pressure release mechanism \n64\n along flow line \n62\n, as illustrated in \nFIG.', '2\n.', 'The pressure signal is communicated to the corresponding valve assembly \n60\n via flow line \n62\n and causes actuation of the valve assembly \n60\n.', 'In the illustrated embodiment, the dart \n66\n is released and shifted into engagement with the corresponding passage \n42\n.', 'In this example, the dart \n66\n comprises ICD \n68\n which allows a desired production flow \n82\n to flow through the ICD \n68\n and into base pipe \n26\n, as illustrated in \nFIG.', '3\n, when valve assembly \n60\n is in the restricted flow position.', 'Referring generally to \nFIGS.', '4-11\n, embodiments of valve assembly \n60\n are illustrated and comprise a dart \n66\n.', 'By way of example, the dart \n66\n may be part of a dart cartridge and may include ICD \n68\n which is selectively moved into engagement with the corresponding passage \n42\n.', 'However, the dart \n66\n also may be formed with a plug (as described in greater detail below with reference to \nFIG.', '17\n) which is moved to plug corresponding passage \n42\n and to thus force production flow through at least one ICD \n68\n positioned through the wall of base pipe \n26\n.', 'In the embodiment illustrated in \nFIGS. 4A and 4B\n, the dart \n66\n is held in structure \n70\n via spring release pin \n75\n which extends along a passage \n84\n, e.g. a bore, oriented longitudinally through dart \n66\n.', 'When the pressure signal is applied through flow line \n62\n, piston \n72\n is moved into engagement with spring release pin \n75\n in a manner which releases the dart \n66\n and thus the spring \n74\n.', 'The spring \n74\n forces dart \n66\n to move linearly into engagement with corresponding passage \n42\n as illustrated in \nFIG.', '4B\n.', 'The extended spring release pin \n75\n and corresponding passage \n84\n cooperate to help guide ICD \n68\n into engagement with passage \n42\n.', 'Once the dart \n66\n is extended, the spring release pin \n75\n may be re-locked in position via a lock mechanism \n85\n, e.g. a ball and pocket mechanism along passage \n84\n.', 'In this example, the ICD \n68\n may comprise one or more inflow control orifices or friction-inducing conduits 86 sized to enable the desired production flow after actuation of valve assembly \n60\n.', 'In some applications, each orifice \n86\n may be provided with a nozzle \n87\n formed of a suitably hard material.', 'In \nFIGS.', '5A and 5B\n, other embodiments of mechanisms for selectively releasing dart \n66\n and spring \n74\n are illustrated.', 'For example, the embodiment illustrated in \nFIG.', '5A\n comprises spring release pin \n75\n but in a shorter form which does not utilize passage \n84\n extending through the entire dart \n66\n.', 'The embodiment illustrated in \nFIG.', '5B\n utilizes a cutter mechanism \n88\n.', 'The cutter mechanism \n88\n may be actuated by piston \n72\n so as to cut a cord \n90\n, e.g. wire or multi-fiber string, which releases dart \n66\n and spring \n74\n, as illustrated in greater detail in \nFIGS.', '6A-6D\n.', 'As illustrated, the cord \n90\n is secured to dart \n66\n so as to hold spring \n74\n in a compressed state.', 'Once cutter mechanism \n88\n is actuated via piston \n72\n, the cord \n90\n is cut and dart \n66\n is released.', 'At this stage, spring \n74\n shifts dart \n66\n linearly into engagement with corresponding passage \n42\n.', 'A ball and pocket lock mechanism, e.g. lock mechanism \n85\n, may be used to secure the dart \n66\n in engagement with corresponding passage \n42\n.', 'However, additional and/or other types of locking mechanisms \n92\n, e.g. a spring-loaded catch, may be used to secure the dart \n66\n in this engaged position, as further illustrated in \nFIGS.', '6C and 6D\n.', 'Referring generally to \nFIG.', '7\n and \nFIGS.', '8A-8B\n, an embodiment of valve assembly \n60\n is illustrated in which fluid pressure is used to shift dart \n66\n rather than spring \n74\n.', 'In this example, the dart \n66\n is formed as a piston which seals with an interior surface of structure \n70\n.', 'The dart \n66\n may be held in a retracted position within structure \n70\n, as illustrated in \nFIG.', '7\n.', 'By way of example, the dart \n66\n may be held within structure \n70\n by a dart retainer \n94\n, e.g. a tension bolt \n96\n having a built in fracture region \n98\n.', 'The flow line \n62\n is placed in fluid communication with retainer \n94\n and dart \n66\n via a coupling \n100\n attached to structure \n70\n.', 'When the pressure signal, e.g. a sufficient pressure level, is provided through flow line \n62\n, the retainer \n94\n is released, e.g. tension bolt \n96\n is fractured, and dart \n66\n is released, as further illustrated in \nFIGS.', '8C and 8D\n.', 'Pressurized fluid may be directed into structure \n70\n through flow line \n62\n on a back side of dart \n66\n so as to shift dart \n66\n linearly into engagement with the corresponding passage \n42\n.', 'Locking mechanism \n92\n may again be used to secure the dart \n66\n and ICD \n68\n in this engaged position.', 'A similar embodiment of valve assembly \n60\n may include spring \n74\n so as to facilitate shifting of the dart \n66\n and ICD \n68\n into engagement with corresponding passage \n42\n, as illustrated in \nFIG.', '9\n and \nFIGS.', '10A-10B\n.', 'The retainer \n94\n/tension bolt \n96\n may again be used to secure dart \n66\n at a retracted position within structure \n70\n.', 'In this embodiment, the dart \n66\n may again be formed as a piston forming a seal with a corresponding interior surface of structure \n70\n.', 'When the pressure signal, e.g. a sufficient pressure level, is provided through flow line \n62\n, the retainer \n94\n is released, e.g. tension bolt \n96\n is fractured, and dart \n66\n is released, as further illustrated in \nFIGS.', '10C-10D\n.', 'Pressurized fluid may be used in cooperation with spring \n74\n to shift dart \n66\n linearly into engagement with the corresponding passage \n42\n.', 'Locking mechanism \n92\n may again be used to secure the dart \n66\n and ICD \n68\n in this engaged position.', 'Referring generally to \nFIGS.', '11A-11D\n, an embodiment of valve assembly \n60\n is illustrated with a backup trigger mechanism \n102\n.', 'The backup trigger mechanism \n102\n may be used with a variety of primary triggers which are actuated via a pressure signal provided in the shunt tubes system \n48\n.', 'In the example illustrated, the backup trigger mechanism \n102\n is used in combination with cutter mechanism \n88\n which serves as the primary trigger mechanism.', 'If, for example, the cutter mechanism \n88\n is unable to sever cord \n90\n or otherwise release dart \n66\n, the secondary or backup trigger mechanism \n102\n ensures that dart \n66\n is able to transition into engagement with the corresponding passage \n42\n.', 'In the specific example illustrated, backup trigger mechanism \n102\n comprises a dissolvable clamping block \n104\n.', 'The dissolvable clamping block \n104\n is constructed from material which dissolves over time in the presence of fluids found in or directed into wellbore \n22\n.', 'If the primary cutter mechanism \n88\n is unable to sever cord \n90\n and release dart \n66\n, the dissolvable clamping block \n104\n continues to dissolve until cord \n90\n is released.', 'For example, the cord \n90\n may be clamped between block \n104\n and an adjacent structure or the cord \n90\n may be tied to or otherwise secured within dissolvable clamping block \n104\n.', 'Once block \n104\n dissolves, the cord \n90\n is released and dart \n66\n is transitioned into engagement with the corresponding passage \n42\n.', 'It should be noted the valve assembly \n60\n may be selectively actuated via the appropriate pressure signal provided in shunt tube system \n48\n in many types of applications.', 'As illustrated schematically in \nFIG.', '12\n, for example, the bulkhead \n40\n may be located in a variety of positions along many types of well completion systems \n20\n so as to provide desired fluid flow control through various sections of the well completion system \n20\n.', 'The valve member \n66\n, e.g. dart \n66\n, may be used with various ICDs \n68\n and/or other tools to provide a desired valving and to thus control fluid flow.', 'In some embodiments (see \nFIG.', '17\n below), the dart \n66\n is used to plug passage \n42\n and the ICD \n68\n comprises a nozzle or other suitable flow control device disposed through, for example, the wall forming base pipe \n26\n.', 'Depending on the application, the valve assembly \n60\n may be actuated via shunt tube system supplied pressure signals for opening fluid flow, closing fluid flow, or providing desired restrictions on fluid flow.', 'In some applications, the valve assembly \n60\n may be positioned to change flow through one or more openings \n46\n formed directly through base pipe \n26\n, as illustrated in \nFIG.', '13\n.', 'Accordingly, various types of valve assemblies \n60\n may be operatively coupled with the shunt tube system \n48\n for actuation via various types of pressure signals provided via shunt tube system \n48\n.', 'Referring generally to \nFIG.', '14\n, a schematic representation of another embodiment of valve assembly \n60\n is illustrated.', 'In this embodiment, the valve assembly \n60\n is not actuated via a pressure signal but by another type of suitable signal.', 'For example, the valve assembly \n60\n may be actuated via an electric signal, such as a timed electric signal.', 'The timer-based activation enables the valve assembly \n60\n to be held in the open flow position to facilitate dehydration of the gravel pack during a gravel packing operation.', 'However, the valve assembly \n60\n is automatically shifted to the restricted production flow position upon passage of a predetermined period of time.', 'By way of example, the actuator system \n61\n of valve assembly \n60\n may comprise an actuator device \n106\n coupled with a timer \n108\n and corresponding electronics \n110\n, including a switch \n112\n.', 'A battery \n114\n or other suitable power source may be used to power the timer \n108\n and corresponding electronics \n110\n.', 'The predetermined period of time may be controlled by timer \n108\n and may be set to exceed the length of time for properly placing the gravel pack but not so long as to exceed the life of battery \n114\n.', 'When the timer \n108\n has counted to a pre-determined setting, the electronics \n110\n, e.g. on-board electronics, closes switch \n112\n coupled with actuator device \n106\n.', 'When the switch \n112\n is closed, an electrical signal, e.g. an electrical power signal, is able to communicate with the actuator device \n106\n and cause it to actuate.', 'By way of example, the actuator device \n106\n may be used to enable actuation of a piston coupled with the valve member \n66\n.', 'Referring generally to \nFIGS.', '15 and 16\n, an example is illustrated of an actuator system \n61\n utilizing a timed electric signal to initiate actuation of the valve assembly \n60\n.', 'In this embodiment, the actuator device \n106\n, timer \n108\n, electronics \n110\n, switch \n112\n, and battery \n114\n are disposed in a housing \n116\n.', 'By way of example, the actuator device \n106\n may be in the form of an ERD having a rupture member \n118\n, e.g. a rupture disc, which is ruptured upon impact by a corresponding rupture piston \n120\n.', 'The rupture piston \n120\n is moved into rupturing engagement with the rupture member \n118\n in response to a timed electric signal received upon the closing of switch \n112\n.', 'In other words, timer \n108\n and electronics \n110\n cause the closing of switch \n112\n after passage of a predetermined time period.', 'In this example, the closing of switch \n112\n in response to input from timer \n108\n and electronics \n110\n causes ignition of a propellant \n122\n in a chamber \n124\n enclosing rupture piston \n120\n.', 'The resulting pressure acting against rupture piston \n120\n drives the rupture piston \n120\n into rupturing engagement with the corresponding rupture member \n118\n.', 'Once the rupture member \n118\n is ruptured, fluid in an adjacent chamber \n125\n of housing \n116\n is allowed to pass through the actuator device \n106\n, as represented by arrow \n126\n.', 'This allows a first piston \n128\n located in chamber \n125\n to shift due to the hydrostatic pressure surrounding housing \n116\n, as illustrated in \nFIG.', '16\n.', 'The hydrostatic pressure drives external fluid into chamber \n125\n via one or more ports \n130\n extending through housing \n116\n.', 'Once the first piston \n128\n is sufficiently shifted, the inflowing fluid is able to shift a secondary piston \n132\n which may be coupled with valve member \n66\n.', 'Thus, the timed electric signal may be used to initiate actuation of the valve assembly \n60\n to the reduced flow configuration for subsequent production.', 'It should be noted, the actuator device \n106\n may have a variety of configurations and actuation mechanisms which are actuated in response to the timed electric signal or other suitable signal.', 'Referring generally to \nFIG.', '17\n, another embodiment of valve assembly \n60\n is illustrated as combined into a corresponding screen assembly \n24\n.', 'In this embodiment, valve assembly \n60\n is again positioned in cooperation with a corresponding passage \n42\n.', 'As with other embodiments described herein, each valve assembly \n60\n may be actuated between positions via a suitable actuator system \n61\n.', 'The actuation system \n61\n similarly actuates in response to a suitable signal which may be in the form of a pressure signal, a timed electrical signal, or another suitable signal as described above.', 'Additionally, each valve assembly \n60\n comprises valve member/dart \n66\n oriented for selective engagement with the corresponding passage \n42\n.', 'However, the dart \n66\n comprises a plug member \n134\n positioned to engage, e.g. sealably engaged, bulkhead \n40\n at corresponding passage \n42\n.', 'The plug member \n134\n serves to block flow through passage \n42\n.', 'However, a separate ICD \n68\n (or a plurality of ICDs \n68\n) may be positioned to enable production flow to the interior of base pipe \n26\n.', 'As illustrated, the ICD(s) \n68\n may comprise a nozzle, bore, or other suitable device for enabling a controlled flow from the exterior of base pipe \n26\n to the interior of base pipe \n26\n once valve assembly \n60\n has been actuated to block flow through passage \n42\n via plug member \n134\n.', 'Referring generally to \nFIGS.', '18A and 18B\n, another example of a completion system \n20\n is illustrated as deployed in a wellbore \n22\n.', 'In this example, completion system \n20\n again comprises screen assemblies \n24\n each associated with base pipe \n26\n and corresponding valve assembly \n60\n.', 'However, this embodiment of completion system \n20\n does not employ an alternate path system such as the shunt tube system \n48\n described above.', 'The valve assemblies \n60\n may be actuated via various types of actuator systems \n61\n, as described above, in response to a suitable signal such as a pressure signal or timed electric signal.', 'According to an embodiment, the valve assemblies \n60\n associated with corresponding screen assemblies \n24\n are connected to a pressure control line \n136\n.', 'The pressure control line \n136\n may be ported into production tubing \n138\n at a port location \n139\n.', 'The production tubing \n138\n is in fluid communication with the base pipe or pipes \n26\n positioned within screen assemblies \n24\n.', 'The pressure control line \n136\n also may be ported to each valve assembly \n60\n.', 'By way of example, each valve assembly \n60\n may have a surrounding dart housing \n140\n, and the pressure control line \n136\n may be ported into the dart housings \n140\n and ultimately into fluid communication with piston \n72\n or other suitable actuating component.', 'In some embodiments, a pressure release device \n142\n may be positioned along the pressure control line \n136\n between valve assemblies \n60\n and production tubing \n138\n.', 'By way of example, the pressure release device \n142\n may comprise a burst member \n144\n, e.g. a burst disc.', 'To rupture the burst member \n144\n, sufficient pressure may be applied within production tubing \n138\n to cause fracture of the burst member and activation of the valve assemblies \n60\n.', 'According to one embodiment, a straddle packer \n146\n may be moved downhole within production tubing \n138\n until it straddles port/location \n139\n.', 'A suitable rupture pressure may then be applied from the surface until the burst member \n144\n is fractured.', 'As a result, a pressure signal in the form of increased pressure travels through pressure control line \n136\n and may be used to activate the valve assembly \n60\n.', 'By way of example, the pressure signal in pressure control line \n136\n may be used to shift darts \n66\n (and the corresponding ICD \n68\n or plug member \n134\n) into flow restricting engagement with corresponding passages \n42\n.', 'It should be noted, however, this type of system also may utilize timed electric signals or other suitable signals to cause controlled actuation valve assemblies \n60\n in completion systems which do not utilize alternate path systems.', 'By way of example, these types of systems may be employed to perform high rate alpha-beta gravel packs with completion systems utilizing ICDs but without alternative path systems.', 'Additionally, these types of systems may be used as back-up systems with various completion systems \n20\n, including alternate path type completions.', 'The components and configuration of completion systems \n20\n may be changed to accommodate several gravel packing and production applications.', 'Similarly, the components and configuration of the shunt tube system \n48\n, valve assembly \n60\n, actuator system \n61\n, and pressure release mechanism \n64\n may be changed according to parameters of a given application.', 'By way of example, the actuator system \n61\n may act in response to pressure signals, timed electric signals, or other suitable signals.', 'For example, the actuator system \n61\n may comprise an electric rupture disc or other electronic release device which may be configured to electronically respond to other inputs, e.g. electrical inputs from a built in timer.', 'Actuator systems \n61\n also may be constructed to enable actuation of the pressure release mechanism \n64\n according to pressure signals in the form of various pressure inputs.', 'By way of example, actuation pressures used to enable communication of pressure through pressure release mechanism \n64\n may be in the range from 200 psi through 2500 psi or even higher.', 'The pressure signals also may comprise various pressure pulses/patterns applied to actuator system \n61\n to cause actuation of valve assembly \n60\n.', 'Additionally, the valve assembly \n60\n may utilize various types of valve members \n66\n, e.g. darts or other mechanisms, which may be selectively shifted to provide fluid flow control.', 'As discussed above, various types of valve members \n66\n may comprise ICDs \n68\n or plugs \n134\n of various sizes and configurations to provide desired fluid flow patterns before and after actuation of valve assembly \n60\n.', 'For example, the ICD \n68\n may have a nose protrusion with a seal, e.g. an O-ring, disposed on its outside diameter for sealing insertion into the corresponding passage \n42\n.', 'The ICD \n68\n also may comprise nozzle \n87\n disposed along an inside diameter of the nose protrusion and in communication with radial holes in a wall of dart \n66\n to provide a flow path to and through the nozzle \n87\n.', 'Such ICDs \n68\n may be used as part of the dart \n66\n or within the wall forming base pipe \n26\n depending on the configuration of the valve assemblies \n60\n.', 'The nozzle \n87\n may be sized to provide a desired choking of the production fluid flow as production fluid flows through filter section \n30\n, along annulus \n34\n, through the radial holes in dart \n66\n, and then through the ICD nozzle \n87\n.', 'If the dart \n66\n employees plug \n134\n, the nozzle \n87\n may be disposed within the wall forming base pipe \n26\n.', 'Following passage through nozzle \n87\n, the production flow is able to move to an interior of the base pipe \n26\n for production to a surface location or other desired location.', 'However, the structure of valve member \n66\n and/or overall valve assembly \n60\n may be changed to accommodate various flow control applications.', 'In fact, some embodiments may utilize dart \n66\n or another suitable operator which is moved in a non-linear motion to provide a desired valve control over fluid flow.', 'Various pressure levels and/or other pressure signals also may be provided in shunt tube system \n48\n and through flow line \n62\n for actuation of the valve assembly \n60\n between different operational positions.', 'Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.'] | ['1.', 'A system for use in a well, comprising:\na completion system having a screen assembly sized for deployment in a wellbore, the screen assembly comprising: a tubular member having a filter section and a non-permeable section; a base pipe disposed within the tubular member and creating an annulus therebetween, the base pipe having a perforated base pipe section radially inward of the non-permeable section and a non-perforated base pipe section radially inward of the filter section; a bulkhead extending between the base pipe and the tubular member at a location dividing the perforated base pipe section and the non-perforated base pipe section, the bulkhead having a passage therethrough of sufficient size to allow enough flow to the perforated base pipe section so as to avoid substantial pressure loss during gravel packing; and a valve assembly positioned in cooperation with the passage for selectively restricting flow through the passage, the valve assembly being actuatable via a signal applied to an actuator system of the valve assembly, wherein the completion system comprises a shunt tube system deployed externally of the tubular member, and wherein the valve assembly is coupled with a flow line extending to the shunt tube system, the valve assembly being actuatable via a pressure signal, the valve assembly comprising a dart oriented for selective engagement with the passage once the valve assembly is actuated via the pressure signal applied via the flow line, thus restricting flow through the bulkhead and through the perforated section of the base pipe.', '2.', 'The system as recited in claim 1, wherein the completion system comprises a plurality of screen assemblies.', '3.', 'The system as recited in claim 1, wherein the dart comprises an inflow control device (ICD).', '4.', 'The system as recited in claim 1, wherein the dart comprises a plug member positioned to plug the passage once the valve assembly is actuated.', '5.', 'The system as recited in claim 1, wherein the dart is moved into engagement with the passage via a spring upon application of sufficient pressure in the shunt tube system to cause release of the dart.', '6.', 'The system as recited in claim 1, wherein the dart is moved into engagement with the passage via application of sufficient pressure in the shunt tube system to cause release of the dart and then to shift the dart.', '7.', 'The system as recited in claim 1, wherein the valve assembly is actuatable via an electric signal applied to the actuator system.', '8.', 'The system as recited in claim 1, wherein the completion system comprises a backup actuation system.', '9.', 'The system as recited in claim 1, wherein the valve assembly comprises a lock mechanism.', '10.', 'The system as recited in claim 1, wherein the passage comprises a plurality of passages and the valve assembly comprises a plurality of darts corresponding with the plurality of passages.', '11.', 'A system, comprising:\na completion system having: a screen assembly sized for deployment in a borehole, the screen assembly comprising a tubular member having a filter section and a base pipe disposed in the tubular member; and a valve assembly positioned to control a fluid flow through a passage disposed within the screen assembly, the valve assembly being actuatable via a signal so as to change flow into the base pipe from a higher rate during a gravel packing operation to a lower rate during a subsequent production operation, wherein the completion system comprises a shunt tube system deployed externally of the tubular member, and wherein the signal comprises a pressure signal applied through the shunt tube system.', '12.', 'The system as recited in claim 11, wherein the valve assembly comprises a dart having an ICD which is selectively movable into the passage to reduce flow therethrough.', '13.', 'The system as recited in claim 11, wherein the valve assembly comprises a dart having a plug member which is selectively movable into the passage to block flow therethrough and to thus force a production flow through an ICD mounted in the base pipe.', '14.', 'The system as recited in claim 11, wherein the signal comprises a timed, electrical signal.', '15.', 'The system as recited in claim 11, wherein the signal comprises a pressure signal.', '16.', 'A method, comprising:\nproviding a well completion with a shunt tube system to facilitate a gravel packing operation;\nenabling a gravel pack carrier fluid to return through a base pipe of the well completion;\npositioning a valve assembly to restrict fluid flow into the base pipe following the gravel packing operation; and\nselectively actuating the valve assembly, via a signal, to restrict fluid flow into the base pipe,\nwherein the signal comprises a pressure signal applied through the shunt tube system, and\nwherein selectively actuating comprises actuating a pressure release mechanism to enable flow of the pressure signal from the shunt tube system to the valve assembly.'] | ['FIG.', '1 is a schematic illustration of an example of a completion system deployed in a wellbore, according to an embodiment of the disclosure;; FIG.', '2 is a schematic illustration similar to that of FIG.', '1', 'but following a gravel packing operation, according to an embodiment of the disclosure;; FIG. 3 is a schematic illustration similar to that of FIG.', '2 following initiation of production flow, according to an embodiment of the disclosure;; FIG.', '4A is a cross-sectional illustration showing operation of a valve assembly operable to control fluid flow with respect to the completion system, according to an embodiment of the disclosure;; FIG.', '4B is a cross-sectional illustration similar to that of FIG.', '4A', 'but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;; FIG.', '5A is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;; FIG.', '5B is a cross-sectional illustration similar to that of FIG.', '5A', 'but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;; FIG.', '6A is a cross-sectional illustration showing another embodiment of the valve assembly, according to an embodiment of the disclosure;; FIG.', '6B is an enlarged illustration of an example of a cutter mechanism which may be used in the valve assembly illustrated in FIG.', '6A, according to an embodiment of the disclosure;; FIG.', '6C is an enlarged illustration of an example of a locking mechanism which may be used in the valve assembly illustrated in FIG.', '6A, according to an embodiment of the disclosure;; FIG.', '6D is a cross-sectional illustration similar to that of FIG.', '6A but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;; FIG. 7 is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;; FIG.', '8A is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;; FIG.', '8B is a cross-sectional illustration similar to that of FIG.', '8A', 'but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;; FIG.', '8C is an enlarged illustration of an example of a retainer mechanism which may be used in the valve assembly illustrated in FIG.', '8A, according to an embodiment of the disclosure;; FIG.', '8D is an illustration similar to that of FIG.', '8C', 'but after release of the retainer mechanism, according to an embodiment of the disclosure;; FIG. 9 is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;; FIG.', '10A is a cross-sectional illustration of another embodiment of the valve assembly, according to an embodiment of the disclosure;; FIG.', '10B is a cross-sectional illustration similar to that of FIG.', '10A but showing the valve assembly in a different operational position, according to an embodiment of the disclosure;; FIG.', '10C is an enlarged illustration of an example of a retainer mechanism which may be used in the valve assembly illustrated in FIG.', '10A, according to an embodiment of the disclosure;; FIG.', '10D is an illustration similar to that of FIG.', '10C', 'but after release of the retainer mechanism, according to an embodiment of the disclosure;; FIG.', '11A is an illustration of another embodiment of the valve assembly having a backup triggering system for actuating the valve assembly, according to an embodiment of the disclosure;; FIG.', '11B is an illustration of the backup triggering system from a different angle, according to an embodiment of the disclosure;; FIG.', '11C is an illustration of the backup triggering system from a different angle, according to an embodiment of the disclosure;; FIG.', '11D is a cross-sectional illustration of the backup triggering system for actuating the valve assembly, according to an embodiment of the disclosure;; FIG.', '12 is a schematic illustration showing another application of the valve assembly, according to an embodiment of the disclosure;; FIG.', '13 is a schematic illustration showing another application of the valve assembly, according to an embodiment of the disclosure;; FIG.', '14 is a schematic illustration showing another embodiment of an actuator system of the valve assembly, according to an embodiment of the disclosure;; FIG.', '15 is a cross-sectional illustration showing another embodiment of an actuator system usable in various embodiments of the valve assembly, according to an embodiment of the disclosure;; FIG.', '16 is a cross-sectional illustration similar to that of FIG.', '15', 'but showing the actuator system in a different operational position, according to an embodiment of the disclosure;', '; FIG.', '17 is a schematic illustration of another example of a completion system deployed in a wellbore, according to an embodiment of the disclosure;; FIG.', '18A is a schematic illustration of another example of a completion system deployed in a wellbore, according to an embodiment of the disclosure; and; FIG.', '18B is a schematic illustration similar to that of FIG.', '18A but in a different operational position, according to an embodiment of the disclosure.'] |
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US11112296 | Downhole tool string weight measurement and sensor validation | Apr 12, 2019 | Alejandro Camacho Cardenas | Schlumberger Technology Corporation | NPL References not found. | 2274339; February 1942; Loomis; 3374341; March 1968; Klotz; 8280636; October 2, 2012; Newman; 20170370203; December 28, 2017; Hadi; 20190012411; January 10, 2019; Camacho Cardenas; 20190264545; August 29, 2019; Camacho Cardenas et al. | Foreign Citations not found. | ['Methods and systems for performing weigh measurement of a downhole tool string and validating accuracy of corresponding sensors.', 'A method may include commencing operation of a processing device to control operations at an oil and gas wellsite.', 'The processing device may then output a movement control command to a lifting device to cause a downhole tool string to move in accordance to the movement control command, receive an acceleration measurement of the downhole tool string, and determine a weight measurement of the downhole tool string based on the movement control command and the acceleration measurement.'] | ['Description\n\n\n\n\n\n\nBACKGROUND OF THE DISCLOSURE\n \nWells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other materials that are trapped in subterranean formations.', 'Well construction operations (e.g., drilling operations) may be performed at a wellsite by a drilling system having various automated surface and subterranean equipment operating in a coordinated manner.', 'For example, a drive mechanism, such as a top drive or rotary table located at a wellsite surface, can be utilized to rotate and advance a drill string into a subterranean formation to drill a wellbore.', 'The drill string may include a plurality of drill pipes coupled together and terminating with a drill bit.', 'Length of the drill string may be increased by adding additional drill pipes while depth of the wellbore increases.', 'Drilling fluid may be pumped from the wellsite surface down through the drill string to the drill bit.', 'The drilling fluid lubricates and cools the drill bit, and carries drill cuttings from the wellbore back to the wellsite surface.', 'The drilling fluid returning to the surface may then be cleaned and again pumped through the drill string.', 'The equipment of the drilling system may be grouped into various subsystems, wherein each subsystem performs a different operation controlled by a corresponding local and/or a remotely located controller.', 'The wellsite equipment is typically monitored and controlled from a control center located at the wellsite surface.', 'A typical control center houses a control station operable to receive sensor measurements from various sensors associated with the wellsite equipment and permit monitoring of the wellsite equipment by the wellsite control station and/or by human wellsite operators.', 'The wellsite equipment may then be automatically controlled by the wellsite control station or manually by the wellsite operator based on the sensor measurements.', 'Because the various pieces of well site equipment often operate in a coordinated manner, accuracy of sensor measurements generated or facilitated by various sensors is vital to achieve safe and efficient operation of such equipment.', 'Sensors can undergo physical changes, lose calibration, or fail over time, resulting in a slow drift in sensor measurements.', 'An inaccurate sensor (e.g., weight sensor) may cause improper operation (e.g., failure in mechanization, failure in synchronization) not just of the piece of equipment comprising the sensor, but other equipment as well.', 'Inaccurate sensor measurements (e.g., hook load measurement) can also cause improper decision making by the control station and/or wellsite operators.', 'Furthermore, inaccurate sensor measurements can lead to loss of productivity, higher consumption of resources, and higher maintenance costs.', 'One way of ensuring accuracy of sensor measurements is to calibrate sensors on a regular basis.', 'However, a typical calibration process involves removing the sensor from the associated piece of wellsite equipment and connecting the sensor to a testing device to be checked against a reference.', 'Because knowledge that a sensor is out of calibration is acquired after calibration, calibration does not validate accuracy of sensor measurements while the sensor is installed in association with the equipment.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces a system including an acceleration sensor and a processing device.', 'The acceleration sensor is disposed in association with a piece of equipment at an oil and gas wellsite and facilitates determination of an acceleration measurement of a downhole tool string.', 'The processing device includes a processor and a memory storing computer program code.', 'The processing device outputs a movement control command to a lifting device to cause the downhole tool string to move in accordance to the movement control command, receives the acceleration measurement, and determines a weight measurement of the downhole tool string based on the movement control command and the acceleration measurement.', 'The present disclosure also introduces a method including commencing operation of a processing device to control operations at an oil and gas wellsite.', 'The processing device outputs a movement control command to a lifting device to cause a downhole tool string to move in accordance to the movement control command, receives an acceleration measurement of the downhole tool string, and determines a weight measurement of the downhole tool string based on the movement control command and the acceleration measurement.', 'The present disclosure also introduces a method including commencing operation of a processing device to control operations at an oil and gas wellsite, in which the processing device outputs a current movement control command to a lifting device to cause a downhole tool string to move, receives a current acceleration measurement of the downhole tool string, compares the current movement control command and the current acceleration measurement to recorded past movement control commands and corresponding recorded past acceleration measurements, and determines a current weight measurement of the tool string to be equal to a recorded past weight measurement associated with closest recorded movement control command and corresponding recorded acceleration measurement.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIGS.', '4-6\n are graphs related to one or more aspects of the present disclosure.', 'FIG.', '7\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Systems and methods (e.g., processes, operations) according to one or more aspects of the present disclosure may be utilized or otherwise implemented in association with an automated well construction system at an oil and gas wellsite, such as for constructing a wellbore to obtain hydrocarbons (e.g., oil and/or gas) from a subterranean formation.', 'However, one or more aspects of the present disclosure may be utilized or otherwise implemented in association with other automated systems in the oil and gas industry and other industries.', 'For example, one or more aspects of the present disclosure may be implemented in association with wellsite systems for performing fracturing, cementing, acidizing, chemical injecting, and/or water jet cutting operations, among other examples.', 'One or more aspects of the present disclosure may also be implemented in association with mining sites, building construction sites, and/or other work sites where automated machines or equipment are utilized.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of a well construction system \n100\n according to one or more aspects of the present disclosure.', 'The well construction system \n100\n represents an example environment in which one or more aspects of the present disclosure described below may be implemented.', 'The well construction system \n100\n may be or comprise a drill rig and associated wellsite equipment.', 'Although the well construction system \n100\n is depicted as an onshore implementation, the aspects described below are also applicable to offshore implementations.', 'The well construction system \n100\n is depicted in relation to a wellbore \n102\n formed by rotary and/or directional drilling from a wellsite surface \n104\n and extending into a subterranean formation \n106\n.', 'The well construction system \n100\n includes surface equipment \n110\n located at the wellsite surface \n104\n and a drill string \n120\n suspended within the wellbore \n102\n.', 'The surface equipment \n110\n may include a mast, a derrick, and/or another support structure \n112\n disposed over a rig floor \n114\n.', 'The drill string \n120\n may be suspended within the wellbore \n102\n from the support structure \n112\n.', 'The support structure \n112\n and the rig floor \n114\n are collectively supported over the wellbore \n102\n by legs and/or other support structures (not shown).', 'The drill string \n120\n may comprise a bottom-hole assembly (BHA) \n124\n and means \n122\n for conveying the BHA \n124\n within the wellbore \n102\n.', 'The conveyance means \n122\n may comprise drill pipe, heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough logging condition (TLC) pipe, coiled tubing, and/or other means for conveying the BHA \n124\n within the wellbore \n102\n.', 'A downhole end of the BHA \n124\n may include or be coupled to a drill bit \n126\n.', 'Rotation of the drill bit \n126\n and the weight of the drill string \n120\n collectively operate to form the wellbore \n102\n.', 'The drill bit \n126\n may be rotated from the wellsite surface \n104\n and/or via a downhole mud motor (not shown) connected with the drill bit \n126\n.', 'The BHA \n124\n may also include various downhole tools \n180\n, \n182\n, \n184\n.\n \nOne or more of the downhole tools \n180\n, \n182\n, \n184\n may be or comprise an MWD or LWD tool comprising a sensor package \n186\n operable for the acquisition of measurement data pertaining to the BHA \n124\n, the wellbore \n102\n, and/or the formation \n106\n.', 'One or more of the downhole tools \n180\n, \n182\n, \n184\n and/or another portion of the BHA \n124\n may also comprise a telemetry device \n187\n operable for communication with the surface equipment \n110\n, such as via mud-pulse telemetry.', 'One or more of the downhole tools \n180\n, \n182\n, \n184\n and/or another portion of the BHA \n124\n may also comprise a downhole processing device \n188\n operable to receive, process, and/or store information received from the surface equipment \n110\n, the sensor package \n186\n, and/or other portions of the BHA \n124\n.', 'The processing device \n188\n may also store executable computer programs (e.g., program code instructions), including for implementing one or more aspects of the operations described herein.', 'The support structure \n112\n may support a driver, such as a top drive \n116\n, operable to connect (perhaps indirectly) with an upper end of the drill string \n120\n, and to impart rotary motion \n117\n and vertical motion \n135\n to the drill string \n120\n, including the drill bit \n126\n.', 'However, another driver, such as a kelly and rotary table (neither shown), may be utilized instead of or in addition to the top drive \n116\n to impart the rotary motion \n117\n to the drill string \n120\n.', 'The top drive \n116\n and the connected drill string \n120\n may be suspended from the support structure \n112\n via a hoisting system or equipment, which may include a traveling block \n113\n, a crown block \n115\n, and a tubular lifting device, such as a draw works \n118\n storing a support cable or line \n123\n.', 'The crown block \n115\n may be connected to or otherwise supported by the support structure \n112\n, and the traveling block \n113\n may be coupled with the top drive \n116\n.', 'The draw works \n118\n may be mounted on or otherwise supported by the rig floor \n114\n.', 'The crown block \n115\n and traveling block \n113\n comprise pulleys or sheaves around which the support line \n123\n is reeved to operatively connect the crown block \n115\n, the traveling block \n113\n, and the draw works \n118\n (and perhaps an anchor).', 'The draw works \n118\n may thus selectively impart tension to the support line \n123\n to lift and lower the top drive \n116\n, resulting in the vertical motion \n135\n.', 'The draw works \n118\n may comprise a drum, a base, and a prime mover (e.g., an engine or motor) (not shown) operable to drive the drum to rotate and reel in the support line \n123\n, causing the traveling block \n113\n and the top drive \n116\n to move upward.', 'The draw works \n118\n may be operable to reel out the support line \n123\n via a controlled rotation of the drum, causing the traveling block \n113\n and the top drive \n116\n to move downward.', 'The top drive \n116\n may comprise a grabber, a swivel (neither shown), elevator links \n127\n terminating with an elevator \n129\n, and a drive shaft \n125\n operatively connected with a prime mover (not shown), such as via a gear box or transmission (not shown).', 'The drive shaft \n125\n may be selectively coupled with the upper end of the drill string \n120\n and the prime mover may be selectively operated to rotate the drive shaft \n125\n and the drill string \n120\n coupled with the drive shaft \n125\n.', 'Hence, during drilling operations, the top drive \n116\n, in conjunction with operation of the draw works \n118\n, may advance the drill string \n120\n into the formation \n106\n to form the wellbore \n102\n.', 'The elevator links \n127\n and the elevator \n129\n of the top drive \n116\n may handle tubulars (e.g., drill pipes, drill collars, casing joints, etc.) that are not mechanically coupled to the drive shaft \n125\n.', 'For example, when the drill string \n120\n is being tripped into or out of the wellbore \n102\n, the elevator \n129\n may grasp the tubulars of the drill string \n120\n such that the tubulars may be raised and/or lowered via the hoisting equipment mechanically coupled to the top drive \n116\n.', 'The grabber may include a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft \n125\n.', 'The top drive \n116\n may have a guide system (not shown), such as rollers that track up and down a guide rail on the support structure \n112\n.', 'The guide system may aid in keeping the top drive \n116\n aligned with the wellbore \n102\n, and in preventing the top drive \n116\n from rotating during drilling by transferring reactive torque to the support structure \n112\n.', 'The well construction system \n100\n may further include a well control system or equipment for maintaining well pressure control.', 'For example, the drill string \n120\n may be conveyed within the wellbore \n102\n through various blowout preventer (BOP) equipment disposed at the wellsite surface \n104\n on top of the wellbore \n102\n and perhaps below the rig floor \n114\n.', 'The BOP equipment may be operable to control pressure within the wellbore \n102\n via a series of pressure barriers (e.g., rams) between the wellbore \n102\n and the wellsite surface \n104\n.', 'The BOP equipment may include a BOP stack \n130\n, an annular preventer \n132\n, and/or a rotating control device (RCD) \n138\n mounted above the annular preventer \n132\n.', 'The BOP equipment \n130\n, \n132\n, \n138\n may be mounted on top of a wellhead \n134\n.', 'The well control system may further include a BOP control unit \n137\n (i.e., a BOP closing unit) operatively connected with the BOP equipment \n130\n, \n132\n, \n138\n and operable to actuate, drive, operate or otherwise control the BOP equipment \n130\n, \n132\n, \n138\n.', 'The BOP control unit \n137\n may be or comprise a hydraulic fluid power unit fluidly connected with the BOP equipment \n130\n, \n132\n, \n138\n and selectively operable to hydraulically drive various portions (e.g., rams, valves, seals) of the BOP equipment \n130\n, \n132\n, \n138\n.', 'The well construction system \n100\n may further include a drilling fluid circulation system or equipment operable to circulate fluids between the surface equipment \n110\n and the drill bit \n126\n during drilling and other operations.', 'For example, the drilling fluid circulation system may be operable to inject a drilling fluid from the wellsite surface \n104\n into the wellbore \n102\n via an internal fluid passage \n121\n extending longitudinally through the drill string \n120\n.', 'The drilling fluid circulation system may comprise a pit, a tank, and/or other fluid container \n142\n holding the drilling fluid (i.e., mud) \n140\n, and a pump \n144\n operable to move the drilling fluid \n140\n from the container \n142\n into the fluid passage \n121\n of the drill string \n120\n via a fluid conduit \n146\n extending from the pump \n144\n to the top drive \n116\n and an internal passage extending through the top drive \n116\n.', 'The fluid conduit \n146\n may comprise one or more of a pump discharge line, a stand pipe, a rotary hose, and a gooseneck connected with a fluid inlet of the top drive \n116\n.', 'The pump \n144\n and the container \n142\n may be fluidly connected by a fluid conduit \n148\n, such as a suction line.', 'During drilling operations, the drilling fluid may continue to flow downhole through the internal passage \n121\n of the drill string \n120\n, as indicated by directional arrow \n157\n.', 'The drilling fluid may exit the BHA \n124\n via ports \n128\n in the drill bit \n126\n and then circulate uphole through an annular space \n108\n (“annulus”) of the wellbore \n102\n defined between an exterior of the drill string \n120\n and the wall of the wellbore \n102\n, such flow being indicated by directional arrows \n159\n.', 'In this manner, the drilling fluid lubricates the drill bit \n126\n and carries formation cuttings uphole to the wellsite surface \n104\n.', 'The returning drilling fluid may exit the annulus \n108\n via a bell nipple \n139\n, an RCD \n138\n, and/or a ported adapter \n136\n (e.g., a spool, cross adapter, a wing valve, etc.) located below one or more portions of the BOP stack \n130\n.', 'The drilling fluid exiting the annulus \n108\n via the bell nipple \n139\n may be directed toward drilling fluid reconditioning equipment \n170\n via a fluid conduit \n158\n (e.g., gravity return line) to be cleaned and/or reconditioned, as described below, prior to being returned to the container \n142\n for recirculation.', 'The drilling fluid exiting the annulus \n108\n via the RCD \n138\n may be directed into a fluid conduit \n150\n (e.g., a drilling pressure control line), and may pass through various wellsite equipment fluidly connected along the conduit \n150\n prior to being returned to the container \n142\n for recirculation.', 'For example, the drilling fluid may pass through a choke manifold \n152\n (e.g., a drilling pressure control choke manifold) and then through the drilling fluid reconditioning equipment \n170\n.', 'The choke manifold \n152\n may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow through and out of the choke manifold \n152\n.', 'Backpressure may be applied to the annulus \n108\n by variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold \n152\n.', 'The greater the restriction to flow through the choke manifold \n152\n, the greater the backpressure applied to the annulus \n108\n.', 'The drilling fluid exiting the annulus \n108\n via the ported adapter \n136\n may be directed into a fluid conduit \n154\n (e.g., rig choke line), and may pass through various equipment fluidly connected along the conduit \n154\n prior to being returned to the container \n142\n for recirculation.', 'For example, the drilling fluid may pass through a choke manifold \n156\n (e.g., a rig choke manifold, well control choke manifold) and then through the drilling fluid reconditioning equipment \n170\n.', 'The choke manifold \n156\n may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow through the choke manifold \n156\n.', 'Backpressure may be applied to the annulus \n108\n by variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold \n156\n.', 'Before being returned to the container \n142\n, the drilling fluid returning to the wellsite surface \n104\n may be cleaned and/or reconditioned via drilling fluid reconditioning equipment \n170\n, which may include one or more of liquid gas separators \n171\n, shale shakers \n172\n, and other drilling fluid cleaning equipment \n173\n.', 'The liquid gas separators \n171\n may remove formation gasses entrained in the drilling fluid discharged from the wellbore \n102\n and the shale shakers \n172\n may separate and remove solid particles \n141\n (e.g., drill cuttings) from the drilling fluid.', 'The drilling fluid reconditioning equipment \n170\n may further comprise other equipment \n173\n operable to remove additional gas and finer formation cuttings from the drilling fluid and/or modify physical properties or characteristics (e.g., rheology) of the drilling fluid.', 'For example, the drilling fluid reconditioning equipment \n170\n may include a degasser, a desander, a desilter, a centrifuge, a mud cleaner, and/or a decanter, among other examples.', 'Intermediate tanks/containers (not shown) may be utilized to hold the drilling fluid while the drilling fluid progresses through the various stages or portions \n171\n, \n172\n, \n173\n of the drilling fluid reconditioning equipment \n170\n.', 'The cleaned/reconditioned drilling fluid may be transferred to the fluid container \n142\n, the solid particles \n141\n removed from the drilling fluid may be transferred to a solids container \n143\n (e.g., a reserve pit), and/or the removed gas may be transferred to a flare stack \n174\n via a conduit \n175\n (e.g., a flare line) to be burned or to a container (not shown) for storage and removal from the wellsite.', 'The surface equipment \n110\n may include a tubular handling system or equipment operable to store, move, connect, and disconnect tubulars (e.g., drill pipes) to assemble and disassemble the conveyance means \n122\n of the drill string \n120\n during drilling operations.', 'For example, a catwalk \n151\n may be utilized to convey tubulars from a ground level, such as along the wellsite surface \n104\n, to the rig floor \n114\n, permitting the elevator \n129\n to grab and lift the tubulars above the wellbore \n102\n for connection with previously deployed tubulars.', 'The catwalk \n151\n may have a horizontal portion and an inclined portion that extends between the horizontal portion and the rig floor \n114\n.', 'The catwalk \n151\n may comprise a skate \n163\n movable along a groove (not shown) extending longitudinally along the horizontal and inclined portions of the catwalk \n151\n.', 'The skate \n163\n may be operable to convey (e.g., push) the tubulars along the catwalk \n151\n to the rig floor \n114\n.', 'The skate \n163\n may be driven along the groove by a drive system (not shown), such as a pulley system or a hydraulic system.', 'Additionally, one or more racks (not shown) may adjoin the horizontal portion of the catwalk \n151\n.', 'The racks may have a spinner unit for transferring tubulars to the groove of the catwalk \n151\n.', 'An iron roughneck \n165\n may be positioned on the rig floor \n114\n.', 'The iron roughneck \n165\n may comprise a torqueing portion \n167\n, such as may include a spinner and a torque wrench comprising a lower tong and an upper tong.', 'The torqueing portion \n167\n of the iron roughneck \n165\n may be moveable toward and at least partially around the drill string \n120\n, such as may permit the iron roughneck \n165\n to make up and break out connections of the drill string \n120\n.', 'The torqueing portion \n167\n may also be moveable away from the drill string \n120\n, such as may permit the iron roughneck \n165\n to move clear of the drill string \n120\n during drilling operations.', 'The spinner of the iron roughneck \n165\n may be utilized to apply low torque to make up and break out threaded connections between tubulars of the drill string \n120\n, and the torque wrench may be utilized to apply a higher torque to tighten and loosen the threaded connections.', 'A set of slips \n161\n may be located on the rig floor \n114\n, such as may accommodate therethrough the drill string \n120\n during tubular make up and break out operations and during the drilling operations.', 'The slips \n161\n may be in an open position during drilling operations to permit advancement of the drill string \n120\n, and in a closed position to clamp the upper end (e.g., uppermost tubular) of the drill string \n120\n to thereby suspend and prevent advancement of the drill string \n120\n within the wellbore \n102\n, such as during the make up and break out operations.', 'During drilling operations, the hoisting system lowers the drill string \n120\n while the top drive \n116\n rotates the drill string \n120\n to advance the drill string \n120\n downward within the wellbore \n102\n and into the formation \n106\n.', 'During the advancement of the drill string \n120\n, the slips \n161\n are in an open position, and the iron roughneck \n165\n is moved away or is otherwise clear of the drill string \n120\n.', 'When the upper end of the drill string \n120\n (i.e., upper end of the uppermost tubular of the drill string \n120\n) connected to the drive shaft \n125\n is near the slips \n161\n and/or the rig floor \n114\n, the top drive \n116\n ceases rotating and the slips \n161\n close to clamp the upper end of the drill string \n120\n.', 'The grabber of the top drive \n116\n then clamps the uppermost tubular connected to the drive shaft \n125\n, and the drive shaft \n125\n rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft \n125\n and the uppermost tubular.', 'The grabber of the top drive \n116\n may then release the uppermost tubular.', 'Multiple tubulars may be loaded on the rack of the catwalk \n151\n and individual tubulars may be transferred from the rack to the groove in the catwalk \n151\n, such as by the spinner unit.', 'The tubular positioned in the groove may be conveyed along the groove by the skate \n163\n until the box end of the tubular projects above the rig floor \n114\n.', 'The elevator \n129\n of the top drive \n116\n may then grasp the protruding box end, and the draw works \n118\n may be operated to lift the top drive \n116\n, the elevator \n129\n, and the new tubular.', 'The hoisting system then raises the top drive \n116\n, the elevator \n129\n, and the new tubular until the tubular is aligned with the upper portion of the drill string \n120\n clamped by the slips \n161\n.', 'The iron roughneck \n165\n is moved toward the drill string \n120\n, and the lower tong of the torqueing portion \n167\n clamps onto the upper end of the drill string \n120\n.', 'The spinning system threadedly connects the lower end (i.e., pin end) of the new tubular with the upper end (i.e., box end) of the drill string \n120\n.', 'The upper tong then clamps onto the new tubular and rotates with high torque to complete making up the connection with the drill string \n120\n.', 'In this manner, the new tubular becomes part of the drill string \n120\n.', 'The iron roughneck \n165\n then releases and moves clear of the drill string \n120\n.', 'The grabber of the top drive \n116\n may then clamp onto the drill string \n120\n.', 'The drive shaft \n125\n is brought into contact with the upper end of the drill string \n120\n (e.g., the box end of the uppermost tubular) and rotated to make up a connection between the drill string \n120\n and the drive shaft \n125\n.', 'The grabber then releases the drill string \n120\n, and the slips \n161\n are moved to the open position.', 'The drilling operations may then resume.', 'The tubular handling system may further include a pipe handling manipulator (PHM) \n160\n disposed in association with a vertical pipe rack \n162\n for storing tubulars \n111\n (or stands of two or three tubulars).', 'The vertical pipe rack \n162\n may comprise or support a fingerboard \n164\n defining a plurality of slots configured to support or otherwise hold the tubulars \n111\n within or above a setback platform or area \n166\n located adjacent to, above, or below the rig floor \n114\n.', 'The vertical pipe rack \n162\n may be connected with and supported by the support structure \n112\n or another portion of the well construction system \n100\n.', 'The fingerboard \n164\n/setback \n166\n provide storage (e.g., temporary storage) of tubulars \n111\n during various operations, such as during and between tripping out and tripping in the drill string \n120\n.', 'The PHM \n160\n may be operable to transfer the tubulars \n111\n between the fingerboard \n164\n/setback \n166\n and the drill string \n120\n (i.e., space above the suspended drill string \n120\n).', 'For example, the PHM \n160\n may include arms \n168\n terminating with clamps \n169\n, such as may be operable to grasp and/or clamp onto one of the tubulars \n111\n.', 'The arms \n168\n of the PHM \n160\n may extend and retract, and/or at least a portion of the PHM \n160\n may be rotatable and/or movable toward and away from the drill string \n120\n, such as may permit the PHM \n160\n to transfer the tubular \n111\n between the fingerboard \n164\n/setback \n166\n and the drill string \n120\n.', 'To trip out the drill string \n120\n, the top drive \n116\n is raised, the slips \n161\n are closed around the drill string \n120\n, and the elevator \n129\n is closed around the drill string \n120\n.', 'The grabber of the top drive \n116\n clamps the upper end of a tubular of the drill string \n120\n coupled to the drive shaft \n125\n.', 'The drive shaft \n125\n then rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft \n125\n and the drill string \n120\n.', 'The grabber of the top drive \n116\n then releases the tubular of the drill string \n120\n, and the drill string \n120\n is suspended by (at least in part) the elevator \n129\n.', 'The iron roughneck \n165\n is moved toward the drill string \n120\n.', 'The lower tong clamps onto a lower tubular below a connection of the drill string \n120\n, and the upper tong clamps onto an upper tubular above that connection.', 'The upper tong then rotates the upper tubular to provide a high torque to break out the connection between the upper and lower tubulars.', 'The spinning system then rotates the upper tubular to separate the upper and lower tubulars, such that the upper tubular is suspended above the rig floor \n114\n by the elevator \n129\n.', 'The iron roughneck \n165\n then releases the drill string \n120\n and moves clear of the drill string \n120\n.', 'The PHM \n160\n may then move toward the drill string \n120\n to grasp the tubular suspended from the elevator \n129\n.', 'The elevator \n129\n then opens to release the tubular.', 'The PHM \n160\n then moves away from the drill string \n120\n while grasping the tubular with the clamps \n169\n, places the tubular in the fingerboard \n164\n/setback \n166\n, and releases the tubular for storage.', 'This process is repeated until the intended length of drill string \n120\n is removed from the wellbore \n102\n.', 'The surface equipment \n110\n of the well construction system \n100\n may also comprise a control center \n190\n from which various portions of the well construction system \n100\n, such as the top drive \n116\n, the hoisting system, the tubular handling system, the drilling fluid circulation system, the well control system, the BHA \n124\n, among other examples, may be monitored and controlled.', 'The control center \n190\n may be located on the rig floor \n114\n or another location of the well construction system \n100\n, such as the wellsite surface \n104\n.', 'The control center \n190\n may comprise a facility \n191\n (e.g., a room, a cabin, a trailer, etc.) containing a control workstation \n197\n, which may be operated by a human wellsite operator \n195\n to monitor and control various wellsite equipment or portions of the well construction system \n100\n.', 'The control workstation \n197\n may comprise or be communicatively connected with a processing device \n192\n (e.g., a controller, a computer, etc.), such as may be operable to receive, process, and output information to monitor operations of and provide control to one or more portions of the well construction system \n100\n.', 'For example, the processing device \n192\n may be communicatively connected with the various surface and downhole equipment described herein, and may be operable to receive signals from and transmit signals to such equipment to perform various operations described herein.', 'The processing device \n192\n may store executable program code, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of methods and operations described herein.', 'The processing device \n192\n may be located within and/or outside of the facility \n191\n.', 'The control workstation \n197\n may be operable for entering or otherwise communicating control commands to the processing device \n192\n by the wellsite operator \n195\n, and for displaying or otherwise communicating information from the processing device \n192\n to the wellsite operator \n195\n.', 'The control workstation \n197\n may comprise a plurality of human-machine interface (HMI) devices, including one or more input devices \n194\n (e.g., a keyboard, a mouse, a joystick, a touchscreen, etc.) and one or more output devices \n196\n (e.g., a video monitor, a touchscreen, a printer, audio speakers, etc.).', 'Communication between the processing device \n192\n, the input and output devices \n194\n, \n196\n, and the various wellsite equipment may be via wired and/or wireless communication means.', 'However, for clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure.', 'Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in \nFIG.', '1\n.', 'Additionally, various equipment and/or subsystems of the well construction system \n100\n shown in \nFIG.', '1\n may include more or fewer components than as described above and depicted in \nFIG.', '1\n.', 'For example, various engines, motors, hydraulics, actuators, valves, and/or other components not explicitly described herein may be included in the well construction system \n100\n, and are within the scope of the present disclosure.', 'The present disclosure further provides various implementations of systems and/or methods for controlling one or more portions of the well construction system \n100\n. \nFIG.', '2\n is a schematic view of at least a portion of an example implementation of a monitoring and control system \n200\n for monitoring and controlling various equipment, portions, and subsystems of the well construction system \n100\n according to one or more aspects of the present disclosure.', 'The following description refers to \nFIGS.', '1 and 2\n, collectively.', 'The control system \n200\n may be in real-time communication with and utilized to monitor and/or control various portions, components, and equipment of the well construction system \n100\n described herein.', 'The equipment of the well construction system \n100\n may be grouped into several subsystems, each operable to perform a corresponding operation and/or a portion of the well construction operations described herein.', 'The subsystems may include a rig control (RC) system \n211\n, a fluid circulation (FC) system \n212\n, a managed pressure drilling control (MPDC) system \n213\n, a choke pressure control (CPC) system \n214\n, a well pressure control (WC) system \n215\n, and a closed-circuit television (CCTV) system \n216\n.', 'The control workstation \n197\n may be utilized to monitor, configure, control, and/or otherwise operate one or more of the well construction subsystems \n211\n-\n216\n.', 'The RC system \n211\n may include the support structure \n112\n, the tubular lifting device or system (e.g., the draw works \n118\n), drill string rotational system (e.g., the top drive \n116\n and/or the rotary table and kelly), the slips \n161\n, the tubular handling system or equipment (e.g., the catwalk \n151\n, the PHM \n160\n, the setback \n166\n, and the iron roughneck \n165\n), electrical generators, and other equipment.', 'Accordingly, the RC system \n211\n may perform power generation controls and drill pipe handling, hoisting, and rotation operations.', 'The RC system \n211\n may also serve as a support platform for drilling equipment and staging ground for rig operations, such as connection make up and break out operations described above.', 'The FC system \n212\n may include the drilling fluid \n140\n, the pumps \n144\n, drilling fluid loading equipment, the drilling fluid reconditioning equipment \n170\n, the flare stack \n174\n, and/or other fluid control equipment.', 'Accordingly, the FC system \n212\n may perform fluid operations of the well construction system \n100\n.', 'The MPDC system \n213\n may include the RCD \n138\n, the choke manifold \n152\n, downhole pressure sensors \n186\n, and/or other equipment.', 'The CPC system \n214\n may comprise the choke manifold \n156\n, and/or other equipment, and the WC system \n215\n may comprise the BOP equipment \n130\n, \n132\n, \n138\n, the BOP control unit \n137\n, and a BOP control station (not shown) for controlling the BOP control unit \n137\n.', 'The CCTV system \n216\n may include the video cameras (not shown) and corresponding actuators (e.g., motors) for moving or otherwise controlling direction of the video cameras.', 'The CCTV system \n216\n may be utilized to capture real-time video of various portions or subsystems \n211\n-\n215\n of the well construction system \n100\n and display video signals from the video cameras on the video output devices \n196\n to display in real-time the various portions or subsystems \n211\n-\n215\n.', 'Each of the well construction subsystems \n211\n-\n216\n may further comprise various communication equipment (e.g., modems, network interface cards, etc.) and communication conductors (e.g., cables), communicatively connecting the equipment (e.g., sensors and actuators) of each subsystem \n211\n-\n216\n with the control workstation \n197\n and/or other equipment.', 'Although the wellsite equipment listed above and shown in \nFIG.', '1\n is associated with certain wellsite subsystems \n211\n-\n216\n, such associations are merely examples that are not intended to limit or prevent such wellsite equipment from being associated with two or more wellsite subsystems \n211\n-\n216\n and/or different wellsite subsystems \n211\n-\n216\n.', 'The control system \n200\n may also include various local controllers \n221\n-\n226\n associated with corresponding subsystems \n211\n-\n216\n and/or individual pieces of equipment of the well construction system \n100\n.', 'As described above, each well construction subsystem \n211\n-\n216\n includes various wellsite equipment comprising corresponding actuators \n241\n-\n246\n for performing operations of the well construction system \n100\n.', 'Each subsystem \n211\n-\n216\n further includes various sensors \n231\n-\n236\n operable to generate sensor data indicative of operational performance and/or status of the wellsite equipment of each subsystem \n211\n-\n216\n.', 'Although the sensors \n231\n-\n236\n and actuators \n241\n-\n246\n are each shown as a single block, it is to be understood that each sensor \n231\n-\n236\n and actuator \n241\n-\n246\n may be or comprise a plurality of sensors and actuators, whereby each actuator performs a corresponding action of a piece of equipment or subsystem \n211\n-\n216\n and each sensor generates corresponding sensor data indicative of the action performed by a corresponding actuator or of other operational parameter of the piece of equipment or subsystem \n211\n-\n216\n.', 'The local controllers \n221\n-\n226\n, the sensors \n231\n-\n236\n, and the actuators \n241\n-\n246\n may be communicatively connected with a processing device \n202\n.', 'For example, the local controllers \n221\n-\n226\n may be in communication with the sensors \n231\n-\n236\n and actuators \n241\n-\n246\n of the corresponding subsystems \n211\n-\n216\n via local communication networks (e.g., field buses, not shown) and the processing device \n202\n may be in communication with the subsystems \n211\n-\n216\n via a communication network \n209\n (e.g., data bus, a wide-area-network (WAN), a local-area-network (LAN), etc.).', 'The sensor data (e.g., electronic signals, information, and/or measurements, etc.) generated by the sensors \n231\n-\n236\n of the subsystems \n211\n-\n216\n may be made available for use by processing device \n202\n and/or the local controllers \n221\n-\n226\n.', 'Similarly, control commands (e.g., signals, information, etc.) generated by the processing device \n202\n and/or the local controllers \n221\n-\n226\n may be automatically communicated to the various actuators \n241\n-\n246\n of the subsystems \n211\n-\n216\n, perhaps pursuant to predetermined programming, such as to facilitate well construction operations and/or other operations described herein.', 'The processing device \n202\n may be or comprise the processing device \n192\n shown in \nFIG.', '1\n.', 'Accordingly, the processing device \n202\n may be communicatively connected with or form a portion of the workstation \n197\n and/or may be at least partially located within the control center \n190\n.', 'The sensors \n231\n-\n236\n and actuators \n241\n-\n246\n may be monitored and/or controlled by the processing device \n202\n.', 'For example, the processing device \n202\n may be operable to receive the sensor data from the sensors \n231\n-\n236\n of the wellsite subsystems \n211\n-\n216\n in real-time, and to provide real-time control commands to the actuators \n241\n-\n246\n of the subsystems \n211\n-\n216\n based on the received sensor data.', 'However, certain operations of the actuators \n241\n-\n246\n may be controlled by the local controllers \n221\n-\n226\n, which may control the actuators \n241\n-\n246\n based on sensor data received from the sensors \n231\n-\n236\n and/or based on control commands received from the processing device \n202\n.', 'The processing devices \n188\n, \n192\n, \n202\n, the local controllers \n221\n-\n226\n, and other controllers or processing devices of the well construction system \n100\n may be operable to receive program code instructions and/or sensor data from sensors (e.g., sensors \n231\n-\n236\n), process such information, and/or generate control commands (i.e., control signals or information) to operate controllable equipment (e.g., actuators \n241\n-\n246\n) of the well construction system \n100\n.', 'Accordingly, the processing devices \n188\n, \n192\n, \n202\n, the local controllers \n221\n-\n226\n, and other controllers or processing devices of the well construction system \n100\n may individually or collectively be referred to hereinafter as equipment controllers.', 'Equipment controllers within the scope of the present disclosure can include, for example, programmable logic controllers (PLCs), industrial computers (IPCs), personal computers (PCs), soft PLCs, variable frequency drives (VFDs) and/or other controllers or processing devices operable to receive sensor data and/or control commands and cause operation of controllable equipment based on such sensor data and/or control commands.', 'The various pieces of wellsite equipment described above and shown in \nFIGS.', '1 and 2\n may each comprise one or more hydraulic and/or electrical actuators, which when actuated, may cause corresponding components or portions of the piece of equipment to perform intended actions (e.g., work, tasks, movements, operations, etc.).', 'Each piece of equipment may further comprise a plurality of sensors, whereby one or more sensors may be associated with a corresponding actuator or another component of the piece of equipment and communicatively connected with an equipment controller.', 'Each sensor may be operable to generate sensor data (e.g., electrical sensor signals or measurements) indicative of an operational (e.g., mechanical, physical) status of the corresponding actuator or component, thereby permitting the operational status of the actuator to be monitored by the equipment controller.', 'The sensor data may be utilized by the equipment controller as feedback data, permitting operational control of the piece of equipment and coordination with other equipment.', 'Such sensor data may be indicative of performance of each individual actuator and, collectively, of the entire piece of wellsite equipment.', 'The present disclosure is further directed to systems and processes for determining sensor measurements and validating or otherwise determining accuracy (i.e., quality) of such sensor measurements in real-time while the sensors are utilized in the field (e.g., at an oil and gas wellsite).', 'Determining sensor measurements may include deducing (e.g., interpolating, comparing) such sensor measurements based on control commands (i.e., control signals or information) and sensor measurements (i.e., signals or information) indicative of actions (e.g., movements, physical operations) and/or other operational parameters (e.g., pressure, temperature, weight, etc.) that are caused by such control commands.', 'Thus, determining sensor measurements may include deducing sensor measurements based on control commands and other sensor measurements caused by such control commands.', 'Accuracy of the deduced sensor measurements may be determined by comparing such deduced sensor measurements to detected (e.g., actually measured by a sensor) sensor measurements.', 'Relative differences or changes between the deduced sensor measurements and the detected sensor measurements may then be established and/or analyzed based on such comparisons, thereby permitting one or both of the deduced sensor measurements and the detected sensor measurements to be determined (e.g., validated, confirmed, deemed) as accurate within a certain degree of confidence.', 'The deduced sensor measurements and the detected sensor measurements may be indicative of corresponding operational parameters (e.g., position, distance, speed, acceleration, weight, force, pressure, event status, etc.) performed or caused by automated equipment.', 'The deduced sensor measurements, the detected sensor measurements, and the operational parameters may be related to each other through context of common or related equipment and/or operations.', 'Accuracy of sensor measurements may be determined in real-time during wellsite operations by a wellsite monitoring and control system, such as the control system \n200\n, communicatively connected with or otherwise operable to receive and compare or otherwise analyze the deduced sensor measurements and/or detected sensor measurements.', 'The control system may help identify anomalies among the sensor measurements during early stages before the sensor measurements degrade further.', 'The control system may compensate for the identified anomalies thereby improving the quality of the deduced and detected sensor measurements, both for real-time use during wellsite operations and for post collection data analysis.', 'The control system may also facilitate improved management of sensors and their state of health.\n \nFIG.', '3\n is a schematic view of at least a portion of an example implementation of a drill string hoisting system \n300\n operable to support and lift individual tubulars \n111\n and a drill string \n120\n according to one or more aspects of the present disclosure.', 'The drill string hoisting system \n300\n may form a portion of or operate in conjunction with the well construction system \n100\n shown in \nFIG.', '1\n and be operable to perform at least a portion of the processes described above in association with \nFIG.', '1\n.', 'The drill string hoisting system \n300\n may, thus, comprise one or more features of the well construction system \n100\n, including where indicated by the same numerals.', 'The drill string hoisting system \n300\n may be monitored and controlled by the control system \n200\n shown in \nFIG.', '2\n.', 'Accordingly, the following description refers to \nFIGS.', '1-3\n, collectively.', 'The drill string hoisting system \n300\n may comprise a top drive \n116\n supported by a traveling block \n113\n operatively connected with and collectively raised by a lifting device, such as a draw works \n118\n via a support line \n123\n.', 'The traveling block \n113\n may comprise a sheave \n303\n connected to a connection block \n305\n and reeved to the stationary block \n115\n via the support line \n123\n.', 'The top drive \n116\n may be coupled with the travelling block \n113\n via a plurality (e.g., two, four) of top drive tie rods or links \n308\n extending between the connection block \n305\n and the top drive \n116\n.', 'The support line \n123\n may be stored on a storage reel \n310\n and tied down by a deadline anchor \n312\n.', 'The support line \n123\n may also or instead be stored on a spool \n314\n of the draw works \n118\n.', 'An elevator \n129\n configured to couple with a box end of a single tubular \n111\n or an upper end (i.e., box end) of the drill string \n120\n may be connected with the top drive \n116\n via elevator links \n127\n.', 'As described above, a motor or another rotary actuator (not shown) of the draw works \n118\n may be operated by a processing device, such as the processing device \n202\n, to rotate the spool \n314\n to wind or unwind the support line \n123\n to lift or lower the top drive \n116\n and, thus, the individual tubulars \n111\n or drill string \n120\n during tubular running and drilling operations.', 'The drill string hoisting system \n300\n may comprise a plurality of sensors \n302\n, \n304\n, \n306\n each operable to generate sensor signals or information that may be indicative of or operable to facilitate determination of sensor measurements of operational parameters of equipment associated with the sensors \n302\n, \n304\n, \n306\n.', 'For example, the drill string hoisting system \n300\n may comprise a plurality of acceleration sensors \n304\n (e.g., strain gauge accelerometers, piezoelectric vibration sensors, etc.), each operable to generate a sensor signal indicative of or operable to facilitate determination of acceleration measurement of the drill string \n120\n.', 'The acceleration sensors \n304\n may be disposed or installed in association with, for example, the travelling block \n113\n, the top drive links \n308\n, the top drive \n116\n, the elevator links \n127\n, and/or the elevator \n129\n.', 'One or more sensors of the sensor package \n186\n of the downhole tool \n180\n may be or comprise an acceleration sensor \n304\n.', 'The drill string hoisting system \n300\n may further comprise one or more rotational position sensors \n306\n, each operable to generate a sensor signal indicative of or operable to facilitate determination of rotational position measurements of the spool \n314\n of the draw works \n118\n.', 'The rotational position sensors \n306\n may be disposed or installed in association with, for example, the motor or a rotational shaft of the draw works \n118\n.', 'The rotational position measurements may be indicative of block position, which may be or comprise position of a traveling block \n113\n or another portion of the drill string hoisting system \n300\n (e.g., top drive \n116\n) supported by the traveling block \n113\n.', 'The rotational position measurements may be further indicative of rotational speed of the spool \n314\n and, thus, linear speed of the traveling block \n113\n and of the drill string \n120\n.', 'The rotational position measurements may be also be indicative of rotational acceleration of the spool \n314\n and, thus, linear acceleration of the traveling block \n113\n and of the drill string \n120\n.', 'The sensors \n306\n may be or comprise, for example, encoders, rotary potentiometers, and rotary variable-differential transformers (RVDTs).', 'Accordingly, when the draw works \n118\n is operated to lift or otherwise move the travelling block \n113\n and the drill string \n120\n, such as during tubular running and drilling operations, one or more of the acceleration sensors \n304\n and/or rotational position sensors \n306\n may each generate a sensor signal or information indicative of or operable to facilitate determination of acceleration measurement of the drill string \n120\n.', 'The drill string hoisting system \n300\n may further comprise a plurality of weight sensors \n302\n, each operable to generate a sensor signal or information indicative of or operable to facilitate determination of weight measurement of the drill string \n120\n supported by the drill string hoisting system \n300\n.', 'The weight sensors \n302\n may be disposed or installed in association with the top drive links \n308\n, the elevator links \n127\n, the deadline anchor \n312\n, and/or other portions of the drill string hoisting system \n300\n.', 'Each weight sensor \n302\n may be or comprise a load sensor (e.g., a load cell, a strain gauge, etc.) operable to generate a sensor signal indicative of or operable to facilitate determination of tension measurement and, thus, weight measurement of members supported by the support line \n123\n, the links \n308\n, and/or the elevator links \n127\n.', 'Thus, when the draw works \n118\n is operated to lift or otherwise move the drill string \n120\n, such as during tubular running and drilling operations, weight measurement of the drill string \n120\n may be determined.', 'The weight measurement of the drill string \n120\n may be or comprise the hook load of the hoisting system \n300\n determined based on weight measurements facilitated by one or more of the weight sensors \n302\n.', 'The weight measurement of the drill string \n120\n determined based on the weight sensors \n302\n may be referred to as a “detected weight measurement,” as such weight measurement was actually detected (i.e., sensed) based on weight sensor signals generated by the weight sensors \n302\n.', 'A processing device, such as the processing device \n202\n, may be operated or caused to generate or otherwise output a movement control command (i.e., signal) to the draw works \n118\n of the drill string hoisting system \n300\n to lift or otherwise cause the drill string \n120\n to move in accordance to the movement control command.', 'During wellsite operations, while each movement control command is outputted and the drill string hoisting system \n300\n moves the drill string \n120\n, the processing device may receive and record to a database the outputted movement control commands and the detected position measurements, weight measurements, and/or acceleration measurements.\n \nFIG.', '4\n is a graph \n400\n showing example profiles of several control commands and operational parameters, including movement control commands \n402\n and sensor measurements \n404\n, \n406\n, \n408\n generated by corresponding sensors disposed in association with one or more pieces of the drill string hoisting system \n300\n shown in \nFIG.', '3\n.', 'The movement control commands \n402\n and sensor measurements \n404\n, \n406\n, \n408\n are plotted along the vertical axis, with respect to time, which is plotted along the horizontal axis.', 'The sensor measurements \n404\n may be or comprise detected weight measurements \n404\n, the sensor measurements \n406\n may be or comprise block position (e.g., traveling block \n113\n position, top drive \n116\n position, etc.)', 'measurements \n406\n (shown in dashed lines for clarity), and the sensor measurements \n408\n may be or comprise drill string acceleration measurements \n408\n.', 'The movement control commands \n402\n and sensor measurements \n404\n, \n406\n, \n408\n shown in graph \n400\n correspond to a period of time during drill string break out operations during which the drill string \n120\n is disassembled.', 'The profile of the movement control commands \n402\n indicate that the processing device outputted the movement control commands \n402\n, thereby causing the draw works \n118\n to lift the travelling block \n113\n and the drill string \n120\n, then to lower the traveling block \n113\n after the uppermost tubular \n111\n of the drill string \n120\n is disconnected, and then to lift the travelling block \n113\n and the drill string \n120\n again after the drill string \n120\n is connected with the elevator \n129\n.', 'The detected weight measurements \n404\n indicate a decrease in the weight of the drill string \n120\n after the uppermost tubular \n111\n is disconnected from the drill string \n120\n.', 'The block position measurements \n406\n indicate a progressive upward movement of the travelling block \n113\n and the drill string \n120\n, no movement of the drill string \n120\n when the uppermost tubular \n111\n of the drill string \n120\n is being disconnected, and downward movement of the travelling block \n113\n after the uppermost tubular \n111\n is disconnected.', 'The drill string acceleration measurements \n408\n indicate an upward accelerations of the drill string \n120\n for a period of time when the draw works \n118\n is commanded to operate via the movement control command \n402\n until the speed of the drill string \n120\n reaches steady state, at which time no acceleration is detected.', 'As can be seen in graph \n400\n, the later one of the acceleration measurements \n408\n is greater as the weight of the drill string decreases and the later of the movement control commands \n402\n remains the same.', 'During wellsite operations, while each movement control command \n402\n is outputted and the drill string hoisting system \n300\n moves the drill string \n120\n, the processing device may receive and record to a database the outputted movement control commands \n402\n, the detected weight measurements \n404\n, the position measurements \n406\n, and the acceleration measurements \n408\n in association with each other.', 'The database may thus comprise the outputted movement control commands, the detected weight measurements recorded at a time when (or before) each movement control command was outputted, and the acceleration measurements recorded when the drill string was accelerating after each movement control command was outputted.', 'Such movement control commands, detected weight measurements, and acceleration measurements correspond with one another and, thus, may be recorded in or as part of the database in association with each other.', 'The processing device may record the outputted movement control commands \n402\n and sensor measurements \n404\n, \n406\n, \n408\n for a predetermined period of time, for a plurality of jobs, and/or from different drill rigs to form a database of outputted movement control commands \n404\n and corresponding sensor measurements \n404\n, \n406\n, \n408\n.', 'The movement control commands \n402\n outputted by the processing device to the draw works \n118\n and/or other portions of the drill string hoisting system \n300\n may cause the drill string \n120\n to be moved up and/or down in a predetermined manner while the acceleration response of the drill string \n120\n is measured.', 'The movement control commands \n402\n may cause the drill string \n120\n to be moved in small or large displacements, at small or large speeds, and/or at small or large accelerations.', 'The movement control commands \n402\n may comprise a standard move control command (e.g., causing a ramp up or ramp down of the drill string \n120\n) that is part of an existing rig activity or operation (e.g., drilling, tripping) or a special move control command (e.g., causing intermittent movements of the drill string \n120\n) that is embedded in an existing rig activity or operation.', 'The movement control commands \n402\n may comprise a special move control command (e.g., causing alternating or random movements of the drill string \n120\n) that is not part of an existing rig activity or operation and whose sole purpose is to determine the weight of the drill string \n120\n.', 'Because the movement control commands \n402\n are inputted to the draw works \n118\n and/or other portions of the drill string hoisting system \n300\n, the movement control commands \n402', 'may also or instead be referred to as movement control inputs.', 'After a database of outputted movement control commands \n404\n and corresponding sensor measurements \n404\n, \n406\n, \n408\n is created, a processing device may periodically, continually, and/or in real-time during current wellsite operations compare or otherwise analyze the recorded movement control commands \n404\n and drill string acceleration measurements \n408\n to deduce or otherwise indirectly determine a current weight measurement of the drill string \n120\n based on a current movement control command \n404\n and acceleration measurement \n408\n, without receiving or otherwise utilizing a current detected weight measurement \n404\n.', 'The weight measurement of the drill string \n120\n determined based on the current movement control command \n404\n and acceleration measurement \n408\n may be referred to as a “deduced weight measurement,” as such weight measurement was deduced or indirectly determined based on current and recorded movement control commands \n404\n and acceleration measurements \n408\n.', 'For example, the processing device may determine a deduced weight measurement of the downhole drill string \n120\n by searching the database for a recorded movement control command \n402\n and a corresponding recorded acceleration measurement \n408\n that are closest to a current movement control command \n402\n and a corresponding current acceleration measurement \n408\n, and then choosing the deduced weight measurement to be equal to the recorded weight measurement associated with the closest found recorded movement control command \n402\n and corresponding recorded acceleration measurement \n408\n.\n \nFIG.', '5\n is a graph \n410\n showing portions of example profiles of several current and recorded control commands and operational parameters, including of control commands and operational profiles shown in \nFIG.', '4\n, including where indicated by the same numerals.', 'The control commands and acceleration measurements are plotted along the vertical axis, with respect to time, which is plotted along the horizontal axis.', 'The graph \n410\n shows current and recorded movement control commands \n402\n, \n412\n, respectively, and current and recorded acceleration measurements \n408\n, \n418\n, respectively, generated by corresponding sensors disposed in association with one or more pieces of the drill string hoisting system \n300\n shown in \nFIG.', '3\n.', 'Accordingly, the following description refers to \nFIGS.', '3-5\n, collectively.', 'The recorded movement control commands \n412\n and the corresponding recorded acceleration measurements \n418\n are the same or substantially similar to the current movement control commands \n402\n and the corresponding current acceleration measurements \n408\n, respectively.', 'A deduced weight measurement \n424\n (shown in dashed lines for clarity) may therefore be deduced (e.g., inferred, predicted) and, thus, chosen to be equal to a recorded detected weight measurement \n414\n corresponding to the closest recorded movement control command \n412\n and corresponding recorded acceleration measurement \n418\n.', 'Accordingly, a current weight of the drill string \n120\n may be deduced based on the current acceleration measurement \n408\n facilitated by the acceleration sensors \n304\n and/or position sensors \n306\n and the current movement control command \n402\n, when analyzed in the context of recorded acceleration measurements \n418\n and recorded movement control commands \n412\n, and without relying on or utilizing the weight sensors \n302\n and the current detected weight measurement \n404\n.', 'A processing device, such as the processing device \n202\n, may be further operable to receive, record, and/or compare or otherwise analyze the detected and deduced weight measurements \n404\n, \n424\n periodically, continually, and/or in real-time during wellsite or other operations.', 'For example, the processing device may compare the detected and deduced weight measurements \n404\n, \n424\n with each other.', 'The processing device may then determine accuracy of the detected and deduced weight measurements \n404\n, \n424\n based on such comparison.', 'For example, if the detected and deduced weight measurements \n404\n, \n424\n are substantially similar or match each other, then the detected and deduced weight measurements \n404\n, \n424\n and the corresponding weight and acceleration sensors \n302\n, \n304\n (and/or the rotational position sensors \n306\n, if utilized) may be deemed or otherwise determined as being accurate, and thus validated.', 'However, if one or both of the detected and deduced weight measurements \n404\n, \n424\n suddenly or progressively change (e.g., the deduced weight measurement \n424\n shifts, as indicated by arrow \n426\n) resulting in detected and deduced weight measurements \n404\n, \n434\n that are appreciably different, not substantially similar, or otherwise do not substantially match, then at least one of the detected and deduced weight measurements \n404\n, \n434\n and the corresponding weight and acceleration sensors \n302\n, \n304\n (and/or the rotational position sensors \n306\n, if utilized) may be deemed or otherwise determined as being inaccurate, and thus not valid.', 'The sensor measurements \n404\n, \n434\n may be determined as being inaccurate, for example, when a difference \n428\n (e.g., in profile and/or magnitude) between the detected and deduced weight measurements \n404\n, \n434\n is equal to or greater than a predetermined threshold amount or is otherwise appreciable.', 'Each of the corresponding weight and acceleration sensors \n302\n, \n304\n (and/or the rotational position sensors \n306\n, if utilized) and/or corresponding pieces of equipment may then be checked to determine which of the weight and acceleration sensors \n302\n, \n304\n is inaccurate or if another problem associated with the corresponding equipment is causing the difference \n428\n between the detected and deduced weight measurements \n404\n, \n434\n.', 'FIG.', '6\n is a graph \n440\n showing a plurality weight measurement differences \n428\n, as described above and shown in \nFIG.', '5\n, recorded over time.', 'The graph \n440\n shows that the differences \n428\n are progressively increasing, which may indicate that the accuracy (i.e., quality) of one or both of the detected and deduced weight measurements \n404\n, \n434\n, shown in \nFIG.', '4\n, is progressively decreasing.', 'Such trend may be indicative of declining condition (i.e., health) of corresponding one or more of the weight and acceleration sensors \n302\n, \n304\n, shown in \nFIG.', '3\n.', 'The graph \n440\n may be generated by a processing device, such as the processing device \n202\n, shown in \nFIG.', '2\n, based on recorded historical and current operational parameter differences \n428\n.', 'The processing device may generate or otherwise output condition information indicative of the health of the corresponding one or more of the weight and acceleration sensors \n302\n, \n304\n (and/or the rotational position sensors \n306\n, if utilized) based on the measurement differences \n428\n.', 'For example, the processing device may output information indicative of which sensor \n302\n, \n304\n and/or equipment comprises a problem.', 'The processing device may also or instead output condition information indicative of remaining life of the corresponding one or more of the sensors \n302\n, \n304\n.', 'Furthermore, a threshold of acceptable condition, indicated by line \n444\n, may be set.', 'Accordingly, if a predetermined number of consecutive measurement differences \n428\n meet or exceed the threshold \n444\n, such as at time \n448\n, the processing device may at such time \n448\n output condition information suggesting or mandating that calibration or other maintenance of the corresponding one or more sensors \n302\n, \n304\n and/or corresponding pieces of equipment be performed.', 'Furthermore, if a running average of the measurement differences \n428\n, indicated by line \n446\n, meets or exceeds the threshold \n444\n, such as at time \n448\n, the processing device may at such time \n448\n output condition information suggesting or mandating that calibration or other maintenance of the corresponding one or more of the sensors \n302\n, \n304\n (and/or the rotational position sensors \n306\n, if utilized) and/or corresponding pieces of equipment be performed.', 'Thus, when the processing device does not detect measurement differences \n428\n over a predetermined period of time, the processing device may determine that the detected and deduced weight measurements \n404\n, \n434\n and, thus, one or more of the sensors \n302\n, \n304\n utilized as a basis for the measurements \n404\n, \n434\n are accurate.', 'However, when the processing device detects sudden or progressive onset of measurement differences \n428\n (e.g., sensor drift), the processing device may determine that the detected and deduced weight measurements \n404\n, \n434\n and, thus, one or more of the sensors \n302\n, \n304\n utilized as a basis for the measurements \n404\n, \n434\n are inaccurate.', 'The inaccurate detected and deduced weight measurements \n404\n, \n434\n may be disregarded until the inaccurate sensors \n302\n, \n304\n are replaced or recalibrated.', 'The inaccurate detected and deduced weight measurements \n404\n, \n434\n may also or instead be compensated by a predetermined value, such as by the detected difference \n428\n until the inaccurate sensors \n302\n, \n304\n are replaced or recalibrated.', 'A processing device, such as the processing device \n202\n and/or another rig control system, may include logic that decides when to execute and/or record functions related to drill string weight measurements and validation.', 'For example, the processing device may run sensor validation functions as part of a manual or automated diagnostics routine.', 'Such routine can be a standard part of rig readiness (e.g. each time the rig is rigged up) and/or be performed during specific times (e.g. each time a new BHA is rigged down).', 'The processing device may also or instead run sensor validation functions on a scheduled basis at pre-determined time intervals.', 'For example, the processing device may be set to run validation on a time domain (e.g. every two days) or on an activity domain (e.g. every 1000 feet of run pipe).', 'The processing device may also or instead run sensor validation functions triggered by predetermined events.', 'For example, every time a load exceeds a threshold amount.', 'The output of sensor validation analysis may trigger an action related to rig operational workflows, such as a further sensor review, investigation, or maintenance and/or sensor replacement.', 'The output of the sensor validation analysis can also or instead trigger functional modes that affect rig workflows.', 'For example, determination of a faulty sensor can trigger events, such as stop operations of the rig, operate the rig under safe-mode conditions, diminished performance, or diminished capacity, change priority and/or timing of maintenance activities, and/or communicate to rig crew(s) actions to be performed.', 'Determination of a correct sensor (or a sensor operating within acceptable limits) can trigger events, such as continue operations of the rig, postpone maintenance activities, and/or operate the rig under increased performance and/or capacity.', 'Although the processing devices and/or control systems within the scope of the present disclosure are utilized to deduce weight measurements of a drill string comprising a plurality of individual tubulars, it is to be understood that the same or similar operations and processes as described above may be utilized to deduce weight measurements of other tool strings, such as comprising a plurality of individual tubulars, but not comprising a drill bit.', 'It is to be further understood that the same or similar operations and processes as described above may also be utilized to deduce weight measurements of other drill or tool strings (e.g., drill or tool strings deployed via coiled tubing or wireline) and/or determine accuracy of sensor measurements of other tool string hoisting systems (e.g., pipe injectors, coiled tubing injectors, wireline winch systems).', 'FIG.', '7\n is a schematic view of at least a portion of an example implementation of a processing system \n500\n (or device) according to one or more aspects of the present disclosure.', 'The processing system \n500\n may be or form at least a portion of one or more processing devices, equipment controllers, and/or other electronic devices shown in one or more of the \nFIGS.', '1-6\n.', 'Accordingly, the following description refers to \nFIGS.', '1-7\n, collectively.', 'The processing system \n500\n may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, PCs (e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, IPCs, PLCs, servers, internet appliances, and/or other types of computing devices.', 'The processing system \n500\n may be or form at least a portion of the processing device \n192\n, \n202\n.', 'The processing system \n500\n may be or form at least a portion of the local controllers \n221\n-\n226\n.', 'Although it is possible that the entirety of the processing system \n500\n is implemented within one device, it is also contemplated that one or more components or functions of the processing system \n500\n may be implemented across multiple devices, some or an entirety of which may be at the wellsite and/or remote from the wellsite.', 'The processing system \n500\n may comprise a processor \n512\n, such as a general-purpose programmable processor.', 'The processor \n512\n may comprise a local memory \n514\n, and may execute machine-readable and executable program code instructions \n532\n (i.e., computer program code) present in the local memory \n514\n and/or another memory device.', 'The processor \n512\n may execute, among other things, the program code instructions \n532\n and/or other instructions and/or programs to implement the example methods and/or operations described herein.', 'For example, the program code instructions \n532\n, when executed by the processor \n512\n of the processing system \n500\n, may cause the processor \n512\n to receive, record, and process (e.g., compare) sensor data (e.g., sensor measurements), deduce sensor data, and output data and/or information indicative of accuracy the sensor data and, thus, the corresponding sensors.', 'The program code instructions \n532\n, when executed by the processor \n512\n of the processing system \n500\n, may also or instead cause one or more portions or pieces of wellsite equipment of a well construction system and/or drill string hoisting system to perform the example methods and/or operations described herein.', 'The processor \n512\n may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples.', 'Examples of the processor \n512\n include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, embedded soft/hard processors in one or more FPGAs.', 'The processor \n512\n may be in communication with a main memory \n516\n, such as may include a volatile memory \n518\n and a non-volatile memory \n520\n, perhaps via a bus \n522\n and/or other communication means.', 'The volatile memory \n518\n may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices.', 'The non-volatile memory \n520\n may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n518\n and/or non-volatile memory \n520\n.', 'The processing system \n500\n may also comprise an interface circuit \n524\n, which is in communication with the processor \n512\n, such as via the bus \n522\n.', 'The interface circuit \n524\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others.', 'The interface circuit \n524\n may comprise a graphics driver card.', 'The interface circuit \n524\n may comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.).', 'The processing system \n500\n may be in communication with various sensors, video cameras, actuators, processing devices, equipment controllers, and other devices of the well construction system via the interface circuit \n524\n.', 'The interface circuit \n524\n can facilitate communications between the processing system \n500\n and one or more devices by utilizing one or more communication protocols, such as an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication, or the like), a proprietary communication protocol, and/or another communication protocol.', 'One or more input devices \n526\n may also be connected to the interface circuit \n524\n.', 'The input devices \n526\n may permit human wellsite operators \n195\n to enter the program code instructions \n532\n, which may be or comprise control commands, operational parameters, and/or operational set-points.', 'The program code instructions \n732\n may further comprise modeling or predictive routines, equations, algorithms, processes, applications, and/or other programs operable to perform example methods and/or operations described herein.', 'The input devices \n526\n may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples.', 'One or more output devices \n528\n may also be connected to the interface circuit \n524\n.', 'The output devices \n528\n may permit for visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data.', 'The output devices \n528\n may be, comprise, or be implemented by video output devices (e.g., an LCD, an LED display, a CRT display, a touchscreen, etc.), printers, and/or speakers, among other examples.', 'The one or more input devices \n526\n and the one or more output devices \n528\n connected to the interface circuit \n524\n may, at least in part, facilitate the HMIs described herein.', 'The processing system \n500\n may comprise a mass storage device \n530\n for storing data and program code instructions \n532\n.', 'The mass storage device \n530\n may be connected to the processor \n512\n, such as via the bus \n522\n.', 'The mass storage device \n530\n may be or comprise a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples.', 'The processing system \n500\n may be communicatively connected with an external storage medium \n534\n via the interface circuit \n524\n.', 'The external storage medium \n534\n may be or comprise a removable storage medium (e.g., a CD or DVD), such as may be operable to store data and program code instructions \n532\n.', 'As described above, the program code instructions \n532\n and other data (e.g., sensor data or measurements) may be stored in the mass storage device \n530\n, the main memory \n516\n, the local memory \n514\n, and/or the removable storage medium \n534\n.', 'Thus, the processing system \n500\n may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor \n512\n.', 'In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code instructions \n532\n (i.e., software or firmware) thereon for execution by the processor \n512\n.', 'The program code instructions \n732\n may include program instructions or computer program code that, when executed by the processor \n712\n, may perform and/or cause performance of example methods, processes, and/or operations described herein.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces a system comprising: (A) an acceleration sensor disposed in association with a piece of equipment at an oil and gas wellsite, wherein the acceleration sensor is operable to facilitate determination of an acceleration measurement of a downhole tool string; and (B) a processing device comprising a processor and a memory storing computer program code, wherein the processing device is operable to: (1) output a movement control command to a lifting device to cause the downhole tool string to move in accordance to the movement control command; (2) receive the acceleration measurement; and (3) determine a weight measurement of the downhole tool string based on the movement control command and the acceleration measurement.', 'The processing device may be operable to determine the weight measurement of the downhole tool string based further on a database of corresponding past movement control commands, past weight measurements, and past acceleration measurements.', 'The weight measurement may be a deduced weight measurement, the piece of equipment may be a first piece of equipment, the system may further comprise a weight sensor disposed in association with a second piece of equipment, the weight sensor may be operable to facilitate determination of a detected weight measurement of the downhole tool string, and the processing device may be further operable to: (A) receive the detected weight measurements; (B) record a database of the movement control commands in association with corresponding detected weight measurements and acceleration measurements; and (C) determine the deduced weight measurement of the downhole tool string by (1) searching the database for a recorded movement control command and corresponding recorded acceleration measurement that are closest to current movement control command and corresponding current acceleration measurement, and (2) determining the deduced weight measurement to be equal to a recorded detected weight measurement corresponding to the closest recorded movement control command and corresponding recorded acceleration measurement.', 'The processing device may be operable to determine the weight measurement of the downhole tool string while the tool string is moved during wellsite operations.', 'The piece of equipment may comprise at least one of a draw works, a travelling block, a top drive, an elevator, and a drill string.', 'The downhole tool string may be or comprise a downhole drill string.', 'The weight measurement may be a deduced weight measurement, the piece of equipment may be a first piece of equipment, the system may further comprises a weight sensor disposed in association with a second piece of equipment, the weight sensor may be operable to facilitate determination of a detected weight measurement of the downhole tool string, and the processing device may be further operable to: receive the detected weight measurement; compare the deduced weight measurement to the detected weight measurement; and determine accuracy of at least one of the acceleration sensor and weight sensor based on the comparison.', 'The processing device may be operable to determine the accuracy of at least one of the acceleration sensor and weight sensor based on the comparison while the first and second pieces of equipment are performing actions as part of a well site operation.', 'Comparing the deduced weight measurement to the detected weight measurement may comprise determining a difference between the deduced weight measurement and detected weight measurement.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that the acceleration sensor and weight sensor are accurate when the deduced weight measurement and detected weight measurement are substantially equal to each other.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that at least one of the acceleration sensor and weight sensor is inaccurate when the deduced weight measurement and detected weight measurement are appreciably different.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that at least one of the acceleration sensor and weight sensor is inaccurate when a difference between the deduced weight measurement and detected weight measurement is equal to or greater than a predetermined threshold quantity.', 'The first piece of equipment may comprise at least one of a draw works, a travelling block, a top drive, an elevator, and a drill string, and the second piece of equipment may comprise at least one of a top drive, a top drive link, an elevator link, and a deadline anchor.', 'The detected weight measurement may be facilitated by the weight sensor.', 'The movement control command outputted by the processing device to the lifting device may comprise one or more of: a standard movement control command that is part of an existing rig operation; a special movement control command that is embedded in an existing rig operation; and a special movement control command that is not part of an existing rig operation and whose sole purpose is to determine the weight measurement of the downhole tool string.', 'The present disclosure also introduces a method comprising commencing operation of a processing device to control operations at an oil and gas wellsite, wherein the processing device: outputs a movement control command to a lifting device to cause a downhole tool string to move in accordance to the movement control command; receives an acceleration measurement of the downhole tool string; and determines a weight measurement of the downhole tool string based on the movement control command and the acceleration measurement.', 'The processing device may determine the weight measurement of the downhole tool string based further on a database of corresponding past outputted movement control commands, past weight measurements, and past acceleration measurements.', 'The weight measurement may be a deduced weight measurement, and the processing device may further: (A) receive a detected weight measurement of the downhole tool string facilitated by a weight sensor; (B) record a database of the outputted movement control commands in association with corresponding detected weight measurements and acceleration measurements; and (C) determine the deduced weight measurement of the downhole tool string by (1) searching the database for a recorded movement control command and corresponding recorded acceleration measurement that are closest to current movement control command and corresponding current acceleration measurement, and (2) determining the deduced weight measurement to be equal to the recorded detected weight measurement associated with the closest recorded movement control command and recorded acceleration measurement.', 'The piece of equipment may comprise at least one of a draw works, a travelling block, a top drive, an elevator, and a drill string.', 'The downhole tool string may be or comprise a downhole drill string.', 'The acceleration measurement may be facilitated by an acceleration sensor, the weight measurement may be a deduced weight measurement, and the processing device may further: receive a detected weight measurement of the downhole tool string facilitated by a weight sensor; compare the deduced weight measurement to the detected weight measurement; and determine accuracy of at least one of the acceleration sensor and weight sensor based on the comparison.', 'The acceleration sensor may be disposed in association with a first piece of equipment, the weight sensor may be disposed in association with a second piece of equipment, and the processing device may further determines the accuracy of at least one of the acceleration sensor and weight sensor based on the comparison while the first and second pieces of equipment are performing actions as part of a well site operation.', 'Comparing the deduced weight measurement to the detected weight measurement may comprise determining a difference between the deduced weight measurement and detected weight measurement.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that the acceleration sensor and weight sensor are accurate when the deduced weight measurement and detected weight measurement are substantially equal to each other.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that at least one of the acceleration sensor and weight sensor is inaccurate when the deduced weight measurement and detected weight measurement are appreciably different.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that at least one of the acceleration sensor and weight sensor is inaccurate when a difference between the deduced weight measurement and detected weight measurement is equal to or greater than a predetermined threshold quantity.', 'The acceleration sensor may be disposed in association with at least one of a travelling block, a top drive, a top drive link, an elevator, and a drill string, and the weight sensor may be disposed in association with at least one of a travelling block, a crown block, a top drive, a top drive link, an elevator, and a deadline anchor.', 'The detected weight measurement may be facilitated by the weight sensor.', 'The movement control command outputted by the processing device to the lifting device may comprise one or more of: a standard movement control command that is part of an existing rig operation; a special movement control command that is embedded in an existing rig operation; and a special movement control command that is not part of an existing rig operation and whose sole purpose is to determine the weight measurement of the downhole tool string.', 'The present disclosure also introduces a method comprising commencing operation of a processing device to control operations at an oil and gas wellsite, wherein the processing device: outputs a current movement control command to a lifting device to cause a downhole tool string to move; receives a current acceleration measurement of the downhole tool string; compares the current movement control command and the current acceleration measurement to recorded past movement control commands and corresponding recorded past acceleration measurements; and determines a current weight measurement of the tool string to be equal to a recorded past weight measurement associated with closest recorded movement control command and corresponding recorded acceleration measurement.', 'Comparing the current movement control command and the current acceleration measurement to the recorded past movement control commands and the corresponding recorded past acceleration measurements may comprise searching the recorded past movement control commands and corresponding recorded past acceleration measurements for recorded past movement control commands and corresponding recorded past acceleration measurements that are closest to the current movement control command and the current acceleration measurement.', 'The current acceleration measurement may be facilitated by an acceleration sensor disposed in association with at least one of a draw works, a travelling block, a top drive, an elevator, and a drill string.', 'The downhole tool string may be or comprise a downhole drill string.', 'The current acceleration measurement may be facilitated by an acceleration sensor, the current weight measurement may be a current deduced weight measurement, and the processing device may further: receive a current detected weight measurement of the downhole tool string facilitated by a weight sensor; compare the current deduced weight measurement to the current detected weight measurement; and determine accuracy of at least one of the acceleration sensor and weight sensor based on the comparison.', 'The acceleration sensor may be disposed in association with a first piece of equipment, the weight sensor may be disposed in association with a second piece of equipment, and the processing device may further determine the accuracy of at least one of the acceleration sensor and weight sensor based on the comparison while the first and second pieces of equipment are performing actions as part of a wellsite operation.', 'Comparing the current deduced weight measurement to the current detected weight measurement may comprise determining a difference between the current deduced weight measurement and current detected weight measurement.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that the acceleration sensor and weight sensor are accurate when the current deduced weight measurement and current detected weight measurement are substantially equal to each other.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that at least one of the acceleration sensor and weight sensor is inaccurate when the current deduced weight measurement and current detected weight measurement are appreciably different.', 'Determining the accuracy of at least one of the acceleration sensor and weight sensor may comprise determining that at least one of the acceleration sensor and weight sensor is inaccurate when a difference between the current deduced weight measurement and current detected weight measurement is equal to or greater than a predetermined threshold quantity.', 'The acceleration sensor may be disposed in association with at least one of a travelling block, a top drive, a top drive link, an elevator, and a drill string, and the weight sensor may be disposed in association with at least one of a travelling block, a crown block, a top drive, a top drive link, an elevator, and a deadline anchor.', 'The detected weight measurement may be facilitated by the weight sensor.', 'The movement control command outputted by the processing device to the lifting device may comprise one or more of: a standard movement control command that is part of an existing rig operation; a special movement control command that is embedded in an existing rig operation; and a special movement control command that is not part of an existing rig operation and whose sole purpose is to determine the weight measurement of the downhole tool string.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'A system comprising:\nan acceleration sensor disposed in association with a first piece of equipment at an oil and gas wellsite, wherein the acceleration sensor is operable to facilitate determination of an acceleration measurement of a downhole tool string;\na weight sensor disposed in association with a second piece of equipment, the weight sensor operable to facilitate determination of a detected weight measurement of the downhole tool string; and\na processing device comprising a processor and a memory storing computer program code, wherein the processing device is operable to: output a movement control command to a lifting device to cause the downhole tool string to move in accordance to the movement control command; receive the acceleration measurement; and determine a deduced weight measurement of the downhole tool string based on the movement control command and the acceleration measurement; receive the detected weight measurement; compare the deduced weight measurement to the detected weight measurement; and determine an accuracy of at least one of the acceleration sensor and the weight sensor based on the comparison.', '2.', 'The system of claim 1 wherein the processing device is operable to determine the deduced weight measurement of the downhole tool string further based on a database of corresponding past movement control commands, past weight measurements, and past acceleration measurements.', '3.', 'The system of claim 1 wherein the first piece of equipment comprises at least one of a draw works, a travelling block, a top drive, an elevator, and a drill string.', '4.', 'The system of claim 1 wherein:\nthe processing device is further operable to: receive a plurality of past movement control commands output to the lifting device; receive a plurality of past acceleration measurements from the acceleration sensor; receive a plurality of past detected weight measurements from the weight sensor; record, in a database, each past movement control command of the plurality of past movement control commands in association with a respective corresponding past detected weight measurement of the plurality of past detected weight measurements and a respective corresponding past acceleration measurement of the plurality of past acceleration measurements; and determine the deduced weight measurement of the downhole tool string by: searching the database for a closest past movement control command of the plurality of past movement control commands and the respective corresponding past acceleration measurement that are closest to the movement control command and the acceleration measurement; and determining the deduced weight measurement to be equal to the respective corresponding past detected weight measurement that is recorded in association with the closest past movement control command and the respective corresponding past acceleration measurement.', '5.', 'The system of claim 1 wherein the first piece of equipment comprises at least one of a draw works, a travelling block, a top drive, an elevator, and a drill string, and wherein the second piece of equipment comprises at least one of a top drive, a top drive link, an elevator link, and a deadline anchor.', '6.', 'The system of claim 1 wherein the movement control command outputted by the processing device to the lifting device comprises one or more of:\na standard movement control command that is part of an existing rig operation;\na special movement control command that is embedded in an existing rig operation; or\na special movement control command that is not part of an existing rig operation and whose sole purpose is to determine the deduced weight measurement of the downhole tool string.', '7.', 'The system of claim 1 wherein the processing device is further operable to determine the deduced weight measurement of the downhole tool string by:\naccessing, from a database, a plurality of past movement control commands, a plurality of past acceleration measurements, and a plurality of past weight measurements;\nidentifying a past movement control command of the plurality of past movement control commands and a corresponding past acceleration measurement of the plurality of past acceleration measurements that are closest to the movement control command and the acceleration measurement; and\ndetermining the weight measurement based on a corresponding past weight measurement of the plurality of past weight measurements that is stored in association with the past movement control command and the corresponding past acceleration measurement.', '8.', 'A method comprising:\ncommencing operation of a processing device to control operations at an oil and gas wellsite, wherein the processing device: outputs a movement control command to a lifting device to cause a downhole tool string to move in accordance to the movement control command; receives an acceleration measurement of the downhole tool string facilitated ban an acceleration sensor; determines a deduced weight measurement of the downhole tool string based on the movement control command and the acceleration measurement; receives a detected weight measurement of the downhole tool string facilitated by a weight sensor; compares the deduced weight measurement to the detected weight measurement; and determines an accuracy of at least one of the acceleration sensor and the weight sensor based on the comparison.', '9.', 'The method of claim 8 wherein the processing device determines the deduced weight measurement of the downhole tool string further based on a database of corresponding past outputted movement control commands, past weight measurements, and past acceleration measurements.', '10.', 'The method of claim 8 wherein the processing device further:\nreceives a plurality of past movement control commands output to the lifting device;\nreceives a plurality of past acceleration measurements;\nreceives a plurality of past detected weight measurements of the downhole tool string facilitated by the weight sensor;\nrecords, in a database, each past movement control command of the plurality of past movement control commands in association with a respective corresponding past detected weight measurement of the plurality of past detected weight measurements and a respective corresponding past acceleration measurement of the plurality of past acceleration measurements; and\ndetermines the deduced weight measurement of the downhole tool string by: searching the database for a closest past movement control command of the plurality of past movement control commands and the respective corresponding past acceleration measurement that are closest to the movement control command and the acceleration measurement; and determining the deduced weight measurement to be equal to the respective corresponding past detected weight measurement that is recorded in association with the closest past movement control command and the respective corresponding past acceleration measurement.', '11.', 'The method of claim 8 wherein the acceleration sensor is disposed in association with a first piece of equipment, wherein the weight sensor is disposed in association with a second piece of equipment, and wherein the processing device further determines the accuracy of at least one of the acceleration sensor and the weight sensor based on the comparison while the first and second pieces of equipment are performing actions as part of a wellsite operation.', '12.', 'The method of claim 8 wherein determining the accuracy of at least one of the acceleration sensor and the weight sensor comprises determining that the acceleration sensor and the weight sensor are accurate when the deduced weight measurement and the detected weight measurement are substantially equal to each other.', '13.', 'A method comprising:\ncommencing operation of a processing device to control operations at an oil and gas wellsite, wherein the processing device: outputs a current movement control command to a lifting device to cause a downhole tool string to move; receives a current acceleration measurement of the downhole tool string; compares the current movement control command and the current acceleration measurement to recorded past movement control commands and corresponding recorded past acceleration measurements; and determines a current weight measurement of the downhole tool string to be equal to a recorded past weight measurement associated with a closest recorded past movement control command of the recorded past movement control commands and corresponding recorded past acceleration measurement of the corresponding recorded past acceleration measurements.', '14.', 'The method of claim 13 wherein comparing the current movement control command and the current acceleration measurement to the recorded past movement control commands and the corresponding recorded past acceleration measurements comprises searching the recorded past movement control commands and the corresponding recorded past acceleration measurements for the closest recorded past movement control command and corresponding recorded past acceleration measurement that are closest to the current movement control command and the current acceleration measurement.', '15.', 'The method of claim 13 wherein the current acceleration measurement is facilitated by an acceleration sensor disposed in association with at least one of a draw works, a travelling block, a top drive, an elevator, and a drill string.', '16.', 'The method of claim 13 wherein the current acceleration measurement is facilitated by an acceleration sensor, wherein the current weight measurement is a current deduced weight measurement, and wherein the processing device further:\nreceives a current detected weight measurement of the downhole tool string facilitated by a weight sensor;\ncompares the current deduced weight measurement to the current detected weight measurement; and\ndetermines an accuracy of at least one of the acceleration sensor and the weight sensor based on the comparison.', '17.', 'The method of claim 16 wherein the acceleration sensor is disposed in association with a first piece of equipment, wherein the weight sensor is disposed in association with a second piece of equipment, and wherein the processing device further determines the accuracy of at least one of the acceleration sensor and the weight sensor based on the comparison while the first and second pieces of equipment are performing actions as part of a wellsite operation.', '18.', 'The method of claim 16 wherein determining the accuracy of at least one of the acceleration sensor and the weight sensor comprises determining that the acceleration sensor and the weight sensor are accurate when the current deduced weight measurement and the current detected weight measurement are substantially equal to each other.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIGS.', '4-6 are graphs related to one or more aspects of the present disclosure.', '; FIG. 7 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG. 1 is a schematic view of at least a portion of an example implementation of a well construction system 100 according to one or more aspects of the present disclosure.', 'The well construction system 100 represents an example environment in which one or more aspects of the present disclosure described below may be implemented.', 'The well construction system 100 may be or comprise a drill rig and associated wellsite equipment.', 'Although the well construction system 100 is depicted as an onshore implementation, the aspects described below are also applicable to offshore implementations.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of a drill string hoisting system 300 operable to support and lift individual tubulars 111 and a drill string 120 according to one or more aspects of the present disclosure.', 'The drill string hoisting system 300 may form a portion of or operate in conjunction with the well construction system 100 shown in FIG.', '1', 'and be operable to perform at least a portion of the processes described above in association with FIG.', '1.', 'The drill string hoisting system 300 may, thus, comprise one or more features of the well construction system 100, including where indicated by the same numerals.', 'The drill string hoisting system 300 may be monitored and controlled by the control system 200 shown in FIG.', '2.', 'Accordingly, the following description refers to FIGS.', '1-3, collectively.;', 'FIG. 4 is a graph 400 showing example profiles of several control commands and operational parameters, including movement control commands 402 and sensor measurements 404, 406, 408 generated by corresponding sensors disposed in association with one or more pieces of the drill string hoisting system 300 shown in FIG.', '3.', 'The movement control commands 402 and sensor measurements 404, 406, 408 are plotted along the vertical axis, with respect to time, which is plotted along the horizontal axis.', '; FIG.', '5 is a graph 410 showing portions of example profiles of several current and recorded control commands and operational parameters, including of control commands and operational profiles shown in FIG.', '4, including where indicated by the same numerals.', 'The control commands and acceleration measurements are plotted along the vertical axis, with respect to time, which is plotted along the horizontal axis.', 'The graph 410 shows current and recorded movement control commands 402, 412, respectively, and current and recorded acceleration measurements 408, 418, respectively, generated by corresponding sensors disposed in association with one or more pieces of the drill string hoisting system 300 shown in FIG.', '3.', 'Accordingly, the following description refers to FIGS.', '3-5, collectively.;', 'FIG. 6 is a graph 440 showing a plurality weight measurement differences 428, as described above and shown in FIG.', '5, recorded over time.', 'The graph 440 shows that the differences 428 are progressively increasing, which may indicate that the accuracy (i.e., quality) of one or both of the detected and deduced weight measurements 404, 434, shown in FIG.', '4, is progressively decreasing.', 'Such trend may be indicative of declining condition (i.e., health) of corresponding one or more of the weight and acceleration sensors 302, 304, shown in FIG.', '3.', 'The graph 440 may be generated by a processing device, such as the processing device 202, shown in FIG.', '2, based on recorded historical and current operational parameter differences 428.; FIG.', '7 is a schematic view of at least a portion of an example implementation of a processing system 500 (or device) according to one or more aspects of the present disclosure.', 'The processing system 500 may be or form at least a portion of one or more processing devices, equipment controllers, and/or other electronic devices shown in one or more of the FIGS.', '1-6.', 'Accordingly, the following description refers to FIGS.', '1-7, collectively.'] |
|
US11111425 | Methods and system to reduce imperceptible lab experiments | Jun 20, 2016 | Bhanu Kaushik, Samir Menasria | Schlumberger Technology Corporation | NPL References not found. | 5446681; August 29, 1995; Gethner; 20090277640; November 12, 2009; Thompson; 20130220607; August 29, 2013; Phatak; 20180135382; May 17, 2018; Jandhyala | Foreign Citations not found. | ['Methods may include defining operational parameters for an initial composition design; generating an initial composition design from the defined operational parameters; predicting the performance of the initial composition design using a statistical model; comparing the performance of the initial composition design with the operational parameters; optimizing the initial composition design according to the defined operational parameters; and outputting a final composition design.', 'Methods may also include defining operational parameters for an initial composition design for a wellbore fluid; generating an initial composition design from the defined operational parameters; predicting the performance of the initial composition design using a statistical model; comparing the performance of the initial composition design with the operational parameters; optimizing the initial composition design according to the defined operational parameters; and outputting a final composition design.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nCustomized chemical composition formulation based on a defined need is a complex and time consuming task on the commercial scale.', 'For example, in standard practice a requirement for a particular composition is set based upon client preferences and the demands of the operational environment.', 'However, composition design may also be constrained in some cases by additional considerations that may include, for example, the availability of composition components within a geographical region or governmental restrictions for operating in environmentally sensitive areas.', 'Following the initial stage, the standard optimization process for a composition often involves a laboratory technician relying on experience and empirical data to develop a composition that performs in agreement with client operational requirements.', 'Composition designs are then validated in a laboratory through various experiments to verify that all design criteria are satisfied.', 'Numerous experiments are often conducted.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are described further below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'In one aspect, embodiments of the present disclosure are directed to methods that include defining operational parameters for an initial composition design; generating an initial composition design from the defined operational parameters; predicting the performance of the initial composition design using a statistical model; comparing the performance of the initial composition design with the operational parameters; optimizing the initial composition design according to the defined operational parameters; and outputting a final composition design.', 'In another aspect, embodiments of the present disclosure are directed to methods that include defining operational parameters for an initial composition design for a wellbore fluid, wherein the operational parameters comprise one or more selected from a group consisting of wellbore geometry, formation composition, environmental variables, composition components, pricing information, and temperature; generating an initial composition design from the defined operational parameters; predicting the performance of the initial composition design using a statistical model; comparing the performance of the initial composition design with the operational parameters; optimizing the initial composition design according to the defined operational parameters; and outputting a final composition design.', 'Other aspects and advantages of the disclosure will be apparent from the following description and the appended claims.', 'BRIEF DESCRIPTION OF FIGURES\n \nFIG.', '1\n is an illustration of a completions operation in which cement is installed in an annular region created between a borehole and an installed casing in accordance with embodiments of the present disclosure.', 'FIG.', '2\n is a schematic depicting a flow diagram in accordance with embodiments of the present disclosure.', 'FIG.', '3\n is a computer system in accordance with embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'In one aspect, methods in accordance with this disclosure are directed to design processes to reduce the number of laboratory tests required during the development of customized composition designs that perform according to the specifications of a particular job or client.', 'Methods may utilize a software platform that allows a user to select and optimize composition designs and perform evaluations for expected behavior for various composition components and concentration ranges prior to performing experiments on the actual composition design.', 'In one or more embodiments, methods may include a user-guided application that utilizes computer modeling and statistical algorithms to generate optimized composition designs based upon defined constraints and historical experimental data.\n \nMethods in accordance with the present disclosure may be used to generate customized compositions tailored to a set of user-defined criteria and obviate the need for, or minimizing the number of, laboratory experiments often used to develop composition designs, which may reduce the need for composition design techniques that involve screening incremental formulation changes, experimentation, and optimization.', 'In one or more embodiments, methods in accordance with the present disclosure may allow a user to predict the outcome of lab experiments without experimentation and to identify compositions suitable for any input parameters.', 'Applications in accordance with the present disclosure may include a user interface that presents a user with a selection of optimized composition designs.', 'In particular embodiments, computer modeling may output a composition design that takes into account user inputs that may include market pricing, material properties, availability, operating conditions, chemical compatibilities, and the like.', 'In one or more embodiments, custom composition design may involve the use of statistical analytic models that utilize historical laboratory data to predict with defined accuracy the expected outcome of testing methods for composition design candidates.', 'Final compositions designs may then be validated by laboratory experiment in some embodiments, and the experimental data may be compiled into the historical database to reduce the error for future iterations of composition design and improve the predictive quality of the analytical models.', 'Composition designs may be directed to the production and optimization of cement compositions in some embodiments.', 'Cement compositions may then be emplaced within a wellbore, such as in an annulus created between a wall of the formation and a section of casing installed within the wellbore.', 'With particular respect to \nFIG.', '1\n, a derrick \n100\n is shown installed on a wellbore \n101\n traversing a formation \n102\n.', 'Within the wellbore \n101\n concentric segments of casing \n104\n are nested within each other, in preparation for installation of a cement sheath between the outside of the casing and the exposed formation and/or other emplaced casing strings.', 'During the cementing operation, a cement slurry \n106\n is pumped into an annulus formed between formation \n102\n and the casing \n104\n.', 'In some embodiments, cement slurry may be pumped into multiple annular regions within a wellbore such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or more of an A- or B-annulus (or greater number of annuli where present) created between one or more inner strings of pipe extending into a wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string.', 'However, while cementing is presented as a possible embodiment, it is also envisioned that methods of the present disclosure may be applied to other wellbore fluids and to the formulation of composition designs for industrial applications in which historical testing data for a number of formulations is available.', 'Testing data may include data regarding chemical properties and compatibilities, solubility data, crush testing for proppants, fibers, and solid other additives, temperature stability data, data from various laboratory techniques including fluid loss testing, melting and boiling point data, titrations, scratch testing, filter cake formation and breaking data, spurt loss, gravimetric data, crystallization data, rheometry, hardness testing, and the like.', 'In one or more embodiments, methods in accordance with the present disclosure may be used to formulate wellbore fluids to minimize equipment wear and corrosion, such as the formulation of acid treatments to contain corrosion inhibitors, scale inhibitors, buffering systems, rheology modifiers, chelants, temperature stabilizers, and solvents.', 'In some embodiments, methods in accordance with the present disclosure may be used to formulate wellbore fluids that include fracturing fluids, pads, and spacer fluids used in fracturing operations with control over fluid performance characteristics such as, for example, rheology, friction, fluid loss control, component solubility, proppant content, and leak-off.', 'Further, applications may include design of multi-component compositions used outside of a wellbore including in the transport of hydrocarbon fluids, treatment of waste streams, and development of chemical packages and concentrates for industrial use.\n \nMethods of composition design in accordance with the present disclosure may involve the construction of a model detailing user-specified parameters for a composition design that are tested and screened using a statistical model to generate an optimized final composition design.', 'With particular respect to \nFIG.', '2\n, a flow diagram is presented showing an embodiment of workflow in accordance with the present disclosure.', 'The method begins at \n202\n in which a generated request for a customized composition design is used to define the factors relevant for the chemical composition.', 'Design considerations may include the environment in which the composition design will be used, materials that should be used, cost constraints, desired fluid rheology, features for transport to a job site, operating temperature ranges, corrosive properties, toxicity, concentration ranges of composition components, and other relevant characteristics.', 'A user may then select a prospective starting composition design on which to perform an optimization routine at \n204\n.', 'Once a composition design is selected, the composition design is then optimized at \n206\n according to the input operational parameters.', 'A statistical analytic model is then used at \n208\n to perform a number of virtual experiments based on the expected outcome of the composition design when employed in the target environment.', 'A statistical model is built on the historical data using the composition parameters such as blend fluids, chemicals operating parameters such as temperatures, pressure etc.', 'Based on these parameters multiple analytics algorithms are used to generate an ensemble of analytics model which is used later to predict/score jobs.', 'The model may vary the parameters of the composition design to optimize the design depending on a number of factors.', 'For example, a composition design for a wellbore fluid may take into account the concentration of various components within the fluid, the type of job such as completions or drilling, the length of tubing with the well, the depth of the well, the range of operating temperatures, rheology and friction gradients, cost optimizations, and the like.', 'In particular embodiments, composition designs directed to settable compositions, such as cements and polymer-forming compositions, may also take into account the setting or curing time with respect to handling and travel times, and strength and hardness requirements for the final composition design.', 'Models in accordance with the present disclosure may set up a series of rules and perform experiments or scenarios to analyze composition design performance, generating a composition design that meets the input requirements to a satisfactory degree.', 'Following the modification of the composition design within the user-defined parameters, a final composition design is obtained and output at \n210\n.', 'At this point a user or user-guided program may determine if the recipe is optimal with respect to the input user criteria.', 'If it is determined that the composition design meets the desired criteria to a satisfactory degree, the final composition design is output at \n210\n.', 'If the design composition is unsatisfactory, optimization continues by performing steps \n206\n-\n210\n for one or more iterations until a satisfactory composition design is reached.', 'The final composition design output at \n212\n may then be used directly or may be validated by laboratory experiment.', 'In one or more embodiments, usage data obtained for the final composition design, in the form of field or experimental data, may be compiled into the historical database and incorporated in future statistical modes.', 'Methods in accordance with the present disclosure may produce one or more composition designs based on the context of the input requirements from the field.', 'Models in accordance with the present disclosure may be developed using information regarding the individual fluid and solid composition components, and may incorporate optimization routines that allow the input of various operation-specific parameters such as environmental constraints, chemical properties such as setting times or set strength, fluid rheology, pumping schedules, and other variables used to develop an internal set of rules that is used to screen composition components and output a composition design meeting the selected criteria.', 'In embodiments directed to the design and preparation of wellbore fluid compositions, applications in accordance with the present disclosure may use inputs such as the downhole environment, formation properties, chemical reactivity of various connate fluids, temperatures, and the like, to construct a model for optimizing composition designs.', 'For example, models in accordance with the present disclosure may be a three dimensional (3D) model that estimates properties of the reservoir based on obtained reservoir data.', 'For example, the base model may be a geo-mechanical and material property model of the subsurface of the wellsite and/or the reservoir.', "In particular embodiments, design inputs may include wellbore modeling parameters such as vertical stress, pore pressure, horizontal stresses, reservoir porosity, permeability, vertical permeability, lateral permeability, mechanical properties such as Poisson's Ratio, Young's Modulus, and the like.", 'Other inputs may include cost of resources, cost of capital, raw materials, enterprise operations and/or processes, network management, performance, equipment, energy, competitors, marketing, sales, product specifications, geographic location, economic factors, ambient conditions, customer information, environmental information, among others.', 'Design parameters that may be relevant to wellbore fluid compositions may include, for example, the safe mud weight window, cementing weight, and cement type, casing type, production tubing type, perforation method, casing point locations, the cost of the materials to be used, and the like.', 'Composition designs in accordance with the present disclosure may include predicted compositional properties and performance data generated by an analytical model in some embodiments.', 'In some embodiments, composition designs may also include optimized instructions regarding preparation and use of the composition design depending on the operational requirements.', 'For example, in embodiments directed to wellbore compositions, an output design may include a pumping schedule for a wellbore fluid and/or an order of addition for various components in the design.', 'Further, composition designs may also include estimated chemical and rheological properties, which may enable users to select other operational features such as equipment used in conjunction with the composition such as compatible materials and pumps for transport and handling.', 'Composition designs in accordance with the present disclosure may include cements and other settable materials.', 'Cement compositions may include mixtures of lime, silica and alumina, lime and magnesia, silica, alumina and iron oxide, materials such as calcium sulphate and Portland cements, and pozzolanic materials such as ground slag, or fly ash.', 'Formation, pumping, and setting of a cement slurry is known in art, and may include the incorporation of cement accelerators, retardants, dispersants, etc., as known in the art, so as to obtain a slurry and/or set cement with desirable characteristics.', 'In a particular embodiment, cement compositions may incorporate a magnesium-based cement such as a “Sorel” cement.', 'Magnesium-based cements are fast setting cements that approach maximum strength within 24 hours of contact with water.', 'While not limited by any particular theory, the cement-forming reaction mechanism is thought to be an acid-base reaction between a magnesium oxide, such as MgO, and available aqueous salts.', 'For example, mixing solid MgO and a brine containing MgCl\n2 \nresults in an initial gel formation followed by the crystallization of the gel into an insoluble cement matrix, producing magnesium oxychloride (MOC) cement.', 'Other magnesium-based cements may be formed from the reaction of magnesium cations and a number of counter anions such as, for example, halides, phosphates, sulfates, silicates, aluminosilicates, borates, and carbonates.', 'In some embodiments, anions may be provided by a magnesium salt of the selected anion.', 'In addition to MOC cements, prominent examples of magnesium-based cements also include magnesium oxysulfate (MOS) cements formed by the combination of magnesium oxide and a magnesium sulfate solution), and magnesium phosphate (MOP) cements formed by the reaction between magnesium oxide and a soluble phosphate salt, such as ammonium phosphate (NH\n4\nH\n2\nPO\n4\n).', 'Other suitable magnesium cements may also include magnesium carbonate and magnesium silicate cements.', 'In one or more embodiments, magnesium cements may also include combinations of any magnesium cements described herein and those known in the art.', 'In other embodiments, the cement composition may be selected from hydraulic cements known in the art, such as those containing compounds of calcium, aluminum, silicon, oxygen and/or sulfur, which set and harden by reaction with water.', 'These include “Portland cements,” such as normal Portland or rapid-hardening Portland cement, sulfate-resisting cement, and other modified Portland cements; high-alumina cements, high-alumina calcium-aluminate cements; and the same cements further containing small quantities of accelerators or retarders or air-entraining agents.', 'Other cements may include phosphate cements and Portland cements containing secondary constituents such as fly ash, pozzolan, and the like.', 'Other water-sensitive cements may contain aluminosilicates and silicates that include ASTM Class C fly ash, ASTM Class F fly ash, ground blast furnace slag, calcined clays, partially calcined clays (e.g., metakaolin), silica fume containing aluminum, natural aluminosilicate, feldspars, dehydrated feldspars, alumina and silica sols, synthetic aluminosilicate glass powder, zeolite, scoria, allophone, bentonite and pumice.', 'In one or more embodiments, the set time of the cement composition may be controlled by, for example, varying the grain size of the cement components, varying the temperature of the composition, or modifying the availability of the water from a selected water source.', 'In other embodiments, the exothermic reaction of components included in the cement composition (e.g., magnesium oxide, calcium oxide) may be used to increase the temperature of the cement composition and thereby increase the rate of setting or hardening of the composition.', 'Cement compositions may also include a variety of inorganic and organic aggregates, such as saw dust, wood flour, marble flour, sand, glass fibers, mineral fibers, and gravel.', 'In some embodiments, a cement component may be used in conjunction with set retarders known in the art to increase the workable set time of the cement.', 'Examples of retarders known in the art include organophosphates, amine phosphonic acids, lignosulfate salts, hydroxycarboxylic acids, carbohydrates, borax, sodium pentaborate, sodium tetraborate, or boric acid, and proteins such as whey protein.\n \nEmbodiments of the present disclosure may be implemented on a computing system.', 'Any combination of mobile, desktop, server, embedded, or other types of hardware may be used.', 'For example, as shown in \nFIG.', '3\n, the computing system (\n300\n) may include one or more computer processor(s) (\n302\n), associated memory (\n304\n) (e.g., random access memory (RAM), cache memory, flash memory, etc.), one or more storage device(s) (\n306\n) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities.', 'The computer processor(s) (\n302\n) may be an integrated circuit for processing instructions.', 'For example, the computer processor(s) may be one or more cores, or micro-cores of a processor.', 'The computing system (\n300\n) may also include one or more input device(s) (\n310\n), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device.', 'Further, the computing system (\n300\n) may include one or more output device(s) (\n308\n), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device.', 'One or more of the output device(s) may be the same or different from the input device(s).', 'The computing system (\n300\n) may be connected to a network (\n312\n) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) via a network interface connection (not shown).', 'The input and output device(s) may be locally or remotely (e.g., via the network (\n512\n)) connected to the computer processor(s) (\n302\n), memory (\n304\n), and storage device(s) (\n506\n).', 'Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.', 'Software instructions in the form of computer readable program code to perform embodiments of the invention may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium.', 'Specifically, the software instructions may correspond to computer readable program code that when executed by a processor(s), is configured to perform embodiments of the invention.', 'Further, one or more elements of the aforementioned computing system (\n300\n) may be located at a remote location and connected to the other elements over a network (\n312\n).', 'Further, embodiments of the invention may be implemented on a distributed system having a plurality of nodes, where each portion of the invention may be located on a different node within the distributed system.', 'In one embodiment of the invention, the node corresponds to a distinct computing device.', 'Alternatively, the node may correspond to a computer processor with associated physical memory.', 'The node may alternatively correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.', 'Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A method comprising:\ndefining operational parameters for an initial composition design based on user-specified design considerations including: well environment in which a composition will be used, including wellbore modeling parameters related to vertical stresses, horizontal stresses and permeability; operating temperature ranges; cost constraints; and transport to a wellsite;\nusing a three-dimensional model on a computing system having a computer processor to estimate properties of a reservoir based on obtained reservoir data;\ngenerating an initial composition design based on the defined operational parameters and the three-dimensional model;\npredicting the performance of the initial composition design using a statistical model;\ncomparing the performance of the initial composition design with the operational parameters;\noptimizing the initial composition design according to the defined operational parameters by adding at least one of a corrosion inhibitor, a scale inhibitor, a buffering agent, a rheology modifier, a chelant, a temperature stabilizer, or a solvent so as to minimize wear on well equipment located in the well environment;\nfurther optimizing the initial composition design by iteratively repeating the stages of predicting, comparing, and optimizing; and\noutputting a final composition design suitable for use in a well.', '2.', 'The method of claim 1, wherein the operational parameters comprise one or more selected from a group consisting of environmental variables, composition components, and pricing information.', '3.', 'The method of claim 1, wherein the statistical model comprises historical data of laboratory results for composition components and prior composition designs.', '4.', 'The method of claim 1, wherein the final composition design comprises usage information for the final composition design and/or pricing information.', '5.', 'The method of claim 1, further comprising validating the final composition design.', '6.', 'The method of claim 1, further comprising predicting the performance of the modified composition design using the statistical model.', '7.', 'The method of claim 1, wherein the final composition design comprises one or more selected from a group consisting of composition component concentrations, order of composition component addition, pumping schedule, and reaction times.', '8.', 'The method of claim 1, wherein optimizing comprises modifying the initial composition design to generate a modified composition design by adjusting one or more selected from a group consisting of composition component concentration, composition component cost, composition design rheology, and pumping rate.', '9.', 'The method of claim 8, further comprising predicting the performance of the modified composition design using the statistical model.', '10.', 'The method of claim 1, wherein the initial composition design comprises a composition that hardens to form a polymer or cement, and wherein the operational parameters comprise setting time and/or hardness.', '11.', 'A method comprising:\ndefining operational parameters for an initial composition design for a wellbore fluid composition, wherein the operational parameters comprise geometry of a wellbore; wellbore modeling parameters related to vertical stresses, horizontal stresses and permeability; environmental variables; composition components pricing information; and temperature;\ngenerating an initial composition design from the defined operational parameters;\npredicting the performance of the initial composition design using a statistical model;\ncomparing the performance of the initial composition design with the operational parameters;\noptimizing the initial composition design according to the defined operational parameters so as to reduce wear and corrosion of well equipment located in the wellbore, the optimization being achieved by using modeling, based on individual fluid and solid components of the initial composition design, which incorporates optimization routines allowing input of operation specific parameters;\nfurther optimizing the initial composition design by iteratively repeating the stages of predicting, comparing, and optimizing;\nusing data from a historical database to reduce errors during optimizing the initial composition design;\noutputting a final composition design;\nvalidating the final composition design at least in part by laboratory experiment; and\ncompiling experimental data from each laboratory experiment into the historical database.\n\n\n\n\n\n\n12.', 'The method of claim 11, wherein the operational parameters further comprise one or more selected from a group consisting of a safe mud weight window, cementing weight, cement type, casing type, production tubing type, perforation method, and casing point locations.', '13.', "The method of claim 11, wherein the operational parameters comprise one or more formation properties selected from a group consisting of vertical stress, pore pressure, horizontal stresses, reservoir porosity, permeability, vertical permeability, lateral permeability, mechanical properties such as Poisson's Ratio, and Young's Modulus.\n\n\n\n\n\n\n14.", 'The method of claim 11, wherein the statistical model comprises historical data of laboratory results for composition components and prior composition designs.', '15.', 'The method of claim 11, wherein the final composition design comprises usage information for the final composition design and/or pricing information.', '16.', 'The method of claim 11, further comprising updating the statistical model to contain data obtained from validating the final composition design.', '17.', 'The method of claim 11, wherein the final composition design comprises one or more selected from a group consisting of composition component concentrations, order of composition component addition, pumping schedule, and reaction times.', '18.', 'The method of claim 11, wherein optimizing comprises modifying the initial composition design to generate a modified composition design by adjusting one or more selected from a group consisting of composition component concentration, composition component cost, composition design rheology, and pumping rate.', '19.', 'The method of claim 11, wherein the initial composition design comprises a composition that hardens to form a polymer or cement, and wherein the operational parameters comprise setting time and/or hardness.'] | ['FIG.', '1 is an illustration of a completions operation in which cement is installed in an annular region created between a borehole and an installed casing in accordance with embodiments of the present disclosure.', '; FIG.', '2 is a schematic depicting a flow diagram in accordance with embodiments of the present disclosure.', '; FIG.', '3 is a computer system in accordance with embodiments of the present disclosure.'] |
|
US11119237 | Methods and systems for determining fast and slow shear directions in an anisotropic formation using a logging while drilling tool | Apr 13, 2017 | Pu Wang, Sandip Bose, Bikash Kumar Sinha, Ting Lei | SCHLUMBERGER TECHNOLOGY CORPORATION | Alford, J. et al., “Sonic Logging While Drilling-Shear Answers,” Oilfield Review, 2012, 24(1), pp. 4-15.; Alford, R. M., “Shear Data in the Presence of Azimuthal Anisotropy: Dilley, Texas”, SEG Technical Expanded Abstracts, 1986, pp. 476-479.; Arroyo Franco, J. L et al., “Sonic Investigations in and Around the Borehole,” Oilfield Review, 2006, 18(1), pp. 14-31.; Bose, S. et al., “Anisotropy Processing Without Matched Cross-dipole Transmitters”, presented at the 75th Annual Meeting, SEG Technical Program Expanded Abstracts, 2007, pp. 114-118.; Ekstrom, M. E., “Dispersion Estimation from Borehole Acoustic Arrays Using a Modified Matrix Pencil Algorithm”, presented at the 29th Asilomar Conference on Signals, Systems, and Computers, Pacific Grove, California, USA, 1995, 1, pp. 449-453.; Esmersoy, C. et al., “Dipole shear anisotropy logging”, presented at the 64th Annual Meeting, SEG Technical Program Expanded Abstracts, 1994, pp. 1139-1142.; Haldorsen, J. B. U. et al., “Borehole Acoustic Waves,” Oilfield Review, 2006, 18(1), pp. 34-43.; Sinha, B. K. et al., “Borehole Dipole and Quadrupole Modes in Anisotropic Formations”, 2003 IEEE Ultrasonics Symposium Proceedings, pp. 284-289.; Sinha, B. K. et al., “Elastic wave propagation in deviated wells in anisotropic formations”, Geophysics, 2006, 71(6), pp. D191-D202.; Sinha, B. K. et al., “Influence of a pipe tool on borehole modes”, Geophysics, 2009, 74(3), pp. E111-E123.; Sinha, B. K. et al., “Sonic logging in deviated wellbores in the presence of a drill collar”, presented at the 2010 SEG Annual Meeting and Exposition, Expanded Abstracts, Denver, Colorado, USA, pp. 553-557.; Tang, X. M. et al., “A curve-fitting method for analyzing dispersion characteristics of guided elastic waves”, presented at the 79th SEG Annual Meeting, Houston, SEG Technical Program Expanded Abstracts, 2009, pp. 461-465.; Wang, P. et al., “Broadband Dispersion Extraction of Borehole Acoustic Modes via Sparse Bayesian Learning”, presented at the 5th IEEE International Workshop on Computational Advances in Multi-Sensor Adaptive Processing, Saint Martine, 2013, pp. 268-271.; Wang, P. et al., Dipole Shear Anisotropy Using Logging-While-Drilling Sonic Tools, presented at the SPWLA 57th Annual Symposium, Reykjavik, Iceland, 2016, 14 pages. | 6718266; April 6, 2004; Sinha et al.; 7120541; October 10, 2006; Wang; 8339897; December 25, 2012; Keron et al.; 20040158997; August 19, 2004; Tang; 20100034052; February 11, 2010; Pabon; 20110019501; January 27, 2011; Market; 20120026831; February 2, 2012; Mickael; 20150012251; January 8, 2015; Horne et al.; 20170115413; April 27, 2017; Wang et al.; 20170115414; April 27, 2017; Wang et al. | 2015021004; February 2015; WO | ['Methods are provided for determining properties of an anisotropic formation (including both fast and slow formations) surrounding a borehole.', 'A logging-while-drilling tool is provided that is moveable through the borehole.', 'The logging-while drilling tool has at least one dipole acoustic source spaced from an array of receivers.', 'During movement of the logging-while-drilling tool, the at least one dipole acoustic source is operated to excite a time-varying pressure field in the anisotropic formation surrounding the borehole.', 'The array of receivers is used to measure waveforms arising from the time-varying pressure field in the anisotropic formation surrounding the borehole.', 'The waveforms are processed to determine a parameter value that represents shear directionality of the anisotropic formation surrounding the borehole.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION(S)\n \nThe subject disclosure claims priority from U.S. Provisional Appl.', 'No. 62/322,870, filed on Apr. 15, 2016,', 'herein incorporated by reference in its entirety.', 'TECHNICAL FIELD', 'The subject disclosure relates to the investigation of earth formations.', 'More particularly, the subject disclosure relates to methods of measuring formation characteristics using logging-while-drilling (LWD) acoustic measurement tools.\n \nBACKGROUND\n \nWireline borehole acoustic logging is a major part of subsurface formation evaluation that is important in oil and gas exploration and production.', 'The logging is achieved by lowering a wireline acoustic measurement tool comprising at least one transmitter and an array of receivers into a fluid-filled well, exciting the transmitter(s), recording resulting acoustic waveforms at the receivers, and processing the recorded waveforms to obtain a depth log of slowness measurements (where slowness is the reciprocal of velocity) along the well.', 'The acoustic propagation in the borehole is affected by the properties of rocks surrounding the wellbore.', 'More specifically, the fluid-filled borehole supports propagation of certain number of borehole guided modes that are generated by a transducer placed inside the borehole fluid.', 'These borehole acoustic modes are characterized by their acoustic slowness dispersions which contain valuable information about the rock mechanical properties.', 'Therefore, the acoustic logging can provide answers pertaining to such properties with diverse applications such as geophysical calibration of seismic imaging, geomechanical assessment of wellbore stability, and stress characterization for fracture stimulation.', 'Examples of such acoustic logging are described in i)', 'J. L. A. France, M. A. M. Ortiz, G. S. De, L. Renlie and S. Williams, “Sonic investigations in and around the borehole,” \nOilfield Review\n, vol.', '18, no. 1, pp. 14-31, March 2006; ii) J. B. U. Haldorsen, D. L. Johnson, T. Plona, B. Sinha, H.-P. Valero and K. Winker, “Borehole acoustic waves,” \nOilfield Review\n, vol.', '18, no. 1, pp.', '34-43, March 2006; and iii) J. Alford, M. Blyth, E. Tollefsen, J. Crowe, J. Loreto, S. Mohammed, V. Pistre, and A. Rodriguez-Herrera, “Sonic logging while drilling—shear answers,” \nOilfield Review\n, vol.', '24, no. 1, pp.', '4-15, January 2012.', 'Logging-while-drilling (LWD) acoustic tools such as SonicScope 475 and SonicScope 825 of Schlumberger Technology Corporation have been demonstrated to save a great amount of rig time and to help improve the drilling efficiency and safety.', 'Processing of the sonic data from the LWD acoustic tools provides monopole compressional and shear slownesses in fast formations and quadrupole shear slowness mostly in slow formations.', 'However, both monopole and quadrupole shear slownesses cannot provide a complete anisotropy characterization.', 'To have a complete anisotropy characterization, one of the most important inputs is the fast-shear azimuthal direction and/or slow shear azimuthal direction, which are desirable for subsequent stress and mechanical analyses of the rock properties around the borehole.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'Methods are provided for determining properties of an anisotropic formation (including both fast and slow formations) surrounding a borehole.', 'A logging-while-drilling tool is provided that is moveable through the borehole.', 'The logging-while drilling tool has at least one dipole acoustic source spaced from an array of receivers.', 'During movement of the logging-while-drilling tool, the at least one dipole acoustic source is operated to excite a time-varying pressure field in the anisotropic formation surrounding the borehole.', 'The array of receivers are used to measure waveforms arising from the time-varying pressure field in the anisotropic formation surrounding the borehole.', 'The waveforms are processed to determine shear directionality of the anisotropic formation surrounding the borehole.', 'Additional aspects, embodiments, objects and advantages of the disclosed methods may be understood with reference to the following detailed description taken in conjunction with the provided drawings.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a schematic diagram of a transversely isotropic formation with a vertical axis of symmetry (TIV).', 'FIG.', '2\n is a schematic diagram of a transversely isotropic formation with a horizontal axis of symmetry (TIH).', 'FIG.', '3\n is a schematic diagram illustrating a drill-colar mode (dashed curve labeled “blue”) that propogates in a Logging-While-Drilling (LWD) acoustic measurement tool and that interferes with a formation mode (dashed curve labeled “green”).', 'FIGS.', '4A and 4B\n are schematic diagrams illustrating cross-dipole orthogonal firing of a wireline acoustic measurement tool.', 'FIGS.', '5A and 5B\n are schematic diagrams illustrating non-orthogonal dipole firings of an LWD acoustic measurement tool.\n \nFIG.', '6\n is a schematic diagram of a wellsite system that can be used in practicing the embodiments of the subject disclosure.', 'FIG.', '7\n is a schematic diagram of a LWD acoustic measurement tool that can be used in practicing the embodiments of the subject disclosure.', 'FIG.', '8\n is a flowchart illustrating a time-domain workflow according to an embodiment of the subject disclosure.', 'FIGS.', '9A and 9B\n illustrate synthetic time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, of a dipole transmitter in the horizontal section of a fast TIV formation.\n \nFIG.', '9C\n illustrates the slowness dispersions of the synthetic time-domain waveforms of \nFIGS.', '9A and 9B\n in the horizontal section of a fast TIV formation.', 'FIG.', '10\n illustrates a two-dimensional cost function of the four-component non-orthogonal LWD waveform rotation for the example of \nFIGS.', '9A, 9B and 9C\n.', 'FIGS.', '11A and 11B\n illustrate rotated time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, for the example of \nFIGS.', '9A, 9B and 9C\n.\n \nFIG.', '11C\n illustrates the slowness dispersions of the rotated time-domain waveforms of \nFIGS.', '11A and 11B\n in the horizontal section of the fast TIV formation.', 'FIGS.', '12A and 12B\n illustrate synthetic time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, from a dipole source in the horizontal section of a fast TIV formation.', 'The D1 and D2 firings are, respectively, 35 and 67 degrees away from the slow shear azimuth.\n \nFIG.', '12C\n illustrates the slowness dispersions of the time-domain waveforms of \nFIGS.', '12A and 12B\n in the horizontal section of the fast TIV formation.', 'FIG.', '13\n illustrates a two-dimensional cost function of the four-component non-orthogonal LWD waveform rotation for the example of \nFIGS. 12A, 12B and 12C\n.\n \nFIGS.', '14A and 14B\n illustrate rotated time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, for the example of \nFIGS.', '12A, 12B and 12C\n.', 'FIG.', '14C\n illustrates the slowness dispersions of the rotated time-domain waveforms of \nFIGS.', '14A and 14B\n in the horizontal section of the fast TIV formation.', 'FIGS.', '15A and 15B\n illustrate rotated time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, from a dipole source in the horizontal section of a slow TIV formation.\n \nFIG.', '15C\n illustrates the slowness dispersions of the rotated time-domain waveforms of \nFIGS.', '15A and 15B\n in the horizontal section of the slow TIV formation.', 'FIG.', '16\n is a flowchart illustrating a frequency-domain workflow according to an embodiment of the subject disclosure.', 'FIG.', '17\n is a schematic diagram illustrating shear wave splitting arising from a dipole transmitter in anisotropic formations and principal polarization directions.\n \nFIG.', '18A\n illustrates an exemplary model slowness dispersion of the fast and slow coupled collar-formation flexural modes arising from a dipole firing which is 45° away from the fast shear direction in a slow formation.', 'The solid dots between 3.5 and 6 kHz represents a band limited dispersion used in the frequency-domain workflow.\n \nFIG.', '18B\n shows an exemplary one-dimensional LWD-DATC cost function, which is constructed using raw inline and crossline waveforms between 3.5 and 6 kHz.\n \nFIG.', '19A\n shows two exemplary slowness dispersions of the fast and slow coupled collar-formation flexural modes arising from a dipole firing which is 45° away from the fast shear direction in a slow formation (same as \nFIG.', '18A\n), where the slowness dispersions are extracted from pre-rotated inline and crossline waveforms with a pre-determined angle of 60°.', 'FIG.', '19B\n shows an exemplary one-dimensional LWD-DATC cost function constructed from selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes of \nFIG.', '19A\n.', 'FIG.', '20A\n shows two exemplary slowness dispersions of the fast and slow coupled collar-formation flexural modes arising from a dipole firing that is 67° away from the fast shear direction (different from \nFIGS.', '18A and 19A\n) in a slow formation, where the slowness dispersions are extracted from pre-rotated inline and crossline waveforms with a pre-determined angle of 60°.', 'FIG.', '20B\n shows an exemplary one-dimensional LWD-DATC cost function constructed from selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes of \nFIG.', '20A\n.', 'FIG.', '20C\n shows rotated inline and crossline waveforms for the example of \nFIG.', '20A\n when the inline receivers are parallel to the fast shear direction of the slow formation.', 'FIG.', '21A\n shows two exemplary slowness dispersions of the fast and slow coupled collar-formation flexural modes arising from a dipole firing that is 85° away from the fast shear direction in a fast formation, where the slowness dispersions are extracted from raw (non-rotated) inline and crossline waveforms\n \nFIG.', '21B\n shows an exemplary one-dimensional LWD-DATC cost function constructed from selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes of \nFIG.', '21A\n.', 'FIG.', '21C\n shows rotated inline and crossline waveforms for the example of \nFIG.', '21A\n when the inline receivers are parallel to the fast shear direction of the fast formation.', 'FIG.', '22\n shows an example computing system that can be used to implement the time-domain and frequency domain workflows as described herein.', 'DETAILED DESCRIPTION', 'The particulars shown herein are by way of example and for purposes of illustrative discussion of the examples of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure.', 'In this regard, no attempt is made to show details in more detail than is necessary, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice.', 'Furthermore, like reference numbers and designations in the various drawings indicate like elements.', 'As used throughout the specification and claims, the term “downhole” refers to a subterranean environment, particularly in a well or wellbore.', '“Downhole tool” is used broadly to mean any tool used in a subterranean environment including, but not limited to, a logging tool, an imaging tool, an acoustic tool, a permanent monitoring tool, and a combination tool.', 'The various techniques disclosed herein may be utilized to facilitate and improve data acquisition and analysis in downhole tools and systems.', 'In this disclosure, downhole tools and systems are provided that utilize arrays of sensing devices that are configured or designed for easy attachment and detachment in downhole sensor tools or modules that are deployed for purposes of sensing data relating to environmental and tool parameters downhole, within a borehole.', 'The tools and sensing systems disclosed herein may effectively sense and store characteristics relating to components of downhole tools as well as formation parameters at elevated temperatures and pressures.', 'Chemicals and chemical properties of interest in oilfield exploration and development may also be measured and stored by the sensing systems contemplated by the present disclosure.', 'The sensing systems herein may be incorporated in tool systems such as wireline logging tools, measurement-while-drilling and logging-while-drilling tools, permanent monitoring systems, drill bits, drill collars, sondes, among others.', 'For purposes of this disclosure, when any one of the terms wireline, cable line, slickline or coiled tubing or conveyance is used it is understood that any of the referenced deployment means, or any other suitable equivalent means, may be used with the present disclosure without departing from the spirit and scope of the present disclosure.', 'Moreover, inventive aspects lie in less than all features of a single disclosed embodiment.', 'Thus, the claims following the Detailed Description are hereby expressly incorporated into this Detailed Description, with each claim standing on its own as a separate embodiment.', 'Borehole acoustic logging is a major part of subsurface formation evaluation that is key to oil and gas exploration and production.', 'The logging may be achieved using an acoustic measurement tool, which includes one or multiple acoustic transducers, or sources, and one or multiple sensors, or receivers.', 'The acoustic measurement tool may be deployed in a fluid-field wellbore for purposes of exciting and recording acoustic waveforms.', 'The receivers thus, may acquire data representing acoustic energy that results from the acoustic energy that is emitted by the acoustic sources of the acoustic measurement tool.', 'The acoustic propagation in the borehole is affected by the properties of rocks surrounding the wellbore.', 'More specifically, the fluid-filled borehole supports propagation of certain number of borehole guided modes that are generated by energy from a source that is placed inside the borehole fluid.', 'These borehole acoustic modes are characterized by their acoustic slowness (i.e., reciprocal of velocity) dispersions, which contain valuable information about the rock mechanical properties.', 'Therefore, the acoustic logging may provide answers pertaining to such diverse applications as geophysical calibration of seismic imaging, geomechanical assessment of wellbore stability, and stress characterization for fracture stimulation.', 'In the context of this application, “acoustic energy” or “sonic energy” refers to energy in the sonic frequency spectrum, and may be, as example, energy between 200 Hertz (Hz) and 30 kiloHertz (kHz).', 'In general, the energy that is emitted by the sources of the acoustic measurement tool may travel through rock formations as either body waves or surface waves (called “flexural waves” herein).', 'The body waves include compressional waves, or P-waves, which are waves in which small particle vibrations occur in the same direction as the direction in which the wave is traveling.', 'The body waves may also include shear waves, or S-waves, which are waves in which particle motion occurs in a direction that is perpendicular to the direction of wave propagation.', 'In addition to the body waves, there are a variety of borehole guided modes whose propagation characteristics can be analyzed to estimate certain rock properties of the surrounding formation.', 'For instance, axi-symmetric Stoneley and borehole flexural waves are of particular interest in determining the formation shear slownesses.', 'As described herein, the flexural waves may also include waves that propagate along the acoustic measurement tool.', 'The acoustic measurement tool may include multiple acoustic sources that are associated with multiple source classifications, or categories.', 'For example, the acoustic measurement tool may include one or multiple monopole sources.', 'In response to energy from a monopole sonic source, the receivers of the acoustic measurement tool may acquire data representing energy attributable to various wave modes, such as data representing P-waves, S-waves and Stoneley waves.', 'The acoustic measurement tool may also include one or multiple directional sources, such as dipole or quadrupole sources, which produce additional borehole guided waves, which travel through the fluid in the borehole and along the acoustic measurement tool itself.', 'Data representing these flexural waves may be processed for such purposes as determining the presence or absence of azimuthal anisotropy.', 'For example, implementations that are described herein, the data representing the flexural waves is processed for purposes of determining a formation shear slowness.', 'The speeds at which the aforementioned waves travel are affected by various properties of the downhole environment, such as the rock mechanical properties, density and elastic dynamic constants, the amount and type of fluid present in the formation, the makeup of rock grains, the degree of inter-grain cementation and so forth.', 'Therefore, by measuring the speed of acoustic wave propagation in the borehole, it is possible to characterize the surrounding formations based on sensed parameters relating to these properties.', 'The speed, or velocity of a given sonic wave, or waveform, may be expressed in terms of the inverse of its velocity, which is referred to herein as the “slowness.”', 'In this context, an “acoustic wave” or “acoustic waveform” may refer to a particular time segment of energy recorded by one or multiple receivers and may correspond to a particular acoustic waveform mode, such as a body wave, flexural or other guided borehole waves.', 'Certain acoustic waves are non-dispersive, or do not significantly vary with respect to frequency.', 'Other acoustic waves, however, are dispersive, meaning that the wave-slownesses vary as a function of frequency.', 'The acoustic measurement tool may be deployed on a number of platforms, such as a wireline tool or a logging while drilling (LWD) platform.', 'In other words, an LWD acoustic measurement tool is disposed on a drilling string, or pipe.', 'Newly introduced logging-while-drilling (LWD) acoustic measurement tools have been demonstrated to save a great amount of rig time and to help drill more efficiently with greater safety margins.', 'Recent progress has enabled LWD acoustic measurement tools to deliver compressional and shear slowness logs in the fast and slow formations using monopole and quadrupole transmitters.', 'In this context, a “fast formation” refers to a formation in which the shear wave velocity is greater than the compressional velocity of the borehole fluid (or “drilling mud”).', 'Otherwise, the formation is a “slow” formation.', 'However, due to their azimuthal characteristics, the LWD acoustic measurement tools can be used to obtain only a single reliable shear slowness estimate which is appropriate for isotropic and TIV (transversely isotropic with a vertical axis of symmetry) formations.', 'An example TIV formation is shown in \nFIG.', '1\n.', 'In the TIV formation, elastic properties are uniform horizontally, but vary vertically.', 'Currently, there are no reliable techniques for obtaining the fast and slow shear slownesses in anisotropic formations (such as transversely isotropic with a horizontal axis of symmetry or TIH formations) or orthorhombic formations, because they require the use of directional dipole firings.', 'For example, see i) J. Alford, M. Blyth, E. Tollefsen, J. Crowe, J. Loreto, S. Mohammed, V. Pistre, and A. Rodriguez-Herrera, “Sonic logging while drilling—shear answers,” \nOilfield Review\n, vol.', '24, no. 1, pp.', '4-15, January 2012; ii) B. K. Sinha and E. Simsek, “Sonic logging in deviated wellbores in the presence of a drill collar”, 2010 \nSEG Annual Meeting and Exposition\n, Expanded Abstracts, Denver, Colo.; iii) B. K. Sinha, E. Simsek, and Q-H. Liu, “Elastic wave propagation in deviated wells in anisotropic formations”, \nGeophysics, \n71(6), D191-D202, 2006; iv) B. K. Sinha, J. Pabon and C-J. Hsu, “Borehole dipole and quadrupole modes I anisotropic formations”, 2003 IEEE Ultrasonics Symposium Proc., 284-289; and v) B. K. Sinha, E. Simsek, and S. Asvadurov, “Influence of a pipe tool on borehole modes”, \nGeophysics\n, vol.', '74(3), May-June, 2009.', 'An example TIH formation is shown in \nFIG.', '2\n.', 'In the TIH formation, elastic properties are uniform in vertical planes parallel to fractures, but vary in the perpendicular horizontal direction.', 'In an anisotropic formation, firing of the dipole transmitters generally excites both the fast and slow flexural waves, behaving like the shear-wave splitting, with different polarizations and different velocities.', 'The shear waves polarized parallel to layering in the TIV formation (e.g., a shale) or vertical fractures in the TIH formation (e.g., a formation with aligned vertical fractures) travel faster than the shear waves polarized orthogonal to the layering or fracture.', 'Therefore, the azimuth direction of the fast shear, slow shear and flexural waves can be detected by using firing from cross-dipole transmitters (e.g., cross-dipole orthogonal firings) in a wireline acoustic measurement tool.', 'Once the azimuth direction of the fast shear and slow shear is determined, the raw dipole waveforms can be rotated to yield waveforms propagating with the fast and slow shear polarizations.', 'Then the fast and slow shear slownesses can be extracted from these rotated waveforms corresponding to the fast and slow shear azimuth directions.', 'In summary, both the fast and slow shear slownesses together with the fast shear azimuth direction are inputs to a complete formation anisotropy characterization.', "Wireline acoustic measurement tools, such as Schlumberger's Sonic Scanner™, has been commercialized to provide such complete formation anisotropy characterization.", 'However, the same anisotropy characterization has not been available in LWD acoustic measurement tools, due to a number of fundamental challenges in LWD acoustic measurement tools.', 'These challenges include the following: \n \n \n \nstrong interference and coupling from collar modes in LWD acoustic measurement tools;\n \ncross-dipole orthogonal firing cannot be maintained in LWD acoustic measurement tools;\n \ntool eccentering in LWD acoustic measurement tools; and\n \nsignal-to-noise ratio (SNR) in LWD acoustic measurement tools.', 'With regard to the first challenge regarding strong interference and coupling from collar modes in the LWD acoustic measurement tool, the LWD acoustic measurement tool has to be mechanically competent for drilling and the drill-collar mode interferes with the formation mode of interest.', 'This is unlike the wireline Sonic Scanner™.', 'In fact, the drill-collar mode dominates the acoustic response especially for the dipole flexural modes in fast formations and strongly couples with the formation mode of interest.', 'Note that a LWD acoustic measurement tool consists of a stiff drill collar to survive the harsh drilling environment.', 'As shown in \nFIG.', '3\n, the stiff drill-collar supports propagation of a drill-collar mode (dashed blue curve) that interferes with a formation flexural mode (dashed green curve).', 'The drill-collar mode intersects the formation flexural mode in a fast formation.', 'As these two modes interact in a composite structure, they cannot simply overlay on top of each other.', 'Instead, they repel one from the other to form the coupled collar-formation mode (top blue solid curve, also referred to as the tool flexural mode) and the formation-collar mode (bottom green solid curve, also referred to as the formation flexural mode).', 'Moreover, the drill-collar flexural mode is usually the dominant one.', 'Therefore, a conventional wireline dipole workflow developed for handling a single formation mode cannot be applied to this complex scenario.', 'The second challenge stems from the fact that the cross-dipole orthogonal firing is unavailable in the LWD acoustic measurement tool due to tool pipe rotation and therefore cannot be assumed.', 'The cross-dipole orthogonal firing in a wireline acoustic measurement tool is shown in \nFIGS.', '4A and 4B\n.', 'The wireline acoustic measurement tool includes an array of receivers or receiver stations (labeled 1, 2, 3, 4) that are offset at 90 degrees relative to one another about the circumference of the wireline acoustic measurement tool.', 'FIG.', '4A\n shows the cross-sectional coordinate system of the X-Dipole firing.', 'The X-Dipole direction, which is denoted by the solid line with arrow, is offset θ-degrees from the fast shear direction.', 'This fast shear direction aligns with the inline receivers (e.g., the azimuthal receiver stations 1 and 3) and perpendicular to the crossline receivers (e.g., the azimuthal receiver stations 2 and 4) of the receiver array for the X-Dipole firing.', 'The fast and slow shear directions are denoted as dashed black lines with arrows in \nFIG.', '4A\n.', 'FIG.', '4B\n shows the cross-sectional coordinate system of the Y-Dipole firing.', 'The Y-Dipole direction, which is denoted by the solid line with arrow, is (θ+90°)-degree away from the fast shear direction.', 'This fast shear direction aligns with the inline receivers (e.g., the azimuthal receiver stations 2 and 4) and perpendicular to the crossline receivers (e.g., the azimuthal receiver stations 1 and 3) for the Y-dipole firing.', 'The fast and slow shear directions are denoted as dashed black lines with arrows in \nFIG.', '4B\n.', 'The cross-dipole orthogonal firing (X-dipole firing/Y-dipole firing) of the wireline acoustic measurement tool enables acquisition of four-component waveforms for the receiver array.', 'The four-component waveforms include an X-Inline waveform, an X-Crossline waveform, a Y-Inline waveform, and a Y-Crossline waveform.', 'The four-component waveforms can be synthetically rotated towards the fast and slow shear polarization directions by minimizing the total crossline energy, for example via the Alford rotation algorithm as described in i) R. M. Alford, “Shear data in the presence of azimuthal anisotropy,” 56th Ann.', 'Internat.', 'Mtg., Sot. Explor.', 'Geophys., Expanded Abstracts, 476-479, 1986; and ii) C. Esmersoy, K. Koster, M. Williams, A. Boyd and M. Kane, “Dipole shear anisotropy logging”, 64th Ann.', 'Internat.', 'Mtg., Soc.', 'Expl.', 'Geophys., Expanded Abstracts, 1139-1142, 1994.', 'In contrast to the wireline acoustic measurement tool, the orthogonality of the two LWD dipole firings for each depth is no longer maintained due to the fast tool rotation with variable speeds during the drilling process.', 'An example of the two LWD dipole firings is shown in \nFIGS.', '5A and 5B\n.', 'Note that the LWD acoustic measurement tool also includes an array of receivers or receiver stations (labeled 1, 2, 3, 4) that are offset at 90 degrees relative to one another about the circumference of the LWD acoustic measurement tool.', 'FIG.', '5A\n shows the cross-sectional coordinate system of the D1 (Dipole-1) firing.', 'The D1 direction, which is denoted by the solid line with arrow, is offset θ-degrees from the fast shear direction.', 'This fast shear direction aligns with the inline receivers (e.g., the azimuthal receiver stations 1 and 3) and perpendicular to the crossline receivers (e.g., the azimuthal receiver stations 2 and 4) of the receiver array for the D1 firing.', 'The fast and slow shear directions are denoted as dashed black lines with arrows in \nFIG.', '5A\n.', 'FIG.', '5B\n shows the cross-sectional coordinate system of the D2 firing.', 'The D2 direction, which is denoted by the solid line with arrow, is offset (θ+ϕ)-degrees from the fast shear direction.', 'The fast shear direction aligns with the inline receivers (e.g., the azimuthal receiver stations 2 and 4) and perpendicular to the crossline receivers (e.g., the azimuthal receiver stations 1 and 3) of the array for the D2 firing.', 'The D1 and D2 dipole firings of the LWD acoustic measurement tool enables acquisition of four-component waveforms for the receiver array.', 'The four-component waveforms include an X-Inline waveform, an X-Crossline waveform, a Y-Inline waveform, and a Y-Crossline waveform.', 'Due to the non-orthogonal nature of the D1 and D2 firings, the four-component Alford waveform rotation used for the wireline acoustic measurement tool cannot be applied to the four-components waveforms of the LWD acoustic measurement tool.', 'The third challenge stems from eccentering of the LWD acoustic measurement tool during the LWD operations.', 'Since the fast rotation of drill string precludes the use of centralizers with the LWD acoustic measurement tools, stabilizers are used to limit the amount of eccentering.', 'However, the use of these stabilizers cannot provide a complete centralization of the LWD acoustic measurement tool.', 'The amount of tool eccentering is further aggravated in deviated wells.', 'Large amount of eccentering poses additional challenges for the anisotropic processing of LWD dipole sonic data.', 'The fourth challenge stems from the SNR of the LWD acoustic measurement tool.', 'Compared with the wireline logging environment, the acquired data in the LWD environment is usually corrupted by the drilling noise, shocks, and vibration.', 'Furthermore, the directional nature of the dipole transmitters precludes the use of waveform stacking as used for the monopole and quadrupole logging with a rotating drill string.', 'To overcome the aforementioned challenges, the present disclosure introduces two independent workflows that can be used to calculate a parameter value that characterizes the fast shear azimuth direction of the formation from the processing of dipole waveforms acquired by an LWD-acoustic measurement tool.', 'The first workflow consists of a time-domain, non-orthogonal waveform rotation algorithm using the four-component waveforms from the two non-orthogonal LWD dipole firings.', 'The second workflow is based on a frequency-domain processing of the dipole sonic data.', 'This processing is a multi-component rotation algorithm that accounts for the presence of the drill collar and its associated drill-collar flexural mode in the recorded dipole waveforms.', 'The output from either of the two workflows is a parameter value that represents the fast shear azimuth direction of the formation, which can be used as an input to the formation stress and fracture analyses.', 'For example, the parameter value that represents the fast shear azimuth direction of the formation can be used to synthetically rotate the LWD dipole waveforms acquired by a LWD acoustic measurement tool to point toward the fast and slow shear directions.', 'Then the fast and slow formation shear slownesses can be estimated from the rotated waveforms using a data-driven or model-based and/or workflow.', 'Thus, by cascading the LWD dipole waveform rotation and the dipole shear slowness estimation, complete characterization of the anistropy of the formation can be provided by the LWD tool.', 'An example of a workflow that estimates fast and slow formation shear slownesses from acoustic waveforms is described in U.S. patent application Ser.', 'No. 15/331,946, filed on Oct. 24, 2016, entitled “Determining Shear Slowness from Dipole Source-based Measurements Acquired by a Logging-While-Drilling Acoustic Measurement Tool.”', 'In this workflow, for the case where the acoustic measurements are acquired in a fast formation and are associated with a relatively high SNR (an SNR at, near or above 20 dB, for example), the fast and slow formation shear slownesses can be determined from a low frequency formation flexural asymptote engine, which bases the shear slowness determination on a low-frequency asymptote of extracted flexural dispersions.', 'For the other cases (slow formations or fast formation coupled with a lower SNR), the fast and slow formation shear slownesses can be determined from a model-based inversion engine, which employs a model that explicitly accounts for the presence of the acoustic measurement tool in the borehole.', 'As such, the model-based inversion engine may consider such model inputs as compressional slowness, formation density, mud density, hole diameter, and so forth.', 'Therefore, for the slow formation, when the tool flexural acoustic mode significantly interferes with the formation flexural acoustic mode at the low frequency region, the model-based inversion is used, as the low-frequency asymptote of the extracted flexural dispersion no longer converges to the shear slowness.', 'In accordance with example implementations, the model-based inversion engine can use a boundary condition determinant associated with a concentrically placed cylindrical structure to construct the cost function and estimate multiple physical parameters of interest from numerical optimization techniques.', 'Another example of a workflow that estimates fast and slow formation shear slownesses from acoustic waveforms is described in U.S. patent application Ser.', 'No. 15/331,958, filed on Oct. 24, 2016, entitled “Determining Shear Slowness Based on a High Order Formation Flexural Acoustic Mode.”', 'In this workflow, acoustic modes (including the first and third order formation flexural acoustic modes) are extracted from the acoustic waveforms.', 'The extracted acoustic modes are processed by a high frequency slowness frequency analysis (HF-SFA) engine based on input parameters (such as a slowness range and a frequency range).', 'These ranges may be user selected, in accordance with example implementations.', 'The HF-SFA engine non-coherently integrates the dispersion energy along the frequency axis to provide an output.', 'A peak finding engine identifies at least one peak in the integrated energy, and this peak corresponds to an estimated or determined shear slowness.', 'FIG.', '6\n illustrates a wellsite system in which the workflows of the present disclosure can be employed.', 'The wellsite can be onshore or offshore.', 'In this exemplary system, a borehole \n11\n is formed in subsurface formations by rotary drilling in a manner that is well known.', 'Embodiments of the present disclosure can also use directional drilling, as will be described hereinafter.', 'A drill string \n12\n is suspended within the borehole \n11\n and has a bottom hole assembly \n100\n which includes a drill bit \n105\n at its lower end.', 'The surface system includes platform and derrick assembly \n10\n positioned over the borehole \n11\n.', 'The assembly \n10\n includes a rotary table \n16\n, kelly \n17\n, hook \n18\n and rotary swivel \n19\n.', 'The drill string \n12\n is rotated by the rotary table \n16\n, energized by means not shown, which engages the kelly \n17\n at the upper end of the drill string.', 'The drill string \n12\n is suspended from a hook \n18\n, attached to a traveling block (also not shown), through the kelly \n17\n and a rotary swivel \n19\n which permits rotation of the drill string relative to the hook.', 'As is well known, a top drive system could alternatively be used.', 'In the example of this embodiment, the surface system further includes drilling fluid or mud \n26\n stored in a pit \n27\n formed at the well site.', 'A pump \n29\n delivers the drilling fluid \n26\n to the interior of the drill string \n12\n via a port in the swivel \n19\n, causing the drilling fluid to flow downwardly through the drill string \n12\n as indicated by the directional arrow \n8\n.', 'The drilling fluid exits the drill string \n12\n via ports in the drill bit \n105\n, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows \n9\n.', 'In this well known manner, the drilling fluid lubricates the drill bit \n105\n and carries formation cuttings up to the surface as it is returned to the pit \n27\n for recirculation.', 'The bottom hole assembly \n100\n of the illustrated embodiment has a logging-while-drilling (LWD) tool \n120\n, a measuring-while-drilling (MWD) tool \n130\n, a roto-steerable system \n150\n, and drill bit \n105\n.', 'In other embodiments, the bottom hole assembly \n100\n can include a mud motor that is powered by the flow of the drilling fluid and drives the rotation of the drill bit \n105\n.', 'The LWD tool \n120\n is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools.', 'It will also be understood that more than one LWD and/or MWD tools can be employed, e.g. as represented at \n120\nA. The LWD tool includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment.', 'In the present embodiment, the LWD tool includes at least a dipole transmitter that transmits directional D1 and D2 dipole firings and an array of receivers for receiving the four-component waveforms of the acoustic energy that results from the directional D1 and D2 dipole firings as described herein.', 'The MWD module \n130\n is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit.', 'In the present embodiment, the MWD module includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.', 'The LWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system.', 'This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed.', 'FIG.', '7\n schematically illustrates selected components of the acoustic measurement LWD module \n120\n of \nFIG.', '6\n according to embodiments of the subject disclosure.', 'A pipe portion \n203\n defines a mud channel \n205\n.', 'Distributed on the pipe portion \n203\n is a number of acoustic transmitters including a pair of dipole transmitters \n201\n that transmit directional D1 and D2 dipole firings.', 'An array of receivers \n207\n and receiver electronics \n211\n are distributed on the pipe portion \n203\n.', 'The array of receivers receive the four-component waveforms of the acoustic energy that results from the directional D1 and D2 dipole firings as described herein.', 'A surface-located processing facility \n151\n (\nFIG.', '6\n) controls the D1 and D2 firings of the dipole transmitters \n201\n and the receiver electronics \n211\n.', 'The processing facility \n151\n can be located in one or more locations at the wellsite.', 'According to some embodiments, the processing facility \n151\n can process and interpret the data from the acoustic measurement LWD module \n120\n at one or more locations remote from the wellsite.', 'The processing facility \n151\n may include one or more central processing units, storage systems, communications and input/output modules, a user display, and a user input system.', 'Time-Domain Workflow\n \nAn embodiment of the first workflow that employs a time-domain LWD four-component waveform rotation scheme is summarized in the flow chart of \nFIG.', '8\n.', 'The embodiment follows the geometry of the D1 and D2 dipole firing and the inline and crossline waveforms received by the receiver array described above with respect to \nFIGS.', '5A and 5B\n.', 'In optional block \n801\n, the time domain inline and crossline array waveforms of the acoustic energy arising from the D1 LWD dipole firing as received by the receivers of the receiver array can be filtered to remove unwanted noise components.', 'Such filtering can be carried out in one or more domains, such as in the time domain (e.g., time window processing), frequency domain (e.g., bandpass filtering), the slowness domain (e.g., semblance, Nth-root stacking processing), and in the time-frequency domain (using wavelets or other time-frequency representations).', 'In optional block \n803\n, the time domain inline and crossline array waveforms of the acoustic energy arising from the D2 LWD dipole firing as received by the receivers of the receiver array can be filtered to remove unwanted noise components.', 'Such filtering can be carried out in one or more domains, such as in the time domain (e.g., time window processing), frequency domain (e.g., bandpass filtering), the slowness domain (e.g., semblance, Nth-root stacking processing), and in the time-frequency domain (using wavelets or other time-frequency representations).', 'In block \n805\n, the time-domain inline and crossline array waveforms corresponding to the D1 LWD dipole firing as provided by the waveform filtering of block \n801\n (or as received by the receivers of the receiver array if the waveform filtering of block \n801\n is omitted) can be represented as a D1 data vector/matrix u\nD1 \nas follows:\n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)', 'u\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n \n \nwhere u\nD1IN \n(t, z\nm\n) and u\nD1OF \n(t, z\nm\n) are, respectively, the time-doman inline and crossline array waveforms at the m-th receiver at a given time t, and z\nm \ndenotes the axial location of the m-th receiver.', 'In total there are M receivers.', 'For example, \nFIGS.', '5A and 5B\n illustrate an example where there are 4 azimuthal receivers at a given axial location.', 'Other embodiments can use more than four azimuthal receivers at a given axial location.', 'The azimuthal receiver configuration can be stacked/replicated over a number of axial locations offset from the dipole source for increased sensitivity.', 'In this case, the number of azimuthal receivers at each axial location can be summed together with a sinusoidal function as weights to give the M total receivers.', 'In an anisotropic formation, the time-domain inline array waveforms u\nD1IN \nand crossline array waveforms u\nD1OF \narising from the D1 dipole firing consist of contributions from both the fast and slow shear propagations of the D1 dipole firing.', 'As a result, the D1 data vector/matrix u\nD1 \ncan be represented as follows:\n \n \n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n=\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n=\n \n \n\u2062\n \n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \n \ns\n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n*\n \n \n \ng\n \nf\n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ns\n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n*\n \n \n \ng\n \ns\n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n1\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n=\n \n△\n \n \n\u2062\n \n \n\u2062\n \n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \nS\n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n2\n \n)\n \n \n \n \n \n \n \n \n \nNote that the rotation matrix R(θ) is used to project the waveforms twice, one from the D1 dipole source to the fast/slow shear directions and another (the transpose of the rotation matrix R(θ)) from the fast/slow shear directions to the receiver z\nm\n.', 'The matrix D(t, z\nm\n) denotes the propagating waveforms directly in the fast and slow shear directions (e.g., the diagonal elements).', 'The vector S is a selection vector for the two-component waveforms for the D1 dipole firing.', 'In block \n807\n, the time-domain inline and crossline array waveforms corresponding to the D2 LWD dipole firing as provided by the waveform filtering of block \n803\n (or as received by the receivers of the receiver array if the waveform filtering of block \n803\n is omitted) can be represented in a D2 data/vector matrix form.', 'Assuming the source signatures from the D1 and D2 dipole firings are the same, the time-domain inline and crossline array waveforms corresponding to the D2 LWD dipole firing can be represented as a D2 data/vector matrix u\nD2 \nas follows:', 'u\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n=\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n=\n \n \n\u2062\n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n \n \n \n-\n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n \n \n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)', 'cos\n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n\u2062\n \n \n[\n \n \n \n \n \n \ns\n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n*\n \n \n \ng\n \nf\n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ns\n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n*\n \n \n \ng\n \ns\n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n \n \n \n \n \n-\n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n \n \n \n \ncos\n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n1\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n=\n \n△\n \n \n\u2062\n \n \n\u2062\n \n \n \nR\n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \n \nθ\n \n+\n \nϕ\n \n \n)\n \n \n \n\u2062\n \nS\n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n \n \nNote that the rotation matrix R(θ+ϕ) for the D2 dipole firing employs a rotation angle of θ+ϕ. Note that the rotation matrix R(θ+ϕ) is used to project the waveforms twice, one from the D2 dipole source to the fast/slow shear directions and another (the transpose of the rotation matrix R(θ+ϕ)) from the fast/slow shear directions to the receiver z\nm\n.', 'The matrix D(t, z\nm\n) denotes the propagating waveforms directly in the fast and slow shear directions (e.g., the diagonal elements).', 'The vector S is a selection vector for the two-component waveforms for the D2 dipole firing.', 'It is worth noting that the rotation matrix R(θ+ϕ) has the following property: \n \nR\n(θ+ϕ)=\nR\n(ϕ)\nR\n(θ), \n \nR\n(θ)\nR\nT\n(θ)=\nI\n2\n\u2003\u2003Eqn.', '(4) \n \nwhere I\n2 \nis the identity matrix of dimension \n2\n.', 'Therefore, the Eqn.', '(3) arising from the D2 dipole firing is equivalent to: \n \nU\nD2\n=R\n(ϕ)\nR\n(θ)\nD\n(\nt,z\nm\n)\nR\nT\n(θ)\nR\nT\n(ϕ)\nS\n\u2003\u2003Eqn.', '(5)', 'In block \n809\n, a rotation matrix R(ϕ) is defined for the D2 data/vector u\nD2 \nas:\n \n \n \n \n \n \n \n \n \nR\n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n=\n \n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n]\n \n \n.', 'Eqn\n \n.', '\u2062\n \n \n(\n \n6\n \n)\n \n \n \n \n \n \n \n \n \nNote that the angle ϕ represents the angle difference between the D1 and D2 firings as follows:\n \n \n \n \n \n \n \n \n \n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n\u2062\n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n=\n \n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nS\n \n~\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nwhere\n \n\u2062\n \n \n \n \n\u2062\n \n \nS\n \n~\n \n \n \n=\n \n \n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \nS\n \n \n=\n \n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n]\n \n \n.', 'Eqn\n \n.', '\u2062\n \n \n(\n \n7\n \n)\n \n \n \n \n \n \n \n \n \nNote that the rotation matrix R\nT \n(ϕ) is the transpose of the rotation matrix R(ϕ)).', 'In block \n811\n, rotation matrix R(θ) and rotation matrix P(θ) are defined as follows:\n \n \n \n \n \n \n \n \n \n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)', '=\n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n \n,\n \nand\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nP\n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n=\n \n \n \n[\n \n \n \n \n1\n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n \n1\n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n]\n \n \n.', 'Eqn\n \n.', '\u2062\n \n \n(\n \n8\n \n)', 'In block \n813\n, a four-component data vector u can be defined by combining the D1 data vector/matrix u\nD1 \nfrom the D1 dipole firing (block \n805\n) and the rotated data vectors R\nT \n(ϕ)u\nD2 \nfrom the D2 dipole firing (block \n807\n and Eqn.', '(6)) as follows:\n \n \n \n \n \n \n \n \n \n \n \nu\n \n=\n \n \n \n[\n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nϕ\n \n)', '\u2062\n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n]\n \n \n=\n \n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2061\n \n \n[\n \n \nS\n \n,\n \n \nS\n \n~\n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n=\n \n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2061\n \n \n[\n \n \n \n \n1\n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n \n0\n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nϕ\n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n=\n \n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nP\n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n9\n \n)', 'Furthermore, the four-component data vector u can be rotated based on the rotation matrices R(θ) and P(ϕ) (Eqn. (8)) to define a matrix D(t, z\nm\n) as follows: \n \nD\n(\nt,z\nm\n)=\nR\nT\n(θ)[\nu\nD1\nR\nT\n(ϕ)\nu\nD2\n]\nP\n−1\n(ϕ)\nR\n(θ)\u2003\u2003Eqn.', '(10) \n \nThen, in block \n815\n, a cost function that involves the total crossline energy of the matrix D(t, z\nm\n) across all of the M receivers and all time samples can be evaluated and minimized by computer-implemented methods as follows:\n \n \n \n \n \n \n \n \n \n \nmin\n \n \nθ\n \n,\n \nϕ\n \n \n \n\u2062\n \n \n \n∑\n \n \nt\n \n=\n \n \nt\n \n0\n \n \n \n \n \nt\n \n0\n \n \n+\n \nT\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n∑\n \n \nm\n \n=\n \n1\n \n \nM\n \n \n\u2062\n \n \n \n \n\u2062\n \n \noff\n \n\u2062\n \n \n{\n \n \nD\n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n}\n \n \n \n \n \n \n=\n \n \n \nmin\n \n \nθ\n \n,\n \nϕ\n \n \n \n\u2062\n \n \n \n∑\n \n \nt\n \n=\n \n \nt\n \n0\n \n \n \n \n \nt\n \n0\n \n \n+\n \nT\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n∑\n \n \nm\n \n=\n \n1\n \n \nM\n \n \n\u2062\n \n \n \n \n\u2062\n \n \noff\n \n\u2062\n \n \n{\n \n \n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2061\n \n \n[\n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n\u2062\n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \nP\n \n \n-\n \n1\n \n \n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n\u2062\n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n}\n \n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n11\n \n)\n \n \n \n \n \n \n \n \n \nwhere off {D} computes the sum of all off-diagonal elements of D, t\n0 \nis the time index of the first sample, and T is the total sample duration.', 'In certain scenarios, a magnetometer of the LWD acoustic measurement tool can measure both D1 and D2 firing azimuth directions up to a certain precision with respect to a reference (e.g., the direction of gravity).', 'Such output can provide an a priori range of θ: θ∈', '[θ\n1l\n, θ\n1h\n]) and (θ+ϕ):(θ+ϕ) ∈ [θ\n2l\n, θ\n2h\n] with respect to the same reference direction.', 'This provides a feasible range of the angle ϕ as follows: \n ϕ∈[θ\n2l\n−θ\n1h\n−θ\n1l\n]\u2003\u2003Eqn.', '(12) \n \nTherefore, the two rotation angles θ, ϕ can be determined by computer-implemented methods that solve the following constrained minimization problem:', 'min\n \n \nθ\n \n,\n \nϕ\n \n \n \n\u2062\n \n \n \n∑\n \n \nt\n \n=\n \n \nt\n \n0\n \n \n \n \n \nt\n \n0\n \n \n+\n \nT\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n∑\n \n \nm\n \n=\n \n1\n \n \nM\n \n \n\u2062\n \n \n \n \n\u2062\n \n \noff\n \n\u2062\n \n \n{\n \n \n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2061\n \n \n[\n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n\u2062\n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \nP\n \n \n-\n \n1\n \n \n \n\u2061\n \n \n(\n \nϕ\n \n)\n \n \n \n\u2062\n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n}\n \n \n \n \n \n \n,\n \n \ns\n \n.\n \nt\n \n.\n \n \n,\n \n \nϕ\n \n∈\n \n \n[\n \n \n \n \nθ\n \n \n2\n \n\u2062\n \nl\n \n \n \n-\n \n \nθ\n \n \n1\n \n\u2062\n \nh\n \n \n \n \n,\n \n \n \nθ\n \n \n2\n \n\u2062\n \nh\n \n \n \n-\n \n \nθ\n \n \n1\n \n\u2062\n \nl\n \n \n \n \n \n]\n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n13\n \n)', 'Once θ and ϕ have been determined, the fast shear direction of the formation can be calculated as θ\n1\n=θ degrees away from the D1 dipole firing direction.', 'In other words, the value of the parameter θ\n1 \nrepresents the fast shear direction of the formation.', 'The fast shear direction of the formation can also be calculated as θ\n2\n=(θ+ϕ)', 'degrees away from the D2 dipole firing direction.', 'In other words, the value of the parameter θ\n2 \nrepresents the fast shear direction of the formation.', 'The slow shear direction of the formation can be calculated by an offset of 90° relative to the fast shear direction of the formation as is evident from \nFIGS.', '5A and 5B\n.', 'Note that if the angle difference between the D1 and D2 firing is known (e.g., the D1 and D2 firing directions can be determined precisely), the rotation angle ϕ is known and the two-dimensional minimization of Eqn.', '(13) reduces to a one-dimensional minimization over θ.', 'In order to validate the first workflow, consider an example of the horizontal section of a fast TIV formation (e.g., the Bakken shale formation).', 'The synthetic data, generated by forward modeling code, simulates a fast formation with an LWD acoustic measurement tool centered in the borehole.', 'The formation, mud and tool parameters of the forward modeling code are listed in Table 1 below:\n \n \n \n \n \n \n \n \n \n \n \n \nTABLE 1\n \n \n \n \n \n \n \n \nParameters\n \nValues\n \nUnits\n \n \n \n \n \n \n \n \n \n \nDTs(slow)\n \n\u2002\u20092170 (141)\n \nm/s (us/ft)\n \n \n \n \nDTs(fast)\n \n\u2002\u20092619 (116)\n \nm/s (us/ft)\n \n \n \n \nDTc\n \n\u2002\u20093473 (88)\n \nm/s (us/ft)\n \n \n \n \nρ\nF\n \n\u2002\u20092230\n \nkg/m\n3\n \n \n \n \nDTm\n \n\u2002\u20091500 (203)\n \nm/s (us/ft)\n \n \n \n \nρ\nM\n \n\u2002\u20091000\n \nkg/m\n3\n \n \n \n \nDTs\ntool\n \n\u2002\u20093110 (98)\n \nm/s (us/ft)\n \n \n \n \nDTc\ntool\n \n\u2002\u20095751 (53)\n \nm/s (us/ft)\n \n \n \n \nρ\nT\n \n\u2002\u20097630\n \nkg/m\n3\n \n \n \n \nD\n \n0.1600 (6.3)\n \nm (in)', 'The LWD acoustic measurement tool contains 12 axial receivers placed at a distance from 7 ft to 10.6 ft away from a dipole transmitter with an inter-element spacing of 0.2 ft.\n \nFIGS.', '9A and 9B\n show the synthetic received time-domain array waveforms generated from the dipole transmitter in the horizontal section of the fast TIV formation.', 'The D1 and D2 firings are, respectively, 15 and 85 degrees away from the slow shear azimuth.', 'In this case, the D1 inline array waveforms are mostly dominated by the propagation from the slow shear direction, while the D2 inline array waveforms are mostly dominated by the propagation from the fast shear direction.', 'FIG.', '9C\n shows the slowness dispersions generated from the dipole transmitter in the horizontal section of the fast TIV formation.', 'The slowness dispersions represent the dipole flexural dispersion extracted by the matrix pencil method, referred to as the TKO algorithm and described in M. P. Ekstrom, “Dispersion estimation from borehole acoustic arrays using a modified matrix pencil algorithm,”', 'Proc. 29th Asilomar Conf.', 'Signals, Syst., Comput., vol.', '2, Pacific Grove, Calif., November 1995, pp. 449-453. \nFIG.', '9C\n shows that two flexural modes are present in the fast TIV formation.', 'The upper branch (above 200 us/ft) is the dominant drill-collar flexural dispersion, while the lower branch is the formation flexural dispersion.', 'The low frequency asymptotes of the formation flexural dispersions (D1 shown with dots labeled with “∘” and D2 shown with dots labeled with “+”) approach to the fast and slow shear slownesses in Table 1.', 'Specifically, the formation flexural dispersion of D1 is similar to the slow flexural dispersion as D1 is close to the slow shear azimuth.', 'FIG.', '10\n shows a two-dimensional cost function of the four-component non-orthogonal LWD waveform rotation in the (θ\n1\n=θ\n2\n=θ+ϕ) plane (Block \n815\n of \nFIG.', '8\n) for the synthetic example of \nFIGS.', '9A and 9B\n.', 'The two dashed lines are constraints for the upper and lower limit of the angle difference between the D1 and D2 firing directions.', 'Such constraints can be derived from the tolerance of D1 and D2 firing directions as measured during rotation of the LWD acoustic measurement tool, for example by a magnometer.', 'It is easy to observe that the global minima are located at (14.2°, 84.9°) and (104.2°, 174.9°) for [θ, θ+ϕ].', 'Note that there is a 90° ambiguity in the [θ, θ+ϕ] plane as one can rotate D1 to the fast shear direction and D2 to the slow shear direction or vice versa.', 'Since the workflow values the cost function to find the minimization of the total crossline energy, the coordinates of the global minima give the estimated rotation angles.', 'From \nFIG.', '10\n, the workflow searches for the minima within a bounded region (in between the two dashed lines) and the local minima are seen at (01=14.2°, θ\n2\n=84.9°) and (θ\n1\n=104.2°, θ\n2\n=174.9°), where the former one gives the slow shear polarization direction (i.e., 14.2° away from the D1 firing or 84.9° away from the D2 firing) and the latter one yields the fast shear direction due to a 90° ambiguity.', 'Nevertheless, the 90° ambiguity can be removed by rotating the four-component waveforms and identifying which rotated waveforms correspond to the fast and slow flexural waveforms as described in C. Esmersoy, K. Koster, M. Williams, A. Boyd and M. Kane, “Dipole shear anisotropy logging”, 64th Ann.', 'Internat.', 'Mtg., Soc.', 'Expl.', 'Geophys., Expanded Abstracts, 1139-1142, 1994.', 'FIGS.', '11A and 11B\n show the rotated inline and crossline array waveforms for the D1 and D2 dipole firings of \nFIGS.', '9A and 9B\n.', 'Particularly, the D1 firing is rotated to the slow shear direction while D2 is rotated towards the fast shear direction using the estimated rotation angles from \nFIG.', '10\n.', 'Note that the crossline energy of the rotated waveforms is significantly minimized and the inline waveform energy is enhanced.', 'The modified matrix pencil algorithm (TKO method) can be used to extract the dispersion curves from the rotated inline array waveforms of D1 and D2.', 'FIG.', '11C\n shows the corresponding slowness dispersions.', 'Note that formation flexural dispersion (dots labeled with “∘”) of the rotated D1 captures the slow flexural wave, while the formation flexural dispersion (dots labeled with “+”) of the rotated D2 converges to the fast flexural shear around 110 us/ft.\n \nFIGS.', '12A and 12B\n show synthetic time-domain array waveforms arising from the D1 and D2 firings of the dipole transmitter in the horizontal section of a fast TIV formation.', 'The D1 and D2 firings are, respectively, 35° and 67° away from the slow shear azimuth.', 'In this case, the D1 and D2 inline array waveforms contain a mixture of both the fast and slow flexural waves.', 'Note that the inline and crossline array waveforms for the D1 and D2 dipole firings are closer to an azimuth direction in between the fast and slow shear direction.', 'Specifically, the the D1 and D2 dipole firings are 35° and 67° away from the slow shear direction, respectively.', 'Compared with the case of \nFIGS.', '9A and 9B\n, more waveform energy is split into the crossline channel, as both dipole firings move away from either the fast or slow shear directions.', 'FIG.', '12C\n shows the corresponding slowness dispersions.', 'In \nFIG.', '12C\n, one can no longer see the formation flexural splitting at low frequencies from the inline receivers.\n \nFIG.', '13\n shows the two-dimensional cost function (Block \n815\n of \nFIG.', '8\n) for the synthetic example of \nFIGS.', '12A and 12B\n.', 'The two dashed lines represent the constraints for the upper and lower limit of the angle difference between the D1 and D2 firing directions.', 'The estimated rotation angles are (θ\n1\n=34.4°, θ\n2\n=66.7) within the two dashed lines (the constraints).', 'FIGS.', '14A and 14B\n show the rotated inline and crossline array waveforms for the D1 and D2 dipole firings of \nFIGS.', '12A and 12B\n.', 'Note that the crossline energy of the rotated array waveforms is significantly minimized and the inline array waveforms display the fast and slow flexural modes.', 'FIG.', '14C\n shows the corresponding slowness dispersions.', 'Note that the TKO results on the rotated inline array waveforms recover the formation flexural dispersions splitting at frequencies below 4 kHz.\n \nFIGS.', '15A and 15B\n shows the rotated synthesized inline and crossline array waveforms for D1 and D2 dipole firings in the horizontal section of a slow TIV formation.', 'FIG.', '15C\n shows the corresponding slowness dispersions.', 'The TKO results in \nFIG.', '15C\n show the coupled collar-flexural dispersions corresponding to the inline waveforms from the rotated D1 and D2.', 'The flexural splitting at high frequencies is clearly observed.', 'In this case, the fast and slow shear slownesses can be inverted from the fast and slow flexural dispersions using a model-based workflow as described in U.S. patent application Ser.', 'No. 15/331,946, filed on Oct. 24, 2016, entitled “Determining Shear Slowness from Dipole Source-based Measurements Acquired by a Logging-While-Drilling Acoustic Measurement Tool.”', 'Note that the time-domain workflow as discussed above is computationally efficient.', 'However, its performance may be affected by the strong noise level and the tool eccentering effect in the LWD operation.', 'Moreover, its performance can be affected by mismatch in the source-signatures of the D1 and D2 dipole firings.', 'Thus, a complementary frequency-domain workflow is described below that is intended to relax the limitations of the time-domain workflow.\n \nFrequency-Domain Workflow\n \nAn embodiment of the second workflow that employs a frequency domain LWD multiple-component waveform rotation scheme is summarized in the flow chart of \nFIG.', '16\n.', 'The embodiment follows the geometry of the D1 and D2 dipole firing and the inline and crossline waveforms received by the receiver array described above with respect to \nFIGS.', '5A and 5B\n.', 'The frequency-domain workflow, referred to herein as the LWD-DATC workflow, takes into account the presence of drill collar and its associated collar-flexural mode in the waveforms, and outputs a parameter value that represents the Fast Shear Azimuth (FSA) direction of the formation.', 'Compared with the time-domain workflow discussed above, the LWD-DATC workflow is more robust to the presence of noise and any tool eccentering that might be there (insofar as the dispersion is less affected).', 'Furthermore, it is based on processing inline and crossline waveforms generated by a single directional dipole firing.', 'This alleviates the requirement of dipole source matching.', 'The frequency-domain workflow begins in block \n1601\n where a fast Fourier transform is applied to the time domain inline and crossline array waveforms of the acoustic energy arising from the either the D1 or D2 LWD dipole firing as received by the receivers of the receiver array.', 'As an optional part of block \n1601\n, the inline and crossline array waveforms can be filtered to remove unwanted noise components.', 'Such filtering can be carried out in one or more domains, such as in the time domain (e.g., time window processing), frequency domain (e.g., bandpass filtering), the slowness domain (e.g., semblance, Nth-root stacking processing), and in the time-frequency domain (using wavelets or other time-frequency representations).', 'The frequency-domain inline and crossline array waveforms output from block \n1601\n can be represented in a data vector/matrix form.', 'For example, the frequency-domain inline and crossline array waveforms corresponding to the one dipole firing (D1, for instance) can be represented by a two-component data vector/matrix u\nD1 \nas follows:\n \n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)', 'u\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n14\n \n)\n \n \n \n \n \n \n \n \n \nwhere ω is angular frequency.', 'The two-component data vector/matrix u\nD1 \ncan be expressed as follows:', 'u\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n=\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n\u2062\n \n \n=\n \n \n \n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \n \ns\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \n \ng\n \nf\n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ns\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \n \ng\n \ns\n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \n \n-\n \nsin\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n \n \n1\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n=\n \nΔ\n \n \n\u2062\n \n \n \nR\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n\u2062\n \n \n \nR\n \nT\n \n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \nS\n \n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n15\n \n)', 'This two-component data vector/matrix u\nD1 \nis a simple transformation of the time-domain data vector of Eqn.', '(2) into the frequency domain.', 'In order to model the propogation of the pressure field associated with the fast and slow flexural waves, consider a dipole transmitter oriented at an angle θ with respect to the fast shear direction as shown in \nFIG.', '17\n.', 'The dipose transmitter waveform can be decomposed into two virtual sources directed along the fast and slow shear directions.', 'The fast and slow flexural waves with corresponding polarization directions propogate along the borehole in accordance with the fast and slow dispersions.', 'The inline array waveforms U\nXX \nand the crossline array waveforms U\nXY \ncontain contributions from both the fast and slow flexural waves.', 'The model representation of the inline and crossline array waveforms are denoted by U\nXX \nand U\nXY\n, respectively.', 'The model representation of the inline and crossline array waveforms U\nXX \nand U\nXY \ntake the following form: \n \nU\nXX\n=S\nX \ncos\n2 \nθg\nf\n+S\nX \nsin\n2 \nθg\ns\n, \n \nU\nXY\n=S\nX \nsin θ cos θ\ng\nf\n+S\nX \nsin θθ\ng\ns\n,\u2003\u2003Eqn.', '(16) \n \nwhere S\nX \nis the source signature for the dipole transmitter aligned along the X-direction that makes the angle θ with respect to the fast shear direction.', 'The eigenfunctions for the pressure field associated with the fast and slow flexural waves are given as: \n \ng\nf\n(ω,\nz\nm\n)=−ρ\nm\nω\n2 \ncos φζ(\nk\nr\nf\n,k\nz\nf\n,r\n) \n \ng\ns\n(ω,\nz\nm\n)', '=−ρ\nm\nω\n2 \ncos φζ(\nk\nr\ns\n,k\nr\ns\n,r\n)\u2003\u2003Eqn.', '(17) \n \nwhere ρ\nm \nis the mud density, r and φ are the radial and azimuthal coordinates, respectively of a given receiver, k\nr \nand k\nz \nare the radial and axial wavenumbers, respectively, for the fast and slow flexural waves (denoted by super-script f and s) with the following association\n \n \n \n \n \n \n \n \n \n \n \n(\n \n \nk\n \nr\n \ns\n \n \n)', '2\n \n \n=\n \n \n \n \nω\n \n2\n \n \n \nv\n \nm\n \n2\n \n \n \n-\n \n \n \n(\n \n \nk\n \nz\n \ns\n \n \n)\n \n \n2\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n(\n \n \nk\n \nr\n \nf\n \n \n)\n \n \n2\n \n \n=\n \n \n \n \nω\n \n2\n \n \n \nv\n \nm\n \n2\n \n \n \n-\n \n \n \n(\n \n \nk\n \nz\n \nf\n \n \n)\n \n \n2\n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n18\n \n)\n \n \n \n \n \n \n \n \n with v\nm \ndenoting the mud compressional velocity.', 'Note that a function ζ can be used to represent the difference between the LWD acoustic measurement tool and wireline acoustic measurement tool.', 'In the wireline acoustic measurement tool, the tool flexural mode is designed to be significantly slower than the formation flexural modes encountered in logging conditions and is moreover attenuated due to the presence of an isolation section between the dipole transmitter and the receivers.', 'Therefore, the formation flexural mode is the dominant one with no interference from the tool flexural mode.', 'In this case, the function ζ is given as: \n ζ(\nk\nr\nf\n,k\nz\nf\n,r\n)', '=\nJ\n1\n(\nk\nr\nf\nr\n)', 'A e\njk\nz\nf\nx\nm\n, \n ζ(\nk\nr\ns\n,k\nz\ns\n,r\n)', '=\nJ\n1\n(\nk\nr\nf\nr\n)', 'A e\njk\nz\ns\nz\nm\n\u2003\u2003Eqn.', '(19) \n \nwhere J\n1 \nis the Bessel function of first kind, and\n \nA is an amplitude coefficient of the Bessel function common to both fast and slow flexural eigenfunctions and obtained from the continuity condition at the borehole surface for the wireline propagation mode.', 'The Bessel function J\n1 \naccounts for the formation flexural mode and is described in the following references: i) B. K. Sinha and X. Huang, “Dipole Anisotropy from Two-Component Acquisition: Validation against synthetic data,” Schlumberger-Doll Research Note, 1999; ii) B. K. Sinha, S. Bose and X. Huang, “Determination of dipole shear anisotropy of earth formations”, U.S. Pat.', 'No. 6,718,266 B 1, 2002; and iii)', 'S. Bose, B. K. Sinha, S. Sunaga, T. Endo and H. P. Valero, “Anisotropy processing without matched cross-dipole transmitters”, 75th Ann.', 'Internat.', 'Mtg., Soc.', 'Expl.', 'Geophys., Expanded Abstracts, 2007.', 'In the LWD acoustic measurement tool there is direct propagation of the strong drill-collar flexural wave.', 'To account for the existence of the rotating tool pipe and the fact that the receivers are located in the annulus just outside of the rotating tool pipe and inside the formation, the function is modified for either a slow formation or a fast formation to include Bessel functions of the second kind in addition to those of the first kind.', 'In a slow formation, the function ζ is modified as follows: \n ζ(\nk\nr\nf\n,k\nz\nf\n,r\n)=[\nJ\n1\n(\nk\nr\nf\nr\n)\nA+Y\n1\n(\nk\nr\nf\nr\n)\nB\n]\ne\njk\nz\nf\nx\nm\n, \n ζ(\nk\nr\ns\n,k\nz\ns\n,r\n)=[\nJ\n1\n(\nk\nr\ns\nr\n)\nA+Y\n1\n(\nk\nr\ns\nr\n)\nB\n]\ne\njk\nz\ns\nz\nm\n,\u2003\u2003Eqn.', '(20) \n \nwhere J\n1 \nis the Bessel function of the first kind,\n \nY\n1 \nis the Bessel function of the second kind,\n \nk\nr\nf \nand k\nr\ns \nare the radial wavenumbers for the fast and slow coupled tool-formation flexural waves, and\n \nA and B are amplitude coefficients for Bessel functions of the first and second kind respectively obtained from the continuity conditions at the borehole and tool pipe surface for the LWD propagation mode in the slow formation.', 'Note that the Y\n1 \nBessel function of Eqn.', '(20) is needed to properly account for propagation of the drill-collar flexural wave in the annulus between the rotating tool and the formation in this slow formation case.', 'In the case of a slow formation, Eqn.', '(15) can be rewritten with the following expression for the two-component data vector/matrix u\nD1\n:\n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n=\n \n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)', 'u\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nm\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n=\n \n \n \n-\n \n \nρ\n \nm\n \n \n \n\u2062\n \n \nω\n \n2\n \n \n\u2062\n \n \ns\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \n \nφ\n \n\u2061\n \n \n(\n \n \n \nA\n \n\u2061\n \n \n[\n \n \n \n \n \n \nJ\n \nf\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n \n \n0\n \n \n \n \n \nJ\n \ns\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n \n \n \n \n0\n \n \n \n \n \n \nJ\n \ns\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n-\n \n \n \nJ\n \nf\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n+\n \n \nB\n \n\u2061\n \n \n[\n \n \n \n \n \n \nY\n \nf\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n \n \n0\n \n \n \n \n \nY\n \ns\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n \n \n \n \n0\n \n \n \n \n \n \nY\n \ns\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n-\n \n \n \nY\n \nf\n \n \n\u2061\n \n \n(\n \n \nz\n \nm\n \n \n)\n \n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n)\n \n \n \n\u2062', '[\n \n \n \n \n \n \ncos\n \n2\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n\u2062\n \n \n \n \n\u2062\n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n21\n \n)\n \n \n \n \n \n \n \n \n \nJ\nf\n(\nz\nm\n)=\nJ\n1\n(\nk\nr\nf\nr\n)\ne\njk\nz\nf\nz\nm\n, \n \nJ\ns\n(\nz\nm\n)=\nJ\n1\n(\nk\nr\ns\nr\n)\ne\njk\nz\ns\nz\nm\n, \n where \n \nY\nf \n(\nz\nm\n)=\nY\n1\n(\nk\nr\nf\nr\n)\ne\njk\nz\nf\nz\nm\n, and \n \nY\ns\n(\nz\nm\n)=\nY\n1\n(\nk\nr\ns\nr\n)\ne\njk\nz\ns\nz\nm\n,\u2003\u2003Eqn.', '(22)', 'The array waveforms for all of the receivers can be combined into two long vectors as follows:\n \n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \n1\n \n \n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \n2\n \n \n \n)\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nM\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \nω\n \n)', '=\n \n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \n1\n \n \n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \n2\n \n \n \n)\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \n \nω\n \n,\n \n \nz\n \nM\n \n \n \n)\n \n \n \n \n \n \n]\n \n \n.', 'Eqn\n \n.', '\u2062\n \n \n(\n \n23\n \n)', 'The vectors of Eqn.', '(23) can be rewritten into a matrix form as follows:\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n=\n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \n{\n \n \n \nA\n \n\u2061\n \n \n[\n \n \n \n \n \nJ\n \nf\n \n \n \n \n0\n \n \n \n \nJ\n \ns\n \n \n \n \n \n \n0\n \n \n \n \n \nJ\n \ns\n \n \n-\n \n \nJ\n \nf\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n+\n \n \nB\n \n\u2061\n \n \n[\n \n \n \n \n \nY\n \nf\n \n \n \n \n0\n \n \n \n \nY\n \ns\n \n \n \n \n \n \n0\n \n \n \n \n \nY\n \ns\n \n \n-\n \n \nY\n \nf\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n)\n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n \n \n \n \n \n \n=\n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)', '\u2062\n \n \n(\n \n \n \nAJ\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n+\n \n \nBY\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n)\n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)', '\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \nwhere\n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n24\n \n)\n \n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n=\n \n \n \n-\n \n \nρ\n \nm\n \n \n \n\u2062\n \n \nω\n \n2\n \n \n\u2062\n \n \ns\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \n \n \n\u2062\n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nφ\n \n \n \n,\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \ncos\n \n2\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n\u2062\n \n \n \n \n\u2062\n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nJ\n \nf\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \nf\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \nf\n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \nj\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \nf\n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \nf\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \nf\n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nJ\n \ns\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \ns\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \ns\n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \ns\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \ns\n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \ns\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \ns\n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nY\n \nf\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \nf\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \nf\n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \nf\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \nf\n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \nf\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \nf\n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \nand\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nY\n \ns\n \n \n=\n \n \n \n[\n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \ns\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \ns\n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \ns\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \ns\n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \ns\n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \ns\n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n.', 'Eqn\n \n.', '\u2062\n \n \n(\n \n25\n \n)', 'The matrices of Eqns.', '(24) and (25) can be rewritten into a simplified form as follows:\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n=\n \n \n \n[\n \n \n \nJ\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \nY\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \nA\n \n \n \n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \nB\n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n=\n \n \n \nD\n \n\u2061\n \n \n(\n \n \nω\n \n,\n \nθ\n \n \n)\n \n \n \n\u2062\n \n \nb\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n \n \n.', 'Eqn\n \n.', '\u2062\n \n \n(\n \n26\n \n)', 'In practice, the data vector/matrix u\nD1 \nof Eqn.', '(26) is usually contaminated by noise as follows: \n \nu\nD1\n(ω)=\nD\n(ω,θ)\nb\n(ω)+\nn\n(ω).', 'Eqn.', '(27) \n \nTo find a solution of the rotation angle θ in a slow formation, an LWD-DATC cost function can be constructed from the data vector/matrix u\nD1 \nof Eqn.', '(26).', 'Note that the data vector/matrix u\nD1 \nof Eqn.', '(26) is produced from the model of propogation of the pressure field associated with the fast and slow flexural waves of Eqns.', '(16)-(26).', 'The LWD-DATC cost function involves the frequency-domain waveforms across the receivers of the array and multiple frequency points as follows:\n \n \n \n \n \n \n \n \n \nθ\n \n^\n \n \n=\n \n \narg\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nmax\n \nθ\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n∑\n \n \nω\n \n∈\n \nΩ\n \n \n \n\u2062\n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \nH\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nP\n \n \nD\n \n\u2061\n \n \n(\n \n \nω\n \n,\n \nθ\n \n \n)', '\u2062\n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n28\n \n)\n \n \n \n \n \n \n \n \n \nwhere Ω is the set of selected frequency points,\n \nP\nD(ω, θ) \nis the projection matrix onto the subspace of the signal matrix D(ω, θ) of the form P\nD(ω, θ)\n=D(ω, θ) (D\nH \n(ω, θ)\n−1 \nD\nH\n(ω, θ), and \n \nD\n(ω,θ) is a rank-two matrix of the form \nD\n(ω,θ)=', '[\nJ\n(ω)\nv\n(θ)\nY\n(ω)\nv\n(θ)] for the slow formation.', 'Eqn.', '(29) \n \nWith this cost function, the rotation angle θ is estimated as the parameter that maximizes the total energy projected onto the signal subspace defined by the two Bessel functions J(ω) and Y(ω) along the fast and slow flexural dispersions.', 'The set of the selected frequency points Ω of the cost function is based on estimated dispersion of the fast and slow (tool/formation) flexural modes.', 'In a fast formation, the function ζ is modified to describe the coupled tool and formation flexural modes as follows: \n ζ(\nk\nr\nf\n,k\nz\nf\n,r\n)=[\nJ\n1\n(\nk\nr\nf,F\nr\n)', 'A\nF\n+Y\n1\n(\nk\nr\nf,F\nr\n)\nB\nF\n]\ne\njk\nz\nf,F\nz\nm', '+[\nJ\n1\n(\nk\nr\nf,T\nr\n)', 'A\nr\n+Y\n1\n(\nk\nr\nf,T\nr\n)\nB\nT\n]\ne\njk\nz\nf,T\nz\nm\n, \n (\nk\nr\nf\n,k\nz\nf\n,r\n)=[\nJ\n1\n(\nk\nr\nf,F\nr\n)\nA\nF\n+Y\n1\n(\nk\nr\nf,F\nr\n)\nB\nF\n]\ne\njk\nz\nf,F\nz\nm', '+[\nJ\n1\n(\nk\nr\nf,T\nr\n)', 'A\nr\n+Y\n1\n(\nk\nr\nf,T\nr\n)\nB\nT\n]\ne\njk\nz\nf,T\nz\nm\n,\u2003\u2003Eqn.', '(30) \n \nwhere J\n1 \nis the Bessel function of the first kind, Y\n1 \nis the Bessel function of the second kind, k\nr\nj,F \nand k\nr\ns,F \nare the radial wavenumbers for the fast and slow formation flexural waves, k\nr\nf,T \nand k\nr,s,T \nare the radial wavenumbers for the fast and slow tool flexural waves; A\nF \nand B\nF \nare the amplitude coefficients for the Bessel function of the first and second kind respectively, representing the LWD formation flexural propagation mode in the fast formation and obtained from the continuity conditions at the borehole and tool pipe interfaces; and A\nT \nand B\nT \nare similarly the amplitude coefficients for the Bessel function of the first and second kind respectively, representing the LWD tool flexural propagation mode in the fast formation and obtained from the continuity conditions at the borehole and tool pipe interfaces.', 'Note that in Eqn.', '(30) the Y\n1 \nBessel function of Eqn.', '(21) is used in a similar manner as described above with respect to Eqn.', '(20) to properly account for the propagation of the drill-collar flexural wave in the annulus between the rotating tool and the formation.', 'It also accounts for the coupling between the rotating tool and the formation.', 'In the case of a fast formation, Eqn.', '(15) can be rewritten with the following expression of the two-component data vector/matrix u\nD1\n:\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n=\n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \n(\n \n \n \n \n \n \n \nA\n \nT\n \n \n\u2061\n \n \n[\n \n \n \n \n \nJ\n \nf\n \nT\n \n \n \n \n0\n \n \n \n \nJ\n \ns\n \nT\n \n \n \n \n \n \n0\n \n \n \n \n \nJ\n \ns\n \nT\n \n \n-\n \n \nJ\n \nf\n \nT\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n+\n \n \n \nB\n \nT\n \n \n\u2061\n \n \n[\n \n \n \n \n \nY\n \nf\n \nT\n \n \n \n \n0\n \n \n \n \nY\n \ns\n \nT\n \n \n \n \n \n \n0\n \n \n \n \n \nY\n \ns\n \nT\n \n \n-\n \n \nY\n \nf\n \nT\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n+\n \n \n \nA\n \nF\n \n \n\u2061\n \n \n[\n \n \n \n \n \nJ\n \nf\n \nF\n \n \n \n \n0\n \n \n \n \nJ\n \ns\n \nF\n \n \n \n \n \n \n0\n \n \n \n \n \nJ\n \ns\n \nF\n \n \n-\n \n \nJ\n \nf\n \nF\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n+\n \n \n \nB\n \nF\n \n \n\u2061\n \n \n[\n \n \n \n \n \nY\n \nf\n \nF\n \n \n \n \n0\n \n \n \n \nY\n \ns\n \nF\n \n \n \n \n \n \n0\n \n \n \n \n \nY\n \ns\n \nF\n \n \n-\n \n \nY\n \nf\n \nF\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n)\n \n \n \n \n \n \n \n \n \n=\n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \n(\n \n \n \n \nA\n \nT\n \n \n\u2062\n \n \n \nJ\n \nT\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n+\n \n \n \nB\n \nT\n \n \n\u2062\n \n \n \nY\n \nT\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n+\n \n \n \nA\n \nF\n \n \n\u2062\n \n \n \nJ\n \nf\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n+\n \n \n \nB\n \nF\n \n \n\u2062\n \n \n \nY\n \nF\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n)\n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \nwhere\n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n31\n \n)\n \n \n \n \n \n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)', '=\n \n \n \n-\n \n \nρ\n \nm\n \n \n \n\u2062\n \n \nω\n \n2\n \n \n\u2062\n \n \ns\n \n\u2061\n \n \n(\n \nω\n \n)', '\u2062\n \n \n \n \n\u2062\n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nφ\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \ncos\n \n2\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n\u2062\n \n \n \n \n\u2062\n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n32\n \n)\n \n \n \n \n \n \n \n \n \n \nJ\n \nf\n \nT\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nJ\n \ns\n \nT\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nJ\n \nf\n \nF\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nJ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nY\n \ns\n \nT\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nY\n \nf\n \nF\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \nf\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n \n,\n \n \n \n \n \n \n \n \n \n \n \n \n \nY\n \ns\n \nF\n \n \n=\n \n \n \n[\n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nF\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \n1\n \n \n \n \n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \n2\n \n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \nY\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nk\n \nr\n \n \ns\n \n,\n \nT\n \n \n \n\u2062\n \nr\n \n \n)\n \n \n \n\u2062\n \n \ne\n \n \n \njk\n \nz\n \n \ns\n \n,\n \nF\n \n \n \n\u2062\n \n \nz\n \nM\n \n \n \n \n \n \n \n \n]\n \n \n.', 'The matrices of Eqns.', '(31) and (32) can be rewritten into a simplified form as follows:\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nIN\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nOF\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n=\n \n \n \n[\n \n \n \n \nJ\n \nT\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nY\n \nT\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nJ\n \nF\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nY\n \nF\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nv\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nA\n \nT\n \n \n \n \n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nB\n \nT\n \n \n \n \n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nA\n \nF\n \n \n \n \n \n \n \n \n \nα\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nB\n \nF\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n=\n \n \n \nD\n \n\u2061\n \n \n(\n \n \nω\n \n,\n \nθ\n \n \n)\n \n \n \n\u2062\n \n \nb\n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n \n \n.', 'Eqn\n \n.', '\u2062\n \n \n(\n \n33\n \n)', 'This form consists of the same expression as in the case of the slow formation (Eqn. (26)), except that the rank of the matrix D(ω, θ) increases from 2 to 4 due to the separation of the drill-collar and formation flexural modes.', 'In practice, the data vector/matrix u\nD1 \nof Eqn.', '(33) is usually contaminated by noise as follows: \n \nu\nD1\n(ω)=\nD\n(ω,θ)\nb\n(ω)+\nn\n(ω)\u2003\u2003Eqn.', '(34) \n \nTo find a solution of the rotation angle θ in a fast formation, an LWD-DATC cost function can be constructed from the data vector/matrix u\nD1 \nof Eqn.', '(33).', 'Note that the data vector/matrix u\nD1 \nof Eqn.', '(33) is produced from the model of propogation of the pressure field associated with the fast and slow flexural waves of Eqns.', '(29)-(33).', 'The LWD-DATC cost function involves the frequency-domain waveforms across all of the receivers of the array and multiple frequency points as follows:\n \n \n \n \n \n \n \n \n \nθ\n \n^\n \n \n=\n \n \narg\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nmax\n \nθ\n \n \n\u2062\n \n \n \n∑\n \n \nω\n \n∈\n \nΩ\n \n \n \n\u2062\n \n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \nH\n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n\u2062\n \n \nP\n \n \nD\n \n\u2061\n \n \n(\n \n \nω\n \n,\n \nθ\n \n \n)', '\u2062\n \n \n \nu\n \n \nD\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2061\n \n \n(\n \nω\n \n)\n \n \n \n \n \n \n \n \n \n \n \nEqn\n \n.', '\u2062\n \n \n(\n \n35\n \n)\n \n \n \n \n \n \n \n \n \nwhere, again, P\nD(ω, θ) \nis the projection matrix onto the subspace of the matrix\n \nD(ω, θ), P\nD(ω, θ)\n=D(ω, θ) (D\nH \n(ω, θ)D(ω, θ))\n−1 \nD\nH \n(ω, θ), and\n \nD(ω, θ) is a rank-four matrix given as \n \nD\n(ω,θ)=[\nJ\nT\n(ω)\nv\n(θ)\nY\nT\n(ω)\nv\n(θ)\nJ\nF\n(ω)\nv\n(θ)\nY\nF\n(ω)\nv\n(θ)]\u2003\u2003Eqn.', '(36)', 'In order to construct the LWD-DATC cost function for a slow formation or a fast formation, the frequency-domain workflow rotates the data vectors output from block \n1601\n (e.g., the two-component data vectors of Eqn.', '(15)) with a set of one or more predetermined rotation angles in block \n1603\n.', 'If the data vectors are rotated by a set of two or more predetermined rotation angles, the rotated data vectors (which are rotated by the predetermined rotation angle) that shows the largest flexural dispersion splitting are selected for output to block \n1605\n.', 'Note that the set of one or more predetermined rotation angles can be configured to cover the fast shear direction based on the fast shear directions acquired from other depths in the formation.', 'In block \n1605\n, the rotated data vectors output from block \n1603\n are used to estimate the dispersion of fast and slow (tool/formation) flexural modes arising from the D1 or D2 LWD dipole firing.', 'Such operations can employ a variety of methods known in the art for such estimation.', 'A number of methods are described in i) U.S. patent application Ser.', 'No. 15/331,946, filed on Oct. 24, 2016, entitled “Determining Shear Slowness from Dipole Source-based Measurements Acquired by a Logging-While-Drilling Acoustic Measurement Tool;” ii) Ekstrom, M. P., “Dispersion estimation from borehole acoustic arrays using a modified matrix pencil algorithm,” 29th Asilomar Conf.', 'Signals, Syst., Comput., Pacific Grove, Calif., pp. 449-453, Oct. 31, 1995; iii) Tang, X. M., Li, C., and Patterson, D., “A curve-fitting method for analyzing dispersion characteristics of guided elastic waves,” The 79th SEG Annual Meeting, Houston, Tex., 25-30 Oct. 25-30, 2009, pp.', '461-465; iv) Wang, C., “Sonic well logging methods and apparatus utilizing parametric inversion dispersive wave processing,” U.S. Pat.', 'No. 7,120,541; v) Aeron, S., Bose, S. and Valero, H.-P., “Automatic Dispersion Extraction of Multiple Time-Overlapped Acoustic Signals,” U.S. Pat.', 'No. 8,339,897; vi) Wang, P. and Bose, S., “Broadband dispersion extraction of borehole acoustic modes via sparse Bayesian learning: 5th IEEE International Workshop on Computational Advances in Multi-Sensor Adaptive Processing, Saint Martine, Dec. 15-18, 2013, pp.', '268-271; and vii) Wang, P. and Bose, S., “Apparatus for Mode Extraction Using Multiple Frequencies,” PCT Publication No. PCT/US14/049703;', 'herein incorporated by reference in their entireties.', 'The estimated dispersions for each of the modes can be represented in terms of the phase slowness, or equivalently, the axial wavenumbers, as a function of frequency, which are then used as described below.', 'In block \n1607\n, the rotated data vectors output from block \n1603\n are used to define a propogation model of the pressure field associated with the fast and slow flexural waves arising from the D1 or D2 LWD dipole firing for the appropriate fast or slow formation.', 'In one embodiment, for a slow formation, the rotated data vectors output from block \n1603\n are used to define the frequency domain waveforms u\nD1IN\n(ω) and u\nD1OF\n(ω) for the receivers of the receiver array with respect to the propagation model of Eqns.', '(15)-(26) as described above.', 'The estimated dispersion of the fast and slow (tool/formation) flexural modes as computed in block \n1605\n can be used to define the propagation model for the slow formation.', 'For example, the wavenumbers of the fast and slow (tool/formation) flexural modes as computed in block \n1605\n can be used to compute the matrix D(ω, θ) of Eqn.', '(29) via the matrices J\nf\n, J\ns\n,', 'Y\nf\n, Y\ns \nof Eqn. (25).', 'In another embodiment, for a fast formation, the rotated data vectors output from block \n1603\n are used to define the frequency domain waveforms u\nD1IN\n(ω) and u\nD1OF\n(ω) for all of the receivers of the receiver array with respect to the propagation model of of Eqns.', '(29)-(32) as described above.', 'The estimated dispersion of the fast and slow (tool/formation) flexural modes as computed in block \n1605\n can be used to define the propogation model for the fast formation.', 'For example, the wavenumbers of the fast and slow (tool/formation) flexural modes as computed in block \n1605\n can be used to compute the matrix D(ω, θ) of Eqn.', '(36) via the matrices J\nf\nT\n, J\ns\nT\n, J\nf\nF\n, Y\ns\nT\n, Y\nf\nF\n, and Y\ns\nF \nof Eqn.', '(32).', 'In block \n1609\n, the LWD-DATC cost function (e.g., Eqn. (28) for the slow formation or Eqn.', '(34) for the fast formation) is constructed based on the propogation model defined in block \n1607\n.', 'The set of the selected frequency points Ω of the LWD-DATC cost function is based on estimated dispersion of the fast and slow (tool/formation) flexural modes computed in block \n1605\n.', 'In particular, the frequency points are selected to lie in a frequency band where we have sufficiently large separation between the fast and slow flexural (formation/tool) dispersions.', 'In the fast formation case, the selected frequency points can lie in the low frequency range where the formation flexural dispersions normally show large separation.', 'In the slow formation case, the selected frequency points can lie in the relatively high frequency range where the dispersion separation is larger.', 'The LWD-DATC cost function is then evaluated by computer-implemented methods to determine the angle θ where the total energy projected onto the signal subspace defined by the two Bessel functions J(ω) and Y(ω) along the fast and slow flexural dispersions is maximized.', 'In block \n1611\n, the angle θ obtained by the maximized cost function in block \n1609\n can be used to estimate the fast shear direction of the formation as θ degrees away from the respective D1 or D2 dipole firing direction.', 'In other words, the parameter value for the angle θ as obtained by the maximized cost function in block \n1609\n represents the fast shear direction of the formation.', 'The slow shear direction of the formation can be calculated by an offset of 90° relative to the fast shear direction of the formation as is evident from \nFIGS.', '5A and 5B\n.', 'In block \n1613\n, the workflow evaluates a stopping criterion to determine if the stopping criterion is satisfied.', 'There are a number of possible options for the choice of stopping criterion.', 'One choice is to re-iterate the process once and see if the estimated fast shear azimuth is close enough to its estimate in the previous iteration.', 'If the two estimates are close (subject to a threshold), then the workflow ends and outputs the estimated fast shear azimuth direction in the last iteration or the average value as the final estimate of the fast shear azimuth direction.', 'If so (yes), the fast shear direction as determined in block \n1611\n is stored and output as the fast shear azimuth direction of the slow formation.', 'If not (no), the data vectors output from block \n1601\n (e.g., the two-component data vectors of Eqn.', '(15)) can be rotated at one or more predetermined rotation angles in block \n1615\n in a manner similar to block \n1603\n and the operations of blocks \n1605\n to \n1613\n can be repeated for one or more additional iterations until the stopping criterion is satisfied.', 'To evaluate the effectiveness of the LWD-DATC cost function, first consider a slow formation, which is the same case as shown in \nFIGS.', '15A, 15B and 15C\n.', 'To construct the LWD-DATC cost function for the slow formation, the wavenumbers of the fast and slow collar-formation flexural modes are used as inputs to compute the matrix D(ω, θ) of Eqn.', '(29) via the matrices J\nf\n, J\ns\n,', 'Y\nf\n, Y\ns \nof Eqn. (25).', 'To validate the proposed frequency-domain workflow, true model wavenumbers can be used to construct the LWD-DATC cost function.', 'In this case, the inline and crossline array waveforms arising from only the D1 firing are used.', 'Specifically, the D1 firing direction is 45° away from the fast shear direction.', 'FIG.', '18A\n shows the model slowness dispersion of the fast and slow coupled collar-formation flexural modes.', 'The solid dots between 3.5 and 6 kHz represents a band limited dispersion used in the frequency-domain workflow.', 'FIG.', '18B\n shows the one-dimensional LWD-DATC cost function, which is constructed by using the inline and crossline waveforms between 3.5 and 6 kHz from a dipole firing which is 45° away from the fast shear direction.', 'The maximum of the LWD-DATC cost function corresponds to the fast shear direction, whereas the minimum of the LWD-DATC cost function represents the slow shear direction.', 'The difference between the maximum and minimum reflects the calculated difference between the fast and slow shear polarization directions.', 'Note that the true model slowness dispersion of the fast and slow coupled collar-formation flexural modes between 3.5 and 6 kHz is used to construct the LWD-DATC cost function, which computes the projected total signal energy between 3.5 and 6 kHz.', 'It is further seen in \nFIG.', '18B\n that the maximum of the LWD-DATC cost function provides the fast shear direction at 46.68°, whereas the minimum yields the slow shear direction.', 'The difference between the maximum and minimum reflects the difference between the fast and slow shear polarization directions.', 'In practice, the measured dispersion for the fast and slow flexural waves may not be known in advance.', 'To address this issue, the inline and crossline array waveforms can be rotated by a set of pre-determined angles in block \n1603\n.', 'For instance, the inline and crossline array waveforms can be rotated by a set of three pre-determined angles [20°, 40°, 60°], and the pre-rotated waveforms showing the largest flexural dispersion splitting can be selected.', 'Then, in block \n1609\n, estimated flexural dispersions from the pre-rotated waveforms (block \n1605\n) are used to construct the LWD-DATC cost function (block \n1607\n).', 'In an example shown in \nFIGS.', '19A and 19B\n, two slowness dispersions of the fast and slow coupled collar-formation flexural modes are selected from the pre-rotated waveforms with a pre-determined angle of 60° to construct the LWD-DATC cost function.', 'The selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes are used to construct and evaluate the LWD-DATC cost function shown in \nFIG.', '19B\n.', 'Note that the maximum of the LWD-DATC cost function is shifted to the left to 42.5° and this effect may be attributed to the pre-rotation.', 'One may mitigate this effect by using multiple pre-determined angles with a finer step size.', 'Consider another case with a D2 firing direction that is 67° away from the fast-shear direction in a slow formation.', 'Again, the inline and crossline array waveforms can be rotated by a set of pre-determined angles in block \n1603\n.', 'For instance, the inline and crossline array waveforms can be rotated by a set of three pre-determined angles [20°, 40°, 60°], and the pre-rotated waveforms showing the largest flexural dispersion splitting can be selected.', 'Then, in block \n1609\n, estimated flexural dispersions from the pre-rotated waveforms (block \n1605\n) are used to construct the LWD-DATC cost function (block \n1607\n).', 'In an example shown in \nFIGS.', '20A, 20B and 20C\n, two slowness dispersions of the fast and slow coupled collar-formation flexural modes are selected from the pre-rotated waveforms with a pre-determined angle of 60° to construct the LWD-DATC cost function.', 'The selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes are used to construct and evaluate the LWD-DATC cost function shown in \nFIG.', '20B\n, which attains its maximum at 67.18°.', 'The rotated inline and crossline waveforms are shown in \nFIG.', '20C\n.', 'Note that, the crossline energy is not minimized to zero as the LWD-DATC cost function does not minimize the crossline energy directly.', 'Nevertheless, the crossline energy is relatively small when it is compared with the inline waveform energy.', 'Finally, consider the frequency-domain workflow in a fast formation with the physical parameters given in Table 1 where a single dipole D2 firing direction is 85° from the fast shear direction.', 'Again, the inline and crossline array waveforms can be rotated by a set of pre-determined angles in block \n1603\n.', 'For instance, the inline and crossline array waveforms can be rotated by a set of three pre-determined angles [0°, 20°, 40°, 60°], and the pre-rotated waveforms showing the largest flexural dispersion splitting can be selected.', 'Then, in block \n1609\n, estimated flexural dispersions from the pre-rotated waveforms (block \n1605\n) are used to construct the LWD-DATC cost function (block \n1607\n).', 'In an example shown in \nFIGS.', '21A, 21B and 21C\n, by applying the multiple pre-rotation angles in block \n1603\n, it is found that the raw inline and crossline array waveforms (rotated by 0°) yield the best flexural dispersion splitting, especially for the formation flexural dispersion at low frequencies.', 'Then, in block \n1609\n, the tool fast and slow flexural dispersion mode estimates between 3.5 and 6 kHz (the upper branch of \nFIG.', '21A\n shows the tool slow flexural mode and the tool fast flexural mode with dots labelled “slow” and “fast”, respectively) as well as the formation fast and slow flexural dispersion mode estimates between 3.5 and 6 kHz (the lower branch of \nFIG.', '21A\n shows the formation slow flexural mode and the formation fast flexural mode with dots labelled “slow” and “fast”, respectively) are extracted from the raw inline and crossline array waveforms and used to compute the LWD-DATC cost function shown in \nFIG.', '20B\n.', 'The estimated rotation angle is 84.61°.', 'Note that for the assumed fast formation, the difference between the maximum and minimum of the LWD-DATC cost function is significantly smaller than that of the slow formation previously considered.', 'In addition, \nFIG.', '21C\n displays the rotated inline and crossline array waveforms, where the inline array waveforms clearly exhibit significantly larger amplitudes while the crossline array waveforms are significantly reduced.', 'In one aspect, some of the methods and processes described above for the time-domain and/or the frequency-domain workflows are performed by a processor.', 'The term “processor” should not be construed to limit the embodiments disclosed herein to any particular device type or system.', 'The processor may include a computer system which can be part of the Logging and Control System \n151\n of \nFIG.', '6\n.', 'The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing any of the methods and processes described above.', 'The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.', 'Some of the methods and processes described above, can be implemented as computer program logic for use with the computer processor.', 'The computer program logic may be embodied in various forms, including a source code form or a computer executable form.', 'Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, or JAVA).', 'Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor.', 'The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).', 'Alternatively or additionally, the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)).', 'Any of the methods and processes described above can be implemented using such logic devices.\n \nFIG.', '22\n shows an example computing system \n300\n that can be used to implement the methods and processes described above for the time-domain and/or the frequency-domain workflows or parts thereof.', 'The computing system \n300\n can be an individual computer system \n301\nA or an arrangement of distributed computer systems.', 'The computer system \n301\nA includes one or more analysis modules \n303\n (a program of computer-executable instructions and associated data) that can be configured to perform various tasks according to some embodiments, such as the tasks described above.', 'To perform these various tasks, an analysis module \n303\n executes on one or more processors \n305\n, which is (or are) connected to one or more storage media \n307\n.', 'The processor(s) \n305\n is (or are) also connected to a network interface \n309\n to allow the computer system \n301\nA to communicate over a data network \n311\n with one or more additional computer systems and/or computing systems, such as \n301\nB, \n301\nC, and/or \n301\nD. Note that computer systems \n301\nB, \n301\nC and/or \n301\nD may or may not share the same architecture as computer system \n301\nA, and may be located in different physical locations.', 'The processor \n305\n can include at least a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, digital signal processor (DSP), or another control or computing device.', 'The storage media \n307\n can be implemented as one or more non-transitory computer-readable or machine-readable storage media.', 'Note that while in the embodiment of \nFIG.', '22\n, the storage media \n307\n is depicted as within computer system \n301\nA, in some embodiments, storage media \n307\n may be distributed within and/or across multiple internal and/or external enclosures of computing system \n301\nA and/or additional computing systems.', 'Storage media \n307\n may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices.', 'Note that the computer-executable instructions and associated data of the analysis module(s) \n303\n can be provided on one computer-readable or machine-readable storage medium of the storage media \n307\n, or alternatively, can be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes.', 'Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture).', 'An article or article of manufacture can refer to any manufactured single component or multiple components.', 'The storage medium or media can be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions can be downloaded over a network for execution.', 'It should be appreciated that computing system \n300\n is only one example of a computing system, and that computing system \n300\n may have more or fewer components than shown, may combine additional components not depicted in the embodiment of \nFIG.', '22\n, and/or computing system \n300\n may have a different configuration or arrangement of the components depicted in \nFIG.', '22\n.', 'The various components shown in \nFIG.', '22\n may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.', 'There have been described and illustrated herein several embodiments of methods and systems for determining fast and slow shear directions in an anisotropic formation using a logging while drilling tool.', 'While particular embodiments of the invention have been described, those skilled in the art will readily appreciate that many modifications are possible in the examples without materially departing from this subject disclosure.', 'For example, the workflows described herein can be adapted to account for both rotation and sliding motion of the logging while drilling tool during excitation of the time-varying pressure field in the formation surround the borehole and the acquisition of waveforms resulting thereform.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.'] | ['1.', 'A method of determining properties of an anisotropic formation surrounding a borehole, comprising:\nproviding a logging-while-drilling tool that is moveable through the borehole, the logging-while-drilling tool having at least one dipole acoustic source spaced from an array of receivers;\nduring movement of the logging-while-drilling tool, operating the at least one dipole acoustic source to excite a time-varying pressure field in the anisotropic formation surrounding the borehole, wherein the at least one dipole acoustic source produces a predefined excitation of an oriented dipole transmitter wavefield in the borehole at a particular azimuthal direction;\nduring the movement of the logging-while-drilling tool, using the array of receivers to measure waveforms arising from the time-varying pressure field in the anisotropic formation surrounding the borehole; and\nprocessing the waveforms measured by the array of receivers to determine a parameter value that represents shear directionality of the anisotropic formation surrounding the borehole, wherein:\nthe processing involves processing waveforms measured by the array of receivers in the frequency domain for the predefined excitation to evaluate a cost function which is based on a propagation model of dispersion extracted from the waveforms, and\nthe cost function is evaluated to maximize energy projected onto a signal subspace defined by two Bessel functions J(w) and Y(w) along fast and slow flexural dispersions of the waveforms.', '2.', 'A method according to claim 1, wherein the movement of the logging-while-drilling tool involves at least one of rotation and sliding motion of the logging-while-drilling tool.', '3.', 'A method according to claim 1, wherein the parameter value represents a fast shear direction of the anisotropic formation.', '4.', 'A method according to claim 1, wherein the parameter value represents a slow shear direction of the anisotropic formation.', '5.', 'A method according to claim 1, wherein the parameter that represents shear directionality of the anisotropic formation is used to generate synthetically-rotated waveforms, and the synthetically-rotated waveforms are used to estimate dipole shear slowness of the formation.', '6.', 'A method according to claim 1, wherein:\nthe movement of the logging-while-drilling tool involves rotation of the logging-while-drilling tool;\nthe Bessel function J(w) is configured to account for flexural mode of the formation; and\nthe Bessel function Y(w) is configured to account for propagation of a drill-collar flexural wave in an annulus between the rotating logging-while-drilling tool and the formation as well as coupling between the moving logging-while-drilling tool and the formation.', '7.', 'A method according to claim 1, wherein:\nthe cost function involves a set of frequency points that are selected based on estimated dispersion of fast and slow flexural modes.', '8.', 'A method according to claim 1, wherein:\nthe propagation model is determined by rotating two-component data vectors over a set of one or more predetermined rotation angles.', '9.', 'A method according to claim 8, wherein:\nthe two-component data vectors are defined by inline and crossline waveforms received by the array of receivers that correspond to the predefined excitation.', '10.', 'A method according to claim 8, wherein:\nthe propagation model is determined by rotating two-component data vectors over a plurality of predetermined rotation angles, and selecting rotated two-component data vectors that show largest flexural dispersion splitting.\n\n\n\n\n\n\n11.', 'A method according to claim 10, wherein:\nthe set of one or more predetermined rotation angles is configured to cover fast shear direction of the formation based on fast shear directions acquired from other depths in the formation.', '12.', 'A method according to claim 8, wherein:\nthe rotated two-component data vectors are used to estimate dispersion of fast and slow flexural modes arising from the predefined excitation of the sonic dipole transmitter; and\nthe estimated dispersion of fast and slow flexural modes is used to define the propagation model.'] | ['FIG.', '1 is a schematic diagram of a transversely isotropic formation with a vertical axis of symmetry (TIV).; FIG.', '2 is a schematic diagram of a transversely isotropic formation with a horizontal axis of symmetry (TIH).; FIG.', '3 is a schematic diagram illustrating a drill-colar mode (dashed curve labeled “blue”) that propogates in a Logging-While-Drilling (LWD) acoustic measurement tool and that interferes with a formation mode (dashed curve labeled “green”).;', 'FIGS.', '4A and 4B are schematic diagrams illustrating cross-dipole orthogonal firing of a wireline acoustic measurement tool.;', 'FIGS.', '5A and 5B are schematic diagrams illustrating non-orthogonal dipole firings of an LWD acoustic measurement tool.; FIG.', '6 is a schematic diagram of a wellsite system that can be used in practicing the embodiments of the subject disclosure.', '; FIG. 7 is a schematic diagram of a LWD acoustic measurement tool that can be used in practicing the embodiments of the subject disclosure.', '; FIG. 8 is a flowchart illustrating a time-domain workflow according to an embodiment of the subject disclosure.;', 'FIGS.', '9A and 9B illustrate synthetic time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, of a dipole transmitter in the horizontal section of a fast TIV formation.', '; FIG.', '9C illustrates the slowness dispersions of the synthetic time-domain waveforms of FIGS.', '9A and 9B in the horizontal section of a fast TIV formation.', '; FIG.', '10 illustrates a two-dimensional cost function of the four-component non-orthogonal LWD waveform rotation for the example of FIGS.', '9A, 9B and 9C.; FIGS.', '11A and 11B illustrate rotated time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, for the example of FIGS.', '9A, 9B and 9C.; FIG.', '11C illustrates the slowness dispersions of the rotated time-domain waveforms of FIGS.', '11A and 11B', 'in the horizontal section of the fast TIV formation.', '; FIGS.', '12A and 12B illustrate synthetic time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, from a dipole source in the horizontal section of a fast TIV formation.', 'The D1 and D2 firings are, respectively, 35 and 67 degrees away from the slow shear azimuth.', '; FIG.', '12C illustrates the slowness dispersions of the time-domain waveforms of FIGS.', '12A and 12B in the horizontal section of the fast TIV formation.', '; FIG. 13 illustrates a two-dimensional cost function of the four-component non-orthogonal LWD waveform rotation for the example of FIGS.', '12A, 12B and 12C.; FIGS.', '14A and 14B illustrate rotated time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, for the example of FIGS.', '12A, 12B and 12C.; FIG.', '14C illustrates the slowness dispersions of the rotated time-domain waveforms of FIGS.', '14A and 14B in the horizontal section of the fast TIV formation.', '; FIGS.', '15A and 15B illustrate rotated time-domain waveforms arising from non-orthogonal D1 and D2 firings, respectively, from a dipole source in the horizontal section of a slow TIV formation.', '; FIG.', '15C illustrates the slowness dispersions of the rotated time-domain waveforms of FIGS.', '15A and 15B in the horizontal section of the slow TIV formation.', '; FIG.', '16 is a flowchart illustrating a frequency-domain workflow according to an embodiment of the subject disclosure.', '; FIG.', '17 is a schematic diagram illustrating shear wave splitting arising from a dipole transmitter in anisotropic formations and principal polarization directions.; FIG.', '18A illustrates an exemplary model slowness dispersion of the fast and slow coupled collar-formation flexural modes arising from a dipole firing which is 45° away from the fast shear direction in a slow formation.', 'The solid dots between 3.5 and 6 kHz represents a band limited dispersion used in the frequency-domain workflow.;', 'FIG.', '18B shows an exemplary one-dimensional LWD-DATC cost function, which is constructed using raw inline and crossline waveforms between 3.5 and 6 kHz.; FIG.', '19A shows two exemplary slowness dispersions of the fast and slow coupled collar-formation flexural modes arising from a dipole firing which is 45° away from the fast shear direction in a slow formation (same as FIG.', '18A), where the slowness dispersions are extracted from pre-rotated inline and crossline waveforms with a pre-determined angle of 60°.; FIG.', '19B shows an exemplary one-dimensional LWD-DATC cost function constructed from selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes of FIG.', '19A.; FIG.', '20A shows two exemplary slowness dispersions of the fast and slow coupled collar-formation flexural modes arising from a dipole firing that is 67° away from the fast shear direction (different from FIGS.', '18A and 19A) in a slow formation, where the slowness dispersions are extracted from pre-rotated inline and crossline waveforms with a pre-determined angle of 60°.; FIG.', '20B shows an exemplary one-dimensional LWD-DATC cost function constructed from selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes of FIG.', '20A.; FIG.', '20C shows rotated inline and crossline waveforms for the example of FIG.', '20A when the inline receivers are parallel to the fast shear direction of the slow formation.', '; FIG.', '21A shows two exemplary slowness dispersions of the fast and slow coupled collar-formation flexural modes arising from a dipole firing that is 85° away from the fast shear direction in a fast formation, where the slowness dispersions are extracted from raw (non-rotated) inline and crossline waveforms; FIG.', '21B shows an exemplary one-dimensional LWD-DATC cost function constructed from selected slowness dispersions (denoted as solid dots) for the fast and slow flexural modes of FIG.', '21A.; FIG.', '21C shows rotated inline and crossline waveforms for the example of FIG.', '21A when the inline receivers are parallel to the fast shear direction of the fast formation.', '; FIG.', '22 shows an example computing system that can be used to implement the time-domain and frequency domain workflows as described herein.; FIG.', '6 illustrates a wellsite system in which the workflows of the present disclosure can be employed.', 'The wellsite can be onshore or offshore.', 'In this exemplary system, a borehole 11 is formed in subsurface formations by rotary drilling in a manner that is well known.', 'Embodiments of the present disclosure can also use directional drilling, as will be described hereinafter.; FIG.', '7 schematically illustrates selected components of the acoustic measurement LWD module 120 of FIG.', '6 according to embodiments of the subject disclosure.', 'A pipe portion 203 defines a mud channel 205.', 'Distributed on the pipe portion 203 is a number of acoustic transmitters including a pair of dipole transmitters 201 that transmit directional D1 and D2 dipole firings.', 'An array of receivers 207 and receiver electronics 211 are distributed on the pipe portion 203.', 'The array of receivers receive the four-component waveforms of the acoustic energy that results from the directional D1 and D2 dipole firings as described herein.', 'A surface-located processing facility 151 (FIG. 6) controls the D1 and D2 firings of the dipole transmitters 201 and the receiver electronics 211.', 'The processing facility 151 can be located in one or more locations at the wellsite.', 'According to some embodiments, the processing facility 151 can process and interpret the data from the acoustic measurement LWD module 120 at one or more locations remote from the wellsite.', 'The processing facility 151 may include one or more central processing units, storage systems, communications and input/output modules, a user display, and a user input system.;', 'FIGS.', '9A and 9B show the synthetic received time-domain array waveforms generated from the dipole transmitter in the horizontal section of the fast TIV formation.', 'The D1 and D2 firings are, respectively, 15 and 85 degrees away from the slow shear azimuth.', 'In this case, the D1 inline array waveforms are mostly dominated by the propagation from the slow shear direction, while the D2 inline array waveforms are mostly dominated by the propagation from the fast shear direction.', 'FIG.', '9C shows the slowness dispersions generated from the dipole transmitter in the horizontal section of the fast TIV formation.', 'The slowness dispersions represent the dipole flexural dispersion extracted by the matrix pencil method, referred to as the TKO algorithm and described in M. P. Ekstrom, “Dispersion estimation from borehole acoustic arrays using a modified matrix pencil algorithm,”', 'Proc. 29th Asilomar Conf.', 'Signals, Syst., Comput., vol.', '2, Pacific Grove, Calif., November 1995, pp. 449-453. FIG.', '9C shows that two flexural modes are present in the fast TIV formation.', 'The upper branch (above 200 us/ft) is the dominant drill-collar flexural dispersion, while the lower branch is the formation flexural dispersion.', 'The low frequency asymptotes of the formation flexural dispersions (D1 shown with dots labeled with “∘” and D2 shown with dots labeled with “+”) approach to the fast and slow shear slownesses in Table 1.', 'Specifically, the formation flexural dispersion of D1 is similar to the slow flexural dispersion as D1 is close to the slow shear azimuth.', '; FIG.', '10 shows a two-dimensional cost function of the four-component non-orthogonal LWD waveform rotation in the (θ1=θ2=θ+ϕ) plane (Block 815 of FIG.', '8) for the synthetic example of FIGS.', '9A and 9B. The two dashed lines are constraints for the upper and lower limit of the angle difference between the D1 and D2 firing directions.', 'Such constraints can be derived from the tolerance of D1 and D2 firing directions as measured during rotation of the LWD acoustic measurement tool, for example by a magnometer.', 'It is easy to observe that the global minima are located at (14.2°, 84.9°) and (104.2°, 174.9°) for [θ, θ+ϕ].', 'Note that there is a 90° ambiguity in the [θ, θ+ϕ] plane as one can rotate D1 to the fast shear direction and D2 to the slow shear direction or vice versa.', 'Since the workflow values the cost function to find the minimization of the total crossline energy, the coordinates of the global minima give the estimated rotation angles.', 'From FIG.', '10, the workflow searches for the minima within a bounded region (in between the two dashed lines) and the local minima are seen at (01=14.2°, θ2=84.9°) and (θ1=104.2°, θ2=174.9°), where the former one gives the slow shear polarization direction (i.e., 14.2° away from the D1 firing or 84.9° away from the D2 firing) and the latter one yields the fast shear direction due to a 90° ambiguity.', 'Nevertheless, the 90° ambiguity can be removed by rotating the four-component waveforms and identifying which rotated waveforms correspond to the fast and slow flexural waveforms as described in C. Esmersoy, K. Koster, M. Williams, A. Boyd and M. Kane, “Dipole shear anisotropy logging”, 64th Ann.', 'Internat.', 'Mtg., Soc.', 'Expl.', 'Geophys., Expanded Abstracts, 1139-1142, 1994.; FIGS.', '11A and 11B show the rotated inline and crossline array waveforms for the D1 and D2 dipole firings of FIGS.', '9A and 9B. Particularly, the D1 firing is rotated to the slow shear direction while D2 is rotated towards the fast shear direction using the estimated rotation angles from FIG.', '10.', 'Note that the crossline energy of the rotated waveforms is significantly minimized and the inline waveform energy is enhanced.', 'The modified matrix pencil algorithm (TKO method) can be used to extract the dispersion curves from the rotated inline array waveforms of D1 and D2.', 'FIG.', '11C shows the corresponding slowness dispersions.', 'Note that formation flexural dispersion (dots labeled with “∘”) of the rotated D1 captures the slow flexural wave, while the formation flexural dispersion (dots labeled with “+”) of the rotated D2 converges to the fast flexural shear around 110 us/ft.; FIGS.', '12A and 12B show synthetic time-domain array waveforms arising from the D1 and D2 firings of the dipole transmitter in the horizontal section of a fast TIV formation.', 'The D1 and D2 firings are, respectively, 35° and 67° away from the slow shear azimuth.', 'In this case, the D1 and D2 inline array waveforms contain a mixture of both the fast and slow flexural waves.', 'Note that the inline and crossline array waveforms for the D1 and D2 dipole firings are closer to an azimuth direction in between the fast and slow shear direction.', 'Specifically, the the D1 and D2 dipole firings are 35° and 67° away from the slow shear direction, respectively.', 'Compared with the case of FIGS.', '9A and 9B, more waveform energy is split into the crossline channel, as both dipole firings move away from either the fast or slow shear directions.', 'FIG.', '12C shows the corresponding slowness dispersions.', 'In FIG.', '12C, one can no longer see the formation flexural splitting at low frequencies from the inline receivers.; FIG.', '13 shows the two-dimensional cost function (Block 815 of FIG.', '8) for the synthetic example of FIGS.', '12A and 12B. The two dashed lines represent the constraints for the upper and lower limit of the angle difference between the D1 and D2 firing directions.', 'The estimated rotation angles are (θ1=34.4°, θ2=66.7) within the two dashed lines (the constraints).', '; FIGS.', '14A and 14B show the rotated inline and crossline array waveforms for the D1 and D2 dipole firings of FIGS.', '12A and 12B. Note that the crossline energy of the rotated array waveforms is significantly minimized and the inline array waveforms display the fast and slow flexural modes.', 'FIG.', '14C shows the corresponding slowness dispersions.', 'Note that the TKO results on the rotated inline array waveforms recover the formation flexural dispersions splitting at frequencies below 4 kHz.; FIGS.', '15A and 15B shows the rotated synthesized inline and crossline array waveforms for D1 and D2 dipole firings in the horizontal section of a slow TIV formation.', 'FIG.', '15C shows the corresponding slowness dispersions.', 'The TKO results in FIG.', '15C show the coupled collar-flexural dispersions corresponding to the inline waveforms from the rotated D1 and D2.', 'The flexural splitting at high frequencies is clearly observed.', 'In this case, the fast and slow shear slownesses can be inverted from the fast and slow flexural dispersions using a model-based workflow as described in U.S. patent application Ser.', 'No. 15/331,946, filed on Oct. 24, 2016, entitled “Determining Shear Slowness from Dipole Source-based Measurements Acquired by a Logging-While-Drilling Acoustic Measurement Tool.”', '; FIG.', '18A shows the model slowness dispersion of the fast and slow coupled collar-formation flexural modes.', 'The solid dots between 3.5 and 6 kHz represents a band limited dispersion used in the frequency-domain workflow.', 'FIG.', '18B shows the one-dimensional LWD-DATC cost function, which is constructed by using the inline and crossline waveforms between 3.5 and 6 kHz from a dipole firing which is 45° away from the fast shear direction.', 'The maximum of the LWD-DATC cost function corresponds to the fast shear direction, whereas the minimum of the LWD-DATC cost function represents the slow shear direction.', 'The difference between the maximum and minimum reflects the calculated difference between the fast and slow shear polarization directions.', 'Note that the true model slowness dispersion of the fast and slow coupled collar-formation flexural modes between 3.5 and 6 kHz is used to construct the LWD-DATC cost function, which computes the projected total signal energy between 3.5 and 6 kHz.', 'It is further seen in FIG.', '18B that the maximum of the LWD-DATC cost function provides the fast shear direction at 46.68°, whereas the minimum yields the slow shear direction.', 'The difference between the maximum and minimum reflects the difference between the fast and slow shear polarization directions.; FIG.', '22 shows an example computing system 300 that can be used to implement the methods and processes described above for the time-domain and/or the frequency-domain workflows or parts thereof.', 'The computing system 300 can be an individual computer system 301A or an arrangement of distributed computer systems.', 'The computer system 301A includes one or more analysis modules 303 (a program of computer-executable instructions and associated data) that can be configured to perform various tasks according to some embodiments, such as the tasks described above.', 'To perform these various tasks, an analysis module 303 executes on one or more processors 305, which is (or are) connected to one or more storage media 307.', 'The processor(s) 305 is (or are) also connected to a network interface 309 to allow the computer system 301A to communicate over a data network 311 with one or more additional computer systems and/or computing systems, such as 301B, 301C, and/or 301D. Note that computer systems 301B, 301C and/or 301D may or may not share the same architecture as computer system 301A, and may be located in different physical locations.'] |
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US11111751 | Blowout preventer with dual function rams | Mar 9, 2020 | Patrice Couren, Florent Vargas | Schlumberger Technology Corporation | NPL References not found. | 1834063; December 1931; King; 1886340; November 1932; King; 1966809; July 1934; Wickersham; 3554480; January 1971; Rowe; 4526339; July 2, 1985; Miller; 6161618; December 19, 2000; Parks et al.; 6209565; April 3, 2001; Hughes et al.; 6644410; November 11, 2003; Lindsey-Curran et al.; 7216714; May 15, 2007; Reynolds; 7216715; May 15, 2007; Reynolds; 7222674; May 29, 2007; Reynolds; 7690433; April 6, 2010; Reynolds; 8020623; September 20, 2011; Parks et al.; 8607879; December 17, 2013; Reynolds; 8727013; May 20, 2014; Buckley et al.; 8820410; September 2, 2014; Parks et al.; 9505473; November 29, 2016; Kerins et al.; 20140048275; February 20, 2014; Reynolds et al.; 20170130549; May 11, 2017; Kroesen | 2357537; June 2001; GB; 2009025732; February 2009; WO | ['A dual function ram system for a blowout preventer (BOP) includes a first dual function ram that is configured to move within a cavity of the BOP between a withdrawn position to cause the BOP to be in an open configuration and an extended position to cause the BOP to be in a closed configuration.', 'The first dual function ram includes a shearing surface that is configured to shear a tubular within a central bore during a shearing operation and a pipe-sealing surface that is configured to seal against the tubular within the central bore during a pipe-sealing operation.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'A blowout preventer (BOP) is installed on a wellhead to seal and control an oil and gas well during various operations.', 'For example, during drilling operations, a drill string may be suspended from a rig through the BOP into a wellbore.', 'A drilling fluid is delivered through the drill string and returned up through an annulus between the drill string and a casing that lines the wellbore.', 'In the event of a rapid invasion of formation fluid in the annulus, commonly known as a “kick,” the BOP may be actuated to seal the annulus and to control fluid pressure in the wellbore, thereby protecting well equipment positioned above the BOP.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n is a block diagram of a mineral extraction system, in accordance with an embodiment of the present disclosure;\n \nFIG.', '2\n is a cross-sectional top view of a portion of a blowout preventer (BOP) that may be used in the mineral extraction system of \nFIG.', '1\n, in accordance with an embodiment of the present disclosure;\n \nFIG.', '3\n is a perspective view of dual function rams that may be used in the BOP of \nFIG.', '2\n, wherein the dual function rams are in a first mode and are in a withdrawn position, in accordance with an embodiment of the present disclosure;\n \nFIG.', '4\n is a perspective view of the dual function rams of \nFIG.', '3\n, wherein the dual function rams are in the first mode and are in an extended position, in accordance with an embodiment of the present disclosure;\n \nFIG.', '5\n is a perspective view of the dual function rams of \nFIG.', '3\n, wherein the dual function rams are in a second mode and are in the withdrawn position, in accordance with an embodiment of the present disclosure;\n \nFIG.', '6\n is a perspective view of the dual function rams of \nFIG.', '3\n, wherein the dual function rams are in the second mode and are in the extended position, in accordance with an embodiment of the present disclosure;\n \nFIG.', '7\n is a cross-sectional perspective view of a dual function cavity that may be used in the BOP of \nFIG.', '2\n, in accordance with an embodiment of the present disclosure;\n \nFIG.', '8\n is a perspective view of dual function rams that may be used in the dual function cavity of \nFIG.', '7\n, wherein the dual function rams are in a first mode and are in a withdrawn position, in accordance with an embodiment of the present disclosure;\n \nFIG.', '9\n is a perspective view of the dual function rams of \nFIG.', '8\n, wherein the dual function rams are in the first mode and are in an extended position, in accordance with an embodiment of the present disclosure', ';\n \nFIG.', '10\n is a perspective view of the dual function rams of \nFIG.', '8\n, wherein the dual function rams are in a second mode and are in the withdrawn position, in accordance with an embodiment of the present disclosure;\n \nFIG.', '11\n is a perspective view of the dual function rams of \nFIG.', '8\n, wherein the dual function rams are in the second mode and are in the extended position, in accordance with an embodiment of the present disclosure;\n \nFIG.', '12\n is a cross-sectional perspective view of one of the dual function rams of \nFIG.', '8\n, in accordance with an embodiment of the present disclosure; and\n \nFIG.', '13\n is a flow diagram of a method of operating a BOP having dual function rams, in accordance with an embodiment of the present disclosure.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nOne or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'The present embodiments are generally directed to blowout preventers (BOPs).', 'In particular, the present embodiments are generally directed to BOPs that include dual function rams supported within a cavity that is transverse to a central bore of the BOP.', 'The dual function rams may move within the cavity toward one another to an extended position to adjust the BOP to a closed configuration to block fluid flow through the central bore of the BOP and away from one another to a withdrawn position to adjust the BOP to an open configuration to enable fluid flow through the central bore of the BOP.', 'As discussed in more detail below, the dual function rams are configured to operate in two modes.', 'For example, the dual function rams may operate in a pipe mode to seal an annular space about a conduit within the central bore of the BOP during a first operation, and the dual function rams may then be rotated within the cavity (e.g., relative to the cavity) to operate in a shear mode to shear the conduit within the central bore of the BOP during a second operation.', 'The disclosed features may reduce a height of a BOP stack (e.g., having the BOP) and/or enable the BOP stack to include additional BOPs without increasing the height of the BOP stack, for example.', 'While the disclosed embodiments are described in the context of a drilling system and drilling operations to facilitate discussion, it should be appreciated that the BOP may be adapted for use in other contexts and during other operations.', 'For example, the BOP may be used in a production system and/or a pressure control equipment (PCE) stack that is coupled to and/or positioned vertically above a wellhead during various intervention operations (e.g., inspection or service operations), such as wireline operations in which a tool supported on a wireline is lowered through the PCE stack to enable inspection and/or maintenance of a well.', 'In such cases, the BOP may be adjusted from the open configuration to the closed configuration (e.g., to shear or to seal about the wireline extending through the PCE stack) to isolate the environment, as well as other surface equipment, from pressurized fluid within the well.', 'In the present disclosure, a conduit may be any of a variety of tubular or cylindrical structures, such as a drill string, wireline, Streamline™, slickline, coiled tubing, or other spoolable rod.', 'With the foregoing in mind, \nFIG.', '1\n is a block diagram of an embodiment of a mineral extraction system \n10\n.', 'The mineral extraction system \n10\n may be configured to extract various minerals and natural resources, including hydrocarbons (e.g., oil and/or natural gas), from the earth and/or to inject substances into the earth.', 'The mineral extraction system \n10\n may be a land-based system (e.g., a surface system) or an offshore system (e.g., an offshore platform system).', 'As shown, a BOP stack \n12\n may be mounted to a wellhead \n14\n, which is coupled to a mineral deposit \n16\n via a wellbore \n18\n.', 'The wellhead \n14\n may include any of a variety of other components such as a spool, a hanger, and a “Christmas” tree.', 'The wellhead \n14\n may return drilling fluid or mud toward a surface during drilling operations, for example.', 'Downhole operations are carried out by a conduit \n20\n (e.g., drill string) that extends through a central bore \n22\n of the BOP stack \n12\n, through the wellhead \n14\n, and into the wellbore \n18\n.', 'As discussed in more detail below, the BOP stack \n12\n may include one or more BOPs \n24\n (e.g., ram BOPs), and at least one of the BOPs \n24\n may include dual function rams.', 'To facilitate discussion, the BOP stack \n12\n and its components may be described with reference to a vertical axis or direction \n30\n, an axial axis or direction \n32\n, a lateral axis or direction \n34\n, and a circumferential axis or direction \n36\n.', 'FIG.', '2\n is a cross-sectional top view of a portion of the BOP \n24\n that may be used in the mineral extraction system \n10\n of \nFIG.', '1\n, in accordance with an embodiment of the present disclosure.', 'As shown, a first dual function ram \n50\n (e.g., first ram) and a second dual function ram \n52\n (e.g., second ram) are positioned such that the BOP \n24\n is in an open configuration \n54\n.', 'In the open configuration \n54\n, the first dual function ram \n50\n and the second dual function ram \n52\n are withdrawn from the central bore \n22\n, do not contact the conduit \n20\n, and/or do not contact the corresponding opposing ram \n50\n, \n52\n.', 'As shown, the BOP \n24\n includes a body \n56\n (e.g., housing) surrounding the central bore \n22\n.', 'The body \n56\n is generally rectangular in the illustrated embodiment, although the body \n56\n may have any cross-sectional shape, including any polygonal shape and/or annular shape.', 'Bonnet assemblies \n60\n are mounted to the body \n56\n (e.g., via threaded fasteners).', 'In the illustrated embodiment, first and second bonnet assemblies \n60\n are mounted to opposite sides of the body \n56\n.', 'Each bonnet assembly \n60\n supports an actuator \n62\n, which may include a piston \n64\n and a connecting rod \n66\n.', 'As shown in the illustrated embodiment of \nFIG.', '2\n, when in the open configuration \n54\n, the first dual function ram \n50\n is generally adjacent to a first end \n68\n of the body \n56\n and the second dual function ram \n52\n is generally adjacent to a second end \n70\n, opposite the first end \n68\n, of the body \n56\n.', 'The actuators \n62\n may drive the first and second dual function rams \n50\n, \n52\n toward and away from one another along the axial axis \n32\n and through the central bore \n22\n to contact and/or shear the conduit \n20\n to seal the central bore \n22\n.', 'As discussed in more detail below, the first and second dual function rams \n50\n, \n52\n may be configured to operate in two modes via rotation of the first and second dual function rams \n50\n, \n52\n relative to the body \n56\n.', 'FIG.', '3\n is a perspective view of the first dual function ram \n50\n and the second dual function ram \n52\n in a first mode \n80\n (e.g., shear mode; first position; first position along the circumferential axis \n36\n) and withdrawn from the central bore \n22\n such that the BOP \n24\n is in the open configuration \n54\n.', 'As shown, the first dual function ram \n50\n and the second dual function ram \n52\n are supported within a cavity \n82\n (e.g., ram cavity) that is transverse to the central bore \n22\n of the BOP \n24\n (e.g., a respective central axis of the cavity \n82\n is transverse, such as orthogonal, to a respective central axis of the central bore \n22\n; a respective central axis of the cavity \n82\n is aligned with the axial axis \n32\n and a respective central axis of the central bore \n22\n is aligned with the vertical axis \n30\n).', 'In operation, the first dual function ram \n50\n and the second dual function ram \n52\n move through the cavity \n82\n toward and away from one another.', 'For example, the first dual function ram \n50\n and the second dual function ram \n52\n may move toward one another to transition the BOP \n24\n from the open configuration \n54\n of \nFIG.', '3\n to a closed configuration \n90\n of \nFIG.', '4\n.', 'Similarly, the first dual function ram \n50\n and the second dual function ram \n52\n may move away from one another to transition the BOP \n24\n from the closed configuration \n90\n of \nFIG.', '4\n to the open configuration \n54\n of \nFIG.', '3\n.', 'In the closed configuration \n90\n, the first dual function ram \n50\n and the second dual function ram \n52\n extend into the central bore \n22\n, seal the central bore \n22\n, contact the conduit \n20\n, and/or contact the corresponding opposing ram \n50\n, \n52\n.', 'The first dual function ram \n50\n and the second dual function ram \n52\n may be driven to move toward and away from one another along the axial axis \n32\n via the actuator \n62\n of \nFIG.', '2\n.', 'For example, the first dual function ram \n50\n and the second dual function ram \n52\n may each include a respective feature \n92\n (e.g., protrusion) that is configured to couple (e.g., rotatably or nonrotatably couple) to a respective connecting rod \n66\n of a respective actuator \n62\n to enable the actuators \n62\n to drive the first dual function ram \n50\n and the second dual function ram \n52\n toward and away from one another along the axial axis \n32\n.', 'As noted above, the first dual function ram \n50\n and the second dual function ram \n52\n may be configured to operate in two modes (e.g., different modes, which may correspond to different positions of the first and second dual function rams \n50\n, \n52\n within the cavity \n82\n), such as the first mode \n80\n and a second mode.', 'To enable the first and second dual function rams \n50\n, \n52\n to operate in two modes, the first and second dual function rams \n50\n, \n52\n may have two sets of opposing surfaces that are configured to engage one another.', 'The two sets of opposing surfaces may be offset (e.g., about the circumferential axis \n36\n) from one another such that only one of the two sets of opposing surface is positioned within the central bore \n22\n while the first and second dual function rams \n50\n, \n52\n are extended with the BOP \n24\n in the closed configuration \n90\n of \nFIG.', '4\n.', 'The other set of the two sets of opposing surfaces is positioned outside of the central bore \n22\n while the first and second dual function rams \n50\n, \n52\n are extended with the BOP \n24\n in the closed configuration \n90\n of \nFIG.', '4\n.', 'With reference to \nFIGS.', '3 and 4\n, the first and second dual function rams \n50\n, \n52\n include a first set of opposing surfaces \n100\n that includes a first shear edge \n102\n (e.g., surface) on the first dual function ram \n50\n (e.g., on a body of the first dual function ram \n50\n; on a portion of the body) and a second shear edge \n104\n (e.g., surface) on the second dual function ram \n52\n (e.g., on a body of the second dual function ram \n52\n; on a portion of the body).', 'In the first mode \n80\n (e.g., shear mode), the first shear edge \n102\n and the second shear edge \n104\n are positioned such that the first shear edge \n102\n and the second shear edge \n104\n will enter the central bore \n22\n as the first and second dual function rams \n50\n, \n52\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '4\n.', 'In particular, in the first mode \n80\n, the first shear edge \n102\n and the second shear edge \n104\n may extend along the lateral axis \n34\n, may be positioned at an upper portion of the cavity \n82\n along the vertical axis \n30\n, and/or may face toward one another so as to enable the first shear edge \n102\n and the second shear edge \n104\n to contact and to shear the conduit \n20\n (\nFIG.', '2\n) within the central bore \n22\n.', 'As shown in \nFIGS.', '3 and 4\n, the first and second dual function rams \n50\n, \n52\n also include a second set of opposing surfaces \n110\n that includes a first pipe edge \n112\n (e.g., surface) on the first dual function ram \n50\n (e.g., on the body of the first dual function ram \n50\n; on a portion of the body) and a second pipe edge \n112\n (e.g., surface) on the second dual function ram \n52\n (e.g., on the body of the second dual function ram \n52\n; on a portion of the body).', 'In the first mode \n80\n (e.g., shear mode), the first pipe edge \n112\n and the second pipe edge \n114\n are positioned such that the first pipe edge \n112\n and the second pipe edge \n114\n do not enter the central bore \n22\n as the first and second dual function rams \n50\n, \n52\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '4\n.', 'In particular, in the first mode \n80\n, the first pipe edge \n112\n and the second pipe edge \n114\n may extend along the vertical axis \n30\n and/or may be positioned at a first side portion of the cavity \n82\n along the lateral axis \n34\n so as to enable the first pipe edge \n112\n and the second pipe edge \n114\n to avoid contact with the conduit \n20\n (\nFIG.', '2\n) in the central bore \n22\n, to avoid placement within the central bore \n22\n, and/or to avoid interference with the operation (e.g., shearing operation) of the first shear edge \n102\n and the second shear edge \n104\n.', 'In this way, the first pipe edge \n112\n and the second pipe edge \n114\n may move with the first shear edge \n102\n and the second shear edge \n104\n along the axial axis \n32\n, but may be blocked from entry into the central bore \n22\n while the first shear edge \n102\n and the second shear edge \n104\n are positioned within the central bore \n22\n.', 'In the first mode \n80\n, the first pipe edge \n112\n and the second pipe edge \n114\n may contact one another and may provide support (e.g., structural support) to the first and second dual function rams \n50\n, \n52\n.\n \nFIG.', '5\n is a perspective view of the first dual function ram \n50\n and the second dual function ram \n52\n in a second mode \n118\n (e.g., pipe-sealing mode mode; second position; second position along the circumferential axis \n36\n) and withdrawn from the central bore \n22\n such that the BOP \n24\n is in the open configuration \n54\n.', 'FIG.', '6\n is a perspective view of the first dual function ram \n50\n and the second dual function ram \n52\n in the second mode \n118\n and extended into the central bore \n22\n such that the BOP \n24\n is in the closed configuration \n90\n.', 'The first dual function ram \n50\n and the second dual function ram \n52\n may move toward and away from one another to transition the BOP \n24\n between the open configuration \n54\n of \nFIG.', '5\n and the closed configuration \n90\n of \nFIG.', '6\n.', 'In the second mode \n118\n, the first pipe edge \n112\n and the second pipe edge \n114\n are positioned such that the first pipe edge \n112\n and the second pipe edge \n114\n enter the central bore \n22\n as the first and second dual function rams \n50\n, \n52\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '6\n.', 'In particular, in the second mode \n118\n, the first pipe edge \n112\n and the second pipe edge \n114\n may extend along the lateral axis \n34\n, may be positioned at an upper portion of the cavity \n82\n along the vertical axis \n30\n, and/or may face toward one another so as to enable the first pipe edge \n112\n and the second pipe edge \n114\n to contact one another and to contact the conduit \n20\n (\nFIG.', '2\n) in the central bore \n22\n to seal the annular space about the conduit \n20\n.', 'In the second mode \n118\n, the first shear edge \n102\n and the second shear edge \n104\n are positioned such that the first shear edge \n102\n and the second shear edge \n104\n do not enter the central bore \n22\n as the first and second dual function rams \n50\n, \n52\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '6\n.', 'In particular, in the second mode \n118\n, the first shear edge \n102\n and the second shear edge \n104\n may extend along the vertical axis \n30\n and/or may be positioned at a second side portion (e.g., opposite the first side portion) of the cavity \n82\n along the lateral axis \n34\n so as to enable the first shear edge \n102\n and the second shear edge \n104\n to avoid contact with the conduit \n20\n (\nFIG.', '2\n) in the central bore \n22\n, to avoid placement within the central bore \n22\n, and/or to avoid interference with the operation (e.g., pipe-sealing operation) of the first pipe edge \n112\n and the second pipe edge \n114\n.', 'In this way, the first shear edge \n102\n and the second shear edge \n104\n may move with the first pipe edge \n112\n and the second pipe edge \n114\n along the axial axis \n32\n, but may be blocked from entry into the central bore \n22\n while the first pipe edge \n112\n and the second pipe edge \n114\n are positioned within the central bore \n22\n.', 'In the second mode \n118\n, the first shear edge \n102\n and the second shear edge \n104\n may contact one another and may provide support to the first and second dual function rams \n50\n, \n52\n.', 'As shown, the first dual function ram \n50\n and the second dual function ram \n52\n may be generally cylindrical structures and may include various sealing elements (e.g., packers) within grooves \n120\n to facilitate formation of a seal across the central bore \n22\n while the BOP \n24\n is in the closed configuration \n90\n (e.g., in both the first and second modes \n80\n, \n118\n).', 'The grooves \n120\n are shown without the sealing elements for image clarity.', 'For example, one sealing element may be positioned between the first shear edge \n102\n and the first pipe edge \n112\n along the circumferential axis \n36\n.', 'Additionally, the cylindrical shape may enable the first dual function ram \n50\n and the second dual function ram \n52\n to rotate within the cavity \n82\n (e.g., relative to the body \n56\n; in the circumferential direction \n36\n) to thereby efficiently transition between the first mode \n80\n and the second mode \n118\n.', 'In some embodiments, the first dual function ram \n50\n and the second dual function ram \n52\n may each include a respective groove \n122\n (e.g., curved groove, extending along the circumferential axis \n36\n) that is configured to engage a respective rotating shaft \n124\n.', 'In particular, each groove \n122\n may include a toothed profile \n126\n (e.g., gear profile) and each rotating shaft \n124\n may include a corresponding toothed profile \n128\n (e.g., gear profile).', 'Thus, as each rotating shaft \n124\n rotates (e.g., via an actuator, such as a motor), the engagement between the toothed profiles \n126\n, \n128\n drives the respective dual function ram \n50\n, \n52\n to rotate within the cavity \n82\n.', 'Alternatively, it should be appreciated that any other suitable mechanism, such as the actuator \n62\n (\nFIG.', '2\n), may be capable of driving the first dual function ram \n50\n and the second dual function ram \n52\n to rotate within the cavity \n82\n (e.g., in addition to driving the movement along the axial axis \n32\n).', 'Advantageously, the embodiment of the BOP \n24\n of \nFIGS.', '3-6\n may enable the BOP \n24\n to use the same rams (e.g., the first and second dual function rams \n50\n, \n52\n) to operate in two modes (e.g., the first mode \n80\n and the second mode \n118\n) depending on which of the two modes is desired at the particular time.', 'In this way, the embodiment of the BOP \n24\n of \nFIGS.', '3-6\n may enable the BOP \n24\n to use the same rams (e.g., the first and second dual function rams \n50\n, \n52\n) to carry out two operations (e.g., the shearing operation and the pipe-sealing operation) depending on which of the two operations is desired at the particular time.', 'For example, the BOP \n24\n may operate in the second mode \n118\n to seal the annular space about the conduit \n20\n (\nFIG.', '2\n) during planned maintenance operations, and the BOP \n24\n may be operate in the first mode \n80\n to shear the conduit \n20\n during an unexpected increase in pressure within the wellbore \n18\n (\nFIG.', '1\n).', 'The BOP \n24\n may efficiently switch between the first mode \n80\n and the second mode \n118\n via rotation of the first and second dual function rams \n50\n, \n52\n within the cavity \n82\n (e.g., via the rotating shaft \n124\n).', 'It should be appreciated that manual and/or electronic control may be utilized to rotate the first and second dual function rams \n50\n, \n52\n.', 'For example, an operator may manually drive rotation of the rotating shaft \n124\n to rotate the first and second dual function rams \n50\n, \n52\n.', 'Additionally or alternatively, a control system (e.g., electronic control system) may electronically control the rotation of the rotating shaft \n124\n (e.g., via control of an actuator) to rotate the first and second dual function rams \n50\n, \n52\n.', 'For example, the control system may receive an input (e.g., input by an operator via a user interface; from a sensor that monitors a pressure within the wellbore \n18\n [\nFIG.', '1\n]).', 'In response to the input, the control system may control the rotation of the rotating shaft \n124\n to rotate the first and second dual function rams \n50\n, \n52\n to the desired position that corresponds to the desired mode (e.g., the first or the second mode \n80\n, \n118\n) to prepare for and to enable operation in the desired mode.', 'In some embodiments, the control system may also control the movement of the first and second dual function rams \n50\n, \n52\n along the axial axis \n32\n to adjust the BOP \n24\n between the open configuration \n54\n and the closed configuration \n90\n.', 'With reference to \nFIG.', '3\n, the control system may include a controller \n130\n having a processor \n132\n and a memory device \n134\n.', 'The controller \n130\n may be part of or include a distributed controller or control system with one or more electronic controllers in communication with one another to carry out the various techniques disclosed herein.', 'The processor \n132\n may also include one or more processors configured to execute software, such as software for processing signals and/or controlling the components associated with the BOP \n24\n.', 'The memory device \n134\n disclosed herein may include one or more memory devices (e.g., a volatile memory, such as random access memory [RAM], and/or a nonvolatile memory, such as read-only memory [ROM]) that may store a variety of information and may be used for various purposes.', 'For example, the memory device \n134\n may store processor-executable instructions (e.g., firmware or software) for the processor \n132\n to execute, such as instructions for processing signals and/or controlling the components associated with the BOP \n24\n.', 'It should be appreciated that the controller \n130\n may include various other components, such as a communication device \n136\n that is capable of communicating data or other information (e.g., a current position or mode) to various other devices (e.g., a remote computing system).', 'FIG.', '7\n is a cross-sectional perspective view of a dual function cavity \n140\n that may be used in the BOP \n24\n of \nFIG.', '2\n, in accordance with an embodiment of the present disclosure.', 'As shown, the dual function cavity \n140\n (e.g., dual function ram cavity) extends through a body \n142\n (e.g., housing) of the BOP \n24\n.', 'The dual function cavity \n140\n is transverse to the central bore \n22\n of the BOP \n24\n (e.g., a respective central axis of the dual function cavity \n140\n is transverse, such as orthogonal, to a respective central axis of the central bore \n22\n; a respective central axis of the dual function cavity \n140\n is aligned with the axial axis \n32\n and a respective central axis of the central bore \n22\n is aligned with the vertical axis \n30\n).', 'The dual function cavity \n140\n may include one or more stops \n144\n that are configured to block movement of a respective portion of a first dual function ram and a respective portion of a second dual function ram into the central bore \n22\n.', 'The one or more stops \n144\n may be configured to overlap with the respective portions of the first and second dual function rams along the vertical axis \n30\n to thereby block the movement of the respective portions of the first and second dual function rams into the central bore \n22\n.', 'As shown, a vertical gap \n146\n (e.g., having a semi-circular or D-shaped cross-sectional shape taken in a plane along the lateral axis \n34\n) is provided between the one or more stops \n144\n and an upper portion of the dual function cavity \n140\n to enable other respective portions of the first and second dual function rams to move into the central bore \n22\n.', 'In the illustrated embodiment, the one or more stops \n144\n include an annular wall that is coaxial with the central bore \n22\n; however, the one or more stops \n144\n may have any suitable structural configuration to facilitate the disclosed techniques.', 'The dual function cavity \n140\n may be cylindrical (e.g., have a circular cross-sectional shape taken in a plane along the lateral axis \n34\n) on opposite sides of the one or more stops \n144\n (e.g., outside of the central bore \n22\n).', 'With the foregoing in mind, \nFIG.', '8\n is a perspective view of a first dual function ram \n150\n and a second dual function ram \n152\n that may be used in the dual function cavity \n140\n of \nFIG.', '7\n, in accordance with an embodiment of the present disclosure.', 'In \nFIG.', '8\n, the first dual function ram \n150\n and the second dual function ram \n152\n are in a first mode \n154\n (e.g., shear mode) and withdrawn from the central bore \n22\n such that the BOP \n24\n is in the open configuration \n54\n.', 'In \nFIG.', '9\n, the first dual function ram \n150\n and the second dual function ram \n152\n are in the first mode \n154\n and extend into the central bore \n22\n such that the BOP \n24\n is in the closed configuration \n90\n.', 'As noted above, the first dual function ram \n50\n and the second dual function ram \n52\n may be configured to operate in two modes (e.g., different modes, which may correspond to different positions of the first and second dual function rams \n150\n, \n152\n within the dual function cavity \n140\n), such as the first mode \n154\n and a second mode.', 'To enable the first and second dual function rams \n150\n, \n152\n to operate in two modes, the first and second dual function rams \n150\n, \n152\n may have two sets of opposing surfaces that are configured to engage one another.', 'The two sets of opposing surfaces may be offset (e.g., about the circumferential axis \n36\n) from one another such that only one of the two sets of opposing surfaces is positioned within the central bore \n22\n while the first and second dual function rams \n150\n, \n152\n are extended with the BOP \n24\n in the closed configuration \n90\n of \nFIG.', '9\n.', 'The other set of the two sets of opposing surfaces is positioned outside of the central bore \n22\n while the first and second dual function rams \n150\n, \n152\n are extended with the BOP \n24\n in the closed configuration \n90\n of \nFIG.', '9\n (e.g., due at least in part to the one or more stops \n44\n blocking movement of the other set of the two sets of opposing surfaces into the central bore \n22\n).', 'In the illustrated embodiment, the first and second dual function rams \n150\n, \n152\n each include two ram portions (e.g., a first portion having one surface of the first set of opposing surfaces and a second portion having one surface of the second set of opposing surfaces).', 'Each of the ram portions has a semi-circular or D-shaped cross-sectional shape taken in a plane along the lateral axis \n34\n, and the cross-sectional shape corresponds to or otherwise enables the first and second dual function rams \n150\n, \n152\n to pass through the gap \n146\n (e.g., when aligned with the gap \n146\n).', 'Each of the ram portions is positioned adjacent to another one of the ram portions to form a generally cylindrical structure that fits within the portion of the dual function cavity \n140\n.', 'Each of the ram portions may move independently from the other ram portions (e.g., the ram portions of the first dual function ram \n150\n may move independently from one another; the ram portions of the second dual function ram \n152\n may move independently from one another).', 'With reference to \nFIGS.', '8 and 9\n, the first and second dual function rams \n150\n, \n152\n include a first set of opposing surfaces \n160\n that includes a first shear edge \n162\n (e.g., surface) on the first dual function ram \n150\n (e.g., on a body of the first dual function ram \n150\n; on a portion of the body) and a second shear edge \n164\n (e.g., surface) on the second dual function ram \n152\n (e.g., on a body of the second dual function ram \n152\n; on a portion of the body).', 'In the first mode \n154\n (e.g., shear mode), the first shear edge \n162\n and the second shear edge \n164\n are positioned such that the first shear edge \n162\n and the second shear edge \n164\n enter the central bore \n22\n as the first and second dual function rams \n150\n, \n152\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '9\n.', 'In particular, in the first mode \n154\n, the first shear edge \n162\n and the second shear edge \n164\n may extend along the lateral axis \n34\n, may be positioned at an upper portion of the dual function cavity \n140\n along the vertical axis \n30\n, and/or may face toward one another so as to enable the first shear edge \n162\n and the second shear edge \n164\n to pass through the gap \n146\n into the central bore \n22\n to contact and to shear the conduit \n20\n (\nFIG.', '2\n) in the central bore \n22\n.', 'As shown in \nFIGS. 8 and 9\n, the first and second dual function rams \n150\n, \n152\n also include a second set of opposing surfaces \n170\n that includes a first pipe edge \n172\n (e.g., surface) on the first dual function ram \n150\n (e.g., on a body of the first dual function ram \n50\n; on a portion of the body) and a second pipe edge \n172\n (e.g., surface) on the second dual function ram \n152\n (e.g., on a body of the second dual function ram \n152\n; on a portion of the body).', 'In the first mode \n154\n (e.g., shear mode), the first pipe edge \n172\n and the second pipe edge \n174\n are positioned such that the first pipe edge \n172\n and the second pipe edge \n174\n do not enter the central bore \n22\n as the first and second dual function rams \n150\n, \n152\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '9\n.', 'In particular, in the first mode \n154\n, the first pipe edge \n172\n and the second pipe edge \n174\n may be positioned at a lower portion of the dual function cavity \n140\n along the vertical axis \n30\n so as to overlap with the one or more stops \n144\n along the vertical axis \n30\n and to thereby enable the one or more stops \n144\n to block the first pipe edge \n172\n and the second pipe edge \n174\n from contact with the conduit \n20\n (\nFIG.', '2\n) in the central bore \n22\n, to avoid placement within the central bore \n22\n, and/or to avoid interference with the operation (e.g., shearing operation) of the first shear edge \n162\n and the second shear edge \n164\n.', 'In operation, a portion of the first dual function ram \n150\n and a portion of the second dual function ram \n152\n (e.g., the portions aligned with the gap \n146\n, such as the portions having the first shear edge \n162\n and the second shear edge \n164\n) may move toward one another to transition the BOP \n24\n from the open configuration \n54\n of \nFIG.', '8\n to a closed configuration \n90\n of \nFIG.', '9\n.', 'Similarly, the portions of the first dual function ram \n150\n and the second dual function ram \n152\n may move away from one another to transition the BOP \n24\n from the closed configuration \n90\n of \nFIG.', '9\n to the open configuration \n54\n of \nFIG.', '8\n.', 'In the closed configuration \n90\n, the portions of the first dual function ram \n150\n and the second dual function ram \n152\n extend into the central bore \n22\n, seal the central bore \n22\n, contact the conduit \n20\n, and/or contact the corresponding opposing ram \n50\n, \n52\n.', 'The portions of first dual function ram \n150\n and the second dual function ram \n152\n may be driven to move toward and away from one another along the axial axis \n32\n via the actuator \n62\n of \nFIG.', '2\n.', 'For example, the connecting rod \n66\n of the actuator \n62\n may be aligned with the portions of the first dual function ram \n150\n and the second dual function ram \n152\n to enable the actuators \n62\n to drive the portions of the first dual function ram \n50\n and the second dual function ram \n52\n toward and away from one another along the axial axis \n32\n.', 'FIG.', '10\n is a perspective view of the first dual function ram \n150\n and the second dual function ram \n152\n in a second mode \n180\n (e.g., pipe mode) and withdrawn from the central bore \n22\n such that the BOP \n24\n is in the open configuration \n54\n.', 'FIG.', '11\n is a perspective view of the first dual function ram \n150\n and the second dual function ram \n152\n in the second mode \n180\n and extended into the central bore \n22\n such that the BOP \n24\n is in the closed configuration \n90\n.', 'The first dual function ram \n150\n and the second dual function ram \n152\n may move toward and away from one another to transition the BOP \n24\n between the open configuration \n54\n of \nFIG.', '10\n and the closed configuration \n90\n of \nFIG.', '11\n.', 'In the second mode \n180\n, the first pipe edge \n172\n and the second pipe edge \n174\n are positioned such that the first pipe edge \n172\n and the second pipe edge \n174\n enter the central bore \n22\n as the first and second dual function rams \n150\n, \n152\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '11\n.', 'In particular, in the second mode \n180\n, the first pipe edge \n172\n and the second pipe edge \n174\n may extend along the lateral axis \n34\n, may be positioned at an upper portion of the dual function cavity \n140\n along the vertical axis \n30\n, and/or may face toward one another so as to enable the first pipe edge \n172\n and the second pipe edge \n172\n to pass through the gap \n146\n into the central bore \n22\n so as to enable the first pipe edge \n172\n and the second pipe edge \n174\n to contact one another and to contact the conduit \n20\n (\nFIG.', '2\n) to seal the annular space about the conduit \n20\n in the central bore \n22\n.', 'In the second mode \n180\n, the first shear edge \n162\n and the second shear edge \n164\n are positioned such that the first shear edge \n162\n and the second shear edge \n164\n do not enter the central bore \n22\n as the first and second dual function rams \n150\n, \n152\n are driven to adjust the BOP \n24\n to the closed configuration \n90\n of \nFIG.', '11\n.', 'In particular, in the second mode \n180\n, the first shear edge \n162\n and the second shear edge \n164\n may be positioned a lower portion of the dual function cavity \n140\n along the vertical axis \n30\n so as to overlap with the one or more stops \n144\n along the vertical axis \n30\n and to thereby enable the one or more stops \n144\n to block the first shear edge \n162\n and the second shear edge \n164\n from contact with the conduit \n20\n (\nFIG.', '2\n) in the central bore \n22\n, to avoid placement within the central bore \n22\n, and/or to avoid interference with the operation (e.g., pipe-sealing operation) of the first pipe edge \n172\n and the second pipe edge \n174\n.', 'As shown, the first dual function ram \n150\n and the second dual function ram \n152\n may be generally cylindrical structures and may include various sealing elements (e.g., packers) within grooves \n182\n to facilitate formation of a seal across the central bore \n22\n while the BOP \n24\n is in the closed configuration \n90\n.', 'The grooves \n182\n are shown without the sealing elements for image clarity.', 'In some embodiments, each of the first and second dual function rams \n150\n, \n152\n may be supported within a respective sleeve \n186\n (e.g., annular sleeve).', 'In some embodiments, each of the first and second dual function rams \n150\n, \n152\n may be coupled to the respective sleeve \n186\n (e.g., via an axially-extending key-slot interface; via a splined interface; via a bracket \n188\n).', 'As shown, each sleeve \n186\n may include the bracket \n188\n at one end (e.g., distal from the central bore \n22\n).', 'Each bracket \n188\n may be coupled (e.g., nonrotatably coupled) to a respective rotating shaft \n190\n that is configured to drive rotation of one of the sleeves \n186\n, the first dual function ram \n150\n, and the second dual function ram \n152\n within the dual function cavity \n140\n (e.g., relative to the body \n142\n; in the circumferential direction \n36\n) to thereby efficiently transition between the first mode \n154\n and the second mode \n180\n.', 'The connecting rods \n66\n may be aligned with the portions of the first and second dual function rams \n150\n, \n152\n that are at the upper portion of the dual function cavity \n140\n.', 'Thus, the connecting rods \n66\n may not rotate with the first and second dual function rams \n150\n, \n152\n.', 'Instead, as may be understood with reference to \nFIG.', '12\n, each connecting rod \n66\n may be temporarily (e.g., removably) coupled to the portion of its corresponding dual function ram (e.g., the second dual function ram \n152\n, as shown in detail in \nFIG.', '12\n) while the portion is at the upper portion of the dual function cavity \n140\n via an interface \n191\n (e.g., key-slot interface) to enable the connecting rod \n66\n to drive the portion of its corresponding dual function ram into and out of the central bore \n22\n.', 'For example, the interface \n191\n may include a key \n193\n (e.g., button) on the connecting rod \n66\n and a slot \n195\n (e.g., receptacle) on the portion of the dual function ram.', 'When engaged in this manner, the connecting rod \n66\n may drive the portion of the dual function ram into and out of the central bore \n22\n.', 'To change to a different mode, the connecting rod \n66\n and the portion of the dual function ram may be withdrawn from the central bore \n22\n.', 'While in the withdrawn position, the sleeve \n86\n and the dual function ram may be driven to rotate relative to the connecting rod \n66\n.', 'During the rotation, the slot \n195\n on the portion of the dual function ram may separate from the key \n193\n on the connecting rod \n66\n, and the slot \n197\n on the other portion of the dual function ram may then engage the key \n193\n on the connecting rod \n66\n once the other portion of the dual function ram reaches the upper portion of the dual function cavity \n140\n.', 'Once engaged in this manner, the connecting rod \n66\n may drive the other portion of the dual function into and out of the central bore \n22\n.', 'The bonnet \n60\n may include a support key \n199\n (e.g., button) that engages the slot \n195\n, \n197\n of the respective portion of the dual function ram that is at the lower portion of the dual function cavity \n140\n.', 'It should be appreciated that the key portion of the interface may be on the portion of the dual function ram, and the slot portion of the interface may be on the connecting rod.', 'Additionally, while \nFIG.', '12\n illustrates the second dual function ram \n152\n, it should be appreciated that the first dual function ram \n150\n may include components that operate in the same way.', 'Moreover, it should be appreciated that other techniques for coupling the first and second dual function rams \n150\n, \n152\n and the connecting rods \n66\n may be employed.', 'In some embodiments, the sleeves \n186\n may have an inner diameter that is slightly greater than an outer diameter of the first and second dual function rams \n150\n, \n152\n to reduce friction and wear on the sealing elements.', 'One or more wear rings (e.g., annular rings) may be positioned about an outer surface (e.g., radially-outer surface) of the sleeves \n186\n to reduce friction and/or to block debris ingress (e.g., mud ingress) between the outer surface of the sleeve \n186\n and the body \n142\n that defines the dual function cavity \n140\n.', 'It should be appreciated that any of a variety of techniques may be utilized to rotate the first dual function ram \n150\n and the second dual function ram \n152\n in the manner disclosed herein.', 'For example, the sleeve \n186\n may not be present and/or the rotating shafts \n190\n may directly interface with and engage one or both of the first and dual function rams \n150\n, \n152\n to drive the first and second dual function rams \n150\n, \n152\n to rotate within the dual function cavity \n140\n.', 'Advantageously, the embodiment of the BOP \n24\n of \nFIGS.', '7-12\n may enable the BOP \n24\n to use the same rams (e.g., the first and second dual function rams \n50\n, \n52\n) to operate in two modes (e.g., the first mode \n154\n and the second mode \n180\n) depending on which of the two modes is desired at the particular time.', 'In this way, the embodiment of the BOP \n24\n of \nFIGS.', '7-12\n may enable the BOP \n24\n to use the same rams (e.g., the first and second dual function rams \n150\n, \n152\n) to carry out two operations (e.g., the shearing operation and the pipe-sealing operation) depending on which of the two operations is desired at the particular time.', 'For example, the BOP \n24\n may operate in the second mode \n180\n to seal the annular space about the conduit \n20\n (\nFIG.', '2\n) during planned maintenance operations, and the BOP \n24\n may be operate in the first mode \n154\n to shear the conduit \n20\n during an unexpected increase in pressure within the wellbore \n18\n (\nFIG.', '1\n).', 'The BOP \n24\n may efficiently switch between the first mode \n154\n and the second mode \n180\n via rotation of the first and second dual function rams \n50\n, \n52\n within the dual function cavity \n140\n (e.g., via the rotating shafts \n190\n).', 'It should be appreciated that manual and/or electronic control may be utilized to rotate the first and second dual function rams \n150\n, \n152\n.', 'For example, an operator may manually drive rotation of the rotating shafts \n190\n to rotate the first and second dual function rams \n150\n, \n152\n.', 'Additionally or alternatively, a control system (e.g., electronic control system) may electronically control the rotation of the rotating shafts \n190\n (e.g., via control of an actuator) to rotate the first and second dual function rams \n150\n, \n152\n.', 'For example, the control system may receive an input (e.g., input by an operator via a user interface; from a sensor that monitors a pressure within the wellbore \n18\n [\nFIG.', '1\n]).', 'In response to the input, the control system may control the rotation of the rotating shafts \n190\n to rotate the first and second dual function rams \n150\n, \n152\n to the desired position within the dual function cavity \n140\n to prepare for and to enable operation in the first mode \n154\n or the second mode \n180\n.', 'In some embodiments, the control system may also control the movement of the first and second dual function rams \n150\n, \n152\n along the axial axis \n32\n to adjust the BOP \n24\n between the open configuration \n54\n and the closed configuration \n90\n.', 'With reference to \nFIG.', '8\n, the control system may include a controller \n192\n having a processor \n194\n and a memory device \n196\n.', 'The controller \n192\n may be part of or include a distributed controller or control system with one or more electronic controllers in communication with one another to carry out the various techniques disclosed herein.', 'The processor \n194\n may also include one or more processors configured to execute software, such as software for processing signals and/or controlling the components associated with the BOP \n24\n.', 'The memory device \n196\n disclosed herein may include one or more memory devices (e.g., a volatile memory, such as random access memory [RAM], and/or a nonvolatile memory, such as read-only memory [ROM]) that may store a variety of information and may be used for various purposes.', 'For example, the memory device \n196\n may store processor-executable instructions (e.g., firmware or software) for the processor \n194\n to execute, such as instructions for processing signals and/or controlling the components associated with the BOP \n24\n.', 'It should be appreciated that the controller \n192\n may include various other components, such as a communication device \n198\n that is capable of communicating data or other information to various other devices (e.g., a remote computing system).', 'FIG.', '13\n is a flow diagram of a method \n200\n of operating a BOP (e.g., the BOP \n24\n) having dual function rams (e.g., the dual function rams \n50\n, \n52\n of \nFIGS.', '3-6\n or the dual function rams \n150\n, \n152\n of \nFIGS.', '7-12\n), in accordance with an embodiment of the present disclosure.', 'The method \n200\n includes various steps represented by blocks.', 'It should be noted that the method \n200\n may be performed as an automated procedure by a system, such as the controller \n130\n, \n192\n.', 'Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Further, certain steps or portions of the method \n200\n may be performed by separate devices.', 'As noted above, the steps for using the dual function rams may be initiated automatically (e.g., following a signal that indicates that the BOP should be adjusted to the closed configuration and/or a signal that indicates that the BOP should be adjusted to a different mode).', 'In step \n202\n, the dual function rams may be operated in a first mode by driving at least a portion of each dual function ram into a central bore.', 'For example, a portion of a first dual function ram may be driven into the central bore via a respective actuator and a portion of a second dual function ram may be driven into the central bore via a respective actuator.', 'The portions may include opposing edges (e.g., shear edges) that are configured to interact with (e.g., shear) a tubular within the central bore to carry out a first operation.', 'In step \n204\n, the dual function rams may be withdrawn from the central bore.', 'For example, the portion of the first dual function ram may be withdrawn from the central bore via the respective actuator and the portion of the second dual function ram may be withdrawn from the central bore via the respective actuator.', 'In step \n206\n, the dual function rams may be adjusted to prepare for operation in a second mode.', 'For example, the dual function rams may be rotated relative to the central bore.', 'In step \n208\n, the dual function rams may be operated in a second mode by driving at least another portion of each dual function ram into the central bore.', 'For example, another portion of the first dual function ram may be driven into the central bore via the respective actuator and another portion of the second dual function ram may be driven into the central bore via the respective actuator.', 'The portions may include opposing edges (e.g., pipe edges) that are configured to interact with (e.g., seal against) a tubular (e.g., the same tubular prior to the shearing step or another tubular) within the central bore to carry out a second operation (e.g., pipe-sealing operation).', 'While the embodiments are generally described with reference to a first mode being a shear mode that uses a first shearing edge and a second shearing edge and a second mode being a pipe-sealing mode that uses a first pipe edge and a second pipe edge to facilitate discussion, it should be appreciated that the dual function rams may have any of a variety of other configurations.', 'For example, the first mode may be a pipe-sealing mode that uses a first pipe edge and a second pipe edge to seal about a tubular of a first diameter, and the second mode may be a pipe-sealing mode that uses another first pipe edge and another second pipe edge to seal about another tubular of a second diameter that is different from the first diameter.', 'Similarly, the first mode may be a shearing mode that uses a first shear edge and a second shear edge to shear a tubular of a first diameter, and the second mode may be a shearing mode that uses another first shear edge and another second shear edge to shear another tubular of a second diameter that is different from the first diameter.', 'Accordingly, the shear edges disclosed herein may be replaced with any type of edge (e.g., first edge, pipe edge) to carry out any type of operations and the pipe edges disclosed herein may be replaced with any type of edge (e.g., second edge, shear edge) to carry out any type of operation.', 'In some embodiments, the first mode and the second mode may be the same, the first edges may have the same configuration, and the second edges may have the same configuration to provide duplicate surfaces to improve wear and/or longevity (e.g., extend time between maintenance operations, such as repair or replacement).', 'In some embodiments, additional modes (e.g., more than two) and/or additional sets of opposing surfaces (e.g., more than two) may be provided about each of the rams (e.g., triple-function rams, quadruple function rams).', 'For example, the embodiments of \nFIGS.', '3-6\n may include additional sets of opposing surfaces about the circumference of the rams (e.g., three or four sets of opposing surfaces, such as two sets of shear edges and two sets of pipe edges).', 'While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.', 'Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.', 'Furthermore, any of the features described with respect to \nFIGS.', '1-13\n may be combined in any suitable manner.'] | ['1.', 'A dual function ram system for a blowout preventer (BOP), the dual function ram system comprising:\na first dual function ram configured to move within a cavity of the BOP between a withdrawn position to cause the BOP to be in an open configuration and an extended position to cause the BOP to be in a closed configuration, wherein the first dual function ram comprises a shearing surface that is configured to shear a tubular within a central bore during a shearing operation and a pipe-sealing surface that is configured to seal against the tubular within the central bore during a pipe-sealing operation.', '2.', 'The dual function ram system of claim 1, wherein the shearing surface and the pipe-sealing surface are offset from one another along a circumferential axis of the first dual function ram.', '3.', 'The dual function ram system of claim 1, wherein the first dual function ram comprises a cylindrical shape.', '4.', 'The dual function ram system of claim 1, wherein the first dual function ram comprises a curved groove, and the curved groove comprises a toothed surface that is configured to engage a corresponding toothed surface of a rotating shaft to enable rotation of the rotating shaft to drive rotation of the first dual function ram within the cavity of the BOP.', '5.', 'The dual function ram system of claim 1, comprising the cavity of the BOP, wherein the first dual function ram is configured to rotate within the cavity to a first position to enable the shearing surface to move into and out of the central bore along an axial axis.', '6.', 'The dual function ram system of claim 5, wherein the pipe-sealing surface is configured to be positioned outside of the central bore while the shearing surface is positioned within the central bore.', '7.', 'The dual function ram system of claim 6, wherein the pipe-sealing surface is configured to move with the shearing surface along the axial axis as the shearing surface moves into and out of the central bore along the axial axis.', '8.', 'The dual function ram system of claim 1, comprising a second dual function ram configured to move within the cavity of the BOP, wherein the second dual function ram comprises a respective shearing surface that is configured to shear the tubular within the central bore during the shearing operation and a respective pipe-sealing surface that is configured to seal against the tubular within the central bore during the pipe-sealing operation.', '9.', 'The dual function ram system of claim 1, comprising the cavity of the BOP, wherein the cavity comprises one or more stops configured to block entry of one of the shearing surface or the pipe-sealing surface into the central bore.', '10.', 'A blowout preventer (BOP), comprising:\na housing defining a central bore;\na cavity intersecting the central bore; and\na first dual function ram supported within the cavity, wherein the first dual function ram is configured to move within the cavity along an axial axis between a withdrawn position to cause the BOP to be in an open configuration and an extended position to cause the BOP to be in a closed configuration, wherein the first dual function ram is configured to rotate within the cavity along a circumferential axis between a first position that enables a first surface of the first dual function ram to enter the central bore to carry out a first operation and a second position that enables a second surface of the first dual function ram to enter the central bore to carry out a second operation.\n\n\n\n\n\n\n11.', 'The BOP of claim 10, wherein the first surface comprises a shearing surface and the second surface comprises a pipe-sealing surface.', '12.', 'The BOP of claim 10, wherein the first surface and the second surface are offset from one another along the circumferential axis of the first dual function ram.', '13.', 'The BOP of claim 10, wherein the first dual function ram comprises a cylindrical shape.', '14.', 'The BOP of claim 10, wherein the first dual function ram comprises a curved groove, and the curved groove comprises a toothed surface that is configured to engage a corresponding toothed surface of a rotating shaft to enable rotation of the rotating shaft to drive rotation of the first dual function ram within the cavity of the BOP.', '15.', 'The BOP of claim 10, wherein the first surface is configured to be positioned outside of the central bore while the second surface is positioned within the central bore, and wherein the second surface is configured to be positioned outside of the central bore while the first surface is positioned within the central bore.', '16.', 'The BOP of claim 10, wherein the first surface and the second surface are configured to move together along the axial axis.', '17.', 'The BOP of claim 10, comprising a second dual function ram configured to move within the cavity of the BOP, wherein the second dual function ram is configured to move within the cavity, wherein the second dual function ram is configured to rotate within the cavity along the circumferential axis between a respective first position that enables a respective first surface of the second dual function ram to enter the central bore to carry out the first operation and a respective second position that enables a respective second surface of the second dual function ram to enter the central bore to carry out the second operation.', '18.', 'The BOP of claim 10, wherein the cavity comprises one or more stops configured to block entry of one of the first surface or the second surface into the central bore.'] | ['FIG.', '1 is a block diagram of a mineral extraction system, in accordance with an embodiment of the present disclosure;; FIG.', '2 is a cross-sectional top view of a portion of a blowout preventer (BOP) that may be used in the mineral extraction system of FIG.', '1, in accordance with an embodiment of the present disclosure;; FIG.', '3 is a perspective view of dual function rams that may be used in the BOP of FIG.', '2, wherein the dual function rams are in a first mode and are in a withdrawn position, in accordance with an embodiment of the present disclosure;; FIG. 4 is a perspective view of the dual function rams of FIG.', '3, wherein the dual function rams are in the first mode and are in an extended position, in accordance with an embodiment of the present disclosure;; FIG. 5 is a perspective view of the dual function rams of FIG.', '3, wherein the dual function rams are in a second mode and are in the withdrawn position, in accordance with an embodiment of the present disclosure;; FIG.', '6 is a perspective view of the dual function rams of FIG.', '3, wherein the dual function rams are in the second mode and are in the extended position, in accordance with an embodiment of the present disclosure;; FIG. 7 is a cross-sectional perspective view of a dual function cavity that may be used in the BOP of FIG.', '2, in accordance with an embodiment of the present disclosure;; FIG. 8 is a perspective view of dual function rams that may be used in the dual function cavity of FIG.', '7, wherein the dual function rams are in a first mode and are in a withdrawn position, in accordance with an embodiment of the present disclosure;; FIG. 9 is a perspective view of the dual function rams of FIG. 8, wherein the dual function rams are in the first mode and are in an extended position, in accordance with an embodiment of the present disclosure;; FIG.', '10 is a perspective view of the dual function rams of FIG.', '8, wherein the dual function rams are in a second mode and are in the withdrawn position, in accordance with an embodiment of the present disclosure;; FIG.', '11 is a perspective view of the dual function rams of FIG.', '8, wherein the dual function rams are in the second mode and are in the extended position, in accordance with an embodiment of the present disclosure;; FIG.', '12 is a cross-sectional perspective view of one of the dual function rams of FIG.', '8, in accordance with an embodiment of the present disclosure; and; FIG. 13 is a flow diagram of a method of operating a BOP having dual function rams, in accordance with an embodiment of the present disclosure.', '; FIG.', '2 is a cross-sectional top view of a portion of the BOP 24 that may be used in the mineral extraction system 10 of FIG.', '1, in accordance with an embodiment of the present disclosure.', 'As shown, a first dual function ram 50 (e.g., first ram) and a second dual function ram 52 (e.g., second ram)', 'are positioned such that the BOP 24 is in an open configuration 54.', 'In the open configuration 54, the first dual function ram 50 and the second dual function ram 52 are withdrawn from the central bore 22, do not contact the conduit 20, and/or do not contact the corresponding opposing ram 50, 52.; FIG.', '3 is a perspective view of the first dual function ram 50 and the second dual function ram 52 in a first mode 80 (e.g., shear mode; first position; first position along the circumferential axis 36) and withdrawn from the central bore 22 such that the BOP 24 is in the open configuration 54.', 'As shown, the first dual function ram 50 and the second dual function ram 52 are supported within a cavity 82 (e.g., ram cavity) that is transverse to the central bore 22 of the BOP 24 (e.g., a respective central axis of the cavity 82 is transverse, such as orthogonal, to a respective central axis of the central bore 22; a respective central axis of the cavity 82 is aligned with the axial axis 32 and a respective central axis of the central bore 22 is aligned with the vertical axis 30).', 'In operation, the first dual function ram 50 and the second dual function ram 52 move through the cavity 82 toward and away from one another.; FIG.', '5 is a perspective view of the first dual function ram 50 and the second dual function ram 52 in a second mode 118 (e.g., pipe-sealing mode mode; second position; second position along the circumferential axis 36) and withdrawn from the central bore 22 such that the BOP 24 is in the open configuration 54.', 'FIG.', '6 is a perspective view of the first dual function ram 50 and the second dual function ram 52 in the second mode 118 and extended into the central bore 22 such that the BOP 24 is in the closed configuration 90.', 'The first dual function ram 50 and the second dual function ram 52 may move toward and away from one another to transition the BOP 24 between the open configuration 54 of FIG.', '5 and the closed configuration 90 of FIG.', '6.; FIG. 7 is a cross-sectional perspective view of a dual function cavity 140 that may be used in the BOP 24 of FIG.', '2, in accordance with an embodiment of the present disclosure.', 'As shown, the dual function cavity 140 (e.g., dual function ram cavity) extends through a body 142 (e.g., housing) of the BOP 24.', 'The dual function cavity 140 is transverse to the central bore 22 of the BOP 24 (e.g., a respective central axis of the dual function cavity 140 is transverse, such as orthogonal, to a respective central axis of the central bore 22; a respective central axis of the dual function cavity 140 is aligned with the axial axis 32 and a respective central axis of the central bore 22 is aligned with the vertical axis 30).', 'The dual function cavity 140 may include one or more stops 144 that are configured to block movement of a respective portion of a first dual function ram and a respective portion of a second dual function ram into the central bore 22.', 'The one or more stops 144 may be configured to overlap with the respective portions of the first and second dual function rams along the vertical axis 30 to thereby block the movement of the respective portions of the first and second dual function rams into the central bore 22.', 'As shown, a vertical gap 146 (e.g., having a semi-circular or D-shaped cross-sectional shape taken in a plane along the lateral axis 34) is provided between the one or more stops 144 and an upper portion of the dual function cavity 140 to enable other respective portions of the first and second dual function rams to move into the central bore 22.', 'In the illustrated embodiment, the one or more stops 144 include an annular wall that is coaxial with the central bore 22; however, the one or more stops 144 may have any suitable structural configuration to facilitate the disclosed techniques.', 'The dual function cavity 140 may be cylindrical (e.g., have a circular cross-sectional shape taken in a plane along the lateral axis 34) on opposite sides of the one or more stops 144 (e.g., outside of the central bore 22).', '; FIG.', '10 is a perspective view of the first dual function ram 150 and the second dual function ram 152 in a second mode 180 (e.g., pipe mode) and withdrawn from the central bore 22 such that the BOP 24 is in the open configuration 54.', 'FIG.', '11 is a perspective view of the first dual function ram 150 and the second dual function ram 152 in the second mode 180 and extended into the central bore 22 such that the BOP 24 is in the closed configuration 90.', 'The first dual function ram 150 and the second dual function ram 152 may move toward and away from one another to transition the BOP 24 between the open configuration 54 of FIG.', '10 and the closed configuration 90 of FIG.', '11.; FIG. 13 is a flow diagram of a method 200 of operating a BOP (e.g., the BOP 24) having dual function rams (e.g., the dual function rams 50, 52 of FIGS.', '3-6 or the dual function rams 150, 152 of FIGS.', '7-12), in accordance with an embodiment of the present disclosure.', 'The method 200 includes various steps represented by blocks.', 'It should be noted that the method 200 may be performed as an automated procedure by a system, such as the controller 130, 192.', 'Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Further, certain steps or portions of the method 200 may be performed by separate devices.', 'As noted above, the steps for using the dual function rams may be initiated automatically (e.g., following a signal that indicates that the BOP should be adjusted to the closed configuration and/or a signal that indicates that the BOP should be adjusted to a different mode).'] |
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US11112523 | Calibration of electromagnetic measurement tool | Dec 3, 2018 | Mark Frey | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 4439831; March 27, 1984; Sinclair; 4876511; October 24, 1989; Clark; 5293128; March 8, 1994; Zhou; 6353322; March 5, 2002; Tabarovsky et al.; 6534985; March 18, 2003; Holladay, III et al.; 7141981; November 28, 2006; Folberth et al.; 7915895; March 29, 2011; Chemali et al.; 8301384; October 30, 2012; Forgang et al.; 8378684; February 19, 2013; Minh; 8466683; June 18, 2013; Legendre et al.; 8736270; May 27, 2014; Seydoux; 20040113609; June 17, 2004; Homan et al.; 20050143920; June 30, 2005; Barber et al.; 20060132138; June 22, 2006; Pelegri et al.; 20060208737; September 21, 2006; Merchant et al.; 20080246485; October 9, 2008; Hibbs et al.; 20090302851; December 10, 2009; Bittar et al.; 20110074427; March 31, 2011; Wang et al.; 20110133740; June 9, 2011; Seydoux et al.; 20110238312; September 29, 2011; Seydoux et al.; 20120078558; March 29, 2012; Pelegri et al.; 20130035862; February 7, 2013; Fang et al.; 20130043884; February 21, 2013; Le et al.; 20130154846; June 20, 2013; Mangione; 20130191028; July 25, 2013; Homan et al.; 20130301388; November 14, 2013; Hartmann et al.; 20130311094; November 21, 2013; Donderici; 20140015530; January 16, 2014; Miles; 20140368200; December 18, 2014; Wang et al.; 20150083500; March 26, 2015; Vail, III; 20150177412; June 25, 2015; San Martin et al.; 20150276968; October 1, 2015; Frey; 20160116627; April 28, 2016; Frey; 20160170068; June 16, 2016; Donderici | 2815070; December 2014; EP | ['A calibration method includes determining calibration standards for a reference tool including a reference transmitter and a reference receiver.', 'First and second calibration factors are measured to match a receiver on an electromagnetic measurement tool (the tool to be calibrated) to the reference receiver and to match a transmitter on the electromagnetic measurement tool to the reference transmitter.', 'The electromagnetic measurement tool is deployed in a subterranean wellbore and used to make electromagnetic measurements therein.', 'The measured first and second calibration factors and at least one of the calibration standards are applied to at least one of the electromagnetic measurements to compute a gain calibrated electromagnetic measurement.'] | ['Description\n\n\n\n\n\n\nCROSS REFERENCE TO RELATED APPLICATIONS', 'This application claims the benefit of U.S. Provisional Application Ser.', 'No. 62/593,321 entitled Gain Calibration of Electromagnetic Measurements, filed Dec. 1, 2017.', 'FIELD OF THE INVENTION\n \nDisclosed embodiments relate generally to electromagnetic logging measurements and more particularly to a method for gain calibration of electromagnetic measurements, for example, employing rotating or non-rotating measurement subs including triaxial and/or tilted antenna.', 'BACKGROUND INFORMATION', 'The use of electromagnetic measurements in prior art downhole applications, such as logging while drilling (LWD) and wireline logging applications, may be utilized to determine a subterranean formation resistivity, which, along with formation porosity measurements, can be used to indicate the presence of hydrocarbons in the formation.', 'Moreover, azimuthally sensitive directional resistivity measurements may be employed e.g., in pay-zone steering applications, to provide information upon which steering decisions may be made.', 'Tool and/or measurement calibration methods may be used to improve accuracy in electromagnetic logging operations.', 'Factors such as imperfections in tool construction and gain variations due to tool electronics may introduce significant measurement errors.', 'The intent of tool calibration is to eliminate and/or compensate for the effects of these factors on the measurement data.', 'Air calibration methods may be employed in which an electromagnetic resistivity tool is lifted in air away from any conducting media (e.g. via a crane).', 'A resistivity measurement should yield near-infinite resistivity (i.e., a conductivity of zero).', 'Any deviation is subtracted and is assumed to be related to systematic measurement errors (e.g., related to the electronics, hardware, or processing methods).', 'While the aforementioned calibration methods may provide an adequate calibration for conventional electromagnetic logging tools, they can be difficult to implement with deep reading, directional electromagnetic resistivity tools (look-around tools) or electromagnetic look-ahead tools.', 'As described in more detail below, the transmitter and receiver subs in such deep reading tools may be modular such that neither the axial spacing nor the azimuthal alignment angle between the subs are fixed.', 'Hence a calibration performed for one tool configuration will not necessarily be valid for any other tool configuration.', 'Moreover, performing a conventional air calibration tends to be difficult if not impossible to implement at a drilling site owing to the long spacing between transmitter and receiver subs (e.g., up to 100 feet or more) and the need to suspend the entire bottom hole assembly (BHA).', 'During an electromagnetic look-ahead measurement only a small amount of the tool response comes from ahead of the bit.', 'Isolating that response may involve subtracting the much larger response from behind.', 'Therefore, there remains a need in the art for improved methods for calibrating directional resistivity logging tools, particularly deep reading tools.', 'SUMMARY\n \nA method for calibrating an electromagnetic logging tool is disclosed.', 'The method includes providing an electromagnetic measurement tool including a transmitter and a receiver and a reference tool including a reference transmitter and a reference receiver.', 'The measurement tool may be a deep reading measurement tool, for example, such that the transmitter and receiver may be deployed on distinct transmitter and receiver subs.', 'Calibration standards are determined for the reference tool and first and second calibration factors are measured to match the receiver on the electromagnetic measurement tool to the reference receiver on the reference tool and to match the transmitter on the electromagnetic measurement tool to the reference transmitter on the reference tool.', 'The electromagnetic measurement tool is deployed in a subterranean wellbore and used to make electromagnetic measurements in the wellbore.', 'The first and second measured calibration factors and the determined calibration standard are applied to at least one of the electromagnetic measurements to compute a gain calibrated electromagnetic measurement.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFor a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:\n \nFIG.', '1\n depicts an example drilling rig on which disclosed embodiments may be utilized.\n \nFIG.', '2\n depicts one example of a deep reading electromagnetic logging tool including first and second transmitter and receiver subs.\n \nFIG.', '3\n schematically depicts a deep reading electromagnetic logging tool including collocated triaxial transmitters and receivers.\n \nFIG.', '4\n depicts a flow chart of one disclosed method embodiment.\n \nFIG.', '5\n depicts a flow chart of one disclosed embodiment providing further detail of element \n105\n in the flow chart depicted on \nFIG.', '4\n.\n \nFIG.', '6\n depicts a flow chart of one disclosed embodiment providing further detail of element \n110\n in the flow chart depicted on \nFIG.', '5\n.', 'FIG.', '7\n depicts a flow chart of one disclosed embodiment providing further detail of element \n120\n in the flow chart depicted on \nFIG.', '5\n.', 'FIGS.', '8A and 8B\n depict example calibration loops deployed on axial (\n8\nA) and transverse (\n8\nB) reference receivers.', 'FIG.', '9\n depicts an example receiver electronics calibration circuit.\n \nFIG.', '10\n depicts a flow chart of one disclosed embodiment providing further detail of element \n130\n in the flow chart depicted on \nFIG.', '5\n.', 'FIG.', '11\n depicts an example transmitter electronics calibration circuit.\n \nFIG.', '12\n depicts a flow chart of one disclosed embodiment providing further detail of element \n140\n in the flow chart depicted on \nFIG.', '5\n.', 'FIG.', '13\n depicts one example of a reference air calibration setup including a reference transmitter and a reference receiver.\n \nFIG.', '14\n depicts an example of a computer system.', 'DETAILED DESCRIPTION', 'A disclosed calibration method comprises determining calibration standards for a reference tool including a reference transmitter and a reference receiver.', 'First and second calibration factors are measured to match a receiver on an electromagnetic measurement tool (the tool to be calibrated) to the reference receiver on the reference tool and to match a transmitter on the electromagnetic measurement tool to the reference transmitter on the reference tool.', 'The electromagnetic measurement tool is deployed in a subterranean wellbore and used to make electromagnetic measurements in the wellbore.', 'The first and second measured calibration factors and the calibration standard are applied to at least one of the electromagnetic measurements to compute a gain calibrated electromagnetic measurement.', 'Disclosed embodiments advantageously enable full gain calibration of axial, transverse, tilted, and/or triaxial antenna electromagnetic measurements without the use of an electromagnetic coupling model.', 'In particular, the method does not make use of a model of the transmitter and receiver coupling so long as the electrical properties (e.g., conductivity) of the coupling is stable and repeatable.', 'The method computes a gain ratio for each coupling that cancels the transmitter and receiver gains that are present in the downhole measurements.\n \nFIG.', '1\n depicts an example drilling rig \n10\n suitable for employing various method embodiments disclosed herein.', 'A semisubmersible drilling platform \n12\n is positioned over an oil or gas formation (not shown) disposed below the sea floor \n16\n.', 'A subsea conduit \n18\n extends from deck \n20\n of platform \n12\n to a wellhead installation \n22\n.', 'The platform may include a derrick and a hoisting apparatus for raising and lowering a drill string \n30\n, which, as shown, extends into borehole \n40\n and includes a drill bit \n32\n deployed at the lower end of a bottom hole assembly (BHA) that further includes a deep reading electromagnetic measurement tool including distinct transmitter \n50\n and receiver \n60\n subs configured to make tri-axial electromagnetic logging measurements.', 'It will be understood that the deployment illustrated on \nFIG.', '1\n is merely an example.', 'Drill string \n30\n may include substantially any suitable downhole tool components, for example, including a steering tool such as a rotary steerable tool, a downhole telemetry system, and one or more MWD or LWD tools including various sensors for sensing downhole characteristics of the borehole and the surrounding formation.', 'The disclosed embodiments are by no means limited to any particular drill string configuration.', 'It will be further understood that the disclosed embodiments are not limited to use with a semisubmersible platform \n12\n as illustrated on \nFIG.', '1\n.', 'The disclosed embodiments are equally well suited for use with either onshore or offshore subterranean operations.', 'Moreover, disclosed embodiments are not limited to logging while drilling embodiments as illustrated on \nFIG.', '1\n.', 'The disclosed embodiments are equally well suited for use with any electromagnetic logging tool, including wireline logging tools and logging while drilling tools, used while rotating or non-rotating.\n \nFIG.', '2\n depicts one example embodiment of the electromagnetic measurement tool shown on \nFIG.', '1\n (including transmitter and receiver subs \n50\n and \n60\n).', 'In the depicted embodiment, the transmitter sub (or tool) \n50\n includes an electromagnetic transmitter \n52\n deployed on a transmitter collar \n51\n.', 'The receiver sub (or tool) \n60\n includes an electromagnetic receiver \n62\n deployed on a receiver collar \n61\n.', 'When deployed in a drill string (e.g., drill string \n30\n on \nFIG.', '1\n), the transmitter and receiver subs \n50\n and \n60\n may be axially spaced apart substantially any suitable distance to achieve a desired measurement depth (e.g., in a range from about 20 to about 100 or 200 feet or more depending on the measurement objectives).', 'While not shown, one or more other BHA tools may be deployed between subs \n50\n and \n60\n.', 'As described in more detail below the transmitter \n52\n and receiver \n62\n may each include three tri-axial antennas (e.g., an axial antenna and first and second transverse antennas that are orthogonal to one another in this particular embodiment).', 'As is known to those of ordinary skill in the art, an axial antenna is one whose moment is substantially parallel with the longitudinal axis of the tool.', 'Axial antennas are commonly wound about the circumference of the logging tool such that the plane of the antenna is substantially orthogonal to the tool axis.', 'A transverse antenna is one whose moment is substantially perpendicular to the longitudinal axis of the tool.', 'A transverse antenna may include, for example, a saddle coil (e.g., as disclosed in U.S. Patent Publications 2011/0074427 and 2011/0238312 each of which is incorporated by reference herein).', 'FIG.', '3\n depicts the antenna moments for an example transmitter \n52\n and receiver \n62\n.', 'The transmitter \n52\n includes three collocated tri-axial antennas having mutually orthogonal moments T\n1\nx\n, T\n1\ny\n, and T\n1\nz \naligned with the x-, y-, and z-directions.', 'Receiver \n62\n also includes three collocated tri-axial antennas having mutually orthogonal moments R\n1\nx\n, R\n1\ny\n, and R\n1\nz\n.', 'In the depicted embodiment in which there is no bending of the drill string (or BHA), moment R\n1\nz \nis aligned with T\n1\nz \n(and the z-azis) while moments R\n1\nx \nand R\n1\ny \nare rotationally offset from T\n1\nx \nand T\n1\ny \nby an arbitrary offset angle γ.', 'As depicted, the receiver sub \n60\n is rotationally offset (about the axis of the drill string, the z-axis) with respect to transmitter sub \n50\n the arbitrary misalignment angle γ.', 'It will also be understood that the misalignment angle γ is the result of a rotational misalignment between subs \n50\n and \n60\n during make-up of the drill string and that the misalignment angle γ may therefore have substantially any value.', 'While not depicted, it will be understood that the disclosed embodiments are applicable to electromagnetic measurements made when BHA bending is negligible or when BHA bending is non-negligible.', 'Bending may be negligible, for example, in vertical or horizontal drilling applications and may be non-negligible, for example, while building inclination prior to landing in a zone or bed of interest.', 'Much of the discussion that follows assumes that bending is negligible.', 'These assumptions are for convenience and ease of illustration only.', 'The disclosed embodiments are explicitly not limited in these regards and may be used when bending is negligible or non-negligible.', 'As depicted in \nFIG.', '3\n and according to the described embodiments below, the terms “transmitter” and “receiver” are used to describe different functions of an antenna, as if they were different types of antennas.', 'It will be understood that this is only for illustration purposes.', 'A transmitting antenna and a receiving antenna may have the same physical characteristics, and one of ordinary skill in the art would appreciate that the principle of reciprocity applies and that a radiating element may be used as a transmitter at one time and as a receiver at another.', 'Thus, any specific description of transmitters and receivers in a particular tool embodiment should be construed to include the complementary configuration, in which the “transmitters” and the “receivers” are switched.', 'Furthermore, in this description, a “transmitter” or a “receiver” is used in a general sense and may include a single radiating element, two radiating elements, or three or more radiating elements.', 'It will be further understood that during electromagnetic measurements, a transmitting antenna and a receiving antenna are electromagnetically coupled to one another.', 'For example, the transmitting antenna may be energized (e.g., with an alternating current) and an induced voltage may be measured on the receiving antenna.', 'Based on reciprocity, the receiving antenna may be equivalently energized and an induced voltage may be measured on the transmitting antenna.', 'The disclosed embodiments are explicitly not limited in these regards.', 'The use of electromagnetic measurements (e.g., propagation and induction measurements) is known in the downhole drilling arts.', 'In such measurements, transmitting and receiving antennas are electromagnetically coupled via applying a time varying electric current (an alternating current) in a transmitting antenna that produces a corresponding time varying magnetic field in the local environment (e.g., the tool collar and the formation).', 'The magnetic field in turn induces electrical currents (eddy currents) in the conductive formation.', 'These eddy currents further produce secondary magnetic fields which may produce a voltage response in a receiving antenna.', 'The measured voltage in the receiving antennas can be processed, as is known to those of ordinary skill in the art, to obtain one or more properties of the formation.', 'Electromagnetic measurements may make use of substantially any suitable antenna configuration, for example, one or more axial, transverse, tilted, biaxial, and/or triaxial antenna arrangements as described above and in commonly assigned and commonly invented U.S. Patent Publications 2015/0276968 and 2016/0116627, each of which is incorporated by reference herein in its entirety.', 'Basic Measurement Assumptions', "According to Faraday's Law, the voltage induced V induced in a coil by a magnetic field oscillating at frequency co is proportional to the magnetic flux, F through the area bounded by the coil,\n \n \n \n \n \n \n \n \n \nV\n \ninduced\n \n \n=\n \n \n \n \n-\n \n \nd\n \ndt\n \n \n \n\u2062\n \nF\n \n \n=\n \n \n \n-\n \nj\n \n \n\u2062\n \n \n \n \n\u2062\n \nω\n \n\u2062\n \n \n \n \n\u2062\n \nF\n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n \n \n \n \nIf the magnetic field is constant in magnitude and direction over the area of each of the loops of the coil, then the flux is proportional to the number of receiver turns times the loop-area, A\nR\n \n \n \n \n \n \n \n \nF\n \n=\n \n \n \n∫\n \n \n \n \nB\n \n->\n \n \n·\n \nd\n \n \n\u2062\n \n \n \n \n\u2062\n \n \na\n \n->\n \n \n \n \n=\n \n \n \n \nB\n \nR\n \n \n\u2062\n \n \n \n∑\n \n \ni\n \n=\n \n1\n \n \n \nN\n \nR\n \n \n \n\u2062\n \n \nA\n \nR\n \n \n \n \n=\n \n \n \nB\n \nR\n \n \n\u2062\n \n \nN\n \nR\n \n \n\u2062\n \n \nA\n \nR\n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n \n \n \n \nwhere B\nR \nis the magnetic field component over the loop normal to the loop-area and N\nR \nis the number of receiver coil turns.", 'The magnitude and direction of the magnetic field at the receiver generated by a transmitter coil depends on the magnitude and frequency of the driving current, I, the spacing between the coils, and on the electrical properties of the material between the transmitter (represented as an impedance Z in Equation 3).', 'If the field generated by each of the loops in the transmitter coil is nearly the same in magnitude and direction, then the magnetic field from the transmitter scales as the number of transmitter turns N\nT \nand the transmitter loop area A\nT\n.', 'With these assumptions, the induced voltage is written as follows: \n \nV\ninduced\n∝N\nT\nA\nT\nN\nR\nA\nR\nZI\n\u2003\u2003EQUATION 3 \n \nThe actual voltage measured V is also proportional to the electronic gain and phase of the transmitter and receiver antennas and electronics.', 'If the transmitter current and the turn-area of the transmitter is lumped together with the transmitter electronics gain into a total transmitter gain g\nT \nand the receiver turn-area is lumped together with the receiver electronics gain into a total receiver gain g\nR\n, then the measured voltage can be modeled as being proportional to a formation impedance Z that depends only on the frequency, the electrical properties of the medium between the transmitter and receiver, and on the geometry (for example spacing and orientation) of the antennas as follows: \n \nV=g\nT\ng\nR\nZ\n\u2003\u2003EQUATION 4', 'In addition to the mutual inductive coupling between the transmitter and receiver antennas (coils), other signal sources and other sources of coupling can also generate signals in the receiver system.', 'Noise is a non-coherent signal due to intrinsic noise in the antenna or electronics.', 'Interference is a non-coherent signal on the receiver from sources either inside (power supply switching for example), or outside the tool (power line harmonics, radio broadcasts, lighting, etc.).', 'Coherent sources of coupling also generally occur at some level since it is never possible to perfectly isolate the transmitter and receiver electronics.', 'Imperfections in the transmitter may induce a current that flows down the collar and that couples to imperfections in the receiver (which is referred to as TM mode coupling).', 'Similarly, the transmitter and receiver may couple capacitively.', 'Crosstalk is a voltage in the receiver that arises from coupling between the transmitter and the receiver inside the tool.', 'Crosstalk is coherent with the mutual antenna coupling.', 'The voltage measured at the receiver is the sum of all of the above sources as follows: \n \nV\ntotal\n=V+V\nTM\n+V\ncap', '+V\ncrosstalk\n+V\nnoise\n\u2003\u2003EQUATION 5 \n \nThe following assumptions are made in the disclosed calibration methods that follow:\n \n(i)', 'The magnetic field produced by the transmitter coil is approximately constant in magnitude and direction across the receiver coil.', '(ii) transverse magnetic (TM) mode coupling, capacitive coupling, crosstalk, interference, and (averaged) noise voltages are small compared to the transverse electric (TE) mode signals induced in the receivers by the electromagnetic measurement (i.e., by design).', '(iii) The gains (electronic and antenna) are linear over the measurement range.', '(iv) A tool-formation response model exists that can match the calibrated tool measurements with sufficient accuracy to invert the calibrated measurements for the formation properties of interest.', 'Collocated Orthogonal Triaxial Measurements', 'The current flow {right arrow over (J)} due to an electric field {right arrow over (E)} applied to a material with conductivity a is not necessarily in the same direction as the applied electric field as follows: \n \n{right arrow over (J)}=σ{right arrow over (E)}\n \n \nJ\nx\n=σ\nxx\nE\nx\n+σ\nxy\nE\ny\n+σ\nxz\nE\nz \n \n \nJ\ny\n=σ\nyx\nE\nx\n+σ\nyy\nE\ny\n+σ\nyz\nE\nz \n \n \nJ\nz\n=σ\nzx\nE\nx\n+σ\nzy\nE\ny\n+σ\nzz\nE\nz\n\u2003\u2003EQUATION 6 \n \nIn general the earth is anisotropic and its electrical properties are a tensor which contains information on formation resistivity anisotropy, dip, bed boundaries and other aspects of formation geometry.', 'σ\n \n=\n \n \n[\n \n \n \n \n \nσ\n \nxx\n \n \n \n \n \nσ\n \nxy\n \n \n \n \n \nσ\n \nxz\n \n \n \n \n \n \n \nσ\n \nyx\n \n \n \n \n \nσ\n \nyy\n \n \n \n \n \nσ\n \nyz\n \n \n \n \n \n \n \nσ\n \nzx\n \n \n \n \n \nσ\n \nzy\n \n \n \n \n \nσ\n \nzz\n \n \n \n \n \n]\n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n7\n \n \n \n \n \n \n \n \nTraditional propagation and induction measurements utilizing only axial (z-axis) coils are only sensitive to a fraction of the full conductivity tensor.', 'The mutual inductive couplings between 3 mutually orthogonal collocated transmitter coils and 3 mutually orthogonal collocated receiver coils form a tensor and have sensitivity to the full conductivity tensor (including the nine tensor elements shown in Equation 7).', 'In principle, measurements of these fundamental triaxial couplings can be inferred from this triaxial measurement and can be written compactly in matrix form as follows:\n \n \n \n \n \n \n \n \n \nV\n \ninduced\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \nIZ\n \n=\n \n \n \n[\n \n \n \n \n \nI\n \nx\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \nI\n \ny\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \nI\n \nz\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \nZ\n \nxx\n \n \n \n \n \nZ\n \nxy\n \n \n \n \n \nZ\n \nxz\n \n \n \n \n \n \n \nZ\n \nyx\n \n \n \n \n \nZ\n \nyy\n \n \n \n \n \nZ\n \nyz\n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \nZ\n \nzz\n \n \n \n \n \n]', 'EQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n8\n \n \n \n \n \n \n \n \nWherein the symbol is used throughout to denote when a measurement is ‘modeled as’.', 'The first letter (indice) in the subscript in the Z tensor corresponds to the direction of the transmitter (x-, y-, or z-axes) while the second corresponds to the direction of the receiver.', 'For example, Z\nxx \nrepresents the mutual coupling between the x-axis transmitter firing with current I\nx \n(whose moment is aligned with the x-axis) and the receiver whose moment is also aligned with the x-axis, Z\nyx \nrepresents the mutual coupling between the y-axis transmitter firing with current I\ny \n(whose moment is aligned with the y-axis) and the receiver whose moment is aligned with the y-axis, and so on.', 'As before, the actual voltage measured depends on the electronic and antenna gains.', 'For the triaxial case this can be represented in matrix form as follows:\n \n \n \n \n \n \n \n \nV\n \n=\n \n \n \n[\n \n \n \n \n \nV\n \nxx\n \n \n \n \n \nV\n \nxy\n \n \n \n \n \nV\n \nxz\n \n \n \n \n \n \n \nV\n \nyx\n \n \n \n \n \nV\n \nyy\n \n \n \n \n \nV\n \nyz\n \n \n \n \n \n \n \nV\n \nzx\n \n \n \n \n \nV\n \nzy\n \n \n \n \n \nV\n \nzz\n \n \n \n \n \n]\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \nG\n \nT\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nZG\n \nR\n \n \n \n=\n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n \ng\n \nTx\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nTy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nTz\n \n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \n \nZ\n \nxx\n \n \n \n \n \nZ\n \nxy\n \n \n \n \n \nZ\n \nxz\n \n \n \n \n \n \n \nZ\n \nyx\n \n \n \n \n \nZ\n \nyy\n \n \n \n \n \nZ\n \nyz\n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \nZ\n \nzz\n \n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \n \ng\n \nRx\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nRy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nRz\n \n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n9\n \n \n \n \n \n \n \n \nHere as before, the transmitter currents are included in the generalized transmitter electronic gains G\nT\n.', 'If the magnetic field produced by the transmitter coil is approximately constant in magnitude and direction across the receiver coil, then the mutual inductive coupling scales with the number of turns and the effective coil areas of the transmitter and receiver.', 'As described above, the turn areas can simply be folded into the gains (as in Equation 4).', 'However, in general the antenna moments do not have to be aligned with the x-, y-, and z-tool axes.', 'The moment may then be expressed as a generalized gain times a unit vector that points in the direction normal to the area enclosed by the antenna coil as follows: \n EQUATION 10 \n \n \n \n \n \nV\n \n\u2062\n \n \n=\n \nm\n \n \n\u2062', '[\n \n \n \n \n \ng\n \nTx\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nTy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nTz\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \nm\n \nTxx\n \n \n \n \n \nm\n \nTxy\n \n \n \n \n \nm\n \nTxz\n \n \n \n \n \n \n \nm\n \nTyx\n \n \n \n \n \nm\n \nTyy\n \n \n \n \n \nm\n \nTyz\n \n \n \n \n \n \n \nm\n \nTzx\n \n \n \n \n \nm\n \ntzy\n \n \n \n \n \nm\n \nTzz\n \n \n \n \n \n]\n \n \n \nt\n \n \n\u2062\n \n \n \nZ\n \n\u2061\n \n \n[\n \n \n \n \n \nm\n \nRxx\n \n \n \n \n \nm\n \nRxy\n \n \n \n \n \nm\n \nRxz\n \n \n \n \n \n \n \nm\n \nRyx\n \n \n \n \n \nm\n \nRyy\n \n \n \n \n \nm\n \nRyz\n \n \n \n \n \n \n \nm\n \nRzx\n \n \n \n \n \nm\n \nRzy\n \n \n \n \n \nm\n \nRzz\n \n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n \n \n \ng\n \nRx\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nRy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nRz\n \n \n \n \n \n]\n \n \n \n \n \n \n \n \nwhere the superscript t represents the transpose of the corresponding matrix, and where m\nTxx\n, m\nTyx\n, and m', 'Tzx \nrepresent the projection of a unit vector that is in the same direction as the ‘x’ transmitter moment on the x-, y-, and z-tool axes respectively, m\nTxy\n, m\nTyy\n, and m\nTzy \nrepresent the projection of a unit vector that is in the same direction as the ‘y’ transmitter moment on the x-, y-, and z-tool axes respectively, and m', 'Txz\n, m\nTyz\n, and m\nTzz \nrepresent the projection of a unit vector that is in the same direction as the ‘z’ transmitter moment on the x-, y-, and z-tool axes respectively.', 'Likewise, m\nRxx\n, m\nRyx\n, and m\nRzx \nrepresent the projection of a unit vector that is in the same direction as the ‘x’ receiver moment on the x-, y-, and z-tool axes respectively, m\nRxy\n, T\nRyy\n, and m\nRzy \nrepresent the projection of a unit vector that is in the same direction as the ‘y’ receiver moment on the x-, y-, and z-tool axes respectively; and m', 'Rxz\n, m\nRyz\n, and m\nRzz \nrepresent the projection of a unit vector that is in the same direction as the ‘z’ receiver moment on the x-, y-, and z-tool axes.', 'Note that the subscripts of each tensor element do not necessarily refer to specific directions, but now simply serve to label them.', 'For example the voltage V\nxy \nis the voltage measured on the receiver coil labeled ‘y’ that is not necessarily in the y direction when the transmitter labeled as the ‘x’ transmitter that is not necessarily aligned with the x direction fires.', "For a rotating tool, the transmitter (receiver) moment is rotated around the tool axis at the local transmitter (receiver) tool axis direction, which in general are not the same because of bending of the BHA such that:\n \n \n \n \n \n \n \n \n \n \nm\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nrotated\n \n \n \n=\n \n \n \n \nR\n \nT\n \n \n\u2061\n \n \n[\n \n \n \n \n \nm\n \nTxx\n \n \n \n \n \nm\n \nTxy\n \n \n \n \n \nm\n \nTxz\n \n \n \n \n \n \n \nm\n \nTyx\n \n \n \n \n \nm\n \nTyy\n \n \n \n \n \nm\n \nTyz\n \n \n \n \n \n \n \nm\n \nTzx\n \n \n \n \n \nm\n \ntzy\n \n \n \n \n \nm\n \nTzz\n \n \n \n \n \n]\n \n \n \n=\n \n \n \nR\n \nT\n \n \n\u2062\n \n \nm\n \nT\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nm\n \n \nR\n \n\u2062\n \n_\n \n\u2062\n \nrotated\n \n \n \n=\n \n \n \n \nR\n \nR\n \n \n\u2061\n \n \n[\n \n \n \n \n \nm\n \nRxx\n \n \n \n \n \nm\n \nRxy\n \n \n \n \n \nm\n \nRxz\n \n \n \n \n \n \n \nm\n \nRyx\n \n \n \n \n \nm\n \nRyy\n \n \n \n \n \nm\n \nRyz\n \n \n \n \n \n \n \nm\n \nRzx\n \n \n \n \n \nm\n \nRzy\n \n \n \n \n \nm\n \nRzz\n \n \n \n \n \n]\n \n \n \n=\n \n \n \nR\n \nR\n \n \n\u2062\n \n \nm\n \nR\n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n11\n \n \n \n \n \n \n \n \nwhere R\nT \nand R\nR \nrepresent the rotation matrices of the transmitter and receiver, where the angles T and R are defined with respect to a general reference system (e.g., with respect to a tool, wellbore, or Earth's reference frame).", 'For the case of an electromagnetic logging arrangement employing a triaxial transmitter and a triaxial receiver, the moment matrices are equal to the identity matrix:\n \n \n \n \n \n \nm\n \nT\n \n \n=\n \n \n \nm\n \nR\n \n \n=\n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n1\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n \n \n \nIncluding rotation, the measured voltage may be modeled as follows: \n \nV=G\nT\nm\nT\nt\nR\nT\nt\nZR\nR\nm\nR\nG\nR\n\u2003\u2003EQUATION 12 \n \nBy way of review, Equation 12 assumes the following:\n \n(i) TM mode coupling, capacitive coupling, crosstalk, interference, and (averaged) noise voltages are small compared to the signals induced in the receivers through magnetic coupling through the formation\n \n(ii) The three antennas in each transmitter and receiver triad are substantially collocated and orthogonal to each other.', '(iii)', 'The magnetic fields are approximately constant over both the transmitter and receiver coils such that each can be scaled by a single gain value.', '(iv) The system is linear as the signal level changes, that is the gain does not change with signal level.', '(v) There is no electronic cross-coupling between each of the transmitter and each of receiver channels such that the gain of each triad can be represented by a diagonal matrix.', 'The cross axial antenna (i.e., the x- and y-axis antennas) are generally misaligned in a deep measurement system including distinct transmitter and receiver subs that are threadably connected to a BHA.', 'The misalignment is arbitrary (depending on the orientation of the tool threads and the make-up torque employed in the particular operation) such that the cross-axial transmitter and receiver antennas may be thought of as having an arbitrary alignment angle γ between them.', 'The angle γ can be measured upon tool make-up and is therefore assumed to be known such that Equation 12 can be rewritten as follows: \n \nV\nG\nT\nm\nT\nt\n(\nR\nT\nt\nZR\nR\n)', 'R\nγ\nm\nR\nG\nR\n\u2003\u2003EQUATION 13 \n \nAs noted above, G\nT \nand G\nR \nrepresent the transmitter and receiver gains.', 'For a triaxial transmitter, the gains may be modeled as the product of an antenna gain (effective turn area, gm\nTx\n, gm\nTy\n, and gm\nTz\n) and the corresponding transmitter currents (I\nTx\n, I\nTy\n, and I\nTz\n).', 'For triaxial receivers, the gains may be modeled as the product of an antenna gain (effective turn area, gm\nRx\n, gm\nRy\n, and gm\nRz\n) and the gain of the receiver electronics (ge\nRx\n, ge\nRy\n, and ge\nRz\n), for example, as follows:\n \n \n \n \n \n \nG\n \nT\n \n \n=\n \n \n \n[\n \n \n \n \n \ng\n \nTx\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nTy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nTz\n \n \n \n \n \n]\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \ngm\n \nTx\n \n \n\u2062\n \n \nI\n \nTx\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ngm\n \nTy\n \n \n\u2062\n \n \nI\n \nTy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ngm\n \nTz\n \n \n\u2062\n \n \nI\n \nTz\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \nG\n \nR\n \n \n=\n \n \n \n[\n \n \n \n \n \ng\n \nRx\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nRy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nRz\n \n \n \n \n \n]\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \ngm\n \nRx\n \n \n\u2062\n \n \nge\n \nRx\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ngm\n \nRy\n \n \n\u2062\n \n \nge\n \nRy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ngm\n \nRz\n \n \n\u2062\n \n \nge\n \nRz\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \nIn general, the effective turn area can vary from antenna to antenna owing, for example, to manufacturing tolerances.', 'Moreover, the effective turn area of the antennas is generally temperature (and perhaps pressure) dependent owing to thermal expansion of the molded antenna assembly and (possibly) the shield.', 'The transmitter current amplitude and phase as well as the receiver electronics gain and phase can also vary from assembly to assembly and with downhole temperature during use.', 'Calibration is intended to remove this variability and thereby enable accurate and reliable electromagnetic measurements.', 'It will be understood that tilted transmitters and tilted receivers may be similarly modeled.', 'For example, for a tilted transmitter, the gain may be modeled as the product of an antenna gain (effective turn area gm\nT\n) and the transmitter current (I\nT\n) such that:\n \n \n \n \n \n \nG\n \nT\n \n \n=\n \n \n \n[\n \n \n \n \n \ng\n \nTx\n \n \n \n \n \n \n0\n \n \n \n \n \n \ng\n \nTz\n \n \n \n \n \n]\n \n \n=\n \n \n[\n \n \n \n \n \n \ngm\n \nTx\n \n \n\u2062\n \n \nI\n \nT\n \n \n \n \n \n \n \n0\n \n \n \n \n \n \n \ngm\n \nTz\n \n \n\u2062\n \n \nI\n \nT\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \ngm\n \nTx\n \n \n=\n \n \n \ngm\n \nT\n \n \n\u2062\n \n \nsin\n \n\u2061\n \n \n(\n \nβ\n \n)\n \n \n \n \n \n \n \n \n \n \n \ngm\n \nTz\n \n \n=\n \n \n \ngm\n \nT\n \n \n\u2062\n \n \ncos\n \n\u2061\n \n \n(\n \nβ\n \n)\n \n \n \n \n \n \n \n \nwhere β represents the tilt angle of the transmitter.', 'It will, of course, be understood that the gain of a tilted receiver can be modeled similarly.', 'For the general case of rotation and static bending it will be understood that the rotated tensor couplings (shown in the parentheses in Equation 13) may be expressed mathematically in harmonic form, for example, as follows: \n \nR\nT\nt\nZR\nR\n=Z\nDC\nZ\nFHC \ncos(θ)+\nZ\nFHS \nsin(θ)+\nZ\nSHC \ncos(2θ)+\nZ\nSHS \nsin(2θ)', 'The antenna voltages may be measured as the tool rotates (e.g., during drilling).', 'The measured voltages may be fit to a function of the rotation angle θ (as shown in Equation 15 below) to obtain the average (DC), first-harmonic cosine (FHC), first harmonic sine (FHS), second harmonic cosine (SHC), and second harmonic sine (SHS) voltage coefficients.', 'V=V\nDC\nV\nFHC \ncos(θ)\nV\nFHS \nsin(θ)+\nV\nSHC \ncos(2θ)+\nV\nSHS \nsin(2θ)', 'EQUATION 14 \n \nThese voltage coefficients (harmonics) may be considered to be the “measured” antenna voltages as they represent the antenna measurement input into the gain compensation processing.', 'The measured voltage coefficients may therefore be expressed as follows:\n \n \n \n \n \n \n \n \n \n \nV\n \nDC\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nG\n \nT\n \n \n\u2062\n \n \nm\n \nT\n \nt\n \n \n\u2062\n \n \nR\n \nT\n \nt\n \n \n\u2062\n \n \nZ\n \nDC', '\u2062\n \n \nR\n \nR\n \n \n\u2062\n \n \nR\n \nγ\n \n \n\u2062\n \n \nm\n \nR\n \n \n\u2062\n \n \nG\n \nR\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \nFHC\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nG\n \nT\n \n \n\u2062\n \n \nm\n \nT\n \nt\n \n \n\u2062\n \n \nR\n \nT\n \nt\n \n \n\u2062\n \n \nZ\n \nFHC\n \n \n\u2062\n \n \nR\n \nR\n \n \n\u2062\n \n \nR\n \nγ\n \n \n\u2062\n \n \nm\n \nR\n \n \n\u2062\n \n \nG\n \nRj\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \nFHS\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nG\n \nT\n \n \n\u2062\n \n \nm\n \nT\n \nt\n \n \n\u2062\n \n \nR\n \nT\n \nt\n \n \n\u2062\n \n \nZ\n \nFHS\n \n \n\u2062\n \n \nR\n \nR\n \n \n\u2062\n \n \nR\n \nγ\n \n \n\u2062\n \n \nm\n \nR\n \n \n\u2062\n \n \nG\n \nR\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \nSHC\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nG\n \nT\n \n \n\u2062\n \n \nm\n \nT\n \nt\n \n \n\u2062\n \n \nR\n \nT\n \nt\n \n \n\u2062\n \n \nZ\n \nSHC\n \n \n\u2062\n \n \nR\n \nR\n \n \n\u2062\n \n \nR\n \nγ\n \n \n\u2062\n \n \nm\n \nR\n \n \n\u2062\n \n \nG\n \nR\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \nSHS\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nG\n \nT\n \n \n\u2062\n \n \nm\n \nT\n \nt\n \n \n\u2062\n \n \nR\n \nT\n \nt\n \n \n\u2062\n \n \nZ\n \nSHS\n \n \n\u2062\n \n \nR\n \nR\n \n \n\u2062\n \n \nR\n \nγ\n \n \n\u2062\n \n \nm\n \nR\n \n \n\u2062\n \n \nG\n \nR\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n15', 'Although the calibration and processing methodology disclosed herein applies to the general case (described above with respect to Equation 13), it can be instructive to describe the physics for an example with negligible drill string bending (the disclosed embodiments are not limited in this regard).', 'When BHA bending is negligible, both the transmitter and receiver moments rotate about the same axis (i.e., a common z-axis).', 'In this case, the transmitter and receiver rotation matrices R\nT \nand R\nR \nthrough the angle θ may be expressed as follows:\n \n \n \n \n \n \n \n \n \nR\n \nT\n \n \n=\n \n \n \nR\n \nR\n \n \n=\n \n \n \nR\n \nθ\n \n \n=\n \n \n[\n \n \n \n \n \ncos\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n \n \n-\n \n \nsin\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n \n \n0\n \n \n \n \n \n \nsin\n \n\u2061\n \n \n(\n \nθ\n \n)', 'cos\n \n\u2061\n \n \n(\n \nθ\n \n)\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n16\n \n \n \n \n \n \n \n \nThe rotated tensor couplings may be expressed as follows: \n \nR\nθ\nt\nZR\nθ\n=Z\nDC\n+Z\nFHC \ncos(θ)\nZ\nFHS \nsin(θ)+\nZ\nSHC \ncos(2θ)+\nZ\nSHS \nsin(2θ)', 'EQUATION 17 \n \nwhere:\n \n \n \n \n \n \n \n \n \n \nZ\n \nDC\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n2\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n0\n \n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n2\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nzz\n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \nFHC\n \n \n=\n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nxz\n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nyz\n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nzy\n \n \n \n \n0\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \nFHS\n \n \n=\n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nyz\n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n-\n \n \nZ\n \nxz\n \n \n \n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \n-\n \n \nZ\n \nzx\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \nSHC\n \n \n=\n \n \n[\n \n \n \n \n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n2\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n0\n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \nSHS\n \n \n=\n \n \n[\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n18\n \n \n \n \n \n \n \n \nIt will be understood that the disclosed embodiments are not limited to the use of triaxial transmitter and triaxial receivers as depicted on \nFIG.', '2\n.', 'For example, the disclosed embodiments may also be used for transmitters and receivers employing tilted antennas or for embodiments in which one of the transmitter and receiver employs a tilted antenna and the other employs triaxial antennas.', 'Tilted antenna gains may be treated as described above.', 'Calibration Methodology\n \nFIG.', '4\n depicts a flow chart of one disclosed method embodiment 100.', 'Calibration standards are determined for a reference tool including a reference transmitter and a reference receiver at \n105\n.', 'A first calibration factor is measured to match a first tool receiver (i.e., the receiver of a tool to be calibrated) with the reference tool receiver at \n150\n.', 'A second calibration factor is measured to match a transmitter of the first tool (the transmitter of a tool to be calibrated) with a reference tool transmitter at \n160\n.', 'The calibration factors are then applied to the measurements made by the first tool during (or after) a logging operation at \n170\n to compute calibrated logging measurements.', 'Example embodiments of each of these processes are described in more detail below for both tilted and triaxial antenna arrangements.', 'The method above may be extended to axial and transverse antenna arrangements.', 'FIG.', '5\n depicts a flow chart of one disclosed embodiment providing further detail regarding element \n105\n of method \n100\n depicted on \nFIG.', '4\n.', 'At \n110\n temperature and pressure variation models are determined for transmitter and receiver moments.', 'These models include calibration equations that relate a change in an effective turn area of the transmitter and/or receiver antennas to temperature and/or pressure (e.g., the downhole temperature and pressure).', 'A ratio of a reference receiver tool voltage to a reference loop transmitter current is measured to establish a receiver calibration transfer standard at \n120\n.', 'A ratio of a reference loop receiver voltage to a reference transmitter tool current is measured to establish a transmitter calibration transfer standard at \n130\n.', 'And at \n140\n a ratio of a reference tool assembly receiver voltage to transmitter current is measured to establish a reference air calibration ratio.', 'Changes in Temperature and Pressure\n \nFIG.', '6\n depicts a flow chart of one disclosed embodiment providing further detail of element \n110\n in the flow chart depicted on \nFIG.', '5\n.', 'At \n111\n an environmentally stable transmitter is deployed around a tool receiver antenna in a repeatable position with respect to the tool receiver antenna.', 'The combined assembly (the deployment described in \n111\n) is then deployed in an environmental chamber at \n112\n.', 'Changes in the mutual impedance (or the electromagnetic coupling) between the environmentally stable transmitter and the tool receiver are measured and recorded at \n113\n at various environmental conditions (e.g., over a range of temperatures observed in downhole logging operations).', 'At \n114\n, steps \n111\n, \n112\n, and \n113\n may then repeated for a number of tool receiver antennas (e.g., for each of the individual antennas in a triaxial receiver).', 'The acquired data may then be fit to an appropriate function at \n115\n that models the change in tool receiver effective turn area as a function of temperature.', 'The effective gain of transmitter and receiver antennas depends on the temperature and pressure at which they are employed.', 'For example, thermal expansion of the materials that make up the antenna assembly with increasing temperature tend to increase the effective area of the antenna while increasing pressure tends to compress the antenna materials and reduce the effective area.', 'While the disclosed embodiments are not limited in this regard, both numerical modeling and measured data suggest that the effect of temperature is more significant than that of pressure and that the effect of pressure may be ignored for some operations.', 'In such embodiments, the effective area may be modeled as an effective area at a reference temperature and a factor that models the relative change in the effective area as a function of changing temperature, for example, as in the following equations for a triaxial receiver and a triaxial transmitter:\n \n \n \n \n \n \n \n \n \n \nm\n \nRx\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nRx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \nT\n \n)\n \n \n \n \n)\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nm\n \nRy\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nRy\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \nT\n \n)\n \n \n \n \n)\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nm\n \nRz\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nRz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \nT\n \n)\n \n \n \n \n)\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nm\n \nTx\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nT\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \n \n \n \n\u2062\n \nx\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \nT\n \n)\n \n \n \n \n)\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nm\n \nTy\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nTy\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \nT\n \n)\n \n \n \n \n)\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nm\n \nTz\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nTz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \nT\n \n)\n \n \n \n \n)\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n20\n \n \n \n \n \n \n \n \nwhere m\nRx\n, m', 'Ry\n, and m\nRz \nrepresent the effective turn areas of the x-, y-, and z-axis receiver antennas, m\nTx\n, m\nTy\n, and m', 'Tz \nrepresent the effective turn areas of the x-, y-, and z-axis transmitter antennas, m\nRx0\n, m\nRy0\n, and m\nRz0 \nrepresent the effective turn areas of the receiver antennas at the reference temperature, m\nTx0\n, m\nTy0\n, and m\nTz0 \nrepresent the effective turn areas of the transmitter antennas at the reference temperature, f\nRx \nand f\nRz \nrepresent the for the x- and z-axis receiver antennas, and f\nTx \nand f\nTz \nrepresent the functions of the change in effective area with temperature for the x- and z-axis transmitter antennas.', 'With reference to Equation 20, the effect of temperature may be modeled for each of the antennas in the triaxial transmitter and receiver.', 'Each antenna may have a corresponding effective turn area at the reference temperature.', 'However, the functions of the change in effective area for the transverse antennas (the x and y antennas) are generally about equal (such that f\nRx \nmay be used for each of the x- and y-axis receivers and f\nTx \nmay be used for each of the x- and y-axis transmitters).', 'Since transmitter and receiver antenna designs are sometimes different from one another, the transmitting and receiving antennas are modeled separately in Equation 20 (although the disclosed embodiments are by no means limited in this regard).', 'With reference again to Equation 20, f(T) may be defined, for example, as follows: \n \nf\n(\nT\n)≈ξΔ\nT\n\u2003\u2003EQUATION 21 \n \nwhere ξ is an effective coefficient of thermal expansion, and ΔT represents a temperature difference between a measured temperature and the reference temperature.', 'It will be understood that in certain embodiments it may not be practical to characterize each antenna on each manufactured logging tool collar.', 'In some embodiments, effect of varying pressure and temperature may be evaluated over an ensemble of representative antennas.', 'In embodiments in which the antenna to antenna variation is determined to be small (or repeatable with minimal hysteresis) the measured change in temperature for a representative sample of antennas may be fit to obtain a function that models the relative change in the effective area.', 'Reference Receiver\n \nFIG.', '7\n depicts a flow chart of one disclosed embodiment providing further detail of element \n120\n in the flow chart depicted on \nFIG.', '5\n.', 'A reference tool including a reference receiver is provided.', 'At \n121\n a reference transmitter loop assembly is deployed in a known repeatable position about one of the receiving antennas on the reference tool receiver.', 'The combined assembly (the deployment described in \n121\n) is then deployed in a controlled repeatable environment (such as a lab or an environmental chamber or some other controlled environment) at \n122\n.', 'The reference loop transmitter assembly is energized at \n123\n to establish an electromagnetic coupling with the reference tool receiver and the reference loop transmitter current is measured at \n124\n.', 'The gain of the transmitter electronics used to measure the reference loop transmitter current in \n124\n is calibrated in \n125\n and the reference tool receiver gain is calibrated in \n126\n.', 'A ratio of an electronically calibrated reference receiver voltage to an electronically calibrated reference loop transmitter current is computed in \n127\n.', 'A temperature correction is applied to the computed ratio in \n128\n.', 'As described above, a calibration (test) loop is mounted on a reference receiver on the reference tool.', 'The calibration loop is energized and a corresponding voltage is measured on the reference receiver to determine the coupling between the test loop transmitter and the reference receiver.', 'The test loop may then be subsequently used to match a logging tool receiver (i.e., a receiver to be calibrated) to the reference receiver.', 'To ensure consistency with subsequent calibrations it is desirable that (i) the geometry of the reference loop receiver(s) is/are stable such that its magnetic moment does not change for subsequent calibrations; (ii) the deployment of the calibration loop onto the logging tool be sufficiently repeatable to ensure repeatable coupling between the test loop and the receiver antenna; and (iii) the conductivity of the environment in the vicinity of the logging tool and the test loop be the same for subsequent calibrations so that the total coupling between the loop and the antenna is repeatable.', 'FIGS.', '8A and 8B\n depict example calibration loops \n72\n and \n74\n deployed on axial (\n8\nA) \n76\n and transverse (\n8\nB) \n78\n reference receivers.', 'It has been observed (via both modeling and experimental testing) that the direct coupling between the test loop and the reference receiver antenna tends to be insensitive to the loop geometry and placement/orientation.', 'The sensitivity to small variations in the calibration loop \n72\n, \n74\n orientation on the corresponding receiver \n76\n, \n78\n may be of a second order when the loop moment vector is nearly aligned with the antenna moment vector (i.e., such that an axial test loop is deployed on an axial reference receiver and a transverse test loop is deployed on a transverse reference receiver).', 'For a large test loop (such as depicted on \nFIGS.', '8A and 8B\n), the coupling error can be much less than 0.01 dB for a 0.2-degree error in the relative orientation of the test loop and the receiver antenna.', 'Notwithstanding, for certain applications, sufficient sensitivity remains that that it may be desirable to control the conductivity of the environment at least a few feet around the setup.', 'It will be understood that in the above described calibration scheme the coupling value (impedance) between the test loop(s) and the reference receiver antenna(s) do not need to be determined (i.e., they can remain unknown).', 'Moreover, the methodology does not rely on a mathematical or empirical model of the coupling (impedance) between the test loop and the reference receiver antenna.', 'The methodology advantageously only requires that the coupling be repeatable.', 'With reference again to \nFIG.', '7\n, upon energizing the calibration (test) loop at \n143\n, the corresponding reference receiver voltage can be measured at \n146\n.', 'For example, when a transverse test loop is deployed on a transverse reference receiver, the measured voltage V\nLRrefx_meas \nmay be expressed as follows: \n \nV\nLRrefx_meas\n(\ngm\nRxref\nge\nRxref\nZ\nLxRx\n)\nI\nLx\n\u2003\u2003EQUATION 22 \n \nwhere I\nLx \nrepresents the test loop current applied to the transverse test loop at \n143\n, Z\nLxRx \nrepresents the mutual inductive coupling impedance between the transverse test loop and the transverse receiver antenna, gm\nRxref \nrepresents relative effective turn area of the reference transverse receiver, and ge\nRxref \nrepresents the electronic gain of the transverse reference receiver (i.e., the gain of the reference receiver measurement electronics that measures the x channel voltage).', 'Similarly, when an axial test loop is deployed on an axial reference receiver, the measured voltage V\nLRrefz_meas \nmay be expressed as follows:\n \n \n \n \n \n \n \n \n \nV\n \n \nLRrefz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n(\n \n \n \ngm\n \nRzref\n \n \n\u2062\n \n \nge\n \nRzref\n \n \n\u2062\n \n \nZ\n \nLzRz\n \n \n \n)\n \n \n\u2062\n \n \nI\n \nLz\n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n23\n \n \n \n \n \n \n \n \nwhere I\nLz \nrepresents the test loop current applied to the axial test loop at \n143\n, Z\nLzRz \nrepresents the mutual inductive coupling impedance between the axial test loop and the axial receiver antenna, gm\nRzref \nrepresents relative effective turn area of the reference axial receiver, and ge\nRzref \nrepresents the electronic gain of the axial reference receiver (i.e., the gain of the reference receiver measurement electronics that measures the z channel voltage).', 'With continued reference to \nFIG.', '7\n, the current in the energized test loop I\nLx \nand I\nLz \nmay be measured via the use of calibrated laboratory equipment having known gains a g\neTLx \nand g\neTLz\n.', 'The electronic gain of the reference receiver ge\nRxref \nand ge\nRzref \ncan be measured by the tool itself.', 'For example, electronic gains may be determined by switching in a calibration reference signal \n82\n as shown in circuit \n80\n of \nFIG.', '9\n (in a way similar to procedures used in induction logging tools).', 'The alternating current (AC) calibration signal \n82\n may be generated by a precision digital to analog converter and buffered with fast precision operation amplifiers (although the disclosed embodiments are not limited in this regard).', 'Using such a calibration circuit, the measured transverse and axial receiver electronics gains a g\neRx_meas \nand a g\neRz_meas \nof the reference receiver may be defined as the ratio of the calibration signal measured by the receiver electronics to the known calibration signal, for example, as follows:\n \n \n \n \n \n \n \n \n \n \ng\n \n \neRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \n \nRxcal\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \ncal\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \ng\n \n \neRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \n \nRzcal\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \ncal\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n24\n \n \n \n \n \n \n \n \nwhere V\nRxcal_meas \nand V\nRzcal_meas \nrepresent the calibration signal (voltage) as measured by the transverse and axial reference receiver electronics and V\ncal \nrepresent the known AC calibration signal.', 'With further reference to elements \n125\n-\n128\n of \nFIG.', '7\n, reference loop calibration standards (for the transverse and axial reference receivers) may be obtained by calibrating/correcting the reference receiver voltages: (i) the temperature dependence of the effective turn area of the reference receiver antenna by correcting the measurements to a reference temperature (for example 25 degrees C.) (ii) the current measurement gain in the test loop transmitter, (iii) the electronic gain in the reference receiver antenna electronics, for example, as follows:\n \n \n \n \n \n \n \n \n \n \nC\n \n \nRxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n\u2062\n \n \ng\n \neTLx\n \n \n\u2062\n \n \n \n1\n \n \nge\n \nRxref\n \n \n \n\u2061\n \n \n[\n \n \n \nV\n \n \nLxRxref\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nI\n \nLxmeas\n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nRx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \n \n \n \n\u2062\n \nref\n \n \n \n\u2062\n \n \nZ\n \nLxRx\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nC\n \n \nRzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n\u2062\n \n \ng\n \neTLz\n \n \n\u2062\n \n \n \n1\n \n \nge\n \nRzref\n \n \n \n\u2061\n \n \n[\n \n \n \nV\n \n \nLzRzref\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nI\n \nLzmeas\n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nRz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \n \n \n \n\u2062\n \nref\n \n \n \n\u2062\n \n \nZ\n \nLzRz\n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n25\n \n \n \n \n \n \n \n \nwhere C\nRxloop_ref \nand C\nRzloop_ref \nrepresent calibration factors for the transverse and axial reference receivers that are obtained by electromagnetically coupling the test loop and the corresponding reference receiver and m\nRx0ref \nand m\nRz0ref \nrepresent the effective turn areas of the transverse and axial reference receivers.', 'It will be appreciated that the first term in Equation 25 represents the temperature correction (as described above), g\neTLx \na', 'and g\neTLz \nrepresent the known gains of the electronics used to measure the transverse and axial test loop currents, and ge\nRxref \nand ge\nRzref \nrepresent the electronic gains in the transverse and axial reference receivers.', 'Note also that the calibration factors C\nRxloop_ref \nand C\nRzloop_ref \nequal the product of the effective relative turn area of the reference tool receiver at the reference temperature and the mutual inductive coupling between the loop antenna and the reference tool receiver.', 'Reference Transmitter\n \nFIG.', '10\n depicts a flow chart of one disclosed embodiment providing further detail of element \n130\n in the flow chart depicted on \nFIG.', '5\n.', 'A reference tool including a reference transmitter is provided.', 'At \n131\n a reference receiver loop assembly is deployed in a known repeatable position about one of the transmitting antennas on the reference tool transmitter.', 'The combined assembly (the deployment described in \n131\n) is then deployed in a controlled repeatable environment (such as a lab or an environmental chamber or some other controlled environment) at \n132\n.', 'The reference tool transmitter is energized at \n133\n to establish an electromagnetic coupling with the reference loop receiver and the corresponding reference loop receiver voltage is measured at \n134\n.', 'The gain of the electronics used to measure the reference loop receiver current in \n134\n is calibrated in \n135\n and the reference tool transmitter gain is calibrated in \n136\n.', 'A ratio of an electronically calibrated reference loop receiver voltage obtained in \n134\n to an electronically calibrated reference tool transmitter current is computed in \n137\n.', 'A temperature correction is applied to the computed ratio in \n138\n.', 'The setup used to determine the reference transmitter calibration standard is the same as that described above for the reference receiver, with the exception that the reference tool transmitter is energized and the induced voltage is measured on the calibration loop.', 'The voltage in the reference loop can be measured with calibrated laboratory equipment or with a copy of the same circuitry used to measure the reference tool receiver voltage as described above.', 'The current in the transmitter antenna in the reference can be measured using a transformer with a known well-defined turn ratio, precision, resistor, and measurement electronics with calibration circuitry similar to that discussed above\n \n \n \n \n \n \n \n \n \nI\n \nT_meas\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \ng\n \neT\n \n \n\u2062\n \n \nRnI\n \nT\n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n26\n \n \n \n \n \n \n \n \nwhere I\nT_meas \nrepresents the measured current in the reference tool transmitter (such as a tilted transmitter), I\nT \nrepresents the actual current in the transmitter, g\neT \nrepresents the electronic gain of the transmitter current measuring electronics in the reference transmitter, n represents the transformer turn ratio, R represents the resistance of a load resistor.', 'Likewise, the measured currents I\nTx_meas \nand I\nTz_meas \nin transverse and axial transmitters may be given as follows:\n \n \n \n \n \n \nI\n \n \nTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \ng\n \neTx\n \n \n\u2062\n \n \nRnI\n \nTx\n \n \n \n \n \n \n \n \n \n \nI\n \n \nTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \ng\n \neTz\n \n \n\u2062\n \n \nRnI\n \nTz\n \n \n \n \n \n \n \nwhere I\nTx \nand I\nTz \nrepresent the actual currents in the transverse and axial transmitters and a g\neTx \nand a g\neTz \nrepresent the electronic gains of the transmitter current measuring electronics in the transverse and axial reference transmitters.\n \nFIG.', '11\n represents an example calibration circuit \n90\n for use in measuring the transmitter gains a g\neT\n, g\neTx\n, and/or a g\neTz\n.', 'The circuit is similar to that depicted on \nFIG.', '9\n for use with the reference receivers in that it includes switching in and out a known calibration signal \n92\n.', 'Using such a calibration circuit, the measured reference transmitter electronics gains g\neT_meas\n, g\neTx_meas \nand a g\neTz_meas \nmay be defined (as above with the reference receivers) as the ratio of the calibration signal measured by the receiver electronics to the known calibration signal, for example, as follows:', 'g\n \n \neT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \n \nTcal\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \ncal\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \ng\n \n \neTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \n \nTxcal\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \ncal\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \ng\n \n \neTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \n \nTzcal\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \ncal\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n27\n \n \n \n \n \n \n \n \nwhere V\nTcal_meas\n, V\nTxcal_meas\n, and V\nTzcal_meas \nrepresent the calibration signals (voltages) as measured by the reference transmitters and V\ncal \nrepresent the known AC calibration signal.', 'It will be understood that in certain embodiments since only one transmitter fires at a time, it may be possible to only have one measurement channel to measure each of the antenna currents such that there would only be one electronic gain for the reference transmitter.', 'The disclosed embodiments are, of course, not limited in this regard.', 'As described above for the reference receiver (and with further reference to elements \n135\n-\n138\n of \nFIG.', '10\n), calibration standards for the reference transmitters may be obtained applying (i) a temperature correction, (ii) a reference transmitter current measurement gain correction, and (iii) a receiver loop voltage measurement correction, for example, as follows:\n \n \n \n \n \n \n \n \n \n \nC\n \n \nTxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n\u2062\n \n \n(\n \n \n \nge\n \nTmeas\n \n \n\u2062\n \nRn\n \n \n)\n \n \n\u2062\n \n \n \n1\n \n \nge\n \n \nLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nV\n \n \nTLxref\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nI\n \nTxmeas\n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nTx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \nZ\n \nTLx\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nC\n \n \nTzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n\u2062\n \n \n(\n \n \n \nge\n \nTmeas\n \n \n\u2062\n \nRn\n \n \n)\n \n \n\u2062\n \n \n \n1\n \n \nge\n \n \nLz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nV\n \n \nTLzref\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nI\n \nTzmeas\n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nTz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \nZ\n \nTLz\n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n28\n \n \n \n \n \n \n \n \nwhere C\nTxloop_ref \nand C\nTzloop_ref \nrepresent calibration factors for the transverse and axial reference transmitters that are obtained by electromagnetically coupling the test loop and the corresponding reference transmitter and m\nTx0ref \nand m\nTz0ref \nrepresent the effective turn areas of the transverse and axial reference transmitters It will be appreciated that the first term in Equation 28 represents the temperature correction (as described above), g\neTLx \nand a g\neTLz \nrepresent the gains of the electronics used to measure the test loop currents, and ge\nRxref \nand ge\nRzref \nrepresent the gains in the reference receivers.', 'Air Calibration\n \nFIG.', '12\n depicts a flow chart of one disclosed embodiment providing further detail of element \n140\n in the flow chart depicted on \nFIG.', '5\n.', 'At \n141\n a reference assembly is prepared including a reference tool transmitter assembly and a reference tool receiver assembly at know separation.', 'One example reference assembly \n200\n is depicted on \nFIG.', '13\n in which the reference transmitter tool \n250\n includes a reference transmitter \n252\n and the reference receiver tool \n260\n includes a reference receiver \n262\n.', 'The reference transmitter and reference receiver may be separated by substantially any suitable distance, for example, using a spacer sub \n210\n.', 'With reference again to \nFIG.', '12\n, the reference assembly \n200\n is deployed in a known environment at \n142\n, for example, lifted high into the air up and away from electrically conductive materials (e.g., using a crane).', 'The reference tool transmitter \n252\n is energized at \n143\n to establish an electromagnetic coupling with the reference tool receiver \n262\n and the reference tool transmitter current is measured at \n144\n.', 'The gains of the electronics that are used to measure the reference tool transmitter current are calibrated at \n145\n.', 'Energizing the reference tool transmitter \n252\n induces a voltage in the reference tool receiver \n262\n which is measured (received) at \n146\n using electronics in the reference tool receiver \n262\n.', 'The gains of the electronics that are used to measure the reference tool receiver voltage are then calibrated at \n147\n.', 'A ratio of the electronically calibrated reference tool receiver voltage to the electronically calibrated reference tool transmitter current is calculated at \n148\n and a temperature correction is applied to the calculated ratio at \n149\n.', 'The axial and transverse voltages V\nzz_air \nand V\nxx_air \nmeasured at \n146\n by axial and transverse (z-axis and x-axis) antennas in the reference tool receiver may be modeled, for example, as follows:\n \n \n \n \n \n \n \n \n \n \nV\n \n \nzz\n \n\u2062\n \n_\n \n\u2062\n \nair\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \ng\n \neRz\n \n \n\u2061\n \n \n(\n \n \n \ngm\n \nRzref\n \n \n\u2062\n \n \ngm\n \nTzref\n \n \n\u2062\n \n \nZ\n \n \nTRz\n \nair\n \n \n \n \n)\n \n \n \n\u2062\n \n \nI\n \nTz\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nxx\n \n\u2062\n \n_\n \n\u2062\n \nair\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \ng\n \neRx\n \n \n\u2061\n \n \n(\n \n \n \ngm\n \nRxref\n \n \n\u2062\n \n \ngm\n \nTxref\n \n \n\u2062\n \n \nZ\n \nTRxair\n \n \n \n)\n \n \n \n\u2062\n \n \nI\n \nTx\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n29\n \n \n \n \n \n \n \n \nwhere Z\nTRz\nair \nand Z\nTRxair \nrepresent the (nominal) mutual impedances between the axial and transverse reference transmitter antennas and reference receiver antennas in air (or the known environment), gm\nRzref \nand gm\nRxref \nrepresent the relative effective moments of the axial and transverse reference receiver antennas at the ambient conditions during measurement, gm\nTzref \nand m a gm\nTxref \nrepresent the relative effective moments of the axial and transverse reference transmitter antennas at the ambient conditions during the measurement, g\neRz \nand g\neRx \nrepresent the gains of the electronics used to measure the voltage signals in the axial and transverse reference receiver antennas, and I\nTx \nand I\nTz \nrepresent the axial and transverse reference transmitter currents.', 'Master calibration coefficients for the reference tool may then be constructed from the ratio of the electronically calibrated reference transmitter current to the electronically calibrated reference receiver voltage multiplied by the factors used to scale the reference transmitter and reference receiver relative effective moments to reference temperature conditions.', 'Assuming that the calibrations are accurate, these master calibration coefficients are equal to the inverse of the product of the relative reference transmitter and reference receiver antenna moments at reference conditions multiplied by the coupling impedance between the reference transmitter and receiver antennas.', 'For example, axial and transverse master calibration coefficients C\nzzair \nand C\nxxair \nmay be represented mathematically as follows (and are obtained by electromagnetically coupling the reference transmitters and reference receivers):\n \n \n \n \n \n \n \n \n \nC\n \nzzair\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n[\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)', '\u2062\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n]\n \n \n\u2062\n \n \n\u2003\n \n \n \n \n[\n \n \n \ng\n \n \neRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nRng\n \n \neT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nzz\n \n\u2062\n \n_\n \n\u2062\n \nair\n \n \n \n \n]\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n1\n \n \n \nm\n \n \nRz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \nm\n \n \nTz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n \n \n\u2062\n \n \n1\n \n \nZ\n \nTRzair\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nC\n \nxxair\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062', '[\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n\u2062\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n]\n \n \n\u2062\n \n \n\u2003\n \n \n \n[\n \n \n \ng\n \n \neRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nRng\n \n \neT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2062', '[\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nxx\n \n\u2062\n \n_\n \n\u2062\n \nair\n \n \n \n \n]\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n1\n \n \n \nm\n \n \nRx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n\u2062\n \n \nm\n \n \nTx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n \n \n\u2062\n \n \n1\n \n \nZ\n \nTRxair\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n30\n \n \n \n \n \n \n \n Matching New Tool Receiver to Reference Tool Receiver \n \nWith reference again to \nFIG.', '4\n a new tool receiver (i.e., the receiver of a tool to be calibrated) may be matched with the reference tool receiver at \n150\n.', 'To calibrate the new tool receiver, the same (or a virtually identical) calibration test loop setup as was used on the reference receiver is deployed about the new receiver.', 'As with the reference receiver, the test loop is energized to establish an electromagnetic coupling with new receiver.', 'Transverse and axial measured voltages V\nLxRx_meas \nand V\nLzRz_meas \nmay be represented mathematically, for example, as follows:\n \n \n \n \n \n \n \n \n \n \nV\n \n \nLxRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \ngm\n \nRx\n \n \n\u2062\n \n \ng\n \neRx\n \n \n\u2062\n \n \nZ\n \nLxRx\n \n \n\u2062\n \n \nI\n \nLx\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nLzRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \ngm\n \nRz\n \n \n\u2062\n \n \ng\n \neRz\n \n \n\u2062\n \n \nZ\n \nLzRz\n \n \n\u2062\n \n \nI\n \nLz\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n31\n \n \n \n \n \n \n \n \nwhere Z\nLxRx \nand Z\nLzRz \nrepresent the transverse and axial couplings between the test loop antennas and the new receiver tool antennas.', 'The gains and effective turn areas of the new receiver are as defined previously for the reference receiver.', 'The calibration coefficients for the new receiver tool may be determined by multiplying the reference loop coefficient by the electronically calibrated ratio of the measured transmitter loop current to measured receiver voltage and the factor that corrects the relative moment change for temperature and pressure.', 'Assuming the calibrations to be accurate, the resulting calibration coefficient is equal to the ratio of the reference receiver turn area to the new receiver turn area:', 'EQUATION 32 \n \n \n \n \n \n \nC\n \nRxloop\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \n \nRxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n\u2062\n \n \ng\n \n \neRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n \n1\n \n \ng\n \n \neTLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nI\n \n \nLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nLxRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nRx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n \nm\n \n \nRx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \n \n \n \n \n \n \n \n \nC\n \nRzloop\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \n \nRzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)', '\u2062\n \n \ng\n \n \neRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n \n1\n \n \ng\n \n \neTLz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nI\n \n \nLz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nLzRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nRz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n \nm\n \n \nRz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \n \n \n \n \n \nwhere C\nRxloop \nand C\nRzloop \nrepresent the calibration coefficients (factors) for the new receiver obtained by electromagnetically coupling the test loop and the receiver, C\nRxloop_ref \nand C\nRzloop_ref \nare as defined above in Equation 25, T\nmeas \nrepresents the temperature as measured downhole, and the bracketed quantity\n \n \n \n \n \n[\n \n \n \nI\n \n \nLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nLxRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n represent the current and voltage measurements.', 'Note that the calibration coefficients for the new receiver tool are equal to a ratio of the effective turn areas of the reference and new tool receivers.', 'Matching New Tool Transmitter to Reference Tool Transmitter \n \nWith continued reference to \nFIG.', '4\n a new tool transmitter (i.e., the transmitter of a tool to be calibrated) may be matched with the reference tool transmitter at \n160\n.', 'To calibrate the new tool transmitter, the same (or a virtually identical) calibration test loop setup as was used on the reference transmitter is deployed about the new transmitter.', 'As with the reference transmitter, the test loop is used to measure the corresponding induced voltage when the new tool transmitter is energized (i.e., when the test loop and new transmitter are electromagnetically coupled).', 'Calibration coefficients for the new transmitter can be computed as described above for the new receiver.', 'C\n \nTxloop\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \n \nT\n \n\u2062\n \nxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)', '\u2062\n \n \n(\n \n \n \nge\n \nTmeas\n \n \n\u2062\n \nRn\n \n \n)\n \n \n\u2062\n \n \n \n1\n \n \nge\n \n \nR\n \n\u2062\n \nLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nTLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nTx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n \nm\n \n \nTx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nC\n \nTzloop\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \n \nTzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n\u2061\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n)\n \n \n \n\u2062\n \n \n(\n \n \n \nge\n \nTmeas\n \n \n\u2062\n \nRn\n \n \n)\n \n \n\u2062\n \n \n \n1\n \n \nge\n \n \nR\n \n\u2062\n \nLz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nTLz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nTz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n\u2062\n \nref\n \n \n \n \nm\n \n \nTz\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n33\n \n \n \n \n \n \n \n \nwhere C\nTxloop \nand C\nTzloop \nrepresent the calibration coefficients for the new transmitter obtained by electromagnetically coupling the test loop and the transmitter, C\nTxloop_ref \nand C\nTzloop_ref \nare as defined above with respect to Equation 28, T\nmeas \nrepresents the temperature as measured downhole, and the bracketed quantity\n \n \n \n \n \n[\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nTLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n represent the current and voltage measurements.', 'Note that the calibration coefficients for the new transmitter are equal to a ratio of the effective turn areas of the reference and new tool transmitters.', 'For the y-axis transverse antennas (both receiver and transmitter) only the ratio of the y antenna effective turn area to the x antenna effective turn is needed.', 'The same test loop used for the x antenna is repositioned over the y antenna and the voltage signals may be measured as described previously:\n \n \n \n \n \n \n \n \n \n \nV\n \n \nLxRy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \ngm\n \nRy\n \n \n\u2062\n \n \ng\n \neRy\n \n \n\u2062\n \n \nZ\n \nLxRy\n \n \n\u2062\n \n \nI\n \nLx\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nTyLxref\n \n\u2062\n \n_\n \n\u2062\n \nmea\n \n\u2062\n \ns\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \ngm\n \nTy\n \n \n\u2062\n \n \ng\n \neLx\n \n \n\u2062\n \n \nZ\n \nTyLx\n \n \n\u2062\n \n \nI\n \nTy\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n34\n \n \n \n \n \n \n \n \nwhere V\nLxRy_meas \nrepresents the voltage measured on the new tool y-axis receiver upon repositioning and energizing the transverse test loop, V\nTyLxref_meas \nrepresents the voltage measured on the repositioned transverse test loop when the y-axis transmitter is energized.', 'The transmitter currents, relative turn areas, electronic gains, and coupling impedances are as described previously.', 'The calibration coefficients for the new y-axis receiver antenna and the new y-axis transmitter antenna may be computed as described above.', 'C\n \n \nmRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \ng\n \n \neRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \ng\n \n \neRy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nV\n \n \nLxRy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nLxRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm', 'Ry\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \nm\n \n \nRx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nC\n \n \nmTxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \ng\n \n \neTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \ng\n \n \neTy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2061\n \n \n[\n \n \n \nV\n \n \nTyLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \nV\n \n \nT\n \n\u2062\n \nxLx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \nm\n \n \nTy\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \nm\n \n \nTx\n \n\u2062\n \n \n \n \n\u2062\n \n0\n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n35\n \n \n \n \n \n \n \n \nwhere C\nmRxy_ratio \nand C\nmTxy_ratio \nrepresent the y-axis receiver and transmitter coefficients.', 'Calibration Examples\n \nThe following examples demonstrate the above-described calibration procedure for three electromagnetic logging tool configurations and/or operating conditions.', 'These examples are for purely illustrative purposes and are not intended to limit the disclosed embodiments or the scope of the claims in any way.', 'Triaxial Transmitter and Triaxial Receiver: Nonrotating', 'In operation downhole: (i) the y-axis antenna gains may be matched to the x-axis antenna gains and (2) the data may be rotated to align the transmitter and receiver', 'x directions and/or rotated to an Earth-fixed reference frame (e.g., top-of-hole or North).', '(3) The gains may be matched to the reference tool gains and (4) the reference tool gains may be cancelled by dividing the measurements by the reference tool air calibration values.', 'In describing this example process, it may be instructive to first define the following matrices:\n \n \n \n \n \n \nG\n \n \nTxy\n \n\u2062\n \n_', '\u2062\n \nratio\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062', '[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n1\n \n \n \nC\n \n \nmTxy\n \nratio\n \n \n \n\u2062\n \n \nC\n \n \neTxy\n \nratio\n \n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ngm\n \nTx\n \n \n \ngm\n \nTy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n=\n \n \n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ng\n \nTx\n \n \n \ng\n \nTy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n\u2003\n \n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n1\n \n \n \nC\n \n \nmRxy\n \nratio\n \n \n \n\u2062\n \n \nC\n \n \neRxy\n \nratio\n \n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ngm\n \nRx\n \n \n \ngm\n \nRy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n=\n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ng\n \nRx\n \n \n \ng\n \nRy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n \n \nwhere G\nTxy_ratio \nrepresents a ratio of the x-axis to y-axis transmitter gains and G\nRxy_ratio \nrepresents a ratio of the x-axis to y-axis receiver gains.', 'Applying these ratios to the measured voltage harmonics replaces the y-axis transmitter and y-axis receiver gains with the x-axis transmitter and x-axis receiver gains.', 'The voltage measurements can then be mathematically rotated (in this example embodiment).', 'The measurement tool is essentially non-rotating (e.g., sliding) in the wellbore.', 'For the DC voltages measured between the transmitter and receiver, the measurements are back rotated by the measured alignment angle γm which if manufacturing variation is small, is close to the actual alignment angle α.', 'This procedure essentially mathematically constructs measurements V\nrot \nequivalent to that of a rotationally aligned transmitter', '(T\n1\n) and receiver (R\n1\n).', 'V\n \nrot\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nG\n \n \nTxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nVG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \n \n \n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \nrot\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nG\n \n \nTxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nVG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \n \n \n \n\u2062\n \nm\n \n \nt\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n36\n \n \n \n \n \n \n \n \nThe rotated voltage matrix may be expressed in matrix form, for example, as follows:\n \n \n \n \n \n \n \n \n \nV\n \nrot\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nxx\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nxy\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nxz\n \n \n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nyx\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nyy\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nyz\n \n \n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzx\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzy\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nzz\n \n \n \n \n \n \n]\n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n37\n \n \n \n \n \n \n \n \nAfter gain matching, the voltages can be rotated from the local tool reference frame to an Earth-fixed frame, for example, as follows: \n \nV\nrot_EF\nR\nLE\nt\nV\nrot\nR\nLE\n\u2003\u2003EQUATION 38 \n \nAfter the above described rotations, calibration coefficients may be applied to remove all gains.', 'All measurements involving x-axis and/or y-axis y antennas may have the same calibration coefficient since the x-axis and y-axis gains were previously matched.', 'The following calibration factors may be computed:', 'K\n \nxx\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nC\n \nxxair\n \n \n\u2062\n \n \nC\n \nTxloop\n \n \n\u2062\n \n \n \n \n \n \nC\n \nRxloop\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062', '[\n \n \n \n \nge\n \n \nTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \nge\n \n \nRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n39\n \n \n \n \n \n \n \n \nwhere K\nxx \nrepresents the calibration quantity obtained by combining the air calibration coefficient C\nxxair \nand the calibration coefficients (factors)', 'C\nTxloop \nand C\nRxloop \nfor the transverse transmitter and the transverse receiver,\n \n \n \n \n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nand\n \n\u2062\n \n \n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n represent the transmitter and receiver turn area temperature and pressure correction, \n \n \n \n \n \n[\n \n \n \n \nge\n \n \nTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n represents the gain corrected transmitter current measurement, and \n \n \n \n \n \n[\n \n \n1\n \n \nge\n \n \nRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n corrects for the measured receiver gain.', 'Ideally, the above quantity K\nxx \ncancels the effect of temperature on the downhole logging tool such that K\nxx \nmay be expressed as follows:\n \n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n \n[\n \n \n1\n \n \nZ\n \nTxRxair\n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ngm\n \nRx\n \n \n\u2062\n \n \nge\n \nRx\n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ngm\n \nTx\n \n \n\u2062\n \n \nI\n \nTx\n \n \n \n \n]\n \n \n=\n \n \n\u2003\n \n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ng\n \nRx\n \n \n\u2062\n \n \ng\n \nTx\n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n40\n \n \n \n \n \n \n \n \n \nNote that K\nxx \nis inversely proportional to the transverse receiver gain g\nRx \nand the transverse transmitter gain g\nTx \nsuch that multiplying the appropriate downhole measurements by K\nxx \nfully cancels these gain terms.', 'Measurements made using the transverse x-axis and y-axis transmitter and receiver antennas (i.e., the xx, xy, yx, and yy couplings) may be multiplied by K\nxx \nthereby canceling all transmitter and receiver gains.', 'Similarly, for measurements made using the axial transmitter and axial receiver (the z-axis transmitter and z-axis receiver), the following quantity can be defined:\n \n \n \n \n \n \n \n \n \nK\n \nzz\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nC\n \nzzair\n \n \n\u2062\n \n \nC\n \nTzloop\n \n \n\u2062\n \n \n \n \n \n \nC\n \nRzloop\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \n \nge\n \n \nTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \nge\n \n \nRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n41\n \n \n \n \n \n \n \n \nwhere K\nzz \nrepresents the calibration quantity obtained by combining the air calibration coefficient C\nzzair \nand the calibration coefficients (factors)', 'C\nTzloop \nand C\nRzloop \nfor the axial transmitter and axial receiver,\n \n \n \n \n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nand\n \n\u2062\n \n \n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n represent the transmitter and receiver turn area correction, \n \n \n \n \n \n[\n \n \n \n \nge\n \n \nTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n represents the gain corrected transmitter current measurement, and \n \n \n \n \n \n[\n \n \n1\n \n \nge\n \n \nRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n corrects for the measured receiver gain.', 'Ideally, the above quantity K\nzz \ncancels the effect of temperature on the downhole logging tool such that K\nzz \nmay be expressed as follows:\n \n \n \n \n \n \n \n \n \nK\n \nzz\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062', '[\n \n \n1\n \n \nZ\n \nTzRzair\n \n \n \n]', '[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ngm\n \nRz\n \n \n\u2062\n \n \nge\n \nRz\n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ngm\n \nTz\n \n \n\u2062\n \n \nI\n \nTz\n \n \n \n \n]\n \n \n=\n \n \n\u2003\n \n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \nZ\n \nTzRzair\n \n \n \n\u2062\n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ng\n \nRz\n \n \n\u2062\n \n \ng\n \nTz\n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n42\n \n \n \n \n \n \n \n \n \nNote that K\nzz \nis inversely proportional to the axial receiver gain g\nRz \nand the axial transmitter gain g\nTz \nsuch that multiplying the appropriate downhole measurements by K\nzz \nfully cancels these gain terms.', 'The x-axis and z-axis cross axial measurements use a different formulation to account for the fact that there are no cross axial air calibration measurements.', 'Ratios of test loop coefficients may be employed to cancel the cross axial gains, for example, as follows:\n \n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \nxxair\n \n \n\u2062\n \n \nC\n \nzzair\n \n \n \n \n\u2062\n \n \n \n \n \n[\n \n \n \nC\n \n \nTzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \nC\n \n \nTxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \nC\n \n \nRxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \nC\n \n \nRzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n \n \n·\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n \n[\n \n \n \nC\n \nTxloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n \nC\n \nRzloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \nge\n \n \nTx\n \n\u2062\n \n_', '\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nTx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \nge\n \n \nRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n43', 'Since the air calibration coefficients and reference loop coefficients were measured in an environment with low conductivity (e.g., in air), their phase is small.', 'Therefore, the principal square root can be taken without any risk of phase wrapping such that K\nxz \nmay be expressed as follows:\n \n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ngm\n \nTx\n \n \n\u2062\n \n \nI\n \nTx\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ngm\n \nRz\n \n \n\u2062\n \n \nge\n \nRz\n \n \n \n \n]\n \n \n \n=\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n]\n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \nZ\n \nLxRx\n \n \n \nZ\n \nLxTx\n \n \n \n \n\u2062\n \n \n \n \nZ\n \nLzRz\n \n \n \nZ\n \nLzRz\n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n44\n \n \n \n \n \n \n \n \n \nOwing to electromagnetic reciprocity in which:\n \n \n \n \n \n \n \n \nZ\n \nLxRx\n \n \n \nZ\n \nLxTx\n \n \n \n \n=\n \n \n \n \n \nZ\n \nLzRz\n \n \n \nZ\n \nLzTz\n \n \n \n \n=\n \n1', 'The calibration coefficient may remain independent of the test loop coupling, and may be expressed, for example, as follows:\n \n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n=\n \n \n \n[\n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n]\n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nLikewise, K\nzx \nmay be expressed as follows:\n \n \n \n \n \n \n \n \n \nK\n \nzx\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \nxxair\n \n \n\u2062\n \n \nC\n \nzzair\n \n \n \n \n\u2062\n \n \n \n \n \n[\n \n \n \nC\n \n \nTzloop\n \n\u2062\n \n_', '\u2062\n \nref\n \n \n \n \nC\n \n \nTxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \nC\n \n \nRxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \nC\n \n \nRzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n \n \n·\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n \n[\n \n \n \nC\n \nTzloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n \nC\n \nRxloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \nge\n \n \nTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nTz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \nge\n \n \nRx\n \n\u2062\n \n_', '\u2062\n \nmeas\n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n45\n \n \n \n \n \n \n \n \n \n \n\u2062\n \nand\n \n \n \n \n \n \n \n \n \n \n \n \n \nK\n \nzx\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n]', '[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ngm\n \nTz\n \n \n\u2062\n \n \nI\n \nTz\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ngm\n \nRx\n \n \n\u2062\n \n \nge\n \nRx\n \n \n \n \n]\n \n \n \n=\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n[\n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n]\n \n \n]\n \n \n[\n \n \n \n \n\u2062\n \n \n1\n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n \n \n]\n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n46\n \n \n \n \n \n \n \n \nAs described above for K\nxx \nand K\nzz\n, K\nxz \nand K\nzx \nare inversely proportion to the indicated transmitter and receiver gains such that multiplying the appropriate downhole measurements by K\nxz \nand K\nzx \nfully cancels the gain terms.', 'Upon computing K\nxx\n, K\nxx\n, K\nxx\n, and K\nxx \nas described above, the rotated and calibrated voltage tensor V\nrot_cal \nmay be expressed as follows:\n \n \n \n \n \n \n \n \n \nV\n \nrot_cal\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n\u2003\n \n \n\u2003\n \n \n[\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \nZ\n \nxx\n \n \n·\n \n \nK\n \nxx\n \n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \nZ\n \nxy\n \n \n·\n \n \nK\n \nxx\n \n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \n \nZ\n \nxz\n \n \n·\n \n \nK\n \nxz\n \n \n \n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \nZ\n \nyx\n \n \n·\n \n \nK\n \nxx\n \n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \nZ\n \nyy\n \n \n·\n \n \nK\n \nxx\n \n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \n \nZ\n \nyz\n \n \n·\n \n \nK\n \nxz\n \n \n \n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \nZ\n \nzx\n \n \n·\n \n \nK\n \nzx\n \n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \nZ\n \nzy\n \n \n·\n \n \nK\n \nzx\n \n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \n \nZ\n \nzz\n \n \n·\n \n \nK\n \nzz\n \n \n \n \n \n \n \n\u2062\n \n \n\u2003\n \n\u2003\n \n \n \n\u2003\n \n \n]\n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n47\n \n \n \n \n \n \n \n \nsuch that\n \n \n \n \n \n \nV\n \n \n \nrot\n \n\u2062\n \n_\n \n\u2062\n \ncal\n \n \n;\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062', '[\n \n \n \n \n \n \nZ\n \nxx\n \n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \nZ\n \nxy\n \n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \nZ\n \nxz\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \n \n \nZ\n \nyx\n \n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \nZ\n \nyy\n \n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \nZ\n \nyz\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n\u2062\n \n0\n \n \n \n \n \n \nZ\n \nzz\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n]\n \n \n \n \n \n \n Triaxial Transmitter and Triaxial Receiver:', 'Rotating \n \nAs described above in the previous example, the y-axis antenna gains may be matched to the x-axis antenna gains.', 'The measured data may be rotated to align the transmitter and receiver x-axis (or y-axis) directions and/or rotated to an Earth-fixed reference frame (e.g., top-of-hole or North).', 'The gains may be matched to the reference tool gains and the reference tool gains may be cancelled by dividing the measurements by the reference tool air calibration values.', 'In describing the process, the G\nTxy_ratio \nand G\nRxy_ratio \nmatrices may be applied as described above for the non-rotating example.', 'Applying these ratios to the measured voltage harmonics replaces the y-axis transmitter and y-axis receiver gains with the x-axis transmitter and x-axis receiver gains.', 'The voltage measurements may then be rotated by rotating the harmonic voltage coefficients, for example, as follows:\n \n \n \n \n \n \n \n \n \n \nV\n \nDC_rot\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nG\n \nTxy_ratio\n \n \n\u2062\n \n \nV\n \nDC', '\u2062\n \n \nG\n \nRxy_ratio\n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nG\n \n \nTxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nFHC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nR\n \n90\n \n \n\u2062\n \n \nG\n \n \nTxy\n \n\u2062\n \n_\n \n\u2062\n \nrati\n \n\u2062\n \no\n \n \n \n\u2062\n \n \nV\n \nFHS\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n\u2062\n \n \nR\n \n90\n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nG\n \n \nTxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nSHC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nR\n \n45\n \n \n\u2062\n \n \nG\n \n \nTxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nSHS\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n\u2062\n \n \nR\n \n45\n \nt\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n48\n \n \n \n \n \n \n \n \nwherein an additional 90 degree back rotation of the first harmonic sine measurements gives a quantity that is equivalent to the rotated first harmonic cosine measurement and an additional 45-degree back rotation of the second harmonic sine measurements to give a quantity that is equivalent to the second harmonic cosine.', 'These rotated coefficients may be expressed in tensor (matrix) form, for example, as follows:\n \n \n \n \n \n \n \n \n \nV\n \nDC_rot\n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n\u2003\n \n \n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)', '2\n \n \n \n \n \n0\n \n \n \n \n \n \n \n-\n \n \ng\n \nTx\n \n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nzz\n \n \n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nro\n \n\u2062\n \nt\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nxz\n \n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nyz\n \n \n \n \n \n \n \n \n \ng\n \n \nT\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzx\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzy\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nro\n \n\u2062\n \nt\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062', '[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nxz\n \n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nyz\n \n \n \n \n \n \n \n \n \ng\n \n \nT\n \n\u2062\n \n \n \n \n\u2062\n \nz\n \n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzx\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzy\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n\u2062\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \n-\n \n \ng\n \nTx\n \n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \n-\n \n \ng\n \nTx\n \n \n \n\u2062\n \n \ng\n \n \nR\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n\u2062\n \nx\n \n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n49', 'These quantities can be rotated from the local tool reference frame to an Earth-fixed frame if so desired, for example, as follows:\n \n \n \n \n \n \n \n \n \n \nV\n \n \n \nDC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \nEF\n \n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nR\n \nLE\n \nt\n \n \n\u2062\n \n \nV\n \n \nDC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \nR\n \nLE\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \nEF\n \n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nR\n \nLE\n \nt\n \n \n\u2062\n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \nR\n \nLE\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_', '\u2062\n \nEF\n \n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nR\n \nLE\n \nt\n \n \n\u2062\n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \nR\n \nLE\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \nEF\n \n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nR\n \nLE\n \nt\n \n \n\u2062\n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \nR\n \nLE\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \nEF\n \n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nR\n \nLE\n \nt\n \n \n\u2062\n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \nR\n \nLE\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n50\n \n \n \n \n \n \n \n \nCalibration coefficients K\nxx\n, K\nxz\n, K\nzx\n, and K\nzz \nmay be computed, for example, as described in the previous example.', 'Each rotated voltage harmonic may then be calibrated by applying the calibration coefficients, for example, as follows:\n \n \n \n \n \n \n \n \n \n \n \nV\n \n \nH\n \n\u2062\n \n_', '\u2062\n \ncal\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n \n\u2003\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n\u2003\n \n \n[\n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHxx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHxy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n·\n \n \nV\n \n \nHxz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHyz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHyy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n·\n \n \nV\n \n \nHyz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \n \n \nK\n \nzx\n \n \n·\n \n \nV\n \n \nHzx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nzx\n \n \n·\n \n \nV\n \n \nHzy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nzz\n \n \n·\n \n \nV\n \n \nHzz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n51\n \n \n \n \n \n \n \n \nsuch that the rotated and calibrated voltages can be expressed as:\n \n \n \n \n \n \n \n \n \n \n \nV\n \n \n \n \nDC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \ncal\n \n \n \n;\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n\u2003\n \n \n \n \n[\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n0\n \n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \nZ\n \nzz\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n]', '\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \ncal\n \n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n \n\u2003\n \n \n \n\u2003\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \n\u2003\n \n \n \n \n\u2062\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \nZ\n \nxz\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \nZ\n \nyz\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n0\n \n \n \n \n\u2062\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \ncal\n \n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \nZ\n \nxz\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \nZ\n \nyz\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \nZ\n \nTxRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTzRzair\n \n \n \n \n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \ncal\n \n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n\u2003\n \n \n \n \n[\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n0\n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n\u2062\n \n \n_\n \n\u2062\n \ncal\n \n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n\u2003\n \n \n[\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n0\n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n-\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTxRxair\n \n \n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n52\n \n \n \n \n \n \n \n \nAs is evident in equation 52, a rotating electromagnetic logging tool including a triaxial transmitter and a triaxial receiver results in redundant data.', 'This redundant data may be used to improve reliability accuracy of the measurements.', 'Alternatively, a biaxial transmitter (including x- and z-axis transmitting antennas) and a triaxial receiver may be used to generate the same information, but more economically.', 'In this case the moment matrices may be expressed as follows:\n \n \n \n \n \n \nm\n \nT\n \n \n=\n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \nm\n \nR\n \n \n=\n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n1\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]', 'The rotated measured voltage harmonics can then be obtained as follows (noting that now there is no need to match the x and y transmitter channels):\n \n \n \n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \nV\n \n \nDC\n \n\u2062\n \n_', '\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nDC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nFHC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \nV\n \nFHS\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n\u2062\n \n \nR\n \n90\n \nt\n \n \n\u2062\n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nSHC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nSHS\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_', '\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n53\n \n \n \n \n \n \n \n \nUsing the same calibration procedure, the rotated and calibrated voltages may be expressed as:\n \n \n \n \n \n \n \n \n \nV\n \n \nDC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n\u2003\n \n \n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)', '2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nzz\n \n \n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nxz\n \n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n \n \ng\n \n \nT\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzx\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzy\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nyz\n \n \n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzx\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzy\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n54\n \n \n \n \n \n \n \n Tilted Transmitter and Triaxial Receiver:', 'Rotating \n \nAs described above in the preceding examples, the y-axis antenna gains may be matched to the x-axis antenna gains and the voltage measurements may be rotated to align the transmitter and receiver x-axis (or y-axis) directions and/or rotated to an Earth-fixed reference frame (e.g., top-of-hole or North).', 'The gains may be matched to the reference tool gains and the reference tool gains may be cancelled by dividing the measurements by the reference tool air calibration values.', 'In describing the process, the G\nRxy_ratio \nmatrices may be applied as described for the non-rotating and rotating examples above.', 'Applying these ratios to the measured voltage harmonics replaces the y-axis transmitter and y-axis receiver gains by the x-axis transmitter and x-axis receiver gains.', 'The voltage measurements may then be rotated.', 'For the DC voltages measured between the transmitter and receiver, the measurements are back rotated by the measured alignment angle, γm, which if manufacturing variation is small, is close to the actual alignment angle α.', 'This effectively constructs a measurement that would be obtained if T\n1\n and R\n1\n were aligned.', 'For the DC voltages measured between the transmitter and receiver, the measurements are back rotated by the measured alignment angle γm which if manufacturing variation is small, is close to the actual alignment angle α.', 'This effectively constructs a measurement that would be obtained if T\n1\n and R\n1\n were aligned.', 'The rotated harmonic voltage coefficients are shown below:\n \n \n \n \n \n \n \n \n \n \nV\n \n \nDC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nDC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nFHC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_', '\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nFHS\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n\u2062\n \n \nR\n \n90\n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nSHC\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nV\n \nSHS\n \n \n\u2062\n \n \nG\n \n \nRxy\n \n\u2062\n \n_\n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nγ\n \n\u2062\n \nm\n \n \nt\n \n \n\u2062\n \n \nR\n \n90\n \nt\n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062', '55\n \n \n \n \n \n \n \n \nIt will be understood that a tilted transmitter may be represented mathematically as an axial antenna and a transverse antenna, each having its own gain g\nTz \nand g\nTx\n.', 'These rotated coefficients may be expressed in tensor (matrix) form, for example, as follows:\n \n \n \n \n \n \n \n \n \n \nV\n \n \nDC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)', '2\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nzz\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzx\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzy\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nzz\n \n \n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzx\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \nZ\n \nzy\n \n \n \n \n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRz\n \n \n\u2062\n \n \nZ\n \nzz\n \n \n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \nrot\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n56\n \n \n \n \n \n \n \n \nAfter rotation, the measurements are multiplied by calibration coefficients to remove all gains.', 'Calibration coefficients K\nxx\n, K\nxz\n, K\nzx\n, and K\nzz \nmay be computed, for example, as described in the previous examples.', 'The calibration coefficients are listed below for this example:\n \n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nC\n \nxxair\n \n \n\u2062\n \n \nC\n \nTxloop\n \n \n\u2062\n \n \n \nC\n \nRxloop\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n·\n \n \n \n[\n \n \n \n \nge\n \n \nT\n \n\u2062\n \n_', '\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \nge\n \n \nRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nK\n \nxx\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n \n[\n \n \n1\n \n \nZ\n \nTRxair\n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ngm\n \nRx\n \n \n\u2062\n \n \nge\n \nRx\n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ngm\n \nTx\n \n \n\u2062\n \n \nI\n \nT\n \n \n \n \n]\n \n \n \n=\n \n \n \n[\n \n \n1\n \n \nZ\n \nTrxair\n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ng\n \nRx\n \n \n\u2062\n \n \ng\n \nTx\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n57\n \n \n \n \n \n \n \n \nK\n \nzz\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \nC\n \nzzair\n \n \n\u2062\n \n \nC\n \nTzloop\n \n \n\u2062\n \n \n \n \nC\n \nRzloop\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n]\n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n \n \n[\n \n \n \n \nge\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \nge\n \n \nRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nK\n \nzz\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n1\n \n \nZ\n \nTRzair\n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ngm\n \nRz\n \n \n\u2062\n \n \nge\n \nRz\n \n \n \n \n]\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n[\n \n \n1\n \n \n \ngm\n \nTz\n \n \n\u2062\n \n \nI\n \nT\n \n \n \n \n]\n \n \n=\n \n \n \n[\n \n \n1\n \n \nZ\n \nTRzair\n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ng\n \nRz\n \n \n\u2062\n \n \ng\n \nTz\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n58\n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \nxxair\n \n \n\u2062\n \n \nC\n \nzzair\n \n \n \n \n\u2062\n \n \n \n \n \n[\n \n \n \nC\n \n \nTzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \nC\n \n \nTxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \nC\n \n \nRxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \nC\n \n \nRzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n \n \n·\n \n \n[\n \n \n \nC\n \nTxloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n \n \n \n[\n \n \n \nC\n \nRzloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \nge\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n \nge\n \n \nRz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nK\n \nxz\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ngm\n \nTx\n \n \n\u2062\n \n \nI\n \nT\n \n \n \n \n]\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n[\n \n \n1\n \n \n \ngm\n \nRz\n \n \n\u2062\n \n \nge\n \nRz\n \n \n \n \n]\n \n \n=\n \n \n \n[\n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n]\n \n \n]\n \n \n\u2062\n \n \n\u2003\n \n \n \n[\n \n \n1\n \n \n \ng\n \nTx\n \n \n\u2062\n \n \ng\n \nRz\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \nZ\n \nLxRx\n \n \n \nZ\n \nLxT\n \n \n \n \n\u2062\n \n \n \n \nZ\n \nLzRz\n \n \n \nZ\n \nLzT\n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n59\n \n \n \n \n \n \n \n \nK\n \nzx\n \n \n\u2062\n \n \n=\n \ndef\n \n \n\u2062\n \n \n \n \n \nC\n \nxxair\n \n \n\u2062\n \n \nC\n \nzzair\n \n \n \n \n\u2062\n \n \n \n \n \n[\n \n \n \nC\n \n \nTzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \nC\n \n \nTxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \nC\n \n \nRxloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \nC\n \n \nRzloop\n \n\u2062\n \n_\n \n\u2062\n \nref\n \n \n \n \n]\n \n \n \n \n·\n \n \n[\n \n \n \nC\n \nTxloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nTz\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n \n \n \n[\n \n \n \nC\n \nRxloop\n \n \n \n(\n \n \n1\n \n+\n \n \n \nf\n \nRx\n \n \n\u2061\n \n \n(\n \n \nT\n \nmeas\n \n \n)\n \n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \nge\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n\u2062\n \nRn\n \n \n \nI\n \n \nT\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n \nge\n \n \nRx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nK\n \nzx\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ngm\n \nTx\n \n \n\u2062\n \n \nI\n \nT\n \n \n \n \n]\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n[\n \n \n1\n \n \n \ngm\n \nRx\n \n \n\u2062\n \n \nge\n \nRx\n \n \n \n \n]\n \n \n=\n \n \n \n[\n \n \n[\n \n \n1\n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n]\n \n \n]\n \n \n\u2061\n \n \n[\n \n \n1\n \n \n \ng\n \nTz\n \n \n\u2062\n \n \ng\n \nRx\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n60\n \n \n \n \n \n \n \n \nEach rotated voltage harmonic may then be calibrated by applying the calibration coefficients, for example, as follows:\n \n \n \n \n \n \nV\n \n \nH\n \n\u2062\n \n_', '\u2062\n \ncal\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHxx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHxy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n·\n \n \nV\n \n \nHxz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHyx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxx\n \n \n·\n \n \nV\n \n \nHyy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n·\n \n \nV\n \n \n \n \n \n\u2062\n \n \nH\n \n\u2062\n \nyz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \n \n \n \nK\n \nxz\n \n \n·\n \n \nV\n \n \nHzx\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nzx\n \n \n·\n \n \nV\n \n \nHzy\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n \nK\n \nzz\n \n \n·\n \n \nV\n \n \nHzz\n \n\u2062\n \n_\n \n\u2062\n \nmeas\n \n \n \n \n \n \n \n]\n \n \n \n \n \n \nsuch that the rotated and calibrated voltages can be expressed as:\n \n \n \n \n \n\u2003\n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \nV\n \n \nDC\n \n\u2062\n \n_\n \n\u2062\n \ncal\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062', '[\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n+\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTRxair\n \n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n-\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTRxair\n \n \n \n \n \n \n \n \nZ\n \nzz\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHC\n \n\u2062\n \n_\n \n\u2062\n \ncal\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n \n \n \n \n \nZ\n \nxz\n \n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n]\n \n \n \n \n \n\u2062\n \n \n\u2003\n \n \n \n \n \n\u2062\n \n \n \nV\n \n \nFHS\n \n\u2062\n \n_\n \n\u2062\n \ncal\n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n[\n \n \n \n \n\u2062\n \n \n \n \n \n \n \n \nZ\n \nzx\n \n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n \n \n \n \nZ\n \nzy\n \n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n \n \n \n \n \nZ\n \nyz\n \n \n \n \n \nZ\n \nTRxair\n \n \n \n\u2062\n \n \n \nZ\n \nTRzair\n \n \n \n \n \n]\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \nSHC\n \n\u2062\n \n_\n \n\u2062\n \ncal\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062', '[\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTRxair\n \n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTRxair\n \n \n \n \n \n \n0\n \n \n \n \n]\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nV\n \n \nSHS\n \n\u2062\n \n_\n \n\u2062\n \ncal\n \n \n \n \n\u2062\n \n \n=\n \nm\n \n \n\u2062\n \n \n[\n \n \n \n \n \n \n(\n \n \n \nZ\n \nxx\n \n \n-\n \n \nZ\n \nyy\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTRxair\n \n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nxy\n \n \n+\n \n \nZ\n \nyx\n \n \n \n)\n \n \n \n2\n \n\u2062\n \n \nZ\n \nTRxair\n \n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nEQUATION\n \n\u2062\n \n \n \n \n\u2062\n \n61\n \n \n \n \n \n \n \n \n \nIt will be understood that the above description (and mathematical derivation) is for an electromagnetic tool configuration that makes use of a tilted transmitter and a triaxial receiver.', 'It will be further understood that based on the principle of reciprocity, that the above treatment applies equally to an electromagnetic tool configuration that makes use of a triaxial transmitter and tilted receiver.', 'It will be still further understood that while the above examples make use of distinct x and z calibration loops, that the disclosed embodiments may also employ a tilted test loop with a known tilt angle and perform a similar or identical calibration.', 'The disclosed embodiments are explicitly not limited to use of distinct x and z test loops.', 'The gain compensated electromagnetic measurements may be processed (e.g., via inversion modeling) to determine various electromagnetic and physical properties of a subterranean formation.', 'These properties may be further evaluated to guide (steer) subsequent drilling of the wellbore, for example, during a pay-zone steering operation in which it is desirable to maintain the wellbore within a particular formation layer (i.e., the pay-zone).', 'It will be understood that the various steps in the disclosed calibration methodology may be implemented on a on a downhole processor (controller).', 'By downhole processor it is meant an electronic processor (e.g., a microprocessor or digital controller) deployed in the drill string (e.g., in the electromagnetic logging tool or elsewhere in the BHA).', 'In such embodiments, the above described calibration coefficients and calibration factors may be stored in downhole memory and may then be applied to the electromagnetic measurements by the downhole processor to compute the calibrated measurements.', 'Such calibrated measurements may further be stored in downhole memory and/or transmitted to the surface while drilling via known telemetry techniques (e.g., mud pulse telemetry or wired drill pipe).', 'Whether stored in memory or transmitted to the surface, the calibrated electromagnetic measurements may be utilized in an inversion process (along with a formation model) to obtain various parameters of the subterranean formation.', 'The calibrated measurements may also be used in a geosteering operation to guide subsequent drilling of the wellbore.', 'Calibration of an electromagnetic logging tool (or a portion of the calibration), may be implemented on virtually any type of computer regardless of the platform being used.', 'For example, as shown in \nFIG.', '14\n, a computer system \n300\n includes one or more processor(s) \n302\n, associated memory \n304\n (e.g., random access memory (RAM), cache memory, flash memory, etc.), a storage device \n306\n (e.g., a hard disk, an optical drive such as a compact disk drive or digital video disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities typical of modern computers (not shown).', 'The computer system \n300\n may also include input means, such as a keyboard \n308\n, a mouse \n310\n, or a microphone (not shown).', 'Further, the computer system \n300\n may include output means, such as a monitor \n312\n (e.g., a liquid crystal display (LCD), a plasma display, or cathode ray tube (CRT) monitor) or printer (not shown).', 'The computer system \n300\n may be connected to a network \n314\n (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, or any other similar type of network) with wired and/or wireless segments via a network interface connection (not shown).', 'Those skilled in the art will appreciate that many different types of computer systems exist, and the aforementioned input and output means may take other forms.', 'Generally speaking, the computer system \n300\n includes at least the minimal processing, input, and/or output means necessary to practice one or more of the disclosed embodiments.', 'Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer system \n300\n may be located at a remote location and connected to the other elements over a network.', 'For example, the computer system may be coupled to a downhole processor deployed in an electromagnetic logging tool via a telemetry channel such as a mud pulse telemetry channel or wired drill pipe.', 'Further, one or more embodiments may be implemented on a distributed system having a plurality of nodes, where each portion may be located on a different node within the distributed system.', 'In one or more embodiments, the node corresponds to a computer system.', 'Alternatively, the node may correspond to a processor with associated physical memory.', 'The node may alternatively correspond to a processor with shared memory and/or resources.', 'Further, software instructions for performing one or more embodiments of reservoir engineering may be stored on a computer readable medium such as a compact disc (CD), a diskette, a tape, or any other computer readable storage device.', 'The computer system may be configured to compute the various calibration factors, coefficients, and quantities described above, for example, with respect \nFIGS.', '4-7, 10, and 12\n.', 'For example, the computer system may include instructions to receive voltage and current measurements from corresponding receiving antennas, transmitting antennas, test loop antennas, and their corresponding electronics.', 'The computer system may further include instructions to receive electromagnetic measurements from downhole tool memory (e.g., after retrieving the tool from the wellbore).', 'The computer system may further include instructions to compute the functions that describe changes in effective area of a transmitter and/or receiver antenna with temperature and/or pressure.', 'The computer system may further include instructions to compute calibration factors for the reference tool receiver and transmitter, for example, as recited in Equations 25 and 28, air calibration coefficients for the reference tool, for example, as recited in Equation 30, calibration coefficients for the electromagnetic logging tool receivers and transmitters, for example, as recited in Equations 32 and 33, and calibration coefficients for the electromagnetic logging measurements as recited, for example, in Equations 39, 41, 44, and 45.', 'The computer system may include further instructions to process these calibration quantities in combination with electromagnetic measurements (e.g., received from downhole tool memory) to compute the calibrated measurements.', 'Moreover, the calibration quantities may be processed in combination with downhole temperature and/or pressure measurements and the electromagnetic logging measurements to compute gain calibrated measurements as described above.', 'As also described above, the computed calibration factors, coefficients, and quantities may be stored in downhole memory and may then be applied to the electromagnetic measurements using a downhole processor (e.g., a processor deployed in the electromagnetic logging tool) to compute the calibrated measurements.', 'For example, calibration quantities K\nxx\n, K\nzz\n, K\nxz\n, and/or K\nzx \nmay be computed using computer system \n300\n and stored in downhole memory.', 'A mathematical function describing changes in effective area of a transmitter and/or receiver antenna with temperature and/or pressure may also be stored in downhole memory.', 'In such embodiments, the downhole processor may be configured to process downhole temperature and/or pressure measurements in combination with the calibration quantities stored in memory to compute temperature and/or pressure corrected quantities.', 'The downhole processor may be further configured to multiply selected electromagnetic logging measurements by the corrected quantities and/or by the original calibration quantities to compute the gain calibrated electromagnetic logging measurements downhole.', 'Although methods for gain calibrating electromagnetic measurements have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.'] | ['1.', 'A method for gain calibrating an electromagnetic measurement tool, the method comprising:\n(a) providing (i) an electromagnetic measurement tool including a transmitter and a receiver and a (ii) a reference tool including a reference transmitter and a reference receiver;\n(b) determining calibration standards for the reference tool;\n(c) measuring a first calibration factor to match the receiver on the electromagnetic measurement tool to the reference receiver on the reference tool;\n(d) measuring a second calibration factor to match the transmitter on the electromagnetic measurement tool to the reference transmitter on the reference tool;\n(e) deploying the electromagnetic measurement tool in a subterranean wellbore;\n(f) causing the electromagnetic measurement tool to make electromagnetic measurements while deployed in the subterranean wellbore; and\n(g) applying the first and second calibration factors measured in (c) and (d) and a calibration standard determined in (b) to at least one of the electromagnetic measurements made in (f) to compute a gain calibrated electromagnetic measurement.', '2.', 'The method of claim 1, wherein the electromagnetic measurement tool transmitter is deployed on a first sub and the electromagnetic measurement tool receiver is deployed on a second sub that is different from the first sub.', '3.', 'The method of claim 1, wherein the calibration standards include temperature calibration equations that relate a change in an effective turn area of the transmitter and the receiver to a measured downhole temperature.', '4.', 'The method of claim 1, wherein the calibration standards include temperature calibration equations that relate changes in effective turn areas of the transmitter and the receiver to a measured downhole temperature and a change in effective turn areas of the reference transmitter and reference receiver to a measured surface temperature.', '5.', 'The method of claim 1, wherein the calibration standards are determined in (b) via:\n(i) deploying a test loop on the reference receiver and electromagnetically coupling the test loop and the reference receiver to obtain a calibration factor for the reference receiver;\n(ii) deploying a test loop on the reference transmitter and electromagnetically coupling the test loop and the reference transmitter to obtain a calibration factor for the reference transmitter; and\n(iii) conducting an air hang test with the reference tool wherein the reference transmitter and the reference receiver are electromagnetically coupled to obtain an air calibration coefficient.', '6.', 'The method of claim 5, wherein:\nthe first calibration factor is measured by deploying a test loop on the receiver, electromagnetically coupling the test loop and the receiver, and combining a voltage on either the test loop or the receiver with the calibration factor for the reference receiver; and\nthe second calibration factor is measured by deploying a test loop on the transmitter, electromagnetically coupling the test loop and the transmitter, and combining a voltage on either the test loop or the transmitter with the calibration factor for the reference transmitter.', '7.', 'The method of claim 6, wherein applying the first and second calibration factors and the calibration standard in (g) comprises:\ncombining the air calibration coefficient, the first calibration factor, and the second calibration factor to compute a calibration quantity for the electromagnetic measurement tool; and\nmultiplying at least one of the electromagnetic measurements made in (f) by the calibration quantity to compute a gain calibrated electromagnetic measurement.', '8.', 'The method of claim 1, wherein the transmitter comprises a triaxial transmitter or a tilted transmitter and the receiver comprises a triaxial receiver.', '9.', 'The method of claim 1, wherein:\nthe transmitter includes a transverse transmitting antenna and an axial transmitting antenna and the receiver includes a transverse receiving antenna and an axial receiving antenna;\nthe first calibration factor includes a first transverse calibration factor for the transverse receiving antenna and a first axial calibration factor for the axial receiving antenna; and\nthe second calibration factor includes a second transverse calibration factor for the transverse transmitting antenna and a second axial calibration factor for the transmitting axial transmitting antenna.', '10.', 'The method of claim 9, wherein the reference transmitter includes a transverse reference transmitting antenna and an axial reference transmitting antenna and the reference receiver includes a transverse reference receiving antenna and an axial reference receiving antenna and wherein the calibration standards are determined in (b) via:\n(i) deploying a transverse test loop on the transverse reference receiving antenna and electromagnetically coupling the transverse test loop and the transverse reference receiving antenna to obtain a calibration factor for the transverse reference receiving antenna;\n(ii) deploying an axial test loop on the axial reference receiving antenna and electromagnetically coupling the axial test loop and the axial reference receiving antenna to obtain a calibration factor for the axial reference receiving antenna;\n(iii) deploying a transverse test loop on the transverse reference transmitting antenna and electromagnetically coupling the transverse test loop and the transverse reference transmitting antenna to obtain a calibration factor for the transverse reference transmitting antenna;\n(iv) deploying an axial test loop on the axial reference transmitting antenna and electromagnetically coupling the axial test loop and the axial reference transmitting antenna to obtain a calibration factor for the axial reference transmitting antenna; and\n(v) conducting an air hang test with the reference tool wherein the transverse reference transmitting antenna and the transverse reference receiving antenna are electromagnetically coupled and wherein the axial reference transmitting antenna and the axial reference receiving antenna are electromagnetically coupled to obtain corresponding transverse and axial an air calibration coefficients.', '11.', 'The method of claim 10, wherein:\nthe first transverse calibration factor is measured by deploying a transverse test loop on the transverse receiving antenna, electromagnetically coupling the transverse test loop and the transverse receiving antenna; and combining a voltage on either the transverse test loop or the transverse receiving antenna with the calibration factor for the transverse reference receiving antenna;\nthe first axial calibration factor is measured by deploying an axial test loop on the axial receiving antenna, electromagnetically coupling the axial test loop and the axial receiving antenna; and combining a voltage on either the axial test loop or the axial receiving antenna with the calibration factor for the axial reference receiving antenna;\nthe first transverse calibration factor is measured by deploying a transverse test loop on the transverse transmitting antenna, electromagnetically coupling the transverse test loop and the transverse transmitting antenna; and combining a voltage on either the transverse test loop or the transverse transmitting antenna with the calibration factor for the transverse reference transmitting antenna; and\nthe first axial calibration factor is measured by deploying an axial test loop on the axial transmitting antenna, electromagnetically coupling the axial test loop and the axial transmitting antenna; and combining a voltage on either the axial test loop or the axial transmitting antenna with the calibration factor for the axial reference transmitting antenna.', '12.', 'The method of claim 11, wherein applying the first and second calibration factors in (g) comprises:\ncombining the transverse air calibration coefficient, the first transverse calibration factor, and the second transverse calibration factor to compute a transverse calibration quantity for the electromagnetic measurement tool;\ncombining the axial air calibration coefficient, the first axial calibration factor, and the second axial calibration factor to compute an axial calibration quantity for the electromagnetic measurement tool;\nmultiplying at least one of the electromagnetic measurements made in (f) by the transverse calibration quantity to compute a gain calibrated electromagnetic measurement; and\nmultiplying at least one other of the electromagnetic measurements made in (f) by the axial calibration quantity to compute another gain calibrated electromagnetic measurement.', '13.', 'A method for calibrating an electromagnetic measurement tool, the method comprising:\n(a) providing (i) a deep reading electromagnetic measurement tool including a transmitter deployed on a transmitter sub and a receiver deployed on a receiver sub and (ii) a reference tool including a reference transmitter and a reference receiver;\n(b) deploying a test loop on the reference receiver and electromagnetically coupling the test loop and the reference receiver to obtain a calibration factor for the reference receiver;\n(c) deploying a test loop on the reference transmitter and electromagnetically coupling the test loop and the reference transmitter to obtain a calibration factor for the reference transmitter;\n(d) conducting an air hang test with the reference tool wherein the reference transmitter and the reference receiver are electromagnetically coupled in a known conductivity environment to obtain an air calibration coefficient;\n(e) measuring a first calibration factor to match the receiver on the electromagnetic measurement tool to the reference receiver on the reference tool by deploying a test loop on the receiver, electromagnetically coupling the test loop and the receiver, and combining a voltage on either the test loop or the receiver with the calibration factor obtained in (b);\n(f) measuring a second calibration factor to match the transmitter on the electromagnetic measurement tool to the reference transmitter on the reference tool by deploying a test loop on the transmitter, electromagnetically coupling the test loop and the transmitter, and combining a voltage on either the test loop or the transmitter with the calibration factor obtained in (c);\n(g) combining the air calibration coefficient obtained in (d), the first calibration factor measured in (e), and the second calibration factor measured in (f) to compute a calibration quantity for the electromagnetic measurement tool; and\n(h) deploying the electromagnetic measurement tool in a subterranean wellbore;\n(i) causing the electromagnetic measurement tool to make electromagnetic measurements while deployed in the subterranean wellbore; and\n(j) multiplying at least one of the electromagnetic measurements made in (i) by the calibration quantity computed in (g) to compute a gain calibrated electromagnetic measurement.\n\n\n\n\n\n\n14.', 'The method of claim 13, wherein:\n(e) and (f) further comprise measuring a surface temperature and computing temperature corrected first and second calibration factors based on the surface temperature; and\n(j) further comprises measuring a downhole temperature, computing a temperature corrected calibration quantity based on the downhole temperature, and multiplying the electromagnetic measurement by the temperature corrected calibration quantity.', '15.', 'The method of claim 13, wherein the transmitter includes a transverse transmitting antenna and an axial transmitting antenna, the receiver includes a transverse receiving antenna and an axial receiving antenna, the reference transmitter includes a transverse reference transmitting antenna and an axial reference transmitting antenna, and the reference receiver includes a transverse reference receiving antenna and an axial reference receiving antenna and wherein:\n(g) comprises combining the air calibration coefficient, the first calibration factor, and the second calibration factor obtained using the transverse transmitting antenna, the transverse receiving antenna, the transverse reference transmitting antenna, and the transverse reference receiving antenna in (b), (c), (d), (e), and (f) to compute a transverse calibration quantity;\n(g) further comprises combining the air calibration coefficient, the first calibration factor, and the second calibration factor obtained using the axial transmitting antenna, the axial receiving antenna, the axial reference transmitting antenna, and the axial reference receiving antenna in (b), (c), (d), (e), and (f) to compute an axial calibration quantity; and\n(j) comprises multiplying at least one of the electromagnetic measurements made in (i) by the transverse calibration quantity to compute a gain calibrated electromagnetic measurement and multiplying at least one other of the electromagnetic measurements made in (i) by the axial calibration quantity to compute another gain calibrated electromagnetic measurement.', '16.', 'One or more non-transitory computer-readable storage media comprising computer-executable instructions which upon execution by a computing device perform a method to:\ndetermine calibration standards for a reference tool including a reference transmitter and a reference receiver;\ncompute a first calibration factor to match a receiver on an electromagnetic measurement tool to the reference receiver on the reference tool;\ncompute a second calibration factor to match a transmitter on the electromagnetic measurement tool to the reference transmitter on the reference tool; and\nreceive electromagnetic measurements made by the electromagnetic measurement tool while deployed in a subterranean wellbore; and\napply the first and second computed calibration factors and at least one of the determined calibration standards to at least one of the electromagnetic measurements to compute a gain calibrated electromagnetic measurement.', '17.', 'The one or more non-transitory computer readable storage media of claim 16, wherein the calibration standards are determined via:\ncomputing a calibration factor for the reference receiver based upon an electromagnetic coupling between a test loop deployed on the reference receiver and the reference receiver;\ncomputing a calibration factor for the reference transmitter based upon an electromagnetic coupling between a test loop deployed on the reference transmitter and the reference transmitter; and\ncomputing an air calibration coefficient based on an electromagnetic coupling in air between the reference transmitter and the reference receiver.', '18.', 'The one or more non-transitory computer readable storage media of claim 17, wherein the instructions to compute the first calibration factor and the second calibration factor comprise instructions to:\ncompute the first calibration factor by combining: (i) a voltage received from an electromagnetic coupling between a test loop and the receiver with (ii) the calibration factor for the reference receiver; and\ncompute the second calibration factor by combining: (iii) a voltage received from an electromagnetic coupling between a test loop and the transmitter with (iv) the calibration factor for the reference transmitter.', '19.', 'The one or more non-transitory computer readable storage media of claim 18, wherein the instructions to apply the first and second computed calibration factors and at least one of the determined calibration standards comprises comprise instructions to:\ncombine the air calibration coefficient, the first calibration factor, and the second calibration factor to compute a calibration quantity for the electromagnetic measurement tool; and\nmultiply the at least one electromagnetic measurement by the calibration quantity to compute the gain calibrated electromagnetic measurement.', '20.', 'The one or more non-transitory computer readable storage media of claim 19, further comprising instructions to:\nreceive a surface temperature measurement and compute temperature corrected first and second calibration factors based on the surface temperature measurement; and\nreceive a downhole temperature measurement, compute a temperature corrected calibration quantity based on the downhole temperature measurement, and multiply the at least one electromagnetic measurement by the temperature corrected calibration quantity to compute the gain calibrated electromagnetic measurement.'] | ['FIG.', '1 depicts an example drilling rig on which disclosed embodiments may be utilized.; FIG.', '2 depicts one example of a deep reading electromagnetic logging tool including first and second transmitter and receiver subs.; FIG.', '3 schematically depicts a deep reading electromagnetic logging tool including collocated triaxial transmitters and receivers.; FIG.', '4 depicts a flow chart of one disclosed method embodiment.; FIG.', '5 depicts a flow chart of one disclosed embodiment providing further detail of element 105 in the flow chart depicted on FIG.', '4.; FIG.', '6 depicts a flow chart of one disclosed embodiment providing further detail of element 110 in the flow chart depicted on FIG.', '5.; FIG. 7 depicts a flow chart of one disclosed embodiment providing further detail of element 120 in the flow chart depicted on FIG.', '5.; FIGS.', '8A and 8B depict example calibration loops deployed on axial (8A) and transverse (8B) reference receivers.; FIG.', '9 depicts an example receiver electronics calibration circuit.; FIG.', '10 depicts a flow chart of one disclosed embodiment providing further detail of element 130 in the flow chart depicted on FIG.', '5.; FIG.', '11 depicts an example transmitter electronics calibration circuit.; FIG.', '12 depicts a flow chart of one disclosed embodiment providing further detail of element 140 in the flow chart depicted on FIG.', '5.; FIG. 13 depicts one example of a reference air calibration setup including a reference transmitter and a reference receiver.; FIG.', '14 depicts an example of a computer system.; FIG.', '1 depicts an example drilling rig 10 suitable for employing various method embodiments disclosed herein.', 'A semisubmersible drilling platform 12 is positioned over an oil or gas formation (not shown) disposed below the sea floor 16.', 'A subsea conduit 18 extends from deck 20 of platform 12 to a wellhead installation 22.', 'The platform may include a derrick and a hoisting apparatus for raising and lowering a drill string 30, which, as shown, extends into borehole 40 and includes a drill bit 32 deployed at the lower end of a bottom hole assembly (BHA) that further includes a deep reading electromagnetic measurement tool including distinct transmitter 50 and receiver 60 subs configured to make tri-axial electromagnetic logging measurements.; FIG.', '2 depicts one example embodiment of the electromagnetic measurement tool shown on FIG. 1 (including transmitter and receiver subs 50 and 60).', 'In the depicted embodiment, the transmitter sub (or tool) 50 includes an electromagnetic transmitter 52 deployed on a transmitter collar 51.', 'The receiver sub (or tool) 60 includes an electromagnetic receiver 62 deployed on a receiver collar 61.', 'When deployed in a drill string (e.g., drill string 30 on FIG.', '1), the transmitter and receiver subs 50 and 60 may be axially spaced apart substantially any suitable distance to achieve a desired measurement depth (e.g., in a range from about 20 to about 100 or 200 feet or more depending on the measurement objectives).', 'While not shown, one or more other BHA tools may be deployed between subs 50 and 60.', 'As described in more detail below the transmitter 52 and receiver 62 may each include three tri-axial antennas (e.g., an axial antenna and first and second transverse antennas that are orthogonal to one another in this particular embodiment).', 'As is known to those of ordinary skill in the art, an axial antenna is one whose moment is substantially parallel with the longitudinal axis of the tool.', 'Axial antennas are commonly wound about the circumference of the logging tool such that the plane of the antenna is substantially orthogonal to the tool axis.', 'A transverse antenna is one whose moment is substantially perpendicular to the longitudinal axis of the tool.', 'A transverse antenna may include, for example, a saddle coil (e.g., as disclosed in U.S. Patent Publications 2011/0074427 and 2011/0238312 each of which is incorporated by reference herein).', '; FIG.', '3 depicts the antenna moments for an example transmitter 52 and receiver 62.', 'The transmitter 52 includes three collocated tri-axial antennas having mutually orthogonal moments T1x, T1y, and T1z aligned with the x-, y-, and z-directions.', 'Receiver 62 also includes three collocated tri-axial antennas having mutually orthogonal moments R1x, R1y, and R1z.', 'In the depicted embodiment in which there is no bending of the drill string (or BHA), moment R1z is aligned with T1z (and the z-azis) while moments R1x and R1y are rotationally offset from T1x and T1y by an arbitrary offset angle γ.', 'As depicted, the receiver sub 60 is rotationally offset (about the axis of the drill string, the z-axis) with respect to transmitter sub 50 the arbitrary misalignment angle γ.', 'It will also be understood that the misalignment angle γ is the result of a rotational misalignment between subs 50 and 60 during make-up of the drill string and that the misalignment angle γ may therefore have substantially any value.; FIG.', '4 depicts a flow chart of one disclosed method embodiment 100.', 'Calibration standards are determined for a reference tool including a reference transmitter and a reference receiver at 105.', 'A first calibration factor is measured to match a first tool receiver (i.e., the receiver of a tool to be calibrated) with the reference tool receiver at 150.', 'A second calibration factor is measured to match a transmitter of the first tool (the transmitter of a tool to be calibrated) with a reference tool transmitter at 160.', 'The calibration factors are then applied to the measurements made by the first tool during (or after) a logging operation at 170 to compute calibrated logging measurements.', 'Example embodiments of each of these processes are described in more detail below for both tilted and triaxial antenna arrangements.', 'The method above may be extended to axial and transverse antenna arrangements.; FIG.', '5 depicts a flow chart of one disclosed embodiment providing further detail regarding element 105 of method 100 depicted on FIG.', '4.', 'At 110 temperature and pressure variation models are determined for transmitter and receiver moments.', 'These models include calibration equations that relate a change in an effective turn area of the transmitter and/or receiver antennas to temperature and/or pressure (e.g., the downhole temperature and pressure).', 'A ratio of a reference receiver tool voltage to a reference loop transmitter current is measured to establish a receiver calibration transfer standard at 120.', 'A ratio of a reference loop receiver voltage to a reference transmitter tool current is measured to establish a transmitter calibration transfer standard at 130.', 'And at 140 a ratio of a reference tool assembly receiver voltage to transmitter current is measured to establish a reference air calibration ratio.; FIG.', '6 depicts a flow chart of one disclosed embodiment providing further detail of element 110 in the flow chart depicted on FIG.', '5.', 'At 111 an environmentally stable transmitter is deployed around a tool receiver antenna in a repeatable position with respect to the tool receiver antenna.', 'The combined assembly (the deployment described in 111) is then deployed in an environmental chamber at 112.', 'Changes in the mutual impedance (or the electromagnetic coupling) between the environmentally stable transmitter and the tool receiver are measured and recorded at 113 at various environmental conditions (e.g., over a range of temperatures observed in downhole logging operations).', 'At 114, steps 111, 112, and 113 may then repeated for a number of tool receiver antennas (e.g., for each of the individual antennas in a triaxial receiver).', 'The acquired data may then be fit to an appropriate function at 115 that models the change in tool receiver effective turn area as a function of temperature.; FIG.', '7 depicts a flow chart of one disclosed embodiment providing further detail of element 120 in the flow chart depicted on FIG.', '5.', 'A reference tool including a reference receiver is provided.', 'At 121 a reference transmitter loop assembly is deployed in a known repeatable position about one of the receiving antennas on the reference tool receiver.', 'The combined assembly (the deployment described in 121) is then deployed in a controlled repeatable environment (such as a lab or an environmental chamber or some other controlled environment) at 122.', 'The reference loop transmitter assembly is energized at 123 to establish an electromagnetic coupling with the reference tool receiver and the reference loop transmitter current is measured at 124.', 'The gain of the transmitter electronics used to measure the reference loop transmitter current in 124 is calibrated in 125 and the reference tool receiver gain is calibrated in 126.', 'A ratio of an electronically calibrated reference receiver voltage to an electronically calibrated reference loop transmitter current is computed in 127.', 'A temperature correction is applied to the computed ratio in 128.; FIGS.', '8A and 8B depict example calibration loops 72 and 74 deployed on axial (8A) 76 and transverse (8B) 78 reference receivers.', 'It has been observed (via both modeling and experimental testing) that the direct coupling between the test loop and the reference receiver antenna tends to be insensitive to the loop geometry and placement/orientation.', 'The sensitivity to small variations in the calibration loop 72, 74 orientation on the corresponding receiver 76, 78 may be of a second order when the loop moment vector is nearly aligned with the antenna moment vector (i.e., such that an axial test loop is deployed on an axial reference receiver and a transverse test loop is deployed on a transverse reference receiver).', 'For a large test loop (such as depicted on FIGS.', '8A and 8B), the coupling error can be much less than 0.01 dB for a 0.2-degree error in the relative orientation of the test loop and the receiver antenna.', 'Notwithstanding, for certain applications, sufficient sensitivity remains that that it may be desirable to control the conductivity of the environment at least a few feet around the setup.; FIG.', '10 depicts a flow chart of one disclosed embodiment providing further detail of element 130 in the flow chart depicted on FIG.', '5.', 'A reference tool including a reference transmitter is provided.', 'At 131 a reference receiver loop assembly is deployed in a known repeatable position about one of the transmitting antennas on the reference tool transmitter.', 'The combined assembly (the deployment described in 131) is then deployed in a controlled repeatable environment (such as a lab or an environmental chamber or some other controlled environment) at 132.', 'The reference tool transmitter is energized at 133 to establish an electromagnetic coupling with the reference loop receiver and the corresponding reference loop receiver voltage is measured at 134.', 'The gain of the electronics used to measure the reference loop receiver current in 134 is calibrated in 135 and the reference tool transmitter gain is calibrated in 136.', 'A ratio of an electronically calibrated reference loop receiver voltage obtained in 134 to an electronically calibrated reference tool transmitter current is computed in 137.', 'A temperature correction is applied to the computed ratio in 138.; FIG.', '11 represents an example calibration circuit 90 for use in measuring the transmitter gains a geT, geTx, and/or a geTz.', 'The circuit is similar to that depicted on FIG.', '9 for use with the reference receivers in that it includes switching in and out a known calibration signal 92.', 'Using such a calibration circuit, the measured reference transmitter electronics gains geT_meas, geTx_meas and a geTz_meas may be defined (as above with the reference receivers) as the ratio of the calibration signal measured by the receiver electronics to the known calibration signal, for example, as follows:; FIG.', '12 depicts a flow chart of one disclosed embodiment providing further detail of element 140 in the flow chart depicted on FIG.', '5.', 'At 141 a reference assembly is prepared including a reference tool transmitter assembly and a reference tool receiver assembly at know separation.', 'One example reference assembly 200 is depicted on FIG.', '13 in which the reference transmitter tool 250 includes a reference transmitter 252 and the reference receiver tool 260 includes a reference receiver 262.', 'The reference transmitter and reference receiver may be separated by substantially any suitable distance, for example, using a spacer sub 210.'] |
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US11105952 | Systems and methods for determining the presence of cement behind at least one casing using spectroscopy measurement | Jan 31, 2019 | Pascal Millot, Adil Busaidy, Jeffrey Miles, Tong Zhou, Christian Stoller, David Rose, Richard Radtke | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 10036828; July 31, 2018; Jain; 20120080588; April 5, 2012; Smith, Jr.; 20160202387; July 14, 2016; Fox; 20160273335; September 22, 2016; Quintero; 20170167243; June 15, 2017; Guo | Foreign Citations not found. | ['A presence of cement may be identified based on a downhole tool that may emit neutrons into a wellbore having at least one cement casing.', 'The neutrons may interact with the particular material via inelastic scattering, inelastic neutron reactions, capture of neutrons and/or neutron activation through one of these reactions and cause a material to emit an energy spectrum of gamma rays, and wherein the downhole tool is configured to detect an energy spectrum of the gamma rays that is specific to at least one of a plurality of elements and associated a region within the wellbore.', 'An amount of elements, such as calcium and silicon, may be determined from the gamma ray spectra that may indicate a present of cement within the wellbore.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates to evaluating cement behind at least one casing of a wellbore.', 'In particular, this disclosure relates to determining the presence of cement based on data related to the elemental composition of cement, which may reveal the presence or absence of cement even behind multiple casings.', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'A wellbore drilled into a geological formation may be targeted to produce oil and/or gas from only certain zones of the geological formation.', 'To prevent zones from interacting with one another via the wellbore and to prevent fluids from undesired zones entering the wellbore, the wellbore may be completed by placing a cylindrical casing into the wellbore and cementing the annulus between the casing and the wall of the wellbore.', 'During cementing, cement may be injected into the annulus formed between the cylindrical casing and the geological formation.', 'When the cement properly sets, fluids from one zone of the geological formation may not be able to pass through the wellbore to interact with one another.', 'This desirable condition is referred to as “zonal isolation.”', 'Yet well completions may not always go as planned.', 'For example, the cement may not set as planned and/or the quality of the cement may be less than expected.', 'In other cases, the cement may unexpectedly fail to set above a certain depth due to natural fissures in the formation.', 'Moreover, even when well completions occur as desired, it may be desirable to identify a depth of the wellbore where a “top of cement” may be found.', 'SUMMARY\n \nA summary of certain embodiments disclosed herein is set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'One embodiment of the present disclosure relates to a method for identifying cement in a wellbore in a geological formation, wherein the wellbore includes at least one casing.', 'The method includes placing a downhole tool into a cased wellbore, and the cased wellbore has been cased using a cement having an elemental composition that includes a plurality of elements.', 'The method also includes emitting neutrons using the downhole tool, wherein the neutrons interact with a particular material via inelastic scattering, inelastic neutron reactions, capture of neutrons, neutron activation, or any combination thereof, through one of these reactions and cause the particular material to emit an energy spectrum of the gamma rays.', 'Further, the method includes detecting, at a first location, a first energy spectrum of the gamma rays that is specific to at least one of the plurality of elements.', 'Even further, the method includes determining a presence of cement at the first location based at least in part on the first energy spectrum.', 'Another embodiment of the present disclosure relates to a system for identifying cement in a wellbore in a geological formation, wherein the wellbore includes at least one casing.', 'The system includes a downhole tool that may emit neutrons, wherein the neutrons interact with the particular material via inelastic scattering, inelastic neutron reactions, capture of neutrons, neutron activation, or any combination thereof, through one of these reactions and cause a material to emit an energy spectrum of gamma rays, and wherein the downhole tool may detect an energy spectrum of the gamma rays that is specific to at least one of a plurality of elements and associated a region within the wellbore.', 'The system also includes a processor.', 'Further, the system includes a memory storing instructions to be executed by the processor.', 'The instructions include receiving a first energy spectrum of the gamma rays that is specific to calcium associated with a region within the wellbore.', 'Further, the instruction include determining an amount of cement at the region based at least in part on first energy spectrum.', 'Another embodiment of the present disclosure relates to one or more tangible, non-transitory, machine-readable media having instructions.', 'The instructions cause a processor to receive data indicative of neutrons interacting with a particular material via inelastic scattering, inelastic neutron reactions, capture of neutrons and/or neutron activation through one of these reactions and cause a material to emit an energy spectrum of gamma rays.', 'The instructions also cause the processor to determine a first amount of calcium, silicon, or both based on a first energy spectrum of the gamma rays associated with a first region within a wellbore comprising at least one casing.', 'Further, the instructions cause the processor to determine a second amount of one or more elements based on a second energy spectrum of the gamma rays associated within the first region within the wellbore.', 'Further still, the instructions cause the processor to determine a presence of cement within the first region based at least in part on the first amount and the second amount.', 'Embodiments of this disclosure relate to a method for identifying cement in a wellbore in a geological formation, wherein the wellbore includes multiple casings, the method includes placing a downhole tool into the cased wellbore, wherein the cased wellbore has been cased using a cement having an elemental composition that includes a plurality of elements.', 'Then, neutrons are emitted using the downhole tool, wherein the neutrons interact with the particular material via inelastic scattering, elastic scattering or capture of neutrons and cause the material to emit an energy spectrum of the gamma rays.', 'Further, the energy spectrum of the gamma rays that is specific to at least one of the plurality of elements is detected.', 'Even further, the presence of cement based on the detected energy spectrum is determined.', 'Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:\n \nFIG.', '1\n is a schematic diagram of a system for verifying proper cement installation and/or zonal isolation of a well, in accordance with an embodiment;\n \nFIG.', '2\n shows a flow chart of a method for evaluating cement in the cased wellbore in the geological formation, in accordance with an embodiment;\n \nFIG.', '3\n is a schematic illustration of a downhole tool (e.g., a downhole neutron tool) used to obtain well-logging data relating to material behind multiple casings of the well, in accordance with an embodiment;\n \nFIG.', '4\n is a schematic illustration of a downhole tool (e.g., a downhole neutron tool) used to obtain well-logging data relating to material behind multiple casings of the well, in accordance with an embodiment;\n \nFIG.', '5\n shows well-logging data obtained from a downhole tool, in accordance with an embodiment;\n \nFIG.', '6\n is a flow chart of a process for identifying cement in a wellbore in a geological formation; and\n \nFIG.', '7\n is an additional flow chart of a process for identifying cement in a wellbore in a geological formation.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'When a well is drilled, metal casing may be installed inside the well and cement placed into the annulus between the casing and the wellbore.', 'When the cement sets, fluids from one zone of the geological formation may not be able to pass through the annulus of the wellbore to interact with another zone.', 'This desirable condition is referred to as “zonal isolation.”', 'Proper cement installation may also ensure that the well produces from targeted zones of interest.', 'To verify that the cement has been properly installed and that the cement has remained in a desired state, this disclosure teaches systems and methods for cement evaluation by analyzing well-logging data from a downhole neutron tool (e.g., downhole tool).', 'Namely, the cement may include a concentration of any suitable material—not ordinarily found in that concentration in the materials around the well—that interacts with the neutrons to produce a measurement of radiation signal (e.g., a characteristic radiation) in response.', 'Detecting the characteristic radiation signal using a downhole neutron tool thus may be used to detect the cement.', 'The term “cement” as defined herein may be defined as the cement slurry poured in the annular space between the casing and the wellbore.', 'The cement may include any suitable cement for cementing operations including hydraulic sealing, zonal isolation, structural casing support, etc.', 'A typical elemental composition of cement includes calcium and oxygen (e.g., between approximately 60 to 70%), and may possibly include silicon.', 'In some embodiments, the cement may include other elements based on the type of cement (e.g., cement with carbonates, silicates, or other metal oxides, such as iron or aluminum).', 'When bombarded by neutrons from a downhole neutron tool, the calcium, or other elements present, may emit gamma-rays through several processes such as neutron capture and inelastic neutron interactions (e.g., inelastic excitation or nuclear reactions).', 'In addition, neutron interactions with the isotopes in the cement may convert isotopes in the cement to (unstable) radioactive isotopes through a process called neutron activation.', 'The emitted gamma rays have a particular energy spectrum that indicates the presence of a particular element.', 'Thus, the characteristic gamma-ray spectrum due to calcium may indicate a presence of cement in beyond the first casing in a well.', 'Some of the elements that are present in cement may also be present in significant quantities in the wellbore environment (e.g., calcium is present in limestone).', 'Thus, in certain embodiments, it may be advantageous to detect elements in addition to or instead of calcium, based on the wellbore environment, to determine the location of the casing.', 'For example, measuring the characteristic gamma-ray spectrum due to silicon or oxygen may supplement or be performed instead of measuring the characteristic gamma-ray spectrum due to calcium.', 'The present disclosure is directed to techniques for determining the presence of cement behind one or multiple wellbore casings based on the presence and/or absence of elements, such as calcium, that are related to the cement.', 'The identification of cement behind casings is a common requirement in the oil and gas industry.', 'This is typically accomplished by lowering sensing devices (e.g., cement bond logging tools or other acoustic measurement devices) into wellbores and determining the quality and/or quantity of cement behind a first casing.', 'However, existing techniques are often unable to identify and evaluate cement behind concentric sets of casing.', 'As discussed in detail below, the present application shows techniques for determining the presence or absence of cement behind one or multiple wellbore casings based on the gamma-ray spectrum of a wellbore.', 'With this in mind, \nFIG.', '1\n schematically illustrates a system \n10\n for evaluating cement behind casing in a well.', 'In particular, \nFIG.', '1\n illustrates surface equipment \n12\n above a geological formation \n14\n.', 'In the example of \nFIG.', '1\n, a drilling operation has previously been carried out to drill a wellbore \n16\n.', 'In addition, an annular fill \n18\n (e.g., cement) has been used to seal an annulus \n20\n—the space between the wellbore \n16\n and casing joints \n22\n and collars \n24\n—with cementing operations.', 'As seen in \nFIG.', '1\n, several casing joints \n22\n (also referred to below as casing \n22\n) are coupled together by the casing collars \n24\n to stabilize the wellbore \n16\n.', 'Coupled in this way, the casing joints \n22\n may be assembled to form a casing string to a suitable length and specification for the wellbore \n16\n.', 'The casing joints \n22\n and/or collars \n24\n may be made of carbon steel, stainless steel, or other suitable materials to withstand a variety of forces, such as collapse, burst, and tensile failure, as well as chemically aggressive fluid.', 'The surface equipment \n12\n may carry out various well logging operations to detect conditions of the wellbore \n16\n.', 'The well logging operations may measure parameters of the geological formation \n14\n (e.g., resistivity or porosity) and/or the wellbore \n16\n (e.g., temperature, pressure, fluid type, or fluid flowrate).', 'Other measurements may provide well-logging data relating to cement characteristics (e.g., measurements of characteristic radiation emitted by a material in the cement of the annular fill \n18\n, such as the calcium or silicon present in the cement, in response to neutrons emitted from one or more neutron generators disposed in a downhole neutron tool) that may be used to verify the cement installation and the zonal isolation of the wellbore \n16\n.', 'One or more downhole neutron tools \n26\n may obtain some of these measurements.', 'The example of \nFIG.', '1\n shows the downhole neutron tool \n26\n being conveyed through the wellbore \n16\n by a cable \n28\n.', 'Such a cable \n28\n may be a mechanical cable, an electrical cable, or an electro-optical cable that includes a fiber line protected against the harsh environment of the wellbore \n16\n.', 'In other examples, however, the downhole neutron tool \n26\n may be conveyed using any other suitable conveyance, such as coiled tubing.', 'The downhole neutron tool \n26\n may be used to obtain measurements of radiation emitted by a material (e.g., the calcium or silicon present in the cement) in response to neutrons emitted from a neutron generator—\n52\n or a radioisotopic neutron source disposed in the tool \n26\n.', 'The downhole neutron tool \n26\n may include one or more radiation detectors \n54\n.', 'The radiation detectors \n54\n may detect neutrons that scatter and return to the downhole neutron tool \n26\n and/or gamma rays generated from neutron interactions.', 'The radiation detectors \n54\n may be placed at various distances from the neutron generator \n52\n to gather data about the neutrons and/or gamma rays at various depths of investigation (e.g., near, medium, deep) as explained further below.', 'The data gathered by the radiation detectors \n54\n may be analyzed in order to obtain a number of neutron induced inelastic or capture gamma rays or thermal neutrons due to neutron interactions with the material (e.g., elements in the cement).', 'The data may then be used to determine the amount of the material present surrounding the wellbore to subsequently determine the presence or absence of cement.', 'Still further, the data may be used to determine the thickness of the cement over the depth of the well at various depths based in part on the data (e.g., the detected radiation, number of neutron capture gamma rays, etc.).', 'The downhole neutron tool \n26\n may be deployed inside the wellbore \n16\n by the surface equipment \n12\n, which may include a vehicle \n30\n and a deploying system such as a drilling rig \n32\n.', 'Data related to the geological formation \n14\n or the wellbore \n16\n gathered by the downhole neutron tool \n26\n may be transmitted to the surface, and/or stored in the downhole neutron tool \n26\n for later processing and analysis.', 'The vehicle \n30\n may be fitted with or may communicate with a computer and software to perform data collection and analysis.', 'FIG.', '1\n also schematically illustrates a magnified view of a portion of the cased wellbore \n16\n.', 'As mentioned above, the downhole neutron tool \n26\n may obtain well-logging data relating to the presence of the cement in the annular fill \n18\n behind the casing \n22\n.', 'For instance, the downhole neutron tool \n26\n may obtain measures of well-logging data, which may be used to determine where the material behind the casing \n22\n is fully cemented or at least partly washed out.', 'When the downhole neutron tool \n26\n provides such measurements to the surface equipment \n12\n (e.g., through the cable \n28\n), the surface equipment \n12\n may pass the measurements as well-logging data \n36\n to a data processing system \n38\n that includes a processor \n40\n, memory \n42\n, storage \n44\n, and/or a display \n46\n.', 'In other examples, the well-logging data \n36\n may be processed by a similar data processing system \n38\n at any other suitable location.', 'The processor \n40\n may execute instructions stored in the memory \n42\n and/or storage \n44\n.', 'As such, the memory \n42\n and/or the storage \n44\n of the data processing system \n38\n may be any suitable article of manufacture that can store the instructions.', 'The memory \n42\n and/or the storage \n44\n may be ROM memory, random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive, to name a few examples.', 'The display \n46\n may be any suitable electronic display that can display the logs and/or other information relating to classifying the material in the annulus \n20\n behind the casing \n22\n.', 'In this way, the well-logging data \n36\n from the downhole neutron tool \n26\n may be used to determine whether cement of the annular fill \n18\n has been installed as expected.', 'In some cases, the well-logging data \n36\n may indicate that the cement of the annular fill \n18\n is present, as indicated by the presence of the expected radiation caused by neutron interactions with the cement (e.g., characteristic neutron-capture gamma rays, or “capture gamma-rays” from calcium or silicon in the cement).', 'In other cases, the well-logging data \n36\n may indicate the potential absence of cement in the annular fill \n18\n (e.g., as indicated by region \n50\n), as indicated by the absence or reduction of the expected radiation caused by neutron interactions with the cement.', 'For example, when the well-logging data \n36\n indicates that the annular fill \n18\n lacks the radiation that is expected to be detected when the cement is present, this may imply that the cement is either absent or was of the wrong type or consistency, and/or that fluid channels have formed in the cement of the annular fill \n18\n.', 'The well-logging data \n36\n may also be used to determine the thickness of the cement in the annular space.', 'For example, the thickness of the annular fill \n18\n may utilize pre-fill measurements taken via calipers or other suitable tools to measure the wellbore thickness.', 'The pre-fill measurements may then be compared to post-fill measurements after the annular space is filled with cement.', 'The pre-fill and post-fill measurements may be used to determine whether the thickness of the cement is a suitable thickness, detect abnormalities in the cement, and/or adjust the cementing operations.', 'FIG.', '2\n illustrates a flow chart \n56\n of a cement evaluation method for evaluating cement in the cased wellbore \n16\n in the geological formation \n14\n, in accordance with an embodiment.', 'The flow chart \n56\n may include positioning (block \n58\n) the downhole neutron tool \n26\n into the cased wellbore \n16\n.', 'As described above, the cased wellbore \n16\n may be cased with cement.', 'The cement may emit a characteristic gamma ray spectrum when or after having been bombarded with neutrons, which is distinct from that of the surrounding geological formation \n14\n.', 'The gamma ray spectrum may be used to determine the absence or presence of cement, as explained further below.', 'In some embodiments, the gamma ray spectrum may be used to determine the height of the annular fill, which may be referred to as a “top of cement” in the wellbore.', 'The flow chart \n56\n may include using a neutron generator \n52\n disposed in the downhole neutron tool \n26\n to emit (block \n60\n) neutrons.', 'The emitted neutrons may interact with the material and cause the material to emit a radiation (e.g., a spectrum of gamma rays associated with the material, a die-away pattern of the gamma rays or neutrons) due to high energy (inelastic, referred to as “inelastic gamma-rays”), epithermal or thermal neutron interactions.', 'For example, inelastic scattering or neutron capture gamma rays may be emitted by the material in the cement (e.g., inelastic gamma-rays, capture gamma-rays).', 'These gamma rays may be identifiable as deriving from the material in the cement, as opposed to other downhole materials.', 'For example, the material (e.g., calcium or silicon) may be less likely to be found in the geological formation \n14\n or may be found in a different concentration in the geological formation \n14\n than in the cement (e.g., the material may be found in a low enough concentration in the geological formation \n14\n to distinguish the cement from the geological formation \n14\n).', 'Moreover, since inelastic and capture response may not have the same depth of investigation, comparison of the two responses may identify the presence of cement even when the formation contains the same elements as the cement.', 'For example, the radiation from silicon, which exhibits both inelastic gamma-ray emission and neutron activation gamma-ray emission, may be used to determine the presence of gravel behind a casing in addition to using the radiation from calcium, or alone.', 'The flow chart \n56\n may include using a radiation detector \n54\n to detect (block \n62\n) well-logging data, such as the characteristic radiation associated with the material (e.g., elements present in cement, such as calcium or silicon).', 'The well-logging data may then be used to determine the type and/or amount of the material present surrounding the wellbore to subsequently determine the presence or absence of cement and/or the thickness of the cement.', 'In some embodiments, the downhole neutron tool \n26\n may include multiple radiation detectors \n54\n.', 'For example, a near detector that collects radiation of one range of depth of investigation and a far detector that collections radiation of a second range of depth of investigation.', 'The capture gamma-rays and the inelastic gamma-rays detected by the detector result in a capture spectrum and an inelastic spectrum, respectively.', 'From these spectra (e.g., the capture spectrum and the inelastic spectrum), the presence of an element (e.g., calcium) may be determined.', 'Moreover, a quantitative amount of the element(s) may be inferred based on the gamma-rays detected by the detector.', 'The cement volume may be inferred from the spectral yields directly, including from the capture or inelastic yields individually, or via a combination of the two spectra.', 'The cement may also contain other elements, for example silicon, whose yields or weight concentrations can be used for cement evaluation.', 'In some embodiments, the flow chart \n56\n may be performed in a quantitative fashion, converting the yields or concentrations into a volume of cement through the use of an algorithm.', 'In addition to the elemental measurements, such an algorithm may require inputs for various environmental properties from a list that includes but is not limited to casing size, casing weight, bit size, borehole diameter, borehole fluid type or density, and expected properties of the cement including composition and density.', 'In other embodiments, the flow chart \n56\n may be performed in a qualitative fashion, with the goal of flagging a significant deficit of cement volume or finding a top-of-cement depth.\n \nFIG.', '3\n is a schematic illustration of the downhole neutron tool \n26\n used to obtain well-logging data relating to material behind casing \n22\n of the well, in accordance with an embodiment.', 'Specifically, a neutron source (e.g., the neutron generator \n52\n) in the downhole neutron tool \n26\n may emit neutrons out toward the casing \n22\n.', 'The neutrons may be transported to interfaces at the casing \n22\n, the annular fill \n18\n, and the geological formation \n14\n or an outer casing, respectively.', 'The interactions (e.g., elastic and inelastic collisions, capture, etc.) of the neutrons may vary depending on whether the annular fill \n18\n is cement \n48\n or not cement (e.g., region \n50\n).', 'For example, region \n50\n may include a material with an elemental composition, density, and other properties that are different than cement \n48\n.', 'Indeed, even if the annular fill \n18\n is not solid cement, the region \n50\n may be of the generally liquid or gas character but containing cement (detectable via the characteristic behavior of the cement when interacting with neutrons), the annular fill \n18\n is likely to set into the solid cement \n48\n in time.', 'The neutron generator \n52\n may be used for time-based measurements (e.g., using a pulsed neutron generator) and/or energy-based measurements (e.g., using a radioisotope source, a pulsed neutron generator, etc.).', 'The radiation detector \n54\n may be a gamma-ray and/or a neutron detector that may detect the radiation that results from these neutron interactions.', 'The downhole neutron tool \n26\n may use any suitable number of different data analysis techniques, including utilizing measurements of the detected radiation, number of neutron capture gamma rays, etc.', 'Various measurements obtained at the same depth in the wellbore \n16\n may be correlated to gain insight into the properties of the material behind the casing \n22\n.', 'As illustrated \nFIG.', '3\n, the wellbore \n16\n includes two concentric casings \n22\na \nand \n22\nb\n, and casing is surrounded by an annular fill \n18\na \nand \n18\nb \nthat are at a height \n64\n and \n66\n, respectively.', 'The height \n64\n is equal to height \n66\n and each annular fil \n18\na \nand \n18\nb \ninclude a region \n50\n above the respective heights \n64\n and \n66\n that indicates an absence of cement.', 'As such, the radiation detector \n54\n may determine a signal indicative of the top of the cement as the downhole neutron tool \n26\n moves passes the heights \n64\n and \n66\n.', 'Specifically, below the heights \n64\n and \n66\n, the downhole neutron tool \n26\n may receive gamma-rays indicative of cement, and receive little to no gamma-rays indicative cement as the downhole neutron tool \n26\n detects the region \n50\n during the flow chart \n56\n.', 'In some embodiments, the signal may indicate the height, or approximate height, of the annular fill \n18\nb\n.', 'In some embodiments, the wellbore \n16\n may include more than two casings.\n \nFIG.', '4\n is a schematic illustration of the downhole neutron tool \n26\n used to obtain well-logging data relating to material behind casing \n22\n of the well, in accordance with an embodiment.', 'Specifically, a neutron source (e.g., the neutron generator \n52\n) in the downhole neutron tool \n26\n may emit neutrons out toward the casing \n22\n.', 'The neutrons may be transported to interfaces at the casing \n22\n, the annular fill \n18\n, and the geological formation \n14\n or an outer casing, respectively.', 'The interactions (e.g., elastic and inelastic collisions, capture, etc.) of the neutrons may vary depending on whether the annular fill \n18\n is of the generally solid cement \n48\n not cement (e.g., region \n50\n).', 'The neutron generator \n52\n may be used for time-based measurements (e.g., using a pulsed neutron generator) and/or energy-based measurements (e.g., using a radioisotope source, a pulsed neutron generator, etc.).', 'The radiation detector \n54\n may be a gamma-ray and/or a neutron detector that may detect the radiation that results from these neutron interactions.', 'The downhole neutron tool \n26\n may use any suitable number of different data analysis techniques, including utilizing measurements of the detected radiation, number of neutron capture gamma rays, etc.', 'Various measurements obtained at the same depth in the wellbore \n16\n may be correlated to gain insight into the properties of the material behind the casing \n22\n.', 'As illustrated in \nFIG.', '4\n, the wellbore \n16\n includes two concentric casings \n22\na \nand \n22\nb\n, and the casings \n22\na \nand \n22\nb \nare surrounded by an annular fill \n18\na \nand \n18\nb \ncontaining cement \n48\n that are at a height \n66\n and \n68\n, respectively.', 'The height \n68\n is greater than the height \n66\n; thus, there is less cement outside of the casing \n22\nb \n(e.g., indicated by region \n50\n).', 'As such, the radiation detector \n54\n may determine a signal indicative of the absence of cement above the height \n66\n (e.g., based on a decreased gamma-ray signal) during the flow chart \n56\n.', 'In some embodiments, the signal may be sensitive enough to indicate the height, or approximate height, of the annular fill \n18\nb\n.', 'In some embodiments, the wellbore \n16\n may include more than two casings.\n \nFIG.', '5\n shows logging data \n70\n recorded using the downhole neutron tool \n26\n in a wellbore with multiple casings.', 'Column \n72\n shows an illustration of the wellbore \n16\n and column \n74\n represents the dry weight of calcium calculated from characteristic gamma-ray spectrum of calcium.', 'Based on either a calibration standard or known casing dimensions, the dry weight of calcium may be determined (e.g., a larger distance between casings might result in an annular fill \n18\n with a larger radius, thus increasing the amount of calcium that would be detected by the detector).', 'In column \n74\n, the dry weight calcium goes from 0% to between 1% and 15% as the top of the cement is crossed.', 'This region is identified by the arrow \n76\n on the well diagram at approximately the same depth.', 'The logging data \n70\n also includes columns that represent data obtained from the near detector and far detector (e.g., column \n78\n) and data obtained from the near detector and deep detector (e.g., column \n80\n).', 'In some embodiments, this data may be used in generating quantitative data related to the amount of cement present.', 'For example, given a depth of investigation by the downhole neutron tool of approximately 11 inches for the capture spectrum and approximately 6 inches for the inelastic spectrum, the limit of detection of calcium may be approximately 4.5 inches.', 'Moreover, two or more spectra may be recorded by a detector, wherein the depth of investigation for the two spectra is different.', 'For example, a detector may record a net inelastic spectrum, an early capture spectrum, a late capture spectrum, an activation spectrum, or any combination thereof.', 'For example, in a gauge 6⅛-inch hole cased in a 4½ inch casing, the dry weight of cement may represent approximately 1.6% from the volume investigated by the inelastic spectrum and 5.6% from the capture spectrum.', 'It would be appreciated by one of ordinary skill in the art that the total investigated volume of inelastic emissions may be smaller than the volume of capture emissions, and further, may be different that the volume of activation emissions.', 'For example, certain elements (e.g., Calcium) may not emit a significant activation spectrum.', 'Thus, in some embodiments, it may be desirable to use both or one of the spectra (e.g., the inelastic spectrum and the capture spectrum) to refine any quantitative determinations of the amount of cement.', 'Further, the cement may contain other elements (e.g., silicon) whose yields or weight concentrations may be used to cement evaluation (e.g., qualitative or quantitative determination of cement).', 'Moreover, the spectral shape of the spectrum (e.g., inelastic spectrum, capture spectrum, or activation spectrum) may provide an indication of the depth from which the gamma rays are being emitted.', 'In accordance with the techniques discussed herein, \nFIG.', '6\n shows a flow chart \n82\n for determining an amount or presence of cement within a wellbore.', 'In general, the flow chart \n82\n shows a method for determining an amount or presence of cement based on elemental spectroscopy measurements received by at least one detector \n54\n of a downhole neutron tool \n26\n.', 'The elements illustrated in the flow chart \n82\n may be performed by the data processing system \n38\n or any suitable processing system.', 'It should be appreciated that the steps of the flow chart \n82\n may be performed in addition to or in combination with one or more steps of the flow chart \n56\n shown in \nFIG.', '2\n.', 'The flow chart \n82\n may include detecting (process block \n84\n) a first energy spectrum of the gamma rays at a first region.', 'In some embodiments, the first energy spectrum may include a spectrum indicative of one or more elements over one or more ranges of energies.', 'For example, the spectrum or spectra may include elements typically found in cement, elements not typically found in cement, or elements known to be present in the formation, or any combination thereof.', 'In some embodiments, the spectrum or spectra may be indicative of certain dopants in the cement, such as those that may provide higher signals with gamma-ray spectroscopy and/or elements that are less likely to be found in the formation.', 'In some embodiments, the first energy spectrum may be obtained by a downhole neutron tool \n26\n having one detector \n54\n.', 'In some embodiments, the first energy spectrum may be obtained by a downhole neutron tool \n26\n having multiple detectors \n54\n.', 'The flow chart \n82\n may also include obtaining (process block \n86\n) one or more elemental yields and/or one or more relative elemental yields from the first energy spectrum.', 'In some embodiments, obtaining the elemental yield may include determining a mass and/or volume associated with each element from the detected energy spectrum (e.g., from process block \n84\n).', 'Moreover, the element yields may be determined directly from each spectrum for each element or based on a calibration data.', 'In some embodiments, relative yields, which are a percentage of gamma ray counts generated from individual elements over the total gamma ray counts, a ratio between two elements, and/or a percentage, may be obtained.', 'Additionally, the flow chart \n82\n may include determining (process block \n88\n) the presence of cement based on the one or more elemental yields and/or the one or more relative elemental yields.', 'In some embodiments, cement may be determined based on a combination and/or comparison of multiple detected spectra.', 'For example, an energy spectrum at one region within a wellbore may be compared to another energy spectrum at another region in a wellbore.', 'The two energy spectra may be obtained by, for example, a downhole neutron tool \n26\n having multiple detectors \n54\n in different positions and/or that measure different depths of investigation, or the two energy spectra may be obtained by moving the downhole neutron tool \n26\n having one or multiple detectors \n54\n.', 'Moreover, the detectors may measure gamma rays resulting from different interactions between neutrons and a formation, as discussed herein.', 'In any case, \nFIG.', '7\n shows a flow chart \n90\n for determining an amount or presence of cement within a wellbore.', 'The elements illustrated in the flow chart \n90\n may be performed by the data processing system \n38\n or any suitable processing system.', 'It should be appreciated that the steps of the flow chart \n90\n may be performed in addition to or in combination with one or more steps of the flow chart \n56\n shown in \nFIG.', '2\n and/or the flow chart \n82\n shown in \nFIG.', '6\n.', 'The flow chart \n90\n may include detecting (process block \n92\n) a first energy spectrum of gamma rays for at least one element at a first position.', 'For example, as discussed herein, this may include detecting a spectrum indicative of elements that may be found in cement (e.g., silicon and/or calcium).', 'In some embodiments, detecting the first energy spectrum of gamma rays for at least one element at a first position may include determining an amount (e.g., a concentration, a mass, a volume, etc.) of the at least one element at the first position.', 'As discussed herein, the first position is generally a location and/or region within the wellbore, such as along the annular fill \n18\n behind a casing \n22\n.', 'The flow chart \n90\n may also include detecting (process block \n94\n) a second energy spectrum of the gamma rays for at least one element at a second position.', 'In some embodiments, the second position and the first position may be the same position.', 'As such, the difference between detecting the first energy spectrum and the second energy spectrum may be that different elements are detected for each spectrum.', 'For example, the first energy spectrum may include one or more elements typically found in cement, while the second energy spectrum may include one or more elements not typically found in cement.', 'Alternatively, the first energy spectrum may include one subset of one or more elements found in cement and the second energy spectrum may include a second subset of one or more elements found in cement.', 'As such, the relatively proportions of these elements may be indicative of whether or not cement is present.', 'In some embodiments, the second position may be at a different depth along a wellbore and/or a different depth of investigation (DOI) within the wellbore that may be associated with either a different annular fill (e.g., \n18\na \nor \n18\nb \nas shown in \nFIG.', '3\n), or both.', 'As discussed above, with respect to process block \n92\n, detecting the second energy spectrum of gamma rays for at least one element at a second position may include determining an amount of at least one element at the second position.', 'It should be appreciated that in some embodiments, the first position and the second positions may be detected by a downhole neutron tool \n26\n having either a single detector or multiple detectors, as discussed herein.', 'The flow chart \n90\n may also include determining (process block \n96\n) a presence of cement based on a comparison of the first energy spectrum and the second energy spectrum.', 'For example, the comparison may be a comparison of the magnitude of one or more signals from the first energy spectrum between one or more signals from the second energy spectrum.', 'In such embodiments where multiple elements are detected at a position, the multiple spectra may be represented as a ratio between combinations of the elements detected at each position.', 'It should be appreciated that a ratio of multiple elements may change between a region of cement and a region other than cement.', 'Additionally or alternatively, multiple spectra indicative of multiple elements may be recorded at multiple locations.', 'Each spectra for each location may be compared to determine a presence or absence of cement (e.g., indicative of a top of an annular fill \n18\n.', 'While in some embodiments, the multiple locations may be detected by a downhole neutron tool \n26\n having multiple detectors, it should also be appreciated that multiple locations may be detected by moving the downhole neutron tool \n26\n to a different depth within the wellbore.', 'Further, the location may be a different depth of the investigation and the detected elemental spectrum or spectra from the different depth of investigation may be detected as discussed herein.', 'As one non-limiting example, a wellbore may be disposed in a formation having a relatively larger amount of one or more elements that are not typically found in cement than an element that is present in cement.', 'As such, a ratio of elements present in the cement (e.g., silicon and/or calcium) versus elements that may not be present in the cement may differ between a region associated with an annular fill having cement and a region that does not have cement.', 'As such, an operator of the downhole neutron tool \n26\n may determine where cement is located (e.g., a location of the top of annular fill) in the one or more casings within the wellbore.', 'Put differently, a region investigated by a downhole neutron tool \n26\n that does not contain cement will have a larger amount of elements not found in cement.', 'Additionally or alternatively, the operator may compare the detected amounts for each element as a function of depth in the wellbore to determine the presence of cement, such as a porous region of cement, any holes, the top of the annular fill, and the like.', 'In some embodiments, determining (process block \n88\n) a presence of cement may include a quantitative amount of the element(s) that may be inferred based on the gamma-rays detected by the detector.', 'The cement volume may be inferred from the spectral yields directly, including from the capture or inelastic yields individually, or via a combination of the two spectra.', 'The cement may also contain other elements, for example silicon, whose yields or weight concentrations can be used for cement evaluation.', 'The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms.', 'It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.'] | ['1.', 'A method for identifying cement in a cased wellbore in a geological formation, wherein the cased wellbore includes at least one casing, the method comprising:\nplacing a downhole tool into a cased wellbore, wherein the cased wellbore has been cased using a cement having an elemental composition that includes a plurality of elements;\nemitting neutrons using the downhole tool, wherein the neutrons interact with a particular material via inelastic scattering, inelastic neutron reactions, capture of neutrons, neutron activation, or any combination thereof, through one of these reactions and cause the particular material to emit an energy spectrum of gamma rays;\ndetecting, at a first location, a first energy spectrum of the gamma rays that is specific to at least one of the plurality of elements; and\ndetermining a presence of cement at the first location based at least in part on the first energy spectrum.', '2.', 'The method of claim 1, wherein the presence of cement is a volume of cement determined based at least in part on a combination of an inelastic spectrum and a capture spectrum indicative of calcium.', '3.', 'The method of claim 1, wherein the at least one of the plurality of elements comprises calcium.', '4.', 'The method of claim 1, comprising:\ndetecting, at a second location, a second energy spectrum of the gamma rays that is specific to the at least one of the plurality of elements; and\ndetermining presence of cement at the first location based at least in part on the first energy spectrum, and the second energy spectrum.', '5.', 'The method of claim 1, wherein the first energy spectrum of the gamma rays is specific to at least two of the plurality of elements; and\ndetermining the presence of cement at the first location based at least in part on at least one ratio of elements from the at least two of the plurality of elements.', '6.', 'The method of claim 1, wherein the presence is associated with a region of an annular fill between at least one casing.', '7.', 'The method of claim 1, comprising determining a depth within the cased wellbore based at least in part on a shape of a peak related to an element of the first energy spectrum and the presence of cement.', '8.', 'The method of claim 1, wherein the first location is a first depth in the cased wellbore.', '9.', 'A system for identifying cement in a cased wellbore in a geological formation, wherein the cased wellbore includes at least one casing, comprising:\na downhole tool configured to emit neutrons, wherein the neutrons interact with a particular material via inelastic scattering, inelastic neutron reactions, capture of neutrons, neutron activation, or any combination thereof, through one of these reactions and cause the particular material to emit an energy spectrum of gamma rays, and wherein the downhole tool is configured to detect an energy spectrum of the gamma rays that is specific to at least one of a plurality of elements associated with a region within the cased wellbore;\na processor; and\na memory storing instructions configured to be executed by the processor, the instructions comprising instructions to: receive a first energy spectrum of the gamma rays that is specific to calcium associated with a region within the cased wellbore; and determine an amount of cement at the region based at least in part on the first energy spectrum.', '10.', 'The system of claim 9, wherein the instructions comprise:\nreceive a second energy spectrum of the gamma rays that is specific to one or more elements not including calcium associated with the region within the cased wellbore; and\ndetermine the amount of cement at the region based at least in part on the first energy spectrum and the second energy spectrum.', '11.', 'The system of claim 10, wherein the instructions comprise:\nreceive a third energy spectrum of the gamma rays that is specific to one or more elements associated with an additional region within the cased wellbore;\ndetermine an additional amount of cement at the additional region based at least in part on a comparison between the first energy spectrum, the second energy spectrum, and the third energy spectrum.\n\n\n\n\n\n\n12.', 'The system of claim 11, wherein the region and the additional region are at different depths of investigation.', '13.', 'The system of claim 11, wherein the instructions comprise identifying an absence of cement in the region, the additional region, or both, based on the amount.\n\n\n\n\n\n\n14.', 'The system of claim 13, wherein the identified absence of cement in the region, comprises a depth within the cased wellbore associated with the region.', '15.', 'The system of claim 9, wherein the region is associated with a region of an annular fill between at least one casing.\n\n\n\n\n\n\n16.', 'The system of claim 9, wherein the amount of cement is determined based on a combination of an inelastic spectrum and a capture spectrum indicative of calcium.', '17.', 'One or more tangible, non-transitory, machine-readable media comprising instructions configured to cause a processor to:\nreceive data indicative of neutrons interacting with a particular material via inelastic scattering, inelastic neutron reactions, capture of neutrons and/or neutron activation through one of these reactions and cause the particular material to emit an energy spectrum of gamma rays;\ndetermine a first amount of calcium, silicon, or both based on a first energy spectrum of the gamma rays associated with a first region within a cased wellbore comprising at least one casing;\ndetermine a second amount of one or more elements based on a second energy spectrum of the gamma rays associated with the first region within the cased wellbore; and\ndetermine a presence of cement within the first region based at least in part on the first amount and the second amount.\n\n\n\n\n\n\n18.', 'The one or more machine-readable media of claim 17, wherein the first amount is associated with a first depth of investigation within the first region, the second amount is associated with a second depth of investigation within the first region.', '19.', 'The one or more machine-readable media of claim 18, wherein the second amount of the one or more elements does not include an amount of calcium, silicon, or both.\n\n\n\n\n\n\n20.', 'The one or more machine-readable media of claim 17, where the instructions comprise:\ndetermine a depth within the cased wellbore lacking cement.'] | ['FIG.', '1 is a schematic diagram of a system for verifying proper cement installation and/or zonal isolation of a well, in accordance with an embodiment;; FIG.', '2 shows a flow chart of a method for evaluating cement in the cased wellbore in the geological formation, in accordance with an embodiment;; FIG.', '3 is a schematic illustration of a downhole tool (e.g., a downhole neutron tool) used to obtain well-logging data relating to material behind multiple casings of the well, in accordance with an embodiment;; FIG.', '4 is a schematic illustration of a downhole tool (e.g., a downhole neutron tool) used to obtain well-logging data relating to material behind multiple casings of the well, in accordance with an embodiment;; FIG.', '5 shows well-logging data obtained from a downhole tool, in accordance with an embodiment;; FIG.', '6 is a flow chart of a process for identifying cement in a wellbore in a geological formation; and; FIG. 7 is an additional flow chart of a process for identifying cement in a wellbore in a geological formation.; FIG.', '1 also schematically illustrates a magnified view of a portion of the cased wellbore 16.', 'As mentioned above, the downhole neutron tool 26 may obtain well-logging data relating to the presence of the cement in the annular fill 18 behind the casing 22.', 'For instance, the downhole neutron tool 26 may obtain measures of well-logging data, which may be used to determine where the material behind the casing 22 is fully cemented or at least partly washed out.', 'When the downhole neutron tool 26 provides such measurements to the surface equipment 12 (e.g., through the cable 28), the surface equipment 12 may pass the measurements as well-logging data 36 to a data processing system 38 that includes a processor 40, memory 42, storage 44, and/or a display 46.', 'In other examples, the well-logging data 36 may be processed by a similar data processing system 38 at any other suitable location.', 'The processor 40 may execute instructions stored in the memory 42 and/or storage 44.', 'As such, the memory 42 and/or the storage 44 of the data processing system 38 may be any suitable article of manufacture that can store the instructions.', 'The memory 42 and/or the storage 44 may be ROM memory, random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive, to name a few examples.', 'The display 46 may be any suitable electronic display that can display the logs and/or other information relating to classifying the material in the annulus 20 behind the casing 22.; FIG.', '2 illustrates a flow chart 56 of a cement evaluation method for evaluating cement in the cased wellbore 16 in the geological formation 14, in accordance with an embodiment.', 'The flow chart 56 may include positioning (block 58) the downhole neutron tool 26 into the cased wellbore 16.', 'As described above, the cased wellbore 16 may be cased with cement.', 'The cement may emit a characteristic gamma ray spectrum when or after having been bombarded with neutrons, which is distinct from that of the surrounding geological formation 14.', 'The gamma ray spectrum may be used to determine the absence or presence of cement, as explained further below.', 'In some embodiments, the gamma ray spectrum may be used to determine the height of the annular fill, which may be referred to as a “top of cement” in the wellbore.; FIG.', '3 is a schematic illustration of the downhole neutron tool 26 used to obtain well-logging data relating to material behind casing 22 of the well, in accordance with an embodiment.', 'Specifically, a neutron source (e.g., the neutron generator 52) in the downhole neutron tool 26 may emit neutrons out toward the casing 22.', 'The neutrons may be transported to interfaces at the casing 22, the annular fill 18, and the geological formation 14 or an outer casing, respectively.', 'The interactions (e.g., elastic and inelastic collisions, capture, etc.) of the neutrons may vary depending on whether the annular fill 18 is cement 48 or not cement (e.g., region 50).', 'For example, region 50 may include a material with an elemental composition, density, and other properties that are different than cement 48.', 'Indeed, even if the annular fill 18 is not solid cement, the region 50 may be of the generally liquid or gas character but containing cement (detectable via the characteristic behavior of the cement when interacting with neutrons), the annular fill 18 is likely to set into the solid cement 48 in time.', 'The neutron generator 52 may be used for time-based measurements (e.g., using a pulsed neutron generator) and/or energy-based measurements (e.g., using a radioisotope source, a pulsed neutron generator, etc.).', 'The radiation detector 54 may be a gamma-ray and/or a neutron detector that may detect the radiation that results from these neutron interactions.', 'The downhole neutron tool 26 may use any suitable number of different data analysis techniques, including utilizing measurements of the detected radiation, number of neutron capture gamma rays, etc.', 'Various measurements obtained at the same depth in the wellbore 16 may be correlated to gain insight into the properties of the material behind the casing 22.; FIG. 4 is a schematic illustration of the downhole neutron tool 26 used to obtain well-logging data relating to material behind casing 22 of the well, in accordance with an embodiment.', 'Specifically, a neutron source (e.g., the neutron generator 52) in the downhole neutron tool 26 may emit neutrons out toward the casing 22.', 'The neutrons may be transported to interfaces at the casing 22, the annular fill 18, and the geological formation 14 or an outer casing, respectively.', 'The interactions (e.g., elastic and inelastic collisions, capture, etc.) of the neutrons may vary depending on whether the annular fill 18 is of the generally solid cement 48 not cement (e.g., region 50).', 'The neutron generator 52 may be used for time-based measurements (e.g., using a pulsed neutron generator) and/or energy-based measurements (e.g., using a radioisotope source, a pulsed neutron generator, etc.).', 'The radiation detector 54 may be a gamma-ray and/or a neutron detector that may detect the radiation that results from these neutron interactions.', 'The downhole neutron tool 26 may use any suitable number of different data analysis techniques, including utilizing measurements of the detected radiation, number of neutron capture gamma rays, etc.', 'Various measurements obtained at the same depth in the wellbore 16 may be correlated to gain insight into the properties of the material behind the casing 22.; FIG.', '5 shows logging data 70 recorded using the downhole neutron tool 26 in a wellbore with multiple casings.', 'Column 72 shows an illustration of the wellbore 16 and column 74 represents the dry weight of calcium calculated from characteristic gamma-ray spectrum of calcium.', 'Based on either a calibration standard or known casing dimensions, the dry weight of calcium may be determined (e.g., a larger distance between casings might result in an annular fill 18 with a larger radius, thus increasing the amount of calcium that would be detected by the detector).', 'In column 74, the dry weight calcium goes from 0% to between 1% and 15% as the top of the cement is crossed.', 'This region is identified by the arrow 76 on the well diagram at approximately the same depth.', 'The logging data 70 also includes columns that represent data obtained from the near detector and far detector (e.g., column 78) and data obtained from the near detector and deep detector (e.g., column 80).', 'In some embodiments, this data may be used in generating quantitative data related to the amount of cement present.', 'For example, given a depth of investigation by the downhole neutron tool of approximately 11 inches for the capture spectrum and approximately 6 inches for the inelastic spectrum, the limit of detection of calcium may be approximately 4.5 inches.', 'Moreover, two or more spectra may be recorded by a detector, wherein the depth of investigation for the two spectra is different.', 'For example, a detector may record a net inelastic spectrum, an early capture spectrum, a late capture spectrum, an activation spectrum, or any combination thereof.', 'For example, in a gauge 6⅛-inch hole cased in a 4½ inch casing, the dry weight of cement may represent approximately 1.6% from the volume investigated by the inelastic spectrum and 5.6% from the capture spectrum.', 'It would be appreciated by one of ordinary skill in the art that the total investigated volume of inelastic emissions may be smaller than the volume of capture emissions, and further, may be different that the volume of activation emissions.', 'For example, certain elements (e.g., Calcium) may not emit a significant activation spectrum.', 'Thus, in some embodiments, it may be desirable to use both or one of the spectra (e.g., the inelastic spectrum and the capture spectrum) to refine any quantitative determinations of the amount of cement.', 'Further, the cement may contain other elements (e.g., silicon) whose yields or weight concentrations may be used to cement evaluation (e.g., qualitative or quantitative determination of cement).', 'Moreover, the spectral shape of the spectrum (e.g., inelastic spectrum, capture spectrum, or activation spectrum) may provide an indication of the depth from which the gamma rays are being emitted.'] |
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US11105948 | Downhole tool analysis using anomaly detection of measurement data | Sep 26, 2016 | Bo Hu, Mark Flaum, Jane Troutner | SCHLUMBERGER TECHNOLOGY CORPORATION | International Preliminary Report on Patentability issued in International Patent application PCT/US2016/053648, dated Apr. 4, 2018, 11 pages.; Brieman et al., Classification and Regression Trees. Chapman Hall, Boca Raton, FL, 1984, 72 pages.; International Search Report and Written Opinion issued in International Patent application PCT/US2016/053648, dated Dec. 14, 2016. 16 pages.; Mahalanobis, P.C., “On the generalised distance in statistics,” Proceedings of the National Institute of Sciences of India, vol. 2, pp. 49-55, Apr. 16, 1936.; Breiman, Leo, “Random Forests,” Machine Learning, vol. 45, pp. 5-32, 2001.; Hastie et al., The elements of statistical learning: Data mining, inference, and prediction. New York: Springer Verlag, 2001. pp. 587-601. | 6787758; September 7, 2004; Tubel et al.; 20090166031; July 2, 2009; Hernandez; 20100042327; February 18, 2010; Garvey; 20100082258; April 1, 2010; Wang; 20110022354; January 27, 2011; Kumar; 20110153236; June 23, 2011; Montreuil; 20120245481; September 27, 2012; Blanco; 20120290208; November 15, 2012; Jiang et al.; 20120323494; December 20, 2012; Lovell; 20130046157; February 21, 2013; Addison; 20140062495; March 6, 2014; Carter; 20150314068; November 5, 2015; Alderete, Jr.; 20150347698; December 3, 2015; Soni; 20150363925; December 17, 2015; Shibuya; 20170104657; April 13, 2017; Gopalakrishnan | Foreign Citations not found. | ['A method and system for detecting an anomaly in measurement data captured by a downhole tool is disclosed provided.', 'In the method and system, measurement data comprising a plurality of measurement channels is obtained and reference data including healthy reference data and faulty reference data is also obtained.', 'The measurement data is preprocessed by modeling at least one measurement channel of the plurality of measurement channels using modeling parameters to produce pre-processed measurement data.', 'Further, a first distance between the pre-processed measurement data and the healthy reference data is obtained and determined to exceed a first threshold for the first distance.', 'A report is generated in response to determining that the first distance exceeds the first threshold.', 'The report indicates detection of the anomaly in the measurement data.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThe present application claims priority to U.S. Provisional Application 62/235,071, filed Sep. 30, 2015, the entirety of which is incorporated by reference.', 'FIELD OF THE INVENTION', 'Some embodiments described herein generally relate to systems and apparatuses for downhole tool analysis.', 'Additional embodiments described herein generally relate to methods for downhole tool analysis based on anomaly detection of measurement data.', "BACKGROUND\n \nDownhole tools are used for exploring oil and natural gas deposits under the Earth's surface.", 'A downhole tool may be equipped with a number of sensors that capture measurements used for determining the viability of oil or natural gas exploration.', 'A downhole tool may be used in a logging-while-drilling operation, whereby various measurements are captured as the tool drills and descends under the surface of the Earth.', 'During operation, malfunction of the downhole tool causes noise and other artifacts to be introduced in the measurements captured by the downhole tool.', 'The noise and artifacts corrupt the captured data.', 'The noise and artifacts also result in uncertainty in determinations by exploration personnel as to whether an explored area includes oil or gas deposits.', 'Maintenance and repair of the downhole tool ahead of drilling mitigate the noise or artifacts introduced in the captured measurements.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'A method for detecting an anomaly in measurement data captured by a downhole tool is disclosed.', 'Measurement data comprising a plurality of measurement channels for a time point of a plurality of time points is obtained.', 'Reference data including healthy reference data and faulty reference data is also obtained.', 'The measurement data is pre-processed by modeling at least one measurement channel of the plurality of measurement channels using modeling parameters to produce pre-processed measurement data.', 'The method includes determining a first distance between the pre-processed measurement data and the healthy reference data and determining that the first distance exceeds a first threshold for the first distance.', 'The method also includes generating a report indicating detection of the anomaly in the measurement data in response to determining that the first distance exceeds the first threshold for the first distance.', 'A system that includes a measurement data storage that stores measurement data comprising a plurality of measurement channels is disclosed.', 'The system also includes a reference data storage that stores healthy reference data and faulty reference data and a detection system that is coupled to the measurement data storage and the reference data storage.', 'The detection system obtains the measurement data from the measurement data storage and the healthy reference data and the faulty reference data from the reference data storage.', 'The detection system pre-processes the measurement data by modeling at least one measurement channel of the plurality of measurement channels using modeling parameters to produce pre-processed measurement data.', 'The detection system determines a first distance between the pre-processed measurement data and the healthy reference data.', 'The detection system also determines that the first distance exceeds a first threshold for the first distance and outputs a report indicating detection of an anomaly in the measurement data in response to determining that the first distance exceeds the first threshold.', 'A method for detecting an anomaly in measurement data captured by a downhole tool includes obtaining the measurement data, whereby the measurement data includes a plurality of measurement channels for a time point of a plurality of time points at which measurements were recorded.', 'The method includes obtaining reference data including healthy reference data and faulty reference data and training a classification algorithm using the healthy reference data and faulty reference data.', 'The at least one measurement channel of the plurality of measurement channels is modelled using modeling parameters.', 'Pre-processed measurement data is produced based on modelling the at least one measurement channel of the plurality of measurement channels.', 'The method includes determining whether the measurement data is classified as healthy or faulty based at least in part on evaluating the pre-processed measurement data using the classification algorithm.', 'The method further includes outputting a report indicating that the measurement data is faulty in response to determining that the measurement data is classified as faulty.', 'BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS\n \nIn the drawings, sizes, shapes, and relative positions of elements are not drawn to scale.', 'For example, the shapes of various elements and angles are not drawn to scale, and some of these elements may have been arbitrarily enlarged and positioned to improve drawing legibility.\n \nFIG.', '1\n depicts an environment for downhole tool health prognosis in a drilling operation according to one or more embodiments disclosed herein;\n \nFIG.', '2\n depicts an example of measurement data recorded by the downhole tool according to one or more embodiments disclosed herein;\n \nFIG.', '3\n depicts a flow diagram of a method for pre-processing measurement data according to one or more embodiments disclosed herein;\n \nFIG.', '4\n depicts a flow diagram of a method for classifying the measurement data according to one or more embodiments disclosed herein;\n \nFIG.', '5\n depicts a flow diagram of a method for performing a Mahalanobis distance analysis on the measurement data according to one or more embodiments disclosed herein;\n \nFIG.', '6\n depicts an example of a distribution of the Mahalanobis distances of measurement data of a drilling operation according to one or more embodiments disclosed herein;\n \nFIG.', '7\n depicts an example of a CART-based classification of measurement data according to one or more embodiments disclosed herein;\n \nFIG.', '8\n depicts measurement data classification using the CART algorithm according to one or more embodiments disclosed herein; and\n \nFIG.', '9\n depicts magnitudes by which channels of measurement data contributed to a faulty classification according to one or more embodiments disclosed herein.', 'DETAILED DESCRIPTION\n \nFIG.', '1\n depicts an environment \n100\n for downhole tool \n102\n health prognosis in a drilling operation according to one or more embodiments disclosed herein.', 'The environment \n100\n includes a downhole tool \n102\n, a measurement data storage system \n104\n, a detection system \n106\n and a reference data storage system \n108\n.', 'The downhole tool \n102\n further includes a plurality of sensors \n110\n (singularly referred to herein as sensor \n110\n).', "The downhole tool \n102\n may, for example, be a drilling apparatus used for exploration of oil or gas under the Earth's surface.", 'The sensors \n110\n of the downhole tool \n102\n may be used to capture measurements at various depths of a borehole in a logging-while-drilling environment.', 'The sensors \n110\n, which may be antennas or detectors, may perform Nuclear Magnetic Resonance (NMR) measurements.', "Nuclear Magnetic Resonance enables measuring the porosity and permeability of the Earth's rock and characterizing pore spaces in a drilling environment and the fluid in the pore spaces.", 'In addition, the downhole tool \n102\n may make various other measurements such as the temperature of the downhole tool \n102\n and sensor or antenna resonant frequency.', 'In Nuclear Magnetic Resonance (NMR) measurements, early echo ringing introduces undesirable artifacts in the measured data.', 'The artifacts result from excess energy or voltage captured by a sensor \n110\n.', 'The ringing leads to uncertainty about the measured data and introduces noise in the recorded data.', "The noise may hinder an operator's ability to use the data for detecting the presence of natural resources under the Earth's surface.", 'Reducing the noise introduced by the downhole tool \n102\n results in the recorded data more accurately reflecting the sought measurements.', 'The data captured by the downhole tool \n102\n is evaluated to detect an anomaly or failure as described herein.', 'If an anomaly or failure is detected, the downhole tool \n102\n may be serviced or repaired to mitigate or eliminate the introduced artifacts.', 'More reliable measurement data may then be obtained by the downhole tool \n102\n.', 'Still referring to \nFIG.', '1\n, the measurement data captured by the downhole tool \n102\n is stored in the measurement data storage system \n104\n.', 'The measurement data storage system \n104\n may be any type of device capable of storing data, such as a hard drive or solid-state drive, among others.', 'The measurement data may be provided to the measurement data storage system \n104\n as measurement are made in real-time.', 'For example, as the downhole tool \n102\n descends deeper and makes measurements at various depths, the measurement data may be sent to the measurement data storage system \n104\n.', 'The measurement data may be sent wirelessly over any type of wireless link.', 'Further, the measurement data may also be sent over a wired link.', 'The measurement data may be stored locally by the downhole tool \n102\n and may be provided to the measurement data storage system \n104\n once the measurements for an entire depth of a well are completed.', 'The measurement data may then be provided to the detection system \n106\n.', 'The detection system \n106\n may include one or more computational resources, memory resources and/or networking resources, among others.', 'For example, the detection system \n106\n may be a computer or a server.', 'The detection system \n106\n evaluates the measurement data to determine whether an anomaly or failure is present in the measurement data.', 'The detection system \n106\n may be coupled to the reference data storage system \n108\n.', 'The reference data storage system \n108\n stores both healthy reference data and faulty reference data.', 'The healthy reference data may be a sample of measurement data identified as being healthy.', 'The healthy reference data may, for example, be previously made measurement data identified as having no or minimal early echo ringing artifacts or other noise introduced by the downhole tool \n102\n.', 'The healthy reference data may be used as a baseline as described herein for comparison with the measurement data.', 'Based on the comparison, a degree of similarity between the measurement data and the healthy reference data may be determined and used for identifying whether the measurement data may be classified as healthy.', 'If the measurement data is classified as healthy, it may be concluded the downhole tool \n102\n is operating as desired and may not need repair or maintenance.', 'Similarly, the faulty reference data may be a sample of measurement data identified as being faulty.', 'The faulty reference data may, for example, be a previously made data measurement identified as having a high degree of early echo ringing or other artifacts.', 'The faulty reference data may be used as a baseline for comparison with the measurement data and determining whether the measurement data may be classified as faulty.', 'The measurement data may be categorized as an anomaly if the measurement data deviates from the healthy references data.', 'The measurement data may be categorized as faulty if the measurement data corresponds to the properties of the faulty reference data.', 'FIG.', '2\n depicts an example of measurement data made by the downhole tool \n102\n according to one or more embodiments disclosed herein.', 'At various depths, the downhole tool \n102\n may make various measurements.', 'The measurements are shown to include a depth measurement \n202\n, a time measurement \n204\n, a Nuclear Magnetic Resonance measurement \n206\n, an antenna tuning measurement \n208\n, a tool temperature measurement \n210\n and an antenna resonant frequency \n212\n.', 'It is recognized that the measurements shown in \nFIG.', '2\n are exemplary and in various embodiments additional or different measurements may be made and recorded.', 'The measurements are shown in \nFIG.', '2\n for one depth or time point.', 'However, as may be recognized, the measurement data includes measurements that are made at a plurality of depths or time points.', 'At each depth some of the measurements may be array measurements that are represented by a vector or a string of values.', 'For example, as shown in \nFIG.', '2\n, the Nuclear Magnetic Resonance measurement \n206\n and the antenna tuning measurement \n208\n are each array measurements that are represented by a plurality of values for each depth measurement \n202\n or time measurement \n204\n.', 'The depth measurement \n202\n may represent the depth to which the downhole tool \n102\n descended or at which the various other measurements were made.', 'The time measurement \n204\n may represent the length of time that elapsed from the time at which the downhole tool \n102\n began its descent.', 'On the other hand, the tool temperature measurement \n210\n, as well as the antenna resonant frequency, may be represented by single quantity as opposed to an array.', 'Each type of measurement made by the downhole tool \n102\n is referred to herein as a channel.', 'After collecting and recording the measurement data by the downhole tool \n102\n, the data may be pre-processed ahead of detecting whether the measurement data is to be categorized as faulty or as anomalous.', 'Pre-processing the measurement data may be performed by the detection system \n106\n described with reference to \nFIG.', '1\n.', 'In alternative embodiments, a separate pre-processing system may be provided for pre-processing the measurement data.', 'The data that is pre-processed by the pre-processing system may then be provided to the detection system \n106\n for evaluation.', 'Similar to the detection system \n106\n, the pre-processing system may include computational resources.', 'The pre-processing system may be any type of computer equipped with a processor.', 'For example, the pre-processing system may be a laptop computer that is equipped with a central processing unit (CPU).', 'Pre-processing the measurement data reduces the volume of the measurement data used for anomaly or fault detection.', 'Pre-processing the measurement data also makes anomaly or fault detection more computationally efficient.', 'That is because the detection system evaluates a smaller set of pre-processed measurement data to detect an anomaly or fault as opposed to a larger set of captured measurement data.', 'Pre-processing may remove redundancies in the measurement data and model the measurement data or channels thereof using modeling parameters.\n \nFIG.', '3\n depicts a method for pre-processing measurement data according to one or more embodiments disclosed herein.', 'In the method \n300\n, the detection system \n106\n described with reference to \nFIG.', '1\n receives, at block \n302\n, the measurement data from the measurement data storage system.', 'The measurement data as described herein includes channels that are represented by arrays of multiple quantities.', 'For example, the Nuclear Magnetic Resonance measurement \n206\n may include over a thousand samples for each depth.', 'At block \n304\n, the detection system \n106\n performs channel modeling on array channels.', 'Different types of channels may be modeled differently.', 'For example, the Nuclear Magnetic Resonance echo measurement channel data may be a logarithmic decay and log-linear fitting may be used to represent the measurement data more compactly.', 'In log-linear fitting, the logarithmic decay data may be segmented into two or more segments and each segment may be represented by modeling parameters, such as an intercept and a slope for the segment.', 'Further, an indication of a residual value of the measured Nuclear Magnetic Resonance to the fitted line may be provided for each segment.', 'Accordingly, an array of several hundred or thousand measurements may be modeled and represented by a much smaller number of modeling parameters.', 'Some measurement channels may be frequency responses that are modeled using a peak amplitude of the measured data and a frequency at the peak amplitude of the measured data.', 'Thus, an array of hundreds of measurements may be represented using the two modeling parameters of peak amplitude and frequency.', 'At block \n306\n, the detection system \n106\n performs correlation on the channels of the measurement data and discards highly correlated measurement channels.', 'A high correlation, as measured by a correlation coefficient of near 1 or near −1, between a first measurement channel and a second measurement channel indicates that the first measurement channel is a linear transformation of the second measurement channel or vice-versa.', 'Accordingly, utilizing both measurement channels may be redundant and one of the two measurement channels may be removed from further evaluation.', 'The detection system \n106\n then applies rule-based filtering to remove a set of measurement channels of the measurement data at block \n308\n.', 'For example, certain measurement channels of the measurement data may not factor in determining whether the measurement data is faulty.', 'These measurement channels may be removed from the pre-processed measurement data set.', 'The detection system \n106\n then outputs the pre-processed measurement data \n310\n.', 'The pre-processed measurement data is evaluated by the detection system \n106\n to determine whether the measurement data is to be classified as faulty or anomalous.', 'The measurement data is classified as faulty if the measurement data is determined to have attributes that correspond to those of the faulty reference data.', 'Further, the measurement data is classified as anomalous if the measurement data is determined to have attributes that are different than those of the healthy reference data.', 'Two techniques are described herein for classifying the measurement data.', 'In the first technique, a clustering algorithm, such as the Mahalanobis distance, is used for determining whether the measurement is to be classified as faulty or anomalous.', 'For example, the Mahalanobis distance between the pre-processed measurement data and the healthy reference data or between the pre-processed measurement data and the faulty reference data may be obtained and used for determining whether the measurement is to be classified as faulty or anomalous.', 'In the second technique, a classification algorithm, such as the classification and regression tree (CART) algorithm or the random forest algorithm, is trained with the healthy reference data and the faulty reference data.', 'After the training, the classification algorithm is used to classify the pre-processed measurement data.', 'Reference is made herein to T. Hastie, R. Tibshirani and J. H. Friedman, “The elements of statistical learning: Data mining, inference, and prediction,” New York: Springer Verlag, 2001, L. Breiman, J. H. Friedman, R. A. Olshen, and C. J. Stone, “Classification and regression trees,” Monterey, Calif.:', 'Wadsworth & Brooks/Cole Advanced Books & Software, 1984 and L. Breiman, “Random Forests,” Machine Learning, Vol. 45, pp.', '5-32, 2001, which describe the CART algorithm and the random forest algorithm, among others, and are hereby incorporated by reference herein in their entirety as if fully set forth.', 'FIG.', '4\n depicts a flow diagram of a method for classifying the measurement data according to one or more embodiments disclosed herein.', 'In the method \n400\n, the detection system \n106\n obtains the pre-processed measurement data at block \n402\n.', 'As described herein, the recorded measurement data may be compressed and the redundancies of the measurement data may be removed to obtain the pre-processed measurement data.', 'The detection system \n106\n then obtains, at block \n404\n, the reference data, which includes the healthy reference data and the faulty reference data.', 'At block \n406\n, the detection system \n106\n applies a clustering algorithm or a classification algorithm to the pre-processed measurement data and the reference data to determine whether the measurement data is faulty or anomalous.', 'As described herein, the clustering algorithm may be the Mahalanobis distance and the classification algorithm may be the CART algorithm or a random forest algorithm.', 'At block \n408\n, the detection system \n106\n outputs a report indicating if the measurement data is faulty or anomalous.', 'The report may be used for determining whether the downhole tool \n102\n is to be serviced or repaired, for example, if the data is classified as anomalous or faulty.\n \nFIG.', '5\n depicts a flow diagram of a method for performing a Mahalanobis distance analysis according to one or more embodiments disclosed herein.', 'In the method \n500\n, the detection system \n106\n determines a first Mahalanobis distance \n502\n between the pre-processed measurement data and the healthy reference data.', 'The first Mahalanobis distance is determined as: \n MD\n1\n(\n{right arrow over (x)},{right arrow over (y)}\n)=√{square root over ((\n{right arrow over (x)}−{right arrow over (y)}\n)\nT\nS\n−1\n(\n{right arrow over (x)}−{right arrow over (y)}\n))}\u2003\u2003(Equation (1)) \n where {right arrow over (x)} is a vector that includes the pre-processed measurement data, {right arrow over (y)} is a vector that includes the healthy reference data, S is the covariance matrix, (.)\n−1 \nrepresents the matrix inverse operator and (.)', 'T \nrepresents the transpose operator.', 'The Mahalanobis distance between the pre-processed measurement data and the healthy reference data is indicative of the deviation of the pre-processed measurement data from the healthy reference data.', 'A relatively small Mahalanobis distance is indicative of relatively high degree of similarity between the pre-processed measurement data and the healthy reference data.', 'Conversely, a relatively high Mahalanobis distance is indicative of a relatively low degree of similarity between the pre-processed measurement data and the healthy reference data.', 'A first threshold for the first Mahalanobis distance is set or established such that if the first Mahalanobis distance exceeds the first threshold, the pre-processed measurement data is classified as anomalous.', 'Conversely, if the first Mahalanobis distance does not exceed the first threshold, the pre-processed measurement data is classified as healthy.', 'As may be recognized, reducing the first threshold increases the likelihood of false positives, i.e., mistakenly classifying pre-processed measurement data as anomalous when in fact the pre-processed measurement data is healthy.', 'The first threshold for the first Mahalanobis may be set such that 99% of Mahalanobis distances calculated for various trials of measurement data are below the first threshold and only 1% are equal to or above the first threshold.', 'Furthermore, in a less restrictive scenario, the first threshold may be set such that 95% of Mahalanobis distances calculated for various trials of measurement data are below the first threshold and 5% are above the first threshold.', 'Following determining the first Mahalanobis distance, the detection system \n106\n determines whether the first Mahalanobis distance is greater than the first threshold \n504\n.', 'If a positive determination is made, the pre-processed measurement data is classified as anomalous \n508\n and if a negative determination is made, the pre-processed measurement data is classified as healthy \n506\n.', 'The first Mahalanobis distance may be calculated for every depth for which data measurements are obtained by the downhole tool \n102\n.', 'The vector {right arrow over (x)} may include the pre-processed measurement data for the depth, whereas the vector {right arrow over (y)} may include the healthy reference data for the depth.', 'The downhole tool \n102\n may make measurement at hundreds or thousands of depths or time points and the first Mahalanobis distances may be obtained for each depth or time point.', 'If the pre-processed measurement data is classified as anomalous, the pre-processed measurement data may be further evaluated to determine whether the pre-processed measurement data has similar attributes as those of the faulty reference data and may be further classified as faulty.', 'It is noted that classifying the pre-processed measurement data as anomalous with respect to the healthy reference data facilitates analyzing the downhole tool \n102\n.', 'The anomaly may trigger assessment and analysis of the downhole tool \n102\n for the presence of a malfunction.', 'Accordingly, evaluating whether the pre-processed measurement data is to be categorized faulty as described herein may be forgone.', 'The detection system \n106\n determines a second Mahalanobis distance between the pre-processed data and the faulty reference data \n510\n.', 'Similar to the first Mahalanobis distance, the second Mahalanobis distance may be determined as: \n MD\n2\n(\n{right arrow over (x)},{right arrow over (z)}\n)', '=√{square root over ((\n{right arrow over (x)}−{right arrow over (z)}\n)\nT\nS\n−1\n(\n{right arrow over (x)}−{right arrow over (z)}\n))}\u2003\u2003(Equation (2)) \n where {right arrow over (x)} is a vector that includes the pre-processed measurement data for a certain depth \n202\n or time point \n204\n and {right arrow over (z)} is a vector that includes the faulty reference data for the depth \n202\n or time point \n204\n and S is the covariance matrix.', 'At every depth \n202\n or time point \n204\n, the second Mahalanobis distance (MD\n2\n) may be determined.', 'The detection system \n106\n then determines whether the second Mahalanobis distance is greater than a second threshold \n512\n.', 'If the second Mahalanobis distance is determined to be greater than the second threshold, then the process ends and the pre-processed measurement data, for example, for the depth \n202\n, remains classified as anomalous.', 'Conversely, if a negative determination is made, the pre-processed measurement data is classified as faulty \n514\n.', 'It is noted that another clustering algorithm, such as K-means clustering, may be used to classify the measurement data and determine whether the measurement data is healthy or faulty.', 'Further, a different multi-dimensional distance metric may be used in place of the Mahalanobis distance for determining the distance between the measurement data and the healthy or faulty reference data.\n \nFIG.', '6\n depicts an example of a distribution of the Mahalanobis distances of measurement data of a drilling operation according to one or more embodiments disclosed herein.', 'The distribution of the Mahalanobis distances for data measurements made at various time points indicates that about 90% of the Mahalanobis distances are between 4 and 5.', 'Further, only 1% of the Mahalanobis distances are greater than 7.52.', 'Further, temporally plotting the Mahalanobis distances shows indicates that failure was observed in the measurements made between the 10th and 19th hour of the drilling operation as represented by spikes of the Mahalanobis distances for these measurement.', 'Outside of the range between the 10th and 19th hour, a failure was not detected.', 'It is noted that the Mahalanobis distance may be used for predicting failure.', 'For example, if the Mahalanobis distance is detected to be trending higher with respect to time, the upward trend in the Mahalanobis distance may be used to forecast an upcoming failure.', 'The detection system may use the classification and regression tree (CART) algorithm described herein for determining whether measurement data is faulty or anomalous.', 'The CART algorithm may be trained by the healthy and faulty reference data measurements.', 'The CART algorithm provides a set of rules for optimally dividing a boundary between the healthy and faulty class.', 'The CART algorithm may create non-linear boundaries between the healthy and faulty reference data measurements that are more optimum than linear boundaries.', 'At each node of the CART algorithm, a determination is made about whether the measurement data meets a specific criterion.', 'Depending on whether the measurement data meets the criterion, a tree will branch to another node where another determination is made about the measurement data.', 'The CART algorithm continues to branch until a final determination is made about the measurement data.', 'Similar to the Mahalanobis distance, the CART algorithm may be applied to every vector of measurement data or pre-processed data thereof that is recorded at a certain depth or time point.', 'The CART algorithm then renders a binary determination as to whether the measurement data is to be classified as healthy or faulty.\n \nFIG.', '7\n depicts an example of a CART-based classification of measurement data according to one or more embodiments disclosed herein.', 'After training the CART algorithm with the healthy and faulty reference measurement data, the CART algorithm develops a decision tree for determining whether measurement data is healthy or faulty.', 'The decision tree includes a plurality of nodes \n602\n to query the measurement data.', 'Based on the outcome of the query at a node, the branch \n604\n of the decision tree is followed to a subsequent node \n602\n, where the measurement data is queried again.', 'The branches \n604\n of the decision tree are followed until the tree terminates and the measurement data is classified as healthy \n606\n or faulty \n608\n.', 'Following training the CART algorithm, the decision tree is provided to the detection system \n102\n described with reference to \nFIG.', '1\n.', 'As shown in the example of \nFIG.', '7\n, the detection system \n102\n initially determines whether the measured temperature of the measurement data is greater than 42 degrees.', 'If a positive determination is made, the detection system \n102\n determines if the slope of the first NMR measurement segment is greater than 1 and depending on the outcome of the query, the detection system \n102\n queries the measurement data in accordance with another node of the decision tree.', 'If, on the other hand, a negative determination is made, the detection system \n102\n determines if the antenna resonant frequency of the measurement data is greater than 100 MHz.', 'Depending on the outcome of the query, the detection system \n102\n queries the measurement data in accordance with another node of the decision tree.', 'The branches \n604\n of the decision tree are followed to respective nodes \n602\n until the decision tree terminates with a classification indicating whether the measurement data is determined to be healthy \n606\n or faulty \n608\n.', 'FIG.', '8\n depicts measurement data classification using the CART algorithm according to one or more embodiments disclosed herein.', 'In \nFIG.', '8\n, a value of ‘1’ indicates healthy measurement data, whereas a value of ‘0’ indicates faulty data.', 'As illustrated in \nFIG.', '8\n, the majority of the measurement data recorded by the downhole tool \n102\n is healthy with the exception of the measurement data recorded between the 22nd and 25th hours of operation, which is classified as faulty.', 'The outcomes of the classification by the CART algorithm may be used to generate a report indicating that the downhole tool \n102\n should be serviced or repaired.', 'In addition to classifying the data as healthy of faulty, the CART algorithm may be used by the detection system \n106\n to identify the channels of the measurement data that contributed to the determination of a faulty classification.', 'The CART algorithm may provide the detection system \n106\n with a weight associated with each channel of measurement data.', 'The weight may indicate the degree to which the channel of measurement data contributed to the faulty classification rendered by the CART algorithm.\n \nFIG.', '9\n depicts magnitudes by which channels of measurement data contributed to a faulty classification according to one or more embodiments disclosed herein.', 'In \nFIG.', '9\n, the measurement data has 57 channels.', 'Three of the channels were associated with a relatively high contribution to the faulty classification of the measurement data.', 'The identification of the primary contributing channels to the faulty classification may be provided in a report generated by the detection system \n106\n.', 'Further, the identification may be used by personnel for the repair or maintenance of the downhole tool.', 'In addition, the identification of the primary contributing channels may be a signature or a pattern associated with a certain malfunction of the downhole tool \n102\n.', 'Different malfunctions of the downhole tool \n102\n may introduce different noise or errors in the measured data.', 'When a particular malfunction occurs, a pattern of noise or errors may introduced in the measured data.', 'The pattern may be detected by the detection system \n106\n as a result of performing the CART algorithm on the measured data and identifying the contribution of the channels of the measurement data.', 'The pattern may be used to pinpoint the malfunction of the downhole tool \n102\n that resulted in the measurement data being classified as faulty.', 'It is noted that various classification algorithms, such as the random forest algorithm, may be trained with the healthy reference data and the faulty reference data to obtain a classifier usable to classify the measurement data.', 'Further various combinations of classification algorithms may be used.', 'For example, a multiple tree structure of the same classification algorithm or of differing classification algorithms may be implemented.', 'A few example embodiments have been described in detail above; however, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the scope of the present disclosure or the appended claims.', 'Accordingly, such modifications are intended to be included in the scope of this disclosure.', 'Likewise, while the disclosure herein contains many specifics, these specifics should not be construed as limiting the scope of the disclosure or of any of the appended claims, but merely as providing information pertinent to one or more specific embodiments that may fall within the scope of the disclosure and the appended claims.', 'Any described features from the various embodiments disclosed may be employed in combination.', 'In addition, other embodiments of the present disclosure may also be devised which lie within the scope of the disclosure and the appended claims.', 'Additions, deletions and modifications to the embodiments that fall within the meaning and scopes of the claims are to be embraced by the claims.', 'Certain embodiments and features may have been described using a set of numerical upper limits and a set of numerical lower limits.', 'It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, or the combination of any two upper values are contemplated.', 'Certain lower limits, upper limits and ranges may appear in one or more claims below.', 'Numerical values are “about” or “approximately” the indicated value, and take into account experimental error, tolerances in manufacturing or operational processes, and other variations that would be expected by a person having ordinary skill in the art.', 'The various embodiments described above can be combined to provide further embodiments.', 'These and other changes can be made to the embodiments in light of the above-detailed description.', 'In general, in the following claims, the terms used should not be construed to limit the claims to the specific embodiments disclosed in the specification and the claims, but should be construed to include other possible embodiments along with the full scope of equivalents to which such claims are entitled.', 'Accordingly, the claims are not limited by the disclosure.'] | ['1.', 'A method for detecting while drilling an anomaly in measurement data captured by a downhole tool, comprising:\nobtaining, while drilling, the measurement data, the measurement data comprising a plurality of measurement channels for a time point of a plurality of time points at which measurements were recorded;\nobtaining reference data including healthy reference data and faulty reference data;\npre-processing the measurement data by modeling at least one measurement channel of the plurality of measurement channels using modeling parameters to produce pre-processed measurement data;\ndetermining a first distance between the pre-processed measurement data and the healthy reference data;\ndetermining that the first distance exceeds a first threshold for the first distance;\nin response to determining that the first distance exceeds the first threshold for the first distance, determining a second distance between the pre-processed measurement data and the faulty reference data;\ndetermining whether the second distance exceeds a second threshold;\ngenerating, while drilling and in response to determining that the first distance exceeds the first threshold for the first distance, a first report indicating detection of the anomaly in the measurement data;\ngenerating, while drilling, a second report indicating faulty measurement data in response to determining the second distance does not exceed the second threshold distance; and\ninitiating service or repair of the downhole tool based at least in part on one or more of the first and second reports.', '2.', 'The method of claim 1, wherein the pre-processing of the measurement data further includes:\ndetermining a correlation coefficient between a first measurement channel of the plurality of measurement channels and a second measurement channel of the plurality of measurement channels;\ndetermining whether the correlation coefficient exceeds a threshold for the correlation coefficient; and\nexcluding at least one of the first measurement channel and the second measurement channel from the pre-processed measurement data if the correlation coefficient exceeds the threshold for the correlation coefficient.', '3.', 'The method of claim 1, wherein the at least one measurement channel comprises an array of measurements and wherein modeling the at least one measurement channel further includes linearly fitting at least one segment of the array and representing the at least one segment by the modeling parameters that include a slope and an intercept.', '4.', 'The method of claim 1, wherein the first distance is a Mahalanobis distance.', '5.', 'A system comprising:\na measurement data storage that stores measurement data for a plurality of depths of a downhole tool, wherein the measurement data comprises a plurality of measurement channels for each depth of the plurality of depths;\na reference data storage that stores healthy reference data for each depth of the plurality of depths and faulty reference data;\na detection system, coupled to the measurement data storage and the reference data storage, that: obtains the measurement data from the measurement data storage; obtains the healthy reference data and the faulty reference data from the reference data storage; pre-processes the measurement data by modeling at least one measurement channel of the plurality of measurement channels using modeling parameters to produce pre-processed measurement data; determines a first distance between the pre-processed measurement data for each depth of the plurality of depths and the healthy reference data for each depth of the plurality of depths; determines that the first distance exceeds a first threshold for the first distance; in response to determining that the first distance exceeds the first threshold for the first distance, determines a second distance between the pre-processed measurement data and the faulty reference data; determines whether the second distance exceeds a second threshold; and outputs, while drilling, a first report indicating detection of an anomaly in the measurement data in response to determining that the first distance exceeds the first threshold, and outputs, while drilling, a second report indicating faulty measurement data in response to determining that the second distance does not exceed the second threshold distance, wherein one or more of the first and second reports corresponds to scheduling of a service or repair of the downhole tool.', '6.', 'The system of claim 5 wherein the measurement data is captured at a first time point of a plurality of time points for which measurements are captured and the report indicates detection of the anomaly at the first time point.', '7.', 'The system of claim 5 wherein the first distance is a Mahalanobis distance and the plurality of measurement channels include a Nuclear Magnetic Resonance measurement made by the downhole tool and a tuning measurement and resonant frequency of an antenna of the downhole tool.', '8.', 'The system of claim 5 wherein the at least one measurement channel comprises an array of measurements and wherein modeling the at least one measurement channel further includes linearly fitting at least one segment of the array and representing the at least one segment by the modeling parameters.', '9.', 'The system of claim 5 wherein the pre-processing of the measurement data further includes:\ndetermining a correlation coefficient between a first measurement channel of the plurality of measurement channels and a second measurement channel of the plurality of measurement channels;\ndetermining whether the correlation coefficient exceeds a threshold for the correlation coefficient; and\nexcluding at least one of the first measurement channel and the second measurement channel from the pre-processed measurement data if the correlation coefficient exceeds the threshold for the correlation coefficient.', '10.', 'A method for detecting while drilling an anomaly in measurement data captured by a downhole tool, the method comprising:\nobtaining, while drilling, the measurement data, the measurement data including a plurality of measurement channels for a time point of a plurality of time points at which measurements were recorded;\nobtaining reference data including healthy reference data and faulty reference data;\ntraining a classification algorithm using the healthy reference data and faulty reference data;\npre-processing the measurement data by modeling at least one measurement channel of the plurality of measurement channels using modeling parameters to produce pre-processed measurement data;\ndetermining whether the measurement data is classified as healthy or faulty based at least in part on evaluating the pre-processed measurement data using the classification algorithm;\nassigning, using the classification algorithm, a weight to each measurement channel of the plurality of measurement channels, the weight indicating a degree to which data from a respective measurement channel contributed to the determination of healthy or faulty measurement data;\noutputting, while drilling, a report indicating that the measurement data is faulty and identifying at least one of the plurality of measurement channels based on the assigned weight, in response to determining that the measurement data is classified as faulty; and\ninitiating service or repair of the downhole tool based at least in part on the report.\n\n\n\n\n\n\n11.', 'The method of claim 10 wherein the evaluating of the pre-processed measurement data using the classification algorithm further includes querying the plurality of measurement channels at a plurality of nodes of the classification algorithm.', '12.', 'The method of claim 10, wherein the classification algorithm is a classification and regression tree (CART) algorithm or a random forest algorithm.', '13.', 'The method of claim 10 wherein the at least one measurement channel comprises an array of measurements and wherein the modeling of the at least one measurement channel further includes linearly fitting at least one segment of the array of measurements and representing the at least one segment by the modeling parameters.', '14.', 'The method of claim 10, wherein the at least one measurement channel comprises an array of measurements and wherein the modeling of the at least one measurement channel further include representing the array of measurements by a peak amplitude of the array of measurements and a frequency of the array of measurements.'] | ['FIG.', '1 depicts an environment for downhole tool health prognosis in a drilling operation according to one or more embodiments disclosed herein;; FIG.', '2 depicts an example of measurement data recorded by the downhole tool according to one or more embodiments disclosed herein;; FIG.', '3 depicts a flow diagram of a method for pre-processing measurement data according to one or more embodiments disclosed herein;; FIG.', '4 depicts a flow diagram of a method for classifying the measurement data according to one or more embodiments disclosed herein;; FIG.', '5 depicts a flow diagram of a method for performing a Mahalanobis distance analysis on the measurement data according to one or more embodiments disclosed herein;; FIG.', '6 depicts an example of a distribution of the Mahalanobis distances of measurement data of a drilling operation according to one or more embodiments disclosed herein;; FIG.', '7 depicts an example of a CART-based classification of measurement data according to one or more embodiments disclosed herein;; FIG.', '8 depicts measurement data classification using the CART algorithm according to one or more embodiments disclosed herein; and; FIG.', '9 depicts magnitudes by which channels of measurement data contributed to a faulty classification according to one or more embodiments disclosed herein.; FIG.', '1 depicts an environment 100 for downhole tool 102 health prognosis in a drilling operation according to one or more embodiments disclosed herein.', 'The environment 100 includes a downhole tool 102, a measurement data storage system 104, a detection system 106 and a reference data storage system 108.', 'The downhole tool 102 further includes a plurality of sensors 110 (singularly referred to herein as sensor 110).', "The downhole tool 102 may, for example, be a drilling apparatus used for exploration of oil or gas under the Earth's surface.; FIG.", '2 depicts an example of measurement data made by the downhole tool 102 according to one or more embodiments disclosed herein.', 'At various depths, the downhole tool 102 may make various measurements.', 'The measurements are shown to include a depth measurement 202, a time measurement 204, a Nuclear Magnetic Resonance measurement 206, an antenna tuning measurement 208, a tool temperature measurement 210 and an antenna resonant frequency 212.', 'It is recognized that the measurements shown in FIG.', '2 are exemplary and in various embodiments additional or different measurements may be made and recorded.', 'The measurements are shown in FIG.', '2 for one depth or time point.', 'However, as may be recognized, the measurement data includes measurements that are made at a plurality of depths or time points.', '; FIG.', '3 depicts a method for pre-processing measurement data according to one or more embodiments disclosed herein.', 'In the method 300, the detection system 106 described with reference to FIG.', '1 receives, at block 302, the measurement data from the measurement data storage system.', 'The measurement data as described herein includes channels that are represented by arrays of multiple quantities.', 'For example, the Nuclear Magnetic Resonance measurement 206 may include over a thousand samples for each depth.', 'At block 304, the detection system 106 performs channel modeling on array channels.', 'Different types of channels may be modeled differently.', 'For example, the Nuclear Magnetic Resonance echo measurement channel data may be a logarithmic decay and log-linear fitting may be used to represent the measurement data more compactly.', 'In log-linear fitting, the logarithmic decay data may be segmented into two or more segments and each segment may be represented by modeling parameters, such as an intercept and a slope for the segment.', 'Further, an indication of a residual value of the measured Nuclear Magnetic Resonance to the fitted line may be provided for each segment.; FIG.', '4 depicts a flow diagram of a method for classifying the measurement data according to one or more embodiments disclosed herein.', 'In the method 400, the detection system 106 obtains the pre-processed measurement data at block 402.', 'As described herein, the recorded measurement data may be compressed and the redundancies of the measurement data may be removed to obtain the pre-processed measurement data.; FIG.', '5 depicts a flow diagram of a method for performing a Mahalanobis distance analysis according to one or more embodiments disclosed herein.', 'In the method 500, the detection system 106 determines a first Mahalanobis distance 502 between the pre-processed measurement data and the healthy reference data.', 'The first Mahalanobis distance is determined as: MD1({right arrow over (x)},{right arrow over (y)})=√{square root over (({right arrow over (x)}−{right arrow over (y)})TS−1({right arrow over (x)}−{right arrow over (y)}))}\u2003\u2003(Equation (1)) where {right arrow over (x)} is a vector that includes the pre-processed measurement data, {right arrow over (y)} is a vector that includes the healthy reference data, S is the covariance matrix, (.)−1 represents the matrix inverse operator and (.)T represents the transpose operator.', '; FIG.', '6 depicts an example of a distribution of the Mahalanobis distances of measurement data of a drilling operation according to one or more embodiments disclosed herein.', 'The distribution of the Mahalanobis distances for data measurements made at various time points indicates that about 90% of the Mahalanobis distances are between 4 and 5.', 'Further, only 1% of the Mahalanobis distances are greater than 7.52.', 'Further, temporally plotting the Mahalanobis distances shows indicates that failure was observed in the measurements made between the 10th and 19th hour of the drilling operation as represented by spikes of the Mahalanobis distances for these measurement.', 'Outside of the range between the 10th and 19th hour, a failure was not detected.', '; FIG.', '7 depicts an example of a CART-based classification of measurement data according to one or more embodiments disclosed herein.', 'After training the CART algorithm with the healthy and faulty reference measurement data, the CART algorithm develops a decision tree for determining whether measurement data is healthy or faulty.', 'The decision tree includes a plurality of nodes 602 to query the measurement data.', 'Based on the outcome of the query at a node, the branch 604 of the decision tree is followed to a subsequent node 602, where the measurement data is queried again.', 'The branches 604 of the decision tree are followed until the tree terminates and the measurement data is classified as healthy 606 or faulty 608.; FIG.', '8 depicts measurement data classification using the CART algorithm according to one or more embodiments disclosed herein.', 'In FIG. 8, a value of ‘1’ indicates healthy measurement data, whereas a value of ‘0’ indicates faulty data.', 'As illustrated in FIG. 8, the majority of the measurement data recorded by the downhole tool 102 is healthy with the exception of the measurement data recorded between the 22nd and 25th hours of operation, which is classified as faulty.', 'The outcomes of the classification by the CART algorithm may be used to generate a report indicating that the downhole tool 102 should be serviced or repaired.; FIG.', '9 depicts magnitudes by which channels of measurement data contributed to a faulty classification according to one or more embodiments disclosed herein.', 'In FIG.', '9, the measurement data has 57 channels.', 'Three of the channels were associated with a relatively high contribution to the faulty classification of the measurement data.', 'The identification of the primary contributing channels to the faulty classification may be provided in a report generated by the detection system 106.', 'Further, the identification may be used by personnel for the repair or maintenance of the downhole tool.'] |
|
US11105157 | Method and system for directional drilling | Apr 5, 2020 | Matthew Summers, Ginger Vinyard Hildebrand, Wayne Kotovsky, Chunling Gu Coffman, Rustam Isangulov | Schlumberger Technology Corporation | International Search Report and Written Opinion for the counterpart International patent application PCT/US2015/041645 dated Sep. 21, 2015.; International Preliminary Report on Patentability for the counterpart International patent application PCT/US2015/041645 dated Mar. 9, 2017. | 6438495; August 20, 2002; Chau et al.; 7000710; February 21, 2006; Umbach; 7059427; June 13, 2006; Power et al.; 7139689; November 21, 2006; Huang; 7957946; June 7, 2011; Pirovolou; 8210283; July 3, 2012; Benson et al.; 8360171; January 29, 2013; Boone et al.; 8510081; August 13, 2013; Boone et al.; 8528663; September 10, 2013; Boone; 8596385; December 3, 2013; Benson et al.; 8794353; August 5, 2014; Benson et al.; 8996396; March 31, 2015; Benson et al.; 9157309; October 13, 2015; Benson et al.; 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2014; Boone et al.; 20140190747; July 10, 2014; Hay; 20140291023; October 2, 2014; Edbury; 20140367170; December 18, 2014; Hoehn; 20150015250; January 15, 2015; Gzara et al.; 20150107899; April 23, 2015; Fisher, Jr.; 20150233229; August 20, 2015; Benson et al.; 20150247397; September 3, 2015; Samuel; 20160040526; February 11, 2016; Mebane, III; 20160298392; October 13, 2016; Gajji; 20170037722; February 9, 2017; Jeffryes et al.; 20170306702; October 26, 2017; Summers et al.; 20190048707; February 14, 2019; Benson et al.; 20200063546; February 27, 2020; Weideman | 2014/121448; August 2014; WO | ['A method for wellbore directional drilling includes selecting a starting and stopping spatial position of at least one portion of the wellbore.', 'A sequence of sliding and rotary drilling operations within the portion is determined to calculate a wellbore trajectory.', 'The sequence has at least one drilling operating parameter.', 'The operations include a constraint on the drilling operating parameter or the calculated trajectory.', 'The calculated trajectory includes a projected steering response of a steerable motor in response to the at least one drilling operating parameter.', 'Drilling the portion of the wellbore is started.', 'A spatial position of the wellbore during drilling is determined at least one point intermediate the starting and stopping positions.', 'Using a relationship between the projected steering response and the drilling operating parameter, the drilling parameter and/or the constraint are adjusted based on the measured spatial position and the stopping spatial position.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a divisional application of co-pending U.S. patent application Ser.', 'No. 15/507,615 filed on Feb. 28, 2017 under National Phase of the International patent application number PCT/US2015/041645, filed on Jul. 23, 2015 which claims priority to U.S. Provisional Patent Application Ser.', 'No. 62/042,869, filed on Aug. 28, 2014, each of which is incorporated herein by reference in its entirety.', 'BACKGROUND\n \nThis disclosure is related to the field of directional drilling of subsurface wellbores.', 'More specifically, the disclosure is related to optimizing performance of directional drilling using steerable drilling motors.', 'Wellbores drilled through subsurface formations are known in the art to be drilled along selected geodetic trajectories (“directional drilling”) so as to traverse a path from the surface location of the well to one or more selected subsurface target positions located at predetermined depths and geodetic locations away from the surface location.', 'One technique for directional drilling known in the art is to use “steerable motors” as part of a drilling tool assembly disposed proximate a bottom end of a drill string.', 'A steerable motor is a device which couples within a drill string and is operated to rotate a drill bit coupled to an output end of the motor.', 'The motor may be operated, e.g., by drilling fluid pumped through the drill string by one or more pumps disposed at the surface.', 'Operating components of the motor that generate rotational energy to turn the drill bit are disposed in a housing that has a bend along its length.', 'The angle subtended by the bend may range from a fraction of a degree to several degrees, depending on the particular selected trajectory for any part or all of a directionally drilled wellbore.', 'Steerable motors are operated in one of two modes.', 'In “rotary drilling” mode, the entire drill string, including the steerable motor, is rotated from equipment on a drilling unit (“rig”) at the surface.', 'The equipment may be a kelly/rotary table combination or a top drive.', 'In rotary drilling mode, the direction along which the well trajectory exists (defined by geodetic azimuth and inclination from vertical) is maintained substantially constant, that is, the direction of the well does not change.', 'When it is desired to change the well trajectory in any aspect, the rotation of the drill string is stopped and the steerable motor is oriented so that the bend in the motor housing is directed toward the intended change of direction in the well trajectory.', 'Such operation is known as “slide drilling.”', 'It is known in the art that slide drilling typically reduces the rate at which the wellbore is drilled (“rate of penetration”—ROP) as contrasted with rotary drilling.', 'Thus, in order to minimize the time of a particular wellbore drilling operation, it may be desirable to minimize the amount of time engaged in slide drilling to drill the well along the selected trajectory.', 'However, minimizing the sliding distance may require higher trajectory change rates, which may be limited by equipment capabilities and can result in increased wellbore tortuosity.', 'Increased wellbore tortuosity may, for example, cause complications during wellbore completion operations.', 'Therefore, the slide drilling—rotatory drilling sequences should be planned such that the overall speed of drilling is balanced with wellbore quality.', 'Further, while the trajectory change effected by slide drilling for any particular configuration of steerable motor and drilling tool combination may be predicted with some degree of accuracy, the actual well trajectory response of any particular steerable motor and drilling tool combination may be affected by factors that may not be precisely known a priori, as non-limiting examples, the mechanical properties and spatial distribution thereof of the various subsurface formations, manufacturing tolerances in the drilling tool assembly and the particular steerable motor, the variability of the actual drilling parameters used (i.e., execution variability, namely the amount of time required to obtain the selected motor orientation during slide drilling may be highly variable and the ability to hold the correct orientation may be highly variable.', 'Beyond that, predictions of directional drilling performance are based on assumptions about drilling parameters that may or may not be correct) and how the particular type of drill bit used interacts with the subsurface formations to drill through them to lengthen the wellbore.', 'Still further, variations in the selected orientation angle of the bend in the motor housing may vary during sliding as a result of, among other factors, changes in reactive torque as the torque loading on the steerable motor changes.', 'Such variations are impracticable to eliminate because of such factors as variability in friction between the wall of the wellbore and the components of the drill string and changes in the rate at which certain formations are drilled by the drill bit, among others.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a schematic view of an example directional drilling system that may be used in accordance with the present disclosure.', 'FIG.', '2\n is a block diagram of an example directional drilling control system according to the present disclosure.', 'FIG.', '3\n shows a flow chart of an example directional drilling method.\n \nFIG.', '4\n shows an example of non-linear finite element analysis of expected drilling tool and steerable motor response.\n \nFIG.', '5\n shows an example computer system that may be used in some embodiments.', 'DETAILED DESCRIPTION\n \nFIG.', '1\n shows an example directional drilling system that may be used in some embodiments according to certain aspects of the present disclosure.', 'A drilling rig (“rig”) is designated generally by reference numeral \n11\n.', 'The rig \n11\n shown in \nFIG.', '1\n is a land rig, but this is for illustration purposes only, and is not intended to be a limitation on the scope of the present disclosure.', 'As will be apparent to those skilled in the art, methods and systems according the present disclosure may apply equally to marine drilling rigs, including, but not limited to, jack-up rigs, semisubmersible rigs, and drill ships.', 'The rig \n11\n includes a derrick \n13\n that is supported on the ground above a rig floor \n15\n.', 'The rig \n11\n has lifting gear, which includes a crown block \n17\n mounted to the derrick \n13\n and a traveling block \n19\n.', 'The crown block \n17\n and the traveling block \n19\n are interconnected by a cable \n21\n that is driven by a draw works \n23\n to control the upward and downward movement of the traveling block \n19\n.', 'The traveling block \n19\n carries a hook \n25\n from which a top drive \n27\n may be suspended.', 'The top drive \n27\n rotatably supports a drill pipe string (“drill string”), designated generally by reference numeral \n35\n, in a wellbore \n33\n.', 'The top drive \n27\n may be operated to rotate the drill string \n35\n in either direction, or to apply a selected amount of torque to the drill string \n35\n.', 'According to one example embodiment, the drill string \n35\n may be coupled to the top drive \n27\n through an instrumented top sub \n29\n, although this configuration is not a limitation on the scope of the present disclosure.', 'A surface drill string torque sensor \n53\n may be provided in the instrumented top sub \n29\n.', 'However, the particular location of the surface torque sensor \n53\n is not a limitation on the scope of the present disclosure.', 'A surface drill pipe rotational orientation sensor \n65\n that provides measurements of drill string angular orientation or “surface” tool face may also be provided in the instrumented top sub \n29\n.', 'However, the particular location of the surface drill string orientation sensor \n65\n is not a limitation on the scope of the present disclosure.', 'In one example embodiment, the instrumented top sub \n29\n may be a device sold by 3PS, Inc., Cedar Park, Texas known as “Enhanced Torque and Tension Sub.”', 'The surface torque sensor \n53\n may be implemented, for example, as a strain gage in the instrumented top sub \n29\n.', 'The torque sensor \n53\n may also be implemented as a current measurement device for an electrically operated rotary table or top drive motor, or as a pressure sensor for a hydraulically operated top drive.', 'The drill string torque sensor \n53\n provides a signal which may be sampled electronically.', 'The surface orientation sensor \n65\n may be implemented as an integrating angular accelerometer (and the same may be used to provide measurements related to surface torque).', 'Irrespective of the instrumentation used, the torque sensor \n53\n provides a measurement corresponding to the torque applied to the drill string \n35\n at the surface by the top drive \n27\n or rotary table (not shown), depending on how the rig \n11\n is equipped.', 'Other parameters which may be measured, and the corresponding sensors used to make the measurements, will be apparent to those skilled in the art and include, without limitation, fluid pressure in the drill string \n35\n and the weight suspended by the hook \n29\n, which may be implemented as a sensor such as a strain gauge used as a hookload sensor \n67\n.', 'Measurements of the suspended weight may enable the rig operator (“driller”) to estimate or determine the amount of the total drill string weight that is transferred to a drill bit \n40\n (called “weight on bit”—WOB) coupled to the end of the drill string \n35\n.', 'The drawworks \n29\n in some embodiments may include an automatic controller \n69\n of any type known in the art that can enable automatic control of the rate at which the drill string \n35\n is allowed to move into the wellbore, thus enabling automatic control over the WOB, among other parameters.', 'One non-limiting example of such a drawworks controller is described in U.S. Pat.', 'No. 7,059,427 issued to Power et al.', 'The drill string \n35\n may include a plurality of interconnected sections of drill pipe (not shown separately) and a bottom hole assembly (“BHA”) \n37\n.', 'The BHA \n37\n may include stabilizers, drill collars and a suite of measurement while drilling (“MWD”) instruments, including a directional sensor \n51\n.', 'As will be explained in detail below, the directional sensor \n51\n provides, among other measurements, toolface angle measurements, as well as wellbore geodetic or geomagnetic direction (azimuth) and inclination measurements.', 'A steerable drilling motor (“steerable motor”) \n41\n may be connected near the bottom of the BHA \n37\n.', 'The steerable motor \n41\n may be, but is not limited to, a positive displacement motor, a turbine, or an electric motor that can turn the drill bit \n40\n independently of the rotation of the drill string \n35\n.', 'The steerable motor \n41\n may be disposed in an elongated housing configured to be coupled in the drill string \n35\n.', 'The housing may include a bend along its length.', 'A direction of the bend in the steerable motor housing is referred to as the “toolface angle.”', 'The toolface angle of the steerable motor is oriented in a selected rotary orientation to correct or adjust the azimuth and/or and inclination of the wellbore \n33\n during “slide drilling”, that is, drilling operations in which the drill bit \n40\n is turned only by the action of the steerable motor \n41\n while the remainder of the drill string \n35\n is controlled by the top drive \n27\n (or rotary table if the rig \n11\n is so equipped) to maintain the toolface angle.', 'The toolface angle of the steerable motor \n41\n may be calibrated to toolface measurements made by the MWD directional sensor \n51\n after assembly of the BHA \n37\n so that the system user may be able to determine the steerable motor \n41\n toolface angle at selected times.', 'Drilling fluid is delivered to the interior of the drill string \n35\n by mud pumps \n43\n through a mud hose \n45\n.', 'During rotary drilling, the drill string \n35\n is rotated within the wellbore \n33\n by the top drive \n27\n (or kelly/rotary table if such is used on a particular rig).', 'The top drive \n27\n is slidingly mounted on parallel vertically extending rails (not shown) or other similar structure to resist rotation as torque is applied to the drill string \n35\n.', 'As explained above, during slide drilling, the drill string \n35\n may be rotationally controlled by the top drive \n27\n to maintain a selected steerable motor toolface angle while the drill bit \n40\n is rotated by the steerable motor \n41\n.', 'The steerable motor \n41\n is ultimately supplied with drilling fluid by the mud pumps \n43\n through the mud hose \n45\n and through the drill string \n35\n.', 'The driller may operate the top drive \n27\n to change the toolface orientation of the steerable motor \n41\n during slide drilling by rotating the entire drill string \n35\n.', 'A top drive \n27\n for rotating the drill string \n35\n is illustrated in \nFIG.', '1\n, but the top drive shown is for illustration purposes only, as previously explained, and is not intended to limit the scope of the present disclosure.', "Those skilled in the art will recognize that systems and methods according to the present disclosure may also be used in connection with other equipment used to turn the drill string at the earth's surface.", 'One example of such other equipment is a rotary table and kelly bushing (neither shown) to apply torque to the drill string \n35\n.', 'The cuttings produced as the drill bit \n40\n drills into the subsurface formations are carried out of the wellbore \n33\n by the drilling fluid supplied by the mud pumps \n43\n.', 'The discharge side of the mud pumps \n43\n may include a drill string pressure sensor \n63\n.', 'The drill string pressure sensor \n63\n may be in the form of a pump pressure transducer in hydraulic communication with the mud hose \n45\n connected between the mud pumps \n43\n and the top drive \n27\n (or a swivel on kelly/rotary table rigs).', 'The pressure sensor \n63\n makes measurements corresponding to the pressure inside the drill string \n35\n.', 'The actual location of the pressure sensor \n63\n is not intended to limit the scope of the present disclosure.', 'Some embodiments of the instrumented top sub \n29\n, for example, may include a pressure sensor configured to measure pressure inside the drill string \n35\n.', 'When a portion of the wellbore \n33\n has its trajectory changed by slide drilling to a desired direction by slide drilling, if the intended or planned trajectory of the wellbore then includes maintaining such direction for a selected length or axial distance, the driller may operate the top drive \n27\n to rotate the entire drill string \n35\n.', 'Such operation is referred to as “rotary drilling” and when performed with a steerable drilling motor results in the direction of the wellbore remaining substantially constant.', 'FIG.', '2\n shows a block diagram of a directional drilling control system (“system”) according to an embodiment of the present disclosure.', 'The system may accept as input signals from devices including the directional sensor \n51\n (in an MWD system as explained with reference to \nFIG.', '1\n, for example) which, as explained above, produces a signal indicative of the toolface angle of the steerable motor \n41\n.', 'The system may accept as input a signal from the drill string torque sensor \n53\n.', 'The torque sensor \n53\n provides a measure of the torque applied to the drill string (\n35\n in \nFIG.', '1\n) at the surface.', 'The system may also accept as input a signal from the drill string pressure sensor \n63\n that provides measurements of the drill string internal fluid pressure.', 'The system may also accept as input signals from the surface drill pipe orientation sensor \n65\n.', 'The system may also accept as input measurements from the hookload sensor \n67\n.', 'In \nFIG.', '2\n the outputs of the directional sensor \n51\n, the torque sensor \n53\n, the pressure sensor \n63\n, hookload sensor \n67\n and the drill pipe orientation sensor \n65\n may be received at or otherwise operatively coupled to a processor \n55\n.', 'The processor \n55\n may be programmed to process signals received from the above described sensors \n51\n, \n53\n, \n63\n, \n67\n and \n65\n.', 'The processor \n55\n may also receive user input from user input devices, indicated generally at \n57\n.', 'User input devices \n57\n may include, but are not limited to, a keyboard, a touch screen, a mouse, a light pen, or a keypad.', 'The processor \n55\n may also provide visual output to a display \n59\n.', 'The processor \n55\n may also provide output to a drill string rotation controller \n61\n that operates the top drive or rotary table (\nFIG.', '1\n) to rotate the drill string (\n35\n in \nFIG.', '1\n) in a manner as will be further explained below.', 'The processor \n55\n may also provide output to operate the drawworks controller \n69\n to automatically control the WOB in some embodiments.', 'In some embodiments, the processor \n55\n may be programmed to operate the drawworks controller \n69\n to provide a substantially constant value or other values of drill string fluid (mud) pressure a selected amount above the pressure existing when the drill bit (\n40\n in \nFIG.', '1\n) is not on the bottom of the wellbore (\n33\n in \nFIG.', '1\n) and thus exerts no torque (i.e., the no load pressure).', 'Referring again to \nFIG.', '1\n, as the wellbore \n33\n drilling commences, the wellbore \n33\n may be substantially vertical.', 'At a selected depth in the wellbore \n33\n, called the “kickoff point” K, directional drilling along a selected trajectory may be initiated.', 'Initiating directional drilling may be performed by having the driller operate the top drive \n27\n (or kelly/rotary table if such are used on a particular rig) to rotate the drill string \n35\n to a rotary orientation such that a selected toolface angle (as may be measured by the directional sensor \n51\n) of the steerable motor \n41\n is obtained.', 'The drill string \n35\n may be lowered into the wellbore \n33\n such that some of the axial loading (weight) of the drill string \n35\n is transferred to the drill bit \n40\n.', 'When the drill bit \n40\n engages the subsurface formations and begins to drill them, the steerable motor \n41\n will exert torque on the drill bit \n40\n.', 'A reactive torque will be generated and applied to the drill string \n35\n, the reactive torque being in a direction opposite to the torque generated by the drilling motor \n41\n.', 'The driller may operate the top drive \n27\n to apply torque in a direction opposite to the reactive torque such that the selected steerable motor toolface angle is substantially maintained.', 'It will be appreciated by those skilled in the art that when the wellbore is substantially vertical, the toolface measurement may be referenced to a geodetic or geomagnetic reference.', 'Such toolface measurement may be referred to as “magnetic toolface” (MTF).', "As the wellbore inclination increases above a threshold level (usually about five degrees from vertical), the toolface angle measurement may be referenced to Earth's gravity (i.e., vertical).", 'Such toolface measurement may be referred to as “gravity toolface” (GTF).', 'The orientation sensor \n65\n may generate a signal indicative of the drill string \n35\n rotational orientation at the surface when such conditions are maintained.', 'As will be appreciated by those skilled in the art, the actual rotational orientation of the drill string \n35\n as measured by the orientation sensor \n65\n may depend on, among other factors, the length of the drill string \n35\n and the torsional properties of the components of the drill string \n35\n.', 'Thus, the measured drill string orientation at the surface may differ from the measured toolface angle (e.g., by directional sensor \n51\n), however, provided that the same surface measured rotational orientation is maintained, it may be assumed for purposes of relatively short lengths of the wellbore, limited in length to a selected number (e.g., one or two) of segments of drill pipe making up the drill string \n35\n that maintaining a selected surface measured drill string orientation will result in the toolface angle of the steerable motor \n41\n being similarly maintained (provided that other drilling operating parameters are maintained).', 'The foregoing relationship between the surface measured drill string orientation and the steerable motor toolface angle may prove useful if the toolface measurement from the directional sensor \n51\n is communicated to the surface using MWD telemetry techniques known in the art, which may provide only one to three toolface measurements per minute at the surface.', 'During directional drilling, each time one or more segments are added to the drill string \n35\n or it is otherwise lengthened from the top drive (or kelly) to the drill bit \n40\n, the relationship between the measurement made by the drill string orientation sensor \n65\n and the toolface orientation (as may be measured by the directional sensor \n51\n) may change, but the relationship may be readily reestablished for the changed length drill string \n35\n.', 'Directional drilling by slide drilling as described above may continue until a desired wellbore inclination angle and subsurface location away from the surface location are obtained, such as indicated at X in \nFIG.', '1\n.', 'Thereafter, the wellbore \n35\n may be drilled, for example, along a substantially constant trajectory or any other selected trajectory to another selected subsurface location point, e.g., as indicated by F in \nFIG.', '1\n.', 'The foregoing maintaining the toolface angle of the steerable motor \n41\n by maintaining a measured drill string orientation at the surface may be performed automatically by operation of the drill string rotation controller (\n61\n in \nFIG.', '2\n) in response to command signals generated by the processor (\n55\n in \nFIG.', '2\n).', 'The processor \n55\n may be programmed to maintain a selected surface measured orientation of the drill string by suitable programming to respond to the sensor inputs as described with reference to \nFIG.', '2\n and particularly with respect to the measurements of torque and rotational orientation of the drill string made at the surface.', 'Maintaining orientation of the drill string so that the toolface angle as measured by the MWD directional sensor \n51\n may also be manually performed by the driller operating the top drive \n27\n and drawworks \n23\n such that the directional sensor measurements of toolface correspond to the desired change in direction of the wellbore trajectory.', 'In an example method for directional drilling according to the present disclosure, and referring to \nFIG.', '3\n, a drilling plan may include a surface geodetic position of a wellbore, as shown in \nFIG.', '1\n, and one or more subsurface “target” geodetic positions \n70\n.', 'For the wellbore to traverse the geodetic distance and subsurface depth from the surface position to the one or more subsurface target positions, a well path (or trajectory) may be selected at \n71\n.', 'The well path may be selected based on certain constraints at \n72\n.', 'The constraints may include, without limitation, a minimum acceptable radius of curvature of the well path (referred to as a maximum “dog leg severity”), the turn/build capability of the particular steerable motor, the maximum permissible true vertical depth (TVD) of the wellbore, the minimum inclination of the wellbore from vertical, a predetermined permissible distance from other wellbores, lease lines, anti-targets, or other constraints and a maximum distance at any point along the well trajectory between the actual well trajectory and the predetermined well plan trajectory.', 'In an example embodiment, an optimization may be performed to generate a preferred well trajectory.', 'The optimization may include an algorithm to select a path which meets one or more optimization criteria.', 'Non-limiting examples of such optimization criteria may include minimized dog leg severity, minimized torque and drag inducing factors, e.g. total curvature, well path tortuosity, limiting path curvature in specific spatial regions, especially to avoid slide drilling in certain formations, total path length to any one or more targets, selected intermediate subsurface well positions being along the selected trajectory, slide drilling length criteria (e.g., not sliding less than or more than a predetermined wellbore length) and maximizing drilling penetration rate (ROP) for any one or more selected segments of the wellbore.', 'ROP in the present context may mean instantaneous drilling rate, or may mean a minimized time to drill a selected length of the wellbore.', 'One or more intermediate targets along the well trajectory may be selected as explained above at \n73\n in \nFIG.', '3\n.', 'At \n74\n, and as will be explained below with reference to \nFIG.', '4\n, drilling operating parameters \n74\n may be selected to cause the well to be drilled along the selected well path.', 'At \n75\n, drilling may commence using the selected drilling operating parameters.', 'During drilling, the actual position of the wellbore with reference to the planned trajectory as well as the actual drilling parameters may be measured.', 'If it is determined that the one or more well path targets may be reached by using drilling parameters and well path parameters within the constraints, at \n77\n, drilling the well may continue.', 'At \n76\n, if any one or more intermediate or the final target cannot be traversed by the wellbore using drilling operating parameters and well path parameters within the selected constraints, the process may return to \n70\n, wherein it may be required to generate a different well trajectory capable of traversing the remaining target location(s) while maintaining drilling operating parameters and well trajectory parameters within the constraints.', 'In some embodiments, one or more of the constraints may be adjusted or removed.', 'Such adjustment or removal may depend on, e.g., and without limitation, the expected risk of wellbore or drill string mechanical failure, risk of collision with another well, risk of unacceptably traversing a geodetic boundary, or creating a well path having tortuosity such that completion of wellbore construction such as by cementing a casing or liner is made impracticable.', 'The foregoing are only examples of constraint modification or removal considerations and are not to be construed as limitations on the scope of the present disclosure.', 'If a well trajectory cannot be constructed such that the constraints are satisfied, then a new target may be selected.', 'In this case, an additional mechanism may be used to select the target.', 'In some embodiments, the processor (\n55\n in \nFIG. 2\n) or another processor (see \nFIG.', '5\n) may be programmed to automatically shift the original target(s) further along the selected trajectory (i.e., at greater measured depth) where constraints such as those mentioned above can be satisfied.', 'In some embodiments, if the target(s) cannot be shifted within a selected measured depth range while still satisfying the constraints described above, the processor may be programmed to generate a warning indicator to remove the drill string (\nFIG.', '1\n) from the wellbore and change one or more components of the BHA.', 'In some embodiments, as explained above, one or more of the constraints may be adjusted or removed under such conditions to enable reaching the depth-shifted target(s).', 'In some embodiments, the total well path may be subdivided into selected length (measured depth) intervals and the optimization described above may be performed for each interval or any subset thereof.', 'The foregoing element of a directional drilling process is equally applicable to any point along the actual trajectory of the wellbore at any measured depth.', 'That is, not only is the surface position usable as a starting point, any point during the drilling of the wellbore may be used as a starting point for further directional drilling to a subsequent intermediate target point or to a final target point at the planned end (maximum measured depth) of the wellbore.', 'From the initially generated wellbore trajectory, one or more intermediate target(s) along the well path may be selected based on criteria, e.g., and without limitation, user selection based on the initially planned trajectory, any one or more estimated subsequent well trajectory directional survey points, drill string stand length and/or on substantially equal length well segments.', 'The drilling operating parameters (at \n74\n in \nFIG.', '3\n) may be selected based on an example procedure as follows.', 'For a planned section of a wellbore, a model f (d1,d2,tf, WOBs, WOBr, RPM, . . . )', '=xt, vt, T, . . .', 'may be used to predict the resulting wellbore geodetic spatial location xt, wellbore orientation vt, and required drilling time T as a function of the slide drilling measured depth interval (from d1 to d2), the toolface orientation TF used while slide drilling, the weights on bit WOBs and WOBr used while slide drilling and rotary drilling, respectively, and the RPM used while rotary drilling, and other inputs as may be available and useful.', 'Examples of other inputs to the model f may include slide drilling differential pressure (i.e., increase in drilling fluid pressure above the no load pressure when WOB is zero) and drilling fluid flow rate.', 'Examples of other outputs of the model may include drilling tool/BHA component and drill string component wear indicia.', 'For any segment of the wellbore which is not intended to be drilled along a substantially constant direction, a model f (d1, d2, tf)=xt, vt may be used to predict the resulting wellbore geodetic spatial location xt and wellbore geodetic orientation vt based on selected drilling operating parameters and a measured slide drilling toolface angle.', 'By inverting f or applying optimization methods, the parameters d1, d2, tf, WOBs, WOBr, RPM, etc. may be determined in order to reach a target xt, vt, within a desired amount of time while satisfying other constraints (e.g. equipment wear, well path tortuosity, etc.).', 'A starting interval depth d1, an ending interval depth d2, and a slide drilling toolface angle tf are determined.', 'The model f may be used to predict the elapsed time, wellbore location/orientation, sliding efficiency factor (“SEF”) and torque and drag properties for each selected wellbore interval of slide drilling as a function of various drilling operating parameters and optionally formation properties.', 'The drilling operating parameters may include slide drilling depth interval(s), WOB, toolface orientation(s), drill string fluid pressure and bit rotary speed (RPM).', 'Optimization methods and inverted models may be used to find the parameters that optimize one or more drilling performance parameters while satisfying the constraints.', 'In its simplest form, the model f may be inverted for d1, d2 and tf.', 'However, other embodiments may use as input additional parameters such as explained above, including without limitation slide drilling WOB, rotary drilling WOB, rotary drilling bit RPM, slide drilling mud flow rate, and rotary drilling mud flow rate.', 'Some embodiments may invert f for a single slide drilling interval.', 'Other embodiments may determine the foregoing parameters for multiple slide drilling intervals.', 'Input parameters to the model f may include SEF, sliding curve response (“SCR”), tool face offset (TFO—the difference between the measured toolface from the directional sensor [\n51\n in \nFIG.', '2\n] and the actual steering response of the steerable motor (and its directional tendencies during rotary drilling) as determined by directional surveying at selected positions along the well trajectory) and trajectory constraints.', 'SCR and SEF may be adjusted during drilling of the wellbore (starting using initial values based on expected response values from the drill string, drilling operating parameters and the BHA components, including the specific steerable motor).', 'SEF sensitivity to weight on bit can be determined in order to optimize ROP without sacrificing steering constraints.', 'In an example embodiment, SCR may be used in the form of a weighted average based on measurements of the change in wellbore trajectory with respect to measured toolface angle and slide drilling interval length as will be further explained below.', 'The slide drilling interval(s) and associated parameters may be selected to obtain, for example, a desired well trajectory curvature, minimized well path tortuosity, and/or minimized distance to any one or more intermediate predetermined trajectory points along the planned well trajectory.', 'The slide drilling interval(s) can also be selected to keep the borehole within some particular volume in space.', 'Such a volume can be defined for example as the volume of points within various metrics of a reference trajectory, for example, the set of all points within 10 feet true vertical depth (TVD) above, 5 feet TVD below, 20 feet left and 20 feet right of the reference trajectory.', 'The volume need not be centered on the reference trajectory, for example in a curved section the volume may lie more (or completely) on the concave side of the curve.', 'The reference trajectory may be, for example, a well plan.', 'Slide intervals would be placed appropriately before a substantially straight trajectory would exit the volume, taking into account position and orientation uncertainties and the finite turning capability C of the BHA.', 'Slide intervals and associated parameters may also be selected based on borehole quality characteristics such as maximum dog leg severity (DLS) or borehole tortuosity as well as good directional drilling practices such as not slide drilling down while in a curve section.', 'It may not be possible to satisfy all constraints simultaneously.', 'In such circumstances, then the system can apply a preprogrammed prioritization or a user selected prioritization scheme, or the system may request user input as to instructions for how to resolve the conflict.', 'In some embodiments the driller or other system user may select drilling operating parameters (WOB and/or drill string pressure when slide drilling and rotary drilling and drill string RPM while rotary drilling) to optimize ROP while maintaining the measured well path within predetermined tolerances from the planned well path and/or constraints on the drilling operating parameters.', 'The foregoing may be performed to, for example and without limitation, optimize the ROP along any one or more selected intervals of the wellbore or to minimize the specific energy needed to drill one or more selected wellbore intervals.', 'Directional drillers often intentionally limit WOB below that which would produce optimum ROP in order to reduce variability in toolface orientation.', 'Such variation in toolface orientation may result from variations in bit torque and consequent reactive torque applied to the steerable motor when WOB approaches the optimum value for maximizing ROP.', 'Thus, the intent is to enable better control over the well trajectory at the cost of reducing the speed with which the wellbore is drilled.', 'The optimization of the model f may enable determining when WOB can be increased without reducing stability of trajectory control (i.e., increasing the toolface variation) or exceeding other drilling constraints.', 'In some instances it may be desirable to intentionally reduce trajectory control if such reduction either or both increases ROP substantially and does not result in deviation of the well trajectory from limits on such deviation.', 'In some embodiments, there may be one optimization that not only optimizes the generated initial wellbore trajectory but also simultaneously optimizes the depth intervals of individual slide drilling/rotary drilling sections of the wellbore and the drilling operating parameters used therein.', 'In some embodiments there may be two optimization functions, one for the generated well trajectory and one for any individual stand or incremental drilling length.', 'In some embodiments there may only be one optimization for the entire well trajectory.', 'In some embodiments there may only be one optimization for any one or more individual segments (e.g., stands) of the drill string.', 'In some embodiments, there may be no optimization.', '1.', 'In slide drilling, frictional forces and reactive torque affect the ability to precisely control WOB, which in turn affects toolface orientation and/or control of toolface orientation (measured toolface).', 'As a result, the ability to select and maintain the toolface orientation may need to accommodate interrelated considerations of WOB, toolface, reactive torque and friction forces.', 'In slide drilling, toolface direction includes both instantaneous values and accumulated toolface values over time.', 'In order for the system users (e.g., including the driller) to have a better understanding of the trajectory of the borehole, in some embodiments, a depth weighted toolface direction may be calculated and may be displayed.', 'The weighted average toolface direction may be provided on any selected depth interval basis, e.g., on a per stand basis, on a per well section basis, or to monitor results after a change in a target well path location (e.g., a well placement decision).', 'One example of how the weighted average toolface may be presented is provided below.', 'The drilling depth for each measured toolface value (e.g., from the MWD instrument) along a selected depth interval may be displayed and recorded and the actual change in well trajectory over the selected interval (steering curve response or SCR) may be calculated to provide the depth weighted average (referred to as “C”) of the SCR.', 'Measurements of toolface variation may comprise one or more of a difference between successive tool-face measurements, an absolute deviation, a variance, a range, a norm of the average of vectors representing tool-face orientations, a modulus of an average of complex numbers representing the tool-face orientations.', 'In an example embodiment according to the present disclosure, drilling operating parameters may be initially selected based on a modeled response of the drill string and BHA to particular values of or ranges of drilling operating parameters.', 'One such model may be based on non-linear finite element analysis.', 'Referring to \nFIG.', '4\n, an initial well path or trajectory may be selected as shown at \n81\n.', 'At \n82\n, the drill string BHA may be modeled as to their mechanical properties in a selected mesh, including elastic and shear moduli and mass for forming a three dimensional model of all the components of the drill string and BHA.', 'At \n83\n, the modeled drill string and BHA may be placed in a modeled wellbore, having selected mesh elements representing subsurface formations, including properties such as hardness, elastic and shear moduli, and density.', 'At \n84\n, selected model drilling parameters may be applied to the modeled drill string and BHA.', 'At \n85\n, a solution is determined for the drill string and BHA in the wellbore in view of the applied forces (WOB, RPM) and friction of the drill string and BHA along the wellbore.', 'At \n86\n, the response of the drill string and BHA to the applied forces, i.e., change in depth and change in direction may be calculated based on the factors input and calculated at \n84\n and \n85\n.', 'At \n87\n, the process is repeated for increments of depth traversed by the drill string and BHA and the response of the drill string and BHA with respect to depth and direction is recorded.', 'At \n88\n, a characteristic response of the selected drill string and BHA (which includes the selected steerable motor and drill bit) to applied WOB and operating rate of the steerable motor may be calculated and used as an initial predicted steering (directional) response to the selected drilling operating parameters.', 'One example of such modeling is described in U.S. Pat.', 'No. 7,139,689 issued to Huang.', "In other embodiments, the foregoing modeling of directional response may be omitted and, for example, the steerable motor manufacturer's specifications for steering response may be used.", 'Using the foregoing examples of initial steering response (defined as change in wellbore trajectory with respect to measured toolface, WOB, and bit RPM based on mud flow rate and steerable motor hydraulic specifications) as a starting point, during the drilling of the wellbore, an actual steering response of the drill string and BHA with respect to measured toolface, WOB and RPM may be determined and the foregoing may be used to calculate a depth weighted average.', 'Using the foregoing measured drilling response during slide drilling, a relationship between the measured toolface and the actual steering response may be determined.', 'Using the determined relationship, it may be possible to determine a particular toolface orientation to use to most effectively steer the well along the desired path.', 'The relationship between measured toolface and actual steering response may be continually adjusted during the drilling procedure.', 'During rotary drilling, the well trajectory may be assumed to remain constant or may have a predetermined or measured “walk tendency” (change in trajectory during rotary drilling) may be included (examples include walk or inclination build/drop tendencies).', 'When slide drilling a selected distance, dMD, the well trajectory turns in the direction of the toolface orientation (adjusted by the above empirical relationship by an amount proportional to dMD).', 'The constant of proportionality, C, may be updated during drilling as follows.', 'Between consecutive directional surveys made in the wellbore (e.g., using the MWD instrument), the “slide curve rate” (SCR) may be estimated as: \n \nA\n/(\nSD*TDF\n) \n where A represents the angular difference between the wellbore orientation between the two directional surveys; SD represents the total measured depth of slide drilling between the surveys; and TDF represents the “turn direction factor:” \n \nTDF ranges from zero to unity.', 'A TDF=1 represents the well trajectory always turning in the same direction.', 'The TDF decreases with fluctuating turn direction during slide drilling.', 'If estimated walk tendency of the BHA while rotary drilling is known or determinable and is nonzero, the above equation for SCR may be adjusted by replacing A with the angular difference between the final wellbore orientation and the expected wellbore orientation after rotary drilling an amount RD from the initial orientation.', 'RD represents the total measured depth of rotary drilling between successive surveys.', 'C, as previously explained, may be calculated as a function of the SCR values computed above.', 'Examples include weighted averages of SCR values, with weights based on some combination of: temporal proximity, depth proximity, fractional or absolute amount of slide drilling included in the associated survey interval, TDF magnitude, relation to detected change-points estimated from SCR or other values, and outlier metrics among other things.', 'C could also be extrapolated from trends in SCR (in the current well or even offset wells) or SCR values combined with trends estimated by physics-based models.', 'Said trends could be based on any combination of: time, depth, spatial position, spatial orientation, drilling parameters, and values derived therefrom.', 'Any combination of these techniques may be used.', 'Prior to any slide drilling, a default value of C may be used, e.g., calculated using the above described modeling procedure, using values obtained from nearby wells when drilling through similar formations, possibly adjusted for the mechanical properties of the drill string and steerable motor where they are different than those used to drill the nearby wells, or may be selected arbitrarily.', 'The TDF may be calculated for a toolface measurements made over a selected depth interval as follows.', 'First, convert the well trajectory turn direction (0-360 deg) into a complex number (0->1, 90->i, 180->-1, 270->-i, . . . ).', 'The trajectory turn values may be averaged over the selected depth interval the modulus of the result may be calculated.', 'As an example: slide drill 66 feet with toolface=0°, then slide drill 33 feet with toolface=180° between two surveys points, assuming a uniform 10 degrees per 100 feet curve rate.', 'It may be expected that the well inclination would increase 6.6° (with no change in azimuth direction) and then drop 3.3° for a net change of 3.3° increase in inclination with no change in azimuth.', 'Dividing the net inclination change by the total slide drilling depth interval yields 3.3° per 99 feet, where the total possible turn is 10° per 100 feet drilled interval.', 'Thus, the example TDF=1/3.', 'The net turn direction factor is only about 33% of the possible sliding curve rate due to the toolface not being maintained in a constant direction during slide drilling.', 'Dividing by this triples the angle change to give the desired sliding curve rate.', 'TDF={\n1*66+(−1)*33}/99=1/3 \n \nWhen updating C,', 'the fact that the MWD instrument direction and inclination is not always aligned with the wellbore is taken into account where feasible.', 'For example, the MWD instrument being smaller in diameter than the wellbore and rigidly attached to the drill string below it often causes the MWD instrument to partially align with deeper portions of the wellbore (generally in a range of 3 to 10 feet).', 'Therefore SD and TDF are measured in an offset depth range: range', '[md1+D1,md2+D2], wherein md1, md2 are the directional survey measurement depths.', 'D1 and D2 may be assumed to be constant or a function of the well trajectory, BHA/drill string mechanical properties, and potentially other factors such as weight on bit.', 'Directional walk tendency while rotary drilling may also be measured while drilling.', "For example, if no slide drilling occurred between two directional surveys, the magnitude of the tendency may be estimated as A/MD where A is the well trajectory's angular difference between the two survey locations and MD is the total measured depth drilled between the two survey locations.", 'This may be performed when there is no significant “buffer” zone of only rotary drilling before the first survey location and after the second survey location.', 'The foregoing may also better enable exclusion of MWD misalignment as described in the previous paragraph.', 'The direction of the rotary drilling walk tendency may also be computed from the difference between the two successive surveys.', 'Rotary walk tendency may also be estimated in the presence of sliding using the methods described above, e.g., replacing A with an angular difference that accounts for the slide drilling.', 'Rotary drilling walk tendencies computed by such methods may be used to estimate future rotary drilling walk tendencies, which can be taken into account in subsequent drilling recommendations.', 'In actual drilling operations, the actual toolface will fluctuate around the selected value, at least in part due to variability of the mechanical properties of the formations being drilled (and thus changes in WOB and consequent reactive torque exceeding the speed with which the driller or the automated system can adjust to restore the WOB to its selected value).', 'A sliding efficiency factor (SEF) may be calculated and which quantifies how well toolface is maintained within any selected drilled depth interval.', 'SEF has a range of zero to unity wherein zero represents a completely scattered toolface and, 1 represents exactly constant toolface over the entire selected drilled depth interval.', 'It has been shown by experience to be able to attain SEF values on the order of 0.9.', 'In an attempted constant-toolface slide drilling interval:', 'SEF=modulus(average(complex(toolface))), the term SEF*C replaces C when solving for d1 and d2.', 'The system processor (\n55\n in \nFIG.', '2\n) may also be programmed to calculate a moving average of the difference between the expected and actual turn direction.', 'A physics-based model of the BHA may be incorporated to anticipate changes in C, SEF and/or SEF and/or changes in rotary drilling tendencies ahead of the bit as a function of various factors.', 'These factors may include inclination, WOB, differential pressure (i.e., change in mud pump pressure from its value at zero WOB and therefore zero steerable motor load), and turn direction among others.', 'These factors can be incorporated into the simple model functionfin various ways.', 'For example, if a physics-based model (see the Huang patent referred to above) predicts a certain increase in C when inclination changes from a first amount to a second amount, then the value of C in the function ƒ may be likewise increased from its value described above in the same scenario.', 'A model of the subsurface formations may be included to anticipate changes in C, SEF and/or toolface orientation and/or changes in rotary drilling tendencies ahead of the drill bit as the formation being drilled changes.', 'Such a model may be a full geologic formation model that may or may not be calibrated based on formation measurements in the wellbore being drilled or using correlation with formation measurements made in nearby (“offset”) wells, or other wells.', 'Formation layer boundary detection may be based on changes in drilling response parameters while the drilling operating parameters remain constant, for example, WOB and RPM remain constant but ROP changes.', 'Additionally, if differential pressure remains constant and SEF changes, then it is likely that the bit has penetrated a formation with different rock properties (e.g., SEF decreases, formation is likely harder.', 'SEF increases, formation is likely softer).', 'When toolface changes due to formation property or layer boundary inclination (dip) changes', ', the system processor may be programmed to automatically correct for such changes by displaying a different recommended WOB/differential pressure to a user interface (e.g., a display available to the driller) or by causing the drawworks controller (\n69\n in \nFIG.', '1\n) to release the drill string to cause the recommended WOB/differential pressure to be attained.', 'In some embodiments, using automatic correlation of measurements between the current well and nearby (“offset”) wells or the current well and a geologic model, the formation change can be predicted and the drilling operating parameters may be adjusted proactively, that is, prior to actually drilling a different formation.', 'When the motor build/turn capacity is larger than necessary to reach any intermediate target position or the final target position, the system may display suggested drilling operating parameters to the driller on a user interface (or execute the drilling operating parameters automatically) with higher-frequency toolface fluctuation (e.g., by varying WOB or by alternating between slide drilling and rotary drilling) to reduce dogleg severity.', 'One possible implementation is to reduce occurrences of having to pull the drill string out of the wellbore due to insufficient well trajectory turn rate by using a higher turn capacity steerable motor and use the above described TF-fluctuation to keep the net well trajectory turn rate within that prescribed by the well plan, either the original well plan or the well plan as modified during drilling.', 'The system may be configured for a user, e.g., the driller, to override the calculated drilling operating parameters.', 'The system processor may be programmed to accept as input user selected “override” drilling operating parameters and then calculate the resulting expected location and orientation of the wellbore at any measured depth ahead of the current depth to provide the user guidance on the quality of the parameter selection.', 'The drilling operating parameters may be executed manually by the driller or automatically as explained with reference to \nFIGS.', '1 and 2\n.', 'Regardless of the execution mechanism, the results will be monitored both from an execution and an effect standpoint.', 'From an execution standpoint, the system may monitor the actual drilling operating parameters used as contrasted to the calculated drilling operating parameters, and if the as-executed drilling operating parameters result in the desired effect on wellbore steering and ROP performance.', 'The processor may be programmed to generate and display to the user, e.g., to a user interface available to the driller, warnings as to conditions such as failure to execute the calculated drilling operating parameters within a selected tolerance range and/or failure of the well trajectory and/or ROP performance to fall within the predetermined values outside a selected tolerance range.', 'Additionally, if the actual well trajectory deviates from the planned trajectory or calculated trajectory beyond a predetermined threshold, the processor may recalculate the drilling operating parameters such that a revised planned well trajectory may fall within the predetermined threshold deviation from the originally planned wellbore trajectory.', 'One element of the monitoring process is determining when the drill string is sliding or rotating.', 'Existing methods perform such monitoring automatically using measurements of top drive RPM or torque, but are susceptible to error particularly when the top drive is used to adjust toolface orientation or “rock” the pipe to decrease axial friction while sliding.', 'Example methods according to the present disclosure may use toolface orientation measurements from the MWD instrument and other data as a backup measurement (when available) for confirmation of whether slide drilling or rotary drilling is underway at any time.', 'The present example method may identify intervals of measured depth as sliding when certain measures of the scatter of the measured toolface orientations are below a predetermined threshold.', 'Examples of such a measure include variance, absolute deviation, range, and measures of the deviation between consecutive toolface orientation measurements.', 'If available, other drilling parameters may be used, including without limitation surface and downhole RPM, ROP, differential pressure (defined above), wellbore depth, block or top drive elevation, block or top drive velocity, bit depth and WOB among other parameters.', 'Determining whether sliding drilling or rotary drilling is underway at any time may be used to estimate the SCR values which are in turn used to compute C. Determining times of slide drilling and rotary drilling also enables the calculation of “virtual survey points” at the position of the drill bit at any particular measured depth.', 'These “virtual survey points” may be used for subsequent well path construction and user feedback.', 'The virtual survey points may be located between or beyond actual directional survey points at times when the steerable motor toolface is measured.', 'A cone of uncertainty may be calculated based on the distance from the last actual directional survey point as well as signal quality of the intermediate measure points.', 'The cone of uncertainty expands until the next actual directional survey is taken, but the virtual survey points may still allow drilling personnel to make better informed decisions concerning adjustment of the well trajectory at any position along the well.', 'Virtual survey points may be calculated by 1) rotary drilling assuming a straight path (or optionally including an empirically determined trajectory change tendency); 2) slide drilling use the value of C and the measured toolface to estimate the position and orientation of the wellbore at any bit position.', 'Virtual survey points may be used to update the starting point for any subsequent well path segment, or may be used to adjust one or more drilling operating parameters.', 'C may be used for other applications including detecting problems with the steerable motor and detecting formation changes.', 'FIG.', '5\n shows an example computing system \n100\n in accordance with some embodiments.', 'The computing system \n100\n may be an individual computer system \n101\nA or an arrangement of distributed computer systems.', 'The computer system \n101\nA may include the processor (\n55\n in \nFIG.', '2\n) as one of its functional components, and may include one or more analysis modules \n102\n that may be configured to perform various tasks according to some embodiments, such as the tasks explained above, and in particular those tasks described with reference to \nFIGS.', '3 and 4\n.', 'To perform these various tasks, analysis module \n102\n may execute independently, or in coordination with, one or more processors \n104\n, which may be connected to one or more storage media \n106\n.', 'The processor(s) \n104\n may also be connected to a network interface \n108\n to allow the computer system \n101\nA to communicate over a data network \n110\n with one or more additional computer systems and/or computing systems, such as \n101\nB, \n101\nC, and/or \n101\nD (note that computer systems \n101\nB, \n101\nC and/or \n101\nD may or may not share the same architecture as computer system \n101\nA, and may be located in different physical locations, for example, computer system \n101\nA may be at a well drilling location, while in communication with one or more computer systems such as \n101\nB, \n101\nC and/or \n101\nD that may be located in one or more data centers on shore, aboard ships, and/or located in varying countries on different continents).', 'Computer system \n101\nA, for example, may include the above described user interface available for use by the driller.', 'A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.', 'The storage media \n106\n can be implemented as one or more computer-readable or machine-readable storage media.', 'Note that while in the example embodiment of \nFIG.', '5\n the storage media \n106\n are depicted as within computer system \n101\nA, in some embodiments, the storage media \n106\n may be distributed within and/or across multiple internal and/or external enclosures of computing system \n101\nA and/or additional computing systems.', 'Storage media \n106\n may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices.', 'Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or alternatively, can be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes.', 'Such computer-readable or machine-readable storage medium or media may be considered to be part of an article (or article of manufacture).', 'An article or article of manufacture can refer to any manufactured single component or multiple components.', 'The storage medium or media can be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions can be downloaded over a network for execution.', 'It should be appreciated that computing system \n100\n is only one example of a computing system, and that computing system \n100\n may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of \nFIG.', '5\n, and/or computing system \n100\n may have a different configuration or arrangement of the components depicted in \nFIG.', '5\n.', 'The various components shown in \nFIG.', '5\n may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.', 'Further, the steps in the processing methods described above may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices.', 'These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of the present disclosure.', 'While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein.', 'Accordingly, the scope of the invention should be limited only by the attached claims.'] | ['1.', 'A drilling system comprising:\na steerable motor;\nan orientation sensor for measuring orientation of the wellbore;\na toolface sensor for measuring toolface orientation of the steerable motor;\na drill bit at a distal end of a drill string coupled to the steerable motor;\na processor in signal communication with the orientation sensor and the toolface sensor, the processor having instructions to cause the processor to compute one or more of, (i) a steering response of the steerable motor, (ii) measured depths of slide drilling intervals, (iii) a change in toolface orientation with respect to weight applied to the drill bit, and (iv) parameters related to variation in measurements made by the toolface sensor; and\nan interface in signal communication with the processor, the interface providing an output of one or more of the computed parameters or values derived therefrom, the output provided to at least one of a user interface and an automatic drilling unit controller interface,\nwherein measurements of the toolface orientation change with respect to reactive torque of the steerable motor are used by the processor to compute outputs displayable on the user interface that assist determining a zero reactive torque toolface measurement that will result in a desired toolface orientation when a selected reactive torque is determined.', '2.', 'The drilling system of claim 1, wherein the steering response is extrapolated from one or more prior measured steering responses.\n\n\n\n\n\n\n3.', 'The drilling system of claim 2, wherein the extrapolation of the steering response is estimated from a weighted average of prior steering responses, wherein weights for the average are based on one or more of temporal proximity, depth proximity, fractional or absolute amount of slide drilling included in an associated directional survey interval, toolface scatter in the associated directional survey interval, relationship to change-points estimated from any combination of prior steering responses or drilling parameters and outlier measurements.', '4.', 'The drilling system of claim 1, wherein the processor is programmed to cause the user interface to display a warning to replace one or more components of the drill string when the steering response or toolface variation fails to meet threshold criteria either predetermined or based on a current well status and at least one target well spatial location.', '5.', 'The drilling system of claim 1, further comprising: instructions for the processor to receive as input a target spatial position of a wellbore; and instructions for the processor to calculate one or more drilling parameters which, when applied, enable the steerable motor to cause the wellbore trajectory to reach the target spatial position.', '6.', 'The drilling system of claim 1, wherein toolface orientation measurements are used by the processor to determine measured depth intervals that were slide-drilled and rotary drilled.', '7.', 'The drilling system of claim 6, wherein scatter properties of the toolface orientation measurements are used by the processor to determine measured depth intervals that were slide drilled and rotary drilled, the scatter properties including any combination of a difference between successive toolface measurements, an absolute deviation, a variance, a range, a norm of an average of vectors representing the toolface orientations, a modulus of an average of complex numbers representing the tool-face orientations.', '8.', 'The drilling system of claim 1, in which virtual survey points beyond a measured depth of directional surveying equipment or values derived therefrom are calculated by the processor and are output to at least one of the user interface and the automatic drilling controller interface.', '9.', 'The drilling system of claim 8, in which a virtual survey point at or near a bottom of the wellbore is used as a starting point for a well path and wherein an orientation of the virtual survey point is used to constrain tangent vectors at or near the beginning of the well path.', '10.', 'A drilling system comprising:\na steerable motor;\nan orientation sensor for measuring orientation of the wellbore;\na toolface sensor for measuring toolface orientation of the steerable motor;\na drill bit at a distal end of a drill string coupled to the steerable motor;\na processor in signal communication with the orientation sensor and the toolface sensor, the processor having instructions to cause the processor to compute one or more of, (i) a steering response of the steerable motor, (ii) measured depths of slide drilling intervals, (iii) a change in toolface orientation with respect to weight applied to the drill bit, and (iv) parameters related to variation in measurements made by the toolface sensor; and\nan interface in signal communication with the processor, the interface providing an output of one or more of the computed parameters or values derived therefrom, the output provided to at least one of a user interface and an automatic drilling unit controller interface,\nwherein the steering response is extrapolated from one or more prior measured steering responses, wherein the extrapolation of the steering response is estimated from a weighted average of prior steering responses, wherein weights for the average are based on one or more of temporal proximity, depth proximity, fractional or absolute amount of slide drilling included in an associated directional survey interval, toolface scatter in the associated directional survey interval, relationship to change-points estimated from any combination of prior steering responses or drilling parameters and outlier measurements.\n\n\n\n\n\n\n11.', 'The drilling system of claim 10, wherein the steering response is extrapolated from one or more prior measured steering responses.\n\n\n\n\n\n\n12.', 'The drilling system of claim 10, wherein toolface orientation measurements are used by the processor to determine measured depth intervals that were slide-drilled and rotary drilled.', '13.', 'The drilling system of claim 10, in which virtual survey points beyond a measured depth of directional surveying equipment or values derived therefrom are calculated by the processor and are output to at least one of the user interface and the automatic drilling controller interface.', '14.', 'A drilling system comprising:\na steerable motor;\nan orientation sensor for measuring orientation of the wellbore;\na toolface sensor for measuring toolface orientation of the steerable motor;\na drill bit at a distal end of a drill string coupled to the steerable motor;\na processor in signal communication with the orientation sensor and the toolface sensor, the processor having instructions to cause the processor to compute one or more of, (i) a steering response of the steerable motor, (ii) measured depths of slide drilling intervals, (iii) a change in toolface orientation with respect to weight applied to the drill bit, and (iv) parameters related to variation in measurements made by the toolface sensor; and\nan interface in signal communication with the processor, the interface providing an output of one or more of the computed parameters or values derived therefrom, the output provided to at least one of a user interface and an automatic drilling unit controller interface, wherein the processor is programmed to cause the user interface to display a warning to replace one or more components of the drill string when the steering response or toolface variation fails to meet threshold criteria either predetermined or based on a current well status and at least one target well spatial location.', '15.', 'The drilling system of claim 14, wherein the steering response is extrapolated from one or more prior measured steering responses.\n\n\n\n\n\n\n16.', 'The drilling system of claim 14, wherein toolface orientation measurements are used by the processor to determine measured depth intervals that were slide-drilled and rotary drilled.', '17.', 'The drilling system of claim 14 in which virtual survey points beyond a measured depth of directional surveying equipment or values derived therefrom are calculated by the processor and are output to at least one of the user interface and the automatic drilling controller interface.', '18.', 'A drilling system comprising:\na steerable motor;\nan orientation sensor for measuring orientation of the wellbore;\na toolface sensor for measuring toolface orientation of the steerable motor;\na drill bit at a distal end of a drill string coupled to the steerable motor;\na processor in signal communication with the orientation sensor and the toolface sensor, the processor having instructions to cause the processor to compute one or more of, (i) a steering response of the steerable motor, (ii) measured depths of slide drilling intervals, (iii) a change in toolface orientation with respect to weight applied to the drill bit, and (iv) parameters related to variation in measurements made by the toolface sensor; and\nan interface in signal communication with the processor, the interface providing an output of one or more of the computed parameters or values derived therefrom, the output provided to at least one of a user interface and an automatic drilling unit controller interface,\nwherein toolface orientation measurements are used by the processor to determine measured depth intervals that were slide-drilled and rotary drilled and wherein scatter properties of the toolface orientation measurements are used by the processor to determine measured depth intervals that were slide drilled and rotary drilled, the scatter properties including any combination of a difference between successive toolface measurements, an absolute deviation, a variance, a range, a norm of an average of vectors representing the toolface orientations, a modulus of an average of complex numbers representing the tool-face orientations.', '19.', 'The drilling system of claim 18, wherein the steering response is extrapolated from one or more prior measured steering responses.', '20.', 'The drilling system of claim 18, in which virtual survey points beyond a measured depth of directional surveying equipment or values derived therefrom are calculated by the processor and are output to at least one of the user interface and the automatic drilling controller interface.'] | ['FIG.', '1 is a schematic view of an example directional drilling system that may be used in accordance with the present disclosure.', '; FIG.', '2 is a block diagram of an example directional drilling control system according to the present disclosure.', '; FIG.', '3 shows a flow chart of an example directional drilling method.; FIG.', '4 shows an example of non-linear finite element analysis of expected drilling tool and steerable motor response.; FIG.', '5 shows an example computer system that may be used in some embodiments.; FIG.', '1 shows an example directional drilling system that may be used in some embodiments according to certain aspects of the present disclosure.', 'A drilling rig (“rig”) is designated generally by reference numeral 11.', 'The rig 11 shown in FIG. 1 is a land rig, but this is for illustration purposes only, and is not intended to be a limitation on the scope of the present disclosure.', 'As will be apparent to those skilled in the art, methods and systems according the present disclosure may apply equally to marine drilling rigs, including, but not limited to, jack-up rigs, semisubmersible rigs, and drill ships.; FIG.', '2 shows a block diagram of a directional drilling control system (“system”) according to an embodiment of the present disclosure.', 'The system may accept as input signals from devices including the directional sensor 51 (in an MWD system as explained with reference to FIG.', '1, for example) which, as explained above, produces a signal indicative of the toolface angle of the steerable motor 41.', 'The system may accept as input a signal from the drill string torque sensor 53.', 'The torque sensor 53 provides a measure of the torque applied to the drill string (35 in FIG.', '1) at the surface.', 'The system may also accept as input a signal from the drill string pressure sensor 63 that provides measurements of the drill string internal fluid pressure.', 'The system may also accept as input signals from the surface drill pipe orientation sensor 65.', 'The system may also accept as input measurements from the hookload sensor 67.', 'In FIG.', '2 the outputs of the directional sensor 51, the torque sensor 53, the pressure sensor 63, hookload sensor 67 and the drill pipe orientation sensor 65 may be received at or otherwise operatively coupled to a processor 55.', 'The processor 55 may be programmed to process signals received from the above described sensors 51, 53, 63, 67 and 65.', 'The processor 55 may also receive user input from user input devices, indicated generally at 57.', 'User input devices 57 may include, but are not limited to, a keyboard, a touch screen, a mouse, a light pen, or a keypad.', 'The processor 55 may also provide visual output to a display 59.', 'The processor 55 may also provide output to a drill string rotation controller 61 that operates the top drive or rotary table (FIG. 1) to rotate the drill string (35 in FIG.', '1) in a manner as will be further explained below.', 'The processor 55 may also provide output to operate the drawworks controller 69 to automatically control the WOB in some embodiments.', 'In some embodiments, the processor 55 may be programmed to operate the drawworks controller 69 to provide a substantially constant value or other values of drill string fluid (mud) pressure a selected amount above the pressure existing when the drill bit (40 in FIG.', '1) is not on the bottom of the wellbore (33 in FIG.', '1) and thus exerts no torque (i.e., the no load pressure).', '; FIG.', '5 shows an example computing system 100 in accordance with some embodiments.', 'The computing system 100 may be an individual computer system 101A or an arrangement of distributed computer systems.', 'The computer system 101A may include the processor (55 in FIG.', '2) as one of its functional components, and may include one or more analysis modules 102 that may be configured to perform various tasks according to some embodiments, such as the tasks explained above, and in particular those tasks described with reference to FIGS. 3 and 4.', 'To perform these various tasks, analysis module 102 may execute independently, or in coordination with, one or more processors 104, which may be connected to one or more storage media 106.', 'The processor(s) 104 may also be connected to a network interface 108 to allow the computer system 101A to communicate over a data network 110 with one or more additional computer systems and/or computing systems, such as 101B, 101C, and/or 101D (note that computer systems 101B, 101C and/or 101D may or may not share the same architecture as computer system 101A, and may be located in different physical locations, for example, computer system 101A may be at a well drilling location, while in communication with one or more computer systems such as 101B, 101C and/or 101D that may be located in one or more data centers on shore, aboard ships, and/or located in varying countries on different continents).', 'Computer system 101A, for example, may include the above described user interface available for use by the driller.'] |
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US11105196 | Leak detection systems and methods for components of a mineral extraction system | Mar 7, 2019 | Jonathan Haslanger, Vikas Rakhunde, Ian McDaniel | Schlumberger Technology Corporation | NPL References not found. | 4116044; September 26, 1978; Garrett; 4152926; May 8, 1979; Hasha; 4998435; March 12, 1991; Miller; 5209105; May 11, 1993; Hasha; 8347983; January 8, 2013; Hoyer; 9127511; September 8, 2015; Orbell; 10036227; July 31, 2018; Leuchtenberg; 20190093445; March 28, 2019; Kulkarni | Foreign Citations not found. | ['A leak detection system includes an annular housing that defines a bore, a constriction with the bore, and a channel extending radially-outwardly from the bore and positioned upstream of the constriction.', 'The leak detection system also includes a sensor positioned outside of the bore and fluidly coupled to the channel, wherein the sensor is configured to detect a leaked fluid within the bore.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'Natural resources, such as oil and gas, are used as fuel to power vehicles, heat homes, and generate electricity, in addition to a myriad of other uses.', 'Once a desired resource is discovered below the surface of the earth, mineral extraction systems are often employed to access and extract the resource.', 'These systems may be located onshore or offshore depending on the location of a desired resource.', 'Such systems generally include various valves (e.g., gate valves, ball valves) and other types of fluid and/or pressure control equipment.', 'For example, a pressure control equipment (PCE) stack may be mounted above a wellhead to protect other surface equipment from surges in pressure within a wellbore during intervention operations.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n is a side cross-sectional view of a leak detection system for a component of a mineral extraction system, in accordance with an embodiment of the present disclosure;\n \nFIG.', '2\n is side cross-sectional view of a sensor within a channel of the leak detection system of \nFIG.', '1\n, in accordance with an embodiment of the present disclosure;\n \nFIG.', '3\n is a side cross-sectional view of a sensor within a chamber that is fluidly coupled to the channel of the leak detection system of \nFIG.', '1\n, in accordance with an embodiment of the present disclosure;\n \nFIG.', '4\n is a side cross-sectional view of a leak detection system for a component of a mineral extraction system, wherein the leak detection system includes an annular insert, in accordance with another embodiment of the present disclosure;\n \nFIG.', '5\n is a side cross-sectional view of a leak detection system for a component of a mineral extraction system, wherein the leak detection system includes multiple channels, in accordance with another embodiment of the present disclosure;\n \nFIG.', '6\n is a side view of a pressure control equipment (PCE) stack having a leak detection system, in accordance with an embodiment of the present disclosure;\n \nFIG.', '7\n is a side cross-sectional view of a portion of the PCE stack of \nFIG.', '6\n, in accordance with an embodiment of the present disclosure; and\n \nFIG.', '8\n is a method of operating a leak detection system for a component of a mineral extraction system, in accordance with an embodiment of the present disclosure.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nOne or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'The present embodiments generally relate to leak detection systems and methods for components of a mineral extraction system.', 'In particular, a leak detection system may include an annular housing that defines a bore having a constriction (e.g., region of reduced diameter within the bore).', 'The annular housing may also include at least one channel that extends radially-outwardly from the bore, and each channel includes or is otherwise fluidly coupled to a respective sensor that is capable of detecting the presence of a leaked fluid within the bore (e.g., via pressure changes).', 'As discussed in more detail below, these features may facilitate detection of a leak around a rod as the rod moves within the bore.', 'In the present disclosure, a rod may be any of a variety of rigid or flexible (e.g., spoolable) cylindrical or tubular structures (e.g., conduits or tubing), such as a valve stem, wireline, Streamline™, slickline, coiled tubing, or sucker rod.', 'The leak detection system may be used in any of a variety of valves of the mineral extraction system.', 'For example, the leak detection system may be used in a gate valve to detect a leak around a reciprocating valve stem that drives a gate of the gate valve between open and closed positions.', 'Similarly, the leak detection system may be used in a ball valve to detect a leak around a rotating valve stem that drives a ball of the ball valve between open and closed positions.', 'It should be appreciated that the leak detection system may be used in valves of a wellhead, stack equipment (e.g., a “Christmas tree”), and/or surface equipment of the mineral extraction system.', 'As another example, the leak detection system may be used in a pressure control equipment (PCE) stack that may be coupled to and/or positioned vertically above a wellhead during various intervention operations, such as wireline or coil tubing operations in which a tool supported on a rod, such as a wireline, slickline, conduit, or tubing, is lowered through the PCE stack to enable inspection and/or maintenance of a well.', 'The PCE stack includes components, such as a stuffing box, that seal about the wireline or other rod as it moves relative to the PCE stack.', 'Thus, the leak detection system may be positioned vertically above the stuffing box to detect a leak around the wireline or other rod as it moves relative to the PCE stack.', 'With the foregoing in mind, \nFIG.', '1\n is a side cross-sectional view of an embodiment of a leak detection system \n10\n for a component \n12\n of a mineral extraction system.', 'To facilitate discussion, the leak detection system \n10\n and related features may be described with reference to an axial axis or direction \n4\n (e.g., vertical axis or direction), a radial axis or direction \n6\n, and/or a circumferential axis or direction \n8\n.', 'As shown, a rod \n14\n (e.g., movable rod) is positioned within a bore \n16\n defined by a radially-inner wall \n18\n (e.g., annular wall) of a housing \n20\n (e.g., annular housing).', 'The rod \n14\n may move (e.g., reciprocate and/or rotate) within the bore \n16\n relative to the housing \n20\n.', 'In the illustrated embodiment, the housing \n20\n is a one-piece structure to facilitate discussion; however, the housing \n20\n may include multiple sections that are coupled to one another (e.g., via one or more fasteners, such as bolts; via a threaded interface).', 'As shown, the housing \n20\n supports a packer \n22\n (e.g., annular packer, annular elastomer seal, or any other suitable annular sealing device, such as a grease tube that may be filled with grease to seal against a wireline [e.g., braided wireline]) that contacts and seals against the rod \n14\n (e.g., forms a circumferential seal about the rod \n14\n).', 'The packer \n22\n may enable movement of the rod \n14\n through the bore \n16\n relative to the housing \n20\n, while also blocking a flow of fluid (e.g., gas, liquid) from a high pressure portion \n24\n of the bore \n16\n to a low pressure portion \n26\n of the bore \n16\n.', 'The radially-inner wall \n18\n of the housing \n20\n includes a constriction portion \n28\n that extends radially-inwardly to define a constriction \n30\n (e.g., region of reduced diameter within the bore \n16\n).', 'When the rod \n14\n is positioned within the housing \n20\n, the constriction \n30\n is an annular gap between a radially-outer wall \n34\n of the rod \n14\n and the constriction portion \n28\n of the radially-inner wall \n18\n of the housing \n20\n, and the constriction \n30\n has a radial distance \n32\n that is reduced compared to region(s) of the bore \n16\n that are upstream from the constriction \n30\n (e.g., closer to the packer \n22\n).', 'In some embodiments, the constriction portion \n28\n may contact the rod \n14\n without sealing against the rod \n14\n.', 'The housing \n20\n further includes a channel \n40\n (e.g., radially-extending channel; flow path; leak detection path) that fluidly couples the bore \n16\n to a sensor \n42\n (e.g., flow sensor, pressure sensor).', 'In operation, the constriction \n30\n may divert fluid that leaks across the packer \n22\n from the high pressure portion \n24\n of the bore \n16\n to the low pressure portion \n26\n of the bore \n16\n into the channel \n40\n to facilitate detection by the sensor \n42\n.', 'The fluid that leaks across the packer \n22\n from the high pressure portion \n24\n of the bore \n16\n to the low pressure portion \n26\n of the bore \n16\n may be referred to herein as “leaked fluid.”', 'The housing \n20\n may have various configurations to facilitate diversion of the leaked fluid into the channel \n40\n and/or detection of the leaked fluid by the sensor \n42\n.', 'For example, the channel \n40\n may have a diameter \n43\n, such that a total cross-sectional area of the channel \n40\n is greater than a total cross-sectional area of the constriction \n30\n (e.g., annular gap about the rod \n14\n).', 'In some embodiments, the radially-inner wall \n18\n of the housing \n20\n may define a cavity \n44\n (e.g., region of expanded diameter within the bore \n16\n) upstream of the constriction portion \n28\n (e.g., closer to the packer \n22\n).', 'In such cases, the radially-inner wall \n18\n of the housing \n20\n may include a first tapered portion \n46\n and a second tapered portion \n48\n that define the cavity \n44\n.', 'The cavity \n44\n may be positioned at an intersection \n50\n between the bore \n16\n and the channel \n40\n.', 'In particular, the cavity \n44\n may be axially aligned with the channel \n40\n and may be positioned to circumferentially surround the intersection \n50\n between a longitudinal axis \n52\n of the bore \n16\n and a longitudinal axis \n54\n of the channel \n40\n.', 'Thus, the leaked fluid may flow into and/or collect in the cavity \n44\n, and then the leaked fluid may flow into the channel \n40\n.', 'When the rod \n14\n is positioned within the housing \n20\n, the cavity \n44\n is an annular gap between the radially-outer wall \n34\n of the rod \n14\n and the first tapered portion \n46\n and the second tapered portion \n48\n of the radially-inner wall \n18\n of the housing \n20\n, and the cavity \n44\n has a maximum radial distance \n56\n that is expanded compared to the radial distance \n32\n of the constriction \n30\n and/or compared to region(s) of the bore \n16\n that are upstream from the cavity \n44\n (e.g., closer to the packer \n22\n).', 'Advantageously, the sensor \n42\n is positioned outside of the bore \n16\n, which may reduce interference due to movement of the rod \n14\n within the bore \n16\n.', 'Thus, the sensor \n42\n may accurately and reliably detect the presence of the leaked fluid.', 'For example, in the illustrated embodiment, the sensor \n42\n is positioned at an end portion \n60\n (e.g., radially-outer end portion) of the channel \n40\n.', 'However, it should be appreciated that the sensor \n42\n may be positioned in other locations, such as a chamber that extends from or is fluidly coupled to the end portion \n60\n of the channel \n40\n.', 'Furthermore, the sensor \n42\n may be positioned within and supported by the housing \n20\n, or the sensor \n42\n may be in a separate housing that is coupled to the housing \n20\n (e.g., via one or more fasteners, such as bolts).', 'The sensor \n42\n may be any type of sensor that is capable of detecting the leaked fluid (e.g., via a change in pressure and/or a change in a fluid present in the channel \n40\n).', 'For example, in the absence of the leaked fluid, the sensor \n42\n may be exposed to ambient air at a first pressure (e.g., ambient atmospheric pressure).', 'However, in the presence of the leaked fluid, the sensor \n42\n may be exposed to the leaked fluid and/or detect a second pressure that is greater than the first pressure.', 'With the foregoing in mind, \nFIGS.', '2 and 3\n provide non-limiting examples of sensors \n42\n that may be used in the leak detection system \n10\n of \nFIG.', '1\n.', 'In \nFIG.', '2\n, the sensor \n42\n may be an acoustic sensor or an optical sensor that is positioned at or proximate to the end portion \n60\n of the channel \n40\n.', 'The sensor may include an emitter \n70\n that emits waves (e.g., sound or light) toward a detector \n72\n, as shown by arrow \n74\n.', 'Characteristics of the waves (e.g., velocity, amplitude) received at the detector \n72\n may vary in the presence of the leaked fluid (e.g., as compared to the ambient air), thereby enabling detection of the leaked fluid.', 'As shown, the sensor \n42\n is positioned outside of the bore \n60\n and the emitter \n70\n is oriented to emit the waves cross-wise (e.g., angled, such as orthogonal) to the longitudinal axis \n54\n of the channel \n40\n.', 'Accordingly, the movement of the rod \n14\n within the bore \n16\n may not interfere with the measurements obtained by the sensor \n42\n.', 'In \nFIG.', '3\n, the sensor \n34\n is positioned within in a chamber \n76\n that extends from the end portion \n60\n of the channel \n40\n.', 'The sensor \n42\n may be an acoustic sensor or an optical sensor having the emitter \n70\n that emits waves toward the detector \n72\n, as shown by arrow \n78\n.', 'As noted above, characteristics of the waves received at the detector \n72\n may vary in the presence of the leaked fluid.', 'This configuration may also facilitate use of the sensor \n42\n as a level sensor to detect a level of liquid that accumulates within the chamber \n76\n.', 'It should be appreciated that the emitter \n70\n and the detector \n72\n may be positioned adjacent to one another, and the detector \n72\n may then detect the waves after the waves are reflected by the fluid and/or an opposed surface.', 'It should be appreciated that the sensor \n42\n may be positioned in any of a variety of locations, including any surface of the channel \n40\n, any surface of the chamber \n76\n, and/or in a separate housing that is coupled to the housing \n20\n (e.g., via one or more fasteners, such as bolts).', 'Furthermore, the sensor \n42\n may be any of a variety of flow, pressure, and/or mechanical sensors, such as a manometer, a flapper sensor, a float sensor, a reed switch, or a combination thereof.', 'For example, a flapper sensor may include a flap (e.g., hinged or biased member, such as a plate) that is positioned at the end portion \n60\n of the channel \n40\n.', 'The leaked fluid may exert a force on and cause movement of the flap, and the movement of the flap may activate a switch (e.g., a reed switch) or be otherwise detected (e.g., via a strain gauge).', 'As another example, a float sensor may include a permanent magnet sealed inside of a buoyant element and positioned within the chamber \n76\n.', 'As the chamber \n76\n fills with liquid, the permanent magnet rises within the chamber \n76\n and may activate a switch (e.g., a reed switch) or otherwise be detected (e.g., via magnetostrictive wire).', 'Returning the \nFIG.', '1\n, the sensor \n42\n may be communicatively coupled to a controller \n80\n (e.g., electronic controller) that includes a processor \n82\n and a memory device \n84\n.', 'The processor \n82\n may receive and process the signals from the sensor \n42\n to identify the absence and/or the presence of the leaked fluid.', 'For example, the processor \n82\n may compare the signals obtained by the sensor \n42\n during operation of the component \n12\n to a baseline measurement (e.g., taken when the sensor \n42\n is exposed only to ambient air), and a change (e.g., a change above a threshold, such as a change equal to or greater than about 5, 10, 15, 20, 25, or 50 percent) compared to the baseline measurement may indicate the presence of the leaked fluid.', 'In some embodiments, the processor \n82\n may also receive and process the signals from the sensor \n42\n to determine characteristics of the fluid, such as the pressure, the velocity, and/or the composition of the fluid (e.g., based on the characteristics of the waves received at the detector \n72\n).', 'In some embodiments, the processor \n82\n may provide control signals, such as control signals to the sensor \n42\n (e.g., to emit the waves) and/or control signals to an actuator to adjust a compressive force (e.g., in a vertical direction) on the packer \n22\n to adjust the seal against the rod \n14\n.', 'For example, the processor \n82\n may instruct the actuator to increase the compressive force on the packer \n22\n in response to detection of the leaked fluid.', 'In some embodiments, the processor \n82\n may provide control signals to another actuator associated with another component of the mineral extraction system (e.g., another valve; a blowout preventer) in response to detection of the leaked fluid.', 'The controller \n80\n may include an output device \n86\n (e.g., display and/or speaker), and the processor \n82\n may instruct the output device \n86\n to provide a visual or audible output that indicates the presence or absence of the leaked fluid.', 'For example, the processor \n82\n may instruct the output device \n86\n to provide an alarm (e.g., an audible alarm) in response to detection of the leaked fluid.', 'The controller \n82\n may be positioned within the housing \n18\n, within a separate support structure coupled to the housing \n18\n, and/or at a location remote from the housing \n18\n.', 'The controller \n82\n may be part of a distributed controller or control system with one or more controllers (e.g., electronic controllers with processors, memory, and instructions) distributed about the mineral extraction system and in communication with one another to receive and/or to process the signals from sensor \n42\n, to provide an output via the output device \n86\n, and/or to control various components associated with the leak detection system \n10\n.', 'The processor \n82\n may include one or more processors configured to execute software, such as software for processing signals and/or controlling the components associated with the leak detection system \n10\n.', 'The memory device \n84\n disclosed herein may include one or more memory devices (e.g., a volatile memory, such as random access memory [RAM], and/or a nonvolatile memory, such as read-only memory [ROM]) that may store a variety of information and may be used for various purposes.', 'For example, the memory device \n84\n may store processor-executable instructions (e.g., firmware or software) for the processor \n82\n to execute, such as instructions for processing signals received from the sensor \n42\n and/or controlling the components related to the leak detection system \n10\n.', 'It should be appreciated that the controller \n80\n may include various other components, such as a communication device that is capable of communicating data or other information to various other devices (e.g., a remote computing system).', 'Advantageously, the leak detection system \n10\n may enable real-time leak monitoring and/or may provide a configuration that enables the sensor \n42\n to obtain accurate and/or reliable measurements, even while the rod \n14\n moves through the bore \n16\n.', 'As noted above, the housing \n20\n may have various configurations to facilitate diversion of the leaked fluid into the channel \n40\n and/or detection of the leaked fluid by the sensor \n42\n.', 'For example, in \nFIG.', '4\n, the leak detection system includes an annular insert \n90\n and the housing \n20\n is devoid of the cavity \n44\n shown in \nFIG.', '1\n.', 'Instead, the radially-inner wall \n18\n of the housing \n20\n extends axially to provide the bore \n16\n with a generally constant diameter between the packer \n22\n and the constriction \n30\n.', 'As shown, the channel \n40\n is positioned axially between the packer \n22\n and the constriction \n30\n, and the constriction \n30\n is formed by the annular insert \n90\n that extends radially-inwardly from the radially-inner wall \n18\n of the housing \n20\n.', 'The annular insert \n90\n may be coupled to the radially-inner wall \n18\n of the housing \n20\n (e.g., via a threaded interface) and/or may be supported within a groove defined in the radially-inner wall \n18\n of the housing \n20\n.', 'In operation, the constriction \n30\n formed by the annular insert \n30\n may divert the leaked fluid into the channel \n40\n for detection by the sensor \n42\n in the manner discussed above with respect to \nFIGS.', '1-3\n.\n \nFIG.', '5\n illustrates the housing \n20\n with another configuration that may facilitate diversion of the leaked fluid into the channel \n40\n and/or detection of the leaked fluid by the sensor \n42\n.', 'As discussed in more detail below, \nFIG.', '5\n also illustrates an optional additional channel \n96\n (e.g., radially-extending channel; flow path; leak detection path) that may be used in the leak detection system \n10\n.', 'First, in the absence of the additional channel \n96\n, the leak detection system \n10\n may operate to detect the leaked fluid in a similar manner as discussed above with respect to \nFIGS.', '1-4\n.', 'As shown, the housing \n20\n is devoid of the cavity \n44\n shown in \nFIG.', '1\n.', 'Instead, the radially-inner wall \n18\n of the housing \n20\n extends axially to provide the bore \n16\n with a generally constant diameter between the packer \n22\n and the constriction \n30\n.', 'The radially-inner wall \n18\n of the housing \n20\n includes the constriction portion \n28\n that extends radially-inwardly to define the constriction \n30\n.', 'The housing \n20\n further includes the channel \n40\n that fluidly couples the bore \n16\n to the sensor \n42\n, and the channel \n40\n is positioned axially between the packer \n22\n and the constriction \n30\n.', 'In operation, the constriction \n30\n may divert the leaked fluid into the channel \n40\n to facilitate detection by the sensor \n42\n in the manner discussed above with respect to \nFIGS.', '1-4\n.', 'In some embodiments, the leak detection system \n10\n may include the additional channel \n96\n that fluidly couples the bore \n16\n to an additional sensor \n98\n.', 'While the channel \n40\n is positioned upstream of the constriction \n30\n (e.g., closer to the packer \n22\n), the additional channel \n96\n may be positioned at (e.g., axially aligned with) or downstream of the constriction \n30\n (e.g., further from the packer \n22\n).', 'In such cases, instead of identifying the leaked fluid by detecting a change in pressure (e.g., as compared to a baseline measurement) and/or a presence of fluid within the channel \n40\n, the leak detection system \n10\n may compare a first pressure measured by the sensor \n42\n to a second pressure measured by the additional sensor \n98\n.', 'A difference between the first and second pressure may indicate the presence of leaked fluid.', 'For example, when the packer \n22\n adequately seals against the rod \n14\n to block the fluid from passing into the low pressure region \n26\n of the bore \n16\n, the first and second pressure may be substantially the same (e.g., within 1, 2, 3, 4, or 5 percent; ambient atmospheric pressure).', 'However, when the packer \n22\n does not adequately seal against the rod \n14\n and the leaked fluid flows across the packer \n22\n, the leaked fluid may have a first pressure upstream of the constriction \n30\n and may have a second pressure that is lower than the first pressure at or downstream of the constriction \n30\n.', 'Accordingly, upon detection of a difference between the first pressure and the second pressure (e.g., a difference above a threshold, such as a difference of equal to or more than approximately 5, 10, 15, 20, 25, 50, or more percent), the processor \n82\n may determine that the leaked fluid is present in the low pressure region \n26\n of the bore \n16\n.', 'The difference between the first pressure and the second pressure may also provide an indication of a velocity of the leaked fluid and/or a severity of the leak (e.g., the leak detection system \n10\n may operate as a venturi flowmeter).', 'As discussed above, the processor \n82\n may instruct an actuator to increase the compressive force on the packer \n22\n in response to detection of the leaked fluid and/or may instruct the output device \n86\n to provide an output (e.g., alarm).', 'The processor \n82\n may use the difference to determine an amount by which to increase the compressive force on the packer \n22\n and/or the processor \n82\n may instruct the output device \n86\n to provide an output indicative of the velocity of the leaked fluid and/or a severity of the leak.', 'It should be appreciated that any of the features described above with respect to \nFIGS.', '1-5\n may be combined with one another.', 'For example, the bore \n16\n and the constriction \n30\n having the configuration shown in \nFIG.', '4\n may be formed by shaping the radially-inner wall \n18\n of the housing \n20\n (e.g., without a physically separate annular insert \n90\n).', 'Similarly, the annular insert \n90\n may be utilized in combination with the cavity \n44\n shown in \nFIG.', '1\n.', 'Furthermore, the additional channel \n96\n and the additional sensor \n98\n may be incorporated into the leak detection system \n10\n of \nFIG.', '1 or 4\n (e.g., positioned at or downstream of the constriction \n30\n).', 'The leak detection system \n10\n illustrated in \nFIGS.', '1-5\n may be used with various components \n12\n of the mineral extraction system.', 'For example, the leak detection system \n10\n may be utilized with various valves, such as a gate valves, ball valves, and the like.', 'In some cases, the leak detection system \n10\n may be utilized with a PCE stack.', 'To illustrate, \nFIG.', '6\n is a side view of a PCE stack \n100\n that may include the leak detection system \n10\n having any of the features described above with respect to \nFIGS.', '1-5\n.', 'As shown, the rod \n14\n may extend and move through the bore \n16\n defined by the various components of the PCE stack \n100\n, such as a stuffing box \n102\n, a tool catcher \n104\n, a lubricator section \n106\n, a tool trap \n108\n, a valve stack \n110\n, and a connector \n112\n that couples the PCE stack \n100\n to a wellhead or other structure.', 'These components are annular structures stacked vertically with respect to one another (e.g., coaxial) and extend from a first end \n114\n to a second end \n116\n of the PCE stack \n100\n.', 'As shown, the rod \n14\n extends from the first end \n114\n of the PCE stack \n100\n and over a sheave \n118\n to a winch \n120\n, and rotation of the winch \n120\n (e.g., a drum or spool of the winch \n120\n) raises and lowers the rod \n14\n with a tool \n122\n through the PCE stack \n100\n.', 'It should be appreciated that the PCE stack \n100\n may include various other components (e.g., cable tractoring wheels to pull the rod \n14\n through the stuffing box \n102\n, a pump-in sub to enable fluid injection).', 'In operation, the stuffing box \n102\n is configured to seal against the rod \n14\n (e.g., to seal an annular space about the rod \n14\n) to block a flow of fluid across the stuffing box \n102\n.', 'The tool catcher \n104\n is configured to engage or catch the tool \n122\n to block the tool \n122\n from being withdrawn vertically above the tool catcher \n104\n and/or to block the tool \n122\n from falling vertically into the wellbore \n16\n.', 'The lubricator section \n106\n may include one or more annular pipes joined to one another, and the lubricator section \n106\n may support or surround the tool \n122\n while it is withdrawn from the wellbore \n16\n.', 'The tool trap \n108\n is configured to block the tool \n122\n from falling vertically into the wellbore \n16\n while the tool trap \n108\n is in a closed position, and the valve stack \n110\n may include opposed pipe or shear rams that close to isolate the wellbore.', 'An actuation assembly \n124\n may be provided to adjust a compressive force (e.g., in a vertical direction) on a packer of the stuffing box \n102\n to adjust the seal against the rod \n14\n.', 'For example, movement of the actuation assembly \n124\n may squeeze the packer vertically, thereby driving the packer radially (e.g., toward the rod \n14\n) to increase a surface area and/or an effectiveness of the seal against the rod \n14\n.', 'The actuation assembly \n124\n may include an actuator \n126\n (e.g., an electric, linear actuator; hydraulic actuator; pneumatic actuator) that may generate a force that is applied to a lever and/or a piston that is configured to contact and compress the packer vertically to seal around the rod \n14\n.', 'The actuator \n126\n may be communicatively coupled to the controller \n80\n to enable the processor \n82\n to provide instructions to the actuator \n126\n in response to the detection of the leaked fluid, as disclosed herein.', 'The leak detection system \n10\n may be integrated into and/or positioned vertically above the stuffing box \n102\n.', 'To illustrate, \nFIG.', '7\n is a side cross-sectional view of a portion the PCE stack \n100\n of \nFIG.', '6\n having the leak detection system \n10\n integrated into and/or positioned vertically above the stuffing box \n102\n.', 'The illustrated components may be analogous to the component \n12\n shown in \nFIGS.', '1-5\n, and it should be appreciated that the PCE stack \n100\n may include any combination of the features of the leak detection systems \n10\n disclosed herein.', 'In the illustrated embodiment, the stuffing box \n102\n includes the housing \n20\n supporting the packer \n22\n.', 'The housing \n20\n includes multiple housing sections coupled to one another.', 'In particular, the housing \n20\n includes a first annular body \n130\n (e.g., outer body), a second annular body \n132\n (e.g., inner body), and a third annular body \n134\n (e.g., upper body; leak detection body).', 'The bodies \n130\n, \n132\n, \n134\n may be coupled to one another via respective threaded interfaces \n136\n or any other suitable technique (e.g., one or more fasteners, such as bolts; integrally formed).', 'The bodies \n130\n, \n132\n, \n134\n define the bore \n16\n that receives the rod \n14\n.', 'The housing \n20\n (e.g., the third annular body \n134\n of the housing \n20\n) is shaped to define the constriction \n30\n, the channel \n40\n, and the additional channel \n96\n.', 'As noted above, the additional channel \n96\n may be optional.', 'In the absence of the additional channel \n96\n, the leaked fluid may be diverted into the channel \n40\n and/or otherwise detected by the sensor \n42\n (e.g., via a change in pressure compared to a baseline measurement).', 'When both the channel \n40\n and the additional channel \n96\n are present, the leak detection system \n10\n may compare a first pressure measured by the sensor \n42\n to a second pressure measured by the additional sensor \n98\n.', 'The difference between the first and second pressure may indicate the presence of leaked fluid.', 'For example, when the packer \n22\n adequately seals against the rod \n14\n to block the fluid from passing into the low pressure region \n26\n of the bore \n16\n, the first and second pressure may be substantially the same (e.g., within 1, 2, 3, 4, or 5 percent; ambient atmospheric pressure).', 'However, when the packer \n22\n does not adequately seal against the rod \n14\n and the leaked fluid flows across the packer \n22\n, the leaked fluid may have a first pressure upstream of the constriction \n30\n (e.g., on a first side \n140\n of the constriction \n30\n) and may have a second pressure that is lower than the first pressure at or downstream of the constriction \n30\n (e.g., at or on a second side \n142\n of the constriction \n30\n).', 'Accordingly, upon detection of a difference between the first pressure and the second pressure (e.g., a difference above a threshold, such as a difference of equal to or more than approximately 5, 10, 15, 20, 25, 50, or more percent), the processor \n82\n may determine that the leaked fluid is present.', 'As discussed above, the processor \n82\n may instruct the actuator \n126\n (\nFIG.', '6\n) to increase the compressive force on the packer \n22\n and/or may instruct the output device \n86\n to provide an output (e.g., alarm) in response to detection of the leaked fluid.', 'The difference between the first pressure and the second pressure may also provide an indication of a velocity of the leaked fluid and/or a severity of the leak (e.g., the leak detection system \n10\n may operate as a venturi flowmeter).', 'The processor \n82\n may use the difference to determine an amount by which to increase the compressive force on the packer \n22\n and/or the processor \n82\n instruct the output device \n86\n to provide an output indicative of the velocity of the leaked fluid and/or a severity of the leak.\n \nFIG.', '8\n is a flow chart of a method \n150\n of operating the leak detection system \n10\n, in accordance with an embodiment of the present disclosure.', 'The method \n150\n disclosed herein includes various steps represented by blocks.', 'It should be noted that at least some steps of the method \n150\n may be performed as an automated procedure by a system, such as the controller \n80\n.', 'Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Additionally, steps may be added to or omitted from of the method \n150\n.', 'The method \n150\n may include moving the rod \n14\n through the bore \n16\n defined by the housing \n20\n, in step \n152\n.', 'The method \n150\n may include sealing the packer \n22\n about the rod \n14\n as the rod \n14\n moves through the bore \n16\n defined by the housing \n20\n, in step \n154\n.', 'The method \n150\n may also include operating the sensor \n42\n that is positioned outside of the bore \n16\n and that this fluidly coupled to the channel \n40\n to detect the leaked fluid as the rod \n14\n moves through the bore \n16\n defined by the housing \n20\n, in step \n156\n.', 'Additional details and/or steps of the method \n150\n may be understood with reference to the discussion of \nFIGS.', '1-7\n.', 'For example, the method \n150\n may further include operating the additional sensor \n98\n that is positioned outside of the bore \n16\n and that is fluidly coupled to the additional channel \n96\n to detect the leaked fluid as the rod \n14\n moves through the bore \n16\n defined by the housing \n20\n.', 'The method \n150\n may include the various processing and control steps (e.g., processing data from the sensor \n42\n and/or the additional sensor \n98\n to detect the leaked fluid; providing control signals to the actuator \n126\n and/or the output device \n86\n).', 'As discussed above, the constriction \n30\n within the bore \n16\n may facilitate detection of the leaked fluid, such as by diverting the leaked fluid into the channel \n40\n and/or by providing a pressure differential across the constriction \n30\n that can be detected by the sensor \n42\n and the additional sensor \n98\n, for example.', 'Thus, the leaked fluid may be detected in various ways, such as by directly detecting the leaked fluid within the channel \n40\n and/or by detecting changes in pressure (e.g., as compared to a baseline measurement and/or based on a difference between the first pressure at the sensor \n42\n and the second pressure at the additional sensor \n98\n) caused by the leaked fluid.', 'The method \n150\n may be utilized to detect the leaked fluid in any of a variety of components \n12\n of the mineral extraction system, including any of a variety of valves, the stuffing box \n102\n of the PCE stack \n100\n, or the like.', 'While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.', 'Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.'] | ['1.', 'A leak detection system, comprising:\nan annular housing that defines a bore;\nan annular packer disposed within the annular housing and configured to seal against a rod that moves through the bore;\na constriction within the bore;\na channel extending radially-outwardly from the bore and positioned upstream of the constriction;\na sensor positioned outside of the bore and fluidly coupled to the channel, wherein the sensor is configured to detect a leaked fluid within the bore; and\nan actuator configured to compress the annular packer to adjust the seal against the rod in response to the sensor detecting the leaked fluid within the bore.', '2.', 'The leak detection system of claim 1, wherein the constriction is formed by a radially-inner wall of the annular housing.', '3.', 'The leak detection system of claim 1, wherein the constriction is formed by an annular insert coupled to the annular housing.', '4.', 'The leak detection system of claim 1, wherein the sensor comprises a flow sensor, a pressure sensor, an acoustic sensor, an optical sensor, a mechanical sensor, or any combination thereof.', '5.', 'The leak detection system of claim 1, wherein the channel is positioned between the annular packer and the constriction along a longitudinal axis of the bore.', '6.', 'The leak detection system of claim 5, comprising a cavity within the bore, wherein the cavity is a region of an expanded diameter within the bore and is positioned at an intersection between the longitudinal axis of the bore and a respective longitudinal axis of the channel.', '7.', 'The leak detection system of claim 1, comprising an additional channel extending radially-outwardly from the bore and an additional sensor positioned outside of the bore and fluidly coupled to the additional channel.', '8.', 'The leak detection system of claim 7, wherein the additional channel is axially aligned with the constriction.', '9.', 'The leak detection system of claim 7, comprising one or more processors, wherein the one or more processors are configured to receive pressure data from the sensor and the additional sensor, to process the pressure data, and to determine that the leaked fluid is present within the bore in response to identifying a difference between a first pressure at the sensor and a second pressure at the additional sensor.', '10.', 'The leak detection system of claim 1, comprising one or more processors, where in the one or more processors are configured to receive sensor data from the sensor, to process the sensor data, and to determine that the leaked fluid is present within the bore in response to identifying a difference between the sensor data and baseline data.', '11.', 'A component of a mineral extraction system, comprising:\nan annular housing that defines a bore;\nan annular packer configured to seal against a rod that moves through the bore;\na constriction within the bore;\na channel extending radially-outwardly from the bore;\na sensor positioned outside of the bore and fluidly coupled to the channel, wherein the sensor is configured to detect a leaked fluid that leaked across the annular packer; and\none or more processors, wherein the one or more processors are configured to receive sensor data from the sensor, to process the sensor data, to determine that the leaked fluid is present in response to identifying a difference between the sensor data and baseline data, and to instruct an actuator to compress the annular packer to adjust the seal against the rod in response to determining that the leaked fluid is present.', '12.', 'The component of claim 11, wherein the channel is positioned between the annular packer and the constriction along a longitudinal axis of the bore.', '13.', 'The component of claim 11, comprising an additional channel extending radially-outwardly from the bore and an additional sensor positioned outside of the bore and fluidly coupled to the additional channel.', '14.', 'The component of claim 13, wherein the additional channel is axially aligned with the constriction.', '15.', 'The component of claim 11, wherein the component comprises a stuffing box of a pressure control equipment stack.', '16.', 'The component of claim 11, wherein the component comprises a valve, and the rod comprises a reciprocating or rotating valve stem of the valve.', '17.', 'A method of operating a leak detection system for a component of a mineral extraction system, comprising:\nmoving a rod through a bore defined by an annular housing;\nsealing an annular packer about the rod as the rod moves through the bore defined by the annular housing;\noperating a sensor to detect a leaked fluid that leaked across the annular packer as the rod moves through the bore defined by the annular housing, wherein the sensor is positioned outside of the bore and is fluidly coupled to a channel that extends radially-outwardly from the bore at an axial location between a constriction within the bore and the annular packer; and\ncompressing the annular packer to adjust the seal against the rod in response to determining that the leaked fluid is present.', '18.', 'The method of claim 17, operating an additional sensor to detect the leaked fluid that leaked across the annular packer as the rod moves through the bore defined by the annular housing, wherein the additional sensor is positioned outside of the bore and is fluidly coupled to an additional channel that extends radially-outwardly from the bore at a respective location that is axially aligned with the constriction.', '19.', 'The method of claim 17, diverting the leaked fluid into the channel using the constriction to facilitate detection of the leaked fluid by the sensor.'] | ['FIG.', '1 is a side cross-sectional view of a leak detection system for a component of a mineral extraction system, in accordance with an embodiment of the present disclosure;; FIG.', '2', 'is side cross-sectional view of a sensor within a channel of the leak detection system of FIG.', '1, in accordance with an embodiment of the present disclosure;; FIG.', '3 is a side cross-sectional view of a sensor within a chamber that is fluidly coupled to the channel of the leak detection system of FIG.', '1, in accordance with an embodiment of the present disclosure;; FIG. 4 is a side cross-sectional view of a leak detection system for a component of a mineral extraction system, wherein the leak detection system includes an annular insert, in accordance with another embodiment of the present disclosure;; FIG.', '5 is a side cross-sectional view of a leak detection system for a component of a mineral extraction system, wherein the leak detection system includes multiple channels, in accordance with another embodiment of the present disclosure;; FIG.', '6 is a side view of a pressure control equipment (PCE) stack having a leak detection system, in accordance with an embodiment of the present disclosure;; FIG. 7 is a side cross-sectional view of a portion of the PCE stack of FIG.', '6, in accordance with an embodiment of the present disclosure; and; FIG. 8 is a method of operating a leak detection system for a component of a mineral extraction system, in accordance with an embodiment of the present disclosure.', '; FIG.', '5 illustrates the housing 20 with another configuration that may facilitate diversion of the leaked fluid into the channel 40 and/or detection of the leaked fluid by the sensor 42.', 'As discussed in more detail below, FIG. 5 also illustrates an optional additional channel 96 (e.g., radially-extending channel; flow path; leak detection path) that may be used in the leak detection system 10.; FIG.', '8 is a flow chart of a method 150 of operating the leak detection system 10, in accordance with an embodiment of the present disclosure.', 'The method 150 disclosed herein includes various steps represented by blocks.', 'It should be noted that at least some steps of the method 150 may be performed as an automated procedure by a system, such as the controller 80.', 'Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Additionally, steps may be added to or omitted from of the method 150.'] |
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US11105198 | Methods for in-situ multi-temperature measurements using downhole acquisition tool | Mar 31, 2016 | Hadrien Dumont, Christopher Harrison, Youxiang Zuo, Christopher Albert Babin, Li Chen, Vinay K. Mishra, German Garcia, Abhishek Agarwal, Matthew T. Sullivan | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 4690216; September 1, 1987; Pritchard, Jr.; 5691809; November 25, 1997; Tackett et al.; 6755079; June 29, 2004; Proett et al.; 8335650; December 18, 2012; Hsu et al.; 8564768; October 22, 2013; Schroeder et al.; 8910514; December 16, 2014; Sullivan et al.; 9303510; April 5, 2016; Dumont et al.; 20100263442; October 21, 2010; Hsu; 20120024050; February 2, 2012; Godager; 20120145400; June 14, 2012; Harrison et al.; 20130111985; May 9, 2013; Veeningen; 20130219997; August 29, 2013; Sullivan; 20130243028; September 19, 2013; Singh; 20150309002; October 29, 2015; Fukagawa; 20160362977; December 15, 2016; Feng et al.; 20170175524; June 22, 2017; Dumont et al. | WO2014158376; October 2014; WO | ['Methods for obtaining in-situ, multi-temperature measurements of fluid properties, such as saturation pressure and asphaltene onset pressure include obtaining a sample of formation fluid using a downhole acquisition tool positioned in a wellbore in a geological formation.', 'The downhole acquisition tool may be stationed at a first depth in the wellbore that has an ambient first temperature.', 'While stationed at the first depth, the downhole acquisition tool may test a first fluid property of the sample to obtain a first measurement point at approximately the first temperature.', 'The downhole acquisition tool may be moved to a subsequent station at a new depth with an ambient second temperature, and another measurement point obtained at approximately the second temperature.', 'From the measurement points, a temperature-dependent relationship of the first fluid property of the first formation fluid may be determined.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates to measuring properties of formation fluid at various temperatures downhole using a downhole acquisition tool.', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'Reservoir fluid analysis may be used in a wellbore in a geological formation to locate hydrocarbon-producing regions in the geological formation, as well as to manage production of the hydrocarbons in these regions.', 'A downhole acquisition tool may carry out reservoir fluid analysis by drawing in formation fluid and testing the formation fluid downhole or collecting a sample of the formation fluid to bring to the surface.', 'The downhole acquisition tool may include various devices, such as probes and/or packers, that may be used to isolate a desired region of the wellbore (e.g., at a desired depth) and establish fluid communication with the subterranean formation surrounding the wellbore.', 'The probe may draw the formation fluid into the downhole acquisition tool, and direct the formation fluid to one or more fluid analyzers and sensors.', 'The fluid analyzers and sensors may measure fluid properties of the formation fluid.', 'The hydrocarbon-producing regions in the geological formation may be located based on the measured fluid properties of the formation fluid.', 'In certain downhole fluid analysis applications, saturation pressure (PSAT) and asphaltene onset pressure (AOP) of the formation fluid may be tested or estimated.', 'The PSAT of the formation fluid generally describes a relationship between temperature and pressure at which the formation fluid changes phase between liquid and gas.', 'As such, it is sometimes also referred to as the “bubble point” for a liquid, or a “dew point” for a gas.', 'The AOP of the formation fluid generally describes a relationship between temperature and pressure at which the formation fluid begins to precipitate asphaltene components.', 'The downhole acquisition tool may estimate the PSAT and AOP of the formation fluid by collecting a sample of the formation fluid and measuring various fluid properties (e.g., optical density, density, gas-to-oil ratio, pressure, temperature, among others) of the sample.', 'One technique involves obtaining a sample at the bottom of a well and measuring its properties as the downhole acquisition tool is pulled out of the wellbore.', 'Since temperature tends to increase with well depth, the temperature tends to gradually decrease as the downhole acquisition tool is pulled out.', 'As a result, some temperature/pressure coordinates that relate to the PSAT and the AOP of the sample of the formation fluid may be identified.', 'The PSAT and AOP points measured in this way may be used for phase envelope modeling of the formation fluid in an equation of state.', 'Since the PSAT and AOP also tend to vary by temperature, the accuracy of the phase envelope modeling of the formation fluid in the equation of state may depend on the particular temperatures of the measurements while the downhole acquisition tool is being pulled out of the well.', 'Moreover, although this technique may provide some PSAT and AOP measurements for one sample of formation fluid from the well, various depths in the well may have formation fluids with different respective properties for which knowledge of the PSAT and AOP may be valuable.', 'SUMMARY\n \nA summary of certain embodiments disclosed herein is set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'This disclosure relates to obtaining in-situ, multi-temperature measurements of fluid properties, such as saturation pressure and asphaltene onset pressure.', 'In one example, a sample of formation fluid is obtained using a downhole acquisition tool positioned in a wellbore in a geological formation.', 'The downhole acquisition tool may be stationed at a first depth in the wellbore that has an ambient first temperature.', 'While stationed at the first depth, the downhole acquisition tool may test a first fluid property of the sample to obtain a first measurement point at approximately the first temperature.', 'The downhole acquisition tool may be moved to a subsequent station at a new depth with an ambient second temperature, and another measurement point obtained at approximately the second temperature.', 'From the measurement points, a temperature-dependent relationship of the first fluid property of the first formation fluid may be determined.', 'In another example, one or more tangible, machine-readable media may include instructions to receive a first set of measurement values of a first temperature-dependent fluid property of a first formation fluid measured in-situ by a downhole acquisition tool, and fit the first set of measurement values to a first curve.', 'The first set of measurement values may be obtained while the downhole acquisition tool is located at different respective depths, each of which has a different respective ambient temperature.', 'This may cause the measurement values to be measured at corresponding different respective temperatures.', 'The first curve may fit the measurement values to the first temperature-dependent fluid property over a range of temperatures including the different respective temperatures.', 'In another example, a method includes obtaining a sample of a first formation fluid from a first fluid zone in a wellbore using a downhole acquisition tool and obtaining a sample of a second formation fluid from a second fluid zone in the wellbore using the downhole acquisition tool.', 'At each of a number of stations at different depths in the wellbore having different respective ambient temperatures, fluid testing may be performed on at least part of the sample of the first formation fluid and on at least part of the sample of the second formation fluid.', 'Based on the fluid testing, a first temperature-dependent relationship of a first fluid property of the first formation fluid and a second temperature-dependent relationship of the first fluid property of the second formation fluid may be identified.', 'Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:\n \nFIG.', '1\n is a schematic diagram of a well site system that may be used to identify multiple points of a phase envelope of a formation fluid, in accordance with an embodiment;\n \nFIG.', '2\n is a schematic diagram of another example of a well site system that may be used to identify multiple points of a phase envelope of a formation fluid, in accordance with an embodiment;\n \nFIG.', '3\n is a plot of a phase diagram of formation fluid, in accordance with an embodiment;\n \nFIG.', '4\n is a plot showing potential phase envelopes in a phase diagram for saturation pressure (PSAT) when only a single saturation pressure point has been identified;\n \nFIG.', '5\n is a plot showing potential phase envelopes in a phase diagram for asphaltene onset pressure (AOP) when only a single pressure point has been identified;\n \nFIG.', '6\n is a schematic diagram of variations in temperature and pressure throughout the depth of the wellbore, in accordance with an embodiment;\n \nFIG.', '7\n is a flowchart of a method for identifying multiple points of a phase envelope (e.g., saturation pressure or asphaltene onset pressure) of a formation fluid, in accordance with an embodiment;\n \nFIG.', '8\n is a simulated phase diagram of formation fluid having phase envelope models constrained to the data points obtained using the method of \nFIG.', '7\n, in accordance with an embodiment; and\n \nFIG.', '9\n is a plot showing that other properties, such as viscosity, may also be identified at various temperatures in accordance with the systems and methods of this disclosure.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'Acquisition and analysis of representative formation fluid samples downhole in delayed or real time may be useful for determining the economic value of hydrocarbon reserves and oil field development.', 'A downhole acquisition tool may acquire formation fluid and test the formation fluid to determine and/or estimate phase temperature/pressure data points of envelopes.', 'For example, the downhole acquisition tool pressure saturation (PSAT), asphaltene onset pressure (AOP), and/or wax appearance temperature (WAT) may be tested on several different samples at multiple temperatures in-situ.', 'For example, the downhole acquisition tool may measure one or more fluid properties (e.g., optical density, density, gas-to-oil ratio, viscosity, among others) of various samples of formation fluid that were obtained at different depths.', 'By testing the samples for PSAT, AOP, and/or WAT at several different depths, the particular pressure values where these phase envelopes occur may be ascertained for a variety of different temperatures.', 'This may provide a more complete measurement of the phase envelopes at a variety of depths.', 'As a result, a more accurate model of the formation fluids may be obtained for phase envelope modeling and/or to generate phase diagrams of the formation fluid.', 'It may be valuable to obtain more accurate measurements of phase envelopes of formation fluids from different depths.', 'Indeed, one way in which formation fluids from different fluid zones may vary from their individual formation fluid components may be the phase envelopes that describe the behavior of the mixed fluid.', 'Phase envelopes may be diagrammatically represented as curves relating pressure and temperature.', 'On different sides of the curve, the formation fluid may have different phase behavior.', 'For example, a saturation pressure (PSAT) phase envelope describes the temperature and pressures delineating liquid vs. gas behavior.', 'When the formation fluid is at a temperature and pressure above the PSAT phase envelope, the formation fluid may be substantially gas-free, but when the formation fluid is at a temperature and pressure on the other side of the PSAT phase envelope, gas bubbles may begin to form in the formation fluid.', 'In another example, an asphaltene onset pressure (AOP) phase envelope describes the temperature and pressures delineating the appearance of asphaltene components in the formation fluid.', 'When the formation fluid is at a temperature and pressure above the AOP phase envelope, the formation fluid may be substantially free of asphaltenes, but when the formation fluid is at a temperature and pressure on the other side of the AOP phase envelope, asphaltene components may begin to fall out of solution in the formation fluid.', 'Accurately modeling the phase envelopes of the formation fluids may be tremendously valuable for hydrocarbon exploration and production.', 'Indeed, as formation fluids are produced, the formation fluids may experience a range of temperatures and pressures.', 'As a formation fluid is produced, the temperatures and pressures of the well may gradually decrease.', 'At some point, the temperatures and pressures may reach a “bubble point” when the fluid breaks phase at the saturation pressure (PSAT), producing gaseous and liquid phases.', 'In addition, the formation fluid may break phase in the formation itself during production.', 'For example, one zone of the formation may contain oil with dissolved gas.', 'During production, the formation pressure may drop to the extent that the bubble point pressure is reached, allowing gas to emerge from the oil, causing production concerns.', 'At times, too, the formation fluid may experience changes in pressure and temperature that cause asphaltenes to begin to appear, which could result in production-choking “tar mats.”', 'Thus, accurate modeling of the phase envelopes may be very helpful when designing production strategies.', 'Moreover, other fluid properties may also change with temperature and pressure.', 'As noted above, the temperature tends to decrease as the fluid is transiting from the wellbore bottom to the surface.', 'This tends to increase the fluid viscosity as the formation fluid is being extracted.', 'To accurately calculate the flow rate during production, an accurate estimate of the viscosity may be useful.', 'Rather than, or in addition to, measuring the PSAT, AOP, and/or WAT properties of a formation fluid just at the depth where it was collected, or by measuring only a single sample as the downhole acquisition tool is pulled out from the well, the systems and methods of this disclosure may obtain samples of formation fluids at different depths and measure properties related to their phase envelopes at multiple different depths—and thus multiple different temperatures in-situ.', 'In one example, formation fluids may be sampled at different stations and stored in different chambers.', 'At several different depths, part of the formation fluid from each of the different samples may be tested to identify PSAT, AOP, and/or WAT at the temperature that naturally occurs at that depth using a pressure-volume-temperature (PVT) tester.', 'By collecting multiple data points identifying the PSAT, AOP, and/or WAT at multiple different temperatures, more accurate models of the phase envelopes (which may vary with temperature and pressure) of the formation fluid samples may be ascertained.', 'Additionally or alternatively, the downhole acquisition tool may test the PSAT, AOP, and/or WAT of a mixture of formation fluids from different stations at different depths and, accordingly, different temperatures.', 'FIGS.', '1 and 2\n depict examples of wellsite systems that may employ such fluid analysis systems and methods.', 'In \nFIG.', '1\n, a rig \n10\n suspends a downhole acquisition tool \n12\n into a wellbore \n14\n via a drill string \n16\n.', 'A drill bit \n18\n drills into a geological formation \n20\n to form the wellbore \n14\n.', 'The drill string \n16\n is rotated by a rotary table \n24\n, which engages a kelly \n26\n at the upper end of the drill string \n16\n.', 'The drill string \n16\n is suspended from a hook \n28\n, attached to a traveling block, through the kelly \n26\n and a rotary swivel \n30\n that permits rotation of the drill string \n16\n relative to the hook \n28\n.', 'The rig \n10\n is depicted as a land-based platform and derrick assembly used to form the wellbore \n14\n by rotary drilling.', 'However, in other embodiments, the rig \n10\n may be an offshore platform.', 'Drilling fluid referred to as drilling mud \n32\n, is stored in a pit \n34\n formed at the wellsite.', 'A pump \n36\n delivers the drilling mud \n32\n to the interior of the drill string \n16\n via a port in the swivel \n30\n, inducing the drilling mud \n32\n to flow downwardly through the drill string \n16\n as indicated by a directional arrow \n38\n.', 'The drilling mud \n32\n exits the drill string \n16\n via ports in the drill bit \n18\n, and then circulates upwardly through the region between the outside of the drill string \n16\n and the wall of the wellbore \n14\n, called the annulus, as indicated by directional arrows \n40\n.', 'The drilling mud \n32\n lubricates the drill bit \n18\n and carries formation cuttings up to the surface as it is returned to the pit \n34\n for recirculation.', 'The downhole acquisition tool \n12\n, sometimes referred to as a component of a bottom hole assembly (“BHA”), may be positioned near the drill bit \n18\n and may include various components with capabilities such as measuring, processing, and storing information, as well as communicating with the surface.', 'Additionally or alternatively, the downhole acquisition tool \n12\n may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or other suitable types of conveyance.', 'The downhole acquisition tool \n12\n may further include a sampling system \n42\n, which may include a fluid communication module \n46\n, a sampling module \n48\n, and a sample bottle module \n49\n.', 'In a logging-while-drilling (LWD) configuration, the modules may be housed in a drill collar for performing various formation evaluation functions, such as pressure testing and fluid sampling, among others, and collecting representative samples of native formation fluid \n50\n.', 'The example of \nFIG.', '1\n includes two fluid zones \n51\nA and \n51\nB where the native formation fluid \n50\n may enter the wellbore \n14\n.', 'The native formation fluid \n50\n from the fluid zones \n51\nA and \n51\nB may have different properties, particularly if the fluid zones \n51\nA and \n51\nB are hydraulically isolated from one another.', 'As shown in \nFIG.', '1\n, the fluid communication module \n46\n is positioned adjacent the sampling module \n48\n; however the position of the fluid communication module \n46\n, as well as other modules, may vary in other embodiments.', 'Additional devices, such as pumps, gauges, sensors, monitors or other devices usable in downhole sampling and/or testing also may be provided.', 'The additional devices may be incorporated into modules \n46\n or \n48\n or disposed within separate modules included within the sampling system \n42\n.', 'The downhole acquisition tool \n12\n may evaluate fluid properties of an obtained fluid \n52\n.', 'Generally, when the obtained fluid \n52\n is initially taken in by the downhole acquisition tool \n12\n, the obtained fluid \n52\n may include some drilling mud \n32\n, some mud filtrate \n54\n on a wall \n58\n of the wellbore \n14\n, and the native formation fluid \n50\n.', 'To isolate the native formation fluid \n50\n, the downhole acquisition tool \n12\n may identify an amount of contamination that is likely present in the obtained fluid \n52\n.', 'When the contamination level is sufficiently low, the obtained fluid \n52\n may substantially represent uncontaminated native formation fluid \n50\n.', 'In this way, the downhole acquisition tool \n12\n may store a sample of the native formation fluid \n50\n or perform a variety of in-situ testing to identify properties of the native formation fluid \n50\n.', 'Accordingly, the sampling system \n42\n may include sensors that may measure fluid properties such as gas-to-oil ratio (GOR); mass density; optical density (OD); composition of carbon dioxide (CO\n2\n), C\n1\n, C\n2\n, C\n3\n, C\n4\n, C\n5\n, and/or C\n6+\n; formation volume factor; viscosity; resistivity; conductivity, fluorescence; compressibility, and/or combinations of these properties of the obtained fluid \n52\n.', 'In on example, the sampling system \n42\n may include a pressure-volume-temperature (PVT) tester component that includes a volume that can change pressures using a piston or micropiston.', 'The PVT tester component may be used to identify a pressure where the fluid held in its volume crosses a phase envelope.', 'The PVT tester component may operate as described by Application No. PCT/US2014/015467, which is incorporated by reference herein in its entirety for all purposes.', 'In addition, the sampling system \n42\n may be used to monitor mud filtrate contamination to determine an amount of the drilling mud filtrate \n54\n in the obtained fluid \n52\n.', 'When the amount of drilling mud filtrate \n54\n in the obtained fluid \n52\n falls beneath a desired threshold, the remaining native formation fluid \n50\n may be stored as a sample and/or tested.', 'The fluid communication module \n46\n includes a probe \n60\n, which may be positioned in a stabilizer blade or rib \n62\n.', 'The probe \n60\n includes one or more inlets for receiving the obtained fluid \n52\n and one or more flow lines (not shown) extending into the downhole tool \n12\n for passing fluids (e.g., the obtained fluid \n52\n) through the tool.', 'In certain embodiments, the probe \n60\n may include a single inlet designed to direct the obtained fluid \n52\n into a flowline within the downhole acquisition tool \n12\n.', 'Further, in other embodiments, the probe \n60\n may include multiple inlets (e.g., a sampling probe and a guard probe) that may, for example, be used for focused sampling.', 'In these embodiments, the probe \n60\n may be connected to a sampling flowline, as well as to guard flow lines.', 'The probe \n60\n may be movable between extended and retracted positions for selectively engaging the wellbore wall \n58\n of the wellbore \n14\n and acquiring fluid samples from the geological formation \n20\n.', 'One or more setting pistons \n64\n may be provided to assist in positioning the fluid communication device against the wellbore wall \n58\n.', 'The sensors within the sampling system \n42\n may collect and transmit data \n70\n from the measurement of the fluid properties and the composition of the obtained fluid \n52\n to a control and data acquisition system \n72\n at surface \n74\n, where the data \n70\n may be stored and processed in a data processing system \n76\n of the control and data acquisition system \n72\n.', 'The data processing system \n76\n may include a processor \n78\n, memory \n80\n, storage \n82\n, and/or display \n84\n.', 'The memory \n80\n may include one or more tangible, non-transitory, machine readable media collectively storing one or more sets of instructions for operating the downhole acquisition tool \n12\n and estimating an amount of mud filtrate \n54\n in the obtained fluid \n52\n.', 'The memory \n80\n may store mixing rules and algorithms associated with the native formation fluid \n50\n (e.g., uncontaminated formation fluid), the drilling mud \n32\n, and combinations thereof to facilitate estimating an amount of the drilling mud \n32\n in the obtained fluid \n52\n.', 'The data processing system \n76\n may use the fluid property and composition information of the data \n70\n to estimate an amount of the mud filtrate in the obtained fluid \n52\n and/or model phase envelopes or other properties of the obtained fluid \n52\n.', 'These may be used in one or more equations of state (EOS) models describing the obtained fluid \n52\n (e.g., the native formation fluid \n50\n) or, more generally, a reservoir in the geological formation \n20\n.', 'Accordingly, more accurate estimates of the phase envelopes of the obtained fluid \n52\n may likely result in more accurate EOS models.', 'To process the data \n70\n, the processor \n78\n may execute instructions stored in the memory \n80\n and/or storage \n82\n.', 'For example, the instructions may cause the processor \n78\n to estimate fluid and compositional parameters of the native formation fluid \n50\n of the obtained fluid \n52\n, and control flow rates of the sample and guard probes, and so forth.', 'As such, the memory \n80\n and/or storage \n82\n of the data processing system \n76\n may be any suitable article of manufacture that can store the instructions.', 'By way of example, the memory \n80\n and/or the storage \n82\n may be ROM memory, random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive.', 'The display \n84\n may be any suitable electronic display that can display information (e.g., logs, tables, cross-plots, etc.) relating to properties of the well as measured by the downhole acquisition tool \n12\n.', 'It should be appreciated that, although the data processing system \n76\n is shown by way of example as being located at the surface \n74\n, the data processing system \n76\n may be located in the downhole acquisition tool \n12\n.', 'In such embodiments, some of the data \n70\n may be processed and stored downhole (e.g., within the wellbore \n14\n), while some of the data \n70\n may be sent to the surface \n74\n (e.g., in real time or near real time).', 'FIG.', '2\n depicts an example of a wireline downhole tool \n100\n that may employ the systems and methods of this disclosure.', 'The downhole tool \n100\n is suspended in the wellbore \n14\n from the lower end of a multi-conductor cable \n104\n that is spooled on a winch at the surface \n74\n.', 'Like the downhole acquisition tool \n12\n, the wireline downhole tool \n100\n may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or any other suitable conveyance.', 'The cable \n104\n is communicatively coupled to an electronics and processing system \n106\n.', 'The downhole tool \n100\n includes an elongated body \n108\n that houses modules \n110\n, \n112\n, \n114\n, \n122\n, and \n124\n, that provide various functionalities including fluid sampling, sample bottle filling, fluid testing, operational control, and communication, among others.', 'For example, the modules \n110\n and \n112\n may provide additional functionality such as fluid analysis, resistivity measurements, operational control, communications, coring, and/or imaging, among others.', 'As shown in \nFIG.', '2\n, the module \n114\n is a fluid communication module \n114\n that has a selectively extendable probe \n116\n and backup pistons \n118\n that are arranged on opposite sides of the elongated body \n108\n.', 'The extendable probe \n116\n selectively seals off or isolates selected portions of the wall \n58\n of the wellbore \n14\n to fluidly couple to the adjacent geological formation \n20\n and/or to draw fluid samples from the geological formation \n20\n.', 'For example, the probe \n116\n may obtain and store some native formation fluid \n50\n from the first fluid zone \n51\nA and obtain and store some native formation fluid \n50\n from the second fluid zone \n51\nB.', 'The probe \n116\n may include a single inlet or multiple inlets designed for guarded or focused sampling.', 'The native formation fluid \n50\n may be expelled to the wellbore \n14\n through a port in the body \n108\n or the obtained fluid \n52\n, including the native formation fluid \n50\n, may be sent to one or more fluid sampling modules \n122\n and \n124\n.', 'The fluid sampling modules \n122\n and \n124\n may include sample chambers that store the obtained fluid \n52\n.', 'In the illustrated example, the electronics and processing system \n106\n and/or a downhole control system are configured to control the extendable probe assembly \n116\n and/or the drawing of a fluid sample from the geological formation \n20\n to enable analysis of the obtained fluid \n52\n.', 'The sampling system \n42\n may obtain a variety of measurements that can be used to identify phase envelope boundaries of formation fluids \n50\n.', 'A phase diagram \n140\n shown in \nFIG.', '3\n provides one example of phase envelopes that may describe a formation fluid \n50\n.', 'The phase diagram \n140\n describes behavior of the formation fluid \n50\n at various pressures (ordinate \n142\n) and temperatures (abscissa \n144\n).', 'The phase envelopes represented in the phase diagram \n140\n include an asphaltene onset pressure (AOP) phase envelope \n146\n and a saturation pressure (PSAT) phase envelope \n148\n.', 'Other phase envelopes that may describe the behavior of the formation fluid \n50\n, but which are not expressly shown in \nFIG.', '3\n, include wax appearance temperature (WAT) and others relating to more exotic phases.', 'On different sides of the phase envelopes \n146\n and \n148\n, the formation fluid \n50\n may have different phase behavior.', 'For example, the saturation pressure (PSAT) phase envelope \n148\n describes the relationship between temperatures and pressure delineating liquid vs. gas behavior.', 'When the formation fluid \n50\n is at a temperature and pressure above the PSAT phase envelope \n148\n, the formation fluid \n50\n may be substantially gas-free, but when the formation fluid \n50\n is at a temperature and pressure beneath the PSAT phase envelope \n148\n, gas bubbles may begin to form in the formation fluid \n50\n.', 'In another example, the asphaltene onset pressure (AOP) phase envelope \n146\n describes the relationship between temperature and pressure delineating the appearance of asphaltene components in the formation fluid \n50\n.', 'When the formation fluid \n50\n is at a temperature and pressure above the AOP phase envelope \n146\n, the formation fluid \n50\n may be substantially free of asphaltenes, but when the formation fluid \n50\n is at a temperature and pressure beneath the AOP phase envelope \n146\n, asphaltene components may begin to fall out of solution in the formation fluid \n50\n.', 'As mentioned above, the sampling systems \n42\n of the downhole tool \n12\n or the downhole tool \n100\n may perform pressure-volume-temperature (PVT) testing that can ascertain certain data points on the phase envelopes for saturation pressure (PSAT), asphaltene onset pressure (AOP), and/or other indications of phase envelope behavior of fluids, such as wax appearance temperature (WAT).', 'Other fluid properties of the fluids may also be obtained in-situ, including fluid viscosity, density, composition, gas-to-oil ratio (GOR), differential vaporization, and so forth.', 'For example, the sampling system \n42\n may perform PVT testing using a micropiston to maintain, increase, or decrease the pressure of a fluid sample being tested in the sampling system \n42\n while fluid properties such as the optical density of the fluid are measured.', 'By monitoring the fluid properties as the pressure changes, the phase envelope boundaries may be identified.', 'In one example, the sampling system \n42\n may collect and analyze a small sample with equipment with a small interior volume allows for precise control and rigorous observation when the equipment is appropriately tailored for measurement, as described by Application No. PCT/US2014/015467, which, as noted above, is incorporated by reference herein in its entirety for any purpose.', 'At elevated temperatures and pressures, the equipment may also be configured for effective operation over a wide temperature range and at high pressures.', 'Selecting a small size for the equipment may permit rugged operation because the heat transfer and pressure control dynamics of a smaller volume of fluid are easier to control than those of large volumes of liquids.', 'That is, a system with a small exterior volume may be selected for use in a modular oil field services device for use within a wellbore.', 'A small total interior volume can also allow cleaning and sample exchange to occur more quickly than in systems with larger volumes, larger surface areas, and larger amounts of dead spaces.', 'Cleaning and sample exchange are processes that may influence the reliability of the phase transition cell.', 'That is, the smaller volume uses less fluid for observation, but also can provide results that are more likely to be accurate.', 'The sampling system \n42\n may measure the saturation pressure of a representative reservoir fluid sample at the reservoir temperature.', 'In a surface measurement, the reservoir phase envelope may be obtained by measuring the saturation pressure (bubble point or dewpoint pressures) of the sample using a laboratory-based pressure-volume-temperature (PVT) view cell over a range of temperatures.', 'At each temperature, the pressure of a reservoir sample is lowered while the sample is agitated with a mixer.', 'This is done in a view cell until bubbles or condensate droplets are optically observed and is known as a Constant Composition Expansion (CCE).', 'The PVT view cell volume is on the order of tens to hundreds of milliliters, thus using a large volume of reservoir sample to be collected for analysis.', 'This sample can be consumed or altered during PVT measurements.', 'A similar volume may be used for each additional measurement, such as density and viscosity, in a surface laboratory.', 'By contrast, the sampling system \n42\n may use a small volume of fluid used by microfluidic sensors (e.g., approximately 1 milliliter total for the measurements described herein) to make measurements.', 'In one or more embodiments, an optical phase transition cell may be included in the sampling system \n42\n.', 'It may be positioned in the fluid path line to subject the fluid to optical interrogation to determine the phase change properties and its optical properties.', 'U.S. patent application Ser.', 'No. 13/403,989, filed on Feb. 24, 2012 and United States Patent Application Publication Number 2010/0265492, published on Oct. 21, 2010 describe embodiments of a phase transition cell and its operation.', 'Both of these applications are incorporated by reference herein for any purpose in their entirety.', 'The pressure-volume-temperature phase transition cell may contain as little as 300 μl of fluid.', 'The phase transition cell detects the dew point or bubble point phase change to identify the saturation pressure while simultaneously nucleating the minority phase.', 'The phase transition cell may provide thermal nucleation which facilitates an accurate saturation pressure measurement with a rapid depressurization rate of from about 10 to about 100 psi/second.', 'As such, a saturation pressure measurement (including depressurization from reservoir pressure to saturation pressure) may take place in less than 10 minutes, as compared to the saturation pressure measurement via standard techniques in a surface laboratory, wherein the same measurement may take several hours.', 'Some embodiments may include a view cell to measure the reservoir asphaltene onset pressure (AOP), wax appearance temperature (WAT), as well as the saturation pressure (PSAT) phase envelopes.', 'Hence, the phase transition cell becomes a configuration to facilitate the measurement of many types of phase transitions.', "Moreover, in one or more embodiments, a densitometer, a viscometer, a pressure gauge and/or a method to control the sample pressure with a phase transition cell may be integrated so that most sensors and control elements operate simultaneously to fully characterize a live fluid's saturation pressure.", 'In some embodiments, each individual sensor itself has an internal volume of no more than 20 microliters (approximately 2 drops of liquid) and by connecting each in series, the total volume (500 microliters) to charge the system with live oil before each measurement may be minimized.', 'In some embodiments, the fluid has a total fluid volume of about 1.0 mL or less.', 'In other embodiments, the fluid has a total fluid volume of about 0.5 mL or less.', 'A micropiston or piston (e.g., a sapphire piston) may control the pressure within the PVT-testing component of the sampling system \n42\n.', 'In such an embodiment, the control of the pressure in the system may be adjusted by moving the piston to change the volume inside the piston housing and, thus, the sample volume.', 'The PVT-testing component of the sampling system \n42\n may have a relatively small dead volume (e.g., less than 0.5 mL) to facilitate pressure control and sample exchange.', 'In some embodiments, the depressurization or pressurization rate of the fluid may be less than 100 psi/second.', 'In some embodiments, the fluid is circulated through the system at a volumetric rate of no more than 1 ml/sec.', 'Teflon, alumina, ceramic, zirconia or metal with seals may be selected for some components for various embodiments of the pressure control device.', 'Smooth hard surfaces may be used to minimize friction of the moving piston and both energized and dynamic seals may be used.', 'Using the PVT-testing component of the sampling system \n42\n, temperature and pressure measurements for phase envelopes of the formation fluids \n50\n may be obtained.', 'In general, the temperature of the fluids analyzed by the PVT-testing component of the sampling system \n42\n may be substantially ambient to the depth of the wellbore \n14\n.', 'Thus, in general, the deeper the downhole acquisition tool \n12\n, the higher the temperature.', 'The PVT-testing component of the sampling system \n42\n thus may be used to obtain temperature and pressure measurements of the phase envelopes of the formation fluids \n50\n at different temperatures by moving the downhole tool \n12\n to different depths and obtaining new phase envelope measurements at the different temperatures at those depths.', 'This may allow the downhole acquisition tool \n12\n to obtain a more complete set of temperature and pressure data points that describe the phase envelopes of the formation fluids \n50\n.', 'Additionally or alternatively, multi-temperature phase-envelope measurements of mixtures of formation fluids collected at different stations may be tested in-situ.', 'Some examples of mixing and testing formation fluids appear in U.S. patent application Ser.', 'No. 14/975,698, “Systems and Methods for In-Situ Measurements of Mixed Formation Fluids,” which is incorporated by reference in its entirety for any purpose.', 'When the sampling system \n42\n tests the formation fluid \n50\n in-situ to ascertain properties indicative of a phase envelope (e.g., AOP, PSAT, WAT, etc.), the temperature being tested may be generally close to the ambient temperature of the wellbore \n14\n at the current depth of testing.', 'An example of a single data point for a phase envelope boundary is shown by a plot \n160\n of \nFIG.', '4\n.', 'The plot \n160\n describes phase behavior of the formation fluid \n50\n at various pressures (ordinate \n162\n) and temperatures (abscissa \n164\n).', 'The plot \n160\n includes a single data point \n166\n that corresponds to a measured saturation pressure (PSAT) point obtained by the sampling system \n42\n at one particular temperature (and, thus, at one particular depth).', 'With just one data point \n166\n, the phase behavior of the formation fluid \n50\n may be accurately modeled for that particular temperature.', 'Yet there may be a very large number of potential PSAT phase envelopes that could pass through the data point \n166\n.', 'Indeed, there may be one true phase envelope \n168\n that would most accurately describe the phase behavior of the formation fluid \n50\n, but it may be very difficult to distinguish the true phase envelope \n168\n from other potential phase envelopes—some examples of which are shown by curves \n170\n, \n172\n, and \n174\n—with just the single data point \n166\n.', 'A plot \n180\n of \nFIG.', '5\n also describes phase behavior of the formation fluid \n50\n at various pressures (ordinate \n182\n) and temperatures (abscissa \n184\n).', 'The plot \n180\n includes a single data point \n186\n that corresponds to a measured asphaltene onset pressure (AOP) point obtained by the sampling system \n42\n at one particular temperature (and, thus, at one particular depth).', 'With just one data point \n186\n, the phase behavior of the formation fluid \n50\n may be accurately modeled for that particular temperature.', 'Y et there may also be a very large number of potential AOP phase envelopes that could pass through the data point \n186\n.', 'Indeed, there may be one true phase envelope \n188\n that would most accurately describe the phase behavior of the formation fluid \n50\n, but it may be very difficult to distinguish the true phase envelope \n188\n from other potential phase envelopes—one example of which are shown by curve \n190\n—with just the single data point \n186\n.', 'The potential deficiencies of obtaining just one phase-envelope measurement at one temperature may be remedied by performing phase-envelope testing in the sampling system \n42\n using multiple temperatures from a corresponding number of depths.', 'Indeed, as shown by a wellsite diagram \n200\n in \nFIG.', '6\n, the ambient temperature of the sampling system \n42\n may vary with the depth of the wellbore \n14\n.', 'Indeed, a first depth \n202\n may have a first ambient temperature T1, a second depth \n204\n may have a second ambient temperature T2, a third depth \n206\n may have a second ambient temperature T3, a fourth depth \n208\n may have a fourth ambient temperature T4, a fifth depth \n210\n may have a fifth ambient temperature T5, and a sixth depth \n212\n may have a sixth ambient temperature T6, and so forth.', 'In general, the deeper the location in the wellbore \n14\n, the higher the temperature.', 'In the example of \nFIG.', '6\n, the temperatures may have a relationship in which T6>T5>T4>', 'T3>T2>T1.', 'The variations in temperature by depth may allow the sampling system \n42\n to obtain multiple phase-envelope measurements—as well as measurements of other fluid properties, such as viscosity—at a variety of temperatures (e.g., T1, T2, T3, T4, T5, T6) by performing phase-envelope measurements on a sample of formation fluid \n50\n at different depths (e.g., \n202\n, \n204\n, \n206\n, \n208\n, \n210\n, \n212\n).', 'For example, as shown by a flowchart \n220\n of \nFIG.', '7\n, a downhole acquisition tool \n12\n or downhole acquisition tool \n100\n having the sampling system \n42\n may be positioned in the wellbore \n14\n.', 'After obtaining one or more samples at one or more depths, a first part of at least one of the samples of formation fluid \n50\n may tested to obtain one or more phase-envelope data points or other fluid property (e.g., viscosity) at a first depth (block \n222\n).', 'For example, the first depth may be the depth \n202\n and the temperature may be a temperature value T1.', 'The sampling system \n42\n may direct a first volume of formation fluid \n50\n from a first sample stored in the sampling system \n42\n to a PVT-testing component to measure a fluid property parameter such as saturation pressure (PSAT) (block \n224\n).', 'As a result, the sampling system \n42\n may identify the PSAT phase envelope boundary for the particular temperature of the depth (e.g., at temperature T1).', 'While remaining at the first depth and temperature T1, the sampling system \n42\n may continue to measure fluid properties of other fluid samples (block \n226\n).', 'For example, while remaining at the first depth and temperature T1, the sampling system \n42\n may test a first sample that was originally obtained at the first fluid zone \n51\nA, and may subsequently test a second sample that was originally obtained at the second fluid zone \n51\nB, before moving on to another depth.', 'It should be appreciated that, as mentioned above, testing different samples of formation fluids \n50\n individually does not preclude also testing some mixture of the different samples of formation fluids \n50\n in the manner described by U.S. patent application Ser.', 'No. 14/975,698, “Systems and Methods for In-Situ Measurements of Mixed Formation Fluids.”\n \nHaving obtained desired measurements for one or more samples of formation fluid \n50\n at the first depth/temperature (e.g., temperature T1 at depth \n202\n), the sampling system \n42\n may move to another depth, where the sampling system \n42\n may be stationed for some period of time (e.g., \n204\n) (block \n228\n).', 'Moving to the next depth may have the effect of adjusting the ambient temperature of the sampling system \n42\n (e.g., to temperature T2) over the period of time.', 'At this next depth and temperature (e.g., temperature T2 at depth \n204\n), another part of the first sample of formation fluid \n50\n may tested to obtain one or more phase-envelope data points or other fluid property (e.g., viscosity) at the next depth (block \n230\n).', 'Until the sampling system \n42\n is finished collecting measurements of fluid properties (decision block \n232\n), the sampling system \n42\n may continue to collect such fluid property measurements of the different samples or mixtures of samples at different depths and temperatures (e.g., temperature T3 at depth \n206\n, temperature T4 at depth \n208\n, temperature T5 at depth \n210\n, temperature T6 at depth \n212\n, and so forth).', 'Having obtained data points at many different depths and, accordingly, temperatures, the data points may be used to model the phase envelopes of the formation fluids \n50\n (decision block \n234\n).', 'For example, a phase diagram may be generated or the formation fluids \n50\n may be more accurately modeled in one or more equations of state (EOS) of the formation fluids \n50\n and/or the reservoir as a whole.', 'A plot \n240\n of \nFIG.', '8\n represents one example of a phase diagram of a sample of formation fluid \n50\n that may be more accurately modeled by obtaining multiple temperature/pressure data points by obtaining the measurements at multiple depths.', 'The plot \n240\n describes phase behavior of one sample of formation fluid \n50\n at various pressures (ordinate \n242\n) and temperatures (abscissa \n244\n), as measured in-situ by the sampling system \n42\n.', 'The plot \n240\n may more accurately identify a likely asphaltene onset pressure (AOP) phase envelope \n246\n and a saturation pressure (PSAT) phase envelope \n248\n.', 'This is because the plot \n240\n includes multiple data points \n250\n, \n252\n, \n254\n, \n256\n, and \n258\n that correspond to a measured AOP value obtained by the sampling system \n42\n at particular respective depths/temperatures (e.g., T2, T3, T4, T5, and T6).', 'The plot \n240\n also includes multiple data points \n260\n, \n262\n, \n264\n, \n266\n, \n268\n, and \n270\n that correspond to a measured PSAT value obtained by the sampling system \n42\n at particular respective depths/temperatures (e.g., T1, T2, T3, T4, T5, and T6).', 'The AOP phase envelope \n246\n and the PSAT phase envelope \n248\n may be estimated by fitting a curve through the multiple measured data points.', 'As mentioned above, the systems and methods of this disclosure are not limited to obtaining phase envelope measurements at multiple depths/temperatures.', 'Indeed, other fluid properties that vary with temperature may be more accurately identified by measuring them at multiple depths/temperatures.', 'For instance, a plot \n280\n of \nFIG.', '9\n compares a measurement of fluid viscosity (ordinate \n282\n) in relation to a period of time (abscissa \n284\n) during which the sampling system \n42\n is moved deeper into the wellbore and, thus, into higher ambient temperatures.', 'In the particular example of \nFIG.', '9\n, the fluid being measured is J13 hydraulic oil (priming liquid), but \nFIG.', '9\n is intended to show that measurements of viscosity of an oleic fluid (e.g., formation fluid \n50\n) may be obtained at multiple depths/temperatures downhole.', 'Here, a first curve \n286\n represents viscosity of a first sample of the hydraulic oil as measured in a first viscosity-measuring component of the sampling system \n42\n and a second curve \n288\n represents viscosity of a second sample of the hydraulic oil as measured in a second viscosity-measuring component of the sampling system \n42\n.', 'The viscosity may be seen to drop according to a defined function in relation to temperature, since over time, the sampling system \n42\n is moving deeper into the wellbore \n14\n and, accordingly, into higher temperatures.', 'Thus, measurements of the viscosity of samples of the formation fluids \n50\n, likewise, may be obtained at multiple depths and temperatures.', 'This may allow the sampling system \n42\n to obtain data points relating viscosity of the formation fluid \n50\n over a range of temperatures.', 'This may further allow the formation fluids \n50\n to be more accurately modeled in one or more equations of state (EOS) of the formation fluids \n50\n and/or the reservoir as a whole.', 'Furthermore, it should be appreciated that the systems and methods of this disclosure may also be used with other temperature-dependent properties of the formation fluid \n50\n, which may also include density, compressibility, opacity, and so forth.', 'The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms.', 'It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.'] | ['1.', 'A method comprising:\nobtaining a sample of a first formation fluid using a downhole acquisition tool positioned in a wellbore in a geological formation;\ntesting the sample of the first formation fluid for an amount of contamination present in the sample of the of the first formation fluid using the downhole acquisition tool;\ndetermining that the amount of the contamination present in the sample of the first formation fluid is below a threshold level using the downhole acquisition tool;\nstationing the downhole acquisition tool at a first depth in the wellbore in response to determining that the amount of the contamination present in the sample of the first formation fluid being below the threshold level, wherein the first depth has an ambient first temperature;\ntesting a first part of the sample of the first formation fluid using a pressure-volume-temperature tester in the downhole acquisition tool while the downhole acquisition tool is stationed at the first depth to obtain a first measurement point, such that the first part of the sample of the first formation fluid is tested at approximately the first temperature, wherein a densitometer, a viscometer, and a pressure gauge are integrated with the pressure-volume-temperature tester and operate simultaneously with each other and control equipment to characterize the first part of the sample of the first formation fluid, and to control a piston to control pressure in the pressure-volume-temperature tester by controlling the piston, wherein as the piston in the pressure-volume-temperature tester is moved to vary the pressure the densitometer, the viscometer, and the pressure gauge operate simultaneously with each other to determine at least one of saturation pressure at the first temperature, asphaltene onset pressure at the first temperature, a wax appearance temperature at the first temperature of the first part of the sample of the first formation fluid;\ndirecting a second part of the sample of the first formation fluid of fluid to the pressure-volume-temperature tester and moving the downhole acquisition tool to a second depth;\nstationing the downhole acquisition tool at the second depth in the wellbore, wherein the second depth has an ambient second temperature different from the first temperature;\ntesting the second part of the sample of the first formation fluid using the pressure-volume-temperature tester in the downhole acquisition tool while the downhole acquisition tool is stationed at the second depth to obtain a second measurement point, such that the second part of the sample of the first formation fluid is tested at approximately the second temperature wherein a densitometer, a viscometer, and a pressure gauge are integrated with the pressure-volume-temperature tester and operate simultaneously as a piston in the pressure-volume-temperature tester is moved to vary the pressure to determine at least one of saturation pressure at the second temperature, asphaltene onset pressure at the second temperature, a wax appearance temperature at the second temperature of the second part of the sample of the first formation fluid; and\ndetermining a temperature and pressure-dependent relationship of a first fluid property of the first formation fluid based on the first measurement point and the second measurement point.', '2.', 'The method of claim 1, comprises a further comprising measuring the viscosity of the first part of the sample of reservoir fluid at the first temperature and of the second part of the sample of reservoir fluid at the second temperature.', '3.', 'The method of claim 1, wherein determining the temperature and pressure-dependent relationship of the first fluid property of the first formation fluid comprises determining a model of a phase envelope of the first formation fluid.', '4.', 'The method of claim 1, comprising:\nobtaining a sample of second formation fluid using the downhole acquisition tool positioned in the wellbore in the geological formation, wherein the sample of the first formation fluid is obtained from a first fluid zone in the wellbore and the second formation fluid is obtained from a second fluid zone in the wellbore;\ntesting the first fluid property of a first part of the sample of the second formation fluid using the downhole acquisition tool while the downhole acquisition tool is stationed at the first depth to obtain a third measurement point, such that the first part of the sample of the second formation fluid is tested at approximately the first temperature;\ntesting the first fluid property of a second part of the sample of the second formation fluid using the downhole acquisition tool while the downhole acquisition tool is stationed at the second depth to obtain a fourth measurement point, such that the second part of the sample of the second formation fluid is tested at approximately the second temperature; and\ndetermining a temperature-dependent relationship of the first fluid property of the second formation fluid based on the third measurement point and the fourth measurement point.', '5.', 'The method of claim 4, wherein the first fluid zone is hydraulically isolated from the second fluid zone.', '6.', 'The method of claim 1, comprising repeating stationing the downhole acquisition tool at subsequent depths and testing the first fluid property of subsequent parts of the sample of the first formation fluid at the subsequent depths until a total number of measurement points is obtained, wherein the number of measurement points is at least three.\n\n\n\n\n\n\n7.', 'The method of claim 1, comprising:\ntesting a second fluid property of the first part of the sample of the first formation fluid using the downhole acquisition tool while the downhole acquisition tool is stationed at the first depth to obtain a third measurement point, such that the first part of the sample of the first formation fluid is tested at approximately the first temperature;\ntesting the second fluid property of the second part of the sample of the first formation fluid using the downhole acquisition tool while the downhole acquisition tool is stationed at the second depth to obtain a fourth measurement point, such that the second part of the sample of the first formation fluid is tested at approximately the second temperature; and\ndetermining a temperature-dependent relationship of the second fluid property of the first formation fluid based on the third measurement point and the fourth measurement point.\n\n\n\n\n\n\n8.', 'The method of claim 7, wherein the first fluid property comprises a saturation pressure, the second fluid property comprises an asphaltene onset pressure, the temperature-dependent relationship of the first fluid property of the first formation fluid comprises a phase envelope of the saturation pressure, and the temperature-dependent relationship of the second fluid property of the first formation fluid comprises a phase envelope of the asphaltene onset pressure.'] | ['FIG.', '1 is a schematic diagram of a well site system that may be used to identify multiple points of a phase envelope of a formation fluid, in accordance with an embodiment;; FIG.', '2 is a schematic diagram of another example of a well site system that may be used to identify multiple points of a phase envelope of a formation fluid, in accordance with an embodiment;; FIG.', '3 is a plot of a phase diagram of formation fluid, in accordance with an embodiment;; FIG. 4 is a plot showing potential phase envelopes in a phase diagram for saturation pressure (PSAT) when only a single saturation pressure point has been identified;; FIG.', '5 is a plot showing potential phase envelopes in a phase diagram for asphaltene onset pressure (AOP) when only a single pressure point has been identified;; FIG.', '6 is a schematic diagram of variations in temperature and pressure throughout the depth of the wellbore, in accordance with an embodiment;; FIG. 7 is a flowchart of a method for identifying multiple points of a phase envelope (e.g., saturation pressure or asphaltene onset pressure) of a formation fluid, in accordance with an embodiment;; FIG. 8 is a simulated phase diagram of formation fluid having phase envelope models constrained to the data points obtained using the method of FIG.', '7, in accordance with an embodiment; and; FIG. 9 is a plot showing that other properties, such as viscosity, may also be identified at various temperatures in accordance with the systems and methods of this disclosure.; FIGS. 1 and 2 depict examples of wellsite systems that may employ such fluid analysis systems and methods.', 'In FIG.', '1, a rig 10 suspends a downhole acquisition tool 12 into a wellbore 14 via a drill string 16.', 'A drill bit 18 drills into a geological formation 20 to form the wellbore 14.', 'The drill string 16 is rotated by a rotary table 24, which engages a kelly 26 at the upper end of the drill string 16.', 'The drill string 16 is suspended from a hook 28, attached to a traveling block, through the kelly 26 and a rotary swivel 30 that permits rotation of the drill string 16 relative to the hook 28.', 'The rig 10 is depicted as a land-based platform and derrick assembly used to form the wellbore 14 by rotary drilling.', 'However, in other embodiments, the rig 10 may be an offshore platform.', '; FIG.', '2 depicts an example of a wireline downhole tool 100 that may employ the systems and methods of this disclosure.', 'The downhole tool 100 is suspended in the wellbore 14 from the lower end of a multi-conductor cable 104 that is spooled on a winch at the surface 74.', 'Like the downhole acquisition tool 12, the wireline downhole tool 100 may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or any other suitable conveyance.', 'The cable 104 is communicatively coupled to an electronics and processing system 106.', 'The downhole tool 100 includes an elongated body 108 that houses modules 110, 112, 114, 122, and 124, that provide various functionalities including fluid sampling, sample bottle filling, fluid testing, operational control, and communication, among others.', 'For example, the modules 110 and 112 may provide additional functionality such as fluid analysis, resistivity measurements, operational control, communications, coring, and/or imaging, among others.'] |
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US11105942 | Generative adversarial network seismic data processor | Mar 26, 2019 | Stephen Alwon | SCHLUMBERGER TECHNOLOGY CORPORATION | Gatys et al., “A Neural Algorithm of Artistic Style,” arXiv:1508.06576 (2015) (16 pages).; Goodfellow et al. (2014), “Generative Adversarial Nets,” arXiv:1406.2661 (9 pages).; He et al. (2015), “Deep Residual Learning for Image Recognition,” arXiv:1512.03385 (12 pages).; Gulrajani et al. (2017), “Improved Training of Wasserstein GANs”, arXiv:1704.00028. (20 pages).; Isola et al., “Image-to-Image Translation with Conditional Adversarial Networks,” arXiv:1611.07004 (2017) (17 pages).; Ledig et al. (2017) “Photo-Realistic Single Image Super-Resolution Using a Generative Adversarial Network,” arXiv:1609.04802 (19 pages).; Arjovsky et al. (2017), “Wasserstein GAN,” arXiv:1701.07875 (2 pages).; Radford et al. (2015), “Unsupervised Representation Learning with Deep Convolutional Generative Adversarial Networks,” arXiv:1511.06434v2. (16 pages).; Ronneberger et al., “U-Net: Convolutional Networks for Biomedical Image Segmentation,” arXiv:1505.04597 (2015) (8 pages).; Shi et al. (2016), “Real-Time Single Image and Video Super-Resolution Using an Efficient Sub-Pixel Convolutional Neural Network,” arXiv:1609.05158. (10 pages).; Yang et al. (2018), “Application of optimal transport and the quadratic Wasserstein metric to full-waveform inversion,” Geophysics, 83(1), R43-R62.; Zhu et al., “Unpaired Image-to-Image Translation using Cycle-Consistent Adversarial Networks”, arXiv:1703.10593v6 [cs.CV], https://arxiv.org/abs/1703.10593 (submitted on Mar. 30, 2017 (v1) (18 pages). | 20180164458; June 14, 2018; Sudow; 20190295530; September 26, 2019; Hosseini-Asl | Foreign Citations not found. | ['A method can include generating seismic data; training a generator network utilizing at least a portion of the generated seismic data and a discriminator network; and outputting a trained generator network.'] | ['Description\n\n\n\n\n\n\nRELATED APPLICATION', 'This application claims priority to and the benefit of a U.S. Provisional Application having Ser.', 'No. 62/648,928, filed 27 Mar. 2018, which is incorporated by reference herein.\n \nBACKGROUND\n \nReflection seismology finds use in geophysics, for example, to estimate properties of subsurface formations.', 'As an example, reflection seismology may provide seismic data representing waves of elastic energy (e.g., as transmitted by P-waves and S-waves, in a frequency range of approximately 1 Hz to approximately 100 Hz).', 'Seismic data may be processed and interpreted, for example, to understand better composition, fluid content, extent and geometry of subsurface rocks.', 'Various techniques described herein pertain to processing of data such as, for example, seismic data.', 'SUMMARY\n \nA method can include generating seismic data; training a generator network utilizing at least a portion of the generated seismic data and a discriminator network; and outputting a trained generator network.', 'A system can include a processor; memory operatively coupled to the processor; and processor-executable instructions stored in the memory to instruct the system to: generate seismic data; train a generator network utilizing at least a portion of the generated seismic data and a discriminator network; and output a trained generator network.', 'A system can include a processor; memory operatively coupled to the processor; and processor-executable instructions stored in the memory to instruct the system to: access a trained generator network, as trained via generated seismic data and a discriminator network; receive seismic data of a survey of a geologic environment; and process at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'A method can include accessing a trained generator network, as trained via generated seismic data and a discriminator network; receiving seismic data of a survey of a geologic environment; and processing at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'One or more computer-readable storage media can include processor-executable instructions to instruct a computing system to: access a trained generator network, as trained via generated seismic data and a discriminator network; receive seismic data of a survey of a geologic environment; and process at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'Various other apparatuses, systems, methods, etc., are also disclosed.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFeatures and advantages of the described implementations can be more readily understood by reference to the following description taken in conjunction with the accompanying drawings.\n \nFIG.', '1\n illustrates an example of a geologic environment and an example of a technique;\n \nFIG.', '2\n illustrates an example of a geologic environment and examples of equipment;\n \nFIG.', '3\n illustrates an example of a geologic environment, examples of equipment and an example of a method;\n \nFIG.', '4\n illustrates an example of a geologic environment and examples of equipment;\n \nFIG.', '5\n illustrates an example of a geologic environment, an example of a method, examples of equipment and examples of data;\n \nFIG.', '6\n illustrates examples of plots;\n \nFIG.', '7\n illustrates examples of network architectures and processes;\n \nFIG.', '8\n illustrates examples of network architectures and processes;\n \nFIG.', '9\n illustrates examples of plots;\n \nFIG.', '10\n illustrates an example of an architecture of a framework;\n \nFIG.', '11\n illustrates examples of plots;\n \nFIG.', '12\n illustrates examples of graphics of a cycle generative adversarial network (cycle-GAN);\n \nFIG.', '13\n illustrates examples of plots;\n \nFIG.', '14\n illustrates an example of a computational framework;\n \nFIG.', '15\n illustrates an example of a method; and\n \nFIG.', '16\n illustrates example components of a system and a networked system.', 'DETAILED DESCRIPTION', 'The following description includes the best mode presently contemplated for practicing the described implementations.', 'This description is not to be taken in a limiting sense, but rather is made merely for the purpose of describing the general principles of the implementations.', 'The scope of the described implementations should be ascertained with reference to the issued claims.', 'As mentioned, reflection seismology finds use in geophysics, for example, to estimate properties of subsurface formations.', 'As an example, reflection seismology may provide seismic data representing waves of elastic energy (e.g., as transmitted by P-waves and S-waves, in a frequency range of approximately 1 Hz to approximately 100 Hz).', 'Seismic data may be processed and interpreted, for example, to understand better composition, fluid content, extent and geometry of subsurface rocks.', 'As an example, a seismic imaging system can be utilized to perform seismic surveys.', 'As an example, consider a land-based survey of a subsurface region where sensors can be positioned according to a survey footprint that may cover an area of square kilometers where one or more seismic energy sources are fired to emit energy that can travel through the subsurface region such that at least a portion of the emitted energy can be received at one or more of the sensors.', 'As another example, consider a marine survey that may involve towing one or more streamers behind a vessel where a streamer includes sensors where one or more seismic energy sources are fired to emit energy that can travel through water and a subsurface region such that at least a portion of the emitted energy can be received at one or more of the sensors.', 'In a survey, noise may be sensed that can be associated with one or more phenomena.', 'For example, ground roll can be a type of noise that can be coherent noise generated by a surface wave (e.g., a low-velocity, low-frequency, high-amplitude Rayleigh wave).', 'Ground roll may obscure signal and degrade overall data quality; noting that selection of source and geophone arrays, filters and stacking parameters may help to reduce the effect of such noise.', 'In a marine environment, water-bottom roll may result in a type of noise.', 'Water-bottom roll can include a pseudo-Rayleigh wave traveling along an interface of water and a seafloor (e.g., seabed).', 'Water-bottom roll may present in a survey that utilizes one or more seabed sensors.', 'Another type of noise is referred to as ghosting.', 'A ghost can be a short-path multiple, or a spurious reflection that occurs when seismic energy initially reverberates upward from a shallow subsurface and then is reflected downward, such as at the base of weathering or between sources and receivers and a water/air interface.', 'Yet another type of noise can be associated with equipment such as sensor equipment.', 'Such noise may be due to environmental conditions (e.g., temperature, wind, waves, radiation, etc.).', 'As to streamers, noise may occur due to contact with one or more objects.', 'Flotsam and jetsam are terms that describe two types of marine debris.', 'Flotsam is defined as debris in the water that was not deliberately thrown overboard, often as a result from a shipwreck or accident.', "Jetsam describes debris that was deliberately thrown overboard by a crew of a ship in distress, most often to lighten the ship's load.", 'The word flotsam derives from the French word floter, to float.', 'Jetsam is a shortened word for jettison.', 'Other types of debris can be of natural origin (e.g., wood from trees, etc.)', 'and/or dead/decaying marine life (e.g., fish, plants, etc.).', 'As to streamers, noise may occur due to vessel factors such as vessel speed, variation in speed, acceleration, waves impacting vessel performance, navigating around icebergs, making turns, etc.', 'For example, where a vessel is to trace a path for a survey, the path can include turns that cause streamers to change in shape, which may cause bending, etc., changes in angles with respect to source originated seismic energy, etc.', 'As vessel operations involves energy expenditure (e.g., liquid fuel, solar power, etc.), a survey may continue during turns of a survey path.', 'As an example, a streamer cable can be at least partially filled with a material (a fluid, a gel, etc.).', 'An outer tube or jacket may be of the order of a few millimeters thick as to a wall thickness.', 'An outer tube may be constructed of a material or materials that provide integrity while allowing for responsiveness as to sensing.', 'Issues that may arise at sea include shark bites and other physical hazards that may be encountered during towing, storage and deployment.', 'Streamer cables may be spooled onto drums for storage on a vessel, which subjects the streamer cables to various contact and bending forces, etc. (consider winding and unwinding operations).', 'A streamer cable may be serviceable in that repairs may be made.', 'Such repairs may be at sea or at a land-based facility.', 'In general, operations aim to avoid or otherwise diminish down time due to expense and costs (vessel, crew, production schedules, etc.).', 'In various geographies, weather may vary and particular conditions, seasons, etc. may cause some amount of uncertainty in scheduling.', 'In some geographies, regular “windows” exist where conditions can be more favorable for performing surveys.', 'As may be appreciated, various factors can result in noise in seismic survey data.', 'As an example, noise may be subject to attenuation and/or subject to study.', 'For example, attenuation can allow for enhanced signal processing, which can include one or more of transmitting, compressing, reconstructing, interpreting, etc.', 'As to an analysis (e.g., study) of noise, it may provide information as to one or more causes, which may be addressable to reduce noise during and/or after a survey and, for example, before a subsequent survey.', 'For example, consider noise associated with damage to a streamer or a component of a streamer (e.g., guides, fins, etc.).', 'Such damage may present as a particular type of noise that if identified via analysis may allow for quality control and/or remedial measures (e.g., mitigation, data cleansing, data filtering, repair of equipment, etc.).', 'As an example, a machine can acquire seismic data and can process the seismic data via circuitry of the machine, which can include one or more processors and memory accessible to at least one processor.', 'Such a machine can include one or more interfaces that can be operatively coupled to one or more pieces of equipment, whether by wire or wirelessly (e.g., via wireless communication circuitry).', 'As an example, such a machine may be a seismic imager that can generate an image based at least in part on seismic data.', 'Such an image can be a model according to one or more equations and may be an image of structure of a subterranean environment and/or an image of noise, which may be due to one or more phenomena.', 'As an example, a seismic image can be in one or more types of domains.', 'For example, consider a spatial and temporal domain where one dimension is spatial and another dimension is temporal.', 'Such a domain may be utilized for seismic traces that are amplitude values with respect to time as acquired by a receiver of seismic survey equipment.', 'As an example, time may be transformed to depth or other spatial dimension.', 'In such an example, a seismic image can be in a spatial domain with two spatial dimensions.', 'An image can be a multidimensional construct that is at least in part seismic data-based.', 'For example, a digital camera of a smartphone can process data acquired by a CCD array utilizing a model such that the model and associated values may be rendered to a display of the smartphone.', 'In a CCD image sensor, pixels are represented by p-doped metal-oxide-semiconductors (MOS) capacitors.', 'These capacitors are biased above the threshold for inversion when image acquisition begins, allowing the conversion of incoming photons into electron charges at the semiconductor-oxide interface; the CCD image sensor is then used to read out these charges.', 'Instructions executable by a processor of a smartphone can receive the charges as sensor data.', 'Where a CCD is configured to be sensitive to color, it may utilize a Bayer mask over the CCD array where, for example, each square of four pixels has one filtered red, one blue, and two green such that luminance information is collected at every pixel, but the color resolution is lower than the luminance resolution.', 'A color model that can include features of an RGB colorspace model can be utilized by the smartphone to generate data that can be then rendered to a display.', 'Ultimately, the rendering to the display is a model with particular values that depend on the acquired CCD image sensor data.', 'In seismic imaging, rather than photons, seismic energy is sensed.', 'Further, the amount of data sensed tends to be orders of magnitude greater than that of a digital camera of a smartphone.', 'Yet further, a region “sensed” (e.g., surveyed) is generally not visible to the eye.', 'Various types of models can be utilized for seismic imaging such that, for example, rendering can occur to a display of information that is based at least in part on sensed data.', 'As an example, a system can include circuitry that can implement one or more generative adversarial networks, or GANs, which are a class of machine learning techniques that involve two networks trained simultaneously to generate a desired outcome.', 'As an example, such a system can perform one or more seismic processing tasks such as, for example, noise attenuation and trace interpolation.', 'As an example, a GAN can be trained such that a generator can generate output, which may be, for example, seismic data (e.g., noise attenuated seismic data, interpolated seismic data, etc.).', 'As an example, generative adversarial networks (GANs), as a class of networks, can be implemented through use of neural networks working in parallel to generate data that may pass for “real” data.', 'As an example, a GAN can be utilized in a so-called image-to-image process that receives and image and output an image.', 'As an example, a GAN can be utilized in a seismic data-to-seismic data process that receives seismic data and that output seismic data.', 'As an example, one or more GANs may be trained via unsupervised learning.', 'As an example, a computing system can construct GANs that perform one or more tasks in seismic data processing and imaging.', 'As mentioned, such tasks can include, for example, noise attenuation and interpolation.', 'These two examples tend to involve analyzing data in different domains, which demands expert knowledge for proper parameterization.', "By utilizing properly trained GANs, a computing system can perform one or both of these processes in a manner that is more automated and less reliant on an end user's parameters.", 'Various other types of processes may be performed using one or more GANs, for example, consider generating seismic data in a particular “style”, which may be a noise attenuated “style”.', 'FIGS.', '1, 2, 3, 4 and 5\n present various examples of equipment and techniques associated with seismic data.', 'One or more of the examples may be utilized in conjunction with one or more GANs.', 'As an example, a computing system may utilize one or more GANs to handle noise, for example, for purposes of attenuation and/or for purposes of diagnosis and one or more actions responsive to one or more diagnoses.\n \nFIG.', '1\n shows an example of a geologic environment \n150\n (e.g., an environment that includes a sedimentary basin, a reservoir \n151\n, one or more fractures \n153\n, etc.)', 'and an example of an acquisition technique \n170\n to acquire seismic data.', 'As an example, a system may process data acquired by the technique \n170\n, for example, to allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment \n150\n.', 'In turn, further information about the geologic environment \n150\n may become available as feedback (e.g., optionally as input to the system).', 'As an example, a system may include features of a commercially available simulation framework such as the PETREL seismic to simulation software framework (Schlumberger Limited, Houston, Tex.).', 'The PETREL framework provides components that allow for optimization of exploration and development operations.', 'The PETREL framework includes seismic to simulation software components that can output information for use in increasing reservoir performance, for example, by improving asset team productivity.', 'Through use of such a framework, various professionals (e.g., geophysicists, geologists, and reservoir engineers) can develop collaborative workflows and integrate operations to streamline processes.', 'Such a framework may be considered an application and may be considered a data-driven application (e.g., where data is input for purposes of simulating a geologic environment).', 'As an example, a system may include add-ons or plug-ins that operate according to specifications of a framework environment.', 'For example, a commercially available framework environment marketed as the OCEAN framework environment (Schlumberger Limited, Houston, Tex.) allows for integration of add-ons (or plug-ins) into a PETREL framework workflow.', 'The OCEAN framework environment leverages .NET tools (Microsoft Corporation, Redmond, Wash.) and offers stable, user-friendly interfaces for efficient development.', 'In an example embodiment, various components may be implemented as add-ons (or plug-ins) that conform to and operate according to specifications of a framework environment (e.g., according to application programming interface (API) specifications, etc.).', 'In the example of \nFIG.', '1\n, the geologic environment \n150\n may include layers (e.g., stratification) that include a reservoir \n151\n and that may be intersected by a fault \n153\n.', 'As an example, a geologic environment may be or include an offshore geologic environment, a seabed geologic environment, an ocean bed geologic environment, etc.', 'As an example, the geologic environment \n150\n may be outfitted with one or more of a variety of sensors, detectors, actuators, etc.', 'For example, equipment \n152\n may include communication circuitry to receive and to transmit information with respect to one or more networks \n155\n.', 'Such information may include information associated with downhole equipment \n154\n, which may be equipment to acquire information, to assist with resource recovery, etc.', 'Other equipment \n156\n may be located remote from a well site and include sensing, detecting, emitting or other circuitry.', 'Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.', 'For example, \nFIG.', '1\n shows a satellite in communication with the network \n155\n that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).', 'FIG.', '1\n also shows the geologic environment \n150\n as optionally including equipment \n157\n and \n158\n associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures \n159\n.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop the reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment \n157\n and/or \n158\n may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.', 'As an example, a system may be used to perform one or more workflows.', 'A workflow may be a process that includes a number of worksteps.', 'A workstep may operate on data, for example, to create new data, to update existing data, etc.', 'As an example, a system may operate on one or more inputs and create one or more results, for example, based on one or more algorithms.', 'As an example, a system may include a workflow editor for creation, editing, executing, etc. of a workflow.', 'In such an example, the workflow editor may provide for selection of one or more pre-defined worksteps, one or more customized worksteps, etc.', 'As an example, a workflow may be a workflow implementable in the PETREL software, for example, that operates on seismic data, seismic attribute(s), etc.', 'As an example, a workflow may be a process implementable in the OCEAN framework.', 'As an example, a workflow may include one or more worksteps that access a module such as a plug-in (e.g., external executable code, etc.).', 'In \nFIG.', '1\n, the technique \n170\n may be implemented with respect to a geologic environment \n171\n.', 'As shown, an energy source (e.g., a transmitter) \n172\n may emit energy where the energy travels as waves that interact with the geologic environment \n171\n.', 'As an example, the geologic environment \n171\n may include a bore \n173\n where one or more sensors (e.g., receivers) \n174\n may be positioned in the bore \n173\n.', 'As an example, energy emitted by the energy source \n172\n may interact with a layer (e.g., a structure, an interface, etc.) \n175\n in the geologic environment \n171\n such that a portion of the energy is reflected, which may then be sensed by one or more of the sensors \n174\n.', 'Such energy may be reflected as an upgoing primary wave (e.g., or “primary”).', 'As an example, a portion of emitted energy may be reflected by more than one structure in the geologic environment and referred to as a multiple reflected wave (e.g., or “multiple”).', 'For example, the geologic environment \n171\n is shown as including a layer \n177\n that resides below a surface layer \n179\n.', 'Given such an environment and arrangement of the source \n172\n and the one or more sensors \n174\n, energy may be sensed as being associated with particular types of waves.', 'As shown in \nFIG.', '1\n, acquired data \n180\n can include data associated with downgoing direct arrival waves, reflected upgoing primary waves, downgoing multiple reflected waves and reflected upgoing multiple reflected waves.', 'The acquired data \n180\n is also shown along a time axis and a depth axis.', 'As indicated, in a manner dependent at least in part on characteristics of media in the geologic environment \n171\n, waves travel at velocities over distances such that relationships may exist between time and space.', 'Thus, time information, as associated with sensed energy, may allow for understanding spatial relations of layers, interfaces, structures, etc. in a geologic environment.\n \nFIG.', '1\n also shows various types of waves as including P, SV an SH waves.', 'As an example, a P-wave may be an elastic body wave or sound wave in which particles oscillate in the direction the wave propagates.', 'As an example, P-waves incident on an interface (e.g., at other than normal incidence, etc.) may produce reflected and transmitted S-waves (e.g., “converted” waves).', 'As an example, an S-wave or shear wave may be an elastic body wave, for example, in which particles oscillate perpendicular to the direction in which the wave propagates.', 'S-waves may be generated by a seismic energy sources (e.g., other than an air gun).', 'As an example, S-waves may be converted to P-waves.', 'S-waves tend to travel more slowly than P-waves and do not travel through fluids that do not support shear.', 'In general, recording of S-waves involves use of one or more receivers operatively coupled to earth (e.g., capable of receiving shear forces with respect to time).', "As an example, interpretation of S-waves may allow for determination of rock properties such as fracture density and orientation, Poisson's ratio and rock type, for example, by crossplotting P-wave and S-wave velocities, and/or by other techniques.", 'As an example of parameters that can characterize anisotropy of media (e.g., seismic anisotropy), consider the Thomsen parameters ε, δ and γ.', 'The Thomsen parameter δ can describe offset effects (e.g., short offset).', 'As to the Thomsen parameter ε, it can describe offset effects (e.g., a long offset) and can relate to a difference between vertical and horizontal compressional waves (e.g., P or P-wave or quasi compressional wave qP or qP-wave).', 'As to the Thomsen parameter γ, it can describe a shear wave effect.', 'For example, consider an effect as to a horizontal shear wave with horizontal polarization to a vertical shear wave.', 'As an example, seismic data may be acquired for a region in the form of traces.', 'In the example of \nFIG.', '1\n, the technique \n170\n may include the source \n172\n for emitting energy where portions of such energy (e.g., directly and/or reflected) may be received via the one or more sensors \n174\n.', 'As an example, energy received may be discretized by an analog-to-digital converter that operates at a sampling rate.', 'For example, acquisition equipment may convert energy signals sensed by a sensor to digital samples at a rate of one sample per approximately 4 ms.', 'Given a speed of sound in a medium or media, a sample rate may be converted to an approximate distance.', 'For example, the speed of sound in rock may be of the order of around 5 km per second.', 'Thus, a sample time spacing of approximately 4 ms would correspond to a sample “depth” spacing of about 10 meters (e.g., assuming a path length from source to boundary and boundary to sensor).', 'As an example, a trace may be about 4 seconds in duration; thus, for a sampling rate of one sample at about 4 ms intervals, such a trace would include about 1000 samples where latter acquired samples correspond to deeper reflection boundaries.', 'If the 4 second trace duration of the foregoing example is divided by two (e.g., to account for reflection), for a vertically aligned source and sensor, the deepest boundary depth may be estimated to be about 10 km (e.g., assuming a speed of sound of about 5 km per second).', 'As an example, a seismic trace can be a vector with amplitude values where each entry in the vector represents a sample, for example, as sampled according to a sampling rate of a receiver.', 'Such a vector can be amplitude with respect to time for a particular receiver, for a particular “shot” of a seismic source, etc.\n \nFIG.', '2\n shows an example of a geologic environment \n201\n that includes a seabed \n203\n and a sea surface \n205\n.', 'As shown, equipment \n210\n such as a ship may tow an energy source \n220\n and a string of sensors \n230\n at a depth below the sea surface \n205\n (e.g., one or more streamers, etc.).', 'In such an example, the energy source \n220\n may emit energy at a time T\n0\n, a portion of that energy may be reflected from the seabed \n203\n at a time T\n1\n and a portion of that reflected energy may be received at the string of sensors \n230\n at a time T\n2\n.', 'As mentioned with respect to the technique \n170\n of \nFIG.', '1\n, a wave may be a primary or a multiple.', 'As shown in an enlarged view of the geologic environment \n201\n, the sea surface \n205\n may act to reflect waves such that sensors \n232\n of the string of sensors \n230\n may sense multiples as well as primaries.', 'In particular, the sensors \n232\n may sense so-called sea surface multiples, which may be multiples from primaries or multiples of multiples (e.g., due to sub-seabed reflections, etc.).', 'As an example, each of the sensors \n232\n may sense energy of an upgoing wave at a time T\n2\n where the upgoing wave reflects off the sea surface \n205\n at a time T\n3\n and where the sensors may sense energy of a downgoing multiple reflected wave at a time T\n4\n (see also the data \n180\n of \nFIG.', '1\n and data \n240\n of \nFIG.', '2\n).', 'In such an example, sensing of the downgoing multiple reflected wave may be considered noise that interferes with sensing of one or more upgoing waves.', 'As an example, an approach that includes summing data acquired by a geophone and data acquired by a hydrophone may help to diminish noise associated with downgoing multiple reflected waves.', 'Such an approach may be employed, for example, where sensors may be located proximate to a surface such as the sea surface \n205\n (e.g., arrival times T\n2\n and T\n4\n may be relatively close).', 'As an example, the sea surface \n205\n or a water surface may be an interface between two media.', 'For example, consider an air and water interface.', 'As an example, due to differing media properties, sound waves may travel at about 1,500 m/s in water and at about 340 m/s in air.', 'As an example, at an air and water interface, energy may be transmitted and reflected.', 'As an example, each of the sensors \n232\n may include at least one geophone \n234\n and a hydrophone \n236\n.', 'As an example, a geophone may be a sensor configured for seismic acquisition, whether onshore and/or offshore, that can detect velocity produced by seismic waves and that can, for example, transform motion into electrical impulses.', 'As an example, a geophone may be configured to detect motion in a single direction.', 'As an example, a geophone may be configured to detect motion in a vertical direction.', 'As an example, three mutually orthogonal geophones may be used in combination to collect so-called \n3\nC seismic data.', 'As an example, a hydrophone may be a sensor configured for use in detecting seismic energy in the form of pressure changes under water during marine seismic acquisition.', 'As an example, hydrophones may be positioned along a string or strings to form a streamer or streamers that may be towed by a seismic vessel (e.g., or deployed in a bore).', 'Thus, in the example of \nFIG.', '2\n, the at least one geophone \n234\n can provide for motion detection and the hydrophone \n236\n can provide for pressure detection.', 'As an example, the data \n240\n (e.g., analog and/or digital) may be transmitted via equipment, for example, for processing, etc.', 'As an example, a method may include analysis of hydrophone response and vertical geophone response, which may help to improve a PZ summation, for example, by reducing receiver ghost and/or free surface-multiple noise contamination.', 'As an example, a ghost may be defined as a reflection of a wavefield as reflected from a water surface (e.g., water and air interface) that is located above a receiver, a source, etc. (e.g., a receiver ghost, a source ghost, etc.).', 'As an example, a receiver may experience a delay between an upgoing wavefield and its downgoing ghost, which may depend on depth of the receiver.', 'As an example, a surface marine cable may be or include a buoyant assembly of electrical wires that connect sensors and that can relay seismic data to the recording seismic vessel.', 'As an example, a multi-streamer vessel may tow more than one streamer cable to increase the amount of data acquired in one pass.', 'As an example, a marine seismic vessel may be about 75 m long and travel about 5 knots, for example, while towing arrays of air guns and streamers containing sensors, which may be located, for example, about a few meters below the surface of the water.', 'A so-called tail buoy may assist crew in location an end of a streamer.', 'As an example, an air gun may be activated periodically, such as about intervals of 25 m (e.g., about intervals of 10 seconds) where the resulting sound wave travels into the Earth, which may be reflected back by one or more rock layers to sensors on a streamer, which may then be relayed as signals (e.g., data, information, etc.) to equipment on the tow vessel.', 'In the example of \nFIG.', '2\n, the equipment \n210\n may include a system such as the system \n250\n.', 'As shown in \nFIG.', '2\n, the system \n250\n includes one or more information storage devices \n252\n, one or more computers \n254\n, one or more network interfaces \n260\n and one or more sets of instructions \n270\n.', 'As to the one or more computers \n254\n, each computer may include one or more processors (e.g., or processing cores) \n256\n and memory \n258\n for storing instructions (e.g., consider one or more of the one or more sets of instructions \n270\n), for example, executable by at least one of the one or more processors.', 'As an example, a computer may include one or more network interfaces (e.g., wired or wireless), one or more graphics cards, a display interface (e.g., wired or wireless), etc.', 'As an example, pressure data may be represented as “P” and velocity data may be represented as “Z”.', 'As an example, a hydrophone may sense pressure information and a geophone may sense velocity information.', 'As an example, hydrophone may output signals, optionally as digital data, for example, for receipt by a system.', 'As an example, a geophone may output signals, optionally as digital data, for example, for receipt by a system.', 'As an example, the system \n250\n may receive P and Z data via one or more of the one or more network interfaces \n260\n and process such data, for example, via execution of instructions stored in the memory \n258\n by the processor \n256\n.', 'As an example, the system \n250\n may store raw and/or processed data in one or more of the one or more information storage devices \n252\n.\n \nFIG.', '3\n illustrates a schematic diagram of an example of a marine-based seismic acquisition system \n310\n and an example of a method \n390\n.', 'In the system \n310\n, a survey vessel \n320\n may tow one or more seismic streamers \n330\n behind the vessel \n320\n.', 'As an example, streamers \n330\n may be arranged in a spread in which multiple streamers \n330\n are towed in approximately a plane at a depth.', 'As an example, streamers may be towed at multiple depths (e.g., consider an over/under configuration).', 'As an example, the seismic streamers \n330\n may be several thousand meters long and may include various support cables, as well as wiring and/or circuitry that may be used to facilitate communication along the streamers \n330\n.', 'As an example, an individual streamer \n330\n may include a primary cable where the seismic sensors \n358\n that can record seismic signals may be mounted.', 'As an example, the seismic sensors \n358\n may include hydrophones that acquire pressure data.', 'As another example, the seismic sensors \n358\n may include one or more multi-component sensors, for example, consider a sensor capable of detecting a pressure wavefield and at least one component of a particle motion that is associated with acoustic signals that are proximate to the sensor.', 'Examples of particle motions include one or more components of a particle displacement, one or more components (e.g., inline (x), crossline (y) and vertical (z) components (see, e.g., coordinate axes \n359\n) of a particle velocity and one or more components of a particle acceleration.', 'As an example, the marine-based seismic data acquisition system \n310\n may include one or more seismic sources \n340\n (e.g., air guns, etc.).', 'As shown in the example of \nFIG.', '3\n, the seismic sources \n340\n may be coupled to, or towed by, the survey vessel \n320\n.', 'As another example, the seismic sources \n340\n may operate independently of the survey vessel \n320\n in that the sources \n340\n may be coupled to another vessel or vessels, to a buoy or buoys, etc.', 'As an example, the seismic streamers \n330\n can be towed behind the survey vessel \n320\n where acoustic signals \n342\n (e.g., “shots”) may be produced by the seismic sources \n340\n.', 'The acoustic signals \n342\n may be directed down through a water column \n344\n into strata \n362\n and \n368\n beneath a water bottom surface \n324\n.', 'As an example, at least a portion of the acoustic signals \n342\n may be reflected from subterranean geological formation(s), for example, consider a formation \n365\n as depicted in \nFIG.', '3\n.', 'As an example, incident acoustic signals \n342\n generated by the sources \n340\n can produce corresponding reflected acoustic signals, or pressure waves \n360\n, which may be sensed by one or more of the seismic sensors \n358\n.', 'As an example, pressure waves received and sensed by one or more of the seismic sensors \n358\n may include “up going” pressure waves that propagate to the one or more sensors \n358\n without reflection and, for example, “down going” pressure waves that are produced in part by reflections of the pressure waves \n360\n from an air-water boundary \n331\n.', 'As an example, the seismic sensors \n358\n may generate signals, which may be traces or structured as traces (e.g., amplitude with respect to time, etc.).', 'For example, consider traces that include information as to measurements of pressure wavefield and particle motion.', 'As an example, signals may be recorded and may be processed by a signal processing unit \n323\n, which may optionally be deployed on the survey vessel \n320\n.', 'As an example, a method can include performing a seismic survey that acquires seismic data (e.g., traces, etc.) where such data can build an “image” of a survey area, for example, for purposes of identifying one or more subterranean geological formations (see, e.g., the formation \n365\n).', 'As an example, subsequent analysis of seismic data (e.g., interpretation, etc.) may reveal one or more possible locations of hydrocarbon deposits in one or more subterranean geological formations.', 'As an example, an analysis can include determining one or more characteristics of one or more types of hydrocarbons.', 'As an example, an analysis can include one or more of image generation and attribute generation (e.g., seismic attribute generation, etc.).', 'As an example, a particular one of the one or more seismic sources \n340\n may be part of an array of seismic source elements (e.g., air guns, etc.) that may be arranged in strings (e.g., gun strings, etc.) of the array.', 'As an example, one or more sources may be fired (e.g., actuated to emit energy) according to a time schedule (e.g., a timing sequence) during a survey.', 'As an example, a land-based seismic acquisition system may acquire data that may be processed, for example, via one or more of the methods described herein.', 'As mentioned, sources may be fired (e.g., actuated) according to a time schedule, a timing sequence, etc.', 'As an example, consider a sequential source firing method that includes firing sources at intervals combined with continuous vessel travel.', 'As another example, consider a simultaneous source firing method that include firing more than one shot at a given point in time (e.g., within a small duration of time such that analysis may consider the shots to be simultaneous).', 'In such an example, sensors may sense information from multiple simultaneous shots and, for example, processing of the sensed information may separate the sensed information into individual source components.', 'As an example, where simultaneous source firing is implemented, “boat time” (e.g., turnaround time, etc.) may be approximately the same or less than a sequential technique (e.g., depending on survey parameters, goals, etc.).', 'In \nFIG.', '3\n, the method \n390\n includes firing a source \n340\n at a source firing time S\n1\n, firing the source \n340\n at a source firing time S\n2\n and firing the source \n340\n at a source firing time S\n3\n.', 'The method \n390\n also includes receiving signals at the seismic sensor \n358\n.', 'Such a method may result in strong deep interference.', 'For example, where after one shot is fired from a source, a subsequent shot is fired from the source and energy associated with the subsequent shot is received at a seismic sensor over a period of time during which energy from the prior shot is also received.', 'In such an example, a portion of energy of the prior shot interferes with acquisition of energy from the latter shot.', 'The portion of energy from the prior shot may be referred to as late arriving energy (e.g., late data).', 'As an example, interference may also occur in a survey where sources are fired in a relatively simultaneous manner.', 'In such an example, some amount of interference may be expected and, for example, a purposeful part of a survey.', 'As to the energy associated with the source \n340\n at the source firing time S\n1\n, it can be partially reflected at an interface to generate a reflected upgoing portion while another portion penetrate deeper toward another interface.', 'Thus, in the simplified illustration, two portions exist, an upgoing portion and a downgoing portion.', 'As illustrated, at approximately a source firing time S\n2\n, an upgoing portion from the source firing time S\n1\n and an upgoing portion from the source firing time S\n2\n can exist.', 'As these portions travel upwards, they can arrive at the seismic sensor \n358\n over a common span of time to result in S\n1\n-S\n2\n interference.', 'As illustrated, for the source firing time S\n3\n, there may be S\n2\n-S\n3\n interference.', 'Accordingly, interference can exist in data for a plurality of shots of a survey.', 'As an example, interference can exist in one or more types of surveys such as, for example, a land-based survey or a sea-based survey.', 'As mentioned, interference can be more pronounced where a survey aims to acquire data for deep structures in a geologic environment.', 'As an example, interference may be a type of noise that can be amenable to handling via a computing system that includes one or more GANs.', 'As an example, a vessel may include a computing system that includes one or more GANs (e.g., one or more trained GANs) that can include an interface that receives data from one or more streamers (e.g., sensors thereof).', 'Such a computing system may operate in real-time to process data as it is acquired.', 'In such an example, processed data may be generated that has lesser noise (e.g., attenuated noise) and/or processed data may be generated that identifies one or more types of noise, which may be utilized to control, adjust, repair, etc., one or more components of a seismic survey system.', 'FIG.', '4\n shows an example plot \n400\n of quality versus acquisition turnaround time.', 'For example, consider a simultaneous seismic source acquisition and processing technique that may allow for an improvement in quality for a standard turnaround time or a reduced turnaround time that may aim to achieve a quality level of a sequential technique (e.g., which would take a longer time).', 'In \nFIG.', '4\n, a dashed curve corresponds to a single source firing at a time approach while a solid curve corresponds to a simultaneous source firing at a time approach.', 'As illustrated, time may be shortened (see, e.g., Δt) and/or quality may be improved (see, e.g., Δq).', 'As mentioned, interference may occur in one or more types of surveys.\n \nFIG.', '4\n also shows a series of images \n410\n for shots where a shot is an emission from a source.', 'In the example, a pair of guns in a four-boat configuration fired sources (shots or emissions) in an acquisition time window.', 'The left image demonstrates the presence of two water-bottom reflections where an upper reflection is associated with source \n2\n.', 'The center and right images show the shot record on the left after source separation where the center image corresponds to source \n1\n and the right image corresponds to source \n2\n.', 'Such a process is referred to as “source separation”.', 'A method for source separation can include acquiring seismic data of a survey that utilizes multiple sources where the seismic data include blended seismic data for a number of emissions from a corresponding number of the multiple sources and associating at least two portions of the blended seismic data correspondingly with at least two of the multiple sources.', 'For example, in \nFIG.', '4\n, the blended seismic data are the data shown in the left image for sources \n1\n and \n2\n, while the portions shown in the center and right are associated with source \n1\n and source \n2\n, correspondingly.', 'In such a process (e.g., source separation), noise can present some issues that may confound associating portions of blended seismic data correspondingly with sources.\n \nFIG.', '5\n shows a geologic environment \n501\n (lower left), equipment \n510\n, a plot \n515\n of a frequency sweep as generated by the equipment \n510\n (e.g., with start and end times), downgoing energy \n517\n of the frequency sweep, upgoing energy \n519\n of the frequency sweep, and a sensor \n520\n (a node as in an array or grid).', 'While \nFIG.', '5\n is shown as a land-based survey, various features, actions, etc., may be applied in a marine survey where seabed sensors are employed (see the marine-based survey \n380\n of \nFIG.', '3\n).', 'As an example, data can be data of a simultaneous vibroseis survey that includes seismic energy emissions S\n1\n, S\n2\n and S\n3\n.', 'Such data may be plotted as a correlated record from a simultaneous vibroseis acquisition where artifacts of an air blast from S\n1\n (cross airwave), chimney noise from S\n3\n and harmonic from S\n3\n (cross harmonic) may be labeled along with a slip time and a record length for S\n2\n (about 5 seconds).', 'In a vibroseis survey, various types of noise may be present such as chimney noise, which may be seen when data are correlated with a survey sweep and visualized (as a column).', 'As to other types of noise, these may include ground-roll and/or air-blast types of noise.', 'In a slip-sweep operations data can be recorded as a mother record where the interval between two consecutive sweeps is referred to as the slip time (see S\n1\n and S\n2\n and slip time).', 'As mentioned, a computing system can include one or more GANs that can process seismic data.', 'For example, such seismic data may be from one or more types of surveys, some of which have been explained with respect to \nFIGS.', '1, 2, 3, 4 and 5\n.', 'FIG.', '6\n shows example plots \n610\n and \n630\n that are results output by a computing system that implements one or more Generative Adversarial Noise Attenuation Networks (GANANs) for noise attenuation.', 'In the plots of \nFIG.', '6\n, the plot \n610\n is an input shot that is received as seismic data that are passed through a trained network of the computing system to generate the processed seismic data of the plot \n630\n.', 'As shown in the examples of \nFIG.', '6\n, kinematics of the input shot are maintained, but the swell noise in the near channels is attenuated, along with artifacts at farther offsets.', 'In this example, the GANAN works as a strong dip filter, operating with some knowledge of the kinematics of a seismic shot record.', 'At one level, a GAN can involve two networks competing in an adversarial manner to generate data that fits a given distribution.', 'A computing system may implement more than two GANs where, for example, competition may be for common and/or different features.', 'As an example, in a GAN, a generator G (e.g., a generator network) can take an input and generates data, while a discriminator D (e.g., a discriminator network) tries to determine if the output from G is a real example or generated.', 'At the start of training, G tends to generate random noise, and D tends to be able to readily determine that the outputs of G are not real (e.g., fake or otherwise inadequate representations of real features).', 'After training, however, G will tend to recover a data distribution, and D will tend to be less able and possibly unable to distinguish between real samples and generated ones.', 'As an example, a computing system can utilize one or more deep convolutional neural networks (CNNs).', 'For example, the aforementioned generator G and discriminator D may each be a CNN (e.g., or CNNs).', 'In such an example, a GAN can be a Deep Convolutional GAN (DCGAN).', 'As an example, a CNN can be built around a series of convolutional filters that learn to identify particular features of input data.', 'For example, consider identification tasks where a CNN can learn filters for edge detection, color blurring, and other useful features for distinguishing a class of images.', 'By learning various filters and passing them through a network with several layers, a CNN learns to “see” an image in desired manner.', 'As an example, a DCGAN may be utilized to see a subsurface region based at least in part on seismic data.', 'In such an example, the output may be akin to that of a seismic interpretation framework, which may utilized seismic attributes, models, etc. to generate data and, for example, to render such data to a display for human viewing.', 'As mentioned, a computing system can include one or more GANs for seismic noise attenuation.', 'Random noise in seismic data can, at times, be relatively easy for a human to identify by eye (e.g., upon viewing seismic data rendered to a display).', 'However, a computing system may be less sensitive to features and/or patterns that are due to noise and, for example, may prove inadequate in attenuating noise in a manner that does not impact signal (e.g., useful signal).', 'As an example, a computing system can, in an effort to handle noise, convert seismic data of one or more of different domains, such as, for example, the FK or Radon domains.', 'Such domain transformations demand computing resources (e.g., processor time and memory space), which can add runtime to a noise attenuation workflow as well as involve analysis from a human expert.', 'As CNNs can be modeled after the ways humans interpret information, a CNN-based approach can allow for identifying and attenuating noise in a seismic shot record, optionally without performing one or more domain transforms.', 'As an example, a computing system can include circuitry that can implement a DCGAN approach that aims to replicate one or more results as may be achieved via a human and/or a more arduous computational path that involves experts and domain transforms.', 'As an example, a method can include building a Generative Adversarial Noise Attenuation Network (GANAN) in a manner of conditioned style transfer type networks.', 'Such a class of GAN can utilize data in two forms and can attempt to generate one form from the other form.', 'Such a GANAN can be utilized to process seismic data, for example, by changing a noisy image to a clean one (e.g., noisy seismic data to noise attenuated seismic data).', 'As an example, a method can include training a network to perform such a task through use of a noise-free shot to pair with each input shot.', 'Seismic noise attenuation workflows tend to leave some noise in the data, for example, to reduce undesirable signal attenuation.', 'As an example, a GAN-based approach on shots with noise can be utilized to attempt to recreate that noise.', 'As an example, a method can include generating a noise-free shot.', 'For example, a computing system can be utilized to generate synthetic shots with a real data geometry using, for example, a finite difference modeling (FDM) engine (e.g., or other numerical technique).', 'As an example, by using a velocity model that has been updated through Full Waveform Inversion (FWI) and Reflection Tomography (RT), a computing system can help to ensure that a set of synthetic shots possess the underlying kinematics of real data, for example, without random noise associated with real-world acquisition (e.g., equipment and/or processes).', 'As an example, coherent and/or physically explainable noise, such as multiples, can be modeled, leaving random noise different between two datasets.', 'A discriminator model can be built according to a DCGAN framework.', 'For example, it can take an image, either real or generated, as input, and pass it through a series of convolutional filters, or layers.', 'In such an example, each layer of the network can downsample the image until a final layer is a single value representing the probability of the image being real (e.g., or fake).\n \nFIG.', '7\n shows example graphics \n701\n, \n705\n, \n710\n and \n730\n of an architecture of a computational framework that can be utilized for processing seismic data.', 'The graphic \n701\n shows a discriminator network \n702\n and a generator network \n704\n, which can be neural networks.', 'The discriminator network \n702\n can operate using a training set and the generator network \n704\n can operate using random noise where a distribution may be chosen from random noise.', 'For example, the generator network \n704\n can take a vector as input and return an image.', 'The generator network \n704\n may be represented by a function “G”.', 'The discriminator network \n702\n, which may be represented by a function “D” can take an image as input and returns a probability that the image was sampled from an (unknown) probability distribution of data.', 'As shown, the discriminator network \n702\n can output a label or classification (e.g., “real”, “fake”, OK, NOK, etc.).', 'As an example, a generator network can take in random numbers and return an image.', 'The generated image can be fed into a discriminator network alongside one or more images taken from a “ground-truth” dataset.', 'As shown in the example of \nFIG.', '7\n, the discriminator network \n702\n takes in different types of images such as “real” (e.g., ground-truth) and “fake” (e.g., generated or replica) and returns a probability such as a number between 0 and 1, with 1 representing a prediction of authenticity and 0 representing fake.', 'Such an approach can include a double feedback loop: the discriminator network \n702\n is in a feedback loop with the ground truth of the images (known); and the generator network \n704\n is in a feedback loop with the discriminator network \n702\n.', 'While images are mentioned, in various examples, seismic data (e.g., actual and/or synthetic) are utilized as the “ground-truth” for a discriminator network and seismic data are generated by the generator network (e.g., generative network) for feeding to the discriminator network such that the discriminator network can make determinations (e.g., outputs) that facilitate training of the generator network.', 'As an example, noise in seismic data may be identified as being “fake” and signal in seismic data may be identified as being “real”.', 'As an example, a method can include identifying signal and/or noise and processing seismic data based thereon to, for example, enhance seismic data as to signal.', 'As an example, where an analysis of noise is desired, a method can include identifying noise in seismic data and analyzing the noise (e.g., to improve further processing, to understand source thereof, to improve acquisition, etc.).', 'As an example, an adversarial network may be utilized to identify signal and/or noise in seismic data where such seismic data includes signal and one or more types of noise.', 'Such an approach can, for example, aim to enhance signal (e.g., by extracting signal, attenuating noise, etc.).', 'As an example, a discriminator network can be a convolutional network that can categorize data fed to it such as by binomial classifier labeling input as real or fake (e.g., or signal or noise).', 'As an example, a generator network can be an inverse convolutional network, in a sense.', 'For example, while a convolutional classifier can take an image and downsample it to produce a probability, a generator network can take a vector of random noise and upsample it to become an image.', 'In such a characterization, the first throws away data through downsampling techniques like maxpooling, and the second generates “new” data.', 'In an adversarial approach, two networks can try to optimize a different and opposing objective function, or loss function, in a zero-sum game (e.g., an actor-critic model).', 'In such an example, as the discriminator changes its behavior, so does the generator, and vice versa, such that their losses push against each other.', 'As explained, a GAN can be implemented to make generated seismic data that are indistinguishable from actual seismic data or synthetic seismic data.', 'As explained, a GAN can learn a loss that tries to classify an output as being “real” or “fake”, while training a generative model to minimize the loss.', 'As a GAN can learn a loss that that adapts to data, a GAN can be applied, for example, to a task such as changing noisy seismic data to clean seismic data (e.g., attenuating noise in noisy seismic data).', 'For example, consider a GAN in a conditional setting, which may be referred to as a “cGAN”.', 'A cGAN can be suitable for image-to-image types of tasks, as explained with respect to a GANAN.', 'Such an approach can condition on an input and generate a corresponding output.', 'An article by Isola et al., “Image-to-Image Translation with Conditional Adversarial Networks,” arXiv:1611.07004 (2017) is incorporated by reference herein.', 'Another image-to-image type of approach is described in an article by Gatys et al., “A Neural Algorithm of Artistic Style,” arXiv:1508.06576 (2015), which is incorporated by reference herein.', 'The article by Gatys et al. describes representations of content and style using a convolutional neural network (CNN) approach where content and style can be separable and where a trained network can handle both representations independently to produce new, perceptually meaningful images.', 'Gatys et al. generate images that mix the content and style representation from two different source images, specifically, matching the content representation of a photograph depicting the “Neckarfront” in Tuebingen, Germany and style representations of several well-known artworks taken from different periods of art.', 'Images were synthesized by finding an image that simultaneously matches the content representation of the photograph and the style representation of the respective piece of art.', 'Such an approach can render a photograph in the style of the artwork, such that the appearance of a synthesized image resembles the work of art, even though it shows the same content as the photograph.', 'The approach can handle content and style with a loss function that is minimized during image synthesis that includes two terms for content and style, respectively, which are separable such that it is possible to smoothly regulate the emphasis on either reconstructing content or style.', 'A CNN approach provides for a separation of image content from style, thus allowing recasting of the content of one image in the style of another image.', 'For example, to generate images that mix the content of a photograph with the style of a painting, a CNN approach can jointly minimize the distance of a white noise image from the content representation of the photograph in one layer of the network and the style representation of the painting in a number of layers of the CNN.', 'As an example, a method can implement one or more types of image-to-image approaches, which, in terms of seismic data can be seismic data-to-seismic data approaches, which can include actual seismic data, in raw and/or processed forms, and/or synthetic seismic data (e.g., without and/or without noise).', 'In seismic data, unlike a photographic image, a domain may be a mixed domain (e.g., heterogeneous domain) with respect to time and space.', 'As an example, time can be a proxy for depth and, for example, seismic data may be in a spatial domain (e.g., inline and depth, crossline and depth, inline and crossline, etc.).', 'As mentioned, seismic data can be in the form of seismic traces with amplitude values that have corresponding times where each seismic trace can be associated with at least a receiver of seismic survey equipment.', 'As an example, times may be transformed to depths.', 'As mentioned, a seismic data-to-seismic data approach can involve inputting seismic data and outputting seismic data where, for example, the output seismic data are noise attenuated.', 'Such output can be improved output, for example, in terms of signal to noise ratio where the signal represents physical, tangible objects in the Earth.', 'The graphic \n705\n shows an example of a cGAN that includes a discriminator network \n706\n and a generator network \n708\n.', 'In one instance, the discriminator network \n706\n indicates NOK (e.g., “fake”) while in another instance, the discriminator network \n706\n indicates OK (e.g., “real”).', 'The graphic includes various nomenclature, for example, a “regular” GAN may learn a mapping from a random noise vector z to an output image y, G: z→y; whereas, a conditional GAN can learn a mapping from an observed image x and a random noise vector z, to y, G: {x, z}→y.', 'As noted, the condition GAN (cGAN) involves learning a mapping using an observed image x, and a random noise vector z, to an output image y.', 'In such an approach, the generator G can be trained to produce outputs that are to some degree indistinguishable from “real” inputs via an adversarially trained discriminator D, which is trained to do as well as possible at detecting generator generated “fakes”.', 'In the graphic \n705\n, consider training a cGAN to map edges to a photographic image.', 'In such an example, the discriminator D learns to classify between fake (e.g., G(x)) and real {edge, photo} tuples.', 'The generator G learns to “fool” the discriminator D. As illustrated, in the cGAN example of the graphic \n705\n, the generator network \n708\n and the discriminator network \n706\n “observe” the input, which in the foregoing example, can be the input edge map.', 'As an example, a GAN can utilize an approach as described in with respect to the graphic \n705\n to provide an input grid to output grid mapping where a difference can be, for example, with respect to noise.', 'As an example, a method can utilize an approach as in the graphic \n705\n of \nFIG.', '7\n where synthetic seismic images (y) and real seismic images (x) are used in training by a discriminator D such that a generator G is trained to output G(x), which can be a noise attenuated seismic image.', 'As explained herein, various approach can be utilized with seismic data that input actual and/or synthetic seismic data and that output generated seismic data (e.g., noise attenuated seismic data, enhanced resolution seismic data, etc.).', 'As an example, a generator network can be utilized in a conditional GAN (e.g., cGAN) that has a UNet (or “U-Net”) architecture, for example, as explained with respect to the graphic \n730\n of \nFIG.', '7\n.', 'As an example, a discriminator network can be a PatchGAN that operates to penalize features at a scale of patches (e.g., N×N patches).', 'The graphic \n710\n shows details for a discriminator (e.g., discriminator network) and the graphic \n730\n shows details for a GANAN generator, which can be a type of conditional GAN (e.g., cGAN) (see, e.g., the graphic \n705\n).', 'In the example of \nFIG.', '7\n, the discriminator can include features of a CNN framework (e.g., image identification tasks where the result is a single value); where, in the example of \nFIG.', '7\n, representing whether an image is real or generated.', 'In the graphics \n710\n and \n730\n, the number above each layer corresponds to a number of filters in the layer.', 'The generator can use a similar downsampling but follows the downsampling layers with a corresponding series of connected upsampling ones.', 'As shown, the final layer of the generator can aim to create an image with size and amplitude of the input.', 'In the graphics \n710\n and \n730\n, hatching is presented for operations such as convolution, leaky ReLU, and batch normalization (see, e.g., Ronneberger et al., Isola et al., etc.).', 'Such operations can be utilized to define one or more network architectures.', 'As an example, consider a UNet architecture as described in an article by Ronneberger et al., “U-Net: Convolutional Networks for Biomedical Image Segmentation,” arXiv:1505.04597 (2015), which is incorporated by reference herein.', 'Such an architecture includes a contracting path (see the left side of the graphic \n730\n) and an expansive path (see the right side of the graphic \n730\n).', 'The article by Ronneberger et al. describes a contracting path that follows an architecture of a convolutional network and that includes repeated application of convolutions and use of a rectified linear unit (ReLU) along with a max pooling operation with a specified stride for downsampling where, in an expansive path, upsampling of a feature map can be performed followed by convolution.', 'In the article by Isola et al., an architecture is described by letting Ck denote a Convolution-BatchNorm-ReLU layer with k filters where CDk denotes a Convolution-BatchNorm-Dropout-ReLU layer with a dropout rate of Y percent.', 'Convolutions may be defined by “spatial” filters (e.g., operating in a domain of seismic data, which can be temporal and spatial) with size and stride.', 'As an example, convolutions in an encoder and in a discriminator can downsample by a specified factor (e.g., 2, etc.); whereas, in a decoder they can upsample by a specified factor (e.g., 2, etc.).', 'As to a generator architecture, an encoder-decoder architecture, can be specified using notation such as “C128”, “C256”, “C512”, etc.; and “CD512”, “CD256”, “CD128”, etc.', 'As an example, after a last layer in decoder, a convolution can be applied to map to a number of output channels, followed by a Tanh function.', 'As an exception to the above notation, batch normalization (e.g., Batch-Norm) may not be applied to a first layer in an encoder.', 'As an example, ReLUs in an encoder may be specified to be leaky with a slope or not leaky and ReLUs in a decoder may be specified to be leaky with a slope or not leaky.', 'As an example, a U-Net architecture can include such features, for example, with skip connections.', 'Such skip connections can concatenate activations (e.g., from layer i to layer n), which may alter the number of channels in a decoder.', 'As to a discriminator architecture, after a last layer, a convolution may be applied to map to a 1-dimensional output, followed by a Sigmoid function (e.g., or other suitable function).', 'As an example, batch normalization may or may not be applied to a layer.', 'As an example, ReLU can be leaky with a slope or not leaky.', 'As explained with respect to the graphic \n701\n and the graphic \n705\n, a GAN-based approach can involve two networks competing in an adversarial game to generate data that fits a given distribution.', 'In such an approach, a generator G can, for example, take an input and generate data while a discriminator D tries to determine if the output from G is “real” or “fake” (e.g., OK or NOK), where “real” can be a camera light photography image and where a “fake” can be a generated image (e.g., aimed to be a replica of a camera light photography image).', 'At the start of training, G can generate random noise, and D will be able to readily determine that output images are “fake”.', 'After training, however, G can recover a data distribution, and D will be less and less able to distinguish between “real” images and generated “fake” images.', 'As explained, a method can utilize a generator network (e.g., a G network) and a discriminator network (e.g., a D network) that can process signal data such as seismic signal data.', 'As explained with respect to the graphic \n705\n, a method can include an image-to-image translation or a seismic data-to-seismic data translation where, for example, input seismic data include signal and noise and where output seismic data are noise attenuated.', 'Seismic signal data differ from camera light photography in various ways.', 'A digital camera can include a CCD image sensor array that can output pixel values response to an image being focused upon the CCD image sensor array by an optical lens where the image corresponds to a real world object that can be seen by the human eye.', "Specifically, visible light can shine upon the real world object to illuminate it where such illumination can travel to the lens and hence be focused upon the digital camera's CCD image sensor array, which can generate a pixel image of the real world object that, to the human eye, looks identical to the real world object.", 'As may be appreciated, a CCD image sensor array can be an integrator that sums exposure (e.g., consider accumulation of electrons that proceeds until image integration is over and charge begins to be transferred, or thermal equilibrium is reached).', 'As such, a time varying signal is not acquired or represented in digital camera still image data.', 'In contrast, seismic imaging aims to understand physical, real world structures that exist within the Earth.', 'Seismic imaging is a dynamic process that acquires time varying signals (e.g., amplitudes with respect to time).', 'Seismology can be utilized to “image” subsurface structures through use of one or more sources and receivers.', 'Seismic imaging can involve processing to place reflections in their appropriate locations with appropriate amplitudes.', 'As explained, interpretation can be performed through analysis of amplitude data, which may be contaminated by one or more types of noise.', 'An increase in signal to noise (e.g., SNR) can improve interpretation.', 'Such an increase can be via one or more processes, which may aim to separate signal and/or noise, to attenuate noise, to boost signal, etc.', 'In seismic data, amplitudes can be indicative of relative changes in impedance of structures in the Earth and volumetric seismic data may be processed to yield impedances between the reflecting boundaries.', 'When acquiring seismic data, noise that is unrelated to the subsurface can be introduced by mechanics of acquisition equipment and/or an acquisition process.', 'For example, with marine data, strong currents can introduce a high amplitude noise signature that can be much stronger than the seismic signal that is desired.', 'Techniques to attenuating such noise (e.g., noise patterns) tend to rely on careful sorting of the data, or transforming the time/space data to a different domain such as Radon domain or FK domain (Frequency/wavenumber).', 'Such schemes demand expert knowledge to remove noise effectively, and tend to be very sensitive to small mis-parameterizations.', 'As an example, a GAN-based technique can allow for building a noise attenuation tool using examples of clean and noisy data, which can be performed optionally without human intervention to achieve results.', 'Intuitively, a GAN can learn an underlying distribution of data (e.g., via a generator and a discriminator).', 'As an example, when a GAN-based approach is applied to seismic data, a method can include learning what components of seismic data (e.g., a seismic shot record, etc.) are “real” (e.g., desired signal) and what parts are noise.', 'Once a network is trained to have such an ability or abilities, it is able to use its learned distribution(s) to reconstruct one or more “real” parts of seismic data (e.g., a real part of a seismic shot, etc.) and to discard information that it identifies as noise.', 'As an example, a generator network can be based around a UNet architecture.', 'The UNet is a CNN that includes progressive downsampling as in the discriminator network and follows these layers with a corresponding series of upsampling layers to recover the resolution of the input.', 'As an example, upsampling layers can utilize what are termed “skip connections,” which link them to the corresponding downsampling layers.', 'Such an approach allows higher level features to track directly across the network.', 'In seismic data processing, network-based computing system can aim to keep high-level details from the input shot at least in part via one or more skip connections particularly useful.', 'Referring again to \nFIG.', '6\n, the plot \n630\n shows the results of GANAN on a seismic shot record.', 'The plot of \n610\n corresponds to a shot that had already been through a transform-based noise attenuation workflow, however it was unable to attenuate the strong swell noise at the water bottom.', 'As the GANAN approach is attempting to make the shot indistinguishable from a synthetic modeled shot, the output does not possess swell energy that is on the input.', 'The success of the network on the deeper section is less clear, as it is hard to see reflectivity on the near traces of the input.', 'As an example, the GANAN approach can be directed to various aspects, features, etc., of a shot (e.g., a type of seismic data).', 'As an example, consider a focus on recovering such signal, for example, via forward modeling with a Born modeling engine that is designed to capture deeper reflectivity.', 'As mentioned, a GAN-based approach may be utilized for trace interpolation.', 'As an example, consider applying one or more image “super-resolution” approach to trace interpolation.', 'As to trace interpolation, as an example, a discriminator network may be of a same or similar form as to a noise attenuation network while a generator may differ in form.', 'As an example, a network architecture may include features of a scheme such as, for example, that of Ledig et al. (2017) (“Photo-Realistic Single Image Super-Resolution Using a Generative Adversarial Network,” arXiv:1609.04802), which is incorporated by reference herein and includes some aspects of a UNet used in a GANAN.', 'As to noise attenuation, in an interpolation, it can be desirable to maintain high-level features from the input data as it flows through the network.', 'For example, consider utilization of “Residual Blocks” (see, e.g., He et al. (2015), “Deep Residual Learning for Image Recognition,” arXiv:1512.03385, which is incorporated by reference herein).', 'FIG.', '8\n shows an example of an architecture \n800\n of a network that includes skip connections within each block of layers to pass features down the network.', 'As an example, a network may include one or more skip connections.', 'In the example of \nFIG.', '8\n, various details of the network architecture \n800\n for a GATIN generator are illustrated.', 'As shown, the GATIN generator can include convolutional filters, normalization, and an activation function.', 'In the example of \nFIG.', '8\n, after the first layer, the network proceeds to residual layers, where the output of two convolutional layers is added to the input to the residual layer.', 'In the example of \nFIG.', '8\n, after the residual blocks, there is another convolutional layer before the first layer is added again.', 'As in GANAN, these connections can help to ensure that high-level features follow through the network before the upsampling is performed.', 'In the example of \nFIG.', '8\n, after the residual layers, the next task for the network is to perform the upsampling.', 'Such a task may be performed through use of a layer of the network that is able learn upsampling filters, for example, for each feature map.', 'Such a layer may be akin to a sub-pixel convolutional layer as may be utilized efficiently for super-resolution tasks.', 'As an example, through combining residual blocks with a final sub-pixel convolutional layer, a generator takes on an architecture of a Generative Adversarial Trace Interpolation Network, or GATIN.', 'As mentioned, a ReLU can be “leaky”, which can allow a small, non-zero gradient when the unit is not active.', 'As another example, a ReLU can be parameter (e.g., a “PReLU”), which can include a coefficient of leakage as a parameter that is learned along with the other neural network parameters.', 'In the example architecture \n800\n, ReLUs can include one or more non-leaky ReLUs, one or more leaky ReLUs and/or one or more PReLUs.\n \nFIG.', '9\n shows a series of plots \n910\n, \n920\n, \n930\n, \n940\n, \n950\n and \n960\n.', 'In \nFIG.', '9\n, GATIN results, from top to bottom, include a decimated shot, interpolated with GATIN, and the original undecimated shot.', 'The perceptual quality of the interpolation is quite high, including desired effects such as the complex diffraction and undesired effects such as interpolation of noise in the input data.', 'By taking the data to FK space, it is possible to demonstrate that the interpolation is able to recover spatial wavelengths that are lost in the original downsampling.', 'As mentioned, a workflow may optionally include one or more transforms as to one or more domains.', 'In such an example, a network or networks may be utilized (e.g., GAN, GANAN, GATIN, etc.).', 'The GATIN results of \nFIG.', '9\n demonstrate improvements when comparing original data to the decimated and interpolated output.', 'Visually the images appear substantially indistinguishable, which can be a success criterion in image upsampling tasks.', 'As an example, an interpolation can recover the visual qualities of the input data and accurately recover the energy in the shot record.', 'To demonstrate success at that level, the data can be transformed into the FK domain and a comparison can be made of the input shot record to the decimated and re-interpolated result.', 'In such an approach, a workflow can operate with an aim to recover the original trace spacing after decimation.', 'The results illustrated in \nFIG.', '9\n demonstrate how interpolating beyond the acquisition receiver spacing may be achieved utilizing one or more network-based approaches.', 'As an example, a GANAN and/or a GATIN can be built to consume a multidimensional shot record such as, in various examples, a 2D shot record (e.g., one source firing into one cable).', 'As an example, one or more GANANs and/or GATINs may be built to handle one or more spatial dimensions and/or one or more temporal dimensions.', 'As an example, consider 3D spatial seismic data and/or 4D seismic data with a temporal dimension (e.g., time as a dimension).', 'Where time is a dimension, one or more networks may be utilized to identify one or more time-related phenomena.', 'For example, consider signal and/or noise where at least a portion of the signal and/or at least a portion of the noise can change with respect to time (e.g., weather, equipment, changes in a subsurface environment due to injection, production, fracturing, etc.).', 'As an example, a series of seismic data may be received as input where the series may be with respect to time or with respect to space.', 'For example, consider a seismic cube (e.g., a 3D array of seismic data that corresponds to a subterranean volume).', 'In such an example, planes may be analyzed as a series of seismic data.', 'As to time, consider a series of slices that can be of a common area of a subterranean environment where each of the slices in the series corresponds to a different time.', 'As an example, such an approach may aim to handle noise that can differ with respect to time where, for example, signal and/or noise may be processed.', 'In such an example, processing of noise may provide one or more indications as to one or more phenomena (e.g., causes) of the noise and may help to determine whether noise may be changing, in a favorable manner or an unfavorable manner.', 'Such an approach may be utilized for one or more additional surveys (e.g., setting one or more parameters to account for a trend in noise).', 'As an example, a computing system may receive input from multiple cables into networks.', 'For example, consider a computing system that can receive data from a plurality of streamers and that can process the data in real-time where processed data can be attenuated with respect to noise.', 'As an example, noise attenuated data may be more amenable to compression and decompression, which may be lossy or lossless.', 'For example, where signal to noise ratio can be increased, compression may be applied in a lossy manner with reduced impact on signal compared to a lossy manner being applied to data with a lesser signal to noise ratio.', 'In such an example, computational and/or transmission efficiencies may be improved such that computation in real-time and/or transmission in real-time may be performed.', 'As an example, real-time computation and/or transmission can provide for one or more decisions such as control decisions to be made (e.g., communication, transmitted, etc.) in lesser time, which can make surveying and/or interpretation more efficient.', 'As an example, a method can include processing seismic data in 2D and/or 3D (e.g., or higher dimensionality).', 'As an example, an architecture can include 3D convolutions as may be supported by one or more deep learning frameworks.', 'As an example, the TENSORFLOW framework (Google LLC, Mountain View, Calif.) may be implemented, which is an open source software library for dataflow programming that includes a symbolic math library, which can be implemented for machine learning applications that can include neural networks.', 'As an example, the CAFFE framework may be implemented, which is a deep learning framework developed by Berkeley AI Research (BAIR) (University of California, Berkeley, Calif.).', 'The TENSORFLOW framework can run on multiple CPUs and GPUs (with optional CUDA (NVIDIA Corp., Santa Clara, Calif.) and SYCL (The Khronos Group Inc., Beaverton, Oreg.)', 'extensions for general-purpose computing on graphics processing units (GPUs)).', 'TENSORFLOW is available on 64-bit LINUX, MACOS (Apple Inc., Cupertino, Calif.), WINDOWS (Microsoft Corp., Redmond, Wash.), and mobile computing platforms including ANDROID (Google LLC, Mountain View, Calif.) and IOS (Apple Inc.) operating system based platforms.', 'TENSORFLOW computations can be expressed as stateful dataflow graphs; noting that the name TENSORFLOW derives from the operations that such neural networks perform on multidimensional data arrays.', 'Such arrays can be referred to as “tensors”.', 'FIG.', '10\n shows an architecture \n1000\n of a framework such as the TENSORFLOW framework.', 'As shown, the architecture \n1000\n includes various features.', 'As an example, in the terminology of the architecture \n1000\n, a client can define a computation as a dataflow graph and, for example, can initiate graph execution using a session.', 'As an example, a distributed master can prune a specific subgraph from the graph, as defined by the arguments to “Session.run( )”; partition the subgraph into multiple pieces that run in different processes and devices; distributes the graph pieces to worker services; and initiate graph piece execution by worker services.', 'As to worker services (e.g., one per task), as an example, they may schedule the execution of graph operations using kernel implementations appropriate to hardware available (CPUs, GPUs, etc.)', 'and, for example, send and receive operation results to and from other worker services.', 'As to kernel implementations, these may, for example, perform computations for individual graph operations.\n \nFIG.', '11\n shows example plots \n1110\n, \n1120\n, \n1130\n and \n1140\n.', 'As an example, forms of mode collapse may occur building GANAN.', 'In \nFIG.', '11\n, the plots \n1110\n and \n1120\n show input shots while the plots \n1130\n and \n1140\n show GANAN output.', 'In the plots \n1110\n and \n1130\n, a generator is unable to come up with useful filters and outputs random noise for input; whereas, in the plots \n1120\n and \n1140\n, the generator is able to find filters that capture some high-level information that can “fool” a discriminator; however, the resultant data can be rendered to a display, for example, for human review where it can be seen as noise.', 'As an example, a method can include using a Wasserstein loss function in one or more of a discriminator network and a generator network.', 'Such an approach can help to overcome mode collapse for these networks.', 'As an example, a computing system can include features to implement a Wasserstein loss function.', "As an example, such a function may help to address divergences that GANs tend to minimize, which are potentially not continuous with respect to a generator's parameters and, therefore, can lead to training difficulty.", 'For example, consider a using an Earth-Mover (also called Wasserstein-1) distance W (q, p), which is informally defined as the minimum cost of transporting mass in order to transform the distribution q into the distribution p (where the cost is mass times transport distance).', 'Under mild assumptions, W (q, p) is continuous everywhere and differentiable almost everywhere.', 'Various examples of equations appear below as Equations (1), (2) and (3).', 'As to Equation (1), it pertains to a formal definition of a “game” between a generator G and a discriminator D as being a minimax objective for a GAN.\n \n \n \n \n \n \n \n \n \n \nmin\n \nG\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nmax\n \nD\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n𝔼\n \n \nx\n \n~\n \n \nℙ\n \nr\n \n \n \n \n\u2061\n \n \n[\n \n \nlog\n \n\u2061\n \n \n(\n \n \nD\n \n\u2061\n \n \n(\n \nx\n \n)\n \n \n \n)\n \n \n \n]\n \n \n \n \n \n+\n \n \n \n𝔼\n \n \n \nx\n \n~\n \n \n~\n \n \nℙ\n \ng\n \n \n \n \n\u2061\n \n \n[\n \n \nlog\n \n\u2061\n \n \n(\n \n \n1\n \n-\n \n \nD\n \n\u2061\n \n \n(\n \n \nx\n \n~\n \n \n)\n \n \n \n \n)\n \n \n \n]\n \n \n \n \n \n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n \nwhere \nr \nis the data distribution and \ng \nis the model distribution implicitly defined by {tilde over (x)}=G(z), z˜p(z) where the input z to the generator is sampled from some simple noise distribution p, such as the uniform distribution or a spherical Gaussian distribution.', 'min\n \nG\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nmax\n \n \nD\n \n∈\n \n𝒟\n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n𝔼\n \n \nx\n \n~\n \n \nℙ\n \nr\n \n \n \n \n\u2061\n \n \n[\n \n \nD\n \n\u2061\n \n \n(\n \nx\n \n)\n \n \n \n]\n \n \n \n \n \n-\n \n \n \n𝔼\n \n \n \nx\n \n~\n \n \n~\n \n \nℙ\n \ng\n \n \n \n \n\u2061\n \n \n[\n \n \nD\n \n\u2061\n \n \n(\n \n \nx\n \n~\n \n \n)\n \n \n \n]\n \n \n \n \n \n \n \n(\n \n2\n \n)\n \n \n \n \n \n \n \n \nwhere is the set of 1-Lipschitz functions and \ng \nis once again the model distribution implicitly defined by {tilde over (x)}=G(z), z˜p(z).', 'In that case, under an optimal discriminator (called a critic, as it is not trained to classify), minimizing the value function with respect to the generator parameters minimizes (\nr\n, \ng\n).', 'L\n \n=\n \n \n \n \n𝔼\n \n \n \nx\n \n~\n \n \n~\n \n \nℙ\n \ng\n \n \n \n \n\u2061\n \n \n[\n \n \nD\n \n\u2061\n \n \n(\n \n \nx\n \n~\n \n \n)\n \n \n \n]\n \n \n \n-\n \n \n \n𝔼\n \n \nx\n \n~\n \n \nℙ\n \nr\n \n \n \n \n\u2061\n \n \n[\n \n \nD\n \n\u2061\n \n \n(\n \nx\n \n)\n \n \n \n]\n \n \n \n+\n \n \nλ\n \n\u2062\n \n \n \n𝔼\n \n \n \nx\n \n~\n \n \n~\n \n \nℙ\n \n \nx\n \n~\n \n \n \n \n \n\u2061\n \n \n[\n \n \n \n(\n \n \n \n \n\uf605\n \n \n \n∇\n \n \nx\n \n~\n \n \n \n\u2062\n \n \nD\n \n\u2061\n \n \n(\n \n \nx\n \n^\n \n \n)\n \n \n \n \n\uf606\n \n \n2\n \n \n-\n \n1\n \n \n)\n \n \n2\n \n \n]\n \n \n \n \n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n \nwhere the first two terms represent the critic loss and the last term represents the gradient penalty.', 'Above, Equation (2) is for a WGAN value function constructed using the Kantorovich-Rubinstein duality.', 'The WGAN value function results in a critic function whose gradient with respect to its input is better behaved than its GAN counterpart, making optimization of the generator easier.', 'As an example, the WGAN value function may correlate with sample quality.', 'As an example, to enforce the Lipschitz constraint on the critic, a method may clip the weights of the critic to lie within a compact space [−c, c].', 'In such an example, the set of functions satisfying this constraint is a subset of the k-Lipschitz functions for some k which depends on c and the critic architecture.', 'Above, Equation (3) includes a gradient penalty.', 'Equation (3) can be an alternative to clipping weights that can be achieved via penalizing the norm of gradient of the critic with respect to its input.', 'Such an approach can, in various circumstances, perform better than standard WGAN and enable stable training of various of GAN-based architectures.', 'As to a Wasserstein loss function, in mathematics, the Wasserstein or Kantorovich-Rubinstein metric or distance is a distance function defined between probability distributions on a given metric space M.', "Such an approach can be referred to as an “Earth Mover's distance” approach.", 'For example, if each distribution is viewed as a unit amount of “dirt” piled on M, the metric is the minimum “cost” of turning one pile into the other, which is assumed to be the amount of dirt that is to be moved times the distance it has to be moved.', 'As an example, a loss function may be utilized that can be matched to one or more types of mode collapse, for example, to reduce risk of a type or types of mode collapse.', 'As mentioned, a GAN can be a cGAN.', 'For example, consider an objective function of a cGAN according to Equation (4):\n \n \n \n \n \n \n \n \n \n \nℒ\n \n\u2062\n \ncGAN\n \n \n\u2061\n \n \n(\n \n \nG\n \n,\n \nD\n \n \n)', '=\n \n \n \n \n𝔼\n \n \nx\n \n,\n \ny\n \n \n \n\u2061\n \n \n[\n \n \nlog\n \n\u2061\n \n \n(\n \n \nD\n \n\u2061\n \n \n(\n \n \nx\n \n,\n \ny\n \n \n)\n \n \n \n)\n \n \n \n]\n \n \n \n+\n \n \n \n𝔼\n \n \nx\n \n,\n \nz\n \n \n \n\u2061\n \n \n[\n \n \nlog\n \n\u2061\n \n \n(\n \n \n1\n \n-\n \n \nD\n \n\u2061\n \n \n(\n \n \nx\n \n,\n \n \nG\n \n\u2061\n \n \n(\n \n \nx\n \n,\n \nz\n \n \n)\n \n \n \n \n)\n \n \n \n \n)\n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \n4\n \n)\n \n \n \n \n \n \n \n \nwhere G tries to minimize the objective against an adversarial D that tries to maximize it (see, e.g., Isola et al.).', 'As an example, where a “content and style” type of approach is implemented, a loss function may be written in a form akin to Equation (5): \n \ntotal\n(\n{right arrow over (p)},{right arrow over (a)},{right arrow over (x)}\n)', '=α\ntotal\n(\n{right arrow over (p)},{right arrow over (x)}\n)+β\ntotal\n(\n{right arrow over (a)},{right arrow over (x)}\n)\u2003\u2003(5) \n \nwhere {right arrow over (p)}, {right arrow over (a)}, and {right arrow over (x)} are the photograph (e.g., content), the artwork (e.g., style) and the generated artwork (e.g., stylized photograph as generated artwork), respectively, and where α and β are the weighting factors, adjustable for content and style reconstruction, respectively (see, e.g., Gatys et al.).', 'As mentioned, one or more approaches can be implemented for seismic data.', 'For example, consider “structure” or “content” being represented by synthetic seismic data without noise and “artwork” or “style” being actual seismic data.', 'In such an example, the synthetic seismic data can be output with “style” of noise.', 'As another example, consider “structure” or “content” being actual seismic data with noise and “artwork” or “style” being synthetic seismic data without noise.', 'In such an example, the actual seismic data can be output in a style that is with attenuated noise.', 'As yet another example, consider attenuating noise in actual seismic data to produce a noise attenuated “style” of seismic data.', 'Such attenuating may utilize one or more approaches to generate the noise attenuated seismic data.', 'In such an example, actual seismic data with noise can be input where output is of the actual seismic data in a noise attenuated “style” (e.g., a “style” as achieved using one or more approaches to noise attenuation, etc.).', 'As an example, a Wasserstein loss function approach may be implemented in “content and style” type of approach, for example, in one or more of multiple loss terms.', 'Training a GAN can demand an amount of computing power, for example, in the initial training of the network.', 'For example, a CNN as described can have tens to hundreds of millions of parameters in the network, leading to a large memory demand for a heavily decimated seismic dataset.', 'GAN performed on images of 32×32 or 64×64 pixels can be, at times, too small to include useful seismic information.', 'As an example, low frequency data with a large spatial sampling rate and decimated trace counts may be utilized (see, e.g., various plots herein).', 'Such an approach allowed networks to be trained on a single GPU.', 'As an example, parallelization can be utilized to train a GANAN and/or GATIN network at a desired seismic resolution (see, e.g., sample rates of seismic data acquisition and sensing).', 'As explained, ill-posed problems can suffer from a failure case known as mode collapse, examples of which can be seen in the plots \n1110\n, \n1120\n, \n1130\n and \n1140\n of \nFIG.', '11\n.', "Where such mode collapse occurs, the generator's output collapses to random noise, and the discriminator can choose a probability, such as, for example, 0.5, for inputs.", 'As explained, use of a loss function such as a Wasserstein loss function can help to reduce risk of mode collapse when building GANs for seismic data processing due to the subtle features in a shot record.', 'As mentioned, the selection of a loss function in the network can have an effect on results of a machine learning process.', 'As an example, for generating realistic seismic data, a method may utilize a loss function other than mean squared error.', 'As mentioned, the Wasserstein loss with a gradient penalty term may be implemented.', 'Such a loss function can be robust and help to reduce risk of obtaining results without suffering from mode collapse.', 'Various examples demonstrate use of GANs for tasks in seismic processing.', 'As an example, a method can implement a cycle-GAN approach.', 'For example, consider image-to-image translation as a class of vision and graphics problems that aims to learn the mapping between an input image and an output image using a training set of aligned image pairs.', 'However, in some situations, paired training data is not available or not available to an extent that makes training robust.', 'As an example, a cycle-GAN approach can be utilized for learning to translate an image from a source domain X to a target domain Y without using paired examples.', 'As an example, such an approach may be supplemented where one or more paired examples exist.', 'As an example, consider a problem that aims to learn a mapping G: X→Y such that the distribution of images from G(X) is indistinguishable from the distribution Y using an adversarial loss.', 'As such a mapping can be highly under-constrained, an approach can include coupling it with an inverse mapping F: Y→X and introduce a cycle consistency loss to enforce F (G(X))˜X (and vice versa).', 'FIG.', '12\n shows graphical examples of models and associated operations \n1210\n, \n1220\n and \n1230\n.', 'As shown in the graphic \n1210\n, a model can include two mapping functions G: X→Y and F: Y→X and associated discriminators Dy and Dx where Dy encourages G to translate X into outputs indistinguishable from domain Y, and vice versa for Dx and F. To further regularize the mapping, two cycle consistency losses can be introduced that capture the intuition that for translations from one domain to the other and back again, the translations can be expected to return to the starting point.', 'The graphic \n1220\n shows a forward cycle-consistency loss (x→G(x)→F(G(x))˜x) and the graphic \n1230\n shows a backward cycle-consistency loss (y→F(y)→G(F(y))˜y).', 'An article by Zhu et al., “Unpaired Image-to-Image Translation using Cycle-Consistent Adversarial Networks”, arXiv:1703.10593v6 [cs.CV], https://arxiv.org/abs/1703.10593 (submitted on 30 Mar. 2017 (v1), revised 15 Nov. 2018 (v6)), is incorporated by reference herein.\n \nFIG.', '13\n shows examples of images \n1310\n, \n1320\n, \n1330\n and \n1340\n where the images \n1310\n and \n1320\n correspond to noisy and clean, respectively, and where the images \n1330\n and \n1340\n correspond to clean and noisy, respectively.', 'The images \n1310\n, \n1320\n, \n1330\n and \n1340\n demonstrate a use of a GANAN framework in a cycle-GAN approach.', 'Using data that had been identified as clean and noisy, a network was trained to convert one to the other.', 'Such an approach may be utilized with or without synthetic data.', 'As an example, synthetic data with and/or without noise may be utilized.', 'As an example, a GANAN trained using synthetic data may be utilized to supplement training.', 'As an example, a method can utilize labeled data that can include real and/or synthetic data.', 'As an example, a cycle-GAN approach can be implemented without demanding a 1-to-1 correspondence between clean data and noisy data.', 'In such an example, a method may be able to learn by using examples of both clean data and examples of noisy data.', 'For example, consider a method that includes using one “clean” survey and one “noisy” survey and using labels from past processing to identify which survey data were clean and which were noisy.', 'The images \n1310\n, \n1320\n, \n1330\n and \n1340\n of \nFIG.', '13\n correspond to such a method.', 'Above, “clean” data can refer to a level of signal to noise (e.g., SNR), which is greater than that of “noisy” data.', 'As an example, an approach of adding noise to clean data may provide guidance or decision making for performing one or more surveys and/or tailoring one or more survey parameters.', 'For example, for a marine survey, where weather causes particular waves, such type of noise may be generated as an addition to clean data, which may be synthetic data or actual data that has a high signal to noise.', 'The results can inform whether or not to perform the survey and/or how to perform the survey.\n \nFIG.', '14\n shows an example of a computational framework \n1400\n that can include one or more processors and memory, as well as, for example, one or more interfaces.', 'The computational framework of \nFIG.', '14\n can include one or more features of the OMEGA framework (Schlumberger Limited, Houston, Tex.), which includes finite difference modelling (FDMOD) features for two-way wavefield extrapolation modelling, generating synthetic shot gathers with and without multiples.', 'The FDMOD features can generate synthetic shot gathers by using full 3D, two-way wavefield extrapolation modelling, which can utilize wavefield extrapolation logic matches that are used by reverse-time migration (RTM).', 'A model may be specified on a dense 3D grid as velocity and optionally as anisotropy, dip, and variable density.', 'As shown in \nFIG.', '14\n, the computational framework \n1400\n includes features for RTM, FDMOD, adaptive beam migration (ABM), Gaussian packet migration (GPM), depth processing (e.g., Kirchhoff prestack depth migration (KPSDM), tomography (Tomo)), time processing (e.g., Kirchhoff prestack time migration (KPSTM), general surface multiple prediction (GSMP), extended interbed multiple prediction (XIMP)), framework foundation features, desktop features (e.g., GUIs, etc.), and development tools.', 'As an example, the computational framework \n1400\n can include a GAN-based feature or features.', 'For example, consider a GAN-based component for processing seismic data to attenuate noise, increase resolution via interpolation, etc.\n \nFIG.', '15\n shows an example of a method \n1500\n that includes a data generation block \n1510\n for generating data, a training block \n1520\n for training a generator via use of a discriminator and a generator where a competitive process can train the generator to output a trained generator, and a data processing block \n1530\n for processing seismic data utilizing the trained generator to output processed seismic data, which can include one or more of signal and noise.', 'As to the data generation block \n1510\n, as an example, such data may be generated by a generator.', 'As an example, generated data may be generated that is synthetic using a numerical technique that involves modeling.', 'For example, consider using a finite difference method to generate synthetic data (e.g., consider the FDMOD of the OMEGA framework).', 'As an example, data can be model-based data that is synthetic and/or augmented real data as augmented at least in part with synthetic data.', 'As an example, the TENSORFLOW framework may be utilized for network operations (see, e.g., Equations (1), (2), (3), (4), (5), \nFIG.', '7\n, \nFIG.', '8\n, \nFIG.', '12\n, etc.).', 'As an example, the method \n1500\n can include the generation block \n1510\n for generating seismic data; the training block \n1520\n for training a generator network utilizing at least a portion of the generated seismic data and a discriminator network; and the output block \n1530\n for outputting a trained generator network.', 'As an example, such a method can include using the trained generator network to process seismic data, for example, to attenuate noise in seismic data, to interpolate seismic data, etc.', 'As an example, a method can include utilizing a trained generator network to stylize seismic data, for example, to generate seismic data in a “noise attenuated style”.', 'As an example, a method can include generating seismic data using a generator network and training that includes receiving synthetic seismic data and the generated seismic data by a discriminator network.', 'As an example, a method can include generating seismic data using a generator network and training that includes receiving acquired seismic data of a survey and the generated seismic data by a discriminator network.', 'In such an example, the acquired seismic data of the survey can be characterized by a level of signal to noise (e.g., an average SNR, a local SNR, etc.)', 'and/or', 'the acquired seismic data of the survey can be noise attenuated seismic data.', 'The method \n1500\n is shown in \nFIG.', '15\n in association with various computer-readable media (CRM) blocks \n1511\n, \n1521\n, and \n1531\n.', 'Such blocks generally include instructions suitable for execution by one or more processors (or cores) to instruct a computing device or system to perform one or more actions.', 'While various blocks are shown, a single medium may be configured with instructions to allow for, at least in part, performance of various actions of the method \n1500\n.', 'As an example, a CRM block can be a computer-readable storage medium that is non-transitory, not a carrier wave and not a signal.', 'As an example, such blocks can include instructions that can be stored in memory and can be executable by one or more of processors.', 'As an example, a method such as the method \n1500\n of \nFIG.', '15\n may be implemented as part of a framework such as the OMEGA framework.', 'As an example, a computation framework can include features that can access a trained generator network, access seismic data and process at least a portion of the seismic data utilizing the trained generator network to output processed data.', 'As an example, a method can include accessing a trained generator network, as trained via generated seismic data and a discriminator network; receiving seismic data of a survey of a geologic environment; and processing at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'As an example, such a method can include accessing a trained generator network as, for example, output by the method \n1500\n of \nFIG.', '15\n.', 'As an example, a computer-implemented method of training a generator network for seismic signal detection can include generating seismic data, training a generator network utilizing at least a portion of the generated seismic data and a discriminator network; and outputting a trained generator network.', 'As explained, a discriminator network can be utilized for learning of a distribution such that a generator network can output seismic data that are more “real” (e.g., noise attenuated, higher signal to noise ratio, etc.).', 'As an example, a trained generator network may be utilized for one or more purposes, which can include generating signal and/or generating noise and, for example, identifying signal and/or identifying noise.', 'As an example, synthetic seismic data may be utilized where a seismic signal to noise ratio is zero.', 'As an example, seismic data may be utilized where a seismic signal to noise ratio is non-zero.', 'In such an example, noise can include a type of seismic signal acquisition noise.', 'As an example, synthetic seismic data can be generated using a numerical computational technique such as, for example, a finite difference technique, a finite element technique, etc.', 'As an example, a method can include interpolating seismic data, which can provide for enhanced seismic data (e.g., with respect to an acquisition geometry, an acquisition process, etc.).', 'As an example, seismic image data can be pixel image data corresponding to an acquisition geometry of acquisition equipment and a discriminator can be utilized to operate at a sub-pixel level.', 'As an example, a method can implement a GAN-based approach for analysis of noise, for example, for conditions under which data were acquired.', 'As an example, such noise can inform an operator or operators as to how acquisition can be improved (e.g., via geometry, via processing, via equipment, etc.).', 'For example, consider an analysis that indicates that a vessel with streamers can reduce noise or otherwise improve a signal to noise ratio by directing the vessel in a certain manner with respect to waves, currents, etc.', 'As an example, a method can include training a GAN-based network and/or utilizing a trained GAN-based network for seismic data analysis.', 'As an example, such a method may include training using raw seismic data and/or performing an analysis on raw seismic data.', 'Such a method may aim to assess signal as corresponding to physics underlying seismic imaging; rather than aiming to identify a particular structure or object.', 'For example, consider a method that aims to generate seismic data that looks like seismic signals without noise.', 'Such an approach can be a starting point for interpretation of the seismic data to determine/identify structures.', 'For example, a method can provide for enhancing seismic data without “knowing” what structures in the Earth have been imaged or to which structures in the Earth the seismic data pertain.', 'As an example, a method can be implemented in an “object agnostic” manner.', 'As an example, a method may aim to understand what a seismic signal “looks like” and/or what noise “looks like”; rather than what a real world object “looks like”.', 'As an example, a trained network may be utilized for one or more tasks.', 'For example, consider one or more of deghosting and demultiplying seismic data.', 'In such examples, ghosts may be attenuated and/or multiples may be attenuated.', 'As an example, information may be included in ghosts and/or multiples that can be analyzed for one or more purposes.', 'As mentioned, a method can be utilized for quality control and issue identification, which may pertain to one or more aspects of how a survey is performed and/or equipment utilized in performance of a survey.', 'As mentioned, noise output from a computing system can provide information as to cable integrity (e.g., identification of a damaged fin, a damaged cable, etc.).', 'As an example, a workflow can include determining one or more petrophysical properties of rocks.', 'As an example, a workflow can include reducing noise from one or more imaging techniques that are based at least in part on seismic survey data that includes multiple source data.', 'As an example, one or more survey designs can be modelled to ensure quality of a seismic survey.', 'Such an approach can provide for evaluating how well a target zone will be illuminated.', 'A computational framework may include one or more features of the SIMSOURCE framework.', 'As an example, computational frameworks may be integrated, operatively coupled, etc.', 'As an example, one or more computational frameworks may be implemented to perform at least a portion of the method \n1500\n of \nFIG.', '15\n.', 'As an example, data can include streamer data that includes data acquired during a turn in a data acquisition path of a vessel.', 'As an example, a vessel and/or a truck may include computer equipment for implementation of a method such as the method \n1500\n (e.g., or a part thereof) where such a vessel and/or a truck can acquire seismic data.', 'As an example, a survey may be a multi-, wide-, or full-azimuth survey.', 'As an example, a survey may be a steamer survey and/or a seabed survey, which may include one or more of ocean-bottom node (OBN) and ocean-bottom cable (OBC).', 'As an example, a method can include generating seismic data; training a generator network utilizing at least a portion of the generated seismic data and a discriminator network; and outputting a trained generator network.', 'Such a method can include acquiring seismic data of a survey of a geologic environment and processing at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'In such an example, the survey can be or include a marine survey.', 'As an example, a marine survey can include a survey path that includes at least one turn.', 'As an example, processed data can be or include noise attenuated signal data.', 'In such an example, a method can include identifying at least one structural feature of a geologic environment based at least in part on the noise attenuated signal data.', 'As an example, processed data can be or include noise data.', 'In such an example, a method can include identifying at least one cause of noise based at least in part on the noise data.', 'As an example, a method can include attenuating noise in seismic data utilizing a trained generator network.', 'As an example, a method can include performing trace interpolation utilizing the trained generator network.', 'As an example, a method can include utilizing a Wasserstein loss function to reduce risk of mode collapse of a generator network.', 'In such an example, the Wasserstein loss function can include a gradient penalty.', 'As an example, a discriminator network and a generator network can be components of a generative adversarial network-based architecture.', 'As an example, generating seismic data can include generating synthetic seismic data.', 'A system can include a processor; memory operatively coupled to the processor; and processor-executable instructions stored in the memory to instruct the system to: generate seismic data; train a generator network utilizing at least a portion of the generated seismic data and a discriminator network; and output a trained generator network.', 'In such an example, instructions can be included to acquire seismic data of a survey of a geologic environment and to process at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'As an example, a system can include a processor; memory operatively coupled to the processor; and processor-executable instructions stored in the memory to instruct the system to: access a trained generator network, as trained via generated seismic data and a discriminator network; receive seismic data of a survey of a geologic environment; and process at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'In such an example, the system can be part of a survey vessel.', 'As an example, a system can include at least one interface that is operatively coupled to one or more sensors that acquire seismic data.', 'As an example, a system can include instructions to compress generated processed data and transmit compressed generated processed data.', 'As an example, one or more computer-readable storage media can include processor-executable instructions to instruct a computing system to: access a trained generator network, as trained via generated seismic data and a discriminator network; receive seismic data of a survey of a geologic environment; and process at least a portion of the seismic data utilizing the trained generator network to generate processed data.', 'As an example, a computing system can be a generative adversarial network seismic data processor.', 'As an example, a system may include one or more modules, which may be provided to analyze data, control a process, perform a task, perform a workstep, perform a workflow, etc.\n \nFIG.', '16\n shows components of an example of a computing system \n1600\n and an example of a networked system \n1610\n, which may be utilized to perform a method, to form a specialized system, etc.', 'The system \n1600\n includes one or more processors \n1602\n, memory and/or storage components \n1604\n, one or more input and/or output devices \n1606\n and a bus \n1608\n.', 'In an example embodiment, instructions may be stored in one or more computer-readable media (e.g., memory/storage components \n1604\n).', 'Such instructions may be read by one or more processors (e.g., the processor(s) \n1602\n) via a communication bus (e.g., the bus \n1608\n), which may be wired or wireless.', 'The one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g., as part of a method).', 'A user may view output from and interact with a process via an I/O device (e.g., the device \n1606\n).', 'In an example embodiment, a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc. (e.g., a computer-readable storage medium).', 'In an example embodiment, components may be distributed, such as in the network system \n1610\n.', 'The network system \n1610\n includes components \n1622\n-\n1\n, \n1622\n-\n2\n, \n1622\n-\n3\n, . . .', '1622\n-N.', 'For example, the components \n1622\n-\n1\n may include the processor(s) \n1502\n while the component(s) \n1622\n-\n3\n may include memory accessible by the processor(s) \n1602\n.', 'Further, the component(s) \n1602\n-\n2\n may include an I/O device for display and optionally interaction with a method.', 'The network may be or include the Internet, an intranet, a cellular network, a satellite network, etc.', 'As an example, a device may be a mobile device that includes one or more network interfaces for communication of information.', 'For example, a mobile device may include a wireless network interface (e.g., operable via IEEE 802.11, ETSI GSM, BLUETOOTH, satellite, etc.).', 'As an example, a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio/video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery.', 'As an example, a mobile device may be configured as a cell phone, a tablet, etc.', 'As an example, a method may be implemented (e.g., wholly or in part) using a mobile device.', 'As an example, a system may include one or more mobile devices.', 'As an example, a system may be a distributed environment, for example, a so-called “cloud” environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc.', 'As an example, a device or a system may include one or more components for communication of information via one or more of the Internet (e.g., where communication occurs via one or more Internet protocols), a cellular network, a satellite network, etc.', 'As an example, a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).', 'As an example, information may be input from a display (e.g., consider a touchscreen), output to a display or both.', 'As an example, information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed.', 'As an example, information may be output stereographically or holographically.', 'As to a printer, consider a 2D or a 3D printer.', 'As an example, a 3D printer may include one or more substances that can be output to construct a 3D object.', 'For example, data may be provided to a 3D printer to construct a 3D representation of a subterranean formation.', 'As an example, layers may be constructed in 3D (e.g., horizons, etc.), geobodies constructed in 3D, etc.', 'As an example, holes, fractures, etc., may be constructed in 3D (e.g., as positive structures, as negative structures, etc.).', 'Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” together with an associated function.', 'BIBLIOGRAPHY\n \nThe following documents are incorporated by reference herein.', 'Gatys et al.', '(2015), “A Neural Algorithm of Artistic Style,” arXiv:1508.06576.', 'Goodfellow et al.', '(2014), “Generative Adversarial Networks,” arXiv:1406.2661.', 'He et al.', '(2015), “Deep Residual Learning for Image Recognition,” arXiv:1512.03385.', 'Gulrajani et al. (2017), “Improved Training of Wasserstein GANs”, arXiv:1704.00028.', 'Isola et al. (2016), “Image-to-Image Translation with Conditional Adversarial Networks,” arXiv:1611.07004.', 'LeCun, “Session with Yann LeCun.”', 'Quora—A place to share knowledge and better understand the world”, 28 Jul. 2016 (accessed 13 Feb. 2018).', 'Ledig et al. (2017), “Photo-Realistic Single Image Super-Resolution Using a Generative Adversarial Network,” arXiv:1609.04802.', 'Arjovsky et al. (2017), “Wasserstein GAN,” arXiv:1701.07875.', 'Radford et al. (2015), “Unsupervised Representation Learning with Deep Convolutional Generative Adversarial Networks,” arXiv:1511.06434v2.', 'Ronneberger et al. (2015), “U-Net: Convolutional Networks for Biomedical Image Segmentation,” arXiv:1505.04597.', 'Shi et al. (2016), “Real-Time Single Image and Video Super-Resolution Using an Efficient Sub-Pixel Convolutional Neural Network,” arXiv:1609.05158.', 'Yang et al.', '(2018), “Application of optimal transport and the quadratic Wasserstein metric to full-waveform inversion,” GEOPHYSICS, 83(1),', 'R43-R62.\n \nZhu et al., “Unpaired Image-to-Image Translation using Cycle-Consistent Adversarial Networks,” arXiv:1703.10593v6 [cs.CV], https://arxiv.org/abs/1703.10593 (submitted on 30 Mar. 2017 (v1), revised 15 Nov. 2018 (v6)).'] | ['1.', 'A method comprising:\ngenerating seismic data, wherein generating seismic data comprises generating seismic data using a generator network;\ntraining the generator network utilizing at least a portion of the generated seismic data and a discriminator network, wherein training comprises receiving synthetic seismic data and the generated seismic data by the discriminator network; and\noutputting a trained generator network.', '2.', 'The method of claim 1 comprising acquiring seismic data of a survey of a geologic environment and processing at least a portion of the seismic data utilizing the trained generator network to generate processed data.', '3.', 'The method of claim 2 wherein the survey comprises a marine survey.', '4.', 'The method of claim 3 wherein the marine survey comprises a survey path that includes at least one turn.', '5.', 'The method of claim 2 wherein the processed data comprise noise attenuated signal data.', '6.', 'The method of claim 5 comprising identifying at least one structural feature of the geologic environment based at least in part on the noise attenuated signal data.', '7.', 'The method of claim 2 wherein the processed data comprise noise data.', '8.', 'The method of claim 7 comprising identifying at least one cause of noise based at least in part on the noise data.', '9.', 'The method of claim 1 wherein training comprises receiving acquired seismic data of a survey.', '10.', 'The method of claim 9 wherein the acquired seismic data of the survey comprises a level of signal to noise.', '11.', 'The method of claim 9 wherein the acquired seismic data of the survey comprises noise attenuated seismic data.\n\n\n\n\n\n\n12.', 'The method of claim 1 comprising utilizing a Wasserstein loss function to reduce risk of mode collapse of the generator network.', '13.', 'The method of claim 12 wherein the Wasserstein loss function comprises a gradient penalty.', '14.', 'The method of claim 1 further comprising attenuating noise in seismic data utilizing the trained generator network.', '15.', 'The method of claim 1 further comprising performing trace interpolation utilizing the trained generator network.', '16.', 'The method of claim 1 wherein the discriminator network and the generator network comprise components of a generative adversarial network-based architecture.', '17.', 'The method of claim 1 wherein the discriminator network and the generator network comprise components of a cyclic generative adversarial network-based architecture.', '18.', 'A system comprising:\na processor;\nmemory operatively coupled to the processor; and\nprocessor-executable instructions stored in the memory to instruct the system to: generate seismic data, wherein to generate seismic data comprises generation of seismic data using a generator network; train the generator network utilizing at least a portion of the generated seismic data and a discriminator network, wherein to train comprises reception of synthetic seismic data and the generated seismic data by the discriminator network; and output a trained generator network.', '19.', 'One or more computer-readable storage media comprising processor-executable instructions to instruct a computing system to:\ngenerate seismic data, wherein to generate seismic data comprises generation of seismic data using a generator network;\ntrain the generator network utilizing at least a portion of the generated seismic data and a discriminator network, wherein to train comprises reception of synthetic seismic data and the generated seismic data by the discriminator network; and\noutput a trained generator network.', '20.', 'A method comprising:\ngenerating seismic data;\ntraining a generator network utilizing at least a portion of the generated seismic data and a discriminator network;\noutputting a trained generator network; and\nperforming trace interpolation utilizing the trained generator network.\n\n\n\n\n\n\n21.', 'A method comprising:\ngenerating seismic data;\ntraining a generator network utilizing at least a portion of the generated seismic data and a discriminator network;\noutputting a trained generator network;\nacquiring seismic data of a survey of a geologic environment and processing at least a portion of the seismic data utilizing the trained generator network to generate processed data, wherein the processed data comprise noise attenuated signal data; and\nidentifying at least one structural feature of the geologic environment based at least in part on the noise attenuated signal data.'] | ['FIG. 1 illustrates an example of a geologic environment and an example of a technique;; FIG.', '2 illustrates an example of a geologic environment and examples of equipment;; FIG.', '3 illustrates an example of a geologic environment, examples of equipment and an example of a method;; FIG.', '4 illustrates an example of a geologic environment and examples of equipment;; FIG.', '5 illustrates an example of a geologic environment, an example of a method, examples of equipment and examples of data;; FIG.', '6', 'illustrates examples of plots;; FIG. 7 illustrates examples of network architectures and processes;; FIG. 8 illustrates examples of network architectures and processes;; FIG. 9 illustrates examples of plots;; FIG.', '10 illustrates an example of an architecture of a framework;; FIG.', '11 illustrates examples of plots;; FIG.', '12 illustrates examples of graphics of a cycle generative adversarial network (cycle-GAN);; FIG. 13 illustrates examples of plots;; FIG.', '14 illustrates an example of a computational framework;; FIG.', '15 illustrates an example of a method; and; FIG.', '16 illustrates example components of a system and a networked system.; FIGS.', '1, 2, 3, 4 and 5 present various examples of equipment and techniques associated with seismic data.', 'One or more of the examples may be utilized in conjunction with one or more GANs.', 'As an example, a computing system may utilize one or more GANs to handle noise, for example, for purposes of attenuation and/or for purposes of diagnosis and one or more actions responsive to one or more diagnoses.; FIG.', '1 shows an example of a geologic environment 150 (e.g., an environment that includes a sedimentary basin, a reservoir 151, one or more fractures 153, etc.) and an example of an acquisition technique 170 to acquire seismic data.', 'As an example, a system may process data acquired by the technique 170, for example, to allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment 150.', 'In turn, further information about the geologic environment 150 may become available as feedback (e.g., optionally as input to the system).', '; FIG. 1 also shows the geologic environment 150 as optionally including equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop the reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment 157 and/or 158 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.; FIG. 1 also shows various types of waves as including P, SV an SH waves.', 'As an example, a P-wave may be an elastic body wave or sound wave in which particles oscillate in the direction the wave propagates.', 'As an example, P-waves incident on an interface (e.g., at other than normal incidence, etc.) may produce reflected and transmitted S-waves (e.g., “converted” waves).', 'As an example, an S-wave or shear wave may be an elastic body wave, for example, in which particles oscillate perpendicular to the direction in which the wave propagates.', 'S-waves may be generated by a seismic energy sources (e.g., other than an air gun).', 'As an example, S-waves may be converted to P-waves.', 'S-waves tend to travel more slowly than P-waves and do not travel through fluids that do not support shear.', 'In general, recording of S-waves involves use of one or more receivers operatively coupled to earth (e.g., capable of receiving shear forces with respect to time).', "As an example, interpretation of S-waves may allow for determination of rock properties such as fracture density and orientation, Poisson's ratio and rock type, for example, by crossplotting P-wave and S-wave velocities, and/or by other techniques.; FIG.", '2 shows an example of a geologic environment 201 that includes a seabed 203 and a sea surface 205.', 'As shown, equipment 210 such as a ship may tow an energy source 220 and a string of sensors 230 at a depth below the sea surface 205 (e.g., one or more streamers, etc.).', 'In such an example, the energy source 220 may emit energy at a time T0, a portion of that energy may be reflected from the seabed 203 at a time T1 and a portion of that reflected energy may be received at the string of sensors 230 at a time T2.; FIG.', '3 illustrates a schematic diagram of an example of a marine-based seismic acquisition system 310 and an example of a method 390.', 'In the system 310, a survey vessel 320 may tow one or more seismic streamers 330 behind the vessel 320.', 'As an example, streamers 330 may be arranged in a spread in which multiple streamers 330 are towed in approximately a plane at a depth.', 'As an example, streamers may be towed at multiple depths (e.g., consider an over/under configuration).', '; FIG.', '4 shows an example plot 400 of quality versus acquisition turnaround time.', 'For example, consider a simultaneous seismic source acquisition and processing technique that may allow for an improvement in quality for a standard turnaround time or a reduced turnaround time that may aim to achieve a quality level of a sequential technique (e.g., which would take a longer time).', 'In FIG. 4, a dashed curve corresponds to a single source firing at a time approach while a solid curve corresponds to a simultaneous source firing at a time approach.', 'As illustrated, time may be shortened (see, e.g., Δt) and/or quality may be improved (see, e.g., Δq).', 'As mentioned, interference may occur in one or more types of surveys.; FIG.', '4 also shows a series of images 410 for shots where a shot is an emission from a source.', 'In the example, a pair of guns in a four-boat configuration fired sources (shots or emissions) in an acquisition time window.', 'The left image demonstrates the presence of two water-bottom reflections where an upper reflection is associated with source 2.', 'The center and right images show the shot record on the left after source separation where the center image corresponds to source 1 and the right image corresponds to source 2.', 'Such a process is referred to as “source separation”.; FIG.', '5 shows a geologic environment 501 (lower left), equipment 510, a plot 515 of a frequency sweep as generated by the equipment 510 (e.g., with start and end times), downgoing energy 517 of the frequency sweep, upgoing energy 519 of the frequency sweep, and a sensor 520 (a node as in an array or grid).', 'While FIG. 5 is shown as a land-based survey, various features, actions, etc., may be applied in a marine survey where seabed sensors are employed (see the marine-based survey 380 of FIG. 3).; FIG.', '6 shows example plots 610 and 630 that are results output by a computing system that implements one or more Generative Adversarial Noise Attenuation Networks (GANANs) for noise attenuation.', 'In the plots of FIG.', '6, the plot 610 is an input shot that is received as seismic data that are passed through a trained network of the computing system to generate the processed seismic data of the plot 630.', 'As shown in the examples of FIG.', '6, kinematics of the input shot are maintained, but the swell noise in the near channels is attenuated, along with artifacts at farther offsets.', 'In this example, the GANAN works as a strong dip filter, operating with some knowledge of the kinematics of a seismic shot record.;', 'FIG.', '7 shows example graphics 701, 705, 710 and 730 of an architecture of a computational framework that can be utilized for processing seismic data.', 'The graphic 701 shows a discriminator network 702 and a generator network 704, which can be neural networks.', 'The discriminator network 702 can operate using a training set and the generator network 704 can operate using random noise where a distribution may be chosen from random noise.', 'For example, the generator network 704 can take a vector as input and return an image.', 'The generator network 704 may be represented by a function “G”.', 'The discriminator network 702, which may be represented by a function “D” can take an image as input and returns a probability that the image was sampled from an (unknown) probability distribution of data.', 'As shown, the discriminator network 702 can output a label or classification (e.g., “real”, “fake”, OK, NOK, etc.).', '; FIG.', '8 shows an example of an architecture 800 of a network that includes skip connections within each block of layers to pass features down the network.', 'As an example, a network may include one or more skip connections.; FIG.', '9 shows a series of plots 910, 920, 930, 940, 950 and 960.', 'In FIG.', '9, GATIN results, from top to bottom, include a decimated shot, interpolated with GATIN, and the original undecimated shot.', 'The perceptual quality of the interpolation is quite high, including desired effects such as the complex diffraction and undesired effects such as interpolation of noise in the input data.', 'By taking the data to FK space, it is possible to demonstrate that the interpolation is able to recover spatial wavelengths that are lost in the original downsampling.', 'As mentioned, a workflow may optionally include one or more transforms as to one or more domains.', 'In such an example, a network or networks may be utilized (e.g., GAN, GANAN, GATIN, etc.).', '; FIG.', '10 shows an architecture 1000 of a framework such as the TENSORFLOW framework.', 'As shown, the architecture 1000 includes various features.', 'As an example, in the terminology of the architecture 1000, a client can define a computation as a dataflow graph and, for example, can initiate graph execution using a session.', 'As an example, a distributed master can prune a specific subgraph from the graph, as defined by the arguments to “Session.run( )”; partition the subgraph into multiple pieces that run in different processes and devices; distributes the graph pieces to worker services; and initiate graph piece execution by worker services.', 'As to worker services (e.g., one per task), as an example, they may schedule the execution of graph operations using kernel implementations appropriate to hardware available (CPUs, GPUs, etc.)', 'and, for example, send and receive operation results to and from other worker services.', 'As to kernel implementations, these may, for example, perform computations for individual graph operations.', '; FIG.', '11 shows example plots 1110, 1120, 1130 and 1140.', 'As an example, forms of mode collapse may occur building GANAN.', 'In FIG.', '11, the plots 1110 and 1120 show input shots while the plots 1130 and 1140 show GANAN output.', 'In the plots 1110 and 1130, a generator is unable to come up with useful filters and outputs random noise for input; whereas, in the plots 1120 and 1140, the generator is able to find filters that capture some high-level information that can “fool” a discriminator; however, the resultant data can be rendered to a display, for example, for human review where it can be seen as noise.', 'As an example, a method can include using a Wasserstein loss function in one or more of a discriminator network and a generator network.', 'Such an approach can help to overcome mode collapse for these networks.; FIG.', '12 shows graphical examples of models and associated operations 1210, 1220 and 1230.', 'As shown in the graphic 1210, a model can include two mapping functions G: X→Y and F: Y→X and associated discriminators Dy and Dx where Dy encourages G to translate X into outputs indistinguishable from domain Y, and vice versa for Dx and F. To further regularize the mapping, two cycle consistency losses can be introduced that capture the intuition that for translations from one domain to the other and back again, the translations can be expected to return to the starting point.', 'The graphic 1220 shows a forward cycle-consistency loss (x→G(x)→F(G(x))˜x) and the graphic 1230 shows a backward cycle-consistency loss (y→F(y)→G(F(y))˜y).', 'An article by Zhu et al., “Unpaired Image-to-Image Translation using Cycle-Consistent Adversarial Networks”, arXiv:1703.10593v6 [cs.CV], https://arxiv.org/abs/1703.10593 (submitted on 30 Mar. 2017 (v1), revised 15 Nov. 2018 (v6)), is incorporated by reference herein.; FIG.', '13 shows examples of images 1310, 1320, 1330 and 1340 where the images 1310 and 1320 correspond to noisy and clean, respectively, and where the images 1330 and 1340 correspond to clean and noisy, respectively.', 'The images 1310, 1320, 1330 and 1340 demonstrate a use of a GANAN framework in a cycle-GAN approach.', 'Using data that had been identified as clean and noisy, a network was trained to convert one to the other.', 'Such an approach may be utilized with or without synthetic data.', 'As an example, synthetic data with and/or without noise may be utilized.', 'As an example, a GANAN trained using synthetic data may be utilized to supplement training.', 'As an example, a method can utilize labeled data that can include real and/or synthetic data.; FIG.', '14 shows an example of a computational framework 1400 that can include one or more processors and memory, as well as, for example, one or more interfaces.', 'The computational framework of FIG.', '14 can include one or more features of the OMEGA framework (Schlumberger Limited, Houston, Tex.), which includes finite difference modelling (FDMOD) features for two-way wavefield extrapolation modelling, generating synthetic shot gathers with and without multiples.', 'The FDMOD features can generate synthetic shot gathers by using full 3D, two-way wavefield extrapolation modelling, which can utilize wavefield extrapolation logic matches that are used by reverse-time migration (RTM).', 'A model may be specified on a dense 3D grid as velocity and optionally as anisotropy, dip, and variable density.; FIG.', '15 shows an example of a method 1500 that includes a data generation block 1510 for generating data, a training block 1520 for training a generator via use of a discriminator and a generator where a competitive process can train the generator to output a trained generator, and a data processing block 1530 for processing seismic data utilizing the trained generator to output processed seismic data, which can include one or more of signal and noise.; FIG.', '16 shows components of an example of a computing system 1600 and an example of a networked system 1610, which may be utilized to perform a method, to form a specialized system, etc.', 'The system 1600 includes one or more processors 1602, memory and/or storage components 1604, one or more input and/or output devices 1606 and a bus 1608.', 'In an example embodiment, instructions may be stored in one or more computer-readable media (e.g., memory/storage components 1604).', 'Such instructions may be read by one or more processors (e.g., the processor(s) 1602) via a communication bus (e.g., the bus 1608), which may be wired or wireless.', 'The one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g., as part of a method).', 'A user may view output from and interact with a process via an I/O device (e.g., the device 1606).', 'In an example embodiment, a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc. (e.g., a computer-readable storage medium).'] |
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US11105670 | Method for estimating a flow out of a fluid pump, associated calculation system and associated drilling installation | Sep 14, 2016 | Florian Le Blay, Aurore Lafond, Nicolas Elie | SCHLUMBERGER TECHNOLOGY CORPORATION | Schafer et al., “An Evaluation of Flowmeters for the Detection of Kicks and Lost Circulation During Drilling”, IADC/SPE 1992 Drilling Conference held in New Orleans. Louisiana, Feb. 18-21, 1992 (Year: 1992).; Cayeux et al., “Toward Drilling Automation: On the Necessity of Using Sensors That Relate to Physical Models”, SPE/IADC Drilling Conference and Exhibition, Amsterdam, Mar. 5-7, 2013, Revised manuscript received for review Oct. 24, 2013. Paper peer approved Jan. 30, 2014. (Year: 2014).; Schafer et al., An Evaluation of Flowmeters for the Detection of Kicks and Lost Circulation During Drilling, IADC/SPE 1992 Drilling Conference (Year: 1992).; Gerhard Vetter et al., “Pressure Pulsation Dampening Methods for Reciprocating Pumps”, Proceedings of the Tenth International Pump Users Symposium, Jan. 1, 1993, pp. 25-39.; Stephen M. Price et al., “The effects of valve dynamics on reciprocating pump reliability”, Prceedings of the Twelfth International Pump Users Symposium, Jan. 1, 1995, (10 pages).; John E. Purcell et al., “A Comparison of Positive displacement and centrifugal pump applications”, Proceedings of the 14th international pump users symposium, Jan. 1, 1997, pp. 99-104.; International Search Report and Written Opinion issued in the related PCT application PCT/EP2016/001541, dated Dec. 22, 2016 (14 pages).; Extended Search Report issued in the related EP application 15290233.4, dated Mar. 7, 2016 (11 pages).; International Preliminary Report on Patentability issued in the related PCT application PCT/EP2016/001541, dated Mar. 29, 2018 (9 pages). | 3602322; August 1971; Gorsuch; 8249826; August 21, 2012; Anderson; 20130220600; August 29, 2013; Bakri; 20130298696; November 14, 2013; Singfield | WO2014204316; December 2014; WO | ['The disclosure relates to a method for estimating a flow out of at least one fluid pump for injecting fluid in a well, comprising: —determining a calculation model for the flow rate of a pump exiting the at least one pump, said calculation model permitting the calculation of the flow rate in function of at least one calculation parameter (p, SPAM) related to the at least one fluid pump; then —providing at a plurality of measuring times (tm), a set of measurement values (PDH,m, PB,m, SPMDH,m, SPMB,m) representative of said at least one calculation parameter; then —estimating (86) the flow rate exiting the pump in function of the model and of said at least one calculation parameter.'] | ['Description\n\n\n\n\n\n\nThe present disclosure concerns a method for estimating a flow out of a fluid pump, especially of a drilling fluid pump of a drilling installation.', 'BACKGROUND\n \nWhen drilling an oil well or a well for another effluent (in particular gas or water), it is required to accurately monitor the flow of displaced drilling fluids or muds.', 'The drilling fluids are mainly displaced using three-piston pumps, also known as high pressure triplex pumps, or using six-piston pumps also known as hex pumps.', 'Due to the high-pressure constraints and to the properties of the drilling fluid, few flow meter types can be used to accurately measure the flow rate of such pumps.', 'Moreover, such flow meters require heavy modification of the drilling rig circulation system.', 'It is known to calculate the volume flow rate generated by such pump on drilling rigs, considered as the flow rate injected in the drilling rig, by using the geometrical parameters of the pump (liner size, liner displacement) and a constant efficiency determined during efficiency test or assumed when no test result is available.', 'The flow rate injected in the drilling rig is an important parameter of the rig.', 'SUMMARY OF THE DISCLOSURE\n \nAn object of the present disclosure is to provide a method for estimating a real-time flow out of a fluid pump, including a variable pump efficiency.', 'To this end, the present disclosure relates to a method of the aforementioned type, comprising: determining a calculation model for the flow rate of a pump exiting the at least one pump, said calculation model permitting the calculation of the flow rate in function of at least one calculation parameter related to the at least one fluid pump; then providing at a plurality of measuring times, a set of measurement values representative of said at least one calculation parameter; then estimating the flow rate exiting the pump in function of the model and of said at least one calculation parameter.', 'According to advantageous embodiments, the method comprises one or more of the following features, taken in isolation or in any technically possible combination(s): \n \n \n \nthe at least one calculation parameter is chosen among a fluid pressure at an outlet of the pump and a number of cycles of the pump per time unit;\n \nthe calculation model is a physical model such as an isothermal or adiabatic model, or an approximate mathematical model such as a 2\nnd\n-degree polynomial function;\n \nthe fluid pump is a reciprocating pump;\n \nthe method comprises, after the determination of the calculation model, a calibration procedure, including: providing, at a plurality of measuring times, a set of measurement values representative of at least one calibration parameter related to the at least one fluid pump, and then on the basis of said set of measurement values, calculating constant values of the calculation model.', 'The constant values may be coefficients relative to the fluid, such as compressibility, or pump characteristics, such as geometrical volumes\n \nthe at least one calibration parameter is representative of a flow rate measured at the exit of the wellbore;\n \nthe calibration parameters comprise a calibration parameter representative of a fluid density, and/or a calibration parameter representative of a fluid pressure at an outlet of the pump and/or a calibration parameter representative of a number of cycles of the pump per time unit;\n \nthe calibration procedure is performed in cased hole and when the at least one pump is in a stationary state;\n \nthe calibration parameters comprise at least one of the following: a mean flow rate during a predetermined time period, a mean fluid density during a predetermined time period, a mean fluid pressure at an outlet of the pump during a predetermined time period, and a mean number of cycles of the pump per time unit during a predetermined time period;\n \nthe method comprises determining, on the basis of the estimated flow rate at the exit of the pumps and of a flow rate measured at the exit of the wellbore, if there is a kick or a loss in the wellbore;\n \nthe estimation of the flow rate out of the pump is a real-time estimation.', 'The present disclosure also relates to a calculation system comprising a processing unit in interaction with a software application for the implementation of the method described above.', 'The present disclosure also relates to a drilling installation comprising: at least one fluid pump injecting fluid in the wellbore; a measurement unit for providing fluid measurement values representative of the pump, said measurement unit comprising at least one sensor able to measure at least one calculation parameter related to the pump; and a calculation system as described above.', 'According to advantageous embodiments, the drilling installation comprises one or more of the following features, taken in isolation or in any technically possible combination(s): \n \n \n \nthe at least one sensor comprise a pressure sensor and/or a SPM sensor;\n \nthe drilling installation comprises a discharge pipe at the exit of the wellbore, wherein the drilling installation comprises an additional measurement unit comprising a flow meter installation in the discharge pipe for measuring the fluid flow rate exiting the wellbore;\n \nthe drilling installation comprises a flow meter installation, said flow meter installation including a by-pass pipe tapped in a discharge pipe, and a flow meter, in particular a Coriolis flow meter, arranged in the by-pass pipe;\n \nthe drilling installation comprises at least two fluid pumps, said at least two fluid pumps forming a first group and a second group of at least one fluid pump, said first group being characterized by a first outlet pressure and said second group being characterized by a second outlet pressure;\n \nthe drilling installation comprises at least two pressure sensors respectively situated at the outlet of first group of pumps and second group of pumps able to measure the first outlet pressure and second outlet pressure respectively.', 'The present disclosure will be better understood upon reading the following description, which is given solely by way of example, and which is written with reference to the appended drawings, in which:\n \nFIG.', '1\n is a schematic view, in vertical section, of a drilling installation according to an embodiment of the present disclosure;\n \nFIG.', '2\n is a schematic view, in vertical section, of a drilling installation according to another embodiment of the present disclosure;\n \nFIG.', '3\n is an organization chart of a method according to the an embodiment of the disclosure;\n \nFIG.', '4\n is a schematic view of a single-piston pump according to the state of the art;\n \nFIG.', '5\n is a pressure/volume diagram of the single-piston pump of \nFIG.', '4\n;\n \n \nDETAILED DESCRIPTION\n \nOne or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, some features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions may be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would still be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'In the following description, the term “downstream” is understood with respect to the normal direction of circulation of a fluid in a pipe.', 'Drilling installations \n11\n for a fluid production well, such as a hydrocarbon production well, are illustrated on \nFIG.', '1\n and \nFIG.', '2\n.', 'In the following disclosure, the same elements of the embodiments of \nFIGS.', '1 and 2\n are designated by the same reference numbers.', 'The drilling installation \n11\n of \nFIG.', '1\n or \nFIG.', '2\n comprises a drilling pipe \n13\n arranged in a cavity \n14\n bored by a rotary drilling tool \n15\n, and a surface installation \n17\n.', 'The drilling installation \n11\n also comprises a measurement unit \n19\n and a calculation system \n20\n (not shown on \nFIG.', '2\n).', 'The drilling pipe \n13\n is arranged in the cavity \n14\n formed in the earth formation \n21\n by the rotary drilling tool \n15\n.', 'This pipe \n13\n comprises, at the surface \n22\n, a well head \n23\n provided with a discharge pipe \n25\n.', 'The drilling tool \n15\n comprises a drilling head \n27\n, a drill string \n29\n and a liquid injection head \n31\n.', 'The drilling head \n27\n comprises a drill bit \n33\n for drilling through the rocks of the earth formation \n21\n.', 'It is mounted on the lower portion of the drill string \n29\n and is positioned in the bottom of the drilling pipe \n13\n.', 'The string \n29\n comprises a set of hollow drilling tubes.', 'These tubes delimit an inner space \n35\n which makes it possible to bring a liquid from the surface \n22\n to the drilling head \n27\n.', 'To this end, the liquid injection head \n31\n is screwed onto the upper portion of the string \n29\n.', 'The surface installation \n17\n comprises a rotator \n41\n for supporting the drilling tool \n15\n and driving it in rotation, an injector \n43\n for injecting the drilling liquid, and a shale shaker \n45\n (not shown on \nFIG.', '2\n) for collecting the liquid and drilling residues emerging from the discharge pipe \n25\n.', 'The injector \n43\n is hydraulically connected to the injection head \n31\n in order to introduce and circulate a liquid, especially a drilling mud \n47\n, in the inner space \n35\n of the drill string \n29\n.', 'In particular, the injector \n43\n comprises one or more pumps \n50\n to displace the drilling mud \n47\n.', 'The or each pump \n50\n is preferably a reciprocating pump, more preferably a piston pump.', 'For example, the pump \n50\n is a three-piston pump, also known as high pressure triplex pump, or a six-piston pump, also known as hex pump.', 'The pump \n50\n illustrated on \nFIGS.', '1 and 2\n is more particularly a “downhole pump” for injecting fluid via the injecting head, in the line called “standpipe”.', 'In case of a drilling installation \n11\n comprising a deepwater hydraulic circuit, shown on \nFIG.', '2\n, the installation \n11\n may also comprise another line for injecting mud in the wellbore, for instance called “booster line”, the fluid being injected in this line thanks to one or several pumps called “booster pumps” \n51\n.', 'An installation \n11\n with a booster line is shown on \nFIG.', '2\n.', 'A same kind of pump may be used either as a “downhole pump” or as a “booster pump”.', 'In other words, the same pump may be connected at a first moment to the standpipe, constituting a “downhole pump”, and at a second moment to the booster line, constituting a booster “pump”.', 'In a same installation \n11\n, the “downhole pumps” \n50\n have a same first outlet pressure and the “booster pumps” \n51\n have a same second outlet pressure.', 'The measurement unit \n19\n comprises at least one measurement device.', 'In particular, the measurement unit \n19\n of \nFIG.', '1\n comprises a first measurement device \n52\n, situated downstream of the pump or pumps \n50\n, that is to say on the hydraulic connection between the pump or pumps \n50\n and the injection head \n31\n in case of the downhole pumps.', 'The measurement unit \n19\n comprises sensors such as sensors \n53\n, \n56\n able to measure at least one parameter of the pump(s) \n50\n at the outlet of said pump(s) \n50\n.', 'Preferably, the at least one parameter of the pump \n50\n may comprise the mud pressure.', 'It may also comprise a sensor for measuring the temperature and/or the density of the mud exiting the pump.', 'However, it is also possible to choose other parameters.', 'The measurement device \n52\n illustrated on \nFIG.', '1\n comprises a pressure sensor \n53\n.', 'The pressure sensor \n53\n may be a manometer.', 'The installation \n11\n of \nFIG.', '2\n, comprising one or more “downhole pumps” \n50\n and one or more “booster pumps” \n51\n, comprises two measurement units \n52\nA, \n52\nB, each including one pressure sensor \n53\nA, \n53\nB to measure respectively the outlet pressure of the downhole pumps \n50\n and the outlet pressure of the booster pumps \n51\n.', 'The measurement device \n52\n, \n52\nA, \n52\nB may also comprise a SPM sensor \n56\n for determining the number of cycles, or strokes, of the pump(s).', 'This sensor may be a proximity sensor, such as a magnetic or optical sensor.', 'Similarly, the installation comprises two measurement units \n52\nA, \n52\nB, each including one SPM sensor \n56\nA, \n56\nB to measure respectively the SPM of the downhole pumps and of the booster pumps.', 'The surface installation \n17\n also comprises another measurement unit, comprising mud flow rate sensor installation \n54\n for measuring the flow rate of the mud exiting the wellbore on the discharge pipe \n25\n (or flowline) between the exit of the wellbore and the shale shaker \n45\n.', 'Preferably, as shown on \nFIG.', '1\n, the mud flow rate installation \n54\n comprises a flow meter \n54\nA.', 'It is understood by “flow meter”, a device for measuring the flow of a fluid or of a gas.', 'More precisely, the flow meter \n54\nA may be a Coriolis flow meter providing a volume flow rate based on the mass flow rate and the density of the fluid.', 'The Coriolis flow meter is also able to measure the mud density.', 'For instance, the flow meter \n54\nA is installed in a by-pass pipe \n55\n, such as a U-shaped by-pass pipe comprising an inlet \n57\nA opening in the discharge pipe \n25\n at a first tapping point and an outlet \n57\nB also opening in the discharge point at a second tapping point situated downstream from the first tapping point.', 'The installation \n54\n also comprises at least a valve \n58\n at the inlet \n57\nA of the by-pass pipe and to close the discharge pipe in order all the fluid exiting the wellbore passes through the by-pass.', 'However, any other type of flow meter may be used for implementing the method of the disclosure, such as electromagnetic, ultrasonic, etc.', 'The flow meter installation \n54\n may also be installed elsewhere in the drilling installation such as in a mud tank in which it would obtain a flow rate at the exit of the wellbore by measuring the level in the mud tanks.', 'The calculation system \n20\n is, for example, a computer.', 'The calculation system \n20\n comprises a processor \n60\n, a man-machine interface \n62\n and a display unit \n64\n.', 'The processor \n60\n comprises a processing unit \n66\n, a memory \n68\n and a software application \n70\n stored in the memory \n68\n.', 'The software application \n70\n is configured to be executed by the processing unit \n66\n.', 'The man-machine interface \n62\n is, for example, a touchscreen or a keyboard.', 'The display unit \n64\n is, for example, a computer screen.', 'The method for estimating a real-time flow out of a fluid pump according to embodiments of the disclosure will now be described, as an example, with reference to \nFIG.', '3\n.', 'The method comprises (box \n80\n) an initial determination of a calculation model.', 'According to a first embodiment of the disclosure, the chosen calculation model gives the evolution of a volume exiting the pump based on at least one calculation parameter and on constant coefficients.', 'In the first embodiment described hereinafter, the calculation model corresponds to a physical model and the constant coefficients correspond to physical parameters relative for instance to the pump geometry and/or the mud intrinsic parameters.', 'The constant coefficients may therefore be known or be determined using fitting methods on measured data\n \nAccording to a second embodiment of the disclosure, the chosen calculation model relates to the real-time mud volume ejected by the pumps.', 'In particular, this volume is supposed to be dependent on at least one parameter such as the outlet mud pressure.', 'This calculation model in this case may be an analytical model in which the constant coefficients do not correspond to physical parameter.', 'Thereafter, the method optionally calibrates (box \n82\n) the pump or pumps \n50\n, \n51\n in order to determine constant coefficients of the calculation model, such as coefficients related to said pump or pumps \n50\n, \n51\n.', 'The calibration is performed under predetermined conditions in which there is no gain or no loss (for instance, in cased hole and in stationary state of the pump), in order to ensure that the flow measured at the exit of the wellbore by the flow meter \n54\n correspond to the flow rate at the exit of the pump.', 'Thereafter, the method provides (box \n84\n), at a plurality of measuring times, a set of measurement values representative of the at least one calculation parameter.', 'The method then estimates (box \n86\n) the flow rate at the exit of the pump in function of the model and of the at least one calculation parameter.', 'It may also determine (box \n88\n) if there is a kick or a loss in the wellbore on the basis of the flow rate measured at the exit of the wellbore and at the estimated flowrate at the exit of the pump or pumps \n50\n.', 'In the initial determination of a calculation model, the chosen model may be based on physical considerations, such as an isothermal model or an adiabatic model.', 'The chosen model may also be an approximation unrelated to physical considerations such as a polynomial function.', 'In the latter case, the calibration of the pump(s) is mandatory.', 'In the first embodiment, described below, the chosen model is isothermal.', 'The pump or pumps \n50\n, \n51\n which preferably comprise more than one piston, may be modeled as a plurality of single-piston pumps \n90\n.', 'A schematic view of a single-piston pump \n90\n is illustrated on \nFIG.', '4\n.', 'The single piston pump \n90\n comprises a piston chamber \n94\n and a piston \n96\n movable inside said piston chamber.', 'The pump \n90\n also comprises an actuator \n98\n, suitable to move the piston \n96\n along an axis \n100\n.', 'The piston chamber \n94\n comprises a displacement volume \n102\n, corresponding to the course of the piston, and a clearance volume \n104\n.', 'A maximum volume or total volume of the piston chamber \n94\n corresponds to a sum of the displacement volume \n102\n and clearance volume \n104\n.', 'A fluid inlet \n106\n and a fluid outlet \n108\n open into the clearance volume \n104\n.', 'The fluid inlet \n106\n and fluid outlet \n108\n are respectively opened and closed by a suction valve \n110\n and by a discharge valve \n112\n.', 'The suction valve \n110\n is configured to open at a first pressure, also called injection pressure.', 'The discharge valve \n112\n is configured to open at a second pressure, also called outlet pressure.', 'The operating principle of a reciprocating pump can be split into four isothermal stages, as illustrated on \nFIG.', '5\n: \n \n \n \n1) COMPRESSION STAGE: The piston chamber \n94\n is full of fluid at the injection pressure and the volume of fluid corresponds to the total volume of the piston chamber \n94\n.', 'The suction valve \n110\n and discharge valve \n112\n being closed, the piston \n96\n is displaced in the direction of the clearance volume \n104\n to compress the fluid.', 'The configuration of the pump on \nFIG.', '4\n is the configuration of compression stage.\n \n2) EJECTION STAGE:', 'Once the pressure of the chamber has reached the outlet pressure, the discharge valve \n112\n opens and the fluid is ejected from the pump.\n \n3) EXPANSION STAGE:', 'The piston chamber is full of fluid at the outlet pressure and the volume of fluid corresponds to the clearance volume \n104\n of the pump.', 'The suction valve \n110\n and discharge valve \n112\n being closed, the piston \n96\n is displaced in the direction opposite the clearance volume \n104\n, to decompress the fluid.', '4) INJECTION STAGE:', 'The suction valve \n110\n opens and the piston chamber \n94\n is filled up with fluid at injection pressure, until the displacement of the piston \n96\n is completed.', 'The completion of the four above-mentioned stages represents a cycle, or stroke, of the pump \n90\n.', 'The first and second preferred embodiments of the determination \n80\n of a calculation model, will be described below.', 'The following lexicon is used: \n \n \n \nV Volume\n \nT Temperature\n \np Pressure\n \nVout|T,p Volume of fluid displaced by the pump during a cycle at T and p\n \nVdisp/Vd Geometrical volume displaced by the piston\n \nVt Total volume of the piston chamber\n \nVc Dead volume of the piston chamber\n \np0 Reference pressure\n \nχT Isothermal compressibility of the mud\n \npdown Pressure at the exit of the reciprocating pumps system\n \npin Injection pressure (at the inlet of the reciprocating pumps)\n \nti Observation time start\n \nΔti Observation time duration\n \npi\n−\n Mean pressure between ti and ti+Δti\n \nQi\n−\n Mean flow rate between ti and ti+Δti\n \nQ|p0 Flow rate at reference pressure\n \nQout Flow rate at the exit of the reciprocating pump\n \nQcoriolis/Qc Flow rate measured by the Coriolis flowmeter\n \nSPM Number of Strokes Per Minute\n \nQDH Flow rate at the exit of the reciprocating downhole pumps system\n \nQB Flow rate at the exit of the reciprocating booster pumps system\n \nDH Downhole pumps\n \nB Booster pumps\n \n \n \n \n \n1.', 'First Embodiment—Isothermal Volumetric Pump Efficiency', 'According to the theory applied here, the thermodynamic properties of the mud are affecting the pump efficiency or the volume of fluid ejected by the pump.', 'An Equation of State (EoS) of the fluid displaced by the reciprocating pump is derived from the definition of the fluid isothermal compressibility coefficient (Equation (1)):\n \n \n \n \n \n \n \n \n \nχ\n \nT\n \n \n=\n \n \n \n-\n \n \n1\n \nV\n \n \n \n\u2062\n \n \n \n(\n \n \n \n∂\n \nV\n \n \n \n∂\n \np\n \n \n \n)\n \n \nT\n \n \n \n \n \n \n \n(\n \n1\n \n)', 'The volume exiting the pump may be obtained as follows, by modelling the pump as a single-piston reciprocating pump, as defined above: \n \nV\nout\n|\np\no\n=V\nt\ne\n−χ\nT\n(p\no\n−p\nin\n)\n−V\nc\ne\n−×\nT\n(p\no\n−p\ndown\n)\n\u2003\u2003(2) \n \nThe real-time flow rate out of the reciprocating pump \n90\n at time t\ni \nmay then be determined as follows: \n \nQ\nout\n|\np\no\n,i\n=(\nV\nt\ne\n−χ\nT\n(p\no\n−p\nin\n)', '−V\nc\ne\n−χ\nT\n(p\no\n−p\ndown,i\n)\n)', 'SPM\ni\n\u2003\u2003(3) \n where Q\nout\n|p\n0,i \nis the real-time flow rate out of the reciprocating pump \n90\n at time t\ni\n, p\ndown,i \nis the real-time pressure out of the reciprocating pump \n90\n at time t\ni \nand SPM\ni \nis the real-time SPM of the reciprocating pump \n90\n at time t\ni\n.', 'The calculation model determined hereabove is obtained from the physical estimation of the volume out of the pump but it may also be obtained from an estimation of a pump efficiency.', 'The calculation model has also been set up with injection of fluid in the wellbore via a downhole pump only.', 'However, it may be adapted to an installation with several downhole pumps.', 'Indeed, the pump or pumps \n50\n of the installation \n11\n of \nFIG.', '1\n have the same characteristic volumes.', 'In other terms, the pump or pumps \n50\n of the installation \n11\n are modeled by a plurality of single-piston pumps \n90\n with the same displacement volume \n102\n and the same clearance volume \n104\n.', 'They may be modelled by one equivalent downhole pump with the same characteristic volumes as each of the downhole pumps of the installation \n11\n.', 'This one equivalent downhole pump is pumping at a certain SPM, equal to the sum of the SPM of all the downhole pumps of the installation \n11\n.', 'With such a model, the calculation model as set forth above may be applicable to a drilling rig comprising a plurality of downhole pumps.', 'As shown on \nFIG.', '2\n, the installation \n11\n may also comprise at least two types of pumps \n50\n, \n51\n, one or some of which having a same first outlet pressure p\nDH\n, and one or some of which having a same second outlet pressure p\nB\n.', 'In the following disclosure, it is considered that the first outlet pressure characterizes a first group of pumps called “downhole pumps” \n50\n and injecting mud in the wellbore via the standpipe that the second outlet pressure characterizes a second group of pumps called “booster pumps” \n51\n and injecting fluid in the wellbore in parallel of the downhole pumps, via the booster line.', 'The measurement unit \n19\n comprises two pressure sensors \n56\nA and \n56\nB, to measure the outlet pressures p\nDH\n, p\nB \nrespectively of the first group of downhole pumps and of the second group of booster pumps, each of the sensors being situated between the exit of the pump and the entry of the fluid in the wellbore, generally at the surface.', 'In the same manner, if there are several booster pumps in the drilling rig, they may be modelled by one equivalent booster pump with the same efficiency and characteristic volumes as each of the booster pumps.', 'This equivalent booster pump is pumping at a certain SPM, SPM\nB\n, equal to the sum of the SPM of all the booster pumps of the installation \n11\n.', 'In case of a more complex drilling rig installation modelled as explained above, the following equations are obtained: \n \nV\nt,equivalent downhole pump\n=V\nt\n=V\nt,equivalent booster pump \n \n \nV\nc,equivalent downhole pump\n=V\nc\n=V\nc,equivalent booster pump\n\u2003\u2003(4) \n SPM\nDH\n=SPM\nequivalent downhole pump\n=Σ\nj\nSPM\nj\n\u2003\u2003(5) \n SPM\nB\n=SPM\nequivalent booster pump\n=Σ\nk\nSPM\nk\n\u2003\u2003(6) \n \nwhere j accounts for each downhole pump, and k accounts for each booster pump.', 'Thus, the calculation model representing the real-time flow rates at the exit of the downhole-pump system and booster-pump system can be expressed as follows: \n \nQ\nDH\n|\np\no\n,i\n=(\nV\nt\ne\n−χ\nT\n(p\no\n−p\nin\n)\n−V\nc\ne\n−χ\nT\n(p\no\n−p\nDH,i\n)\n)SPM\nDH,i\n\u2003\u2003(7) \n \nQ\nB\n|\np\no\n,i\n=(\nV\nt\ne\n−χ\nT\n(p\no\n−p\nin\n)\n−V\nc\ne\n−χ\nT\n(p\no\n−p\nB,i\n)\n)SPM\nB,i\n\u2003\u2003(8) \n where p\nDH,i \nis the real-time pressure out of the downhole pumps system at time t\ni\n, SPM\nDH,i \nis the real-time SPM of the equivalent downhole pump at time t\ni\n, p\nB,i \nis the real-time pressure out of the booster pumps system at time t\ni \nand SPM\nB,i \nis the real-time SPM of the equivalent booster pump at time t\ni \nThe calculation model may also adapt to any other pump configuration, for instance a wellbore comprising another additional line.', 'A different model may also take into account pumps with different geometrical characteristics.', 'As the values of V\nc\n, V\nt \nand χ\nT \ndepending on the pump (V\nc\n, V\nt\n) and on the mud (χ\nT\n) are generally known, the equations (7) and (8) above can be used for the next operations \n84\n, \n86\n of real-time estimation of the pump system, as illustrated by arrow \n120\n on \nFIG.', '3\n.', 'In order to determine the pump and mud characteristics when they are unknown or when the accuracy of these parameters is not sufficient, a calibration may be performed as illustrated by arrow \n122\n on \nFIG.', '3\n.', 'Operations \n82\n, \n84\n and \n86\n will be explained below.', '2.', 'Second Embodiment—Pump Out Displaced Mud Volume Model', 'The second embodiment, described hereafter, of the determination of a calculation model, has less modeling complexity than the first embodiment previously described.', 'The flow rates at the exit of equivalent downhole pump and equivalent booster pump is related to the effective mud volume ejected from the pumps during one cycle and the number of strokes per minutes of each drilling pump j and each booster pump k (measured data from the pump stroke counters).', 'Q\nDH\n|\np\no\n,i\n=(\nV\nout,DH\n|\np\no\n,i\n)SPM\nDH,i\n\u2003\u2003(9) \n \nQ\nB\n|\np\no\n,i\n=(\nV\nout,B\n|\np\no\n,i\n)SPM\nB,', 'i\n\u2003\u2003(10) \n \nwhere V\nout\n|p\n0,i \nis the real time volume of fluid displaced by each pump during one cycle at time t\ni\n, SPM\nDH,i \nis the real time SPM of the equivalent downhole pump at time t\ni \nand SPM\nB,i \nis the real time SPM of the equivalent booster pump at time t\ni\n.', 'The effective volume of mud ejected from each pump during one cycle depends on the pressure outside of the pumps.', 'From the observation of field results, it has been enlightened that this function can be approximated by a function, such as a polynomial function of degree two: \n \nV\nout\n|\np\no\n,i\n=β\n0\nP\ndown,i\n2\n+β\n1\nP\ndown,i\n+β\n2\n\u2003\u2003(11)', 'The three coefficients β\n0\n, β\n1 \nand β\n2 \nare not known a priori.', 'Thus a calibration \n82\n may be carried out to express β\n0\n, β\n1 \nand β\n2\n.', 'In case there are several pumps, as all the pumps \n90\n are supposed to be identical, these three coefficients are the same for each pump.', 'As also explained above, other function may adapt to a configuration where there is only one type of pumps in the wellbore or pumps with different geometrical characteristics, or any other pump configuration.', 'It will now be explained how the calibration \n82\n is carried out.', 'It may be carried out after a determination of the model according to the first or to the second embodiment.', 'A real-time measured flow rate (corresponding to the Coriolis flow rate QCoriolis|p\n0\n) is measured by the Coriolis flow meter \n54\n on the flow line.', 'The Coriolis flow meter \n54\n is situated downstream of the booster pumps and downhole pumps \n50\n, at the exit of the wellbore, as already explained.', 'Therefore, during the calibration procedure, it can be assumed that the flow rate measured by the Coriolis flow meter \n54\n corresponds to the sum of the flow rates out of the downhole pumps system and out of the booster pumps system.', 'This hypothesis is correct if there is no gain and loss in the well, such as when the calibration is performed in cased hole and in a stationary state of the pumps: these conditions ensure there is no gain and loss in the well and during steady states.', 'The objective of the calibration procedure is to find the unknown constant values β\n0\n, β\n1 \nand β\n2 \nsuch that the analytical expression of the flow rates outside of the pumps (coming from the pump displaced mud volume model) equals the measured flow rate by the Coriolis flow meter.', 'This equality must be verified on mean flow rate values over several stages: \n \nQ\nCoriolis\n|\np\no\n,i\n=\nQ\nDH,analytical2\n|\np\no\n,i\n+\nQ\nB,analytical2\n|\np\no\n,i\n\u2003\u2003(12) \n where \nQ|\np\no\n,i\n is the mean flow rate between t\ni \nand t\ni\n+Δt\ni\n, Δt\ni \nbeing the time length of a fitting stage.', 'In other terms, in the first embodiment, the objective is to find the constant values V\nt\n, V\nc \nand χ\nT \nsuch that the next equality is verified for different calibration stages Δt\ni\n:\n \n \n \n \n \n \n \n \n \n \n \nQ\n \nC\n \n \n\u2062\n \n \n|\n \n \n \np\n \n0\n \n \n,\n \nι\n \n \n \n \n_\n \n \n=\n \n \n \n \n(\n \n \n \n \nV\n \nt\n \n \n\u2062\n \n \ne\n \n \n-\n \n \n \nχ\n \nT\n \n \n\u2061\n \n \n(\n \n \n \np\n \no\n \n \n-\n \n \np\n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \nn\n \n \n \n \n)\n \n \n \n \n \n \n-\n \n \n \nV\n \nc\n \n \n\u2062\n \n \ne\n \n \n-\n \n \n \nχ\n \nT\n \n \n\u2061\n \n \n(\n \n \n \np\n \no\n \n \n-\n \n \n \np\n \n \nDH\n \n,\n \nι\n \n \n \n_\n \n \n \n)\n \n \n \n \n \n \n \n)\n \n \n\u2062\n \n \n \nSPM\n \n \nDH\n \n,\n \nι\n \n \n \n_\n \n \n \n+\n \n \n \n(\n \n \n \n \nV\n \nt\n \n \n\u2062\n \n \ne\n \n \n-\n \n \n \nχ\n \nT\n \n \n\u2061\n \n \n(\n \n \n \np\n \no\n \n \n-\n \n \np\n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \nn\n \n \n \n \n)\n \n \n \n \n \n \n-\n \n \n \nV\n \nc\n \n \n\u2062\n \n \ne\n \n \n-\n \n \n \nχ\n \nT\n \n \n\u2061\n \n \n(\n \n \n \np\n \n0\n \n \n-\n \n \n \np\n \n \nB\n \n,\n \nι\n \n \n \n_\n \n \n \n)\n \n \n \n \n \n \n \n)\n \n \n\u2062\n \n \n \nSPM\n \n \nB\n \n,\n \nι\n \n \n \n_\n \n \n \n \n \n \n \n \n(\n \n13\n \n)', 'In other terms, in the second embodiment, the objective is to find the constant values β\n0\n, β\n1 \nand β\n2 \nsuch that the next equality is verified for different calibration stages Δt\ni\n:\n \n \n \n \n \n \n \n \n \n \n \nQ\n \nC\n \n \n\u2062\n \n \n|\n \n \n \np\n \n0\n \n \n,\n \nι\n \n \n \n \n_\n \n \n=\n \n \n \n \n(\n \n \n \n \nβ\n \n0\n \n \n\u2062\n \n \n \n \np\n \n \nDH\n \n,\n \nι\n \n \n \n_\n \n \n2\n \n \n \n+\n \n \n \nβ\n \n1\n \n \n\u2062\n \n \n \np\n \n \nDH\n \n,\n \nι\n \n \n \n_\n \n \n \n+\n \n \nβ\n \n2\n \n \n \n)\n \n \n\u2062\n \n \n \nSPM\n \n \nDH\n \n,\n \nι\n \n \n \n_\n \n \n \n+\n \n \n \n(\n \n \n \n \nβ\n \n0\n \n \n\u2062\n \n \n \n \np\n \n \nB\n \n,\n \nι\n \n \n \n_\n \n \n2\n \n \n \n+\n \n \n \nβ\n \n1\n \n \n\u2062\n \n \n \np\n \n \nB\n \n,\n \nι\n \n \n \n_\n \n \n \n+\n \n \nβ\n \n2\n \n \n \n)\n \n \n\u2062\n \n \n \nSPM\n \n \nB\n \n,\n \nι\n \n \n \n_\n \n \n \n \n \n \n \n \n(\n \n14\n \n)\n \n \n \n \n \n \n \n where \np\ni\n is the average outlet pressure between t\ni \nand t\ni\n+Δt\ni \nand \nSPM\ni\n is the average Strokes Per Minutes between t\ni \nand t\ni\n+Δt\ni\n.', 'In the calibration \n82\n of the first and second embodiments described above, the data are preferably acquired for at least 5 different SPM.', 'Preferably, the value Δt\ni \nis at least 10 minutes.', 'During the calibration \n82\n, a calibration algorithm is processed by the calculation system \n20\n.', 'The inputs of the calibration algorithm are the measured volume flow rate (from the Coriolis flow meter \n54\n), the pressure p\nDH,i\n, p\nB,i \ndownstream of the pumps (from the pressure sensors \n56\n of the downhole pumps and booster pumps) and the SPM SPM\nDH,i\n, SPM\nB,i\n, of all the pumps.', 'When the calibration algorithm is different, other parameters such as the mud density, etc. may also be taken into account to determine the constant values.', 'For the first embodiment, the outputs of the algorithm are the three constant values V\nc\n, V\nt \nand χ\nT\n, that is to say the clearance volume \n104\n and the total volume (\n102\n+\n104\n) of pump \n90\n, and the mud compressibility.', 'For the second embodiment, the outputs of the algorithm are the three coefficients β\n0\n, β\n1 \nand β\n2\n.', 'The calibration algorithm may be determined from any known inversion method, such as a linear regression.', 'After the calibration \n82\n, the real-time estimation of the pump system is carried out.', 'The method comprises providing (box \n84\n), at a plurality of measuring times t\nm\n, a set of measurement values representative of the calculation parameters used in the calculation models.', 'According to the first and second embodiments described above, the concerned parameters are the first and second outlet pressures p\nDH,m\n, p\nB,m \nrespectively of the downhole pumps and booster pumps, and the first and second SPM SPM\nDH,m\n, SPM\nB,m \nrespectively of the downhole pumps and booster pumps.', 'The pressures are given by the pressure sensors \n53\n while the SPMs are given by the proximity sensors \n56\n.', 'A calculation algorithm is processed (box \n86\n) by the calculation system \n20\n, according to the equations described above by the calculation model \n80\n and according to the constant values/coefficients determined during calibration \n82\n.', 'The inputs of the algorithm are the first and second outlet pressures and the first and second SPM.', 'The outputs of the algorithm are the real-time flow rates out of the downhole pumps and out of the booster pumps.', 'Once the flow rate of mud exiting the pump has been determined, the method comprises (box \n88\n) determining if there is a kick or between the measured flow rate at the exit of the wellbore and the flow rate at the exit of the pumps, corresponding to the flow rate at the inlet of the wellbore indeed enables to determine if there is a kick, in other terms fluid coming from the wellbore (in which case the flow measured at the exit of the wellbore is greater than the one measured at the inlet of the wellbore), or a loss of fluid in the wellbore (in which case the flow measured at the exit of the wellbore is lesser than the one measured at the inlet of the wellbore) a loss in the wellbore based on the measured flow rate at the exit of the wellbore (measured by the flow meter \n54\n) and on the calculated flow rate at the exit of the pumps.'] | ['1.', 'A method for estimating a flow out of at least one fluid pump, wherein the fluid pump is configured for injecting fluid in a wellbore and is situated upstream of an entry of fluid into the wellbore, comprising:\ndetermining a calculation model for the flow rate of a pump exiting the at least one pump, said calculation model permitting the calculation of the flow rate as a function of at least one calculation parameter related to the at least one fluid pump; then\nproviding at a plurality of measuring times, a set of measurement values representative of said at least one calculation parameter; then\nestimating the flow rate exiting the pump as a function of the model and of said at least one calculation parameter, wherein the method further comprises, after the determination of the calculation model, a calibration procedure including:\nproviding, at a plurality of measuring times, first measurement values related to the at least one fluid pump and second measurement values of a flow rate measured at the exit of the wellbore, and\non the basis of said first and second measurement values, calculating constant values of the calculation model.', '2.', 'The method according to claim 1, wherein the at least one calculation parameter is a fluid pressure at an outlet of the pump or a number of cycles of the pump per time unit.', '3.', 'The method according to claim 1, wherein the constant values are coefficients relative to the fluid or the pump characteristics.', '4.', 'The method according to claim 1, wherein the first measurement values comprise values representative of a fluid density, and/or values representative of a fluid pressure at an outlet of the pump, and/or values representative of a number of cycles of the pump per time unit.', '5.', 'The method according to claim 1, wherein the calibration procedure is performed in a cased hole when the at least one pump is in a stationary state.', '6.', 'The method according to claim 1, wherein the first measurement values comprise at least one of the following:\nA mean fluid density during a predetermined time period,\nA mean fluid pressure at an outlet of the pump during a predetermined time period, or\nA mean number of cycles of the pump per time unit during a predetermined time period.', '7.', 'The method according to claim 1, comprising determining, on the basis of the estimated flow rate at the exit of the pumps and of a flow rate measured at the exit of the wellbore, if there is a kick or a loss in the wellbore.', '8.', 'The method according to claim 1, wherein the estimation of the flow rate out of the pump is a real-time estimation.', '9.', 'A calculation system comprising a processing unit in interaction with a software application for the implementation of the method according to claim 1.\n\n\n\n\n\n\n10.', 'A drilling installation comprising:\nat least one fluid pump configured for injecting fluid in the wellbore;\na first measurement unit for providing fluid measurement values representative of the pump, said measurement unit comprising at least one sensor able to measure at least one calculation parameter related to the pump;\na discharge pipe at the exit of the wellbore,\na second measurement unit comprising a flow meter installation in the discharge pipe for measuring the fluid flow rate exiting the wellbore; and\na calculation system according to claim 9.\n\n\n\n\n\n\n11.', 'The drilling installation according to claim 10, wherein the sensor comprises a pressure sensor and/or a sensor for determining a number of cycles of the pump per time unit.', '12.', 'The drilling installation according to claim 10, comprising at least two fluid pumps, said at least two fluid pumps forming a first group and a second group of at least one fluid pump, said first group being characterized by a first outlet pressure and said second group being characterized by a second outlet pressure.', '13.', 'The method according to claim 1, wherein the second measurement values comprise a mean flow rate during a predetermined time period.'] | ['FIG.', '1 is a schematic view, in vertical section, of a drilling installation according to an embodiment of the present disclosure;; FIG.', '2 is a schematic view, in vertical section, of a drilling installation according to another embodiment of the present disclosure;; FIG.', '3 is an organization chart of a method according to the an embodiment of the disclosure;; FIG.', '4 is a schematic view of a single-piston pump according to the state of the art;; FIG.', '5 is a pressure/volume diagram of the single-piston pump of FIG. 4;'] |
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US11105174 | Systems and method for retrievable subsea blowout preventer stack modules | Jul 28, 2017 | Harold Daley, Mac M Kennedy, Michael Urdiales, Gerrit Kroesen | Schlumberger Technology Corporation | NPL References not found. | 3602300; August 1971; Jaffe; 3683835; August 1972; Deslierres; 4721055; January 26, 1988; Pado; 4969627; November 13, 1990; Williams, III; 5069580; December 3, 1991; Herwig et al.; 5235931; August 17, 1993; Nadolink; 6021731; February 8, 2000; French et al.; 6142233; November 7, 2000; Wilkins; 6161618; December 19, 2000; Parks et al.; 6209565; April 3, 2001; Hughes et al.; 6223675; May 1, 2001; Watt et al.; 6257337; July 10, 2001; Wells; 6422315; July 23, 2002; Dean; 6644410; November 11, 2003; Lindsey-Curran et al.; 6763889; July 20, 2004; Rytlewski et al.; 6860525; March 1, 2005; Parks; 7213532; May 8, 2007; Simpson; 7216714; May 15, 2007; Reynolds; 7216715; May 15, 2007; Reynolds; 7222674; May 29, 2007; Reynolds; 7690433; April 6, 2010; Reynolds; 8020623; September 20, 2011; Parks et al.; 8464797; June 18, 2013; Singh et al.; 8607879; December 17, 2013; Reynolds; 8720579; May 13, 2014; Reynolds et al.; 8727013; May 20, 2014; Buckley et al.; 8820410; September 2, 2014; Parks et al.; 9416628; August 16, 2016; Landrith, II et al.; 9725138; August 8, 2017; Baylot et al.; 9797224; October 24, 2017; Stewart et al.; 9862469; January 9, 2018; Drozd et al.; 10151151; December 11, 2018; Roper et al.; 20020040783; April 11, 2002; Zimmerman et al.; 20060037758; February 23, 2006; Reynolds; 20070173957; July 26, 2007; Johansen et al.; 20100307761; December 9, 2010; Buckley et al.; 20160076331; March 17, 2016; Kalinec et al.; 20160326826; November 10, 2016; Wood et al.; 20180029678; February 1, 2018; Peterson et al.; 20180186438; July 5, 2018; Jamieson; 20180245417; August 30, 2018; Miller; 20190031308; January 31, 2019; Daley et al.; 20190032439; January 31, 2019; Smith et al. | 2357537; June 2001; GB; 2015021107; February 2015; WO | ['A blowout preventer (BOP) stack module includes a chassis core having a module frame, wherein the chassis core supports one or more submodules each configured to perform a function of a BOP stack, an underwater vehicle coupling hardware coupled to the chassis core, wherein the underwater vehicle coupling hardware couples with an underwater vehicle configured to transport and selectively couple and uncouple the BOP stack module relative to the BOP stack, and a mechanical connector coupled to the chassis core, wherein the mechanical connector couples to a stack frame of the BOP stack, and at least one port coupled to the chassis core, wherein the at least one port is a fluid port, a hydraulic port, a pneumatic port, an electrical port, or a combination thereof, wherein the at least one port couples with a corresponding port of the BOP stack.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'Subsea installations for hydrocarbon drilling or production typically include a rig or vessel disposed at the surface of a body of water.', 'The rig is in communication with a wellhead assembly disposed on a floor of the body of water.', 'A well then extends from the floor of the body of water into the earth to access hydrocarbon deposits.', 'The wellhead assembly typically includes a blowout preventer (BOP) stack to monitor the well and seal the well before a blowout occurs.', 'When a component of the BOP needs servicing, then the BOP is retrieved, causing the well to be taken off-line.', 'The BOP is then diagnosed, repaired, returned to the floor of the body of water, and reinstalled in the wellhead assembly.', 'The well is then brought back online.', 'Because the BOP stack may be disposed at significant depths (e.g., 4,000 feet or more), from the time the well is taken off-line to the time the well is brought back online may be as long as 2-3 weeks, resulting on lost production for an operator of the well.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n is a schematic of an embodiment of a subsea installation wellhead assembly;\n \nFIG.', '2\n is a schematic of an embodiment of a retrievable module used in the subsea installation wellhead assembly shown in \nFIG.', '1\n;\n \nFIG.', '3\n is a perspective view of an embodiment of a filter module;\n \nFIG.', '4\n is an exploded view of an embodiment of the filter module of \nFIG.', '3\n;\n \nFIG.', '5\n is a schematic of a flow path through an embodiment of the filter module of \nFIGS.', '3 and 4\n;\n \nFIG.', '6\n is a schematic of a flow path through an embodiment of the filter module of \nFIGS.', '3 and 4\n;\n \nFIG.', '7\n is a schematic of a flow path through an embodiment of the filter module of \nFIGS.', '3 and 4\n;\n \nFIG.', '8\n is a schematic of a flow path through an embodiment of the filter module of \nFIGS.', '3 and 4\n;\n \nFIG.', '9\n is a schematic of an embodiment of a deadman/autoshear system (DMAS) module having a single ram block;\n \nFIG.', '10\n is a schematic of an embodiment of a two-ram DMAS having first and second modules;\n \nFIG.', '11\n is a schematic of an embodiment of the two-ram DMAS with dual timers;\n \nFIG.', '12\n is a schematic of an embodiment of an rigid conduit manifold (RCM) distributed over first and second modules;\n \nFIG.', '13\n is a perspective view of an embodiment of a shuttle valve module;\n \nFIG.', '14\n is a perspective view an embodiment of the shuttle valve module of \nFIG.', '13\n;\n \nFIG.', '15\n is a schematic of an embodiment of the shuttle valve module of \nFIGS.', '13 and 14\n;\n \nFIG.', '16\n is a perspective view of an embodiment of an electrical energy storage module;\n \nFIG.', '17\n is a perspective view an embodiment of the electrical energy storage module of \nFIG.', '16\n;\n \nFIG.', '18\n is a schematic of an embodiment of the electrical energy storage module of \nFIGS.', '16 and 17\n;\n \nFIG.', '19\n is a perspective view of an embodiment of a hydraulic energy storage module;\n \nFIG.', '20\n is a perspective view an embodiment of the hydraulic energy storage module of \nFIG.', '19\n;\n \nFIG.', '21\n is a schematic of an embodiment of the hydraulic energy storage module of \nFIGS.', '19 and 20\n;\n \nFIG.', '22\n is a perspective view of an embodiment of a subsea electronics module (SEM);\n \nFIG.', '23\n is a perspective view an embodiment of the SEM of \nFIG.', '22\n;\n \nFIG.', '24\n is a schematic of an embodiment of the SEM of \nFIGS.', '22 and 23\n;\n \nFIG.', '25\n is a family tree of various embodiments of retrievable subsea BOP modules;\n \nFIG.', '26\n is a perspective view of an embodiment of a portion of a blowout preventer (BOP) stack frame;\n \nFIG.', '27\n is a perspective view of an embodiment of an electrical receiver;\n \nFIG.', '28\n is a perspective view of an embodiment of a hydraulic receiver;\n \nFIG.', '29\n is a side, section view of a remotely operated underwater vehicle (ROV) depositing the module in a module receptacle of the BOP stack frame;\n \nFIG.', '30\n is a schematic of an embodiment of the ROV;\n \nFIG.', '31\n is a perspective view of an embodiment of the ROV of \nFIG.', '30\n;\n \nFIG.', '32\n is a perspective view of an embodiment of a frame of the ROV of \nFIG.', '31\n;\n \nFIG.', '33\n is a perspective view of an embodiment of floatation devices of the ROV of \nFIG.', '31\n; and\n \nFIG.', '34\n is a flow chart of an embodiment of a process for controlling buoyancy of the ROV while depositing and/or retrieving the module.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nOne or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Moreover, the use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components.', 'The disclosed techniques include performing one or more functions of a subsea BOP stack with one or more modules retrievable by an underwater vehicle (e.g., ROV, AUV, etc.).', 'Each module may include one or more components or submodules that couple to a chassis core of the module.', 'The module may also include connections (e.g., electrical, fluid, hydraulic, pneumatic, etc.) that provide an interface between the module and an adjacent module, the BOP stack, or an underwater vehicle.', 'Accordingly, any function of the BOP stack could be modularized by performing the function with one or more retrievable modules.', 'Further, the BOP stack can be customized by using various modules.', 'The modules may include ancillary systems, which may be added to existing BOP stacks, or primary systems incorporated into designs of new BOP stacks.', 'If a module of the BOP stack breaks or malfunctions, rather than retrieving the entire BOP stack, taking the well off-line for two weeks or more, a replacement module may be assembled on the rig and an underwater vehicle may be sent down to retrieve the old module and install the new module, thus reducing the time the well is off-line to 1-2 days.', 'Further, by assembling a replacement module for the malfunctioning module, the cause of the malfunction can be diagnosed and repaired after the well has been brought back on line.', 'Thus, engineers tasked with repairing BOP stack do not have to work under the intense pressure to get the well back on-line.\n \nFIG.', '1\n is a schematic of a subsea installation \n10\n.', 'The subsea installation \n10\n includes a well \n12\n.', 'The well \n12\n includes a wellhead assembly \n14\n disposed at or near a sea floor \n16\n of a body of water \n18\n (e.g., an ocean).', 'A well bore \n20\n extends from the wellhead assembly \n14\n through the earth \n22\n toward a mineral deposit \n24\n.', 'A drill string \n26\n extends through the wellbore \n20\n toward the mineral deposit \n24\n.', 'A drill bit \n28\n disposed in the drill string \n26\n removes portions of earth \n22\n, forming cuttings, extending the bore hole \n20\n toward the mineral deposit \n24\n.', 'Drilling fluids (e.g., drilling mud) are pumped down the drill string \n26\n toward the drill bit, indicated by arrow \n30\n, flushing the cuttings away from the drill bit \n28\n and into an annulus \n32\n disposed between the drill string \n26\n and a casing \n34\n.', 'The cuttings and drilling fluids travel through the annulus \n32\n in an opposite direction (indicated by arrow \n36\n) as the drilling mud flow through the drill string \n26\n (indicated by arrow \n36\n).', 'A drilling riser \n38\n extends from the wellhead assembly \n14\n to a rig \n40\n or vessel disposed at a surface \n42\n of the body of water \n18\n and may provide passageways for the drilling fluids down to the well \n12\n and for fluids emanating from the well \n12\n up to the rig \n40\n.', 'The wellhead assembly \n14\n interfaces with the well bore \n20\n via a wellhead hub \n44\n.', 'The wellhead hub \n44\n generally may include a large diameter hub that is disposed at the termination of the well bore \n20\n.', 'The wellhead hub \n44\n provides for the sealable connection of the wellhead assembly \n14\n to the well bore \n20\n.', 'The wellhead assembly \n14\n includes a blowout preventer (BOP) stack \n46\n.', 'Though not shown for the sake of clarity and simplicity, it should be understood that the wellhead assembly \n14\n may include other components or assemblies, such as trees (e.g., Christmas trees, production trees), wellhead connectors, lower and upper marine packages, etc.', 'Further, it should be noted that for clarity, the elements shown in \nFIG.', '1\n are not drawn to scale.', 'The BOP stack \n46\n includes one or more ram BOPs \n48\n and/or one or more annular BOPs \n50\n.', 'In the instant embodiment, the BOP stack \n46\n includes three ram BOPS \n48\n and one annular BOP \n50\n, however, it should be understood embodiments having different combinations of ram BOPs \n48\n and/or annular BOPs \n50\n are also envisaged.', 'The ram BOP \n48\n includes ram blocks that move toward one another in a plane perpendicular to the axis of the drill string \n26\n to block or restrict fluid flow through the drill string \n26\n, the annulus \n32\n, or other flow paths through the BOP stack \n46\n.', 'In some embodiments, the ram BOP \n48\n may be able to open and close like a gate valve to temporarily restrict fluid flow through one or more fluid flow paths of the BOP stack \n46\n.', 'In other embodiments, the ram BOP \n48\n may shear the fluid conduits through the BOP stack \n46\n (e.g., the drill string \n26\n, the casing \n34\n, etc.) to more permanently restrict fluid flow through the one or more fluid flow paths of the BOP stack \n46\n.', 'The annular BOP \n50\n includes an annular elastomeric seal disposed about the axis of the drill string \n26\n.', 'One or more pistons push on the seal in a direction parallel to the axis of the drill string, causing the seal to radially constrict, stopping or restricting fluid flow through the fluid passages in which it is disposed.', 'As the well \n12\n is being drilled, the drill bit \n28\n may access the mineral deposit \n24\n.', 'If the hydrocarbon fluid of the mineral deposit \n24\n is under sufficient pressure, the hydrocarbon fluid may flow up the drill string \n26\n, opposite the flow of drilling mud indicated by arrow \n30\n.', 'Such conditions may lead to an increase in pressure, which may potentially cause tubing, tools, and drilling fluid to be blown out of the well bore \n20\n, or otherwise components of the wall \n12\n.', 'When these conditions occur, one or more of the BOPs \n48\n, \n50\n may be used to temporarily or permanently block or restrict fluid flow through one or more passages of the BOP stack \n46\n.', 'The BOP stack \n46\n may include one or more modules \n52\n that assist in control or otherwise facilitate operation of the BOPs \n48\n, \n50\n.', 'These modules \n52\n may include ancillary systems and/or primary systems.', 'Ancillary systems may be defined as one or more modules that can be added to an existing BOP stack.', 'Ancillary systems may include, for example, accumulators, filters, rigid conduit manifolds, deadman/autoshear systems (DMAS), regulators, acoustic controls, pilot modules, sensor packages, command systems, junction systems, battery systems, etc.', 'Primary systems are modules or groups of modules that are included in a BOP stack by design from the outset.', 'Primary systems, beyond those listed as examples of ancillary systems, and may potentially include, for example, intervention/non-standard control systems, such as non-drilling control and seabed intervention, as well as various BOP control systems.', 'As illustrated in \nFIG.', '1\n, the modules \n52\n may be installed or retrieved individually or in groups by an underwater vehicle, in this instance a remotely operated underwater vehicle (ROV) \n54\n.', 'It should be understood, however, that the disclosed techniques may be applied to underwater vehicles beyond ROVs.', 'Accordingly, though the disclosed embodiments use ROVs, it should be understood that embodiments using other classes of underwater vehicles (such as autonomous underwater vehicles (AUVs) and the like) are also envisaged.', 'The ROV \n54\n may be in communication with the rig \n40\n via an umbilical cord \n56\n.', 'The umbilical cord \n56\n may provide power, control signals, data, etc. to the ROV \n54\n.', 'In some embodiments, the ROV \n54\n travels back and forth between the rig \n40\n and the well head assembly \n14\n to deposit and retrieve modules \n52\n, or otherwise service the well head assembly \n14\n.', 'In other embodiments, an intermediate docking station \n58\n may provide a place to temporarily store modules \n52\n and/or dock the ROV \n54\n when not in used.', 'In such embodiments, a second ROV \n54\n, or the single ROV \n54\n may be used shuttle payloads between the rig \n40\n and the intermediate docking station \n58\n, and between the intermediate docking station \n58\n and the wellhead assembly \n14\n.', 'Typically, when a component of the BOP stack \n46\n needs servicing, the well \n12\n has to be taken off-line and the entire BOP stack \n46\n has to be retrieved to the surface \n42\n.', 'Once at the surface \n42\n, the BOP stack \n46\n is inspected and the problem is identified.', 'In some cases, replacement parts may need to be ordered and delivered.', 'The parts in question are replaced and tests are performed.', 'Once the BOP stack \n46\n is repaired, the whole BOP stack \n46\n is returned to the sea floor \n16\n and operations are resumed.', 'This process leaves the well \n12\n off-line for one week, two weeks, three weeks, or even longer.', 'Further, because repairs and maintenance to the BOP stack \n46\n take the well \n12\n off-line for long periods of time, an operator may wait to make repairs or perform maintenance until multiple operations need to be performed.', 'By incorporating some or all of the functions into retrievable modules, when a problem arises with a module, a replacement module may be assembled on the rig \n40\n or retrieved from storage on the rig \n40\n.', 'The ROV \n54\n may then retrieve the existing module \n52\n (e.g., needing service) and install the new replacement module \n52\n.', 'The well \n12\n may then be brought back on line after one or two days off-line.', 'In some embodiments, the well \n12\n may be able to continue on-line (e.g., no downtime), or only be off-line for a short period of time (a few seconds or minutes).', 'For examples, for some modules \n52\n (modules that are rarely used or not critical), the well \n12\n may continue on-line as the module \n52\n is removed and replaced.', 'In other embodiments, the BOP stack \n46\n may have one or more spare receptacles that allow the replacement module \n52\n to be installed before the existing module \n52\n is replaced, resulting in little or no time off-line.', 'With the well \n12\n back on line, the removed module \n12\n may be inspected, the problem identified, and replacement parts ordered if necessary.', 'In other embodiments, modules \n52\n may be used to customize the BOP stack \n46\n or to add functionality to an existing BOP stack \n46\n.', 'FIG.', '2\n is a schematic of a module \n52\n as shown in the BOP stack \n46\n of \nFIG.', '1\n.', 'As illustrated, the module \n52\n is built around a chassis core \n100\n, which includes a frame \n102\n, to which various components may be mounted.', 'In the illustrated embodiment, the frame \n102\n is generally box-shaped, however the frame \n102\n may be any shape.', 'In some embodiments, a control system \n104\n may be coupled to the frame \n102\n and may be configured to control the operation of the module \n52\n.', 'The frame \n102\n may include interface geometry, such as tabs, tracks, tapered grooves, indentions, detents, snap fittings, guides, rails, brackets, etc. that act as an interface between the frame \n102\n and the BOP stack \n46\n, or components/modules that couple to the frame \n102\n.', 'The control system \n104\n may include various electronic, such as, for example, a processor \n106\n, a memory component \n108\n, and one or more sensors \n110\n.', 'The processor \n106\n may receive data from the sensors \n110\n distributed throughout the module \n52\n, or access data stored on the memory component \n108\n, run programs stored on the memory component \n108\n, and then control the operation of the module \n52\n by generating control signals.', 'In some embodiments, data may be processed and then stored on the memory component \n108\n.', 'The module \n52\n may also include one or more sub-modules or components \n112\n coupled to the chassis core \n102\n.', 'The sub-modules \n112\n or components may be one or more families of assemblies sharing common shapes, dimensions, sizes, connectors, etc.', 'As previously discussed, modules may be designed and assembled to perform a wide range of functions for the BOP stack \n46\n.', 'As such, the rig \n40\n may have a supply of spare subcomponents \n112\n and other miscellaneous module \n52\n components such that a spare module \n52\n may be assembled on the rig \n40\n when a module \n52\n malfunctions, or such that in the event of a module \n52\n malfunction, the malfunctioning module \n52\n may be replaced with the spare module \n52\n by the ROV \n54\n, minimizing the amount of time that the well \n12\n is off-line.', 'Accordingly, the functionality of the various sub-modules \n112\n may vary dependent upon the intended function of the module \n52\n.', 'For example, the sub-modules \n112\n may include valves, filters, batteries, hydraulic accumulators, batteries, capacitors, fluid conduits, manifolds, electronics, sensors, transducers, switches, ram blocks, various control systems, timing systems, counters, triggers, seals, connectors, various electronic, pneumatic, hydraulic, or plumbing components, additional components, or some combination thereof.', 'Further, the equipment to perform some functions of the BOP stack \n46\n may be spread across multiple modules, to increase modularity, because the equipment may not fit within the footprint of the module \n52\n, or for some other reason.', 'Accordingly, the number of possible module \n52\n configurations, each heaving a different combinations of sub-modules is nearly infinite.', 'Specific examples of a few possible module \n52\n configurations are discussed in more detail below.', 'However, it should be understood that these described embodiments are just a few possible examples of many envisaged possible embodiments.', 'The various sub-modules \n112\n may be in communication (e.g., electronic, hydraulic, fluid, pneumatic, etc.) with one another and/or with adjacent modules.', 'Accordingly, the module \n52\n may include fluid conduits \n114\n (e.g., hydraulic conduits, pneumatic conduits, plumbing conduits) and electrical lines \n116\n distributed throughout the module \n52\n, connecting various sub-modules \n112\n and/or the module control system \n104\n.', 'Fluid connectors \n118\n and electrical connectors \n120\n may removably couple the fluid conduits \n114\n and the electrical lines \n116\n to adjacent modules \n52\n or to other components within the BOP stack \n46\n.', 'Each connector \n118\n, \n120\n may include a male connector configured to mate with a female connector, or vice versa.', 'The connectors \n118\n, \n120\n may include, for example, wet-mate connectors, inductive couplers, packer seals, hydraulic couplers, valves, etc.', 'Though only a single fluid connector \n118\n and a single electrical connector \n120\n are shown on each side of the module \n52\n, it should be understood that this is for simplicity and clarity and that each set of connectors \n118\n, \n120\n and conduits \n114\n, \n116\n may include multiple connectors \n118\n, \n120\n and multiple conduits \n114\n, \n116\n.', 'For example, a shuttle valve module \n52\n may include two fluid input connectors \n118\n and one fluid output connector \n118\n.', 'Further, if the module has hydraulic connectors and plumbing connectors for fluid, the module may include multiple sets of fluid conduits \n114\n and fluid connectors \n118\n, each including one or more fluid connectors \n118\n and one or more conduits \n114\n, for each type of fluid.', 'Similarly, the module \n52\n may include multiple sets of electrical connectors \n120\n and electrical lines \n116\n for different functions (e.g., power, communication, control, etc.).', 'The module \n52\n also includes one or more mechanical connectors or latches \n122\n, which facilitate coupling of the module \n52\n to the BOP stack \n46\n.', 'Each connector \n122\n may include a male connector configured to mate with a female connector, or vice versa.', 'In some embodiments, the BOP stack \n46\n may include complimentary geometry or latches that interface with the latches \n122\n to couple the module \n52\n to the BOP stack \n46\n.', 'In other embodiments, the latches \n122\n may merely couple to a component of the BOP stack \n46\n without the use of a complimentary part on the BOP stack \n46\n.', 'The module \n52\n may be deposited in or retrieved from the BOP stack \n46\n by the ROV \n54\n.', 'Accordingly, the module \n52\n may include interfacing geometry configured to interface with the ROV \n54\n (e.g., a tool interface).', 'In the illustrated embodiment, the module \n52\n has a torque tool bucket \n124\n disposed opposite the latches \n122\n, which interfaces with a torque tool of the ROV \n54\n.', 'Though the illustrated embodiment utilizes a torque tool and torque tool bucket \n124\n, it should be understood that other assemblies may be used as an interface between the module \n52\n and the ROV \n54\n.', 'As is discussed in more detail below, the module \n52\n may also include a floatation device \n126\n for managing the buoyancy of the module \n52\n as the ROV \n54\n carries the module \n52\n between the wellhead assembly \n14\n and the rig \n40\n of the intermediate docking station \n58\n.', 'Specifically, the ROV \n54\n may have thrusters capable of controlling the depth of the ROV as long as the ROV is within a threshold value of neutrally buoyant.', 'As such, when the ROV \n54\n picks up or drops off the module \n52\n, the buoyancy of the package (i.e., the ROV \n54\n and its payload) may move outside the buoyancy window in which the ROV \n54\n can control its own depth.', 'For example, when the ROV \n54\n deposits the module \n52\n, the reduction in mass of the package may cause the buoyancy of the ROV \n54\n to rise above the threshold value of neutrally buoyant such that the thrusters would be unable to control the depth of the ROV \n54\n as it floats away.', 'Correspondingly, when the ROV \n54\n retrieves the module \n52\n, the increase in mass of the package may cause the buoyancy of the ROV \n54\n to drop below the threshold value of neutrally buoyant such that the thrusters would be unable to lift the ROV \n54\n back up to the rig \n40\n or the intermediate docking station \n58\n.', 'Attaching the floatation device \n126\n to the module \n52\n to offset the lack of buoyancy due to the weight of the module \n52\n helps to mitigate the increase in buoyancy associated with dropping off the module \n52\n and the reduction in buoyancy associated with picking up the module \n52\n.\n \nFIG.', '3\n is a perspective view of an embodiment of a filter module \n150\n.', 'The filter module may be configured to receive fluid via one or more fluid inlets, filter the fluid, and output fluid via one or more fluid outlets.', 'As illustrated, the filter module \n150\n includes four submodules \n112\n, in this embodiment filter manifolds \n152\n, which may be fluidly coupled to one another via junction manifolds \n154\n.', 'As will be described in more detail below, based on the how the filter manifolds \n152\n are configured and coupled to one another via the chassis core \n100\n and the junction manifolds \n154\n, the filter manifolds \n152\n may be aligned in series, in parallel, or some combination thereof, along a fluid flow path through the module \n150\n.', 'The filter module \n150\n also includes a differential pressure gauge \n156\n, which may measure pressure differences between one or more fluid inlets of the module \n150\n and one or more outlets of the module \n150\n, or various locations along one or more fluid flow paths through the filter module \n150\n.', 'In some embodiments, the filter module \n150\n may also include one or more sensors \n110\n distributed throughout the filter module \n150\n, for example to measure the cleanliness of fluid and/or filter performance in the module \n150\n.', 'For example, the sensors \n110\n may include pressure sensors, particulate content, or concentration sensors, viscosity sensors, flow rate sensors, or any combination thereof.', 'By further example, two or more sensors \n110\n of the same type may be used to determine a change in the sensed parameter through the module \n150\n between the inlets and outlets.', 'Based on measurements taken by the sensors \n110\n, decisions may be made regarding when to replace filters \n152\n, the position of valves that control flow rates through the module \n150\n, etc.\n \nThe filter module \n150\n also includes the torque tool bucket \n124\n, which interfaces with a torque tool of the ROV \n54\n to couple and decouple the filter module \n150\n from the ROV \n54\n.', 'As previously discussed, the filter module \n150\n also includes the floatation device \n126\n, in this embodiment a block of syntactic foam.', 'The floatation device \n126\n increases the buoyancy of the filter module \n150\n, such that the ROV \n54\n is capable of shuttling the filter module \n150\n between the rid \n40\n (or the intermediate docking station \n58\n) and the wellhead assembly \n14\n.\n \nFIG.', '4\n is an exploded view of an embodiment of the filter module \n150\n shown in \nFIG.', '3\n.', 'As previously described, the filter manifolds are disposed about the chassis core \n100\n and coupled to one another via the junction manifolds \n154\n.', 'In some embodiments, sealing members \n155\n (e.g., seal subs) may be disposed at the interfaces between filter manifolds \n152\n and junction manifolds \n154\n.', 'A fluid flow is received from the BOP stack \n46\n or from an adjacent module \n52\n via packer seals \n158\n at one or more fluid inlets \n160\n.', 'One or more of the filter manifolds include a filter bowl \n162\n, which contains a filter element \n164\n, coupled to the filter manifold \n152\n via a collar \n166\n.', 'The various filter manifolds \n152\n may have the same filter elements \n164\n or different filter elements \n164\n (e.g., filter elements of different coarseness to filter different sized particulate, or filter elements designed to filter out different substances).', 'The fluid may follow a fluid flow path through the various filter manifolds \n152\n and junction manifolds \n154\n toward one or more fluid outlets \n167\n, which may include packer seals \n158\n.', 'Auxiliary mounting plates \n168\n may be coupled to one or more sides of the chassis core \n100\n for mounting various additional components.', 'For example, in the instant embodiment, an auxiliary mounting plate \n168\n is mounted to the top of the chassis core \n100\n and configured to couple to the floatation device \n126\n via one or more fasteners \n170\n.', 'A second auxiliary mounting plate \n168\n may be mounted to the bottom of the chassis core \n100\n and configured to couple to a module guide \n172\n (e.g., axial guide) and a pair of primary runners \n174\n (e.g., friction reducing axial slides), which may help guide alignment and/or provide smooth movement (e.g., reduced friction) of the module \n150\n during installation into a receptacle in the ROV \n54\n or the BOP stack \n46\n.', 'In some embodiments, secondary runners may also be mounted on various sub-modules \n112\n or components of the module \n52\n.', 'For example, in the illustrated embodiment, secondary runners \n176\n (e.g., friction reducing axial slides) are mounted to the bottoms of two of the filter manifolds \n152\n to further facilitate installation of the filter module \n150\n.', 'The module guide \n172\n and the runners \n174\n, \n176\n may be made of the same materials or different materials.', 'For example, the module guide \n172\n and the runners \n174\n, \n176\n may be made of a low-friction polymer, such as Polyoxymethylene (POM, also known as acetal, polyacetal, and polyformaldehyde), Polytetrafluoroethylene (PTFE), a metal, or some other material.', 'As shown, the torque tool bucket \n124\n extends into the chassis core \n100\n.', 'The torque tool bucket \n124\n is configured to interface with the torque tool of the ROV \n54\n as the ROV couples to, and decouples from, the filter module \n150\n.', 'At a front end \n178\n of the torque tool bucket \n124\n is a latch \n180\n (e.g., a parker latch), which may be actuated by the ROV \n54\n.', 'At a back end \n182\n of the torque tool bucket \n124\n is a latch stab \n184\n, which actuates a latch for coupling the filter module \n150\n to the BOP stack \n46\n.', 'It should be understood that the filter module \n150\n shown in \nFIG.', '4\n is merely one possible envisaged embodiment and is not intended to limit the scope of the claims.', 'Accordingly, the disclosed techniques may be utilized in modules \n52\n having different components in different configurations, for performing different functions.', 'Further, one or more submodules may be used for each of the elements, flow paths (e.g., serial or parallel), etc., enabling customization of the module onsite (e.g., on the rig) for a desired purpose.', 'FIGS.', '5-8\n illustrate four of many possible envisaged configurations of the filter module \n150\n.', 'FIG.', '5\n is a schematic of a flow path through an embodiment of the filter module \n150\n.', 'As illustrated, three filters \n164\n and the differential pressure gauge \n156\n are in parallel with one another.', 'Fluid enters the filter module \n150\n via the inlet \n160\n, flows through one of the three filters \n164\n, and then exits the filter module \n150\n via the exit \n167\n.', 'Based on the readings of the differential pressure gauge \n156\n (e.g., differential pressure between inlet and outlet increases as filters \n164\n clog) may be used to determine when filters \n164\n should be cleaned or replaced.\n \nFIG.', '6\n is a schematic of a flow path through an embodiment of the filter module \n150\n.', 'Fluid enters the filter module \n150\n via the inlet \n160\n, flows through a coarse filter \n200\n (e.g., a screen that filters out larger particulate) and then proceeds through one of two fine filters \n202\n (e.g., filtering out smaller particulate) in parallel.', 'The fluid exits the filter module \n150\n via the exit \n167\n.', 'The differential pressure gauge \n156\n is fluidly coupled to the fluid flow path upstream of the coarse filter \n200\n and downstream of the fine filters \n202\n.', 'Based on the readings of the differential pressure gauge \n156\n (e.g., differential pressure between inlet and outlet increases as filters \n164\n clog) may be used to determine when filters \n164\n should be cleaned or replaced.\n \nFIG.', '7\n is a schematic of first and second flow paths \n204\n, \n206\n through an embodiment of the filter module \n150\n.', 'Fluid enters the filter module \n150\n via one or two inlets \n160\n, flows through two filters \n164\n in series and then exits the filter module \n150\n via one of two exits \n167\n.', 'In the illustrated embodiment, the two flow paths \n204\n, \n206\n are totally separate from one another.', 'The filter module shown in \nFIG.', '7\n also lacks a differential pressure gauge \n156\n.\n \nFIG.', '8\n is a schematic of first and second flow paths \n204\n, \n206\n through an embodiment of the filter module \n150\n.', 'Fluid enters the filter module \n150\n via one or two inlets \n160\n, flows through one of two filters \n164\n in parallel and then exits the filter module \n150\n via one of two exits \n167\n.', 'In the illustrated embodiment, the two flow paths \n204\n, \n206\n are totally separate from one another.', 'The filter module shown in \nFIG.', '7\n also lacks a differential pressure gauge \n156\n, through some embodiments may include a differential pressure gauge \n156\n.', 'The filter modules \n150\n shown in \nFIGS.', '3-8\n represent one of many possible functions that may be performed by the modules \n52\n of the BOP stack \n46\n.', 'It is also envisaged that one or more modules \n52\n may perform the functions of the deadman/autoshear systems (DMAS) of the BOP stack \n46\n.', 'The deadman system monitors the condition of the primary control system.', 'During normal operations, the DMAS is activated (e.g., “armed”) and prepared for actuation (e.g. “firing”).', 'In the event of a loss of power, control signals, or hydraulic supply, the DMAS is actuated (e.g., “fired”).', 'The autoshear system monitors the connection between the lower marine riser package (LMRP) and the lower BOP stack.', 'If the DMAS is activated and the LMRP separates from the lower BOP stack when the system is armed, the DMAS actuates, or fires, cutting the wellbore \n20\n and sealing the well \n12\n.', 'FIGS.', '9-11\n illustrate various possible embodiments of a DMAS made of one or more modules \n52\n.', 'In general, when the DMAS is armed, an arm/disarm valve is opened, exposing stored hydraulic energy (e.g., from a hydraulic accumulator) to a trigger valve.', 'If a triggering event occurs, the trigger valve opens, cutting the wellbore \n20\n and sealing the well \n12\n by actuating a plurality of shear rams.', 'In some embodiments, the actuation of each of the shear rams may be temporally staggered by a timer.\n \nFIG.', '9\n is a schematic of a DMAS module \n250\n having a single ram block.', 'The various components of the DMAS module \n250\n are disposed about the chassis core \n100\n and may be divided into multiple sub-modules \n112\n.', 'The DMAS module \n250\n acts as a control node for charging and venting one or more hydraulic accumulators \n251\n.', 'A set of supply check valves \n252\n allow various sources \n254\n to charge the hydraulic accumulators via the hydraulic manifold \n251\n.', 'These sources \n254\n may be from the primary control system, the ROV \n54\n, or some other source \n254\n.', 'An accumulator pressure gauge \n256\n monitors pressure in the hydraulic accumulator \n251\n.', 'If the pressure in the hydraulic accumulator is higher than desired, an accumulator dump valve \n258\n may be actuated (e.g., based on signals from the primary control system or the ROV \n52\n) to vent hydraulic fluid (e.g., via a vent port \n260\n) to reduce pressure in the accumulator \n251\n.', 'An arm/disarm valve \n262\n may be actuated based on arm signals and disarm signals received from the primary control system or the ROV \n52\n.', 'When the arm/disarm valve is open (i.e., DMAS is armed), the hydraulic fluid is exposed to a trigger valve \n264\n.', 'During operation, one or more signals are monitored.', 'When one of the monitored signals meets certain conditions (e.g., threshold exceeded, signal drops out, etc.), a quick dump valve \n266\n closes, in turn opening the trigger valve \n264\n and causing the ram \n268\n to close, shearing the borehole \n20\n and sealing the well \n12\n.', 'In some embodiments, a ram close/lock mechanism \n270\n may lock the ram \n268\n.', 'The module \n250\n may also include a DMAS arm indicator \n272\n (e.g., a sensor) to determine the position of the ram \n268\n arm.\n \nFIG.', '10\n is a schematic of a two-ram DMAS \n300\n having first and second modules \n302\n, \n304\n.', 'For a DMAS \n300\n with multiple rams, non-sealing (e.g., non-locking) rams are fired (e.g., actuated)', 'first and then a locking ram is fired (e.g., actuated) on a delay.', 'Accordingly, the first module \n302\n is much like the DMAS module \n250\n shown and described with regard to \nFIG.', '9\n, except that the ram close/lock mechanism \n270\n is moved to the second module \n304\n, because the ram \n268\n of the first module \n302\n is a non-locking ram.', 'As with the single DMAS \n250\n of \nFIG.', '9\n, for the DMAS \n300\n, when the arm/disarm valve \n262\n of the first module \n302\n is armed, the entire DMAS \n300\n is armed (i.e., both rams are armed).', 'When the one or more monitored signals meet the conditions discussed above (e.g., threshold exceeded, signal drops out, etc.), a signal is sent to the second module \n304\n, opening a time trigger \n306\n, which starts a timer \n308\n.', 'When the timer \n308\n expires, a trigger valve \n264\n for the second ram \n310\n is opened, closing the second ram \n310\n.', 'As previously discussed, the second ram is a locking ram, so the second module \n304\n includes the ram close/lock mechanism \n270\n.', 'It should be understood that these techniques may be used to build a DMAS \n300\n having any number of rams, where the number of modules is equal to the number of rams and the last ram is a locking ram, such that the module for the last ram includes the ram close/lock mechanism \n270\n.', 'In some embodiments, it may be desirable to lock the locking ram \n310\n after a given period of time has passed after the locking ram \n310\n has been actuated.', 'In such an embodiment, a second timer \n308\n may be used.', 'FIG.', '11\n is a schematic of an embodiment of the two-ram DMAS \n300\n with dual timers \n308\n.', 'As shown, the second ram \n310\n and trigger valve \n264\n for the second ram \n310\n are shifted from the second module \n304\n to the first module \n302\n to make room for the second timer \n308\n.', 'When the trigger valve \n264\n for the second ram \n310\n opens to close the second ram \n310\n, the second timer \n308\n is started.', 'When the second time \n308\n expires, the ram close/lock mechanism \n270\n is actuated to lock the second ram block \n310\n.', 'It should be understood that \nFIGS.', '9-11\n illustrated several different embodiments of a DMAS made of multiple submodules \n112\n distributed across one or more modules \n52\n.', 'It should be understood that the various submodules \n112\n may be replaced or built up on site (e.g., on the rig) according to the design of the specific BOP stack \n46\n design.', 'As such, the number of rams, the type of rams, timers, etc. may be customized in each module \n52\n via the selection of submodules \n112\n according to the specific BOP stack \n46\n design.', 'However, the illustrated embodiments are not intended to limit the claimed subject matter.', 'As such, various other embodiments of the DMAS having function submodules, timing submodules, and accumulator control submodules \n112\n are envisaged.', 'It is also envisaged that one or more modules \n52\n may perform the functions of rigid conduit manifold (RCM) of the BOP stack \n46\n.', 'The RCM acts as a distribution node for hydraulic fluid sent from the rig \n40\n via rigid conduits that run parallel to the riser \n38\n.', 'The hydraulic fluid is supplied via two rigid conduits, one for each side of the control system (e.g., “blue” and “yellow”).', 'Each conduit may have its own RCM, or the conduits may share an RCM. \nFIG.', '12\n is a schematic of an embodiment of an RCM \n350\n distributed over first and second modules \n352\n, \n354\n.', 'In the illustrated embodiment, each conduit has its own RCM \n350\n.', 'In general, the RCM \n350\n receives hydraulic fluid from the rig \n40\n, and can either block the flow path, stopping the flow of hydraulic fluid, or route the flow of hydraulic fluid along one of several possible flow paths.', 'As shown, hydraulic fluid is received via the hydraulic fluid inlet \n356\n.', 'In some embodiments, the hydraulic fluid may pass through a trash trap \n358\n, which catches debris flowing with the fluid.', 'A flush valve \n360\n may control the flow of fluid to flush outlet \n362\n (e.g., to the ROV \n54\n) to flush out the conduits.', 'The first module \n352\n of the RCM \n350\n may also include a filter \n364\n through which hydraulic fluid flows before proceeding to the various accumulators and associated hardware.', 'As illustrated, the first module \n352\n includes a rigid conduit isolate valve \n366\n and a hotline isolate valve \n368\n.', 'The rigid conduit isolate valve \n366\n closes to stop fluid flow through the associated rigid conduit.', 'The hotline isolate valve \n368\n to isolate supply from the hotline to the main system supply.', 'The RCM \n350\n has an opposite conduit valve \n372\n that controls fluid flow to the opposite conduit (e.g., via the opposite conduit coupling \n374\n) and an accumulator charge valve \n376\n, which controls fluid flow to one or more accumulators via the outlet \n378\n.', 'Returning to the submodule \n112\n with the trash trap \n358\n and the flush valve \n360\n, the first module \n352\n of the RCM \n350\n has an unregulated supply valve \n382\n that provides an unregulated supply of fluid via the unregulated supply outlet \n382\n.', 'Alternatively, a regulated supply valve \n384\n provides a fluid supply to the second module \n354\n of the RCM \n350\n, which includes a flow regulator \n386\n.', 'The regulated fluid flow is then provided via a regulated supply outlet \n388\n.', 'It should be understood, however, that the RCM \n350\n shown in \nFIG.', '12\n is just one possible embodiment of many envisaged embodiment.', 'As previously discussed, it should be understood that DMAS/RCM systems may include one or more modules \n52\n, each including one or more submodules \n112\n that can be selected and build up onsite according to the design of the specific BOP stack \n46\n design.', 'For example, some of the valves of the first module \n352\n may be moved to the second module \n354\n.', 'Similarly, other embodiments of the RCM may include fewer components, additional components, or different configurations of components.', 'Another function of the BOP stack \n46\n that can be modularized is shuttle valves.', 'Shuttle valves receive two fluid flows via two inlets and, based on the position of the shuttle, allow one of the two fluid flows to flow through the valve to an outlet.', 'Typically, unbiased shuttle valves allow the inlet fluid flow with the higher pressure to pass through the valve.', 'In most cases, a BOP stack \n46\n has a single active side (e.g., blue or yellow).', 'When a function is fired, the shuttle valve typically sees the signal coming from the fluid inlet associated with the active side, while the other fluid inlet is at approximately zero psig.', 'FIGS.', '13-15\n illustrate a few envisaged embodiments of a shuttle valve module \n400\n.', 'FIG.', '13\n is a perspective view of an embodiment of the shuttle valve module \n400\n.', 'As with some of the previously described modules \n52\n, the shuttle valve module \n400\n includes one or more submodules \n112\n coupled to the frame \n102\n of the chassis core \n100\n.', 'The shuttle valve module \n400\n interfaces with the ROV \n54\n via the torque tool bucket \n124\n, which is coupled to the frame \n102\n.', 'The floatation device \n126\n is also coupled to the frame \n102\n.', 'In the instant embodiment, the shuttle valve module \n400\n includes four submodules \n112\n, in this case shuttle valve submodules \n402\n.', 'Each shuttle valve submodule \n402\n includes two inlets \n404\n and one outlet \n406\n.', 'Inside each shuttle valve submodule \n402\n, a shuttle shifts between first and second positions.', 'When the shuttle is in the first position, the shuttle valve submodule \n402\n fluidly couples the first inlet \n404\n and the outlet \n406\n, allowing fluid to flow into the first inlet \n404\n, through the shuttle valve submodule \n402\n, and out of the outlet \n406\n.', 'When the shuttle is in the second position, the shuttle valve submodule \n402\n fluidly couples the second inlet \n404\n and the outlet \n406\n, allowing fluid to flow into the second inlet \n404\n, through the shuttle valve submodule \n402\n, and out of the outlet \n406\n.\n \nFIG.', '14\n is a perspective view an embodiment of the shuttle valve module \n400\n shown in \nFIG.', '13\n.', 'As illustrated, the module \n400\n includes a module guide \n172\n, as well as primary and secondary runners \n174\n, \n176\n to facilitate installation and removal of the module \n400\n in the BOP stack \n46\n by the ROV \n54\n. \nFIG.', '15\n is a schematic of an embodiment of the shuttle valve module \n400\n shown in \nFIGS.', '13 and 14\n.', 'As illustrated, each of the four shuttle valve submodules \n402\n includes a shuttle valve \n408\n with a shuttle \n410\n that moves between first and second positions.', 'When the shuttle \n410\n is in the first position, fluid flows from the first inlet \n404\n to the outlet \n406\n.', 'When the shuttle \n410\n is in the second position, fluid flows from the second inlet \n404\n to the outlet \n406\n.', 'Though the shuttle valve module \n400\n includes four shuttle valve submodules \n402\n, each having a shuttle valve \n408\n, it should be understood that the shuttle valve module \n400\n may include a different number of shuttle valve submodules \n402\n, and that each shuttle valve module \n402\n may include more than one shuttle valve \n408\n.', 'As such, the shuttle valve module may be built up with various submodules \n112\n (e.g., shuttle valve submodules \n402\n) according to the design of the specific BOP stack \n46\n design.', 'As such, the embodiments of the shuttle valve module \n400\n shown in \nFIGS.', '13-15\n are merely examples of many possible embodiments of the shuttle valve module \n400\n and not intended to limit the scope of the claims.', 'The energy storage functionality of the BOP stack \n46\n may also be modularized.', 'FIGS.', '16-18\n illustrated a few envisaged embodiments of an electrical energy storage module \n450\n.', 'Without the disclosed embodiments, the various components of the BOP stack \n46\n draw power from an electrical energy storage device, such as a battery or a capacitor integrated within the BOP stack.', 'To change the battery or capacitor, the well \n12\n is taken off-line, the entire BOP stack \n46\n may be disconnected and retrieved.', 'The batteries and/or capacitors are then changed out.', 'The BOP stack \n46\n is then returned to the sea floor \n16\n, reinstalled, and drilling is resumed.', 'Batteries and capacitors on the BOP stack \n46\n typically last a matter of weeks or months.', 'Because changing the batteries and/or capacitors is such a significant undertaking, taking the well \n12\n off-line for as long as 10-15 days, electrical energy draw for each component is kept as low as possible.', 'By modularizing the electrical energy storage function of the BOP stack \n46\n, the batteries and/or capacitors of a BOP stack \n46\n can be retrieved and replaced by an ROV in a day or two rather than 10-15 days.', 'FIG.', '16\n is a perspective view of the electrical energy storage module \n450\n.', 'As illustrated, a plurality of electrical energy storage submodules \n452\n are coupled to the frame \n102\n of the chassis core \n100\n.', 'As previously discussed, the energy storage module \n450\n may be customized by selecting various electrical energy storage submodules \n452\n.', 'In some embodiments, the energy storage module \n450\n may include multiple redundant batteries and/or multiple receptacles to allow installation of multiple batteries.', 'The torque tool bucket \n124\n is coupled to the chassis core \n100\n and provides an interface for the ROV \n54\n.', 'The floatation device \n126\n helps to manage the buoyancy of the electrical energy storage module \n450\n.', 'Each of the electrical energy storage submodules \n452\n includes one or more batteries and/or one or more capacitors configured to store electrical energy.', 'When the electrical energy storage module \n450\n is installed, various components of the BOP stack draw power from the batteries and/or capacitors.', 'After the stored electrical energy is depleted, or after a set period of time, the electrical energy storage module \n450\n may be retrieved and replaced by an ROV with one or more “charged” electrical energy storage modules \n450\n.', 'FIG.', '17\n is a perspective view an embodiment of the electrical energy storage module \n450\n shown in \nFIG.', '16\n.', 'As illustrated, the module \n450\n includes a module guide \n172\n, as well as primary and secondary runners \n174\n, \n176\n to facilitate installation and removal of the module \n450\n in the BOP stack \n46\n by the ROV \n54\n.', 'The electrical energy storage module \n450\n also includes one or more electrical connectors \n120\n for an interface between the electrical energy storage module \n450\n and the BOP stack \n46\n.', 'Accordingly, the electrical energy storage module \n450\n may provide electrical power for various components within the BOP stack \n46\n via the one or more electrical connectors \n120\n.\n \nFIG.', '18\n is a schematic of an embodiment of the electrical energy storage module \n450\n shown in \nFIGS.', '16 and 17\n.', 'As illustrated, each of the one or more electrical energy storage submodules \n452\n may include one or more batteries, capacitors, fuel cells, etc. \n454\n that store electrical energy.', 'The various batteries and/or capacitors \n454\n may be electrically coupled, either directly or indirectly to one or more electrical connectors \n120\n.', 'When the electrical energy storage module \n450\n is installed in the BOP stack \n46\n, the electrical connector \n120\n may interface with a complimentary electrical connector \n120\n on the BOP stack \n46\n to provide electrical energy to one or more components of the BOP stack \n46\n.', 'Because modularizing the electrical energy storage functions of the BOP stack \n46\n makes changing out the batteries and/or capacitors \n454\n much faster than previously possible, electrical energy draw of the components of the BOP stack may become a less important design factor.', 'As with the electrical energy storage functionality of the BOP stack \n46\n, the hydraulic energy storage functionality of the BOP stack \n46\n may also be modularized.', 'FIGS.', '19-21\n illustrate several embodiments of a hydraulic energy storage module \n500\n.', 'As previously discussed, the BOP stack \n46\n may have many components (e.g., BOP rams, valves, various actuators, pumps, etc.) that are hydraulically actuated.', 'As such, these components draw hydraulic energy from hydraulic energy storage devices, such as gas-over hydraulic accumulators, spring loaded hydraulic accumulators, intensifiers or de-boost devices. \nFIG.', '19\n is a perspective view of an embodiment of the hydraulic energy storage module \n500\n.', 'As illustrated, a plurality of hydraulic energy storage submodules \n502\n are coupled to the frame \n102\n of the chassis core \n100\n.', 'As with the other modules \n52\n discussed, the hydraulic energy storage module \n500\n may be customized by selecting the appropriate hydraulic energy storage submodules \n502\n to achieve the desired functionality when the BOP stack \n46\n is being designed.', 'The hydraulic energy storage module \n500\n may then be built up using various hydraulic energy storage submodules \n502\n according to the design of the specific BOP stack \n46\n design.', 'The torque tool bucket \n124\n is coupled to the chassis core \n100\n and provides an interface for the ROV \n54\n.', 'The floatation device \n126\n helps to manage the buoyancy of the hydraulic energy storage module \n500\n.', 'Each of the hydraulic energy storage submodules \n502\n includes one or more hydraulic accumulators, intensifiers or de-boost devices configured to store hydraulic energy and one or more hydraulic ports \n504\n.', 'When the hydraulic energy storage module \n500\n is installed, various components of the BOP stack draw hydraulic power from the accumulators, intensifiers or de-boost devices.', 'After a set amount of the stored hydraulic energy us dissipated, or after a set period of time, the hydraulic energy storage module \n500\n may be retrieved and replaced by an ROV.\n \nFIG.', '20\n is a perspective view an embodiment of the hydraulic energy storage module \n500\n shown in \nFIG.', '19\n.', 'As illustrated, the module \n500\n includes a module guide \n172\n, as well as primary and secondary runners \n174\n, \n176\n to facilitate installation and removal of the module \n500\n in the BOP stack \n46\n by the ROV \n54\n.', 'The hydraulic energy storage module \n500\n also includes one or more hydraulic ports \n504\n as an interface between the hydraulic energy storage module \n500\n and the BOP stack \n46\n.', 'Accordingly, the hydraulic energy storage module \n500\n may provide hydraulic power for various components within the BOP stack \n46\n via the one or more hydraulic ports \n504\n.\n \nFIG.', '21\n is a schematic of an embodiment of the hydraulic energy storage module \n500\n shown in \nFIGS.', '19 and 20\n.', 'As illustrated, each electrical energy storage submodule \n502\n includes one or more (e.g., three) chambers \n506\n that store hydraulic energy.', 'The various chambers \n506\n may be fluidly coupled, either directly or indirectly to the hydraulic ports \n504\n.', 'When the hydraulic energy storage module \n500\n is installed in the BOP stack \n46\n, the hydraulic ports \n504\n may interface with complimentary hydraulic connectors on the BOP stack \n46\n to provide hydraulic energy to one or more components of the BOP stack \n46\n.', 'Because modularizing the hydraulic energy storage functions of the BOP stack \n46\n makes changing out or charging the hydraulic energy storage devices (e.g., accumulators, intensifiers, de-boost devices, etc.) much faster than previously possible, hydraulic energy draw of the components of the BOP stack may become a less important design factor.', 'Another possible envisaged module is a subsea electronics module (SEM), which acts as a sort of brain for the BOP stack \n46\n control system.', 'FIGS.', '22-24\n illustrated several embodiments of a SEM \n550\n.', 'Without the disclosed embodiment, the SEM may be mounted in the MUX section of a subsea BOP control pod.', 'However, if the SEM malfunctions, the entire LMRP or BOP stack \n46\n must be retrieved, taking the well \n12\n off-line for as long as one to two weeks.', 'By modularizing the SEM \n46\n, the may be retrieved or replaced with an ROV \n54\n in a day or two. \nFIG.', '22\n is a perspective view of an embodiment of the SEM \n550\n.', 'As illustrated, a plurality SEM submodules \n552\n are coupled to the frame \n102\n of the chassis core \n100\n.', 'The torque tool bucket \n124\n is coupled to the chassis core \n100\n and provides an interface for the ROV \n54\n.', 'The floatation device \n126\n helps to manage the buoyancy of the SEM \n550\n.', 'Each of the SEM submodules \n552\n includes one or more chambers that house various electrical control components at approximate 1 atmosphere of pressure.', 'When the SEM \n550\n is installed, it supplies control signals to various components throughout the BOP stack \n46\n.\n \nFIG.', '23\n is a perspective view an embodiment of the SEM \n550\n shown in \nFIG.', '22\n.', 'As illustrated, the SEM \n550\n includes a module guide \n172\n, as well as primary and secondary runners \n174\n, \n176\n to facilitate installation and removal of the module \n500\n in the BOP stack \n46\n by the ROV \n54\n.', 'The SEM \n550\n also includes one or more electrical connectors \n120\n as an interface between the SEM \n550\n and the BOP stack \n46\n.', 'Accordingly, the SEM \n550\n may provide control signals for various components within the BOP stack \n46\n via the one or more electrical connectors \n120\n.\n \nFIG.', '24\n is a schematic of an embodiment of the SEM \n550\n shown in \nFIGS.', '22 and 23\n.', 'As illustrated, each SEM submodule \n552\n includes one or more chambers \n554\n that house various electrical components at approximately 1 atmosphere of pressure.', 'For example, the various electrical components may include one or more processors \n556\n (e.g., microprocessors, circuit boards, programmable logic controllers, etc.), one or more memory components \n558\n, one or more batteries or capacitors \n560\n, or some combination thereof.', 'The memory components \n558\n may store data (e.g., collected from sensors distributed throughout the BOP stack \n46\n) and/or programs, algorithms, or routines to be run by the processors \n556\n.', 'The batteries \n560\n may be the primary power source for the SEM \n550\n, or may act as a backup power source if the primary electrical power source of the BOP stack \n46\n fails.', 'When the SEM \n550\n is installed in the BOP stack \n46\n, the electrical connectors \n120\n may interface with a complimentary electrical connectors on the BOP stack \n46\n to provide control signals to one or more components of the BOP stack \n46\n.', 'Though \nFIGS.', '3-24\n illustrate a various possible embodiments for the modules \n52\n, it should be understood that the disclosed embodiments are merely examples and that many other possible embodiments of the modules \n52\n are envisaged.', 'Accordingly, the disclosed techniques may be used to modularize functions or components of the BOP stack \n46\n, such that various components may be replaced by, or various functions performed by, one or more modules \n52\n that may be retrievable by an ROV \n54\n.', 'Further, as discussed with regard to the various module \n52\n embodiments, each module \n52\n may be customized to a specific BOP stack \n46\n design by selecting various submodules \n112\n to achieve the desired functionality.', 'The submodules \n112\n may then be assembled to form a module \n52\n according to the design of the specific BOP stack \n46\n design.', 'As such, each submodule \n112\n may be designed for specific setup, component, of set of components.', 'In some embodiments, each module \n52\n or submodule \n112\n may include redundant processors, memory components, sources of energy, etc. \nFIG.', '25\n is a family tree of various embodiments of retrievable subsea BOP modules \n52\n.', 'As previously described, modules may be divided into primary systems modules \n602\n and ancillary systems modules \n604\n.', 'The primary systems modules \n602\n may include, for example, BOP control system modules \n606\n and intervention/non-standard control system modules \n608\n.', 'The BOP control systems modules \n606\n may modularize primary control functions of the BOP stack \n46\n and may include, for example, the SEM \n550\n shown and described with regard to \nFIGS.', '22-24\n.', 'However, it should be understood that the SEM is one of many possible BOP control systems modules \n606\n.', 'The intervention/non-standard control systems modules \n608\n may include, for example, non-drilling control modules \n610\n, seabed intervention (MUX/acoustic) modules \n612\n, etc.', 'The ancillary system modules \n604\n may be subdivided into hydraulic modules \n614\n, electro-hydraulic modules \n616\n, and electrical modules \n618\n.', 'Electrical modules \n618\n may include, for example, sensor packages \n620\n, command modules \n622\n, junction modules \n624\n, battery modules, etc.', 'The electro-hydraulic modules \n616\n may include, for example, acoustic controls \n628\n (including internal and/or external regulation), pilot modules \n630\n, externally piloted function modules \n632\n, etc.', 'Hydraulic modules may be further subdivided into, for example, accumulator modules \n634\n, filter modules \n636\n, rigid conduit manifold modules \n638\n, DMAS modules \n640\n, regulator modules \n642\n, and expansion modules \n644\n.', 'Emergency accumulator step down modules \n646\n may include or encompass DMAs modules \n640\n and regulator modules \n642\n.', 'DMAS modules \n640\n may further include, for example, DMAS function modules \n648\n and DMAS timing modules \n650\n, etc.', 'The regulator modules \n642\n may include, for example, hydraulic piloted (external) regulator modules \n652\n, manually set regulator modules \n654\n, etc.', 'It should be understood, however, that the various modules \n52\n shown in the family tree \n600\n of \nFIG.', '25\n do not constitute an exhaustive list of possible modules \n52\n, but is instead merely an illustrative set of examples.', 'As such, using the disclosed techniques, any component, system, or function of the BOP stack \n46\n may be modularized by distributing the associated components and/or systems across one or more ROV-retrievable modules \n52\n.', 'The ROV-retrievable modules \n52\n may interface with a frame of the BOP stack \n46\n.', 'FIG.', '26\n is a perspective view of an embodiment of a portion of the BOP stack frame \n700\n.', 'As shown, the frame \n700\n includes a module receptacle \n702\n configured to receive the module \n14\n.', 'The frame \n700\n may also include an exchange weight receptacle \n704\n configured to receive an exchange weight used to control the buoyancy of the ROV54 and its payload.', 'The specifics of the exchange weight are described below with regard to \nFIGS.', '29 and 30\n.', 'In some embodiments, the frame \n700\n may include any number (e.g., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more), size, geometry, and/or configuration of receptacles \n702\n, \n704\n.', 'The frame \n700\n includes docking hardware \n706\n, mounting hardware \n708\n, payload coupling hardware \n710\n, and exchange weight coupling hardware \n712\n configured to facilitate insertion and removal of modules \n52\n and the exchange weight via the ROV \n54\n.', 'As illustrated, the frame \n700\n includes a plurality of interconnected beams or supports, which include vertical supports \n714\n and horizontal supports \n716\n.', 'Collectively, the supports \n714\n, \n716\n of the frame \n700\n define the receptacles \n702\n and \n704\n.', 'The docking hardware \n706\n, mounting hardware \n708\n, module coupling hardware \n710\n, and exchange weight coupling hardware \n712\n are coupled to the frame \n700\n.', 'For example, the docking hardware \n706\n may include one or more docking joints or couplings \n718\n (e.g., first and second spaced couplings), which may include respective docking plates \n720\n and receptacles \n722\n (e.g., circular receptacles, indents, or passages).', 'In some embodiments, the couplings \n718\n may include male and/or female couplings \n718\n, which removably couple with docking hardware (e.g., docking joints or couplings) on the ROV \n54\n.', 'For example, the ROV \n54\n may include docking couplings (e.g., male joints, detents, or arms) that extend into and interlock with the receptacles \n722\n of the couplings \n718\n.', 'In certain embodiments, the docking couplings \n718\n include two circular receptacles \n722\n (e.g., indents) on either side of the frame \n700\n, which may interface with complementary docking hardware (e.g., two detents) on the ROV \n54\n to secure the ROV \n54\n to the frame \n700\n while the module \n52\n and/or exchange weight are being deposited or retrieved.', 'The mounting hardware \n708\n may include one or more guide rails \n724\n and module stops \n726\n.', 'The guide rails \n724\n extend lengthwise along the receptacles \n702\n, \n704\n in a direction of insertion or removal of the module \n52\n or exchange weight, while the stops \n726\n may extend crosswise into the receptacles \n702\n and \n704\n to limit a depth of insertion.', 'The module coupling hardware \n710\n and exchange weight coupling hardware \n712\n may be disposed in one or more portions of the receptacles \n702\n and \n704\n, and may include one or more joints or couplings (e.g., male and/or female couplings).', 'For example, the hardware \n710\n and \n712\n may include mating structures, such as male and female tracks or rails, male and female latch assemblies, male and female snap-fit structures, mating protrusions and recesses, mating hooks and receptacles, mating detents and indentions, magnetic couplings, or any combination thereof.', 'In certain embodiments, the frame \n700\n may include any number, size, geometry, and configuration of receptacles \n702\n and \n704\n.', 'For example, the frame \n700\n may include a plurality of uniform receptacles \n702\n and/or \n704\n, a plurality of different receptacles \n702\n and/or \n704\n, or a combination thereof.', 'By further example, the receptacles \n702\n and/or \n704\n may be arranged vertically one over another, horizontally side by side, or distributed throughout the submerged system.', 'In embodiments with equally sized receptacles \n702\n and \n704\n, the frame \n700\n is configured to facilitate exchange of equally sized modules \n52\n and exchange weights with the ROV \n54\n.', 'In embodiments with differently sized receptacles \n702\n and \n704\n, the frame \n700\n is configured to facilitate exchange of differently sized modules \n52\n and exchange weights with the ROV \n54\n; however, the ROV \n54\n may exchange multiple smaller packages (e.g., modules \n52\n and/or exchange weights) with fewer (e.g., one) larger packages (e.g., modules \n52\n and/or exchange weights) in certain applications.', 'In other words, the exchange of packages (e.g., modules \n52\n and/or exchange weights) between the ROV \n54\n and the frame \n700\n may be a ratio of greater than, less than, or equal to 1:1, 1:2, 1:3, 1:4, 1:5, 1:10, or vice versa.', 'Furthermore, the frame \n700\n may be configured to support a plurality of exchange weights in respective receptacles \n704\n, such that the ROV \n54\n may be configured to selectively retrieve one or more of the exchange weights to obtain a desired buoyancy suitable for a return trip to the surface \n42\n.', 'For example, each of the exchange weights may have an equal or different weight, which may be used alone or in combination with one another to define a desired weight when retrieved by the ROV \n54\n.', 'Similarly, each of the exchange weights may have an equal or different buoyancy, which may be used alone or in combination with one another to define a desired buoyancy when retrieved by the ROV \n54\n.', 'In certain embodiments, the exchange weights may include a solid, liquid, or gas material configured to define a desired weight or buoyancy.', 'In some embodiments, the frame \n700\n may also support components \n728\n that interface with the module once deposited in the module receptacle \n702\n.', 'For example, these components \n728\n may have fluid, hydraulic, electrical, pneumatic, or other connectors that interface with the module \n52\n.', 'Accordingly, the frame \n700\n may include mounting hardware \n730\n for mounting these components \n728\n, which may remain coupled to the frame \n700\n as the module \n52\n is deposited and retrieved.', 'Such mounting hardware \n730\n may include cross-members, brackets, etc.', 'It should be understood, however that the frame \n700\n shown in \nFIG.', '26\n is merely one possible embodiment and that other configurations are also envisaged.', 'For example, the frame \n700\n may have a different shape than the frame \n700\n shown.', 'Further, the frame \n700\n may not completely enclose the module receptacle \n702\n and/or the exchange weight receptacle \n704\n.', 'The module receptacle \n702\n and the exchange weight receptacle \n704\n may be in different positions relative to one another than shown in \nFIG.', '26\n.', 'Further, the docking hardware \n708\n may include a different number of locations (e.g., 1, 3, 4, 5, 6, 7, 8, 9, 10, or more locations), which may be positioned differently than is shown in \nFIG.', '26\n.', 'Additionally, the docking hardware \n708\n may have a different geometry and interface with the corresponding docking hardware on the ROV \n54\n in a different way than is shown in \nFIG.', '26\n.', 'In some embodiments, the frames may be equipped with electrical and/or hydraulic receivers to facilitate electrical of hydraulic connections with modules \n52\n.', 'The electrical and/or hydraulic receivers may be installed or retrieved by an ROV \n54\n.', 'FIGS.', '27 and 28\n illustrate embodiments of electrical and hydraulic receivers.', 'FIG.', '27\n is a perspective view of an electrical receiver \n750\n.', 'The electrical receiver may be disposed within the module receptacle \n702\n of a BOP stack frame \n700\n and act as an interface between the BOP stack \n46\n and the module \n52\n.', 'The electrical receiver \n750\n includes a baseplate \n752\n.', 'As shown, the base plate \n752\n may include a tapered groove \n754\n, which may interface with the module guide \n172\n of a module \n52\n to help facilitate proper installation of the module \n52\n.', 'The electrical receiver includes two side panels \n756\n extending upward from the base plate \n752\n.', 'Though not shown in \nFIG.', '27\n, in some embodiments, the side panels \n756\n may be equipped with fluid, hydraulic, pneumatic, or electrical connections.', 'A top panel \n758\n extends between the side panels \n756\n across the top of an installed module.', 'The electrical receiver \n750\n also includes a back panel \n762\n, which couples to the frame \n700\n.', 'The back panel \n760\n includes a coupling \n762\n, which may couple to the latch of the module \n52\n.', 'In some embodiments, the coupling \n762\n may only be a mechanical coupling.', 'In other embodiments, the coupling \n762\n may also include electrical, fluid, pneumatic, hydraulic couplings, or some combination thereof.', 'In the illustrated embodiment, the back panel \n760\n includes a separate electrical coupling \n764\n.', 'However, in some embodiments, the electrical coupling \n764\n may be incorporated into the coupling \n762\n.', 'FIG.', '28\n is a perspective view of a hydraulic receiver \n766\n.', 'The hydraulic receiver \n766\n may be disposed within the module receptacle \n702\n of a BOP stack frame \n700\n and act as an interface between the BOP stack \n46\n and the module \n52\n.', 'As with the electrical receiver \n750\n of \nFIG.', '27\n, the hydraulic receiver \n766\n includes a baseplate \n752\n with tapered groove \n754\n, two side panels \n756\n extending upward from the base plate \n752\n, the top panel \n758\n, and the back panel \n760\n.', 'As illustrated, the side panels \n756\n include internal hydraulic ports \n768\n and external hydraulic ports \n770\n, which may fluidly couple the hydraulic receiver \n766\n to an adjacent receiver \n766\n or module \n52\n.', 'As with the electrical receiver \n750\n, the back panel \n760\n includes a coupling \n762\n, which may couple to the latch of the module \n52\n.', 'In some embodiments, the coupling \n762\n may only be a mechanical coupling.', 'In other embodiments, the coupling \n762\n may also include electrical, fluid, pneumatic, hydraulic couplings, or some combination thereof.\n \nFIG.', '29\n is a side, section view of the ROV \n54\n depositing a module \n52\n in the module receptacle \n702\n of the BOP stack frame \n700\n.', 'As shown, the ROV \n54\n has docked with the frame \n700\n (e.g., via docking hardware \n720\n) and is in the process of depositing the module \n52\n in the module receptacle \n702\n of the frame \n700\n.', 'As shown, the frame \n700\n, which is part of the BOP stack \n46\n, includes a receiver \n800\n, which is coupled to the frame \n700\n via component mounting hardware \n706\n.', 'The receiver \n800\n may include fluid, hydraulic, pneumatic, electrical, and/or other connectors that interface with complementary connectors on the module \n52\n.', 'In the illustrated embodiment, the ROV \n54\n retrieves an exchange weight \n802\n (e.g., via an arm \n804\n) from the exchange weight receptacle \n704\n after the module \n52\n has been deposited within the module receptacle \n702\n.', 'As will be described in more detail below, the exchange weight \n802\n may have a similar mass or buoyancy as the module \n52\n such that the ROV \n54\n can return to the rig \n40\n or intermediate docking station \n58\n in a controlled fashion after undocking from the frame \n700\n.', 'However, in other embodiments, the exchange weight \n802\n may be retrieved before the module \n52\n is deposited, or while the module \n52\n is being deposited.', 'As illustrated, the module \n52\n includes a latch \n806\n, which interfaces with the coupling \n762\n of the receiver \n800\n to secure the module \n52\n within the module receptacle \n702\n of the frame \n700\n.', 'The latch \n806\n may be actuated by a torque tool \n808\n of the ROV \n54\n (e.g., via the torque tool bucket \n124\n).', 'As described with regard to \nFIGS.', '27 and 28\n, the base plate \n752\n of the may include the tapered groove \n754\n through which the module guide \n172\n slides as the module \n52\n is inserted and removed.', 'Further, the primary runners \n174\n of the module may provide a low-friction interface between the module \n52\n and the receiver \n800\n, allowing the module \n52\n to slide along the base plate \n752\n of the receiver \n800\n \nFIG.', '30\n is a schematic of an embodiment of the ROV \n54\n.', 'As shown, the ROV \n54\n may include one or more thrusters \n850\n, which provide thrust to control the location and motion of the ROV \n54\n.', 'The thrusters \n850\n may be variable (i.e., the direction of thrust for each thruster \n850\n is variable) or fixed (i.e., the direction of thrust for each thruster \n850\n is fixed), such that the thrusters may be used in concert to move the ROV \n54\n laterally within the body of water \n18\n, and/or to control a depth of the ROV \n54\n within the body of water \n18\n.', 'Accordingly, the ROV \n54\n and its payload (e.g., module \n52\n or exchange weight \n802\n) need not be perfectly neutrally buoyant to adjust the depth of the ROV \n54\n.', 'That is, as long as the combined mass or weight of the ROV \n54\n and payload is within a threshold value (e.g., 1,000 lbs) of the neutrally buoyant mass, the thrusters \n850\n may be used control the depth of the ROV \n54\n within the body of water \n18\n.', 'In other embodiments, the threshold may be 100 lbs, 200 lbs, 300 lbs, 400 lbs, 500 lbs, 600 lbs, 700 lbs, 800 lbs, 900 lbs, 1000 lbs, 1100 lbs, 1200 lbs, 1300 lbs, 1400 lbs, 1500 lbs, 1600 lbs, 1700 lbs, 1800 lbs, 1900 lbs, 2000 lbs, 2100 lbs, 2200 lbs, 2300 lbs, 2400 lbs, 2500 lbs, or some other value.', 'In some instances, the mass of the module \n52\n or exchange weight \n802\n may far exceed the threshold value.', 'As will be understood, the ROV \n54\n may be loaded with the module \n52\n or exchange weight \n802\n such that the combined mass of the ROV \n54\n and the module \n52\n or exchange weight \n802\n (“package mass”) is within the threshold value of the neutrally buoyant mass.', 'However, once the ROV \n54\n deposits the module \n52\n at the desired location (e.g., the module \n52\n is deposited in the module receptacle \n702\n of the BOP stack \n46\n), because the mass of the payload is zero or has been reduced, the package mass may no longer be within the threshold value of the neutrally buoyant mass.', 'Accordingly, the thrust provided by the thrusters \n850\n may be insufficient in controlling the depth of the ROV \n54\n as it returns back to the surface \n42\n.', 'Similarly, if the ROV \n54\n is sent to retrieve a module \n52\n, the package mass may be within the threshold value of the neutrally buoyant mass on the way down (e.g., no module \n52\n), but once the ROV \n54\n retrieves the module \n52\n at the BOP stack, the package mass may far exceed the neutrally buoyant mass, beyond a threshold value.', 'In such an instance, the thrusters \n850\n would be unable to provide enough thrust to return the ROV \n54\n to the surface \n42\n.', 'To address this challenge, exchange weights \n802\n and floatation devices \n126\n (e.g., volumes of syntactic foam) may be used individually or in combination to maintain the package mass within the threshold value of the neutrally buoyant mass, or to maintain the package buoyancy within a threshold value of neutrally buoyant.', 'For example, in the illustrated embodiment, both the ROV \n54\n and the module \n52\n may be outfitted with one or more floatation devices \n126\n.', 'The floatation devices \n126\n may include volumes (e.g., blocks) of foam, or other devices that increase the buoyancy of the ROV \n54\n and/or the module \n52\n.', 'For example, in some embodiments, the floatation devices \n126\n may include composite materials synthesized by filling a metal, polymer, or ceramic matrix with hollow spheres called microballoons or cenospheres or non-hollowspheres, otherwise known as syntactic foam.', 'Though the described embodiments utilize blocks (e.g., closed volumes, enclosed volumes, walled volumes, etc.) of syntactic foam as the floatation device \n126\n, it should be understood that the disclosed techniques may be utilized with any device that increases buoyancy.', 'The ROV \n54\n and the module \n52\n each may be outfitted with one or more floatation devices \n126\n, such that the ROV \n54\n and the module \n52\n are individually within a threshold mass or buoyancy of neutral buoyancy, and such that combined ROV \n54\n and module \n52\n are close enough to neutrally buoyant that the thrusters \n850\n may be used to control the depth of the ROV \n54\n when carrying the module \n52\n.', 'However, when the ROV \n54\n deposits the module \n52\n, the floatation devices \n126\n coupled to the module \n52\n are also deposited, such that the ROV \n54\n is close enough to neutrally buoyant that the thrusters \n850\n may be used to control the depth of the ROV \n54\n without the module \n52\n.', 'In the illustrated embodiment, the floatation devices \n126\n are disposed at or near the top of the ROV \n54\n and the module \n52\n, such that the floatation devices \n126\n do not cause the ROV \n54\n or the payloads \n14\n to roll.', 'By making each component in the package \n852\n (ROV \n54\n, module \n52\n, etc.) within threshold values of neutrally buoyant, the various components may be coupled to one another and decoupled from one another without reaching a buoyancy that renders the thrusters \n850\n unable to control the depth of the ROV \n54\n.', 'In some embodiments, the ROV \n54\n may also use an exchange weight \n802\n technique instead of, or in addition to, using floatation devices \n126\n.', 'For example, the ROV \n54\n may be equipped with an exchange weight receptacle \n854\n.', 'The exchange weight \n802\n may have a similar mass and/or buoyancy as the module \n52\n.', 'Accordingly, to deposit a module \n52\n, the module \n52\n is loaded on the ROV \n54\n and the ROV \n54\n dives to the BOP stack \n46\n.', 'The ROV \n54\n then docks to the BOP stack frame using a docking system \n50\n, which may include docking hardware \n858\n.', 'The module \n52\n is then deposited in the equipment receptacle \n702\n and an exchange weight \n802\n is retrieved from the exchange weight receptacle \n704\n of the BOP stack \n46\n and stored in the exchange weight receptacle \n854\n of the ROV \n54\n.', 'Though the illustrated embodiments include a single exchange weight \n802\n and corresponding exchange weight receptacles \n854\n, \n704\n, it should be understood that embodiments having one or more exchange weights \n802\n and corresponding receptacles \n854\n, \n704\n (e.g., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more) are also envisaged.', 'Further, such embodiments may include exchange weights \n802\n and receptacles \n854\n, \n704\n of different weights, sizes, etc.', 'The docking system \n50\n then decouples the ROV \n54\n from the BOP stack \n46\n and the ROV \n54\n returns to the surface \n42\n.', 'Because the exchange weight \n802\n has a mass and/or buoyancy substantially equal or similar to that of the module \n52\n, the buoyancy of the total package \n852\n does not substantially change when the module \n52\n is exchanged for the exchange weight \n802\n.', 'Thus, the thrusters \n850\n are capable of returning the ROV \n54\n to the surface \n42\n.', 'Similarly, to retrieve a module \n52\n, the ROV \n54\n is equipped at the rig \n40\n or the intermediate docking station \n58\n with an exchange weight \n802\n.', 'The ROV \n54\n dives to the location of the module \n52\n to be retrieved (e.g., the BOP stack \n46\n or the intermediate docking station).', 'The ROV \n54\n then docks to the frame \n700\n using the docking system \n856\n.', 'The module \n52\n is then retrieved from the \n702\n and the exchange weight \n802\n is deposited in the exchange weight receptacle \n704\n of the frame \n700\n.', 'The docking system \n50\n then decouples the ROV \n54\n from the frame \n700\n and the ROV \n54\n returns to the surface \n42\n with the module \n52\n.', 'Because the exchange weight \n802\n has a mass and/or buoyancy substantially equal or similar to that of the module \n52\n, the buoyancy of the total package does not substantially change when the payload is retrieved and the exchange weight \n802\n deposited, thus the thrusters \n850\n are capable of returning the ROV \n54\n to the surface \n42\n.', 'As previously described, the ROV \n54\n may receive signals (e.g., power, communication, control signals, etc.) via the umbilical cord \n56\n.', 'The umbilical cord \n56\n may be in communication with communication circuitry \n858\n, which may provide the signals to an ROV control system \n860\n.', 'For example, the control system \n860\n may include a processor \n862\n and a memory component \n864\n.', 'The memory component \n864\n may store data, such as computer programs, code, received or collected data, etc.', 'The processor \n862\n may run programs or code stored on the memory component \n864\n.', 'In some instances, the processor \n862\n may analyze data stored on the memory component \n864\n.', 'The control system \n860\n may control the various other components of the ROV \n54\n.', 'The ROV \n54\n includes a power system \n866\n.', 'As previously described, the ROV \n54\n may receive power via the umbilical cord \n56\n.', 'In such embodiments, the communication circuitry \n858\n may route a power signal to the power system \n866\n, which may provide power to the various components within the ROV \n54\n.', 'In some embodiments, the power system \n866\n may include a battery, capacitor, and/or some other energy storage device.', 'The ROV \n54\n also includes a propulsion system or motion control system \n868\n, which may include the thrusters \n850\n, and/or one or more other propelling devices.', 'The thrusters \n850\n and or the motion control system \n868\n may include, for example, one or more generators, motors, hydraulic pumps, hydraulic motors, hydraulic cylinder, drive components, propellers, compressed gas/air/fluid reservoirs and outlets, etc.', 'The motion control system \n868\n may control the direction and/or thrust provided by the one or more propelling devices \n850\n to control the position of the ROV \n54\n.', 'By maintaining buoyancy within a threshold value of neutral buoyancy, the size, thrust, power, etc. of the thrusters \n850\n may be reduced, enabling a less powerful motion control system \n868\n to handle larger loads than previously possible.', 'As previously discussed, the ROV \n54\n may couple to a module \n52\n.', 'Accordingly, the ROV \n54\n may include module coupling hardware \n808\n (e.g., the torque tool, receptacles, grabbing arms, clamps, snap-fit couplings, etc.) that acts as an interface between the ROV \n54\n and the module \n52\n.', 'In some embodiments, the module coupling hardware \n808\n may include male (e.g., torque tool \n808\n) and female (torque tool bucket \n124\n) components mounted on the ROV \n54\n and the module \n52\n that couple to one another.', 'In other embodiments, the module coupling hardware \n808\n may not have corresponding hardware on the module \n52\n.', 'The module \n52\n may be received in a module receptacle \n870\n of the ROV \n54\n.', 'In some embodiments, the ROV \n54\n may include multiple module receptacles \n870\n, of the same or different sizes, to accommodate multiple modules \n14\n.', 'In some embodiments, the receptacle \n870\n may not completely enclose the module \n52\n.', 'For example, the ROV \n54\n may couple to the module \n52\n via the torque tool \n808\n without pulling the module \n52\n into an enclosed receptacle (i.e., the torque tool may just grab the module \n52\n).', 'The torque tool \n808\n may be under the control of a module coupling system \n872\n, which controls when and how the ROV \n54\n couples to the module \n52\n.', 'Similarly, in embodiments in which the exchange weight \n802\n is used to control buoyancy of the ROV \n54\n, the ROV \n54\n may include exchange weight coupling hardware \n804\n (e.g., brackets, gripping arms, trolleys, tracks, ratcheting systems, wenches, clamps, snapfit couplings, etc.) controlled by an exchange weight coupling system \n874\n.', 'As with the module coupling hardware \n808\n, the exchange weight coupling hardware \n804\n may include male and female components mounted on the ROV \n54\n and the exchange weight \n802\n that couple to one another.', 'In other embodiments, the exchange weight coupling hardware \n804\n may not have corresponding hardware on the exchange weight \n802\n.', 'As shown in \nFIG.', '29\n, the exchange weight \n802\n may be received in one or more receptacles \n854\n of the ROV \n54\n.', 'In embodiments with multiple exchange weights \n802\n and receptacles \n854\n, the receptacles \n854\n may be of the same or different sizes to allow a customization of the one or more exchange weights \n802\n.', 'As with the module receptacle \n870\n, in some embodiments, the exchange weight receptacle \n854\n may not completely enclose the exchange weight \n802\n.', 'For example, the ROV \n54\n may couple to the exchange weight \n802\n via the exchange weight coupling hardware \n804\n without pulling the exchange weight \n802\n into an enclosed receptacle (i.e., the exchange weight coupling hardware \n804\n may just grab the exchange weight \n802\n).', 'The exchange weight coupling hardware \n804\n may be under the control of the exchange weight coupling system \n874\n, which controls when and how the ROV \n54\n couples to the exchange weight \n802\n.', 'The exchange weight \n802\n may include a one or more solid blocks of material (e.g., lead, steel, etc.), or a container that may be selectively filled with a liquid or granular material to achieve a desired mass.', 'In embodiments in which the ROV \n54\n docks to the frame \n700\n, the ROV \n54\n may be outfitted with the docking system \n856\n, which may include docking hardware \n876\n (e.g., brackets, gripping arms, trolleys, tracks, ratcheting systems, wenches, clamps, snapfit couplings, etc.).', 'In such an embodiment, the motion control system \n868\n may be used to position the ROV \n54\n, at which point the docking hardware \n876\n, under the control of the docking system \n856\n, engages with a structure (e.g., frame \n700\n) to secure the ROV \n54\n.', 'Once docked, the ROV \n54\n may retrieve or deposit the module \n52\n, the exchange weight \n802\n, or other objects.', 'While the ROV \n54\n is docked, the buoyancy of the package \n852\n (e.g., ROV \n54\n, module \n52\n, exchange weight \n802\n, etc.) may exceed the buoyancy window of the motion control system \n868\n (i.e., the buoyancy range in which the motion control system \n868\n is capable of controlling the ROV \n54\n within a body of water \n18\n), because the ROV \n54\n relies on the frame \n700\n, or other structure to remain stationary.', 'As previously discussed, in some embodiments, the ROV \n54\n, the module \n52\n, or both, may include floatation devices \n126\n (e.g., blocks of syntactic foam) for increasing the buoyancy of the ROV \n54\n and/or the module \n52\n.', 'As previously discussed, if the buoyancy of the package \n852\n is within a threshold value of neutrally buoyant, the motion control system \n868\n can control the depth of the ROV \n54\n.', 'However, if the buoyancy of the package \n852\n is beyond a threshold value above neutrally buoyant, the ROV \n54\n may float to the surface \n42\n in an uncontrolled manner.', 'Correspondingly, if the buoyancy of the package \n852\n is beyond a threshold value below neutrally buoyant, the ROV \n54\n may sink to the sea floor \n16\n.', 'Accordingly, the ROV \n54\n and the module \n52\n may each be outfitted with floatation devices \n126\n such that the ROV \n54\n and the module \n52\n are each individually within the threshold value of neutrally buoyant, and the package \n852\n is also within the threshold value of neutrally buoyant when the ROV \n54\n and the module \n52\n are coupled to one another.', 'In such a configuration, the ROV \n54\n and module \n52\n may couple to one another and decouple from one another without exceeding the threshold value from neutral buoyancy.', 'The ROV \n54\n may include or be attached to a frame \n878\n (e.g., skid).', 'The module coupling hardware \n808\n, the exchange weight coupling hardware \n804\n, and the docking hardware \n876\n may be coupled to the frame \n878\n and provide an interface between the ROV \n54\n and other components (e.g., module \n52\n, exchange weight \n802\n, BOP stack \n46\n, frame \n700\n, intermediate docking station \n58\n, etc.).', 'Specific embodiments of the frame \n878\n are discussed in more detail below.', 'FIG.', '31\n is a perspective view of an embodiment of the ROV \n54\n shown in \nFIG.', '30\n.', 'As illustrated, the ROV \n54\n includes the frame \n878\n.', 'Docking hardware \n876\n mounted to the frame \n878\n interfaces with complementary docking hardware \n706\n on the frame \n700\n shown in \nFIG.', '26\n.', 'As previously discussed, the docking hardware \n706\n shown in \nFIG.', '26\n is just one of many possible embodiments.', 'Accordingly, the docking hardware \n876\n may take different forms in other embodiments.', 'The ROV \n54\n also includes a bumper \n880\n to facilitate docking to the frame \n700\n and reduce damage or wear to the ROV frame \n878\n or the subsea frame \n700\n.', 'For example, the bumper \n880\n may include one or more shock absorption structures, such as one or more resilient portions (e.g., bumpers made of a resilient material such as rubber) or shock absorbers (e.g., piston-cylinder assemblies or fluid filled resilient bags).', 'In the illustrated embodiment, a plurality of floatation devices \n126\n are disposed within the frame \n878\n, rather than on top of the frame \n878\n.', 'However, the centers of mass of the various floatation devices may be disposed even with or above the center of mass of the rest of the ROV \n54\n and/or module \n52\n, so as not to induce rolling.', 'A central housing \n882\n may be disposed interior of the frame \n878\n and include many of the components and systems shown and described with regard to \nFIG.', '30\n.', 'For example, the central housing \n882\n may include all of or part of the communication circuitry \n858\n, the ROV control system \n860\n, the ROV power system \n866\n, the ROV motion control system \n868\n, the module coupling system \n872\n, the exchange weight coupling system \n874\n, etc.', 'The thrusters \n850\n may be disposed at the rear of the ROV \n54\n and act under the control of the motion control system \n868\n to control the position of the ROV \n54\n.', 'As illustrated, module receptacle \n870\n may be disposed near the front of the ROV (e.g., in the tapered front portion \n884\n) and configured to receive one or more modules \n52\n.', 'Once the ROV \n54\n docks with the subsea frame \n700\n (e.g., via the docking hardware \n876\n), the module may be retrieved from, or transferred to, the module receptacle \n702\n of the subsea frame \n700\n.', 'In the illustrated embodiment, the ROV \n54\n also includes the exchange weight receptacle \n854\n.', 'However, in some embodiments, the ROV \n54\n may not include an exchange weight receptacle \n854\n.', 'In such an embodiment, the ROV \n54\n may rely entirely on floatation devices \n126\n mounted to the ROV \n54\n and/or the module \n52\n for buoyancy control.', 'Accordingly, embodiments of the ROV \n54\n may utilize floatation devices \n126\n, exchange weights \n802\n, or a combination thereof to manage the buoyancy of the ROV \n54\n.\n \nFIG.', '32\n is a perspective view of the frame \n878\n of the ROV \n54\n shown in \nFIG.', '31\n.', 'As illustrated, the frame \n878\n includes docking hardware brackets \n900\n for mounting docking hardware \n876\n.', 'Similarly, the frame \n878\n may include mounting brackets \n902\n, which may facilitate mounting floatation devices \n126\n, thrusters \n850\n, or central housings \n882\n.', 'As shown, a central channel \n904\n may be used for holding modules \n52\n, central housings \n882\n, and the like.', 'Meanwhile, side channels \n906\n may be used for floatation devices \n126\n.\n \nFIG.', '33\n is a perspective view of the floatation devices \n126\n of the ROV \n54\n shown in \nFIG.', '31\n.', 'As illustrated, the floatation devices \n126\n may include multiple different kinds of floatation devices \n126\n.', 'For example, in the instant embodiment, the ROV \n54\n is equipped with internal floatation devices \n908\n, side floatation devices \n910\n, and top floatation devices \n912\n.', 'The internal floatation devices \n908\n are disposed within the frame \n878\n.', 'The side floatation devices \n910\n are coupled to the frame \n878\n but extend outward beyond the frame \n878\n toward either side of the frame \n878\n.', 'The top floatation devices \n912\n may be coupled to the frame \n878\n and disposed on top of the internal floatation devices \n908\n.', 'As previously discussed, the configuration shown in \nFIG.', '33\n (i.e., internal floatation devices \n908\n, side floatation devices \n910\n, and top floatation devices \n912\n) is just one of many possible embodiments.', 'In the illustrated embodiment, the floatation devices \n126\n are made of syntactic foam, but any other buoyancy-increasing material may be used.', 'Furthermore, the floatation devices \n126\n may be selectively and removably coupled to the frame \n878\n of the ROV \n54\n (e.g., on-site or off-site) to tailor the buoyancy of the ROV \n54\n based on the expected payload.\n \nFIG.', '34\n is a flow chart of a process \n950\n for controlling buoyancy of an ROV \n54\n while depositing and/or retrieving the module \n52\n.', 'In block \n952\n, the buoyancy of the ROV \n54\n and/or module \n52\n is determined, either experimentally (e.g., water displacement test), or by measuring the mass and volume.', 'As previously discussed, the motion control system \n868\n (e.g., one or more thrusters \n850\n) of the ROV \n54\n may be capable of controlling the depth of the ROV \n54\n as long as the buoyancy of the package \n852\n is within a threshold value of neutrally buoyant.', 'In some embodiments, if the package \n852\n as a whole, or the ROV \n54\n and module \n52\n individually, do not fall within the threshold value of neutrally buoyant, floatation devices \n126\n may be added to either the ROV \n54\n, the module \n52\n, or both (block \n954\n) in order to achieve the desired buoyancies and buoyancy distribution.', 'For example, blocks of syntactic foam may be coupled to the ROV \n54\n and/or the module \n54\n such that the combined package \n852\n and the individual elements of the package \n852\n (e.g., the ROV \n54\n and the module \n52\n) may have buoyancies within a threshold range of neutrally buoyant such that the ROV motion control system \n868\n can control the depth of the ROV \n54\n with and without the module \n52\n.', 'In block \n956\n of the process \n950\n, the module \n52\n or the exchange weight \n802\n is loaded onto the ROV \n54\n.', 'If the ROV \n54\n is taking a module \n52\n down to deposit at a location, then the module \n52\n is loaded onto the ROV \n54\n.', 'Alternatively, if the ROV \n54\n is retrieving a module \n52\n, then the ROV \n54\n may be loaded with an exchange weight \n802\n.', 'The mass of the exchange weight \n802\n may be determined based upon the mass of the module \n52\n.', 'For example, the exchange weight \n802\n may be selected such that the exchange weight \n802\n and the module \n52\n have substantially similar masses, such that the ROV motion control system \n868\n may be capable of controlling the depth of the ROV \n54\n when loaded with either the module \n52\n or the exchange weight \n802\n.', 'In block \n958\n of the process \n950\n, the ROV \n54\n is deployed from a location at or near the surface \n42\n or an intermediate docking station \n58\n to a location, diving a depth to a second location (e.g., a BOP stack \n46\n at or near the sea floor \n16\n).', 'Once the ROV \n54\n arrives at the location, the module \n52\n is deposited or retrieved (block \n960\n).', 'In some embodiments, the ROV \n54\n may couple (e.g., dock) to a structure \n700\n at the location (e.g., BOP stack \n46\n) via docking hardware \n876\n under the control of the docking system \n856\n.', 'By docking to the BOP stack frame \n700\n or other structure, the ROV \n54\n may deposit or retrieve modules \n52\n and/or exchange weights \n802\n without maintaining a package \n852\n buoyancy within the threshold buoyancy of neutrally buoyant without the ROV \n54\n sinking or floating away.', 'However, in some embodiments, the ROV \n54\n may not dock.', 'Once the module \n52\n and/or exchange weight \n802\n have been deposited or retrieved, the ROV \n54\n may undock, if the ROV \n54\n previously docked to the BOP stack \n46\n.', 'The ROV \n54\n then returns to the location at or near the surface \n42\n or the intermediate docking station \n58\n.', 'The ROV \n54\n may then be retrieved (block \n262\n) and unloaded.', 'The disclosed techniques include performing one or more functions of a subsea BOP stack with one or more ROV-retrievable modules.', 'Each module may include one or more components or submodules that couple to a chassis core of the module.', 'The module may also include connections (e.g., electrical, fluid, hydraulic, pneumatic, etc.) that provide an interface between the module and an adjacent module or the BOP stack.', 'Accordingly, any function of the BOP stack could be modularized by performing the function with one or more ROV-retrievable modules.', 'The modules may include ancillary systems, which may be added to existing BOP stacks, or primary systems incorporated into designs of new BOP stacks.', 'If a module of the BOP stack breaks or malfunctions, rather than retrieving the entire BOP stack, taking the well off-line for two weeks or more, a replacement module may be assembled on the rig and an ROV may be sent down to retrieve the old module and install the new module, thus reducing the time the well is off-line to 1-2 days.', 'Further, by assembling a replacement module for the malfunctioning module, the cause of the malfunction can be diagnosed and repaired after the well has been brought back on line.', 'Thus, engineers tasked with repairing the BOP stack can work on repairs without stringent time constraints.', 'While the disclosed subject matter may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.', 'Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.'] | ['1.', 'A system, comprising:\na blowout preventer (BOP) stack module, comprising: a module frame configured to support a plurality of submodules, wherein each submodule of the plurality of submodules is configured to separately and directly couple to the module frame and to each other, the plurality of submodules wrap around an exterior perimeter of the module frame, the plurality of submodules are configured to perform a function on a BOP stack; an underwater vehicle coupling hardware coupled to the module frame, wherein the underwater vehicle coupling hardware is configured to couple with an underwater vehicle configured to transport and selectively couple and uncouple the BOP stack module relative to the BOP stack; a floatation device configured to manage the buoyancy of the BOP stack module as the underwater vehicle transports the BOP stack module underwater; and a mechanical connector coupled to the module frame, wherein the mechanical connector is configured to couple to a stack frame of the BOP stack; and at least one port coupled to the module frame, wherein the at least one port comprises a fluid port, a hydraulic port, a pneumatic port, an electrical port, or a combination thereof, wherein the at least one port is configured to couple with a corresponding port of the BOP stack.', '2.', 'The system of claim 1, wherein the plurality of submodules comprise a controller submodule having a processor, a memory, and instructions configured to perform one or more BOP functions.', '3.', 'The system of claim 1, wherein the plurality of submodules comprise a monitoring submodule having one or more sensors.', '4.', 'The system of claim 1, wherein the plurality of submodules comprises at least one of a filter submodule, a valve submodule, a fluid manifold submodule, a hydraulics submodule, an electronics submodule, a power submodule, a control submodule, or a combination thereof.', '5.', 'The system of claim 1, comprising a family of submodules configured to selectively couple with the module frame of the BOP stack module to customize the BOP stack module with one or more functions of the BOP stack.', '6.', 'The system of claim 1, wherein the underwater vehicle coupling hardware comprises a torque tool bucket configured to interface with a torque tool of the underwater vehicle, wherein the mechanical connector is configured to be actuated by the torque tool via the torque tool bucket.', '7.', 'The system of claim 1, wherein the module frame comprises a plurality of receptacles configured to receive and support the plurality of submodules.', '8.', 'The system of claim 1, wherein the plurality of submodules couple to an exterior surface of the module frame.', '9.', 'The system of claim 1, wherein the floatation device is coupled to the module frame.', '10.', 'The system of claim 9, wherein the floatation device is further configured to remain coupled to the module frame after the BOP stack module is coupled to the BOP stack.', '11.', 'A system, comprising:\na module frame of a BOP stack module;\na plurality of submodules of a family of submodules configured to selectively couple to the module frame of the BOP stack module to customize the BOP stack module with one or more functions of a BOP stack, wherein the BOP stack module is configured to removably couple with the BOP stack, and is transportable via an underwater vehicle;\na floatation device configured to manage the buoyancy of the BOP stack module as the underwater vehicle transports the BOP stack module underwater; and\nan alignment runner coupled to the module frame that is configured to facilitate installation and removal of the BOP stack module with the underwater vehicle.', '12.', 'The system of claim 11, wherein the plurality of submodules comprise a fluid submodule, an electronics submodule, a control submodule, an energy storage submodule, or any combination thereof.', '13.', 'The system of claim 11, wherein a fluid submodule of the plurality of submodules comprises a fluid passage, a fluid valve, a fluid manifold, a fluid filter, or any combination thereof.', '14.', 'The system of claim 11, wherein an energy storage submodule of the plurality of submodules comprises an electrical energy storage component, a fluid energy storage component, or a combination thereof.', '15.', 'The system of claim 11, comprising a plurality of BOP stack modules including the BOP stack module, wherein each of the plurality of BOP stack modules has a different configuration of submodules.', '16.', 'The system of claim 11, wherein the floatation device is coupled to the module frame.', '17.', 'The system of claim 16, wherein the floatation device is further configured to remain coupled to the module frame after the BOP stack module is coupled to the BOP stack.', '18.', 'A method, comprising:\nselectively coupling a plurality of submodules of a family of submodules to each other and directly to a module frame of a BOP stack module to customize the BOP stack module with one or more functions of a BOP stack, the plurality of submodules wrap around an exterior perimeter of the module frame wherein the BOP stack module is configured to removably couple with the BOP stack via transport by an underwater vehicle; and\ncoupling a floatation device to the module frame of the BOP stack module, the floatation device configured to manage the buoyancy of the BOP stack module as the underwater vehicle transports the BOP stack module underwater, and the floatation device further configured to remain coupled to the module frame after the BOP stack module is removably coupled to the BOP stack.', '19.', 'The method of claim 18, wherein selectively coupling the one or more submodules is performed on site at a surface rig above the BOP stack.', '20.', 'The method of claim 18, comprising coupling together two or more of the submodules on the BOP stack module via electrical connections, fluid connections, or a combination thereof.'] | ['FIG.', '1 is a schematic of an embodiment of a subsea installation wellhead assembly;; FIG.', '2 is a schematic of an embodiment of a retrievable module used in the subsea installation wellhead assembly shown in FIG.', '1;; FIG. 3 is a perspective view of an embodiment of a filter module;; FIG. 4 is an exploded view of an embodiment of the filter module of FIG.', '3;; FIG. 5 is a schematic of a flow path through an embodiment of the filter module of FIGS.', '3 and 4;; FIG.', '6 is a schematic of a flow path through an embodiment of the filter module of FIGS.', '3 and 4;; FIG. 7 is a schematic of a flow path through an embodiment of the filter module of FIGS.', '3 and 4;; FIG.', '8 is a schematic of a flow path through an embodiment of the filter module of FIGS.', '3 and 4;; FIG.', '9 is a schematic of an embodiment of a deadman/autoshear system (DMAS) module having a single ram block;; FIG.', '10 is a schematic of an embodiment of a two-ram DMAS having first and second modules;; FIG.', '11 is a schematic of an embodiment of the two-ram DMAS with dual timers;; FIG.', '12 is a schematic of an embodiment of an rigid conduit manifold (RCM) distributed over first and second modules;; FIG.', '13 is a perspective view of an embodiment of a shuttle valve module;; FIG.', '14 is a perspective view an embodiment of the shuttle valve module of FIG.', '13;; FIG.', '15 is a schematic of an embodiment of the shuttle valve module of FIGS.', '13 and 14;; FIG.', '16 is a perspective view of an embodiment of an electrical energy storage module;; FIG.', '17 is a perspective view an embodiment of the electrical energy storage module of FIG.', '16;; FIG.', '18 is a schematic of an embodiment of the electrical energy storage module of FIGS.', '16 and 17;; FIG.', '19 is a perspective view of an embodiment of a hydraulic energy storage module;; FIG.', '20 is a perspective view an embodiment of the hydraulic energy storage module of FIG.', '19;; FIG. 21 is a schematic of an embodiment of the hydraulic energy storage module of FIGS.', '19 and 20;; FIG.', '22 is a perspective view of an embodiment of a subsea electronics module (SEM);; FIG.', '23 is a perspective view an embodiment of the SEM of FIG.', '22;; FIG.', '24 is a schematic of an embodiment of the SEM of FIGS.', '22 and 23;', '; FIG.', '25 is a family tree of various embodiments of retrievable subsea BOP modules;; FIG.', '26 is a perspective view of an embodiment of a portion of a blowout preventer (BOP) stack frame;; FIG.', '27 is a perspective view of an embodiment of an electrical receiver;; FIG.', '28 is a perspective view of an embodiment of a hydraulic receiver;; FIG.', '29 is a side, section view of a remotely operated underwater vehicle (ROV) depositing the module in a module receptacle of the BOP stack frame;; FIG.', '30 is a schematic of an embodiment of the ROV;; FIG.', '31 is a perspective view of an embodiment of the ROV of FIG.', '30;; FIG.', '32 is a perspective view of an embodiment of a frame of the ROV of FIG. 31;; FIG.', '33 is a perspective view of an embodiment of floatation devices of the ROV of FIG. 31; and; FIG.', '34 is a flow chart of an embodiment of a process for controlling buoyancy of the ROV while depositing and/or retrieving the module.; FIG.', '1 is a schematic of a subsea installation 10.', 'The subsea installation 10 includes a well 12.', 'The well 12 includes a wellhead assembly 14 disposed at or near a sea floor 16 of a body of water 18 (e.g., an ocean).', 'A well bore 20 extends from the wellhead assembly 14 through the earth 22 toward a mineral deposit 24.', 'A drill string 26 extends through the wellbore 20 toward the mineral deposit 24.', 'A drill bit 28 disposed in the drill string 26 removes portions of earth 22, forming cuttings, extending the bore hole 20 toward the mineral deposit 24.', 'Drilling fluids (e.g., drilling mud) are pumped down the drill string 26 toward the drill bit, indicated by arrow 30, flushing the cuttings away from the drill bit 28 and into an annulus 32 disposed between the drill string 26 and a casing 34.', 'The cuttings and drilling fluids travel through the annulus 32 in an opposite direction (indicated by arrow 36) as the drilling mud flow through the drill string 26 (indicated by arrow 36).', 'A drilling riser 38 extends from the wellhead assembly 14 to a rig 40 or vessel disposed at a surface 42 of the body of water 18 and may provide passageways for the drilling fluids down to the well 12 and for fluids emanating from the well 12 up to the rig 40.; FIG.', '2 is a schematic of a module 52 as shown in the BOP stack 46 of FIG.', '1.', 'As illustrated, the module 52 is built around a chassis core 100, which includes a frame 102, to which various components may be mounted.', 'In the illustrated embodiment, the frame 102 is generally box-shaped, however the frame 102 may be any shape.', 'In some embodiments, a control system 104 may be coupled to the frame 102 and may be configured to control the operation of the module 52.', 'The frame 102 may include interface geometry, such as tabs, tracks, tapered grooves, indentions, detents, snap fittings, guides, rails, brackets, etc. that act as an interface between the frame 102 and the BOP stack 46, or components/modules that couple to the frame 102.', 'The control system 104 may include various electronic, such as, for example, a processor 106, a memory component 108, and one or more sensors 110.', 'The processor 106 may receive data from the sensors 110 distributed throughout the module 52, or access data stored on the memory component 108, run programs stored on the memory component 108, and then control the operation of the module 52 by generating control signals.', 'In some embodiments, data may be processed and then stored on the memory component 108.', 'The module 52 may also include one or more sub-modules or components 112 coupled to the chassis core 102.', 'The sub-modules 112 or components may be one or more families of assemblies sharing common shapes, dimensions, sizes, connectors, etc.', 'As previously discussed, modules may be designed and assembled to perform a wide range of functions for the BOP stack 46.', 'As such, the rig 40 may have a supply of spare subcomponents 112 and other miscellaneous module 52 components such that a spare module 52 may be assembled on the rig 40 when a module 52 malfunctions, or such that in the event of a module 52 malfunction, the malfunctioning module 52 may be replaced with the spare module 52 by the ROV 54, minimizing the amount of time that the well 12 is off-line.', 'Accordingly, the functionality of the various sub-modules 112 may vary dependent upon the intended function of the module 52.', 'For example, the sub-modules 112 may include valves, filters, batteries, hydraulic accumulators, batteries, capacitors, fluid conduits, manifolds, electronics, sensors, transducers, switches, ram blocks, various control systems, timing systems, counters, triggers, seals, connectors, various electronic, pneumatic, hydraulic, or plumbing components, additional components, or some combination thereof.', 'Further, the equipment to perform some functions of the BOP stack 46 may be spread across multiple modules, to increase modularity, because the equipment may not fit within the footprint of the module 52, or for some other reason.', 'Accordingly, the number of possible module 52 configurations, each heaving a different combinations of sub-modules is nearly infinite.', 'Specific examples of a few possible module 52 configurations are discussed in more detail below.', 'However, it should be understood that these described embodiments are just a few possible examples of many envisaged possible embodiments.; FIG.', '3 is a perspective view of an embodiment of a filter module 150.', 'The filter module may be configured to receive fluid via one or more fluid inlets, filter the fluid, and output fluid via one or more fluid outlets.', 'As illustrated, the filter module 150 includes four submodules 112, in this embodiment filter manifolds 152, which may be fluidly coupled to one another via junction manifolds 154.', 'As will be described in more detail below, based on the how the filter manifolds 152 are configured and coupled to one another via the chassis core 100 and the junction manifolds 154, the filter manifolds 152 may be aligned in series, in parallel, or some combination thereof, along a fluid flow path through the module 150.', 'The filter module 150 also includes a differential pressure gauge 156, which may measure pressure differences between one or more fluid inlets of the module 150 and one or more outlets of the module 150, or various locations along one or more fluid flow paths through the filter module 150.', 'In some embodiments, the filter module 150 may also include one or more sensors 110 distributed throughout the filter module 150, for example to measure the cleanliness of fluid and/or filter performance in the module 150.', 'For example, the sensors 110 may include pressure sensors, particulate content, or concentration sensors, viscosity sensors, flow rate sensors, or any combination thereof.', 'By further example, two or more sensors 110 of the same type may be used to determine a change in the sensed parameter through the module 150 between the inlets and outlets.', 'Based on measurements taken by the sensors 110, decisions may be made regarding when to replace filters 152, the position of valves that control flow rates through the module 150, etc.; FIG.', '4 is an exploded view of an embodiment of the filter module 150 shown in FIG.', '3.', 'As previously described, the filter manifolds are disposed about the chassis core 100 and coupled to one another via the junction manifolds 154.', 'In some embodiments, sealing members 155 (e.g., seal subs) may be disposed at the interfaces between filter manifolds 152 and junction manifolds 154.', 'A fluid flow is received from the BOP stack 46 or from an adjacent module 52 via packer seals 158 at one or more fluid inlets 160.', 'One or more of the filter manifolds include a filter bowl 162, which contains a filter element 164, coupled to the filter manifold 152 via a collar 166.', 'The various filter manifolds 152 may have the same filter elements 164 or different filter elements 164 (e.g., filter elements of different coarseness to filter different sized particulate, or filter elements designed to filter out different substances).', 'The fluid may follow a fluid flow path through the various filter manifolds 152 and junction manifolds 154 toward one or more fluid outlets 167, which may include packer seals 158.; FIG.', '6 is a schematic of a flow path through an embodiment of the filter module 150.', 'Fluid enters the filter module 150 via the inlet 160, flows through a coarse filter 200 (e.g., a screen that filters out larger particulate) and then proceeds through one of two fine filters 202 (e.g., filtering out smaller particulate) in parallel.', 'The fluid exits the filter module 150 via the exit 167.', 'The differential pressure gauge 156 is fluidly coupled to the fluid flow path upstream of the coarse filter 200 and downstream of the fine filters 202.', 'Based on the readings of the differential pressure gauge 156 (e.g., differential pressure between inlet and outlet increases as filters 164 clog) may be used to determine when filters 164 should be cleaned or replaced.; FIG. 7 is a schematic of first and second flow paths 204, 206 through an embodiment of the filter module 150.', 'Fluid enters the filter module 150 via one or two inlets 160, flows through two filters 164 in series and then exits the filter module 150 via one of two exits 167.', 'In the illustrated embodiment, the two flow paths 204, 206 are totally separate from one another.', 'The filter module shown in FIG. 7 also lacks a differential pressure gauge 156.; FIG.', '8 is a schematic of first and second flow paths 204, 206 through an embodiment of the filter module 150.', 'Fluid enters the filter module 150 via one or two inlets 160, flows through one of two filters 164 in parallel and then exits the filter module 150 via one of two exits 167.', 'In the illustrated embodiment, the two flow paths 204, 206 are totally separate from one another.', 'The filter module shown in FIG. 7 also lacks a differential pressure gauge 156, through some embodiments may include a differential pressure gauge 156.; FIG.', '9 is a schematic of a DMAS module 250 having a single ram block.', 'The various components of the DMAS module 250 are disposed about the chassis core 100 and may be divided into multiple sub-modules 112.', 'The DMAS module 250 acts as a control node for charging and venting one or more hydraulic accumulators 251.', 'A set of supply check valves 252 allow various sources 254 to charge the hydraulic accumulators via the hydraulic manifold 251.', 'These sources 254 may be from the primary control system, the ROV 54, or some other source 254.', 'An accumulator pressure gauge 256 monitors pressure in the hydraulic accumulator 251.', 'If the pressure in the hydraulic accumulator is higher than desired, an accumulator dump valve 258 may be actuated (e.g., based on signals from the primary control system or the ROV 52) to vent hydraulic fluid (e.g., via a vent port 260) to reduce pressure in the accumulator 251.; FIG.', '10 is a schematic of a two-ram DMAS 300 having first and second modules 302, 304.', 'For a DMAS 300 with multiple rams, non-sealing (e.g., non-locking) rams are fired (e.g., actuated) first and then a locking ram is fired (e.g., actuated) on a delay.', 'Accordingly, the first module 302 is much like the DMAS module 250 shown and described with regard to FIG.', '9, except that the ram close/lock mechanism 270 is moved to the second module 304, because the ram 268 of the first module 302 is a non-locking ram.', 'As with the single DMAS 250 of FIG. 9, for the DMAS 300, when the arm/disarm valve 262 of the first module 302 is armed, the entire DMAS 300 is armed (i.e., both rams are armed).', 'When the one or more monitored signals meet the conditions discussed above (e.g., threshold exceeded, signal drops out, etc.), a signal is sent to the second module 304, opening a time trigger 306, which starts a timer 308.', 'When the timer 308 expires, a trigger valve 264 for the second ram 310 is opened, closing the second ram 310.', 'As previously discussed, the second ram is a locking ram, so the second module 304 includes the ram close/lock mechanism 270.', 'It should be understood that these techniques may be used to build a DMAS 300 having any number of rams, where the number of modules is equal to the number of rams and the last ram is a locking ram, such that the module for the last ram includes the ram close/lock mechanism 270.; FIG.', '14 is a perspective view an embodiment of the shuttle valve module 400 shown in FIG.', '13.', 'As illustrated, the module 400 includes a module guide 172, as well as primary and secondary runners 174, 176 to facilitate installation and removal of the module 400 in the BOP stack 46 by the ROV 54.', 'FIG.', '15 is a schematic of an embodiment of the shuttle valve module 400 shown in FIGS.', '13 and 14.', 'As illustrated, each of the four shuttle valve submodules 402 includes a shuttle valve 408 with a shuttle 410 that moves between first and second positions.', 'When the shuttle 410 is in the first position, fluid flows from the first inlet 404 to the outlet 406.', 'When the shuttle 410 is in the second position, fluid flows from the second inlet 404 to the outlet 406.', 'Though the shuttle valve module 400 includes four shuttle valve submodules 402, each having a shuttle valve 408, it should be understood that the shuttle valve module 400 may include a different number of shuttle valve submodules 402, and that each shuttle valve module 402 may include more than one shuttle valve 408.', 'As such, the shuttle valve module may be built up with various submodules 112 (e.g., shuttle valve submodules 402) according to the design of the specific BOP stack 46 design.', 'As such, the embodiments of the shuttle valve module 400 shown in FIGS.', '13-15 are merely examples of many possible embodiments of the shuttle valve module 400 and not intended to limit the scope of the claims.; FIG.', '17 is a perspective view an embodiment of the electrical energy storage module 450 shown in FIG.', '16.', 'As illustrated, the module 450 includes a module guide 172, as well as primary and secondary runners 174, 176 to facilitate installation and removal of the module 450 in the BOP stack 46 by the ROV 54.', 'The electrical energy storage module 450 also includes one or more electrical connectors 120 for an interface between the electrical energy storage module 450 and the BOP stack 46.', 'Accordingly, the electrical energy storage module 450 may provide electrical power for various components within the BOP stack 46 via the one or more electrical connectors 120.; FIG.', '18 is a schematic of an embodiment of the electrical energy storage module 450 shown in FIGS.', '16 and 17.', 'As illustrated, each of the one or more electrical energy storage submodules 452 may include one or more batteries, capacitors, fuel cells, etc. 454 that store electrical energy.', 'The various batteries and/or capacitors 454 may be electrically coupled, either directly or indirectly to one or more electrical connectors 120.', 'When the electrical energy storage module 450 is installed in the BOP stack 46, the electrical connector 120 may interface with a complimentary electrical connector 120 on the BOP stack 46 to provide electrical energy to one or more components of the BOP stack 46.', 'Because modularizing the electrical energy storage functions of the BOP stack 46 makes changing out the batteries and/or capacitors 454 much faster than previously possible, electrical energy draw of the components of the BOP stack may become a less important design factor.;', 'FIG.', '20 is a perspective view an embodiment of the hydraulic energy storage module 500 shown in FIG.', '19.', 'As illustrated, the module 500 includes a module guide 172, as well as primary and secondary runners 174, 176 to facilitate installation and removal of the module 500 in the BOP stack 46 by the ROV 54.', 'The hydraulic energy storage module 500 also includes one or more hydraulic ports 504 as an interface between the hydraulic energy storage module 500 and the BOP stack 46.', 'Accordingly, the hydraulic energy storage module 500 may provide hydraulic power for various components within the BOP stack 46 via the one or more hydraulic ports 504.; FIG.', '21 is a schematic of an embodiment of the hydraulic energy storage module 500 shown in FIGS.', '19 and 20.', 'As illustrated, each electrical energy storage submodule 502 includes one or more (e.g., three) chambers 506 that store hydraulic energy.', 'The various chambers 506 may be fluidly coupled, either directly or indirectly to the hydraulic ports 504.', 'When the hydraulic energy storage module 500 is installed in the BOP stack 46, the hydraulic ports 504 may interface with complimentary hydraulic connectors on the BOP stack 46 to provide hydraulic energy to one or more components of the BOP stack 46.', 'Because modularizing the hydraulic energy storage functions of the BOP stack 46 makes changing out or charging the hydraulic energy storage devices (e.g., accumulators, intensifiers, de-boost devices, etc.) much faster than previously possible, hydraulic energy draw of the components of the BOP stack may become a less important design factor.;', 'FIG.', '23 is a perspective view an embodiment of the SEM 550 shown in FIG.', '22.', 'As illustrated, the SEM 550 includes a module guide 172, as well as primary and secondary runners 174, 176 to facilitate installation and removal of the module 500 in the BOP stack 46 by the ROV 54.', 'The SEM 550 also includes one or more electrical connectors 120 as an interface between the SEM 550 and the BOP stack 46.', 'Accordingly, the SEM 550 may provide control signals for various components within the BOP stack 46 via the one or more electrical connectors 120.; FIG.', '24 is a schematic of an embodiment of the SEM 550 shown in FIGS.', '22 and 23.', 'As illustrated, each SEM submodule 552 includes one or more chambers 554 that house various electrical components at approximately 1 atmosphere of pressure.', 'For example, the various electrical components may include one or more processors 556 (e.g., microprocessors, circuit boards, programmable logic controllers, etc.), one or more memory components 558, one or more batteries or capacitors 560, or some combination thereof.', 'The memory components 558 may store data (e.g., collected from sensors distributed throughout the BOP stack 46) and/or programs, algorithms, or routines to be run by the processors 556.', 'The batteries 560 may be the primary power source for the SEM 550, or may act as a backup power source if the primary electrical power source of the BOP stack 46 fails.', 'When the SEM 550 is installed in the BOP stack 46, the electrical connectors 120 may interface with a complimentary electrical connectors on the BOP stack 46 to provide control signals to one or more components of the BOP stack 46.; FIG.', '28 is a perspective view of a hydraulic receiver 766.', 'The hydraulic receiver 766 may be disposed within the module receptacle 702 of a BOP stack frame 700 and act as an interface between the BOP stack 46 and the module 52.', 'As with the electrical receiver 750 of FIG.', '27, the hydraulic receiver 766 includes a baseplate 752 with tapered groove 754, two side panels 756 extending upward from the base plate 752, the top panel 758, and the back panel 760.', 'As illustrated, the side panels 756 include internal hydraulic ports 768 and external hydraulic ports 770, which may fluidly couple the hydraulic receiver 766 to an adjacent receiver 766 or module 52.', 'As with the electrical receiver 750, the back panel 760 includes a coupling 762, which may couple to the latch of the module 52.', 'In some embodiments, the coupling 762 may only be a mechanical coupling.', 'In other embodiments, the coupling 762 may also include electrical, fluid, pneumatic, hydraulic couplings, or some combination thereof.; FIG.', '29 is a side, section view of the ROV 54 depositing a module 52 in the module receptacle 702 of the BOP stack frame 700.', 'As shown, the ROV 54 has docked with the frame 700 (e.g., via docking hardware 720) and is in the process of depositing the module 52 in the module receptacle 702 of the frame 700.', 'As shown, the frame 700, which is part of the BOP stack 46, includes a receiver 800, which is coupled to the frame 700 via component mounting hardware 706.', 'The receiver 800 may include fluid, hydraulic, pneumatic, electrical, and/or other connectors that interface with complementary connectors on the module 52.', 'In the illustrated embodiment, the ROV 54 retrieves an exchange weight 802 (e.g., via an arm 804) from the exchange weight receptacle 704 after the module 52 has been deposited within the module receptacle 702.', 'As will be described in more detail below, the exchange weight 802 may have a similar mass or buoyancy as the module 52 such that the ROV 54 can return to the rig 40 or intermediate docking station 58 in a controlled fashion after undocking from the frame 700.', 'However, in other embodiments, the exchange weight 802 may be retrieved before the module 52 is deposited, or while the module 52 is being deposited.', '; FIG.', '30 is a schematic of an embodiment of the ROV 54.', 'As shown, the ROV 54 may include one or more thrusters 850, which provide thrust to control the location and motion of the ROV 54.', 'The thrusters 850 may be variable (i.e., the direction of thrust for each thruster 850 is variable) or fixed (i.e., the direction of thrust for each thruster 850 is fixed), such that the thrusters may be used in concert to move the ROV 54 laterally within the body of water 18, and/or to control a depth of the ROV 54 within the body of water 18.', 'Accordingly, the ROV 54 and its payload (e.g., module 52 or exchange weight 802) need not be perfectly neutrally buoyant to adjust the depth of the ROV 54.', 'That is, as long as the combined mass or weight of the ROV 54 and payload is within a threshold value (e.g., 1,000 lbs) of the neutrally buoyant mass, the thrusters 850 may be used control the depth of the ROV 54 within the body of water 18.', 'In other embodiments, the threshold may be 100 lbs, 200 lbs, 300 lbs, 400 lbs, 500 lbs, 600 lbs, 700 lbs, 800 lbs, 900 lbs, 1000 lbs, 1100 lbs, 1200 lbs, 1300 lbs, 1400 lbs, 1500 lbs, 1600 lbs, 1700 lbs, 1800 lbs, 1900 lbs, 2000 lbs, 2100 lbs, 2200 lbs, 2300 lbs, 2400 lbs, 2500 lbs, or some other value.', 'In some instances, the mass of the module 52 or exchange weight 802 may far exceed the threshold value.', 'As will be understood, the ROV 54 may be loaded with the module 52 or exchange weight 802 such that the combined mass of the ROV 54 and the module 52 or exchange weight 802 (“package mass”) is within the threshold value of the neutrally buoyant mass.', 'However, once the ROV 54 deposits the module 52 at the desired location (e.g., the module 52 is deposited in the module receptacle 702 of the BOP stack 46), because the mass of the payload is zero or has been reduced, the package mass may no longer be within the threshold value of the neutrally buoyant mass.', 'Accordingly, the thrust provided by the thrusters 850 may be insufficient in controlling the depth of the ROV 54 as it returns back to the surface 42.', 'Similarly, if the ROV 54 is sent to retrieve a module 52, the package mass may be within the threshold value of the neutrally buoyant mass on the way down (e.g., no module 52), but once the ROV 54 retrieves the module 52 at the BOP stack, the package mass may far exceed the neutrally buoyant mass, beyond a threshold value.', 'In such an instance, the thrusters 850 would be unable to provide enough thrust to return the ROV 54 to the surface 42.', 'To address this challenge, exchange weights 802 and floatation devices 126 (e.g., volumes of syntactic foam) may be used individually or in combination to maintain the package mass within the threshold value of the neutrally buoyant mass, or to maintain the package buoyancy within a threshold value of neutrally buoyant.; FIG.', '31 is a perspective view of an embodiment of the ROV 54 shown in FIG.', '30.', 'As illustrated, the ROV 54 includes the frame 878.', 'Docking hardware 876 mounted to the frame 878 interfaces with complementary docking hardware 706 on the frame 700 shown in FIG.', '26.', 'As previously discussed, the docking hardware 706 shown in FIG.', '26 is just one of many possible embodiments.', 'Accordingly, the docking hardware 876 may take different forms in other embodiments.', 'The ROV 54 also includes a bumper 880 to facilitate docking to the frame 700 and reduce damage or wear to the ROV frame 878 or the subsea frame 700.', 'For example, the bumper 880 may include one or more shock absorption structures, such as one or more resilient portions (e.g., bumpers made of a resilient material such as rubber) or shock absorbers (e.g., piston-cylinder assemblies or fluid filled resilient bags).', 'In the illustrated embodiment, a plurality of floatation devices 126 are disposed within the frame 878, rather than on top of the frame 878.', 'However, the centers of mass of the various floatation devices may be disposed even with or above the center of mass of the rest of the ROV 54 and/or module 52, so as not to induce rolling.', 'A central housing 882 may be disposed interior of the frame 878 and include many of the components and systems shown and described with regard to FIG.', '30.', 'For example, the central housing 882 may include all of or part of the communication circuitry 858, the ROV control system 860, the ROV power system 866, the ROV motion control system 868, the module coupling system 872, the exchange weight coupling system 874, etc.', 'The thrusters 850 may be disposed at the rear of the ROV 54 and act under the control of the motion control system 868 to control the position of the ROV 54.', 'As illustrated, module receptacle 870 may be disposed near the front of the ROV (e.g., in the tapered front portion 884) and configured to receive one or more modules 52.', 'Once the ROV 54 docks with the subsea frame 700 (e.g., via the docking hardware 876), the module may be retrieved from, or transferred to, the module receptacle 702 of the subsea frame 700.', 'In the illustrated embodiment, the ROV 54 also includes the exchange weight receptacle 854.', 'However, in some embodiments, the ROV 54 may not include an exchange weight receptacle 854.', 'In such an embodiment, the ROV 54 may rely entirely on floatation devices 126 mounted to the ROV 54 and/or the module 52 for buoyancy control.', 'Accordingly, embodiments of the ROV 54 may utilize floatation devices 126, exchange weights 802, or a combination thereof to manage the buoyancy of the ROV 54.; FIG.', '32 is a perspective view of the frame 878 of the ROV 54 shown in FIG.', '31.', 'As illustrated, the frame 878 includes docking hardware brackets 900 for mounting docking hardware 876.', 'Similarly, the frame 878 may include mounting brackets 902, which may facilitate mounting floatation devices 126, thrusters 850, or central housings 882.', 'As shown, a central channel 904 may be used for holding modules 52, central housings 882, and the like.', 'Meanwhile, side channels 906 may be used for floatation devices 126.; FIG.', '33 is a perspective view of the floatation devices 126 of the ROV 54 shown in FIG.', '31.', 'As illustrated, the floatation devices 126 may include multiple different kinds of floatation devices 126.', 'For example, in the instant embodiment, the ROV 54 is equipped with internal floatation devices 908, side floatation devices 910, and top floatation devices 912.', 'The internal floatation devices 908 are disposed within the frame 878.', 'The side floatation devices 910 are coupled to the frame 878 but extend outward beyond the frame 878 toward either side of the frame 878.', 'The top floatation devices 912 may be coupled to the frame 878 and disposed on top of the internal floatation devices 908.', 'As previously discussed, the configuration shown in FIG.', '33 (i.e., internal floatation devices 908, side floatation devices 910, and top floatation devices 912) is just one of many possible embodiments.', 'In the illustrated embodiment, the floatation devices 126 are made of syntactic foam, but any other buoyancy-increasing material may be used.', 'Furthermore, the floatation devices 126 may be selectively and removably coupled to the frame 878 of the ROV 54 (e.g., on-site or off-site) to tailor the buoyancy of the ROV 54 based on the expected payload.; FIG.', '34 is a flow chart of a process 950 for controlling buoyancy of an ROV 54 while depositing and/or retrieving the module 52.', 'In block 952, the buoyancy of the ROV 54 and/or module 52 is determined, either experimentally (e.g., water displacement test), or by measuring the mass and volume.', 'As previously discussed, the motion control system 868 (e.g., one or more thrusters 850) of the ROV 54 may be capable of controlling the depth of the ROV 54 as long as the buoyancy of the package 852 is within a threshold value of neutrally buoyant.', 'In some embodiments, if the package 852 as a whole, or the ROV 54 and module 52 individually, do not fall within the threshold value of neutrally buoyant, floatation devices 126 may be added to either the ROV 54, the module 52, or both (block 954) in order to achieve the desired buoyancies and buoyancy distribution.', 'For example, blocks of syntactic foam may be coupled to the ROV 54 and/or the module 54 such that the combined package 852 and the individual elements of the package 852 (e.g., the ROV 54 and the module 52) may have buoyancies within a threshold range of neutrally buoyant such that the ROV motion control system 868 can control the depth of the ROV 54 with and without the module 52.'] |
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US11111784 | System and method for determining bottomhole conditions during flowback operations of a shale reservoir | Jan 22, 2016 | Dean Michael Willberg, Ryan Donald Williams, Katharine Moncada, Jean Desroches, Philippe Enkababian, Pavel Spesivtsev | Schlumberger Technology Corporation | Abbasi, Majid Ali, et al., “Flowback Analysis for Fracture Characterization,” Society of Petroleum Engineers, SPE Canadian Unconventional Resources Conference, Calgary, Alberta, Canada, Oct. 30-Nov. 1, 2012, pp. 1-23 (Year: 2012).; Davis et al., “Novel Controlled Pressure Coring and Laboratory Methodologies Enable Quantitative Determination of Resource-in-Place and PVT Behavior of the Duvernay Shale”, SPE 167199, SPE Unconventional Resources Conference-Canada, Nov. 5-7, 2013, 22 pages.; Bendiksen et al., “The dynamic two-fluid model OLGA: theory and application”, SPE 19451, SPE Prod. Eng., 1991, pp. 171-180.; Warren et al., “The Behavior of Naturally Fractured Reservoirs”, SPE Journal, vol. 3, No. 3, Sep. 1963, pp. 245-255.; Xu et al., “Quick Estimate of Initial Production from Stimulated Reservoirs with Complex Hydraulic Fracture Network”, SPE 146753, SPE Annual Tech. Conf. and Exhibition, Denver, CO, Oct. 30-Nov. 2, 2011, 13 pages.; Extended European Search Report issued in European Patent Appl. No. 16740803.8 dated Oct. 31, 2018; 13 pages.; Abbasi et al., “Flowback Analysis for Fracture Characterization”, SPE 162661, SPE Canadian Unconventional Resources Conference, Nov. 1, 2012, 23 pages.; Salim et al., “A Transient Multi-Phase Flow Simulation using Steady-State Correlations for Coiled Tubing Applications—New Insights to Old Problems”, SPE 130647, 2010 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, Mar. 24, 2010, 15 pages.; Gdanski et al., “Using Lines-of-Solutions to Understand Fracture Conductivity and Fracture Cleanup”, SPE 142096, SPE Production and Operations Symposium, Mar. 27, 2011, pp. 16 pages.; Jingjing et al., “Pressure Transient Analysis and Flux Distribution for Multistage Fracutred Horizontal Wells in Triple-Porosity Reservoir Media with Consideration of Stress-Sensitivity Effect”, Journal of Chemistry, vol. 2015, Mar. 18, 2015, 16 pages.; Thomas, O., “Reservoir Analysis Based on Compositional Gradients”, a Dissertation submitted to the Department of Energy Resources Engineering and the Committee on Graduate Studies of Stanford University, 2007, 177 pages.; Oldenburg, C. M. et al., “Numerical Simulation of the Macondo well blowout reveal strong control of oil flow by reservoir permeability and exsolution of gas”, 2012 PNAS Dec. 11, 2012, 109(50), 6 pages.; Landet, “Modeling and Control for Managed Pressure Drilling from Floaters Heave Compensation by Automatic Nonlinear Control”, NTNU Jun. 2011, 126 pages.; Zhou, “Adaptive Observer Design for the Bottomhole Pressure of a Managed Pressure Drilling System”, Proceedings of the 47th IEEE Conference on Decision and Control Cancun, Mexico, Dec. 9-11, 2008, pp. 2961-2966. | 3224506; December 1965; Huitt et al.; 4630868; December 23, 1986; Jones; 5353637; October 11, 1994; Plumb et al.; 8812238; August 19, 2014; Ljungdahl et al.; 9863240; January 9, 2018; Geehan; 20060070735; April 6, 2006; Guerra et al.; 20080000637; January 3, 2008; McDaniel et al.; 20080133193; June 5, 2008; Gdanski; 20080162099; July 3, 2008; Vega Velasquez; 20080210470; September 4, 2008; Stewart; 20100181073; July 22, 2010; Dupriest; 20100204972; August 12, 2010; Hsu; 20100206560; August 19, 2010; Atencio; 20100217574; August 26, 2010; Usadi; 20100218941; September 2, 2010; Ramurthy; 20100307755; December 9, 2010; Xu et al.; 20110011595; January 20, 2011; Huang et al.; 20110040536; February 17, 2011; Levitan; 20110042076; February 24, 2011; Reitsma; 20120228027; September 13, 2012; Sehsah; 20120303281; November 29, 2012; Hon et al.; 20130068452; March 21, 2013; Wingate; 20140083687; March 27, 2014; Poe et al.; 20140121970; May 1, 2014; Ljungdahl et al.; 20140299210; October 9, 2014; Atherton; 20140299552; October 9, 2014; Stewart et al.; 20140352968; December 4, 2014; Pitcher et al.; 20140365130; December 11, 2014; Woods; 20160125104; May 5, 2016; Waltrich; 20160230526; August 11, 2016; Crews | 2014182739; November 2014; WO | ['A system and method is provided that determines at least one bottomhole condition during flowback operations in a well that traverses a hydraulically fractured reservoir.', 'The system and method measure fluid properties of fluids produced at a surface-location of the well during the flowback operations.', 'A transient fluid flow simulator determines composition and properties of fluids in the well between the surface-location of the well and at least one bottomhole-location of the well based on the measured fluid properties.', 'At least one bottomhole condition in the well is determined based on the composition and properties of fluids in the well between the surface-location and at least one bottomhole-location of the well.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThis application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Application No. 62/107,157, filed on Jan. 23, 2015, the entire contents of which are incorporated herein by reference.', 'BACKGROUND\n \n1.', 'Field\n \nThe present disclosure relates to the production of hydrocarbons from subterranean reservoirs, and particularly from tight reservoirs such as reservoirs having a matrix permeability of less than 1 micro-Darcy.\n \n2.', 'State of the Art\n \nDuring a hydraulic fracturing (“fracking”) treatment, hydraulic fracturing fluid is introduced into a well under high pressure to create cracks or fractures in the reservoir rock through which trapped hydrocarbons (e.g., natural gas and/or petroleum) and connate water can flow from the rock more freely.', 'For shale reservoirs, the hydraulic fracturing fluid typically consists primarily of water.', 'A wide variety of chemical additives can also be used in the hydraulic fracturing fluid.', 'Such additives can include dilute acids, biocides, breakers, corrosion inhibitors, crosslinkers, friction reducers, gels, potassium chloride, oxygen scavengers, pH adjusting agents, scale inhibitors and surfactants.', 'Proppant such as sand, aluminum shot, or ceramic beads can also be used in the hydraulic fractures fluid.', 'The proppant is intended to hold fractures open after the hydraulic fracturing treatment is completed.', 'Following the hydraulic fracturing treatment, and before placing the well into production, a process commonly referred to as “flowback” is commenced.', 'During flowback the elevated pressure in the reservoir caused by introducing the pressurized hydraulic fluid is reduced or “drawn down” allowing fluids (including the hydraulic fracturing fluids and components thereof (such as proppant), cleaning the path for hydrocarbons (e.g., natural gas and/or petroleum) and connate water) to flow from the well back to the surface.', 'Procedure and time for the flowback operation are dictated by economic considerations and reservoir properties.', 'Sometimes, it is desirable to conduct the flowback operations immediately after the fracturing treatment so that the well can benefit from non-dissipated reservoir pressure.', 'There are also reservoirs where wells show better production performance after “seasoning”, when fractured fluid is let to dissipate in formation for several weeks before initiating flowback procedure.', 'In all cases after the flowback is initiated it is desirable to flowback the well at maximum technically and operationally allowable rate so that the well can be put into production quickly.', 'At the same time the flowback rate should not exceed certain limits defined by formation and type of injected materials as exceeding these limits may result in excessive flowback of propping material, formation destabilization and, as a result, in poorer well production performance.', 'Current practices for flowback operations are, in general, based on rule-of-thumb and are embodied in confidential flowback operational procedures of various well operators.', 'Such rule-of-thumb flowback practices can cause extensive tensile rock failure, excessive proppant flowback, fines migration, and scale formation.', 'FIG.', '1A\n shows extensive tensile rock failure, which can lead to loss of the production for the treated zone or even sometimes loss of the well.', 'FIG.', '1B\n shows an excessive amount of proppant that have flowed from the fractures back into the well and to the surface, which can allow the newly formed fractures to reduce in width or close, thereby restricting the flow of hydrocarbons from the reservoir rock.', 'FIG.', '1C\n shows fines that have flowed from the fractures back into the well, which indicate that fines have been generated in the fracture; such fines can lead to complete plugging of the fracture and loss of the treated zone.', 'FIG.', '1D\n shows scale that can be produced during flowback.', 'The scale can coat perforations, casing, production tubulars, valves, pumps, and downhole completion equipment, and thus limit production.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'Illustrative embodiments of the present disclosure are directed to a system and method that determines at least one bottomhole condition during flowback operations in a well that traverses a hydraulically fractured reservoir.', 'The system and method measure fluid properties of fluids produced at a surface-location of the well during the flowback operations.', 'A transient fluid flow simulator determines composition and properties of fluids in the well between the surface-location of the well and at least one bottomhole-location of the well based on the measured fluid properties.', 'At least one bottomhole condition in the well is determined based on the composition and properties of fluids in the well between the surface-location and at least one bottomhole-location of the well.', 'The at least one bottomhole condition can include pressure in the well at one or more bottomhole locations of the well.', 'The at least one bottomhole condition can also include one or more fracture properties in the hydraulically fractured reservoir, such as unpropped fracture area and/or fracture conductivity of a fracture in a near-wellbore region adjacent the well.', 'The calculations of the transient fluid flow simulator in determining the pressures and fluid compositions in the well including bottomhole pressure and other bottomhole conditions can involve a wide variety of data, including a set point or other predefined parameter, data from at least one other well, data characterizing mineralogy of the hydraulically fractured reservoir, data derived during drilling the well, etc.', 'The measurements of the system and calculations of the transient fluid flow simulator can be taken and processed in real-time enabling real-time control over the flowback process.', 'As used herein, “real-time” relates to measurement and computation times occurring over a duration of less than fifteen minutes, and in one embodiment less than ten minutes, and in another embodiment less than one second.', 'In the context of a control system, real-time control denotes a system that generates, receives, and processes data in real-time to carry out the respective control operation.', 'The transient fluid flow simulator may incorporate various sub-models that are coupled together.', 'Specifically, the transient fluid flow simulator may incorporate a well model and a fracture flow model, which models the flow in the well piping as well as through the reservoir and/or the hydraulic fracture.', 'The well model may incorporate output of a particle transport model and a flow model.', 'The particle transport model models the movement of solid particles along the well and the flow model models the movement of fluids along the well.', 'The transient fluid flow simulator may incorporate output of a fluid-fluid displacement model within the fractures, a geomechanical model of geomechanical behavior of the formation rock, and a reservoir model that models the inflow of fluid into the fractures.', 'The geomechanical model models the interaction between the stresses, pressures, and temperatures in the reservoir rock and the hydraulic fracture.', 'The fluid-fluid displacement model models the displacement of oil, gas, and water by hydraulic fracturing fluid in the reservoir rock and also the displacement of the hydraulic fracturing fluid by the resident reservoir fluids.', 'The reservoir model models the physical space of the reservoir by an array of discrete cells, delineated by a grid, which may be regular or irregular.', 'The array of cells is usually three-dimensional, although one-dimensional and two-dimensional models can be used.', 'Values for attributes such as porosity, permeability and water saturation are associated with each cell.', 'The value of each attribute is implicitly deemed to apply uniformly throughout the volume of the reservoir represented by the cell.', 'The transient fluid flow simulator may have a plurality of input parameters related to the fracture reservoir, the well, and fluids expected to flow through fractures and through the well.', 'Also, the transient fluid flow simulator may have a plurality of outputs including: a one-dimensional (e.g., radial direction from the wellbore) pressure distribution along fractures; a one-dimensional fluid saturation distribution for oil/gas/water along the fractures; one-dimensional pressure distribution along the length of the well; and one dimensional fluid saturation distributions for oil/gas/water along the length of the well up to the surface.', 'The outputs can vary with time.', 'The one-dimensional radial distributions of pressure and saturation along the fractures can be modeled at various positions along the well.', 'The transient fluid flow simulator model may output the aforementioned pressure and fluid distributions as a function of wellhead pressure.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1A to 1D\n are illustrations of some types of solids that may flow from a well to the surface during a flowback operation.\n \nFIG.', '2\n is a schematic illustration of a well that traverses a hydraulically fractured reservoir.\n \nFIG.', '3\n is a schematic illustration of an embodiment of a flowback system according to the present disclosure.', 'FIG.', '4\n is a schematic illustration of exemplary data flow and associated calculations within the flowback system of \nFIG.', '3\n.', 'FIG.', '5\n shows an example computing system that can be used to implement the flowback system or parts thereof of \nFIGS.', '3 and 4\n.\n \nFIG.', '6\n is a schematic representation of the component parts of an exemplary flowback model.\n \nFIG.', '7\n is a table showing input parameters for an illustrative flowback model.\n \nFIG.', '8\n is a table showing output parameters for an illustrative flowback model.\n \nFIG.', '9\n is a graph of reservoir pressure and fracture fluid saturation versus radial distance from the wellbore at a respective location along a well.\n \nFIG.', '10\n is a graph of multiphase flow of oil, water, and gas versus time during an exemplary flowback operation.\n \nFIG.', '11A\n is a schematic illustration of fluid flow through a dual porosity medium.\n \nFIG.', '11B\n is a schematic illustration showing fluid flow through in a matrix block shown in \nFIG.', '11A\n.', 'FIGS.', '11C and 11D\n are schematic diagrams for depicting fluid flow through a medium.\n \nFIG.', '11E\n depicts an example flow chart of a method for fracture modeling.\n \nFIG.', '12\n is a schematic illustration of drawdown pressures at a respective bottomhole position in a well at two different times during an exemplary flowback operation.\n \nFIG.', '13\n is an example graph of scheduled maximum allowable drawdown pressure versus time during an exemplary flowback operation.\n \nFIG.', '14\n is a graph of total dissolved solids in produced flowback fluid versus time for various wells.\n \nFIG.', '15\n illustrates an example of a ternary diagram with an example of an associated table of fluid properties.\n \nFIG.', '16\n illustrates an example of a system that includes various management components to manage various aspects of a pipeline environment, according to an embodiment.\n \nFIG.', '17\n illustrates a flowchart of a method for modeling slug flow in a multiphase flow according to an embodiment of the present disclosure.', 'DETAILED DESCRIPTION\n \nIllustrative embodiments of the present disclosure are described below.', 'In the interest of clarity, not all features of an actual implementation are described in this specification.', "It will be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another.", 'Moreover, it will be appreciated that such a development effort might be complex and time-consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.', 'Further, like reference numbers and designations in the various drawings indicate like elements.\n \nFIG.', '2\n shows a schematic of a well \n200\n of a hydraulically fractured hydrocarbon reservoir \n202\n.', 'While certain elements of the well \n200\n are illustrated in \nFIG.', '2\n, other elements of the well \n200\n (e.g., blow-out preventers, wellhead “surface tree”) have been omitted for clarity of illustration.', 'The well \n200\n includes an interconnection of pipes, including vertical and horizontal casing \n204\n, production tubing \n206\n, transitions \n208\n, and a production liner \n210\n that connect to a processing facility (not shown) at the surface \n201\n.', 'The production tubing \n206\n extends inside the casing \n204\n and terminates at a tubing head \n212\n at or near the surface \n201\n.', 'The casing \n204\n contacts the wellbore \n218\n and terminates at casing head \n214\n at or near the surface \n201\n.', 'The production liner \n210\n and horizontal casing \n204\n have aligned radial openings termed “perforation zones” \n220\n that allow fluid communication between the production liner \n210\n and the hydraulically fractured reservoir \n202\n.', 'An annular packer \n222\n is set at a lower end of the production tubing \n206\n and provides a seal between the production tubing \n206\n and the casing \n204\n so that fluid in the production liner \n210\n is directed into the production tubing \n206\n rather than between the production tubing \n206\n and the casing \n204\n.', 'The flow rate of the fluid flowing in the well \n200\n to the surface \n201\n is a function of the drawdown pressure of the well \n200\n.', 'As used herein, “drawdown pressure” means the difference between the average reservoir pressure and the bottomhole pressure.', 'As used herein, “average reservoir pressure” means the average pressure of the fluids trapped within the reservoir rock \n202\n, and “bottomhole pressure” means the pressure at a specified location at the bottom of the well, such as at the top (downstream end) of the production liner \n210\n in \nFIG.', '2\n.', 'Thus, in at least one embodiment, the drawdown pressure is calculated to be the difference between the average pressure in the reservoir rock \n202\n and the flowing pressure in the production liner \n210\n at the downstream end of the production liner at a specified time.', 'As will be discussed in greater detail below, the determination of the average pressure in the reservoir rock \n202\n and the flowing pressure in the production liner \n210\n at the downstream end of the production liner will be determined by solving for pressure and flow distributions throughout the well and the hydraulically fractured reservoir rock over time.', 'The pressure and flow distributions may be determined throughout the well piping or the well annulus depending whether the well is flowed back through the casing and production tubing, or through the casing if the well is flown back before installation of the production tubing or the pressure might be determined throughout the annulus between the wellbore and the piping if the well is flown back through the annulus.', 'The drawdown pressure, and, thus, the flow rate of the fluid flowing in the well \n200\n to the surface \n201\n, can be adjusted by a surface-located wellhead choke \n216\n disposed at or near the tubing head \n212\n.', 'For example, the choke \n216\n can be throttled up whereby the aperture of the choke \n216\n is increased or opened in order to increase the drawdown pressure and increase the flow rate of the fluid flowing in the well \n200\n to the surface \n201\n.', 'In another example, the choke \n216\n can be throttled down whereby the aperture of the choke \n216\n is decreased or closed in order to decrease the drawdown pressure and decrease the flow rate of the fluid flowing in the well \n200\n to the surface \n201\n.', 'After a hydraulic fracturing treatment, and before the production of hydrocarbons can commence, the hydraulic fluid injected into the reservoir must be at least partially removed from the reservoir as part of flowback fluids that flow to the surface \n201\n for collection and transport.', 'As used herein “flowback fluid(s)” include one or more of oil, water, gas, and solids, and mixtures thereof.', 'The flow rate of flowback fluid to the surface \n201\n is termed the “unloading rate.”', 'Generally, it is desirable to remove the flowback fluid from the reservoir as quickly as possible (i.e., a high unloading rate) so that the well \n200\n can begin to produce hydrocarbons.', 'However, if the flowback fluid is withdrawn too quickly (i.e., if the unloading rate is too high), there is a risk of unwanted conditions including tensile rock failure, excessive proppant flowback and fines migration.', 'Moreover, because the flowback operation is a highly transient process, in which the distributions of properties change rapidly, it is important to be able to determine the evolution of these properties over time so that operational corrections can be made to manage the flowback operation efficiently and with reduced risk of damage to the well and the reservoir.\n \nFIG.', '3\n illustrates an embodiment of a real-time flowback system \n500\n that has a plurality of sensors (including a well head pressure sensor \n502\n, a multiphase flow meter \n504\n, a solids analyzer \n505\n, and a chemical analyzer \n506\n), a well-head choke \n508\n, and a control system \n510\n that dynamically controls the operation of the choke \n508\n based upon a plurality of inputs from the sensors \n502\n, \n504\n, \n505\n, and \n506\n.', 'An optional bottomhole pressure sensor \n501\n may also be included.', 'The control system \n510\n includes a controller \n512\n that employs a flowback model \n514\n.', 'The control system \n510\n processes the plurality of inputs to generate an output that includes a choke control signal \n516\n that is used by the choke \n508\n to control the drawdown pressure and flow rate of produced flowback fluid \n518\n during a flowback operation.', 'The control system \n510\n can be configured to control the drawdown pressure and flow so that the drawdown pressure remains at or below the scheduled maximum allowable drawdown pressure, such as illustrated in \nFIG.', '13\n, for example.', 'By controlling the drawdown pressure over time, the above-noted unwanted conditions (including tensile rock failure, excessive proppant flowback, fines migration) can be mitigated if determined or detected by the control system \n510\n, as will be discussed in greater detail below.', 'All of the blocks of the system \n500\n, including the measurements obtained by sensors \n502\n, \n504\n, \n505\n, \n506\n, and \n507\n, and the processing carried out by the control system \n510\n to control the choke \n508\n, may occur in real-time.', 'The control system \n510\n interfaces to the choke \n508\n via wired or wireless signal paths therebetween in order to communicate the choke control signal \n516\n that controls the operation of the choke \n508\n.', 'The control system \n510\n interfaces to wellhead pressure sensor \n502\n via wired or wireless signal paths therebetween to receive data measurements of wellhead pressure.', 'The control system \n510\n interfaces to multiphase flow meter \n504\n via wired or wireless signal paths therebetween in order to receive data measurements of production flow rates of oil/gas/water.', 'The control system \n510\n interfaces to solids analyzer \n505\n via wired or wireless signal paths therebetween in order to receive data representing the type and amount of solids produced from the flowback fluid.', 'The control system \n510\n interfaces to continuous chemical analyzer \n506\n via wired or wireless signal paths therebetween in order to receive data representing chemical analysis of solid content of the produced oil/gas/water over time, as discussed below.', 'The control system \n510\n can be configured to carry out a sequence of calculations and operations to control the drawdown pressure and the flow rate of the flowback fluid by controlling the operation of the choke \n508\n.', 'The control logic can be configured by user input or other suitable data structure, which is used to configure the control system \n510\n in order to carry out control operations that are part of the workflow as described herein.', 'For example, the user input or other suitable data structure can specify parameters (such as pressures, flow rates, temperatures, etc.) for such control operations of the workflow.', 'The choke \n508\n may include a variable sized aperture or orifice that is used to control fluid flow rate or downstream system pressure.', 'As an example, the choke \n508\n may be provided in any of a variety of configurations (e.g., for fixed and/or adjustable modes of operation).', 'As an example, an adjustable choke \n508\n may enable fluid flow and pressure parameters to be changed to suit process or production requirements.', 'As an example, a fixed choke may be configured for resistance to erosion under prolonged operation or production of abrasive fluids.', 'The choke \n508\n may be electrically or pneumatically operated.', 'Flowback System Sensors', 'In one embodiment the flowback system \n500\n may include a wellhead pressure (WHP) sensor \n502\n, a multiphase flow meter \n504\n, a solids analyzer \n505\n, and one or more continuous chemical analyzers \n506\n.', 'As noted above, the flowback system \n500\n may include an optional bottomhole pressure sensor \n501\n.', 'The sensors \n502\n, \n504\n, \n505\n, and \n506\n may be located on the surface, while the bottomhole pressure sensor \n501\n may be located at one or more designated bottomhole locations along the well.', 'The bottomhole pressure sensor \n501\n is configured to provide real-time bottomhole pressure measurements \n521\n to the control system \n510\n, which may be used to control the drawdown pressure and the choke \n508\n.', 'Also, the bottomhole pressure measurements \n521\n of the bottomhole pressure sensor \n501\n may be used to tune the flowback model \n514\n and to validate the downhole pressure(s) determined by the flowback model \n514\n, if need be.', 'The wellhead pressure (WHP) sensor \n502\n is configured to measure the pressure of the flowback fluid at the wellhead.', 'The wellhead pressure sensor \n502\n is communicatively coupled to the control system \n510\n and is configured to output a pressure signal \n522\n that characterizes the pressure of the flowback fluid at the wellhead to the control system \n510\n.', 'The flowback fluid passes by the WHP sensor \n502\n and on through a surface-located solids separator and analyzer \n505\n.', 'The solids separator and analyzer \n505\n receives the produced flowback fluid and separates that fluid into two streams: a stream of produced solids; and a stream of produced oil/gas/water.', 'The produced solids are collected and analyzed by the analyzer \n505\n, while the stream of produced oil/gas/water passes to the surface-located multiphase flow meter \n504\n.', 'The analyzer \n505\n can be configured to characterize the solids content (e.g., amount of different solids types, such as proppant, formation rock, fines, etc.) that are included in the flowback fluid in real time.', 'The solids content of the flowback fluid may include any of proppant, formation rock, and possibly fines.', 'The analyzer \n505\n is communicatively coupled to the control system \n510\n and is configured to output solids content measurement signals \n525\n of the produced fluids to the control system \n510\n.', 'In embodiments, the solid analyzer suitable within the present disclosure includes continuous in line devices such as clamp-on gauges, an example of commercially available device is ClampOn provided by ClampOn Inc., Houston, Tex.; continuous in line devices such as densitometers; Continuous measuring devices such as Vx multi-phase flowmeter commercially available from Schlumberger Limited; or non-continuous measurement devices such as separators.', 'The multiphase flow meter \n504\n is configured to measure flow rates of the various phases (oil/gas/water) of the stream of produced fluids in real time.', 'In one embodiment, the multiphase flow meter \n504\n may be a Model Vx Spectra multiphase flow meter supplied by Schlumberger Limited of Sugarland, Tex.', 'The multiphase flow meter \n504\n is communicatively coupled to the control system \n510\n and is configured to output flow rate measurement signals \n524\n for the oil/gas/water phases of the produced fluids to the control system \n510\n.', 'The stream of produced fluids passes through the multiphase flow meter \n504\n to the surface-located continuous chemical analyzer \n506\n.', 'The continuous chemical analyzer \n506\n is configured to continuously analyze the produced oil/gas/water and to generate data representing chemical analyses of those fluids over time, examples of chemical analysis may include electrical conductivity measurements using capacitive type devices; pH detection using ion selective electrodes, solid state detectors, or spectrophometric methods; flow-through spectrophotometric and Infra-red spectroscopy cells; ion selective electrodes for specific ions, gas chromatography, gas detectors.', 'The data may include conductivity, total dissolved solids (TDS), pH, temperature, total hardness, and total alkalinity.', 'Additional water samples can also be collected and preserved for validation of field measurements in a lab and for detailed analysis for elements such as calcium, magnesium, barium, strontium, sulfate, and sulfide, for extended scaling potential analysis and safety hazards.', 'The continuous chemical analyzer \n506\n is communicatively coupled to the control system \n510\n and is configured to output the afore-mentioned measurement signals \n526\n to the control system \n510\n.', 'The stream of produced fluids passes through the continuous chemical analyzer \n506\n to a surface-located phase separator \n507\n, which is configured to separate the stream of produced oil/gas/water into separate streams of oil, gas, and water, which can be individually collected for storage and/or transport.', 'Also, the separator \n507\n may also be used for measuring flow rates of the oil/gas/water.', 'A flowback model \n514\n can use the pressure signal \n522\n and the flow measurements \n524\n to operate as a transient fluid flow simulator that predicts transient pressure distributions along the well and along hydraulic fractures in the reservoir and that predicts distributions of oil/gas/water saturations along the well and along the hydraulic fractures.', 'Those predictions may be used to calculate determined production flow rates for oil/water/gas over time at block \n513\n.', 'The flowback model \n514\n can also possibly determine solid concentration and other properties in fractures and along the well.', 'The flowback model \n514\n can also be used to characterize the bottomhole pressure and associated drawdown pressure of the well over time.', 'The calculated production flow rates, other properties, and drawdown pressure over time may be used by the automatic choke control \n512\n for use in generating the choke control signal \n516\n.', 'In some embodiments, the bottomhole pressure may be calculated based on a plurality of surface measurements (e.g., wellhead pressure and multiphase flow rates) taken over time.', 'For example, in the case of significant fluid travel time from the bottomhole location to the surface, the actual distribution of fluid composition in the wellbore may not be known.', 'In such a case, the distributions and bottomhole conditions at each moment in time may be extrapolated from prior known measurements of multi-phase surface flow measurements measured at the surface, and parameters of such extrapolation can be later verified and additionally calibrated after the bottomhole fluid reaches the surface.', 'Optionally, the bottomhole pressure may be measured from the bottomhole pressure sensor \n501\n.', 'In this configuration, the bottomhole pressure measurement may be compared to the bottomhole pressure determined by the flowback model in order to validate the flowback model.', 'The flow rates of each phase of the flowback fluid (i.e., oil, gas, water, and solids) may be measured continuously using the multiphase flow meter \n504\n and may also be determined over time using the output of the flowback model \n514\n for comparison with the measured values.', 'For example, see the description of block \n515\n in \nFIG.', '4\n that follows.', 'FIG.', '10\n shows a plot of flow rates of oil/water/gas over time that are determined by the control system \n510\n using the output of the flow model \n514\n.', 'The control system \n510\n can be configured to receive and process measurements from the plurality of sensors \n502\n, \n504\n, \n505\n, and \n506\n and to dynamically adjust the operation of the choke (e.g., regulate the aperture of the choke) based on the measured properties of the flowback fluid.', 'The control system can also be configured to dynamically adjust the operation of the choke \n508\n based on determined conditions and/or calculations derived from the flowback model \n514\n.', 'In one embodiment, the multiphase flow rates that are calculated at block \n513\n are updated in real time based on real time updates of fluid properties determined by the model \n514\n.', 'The updated calculated multiphase flow rates are compared in real time to the measured multiphase flow rates.', 'If the determined multiphase flow rates match the measured multiphase flow rates, then the flowback model \n514\n is validated and the model \n514\n may be used to determine the properties of the fluid column in the well between the surface located choke \n508\n and a bottomhole location, including bottomhole pressure at the bottomhole location.', 'If the determined multiphase flow rates do not match the measured multiphase flow rates, then the model \n514\n may be tuned at block \n520\n (\nFIG.', '4\n) so that the flowback model \n514\n may be updated in real time such that the determined multiphase flow rates match the measured multiphase flow rates, and then the flowback model \n514\n can be used to determine the properties of the fluid column in the well including bottomhole pressure.', 'In another embodiment, a number of different flowback models \n514\n (each initialized to reflect different flowback scenarios) may be implemented concurrently.', 'In this case, each model produces a corresponding set of determined multiphase flow rates at block \n513\n.', 'Thus, multiple sets of determined flow rates may be compared against the measured multiphase flow rates to identify one of the flowback models that best matches the measured multiphase flow rate values.', 'The selected flowback model may then be used to determine the fluid column properties in the well, including bottomhole pressure.', 'In yet another embodiment, the bottomhole pressure may be calculated based on a plurality of surface measurements, taken over time, of pressure (e.g., WHP) and flow rates (e.g., multiphase flows).', 'For example, in the case of significant fluid travel time from the bottomhole location to the surface, the actual distribution of fluid composition in the wellbore may not be known.', 'In such a case, the distributions and bottomhole conditions (e.g., bottomhole pressure) at each moment in time may be extrapolated from prior known measurements of multi-phase surface flow measurements measured at the surface, and parameters of such extrapolation can be later verified and additionally calibrated after the bottomhole fluid reaches the surface.', 'Optionally, the bottomhole pressure may be measured from the bottomhole pressure sensor \n501\n and used to calculate drawdown pressure.', 'Furthermore, the bottomhole pressure measurements may be compared to the bottomhole pressure determined by the flowback model for tuning the flowback model and for validation of the flowback model if need be.', 'In still another embodiment, the flowback model(s) as described above can be used to determine multiple estimates of bottomhole pressure over time and provide a statistical distribution of the bottomhole pressure over time (e.g., a maximum, minimum, average, and standard deviation).', 'Furthermore, deviation from a determined trend or scenario, such as deviation from a predefined drawdown operating envelope, can be reported as an alarm for further analysis and decision making for updating the flowback strategy.', 'Control System—Automatic Choke Control\n \nFIG.', '4\n shows an exemplary data flow and associated calculations within the flowback system of \nFIG.', '3\n.', 'At block \n515\n, the determined multiphase fluid flow rates at the surface may be compared with the corresponding measured multiphase flow rates output by the multiphase flow meter \n504\n.', 'At block \n520\n at least some of the flowback model parameters in \nFIG.', '7\n may be tuned or refined based on the comparison of the measured and target flow rates at block \n515\n.', 'Also, a validation signal (i.e., valid or invalid) may be output to the choke controller \n512\n based on the comparison at block \n515\n.', 'The validation signal may be used by the choke controller \n512\n to denote whether or not the flowback model is valid.', 'In the cases where the model is invalid, a safe mode of operation is followed until the model can be tuned and valid.', 'As an example, such safe mode comprises keeping the current choke setting along unless surface measurements from solids/fluids indicate that the current choke settings corresponds to a danger zone of the system (e.g. a large amount of fines being produced).', 'In block \n540\n, the automatic choke control \n512\n is configured to maintain a controlled drawdown pressure of the well over time as determined by the output of the flowback model \n514\n in order to generate a recommended choke control setting.', 'In blocks \n528\n to \n538\n the automatic choke control \n512\n may receive input \n522\n from the wellhead pressure sensor \n502\n, input \n524\n from the multiphase flow meter \n504\n, an input \n525\n from the solids analyzer \n505\n, input \n526\n from the continuous chemical analyzer \n506\n, as well as other inputs from the flowback model \n514\n and possibly other sources that are used to detect and/or determine unwanted conditions such as sand, salinity, temperature, gas saturations, or oil saturations changes.', 'In block \n542\n, the automatic choke control \n512\n can generate a choke control signal \n516\n based on the recommended choke control setting derived from the drawdown pressure analysis \n540\n or a choke control signal suitable for addressing the unwanted condition(s) determined or detected in blocks \n528\n to \n538\n.', 'In this manner, the recommend choke setting recommended in block \n540\n may be overridden with another suitable choke settings if there is a prediction or measurement indicative of unwanted conditions such as damage to the well.', 'For example, if rock failure, slug formation, fracture surface area loss, insufficient flow to lift the liquids and/or solids or excessive formation solids are determined or detected, then the choke controller \n512\n may override the choke setting recommendation from block \n540\n and generate an alternative choke control signal at block \n542\n to adjust the choke \n508\n based on the specific failure condition(s) that is determined or detected.', 'For example each overridden choke control signal may be predefined and stored in a lookup table accessible to the automatic choke control \n512\n.', 'Moreover, if more than one failure condition is detected or determined, the overridden choke control signal may be based on a predefined priority schedule.', 'For example, any overridden choke control signal output from block \n542\n may be based on the most dangerous failure condition determined or detected.', 'However, if there are no determined or detected failure conditions damage, then the choke control signal recommendation from block \n542\n is not overridden at block \n542\n and the choke control setting is generated at block \n542\n based on the choke control signal recommendation of block \n540\n.', 'In one embodiment, the flowback model \n514\n can include certain parameters related to near wellbore fractures, such as unpropped fracture area and/or fracture conductivity in the near wellbore region.', 'Note that fracture conductivity is based upon the propped fracture width and permeability of the proppant.', 'A safe drawdown envelope can be estimated based on the flowback model \n514\n using these certain parameters together with reservoir mechanical and hydraulic properties.', 'The safe drawdown envelope can be defined such that it avoids tensile failure of the formation.', 'In this configuration, the solids content of the flowback fluid (e.g., the amount of different types of solids such as proppant, formation rock, fines, etc.) as measured by the solids analyzer \n505\n can be compared against predefined threshold levels (which can be derived from historical data of produced solids in similar or like wells or other methods) in order to identify a change in the parameters related to near wellbore fractures.', 'The flowback model \n514\n can then be dynamically updated to accommodate the identified change in the parameters related to near wellbore fractures.', 'The updated flowback model \n514\n can then used to dynamically update the safe drawdown envelope (e.g., safe zone depicted in \nFIG.', '13\n) such that it accounts for the change in near wellbore fractures over time during the flowback operations.', 'Thus, the control scheme is linked to the behavior of the fractures in the near wellbore region, captures the uncertainties of the fracture properties in the near wellbore region, and computes safe operating envelopes for flowback and early production.', 'The comparison of the solids content of the flowback fluid and the predefined threshold levels can also be used to identify risks of fracture failure and pinchout.', 'Upon identifying any of these conditions, the choke control signal \n516\n can be dynamically adjusted such that it mitigates the detected condition(s).', 'Chemical Analyses', 'At block \n528\n in \nFIG.', '4\n, the output \n526\n of the chemical analyzer \n506\n may be used to determine a loss of fracture surface area or productive area in the formation.', 'The choke setting recommendation from block \n540\n may be overridden based on the prediction of loss of fracture surface area or productive area in the formation.', 'Chemical analysis of the produced oil/gas/water may be used to monitor how the chemistry of the fracturing fluid changes over the flowback period as a result of its contact with a stimulated reservoir.', 'Continuous monitoring of parameters such as conductivity, total dissolved solids (TDS), pH, temperature, total hardness, and total alkalinity may provide insight regarding the rock-fluid interaction.', 'The measurements of temperature, pH, total hardness, and total alkalinity obtained by the chemical analyzer \n506\n relate to precipitate potential production of impairing minerals, and an understanding of these parameters can assist in understanding scaling potential.', 'Thus, in one embodiment, if scale formation is measured or determined, and the amount of scale is determined to be excessive, the choke controller may be configured to generate a choke control signal to set the orifice size smaller or to close the choke.', 'Also, the salinity (or a single ionic species such as chloride) that is measured during flowback is directly linked to the reservoir that is connected to the producing hydraulic fracture network (HFN).', 'Each sample of the flowback fluid is essentially a distinct measurement in time of the equilibration process between the fracturing fluid and the formation chemistry.', 'In embodiments, continuous salinity measurements may also be performed.', 'FIG.', '14\n shows plots of measurements of total dissolved solids (TDS) in the flowback fluid as a function of time\n1/2 \nfor a plurality of wells.', 'As shown in \nFIG.', '14\n, each plot steadily increases, and is expected to reach an asymptote at salt concentration close to that of the native reservoir conditions.', 'This is likely a reflection of the fracture aperture distribution along the radial flow paths in \nFIG.', '11A\n and its signature may also indicate regional distributions due to rock type changes.', 'These curves of salinity vs. time\n1/2\n, have been observed to be similar for similar sized completions in the same formation and in the same field.', 'As such they can be used as type curves for interpreting data acquired for new wells.', 'If during the flowback from new wells, rapid, or otherwise unexpected changes in the graph or slope of the salinity vs. time\n1/2 \ncurves could indicate loss of connected fracture surfaces area.', 'Therefore these curves, correlated with wellhead (and calculated bottomhole) pressure data, can be used as input for the choke control system.', 'The above-mentioned equilibration can be observed by taking multiple samples of these flowback fluids over time, and a change in the pattern of the chemistry evolution (e.g., change in chlorides slope vs. time\n1/2\n) would indicate a change in the chemistry that was coming to equilibration with the fracturing fluid.', 'This could be due to a change in geometry (e.g., losing connectivity with the chemistry contributed from a zone), or this could be an event brought about by crossing a pressure threshold (e.g., influx of produced fluids from an underpressured section of the reservoir).', 'Thus, in one embodiment, the choke control signal generated by the choke controller at block \n624\n in \nFIG.', '6\n may be based on a change in slope of the ionic strength, salinity, chlorides salt concentrations, etc. as a function of time\n1/2\n.', 'Slug Formation\n \nAs shown in \nFIG.', '4\n, at block \n530\n, if slug formation or slug flow is determined, an override choke setting may be generated to override the choke setting recommendation of block \n540\n.', 'The term “slug flow” relates to a multiphase-fluid flow regime characterized by a series of liquid plugs (slugs) separated by a relatively large gas pockets.', 'The resulting flow alternates between high-liquid and high-gas composition.', 'The presence of slug flow may indicate a condition that is damaging to fractures in the formation.', 'Slug formation can be determined from the calculated flow rates and the modeled pressure distributions.', 'The frequency of determined slugs may be monitored and based on that frequency, the recommended choke setting may be overridden to change the choke setting to alter the frequency in a case where it is determined that the frequency of the slugs is damaging the fractures.', 'Particular methodologies for predicting slug formations are described below with respect to \nFIGS.', '15 to 17\n.', 'In some cases, the model may determine that slug flow is beneficial and the choke would be adjusted accordingly over variable periods of limited durations.', 'In yet further cases, constant slug flow may be encouraged during the flowback operations if other failure modes are not triggered or have limited negative impact.', 'Tensile Rock Failure\n \nAt block \n532\n the automatic choke control \n512\n may determine tensile rock failure and generate an override choke setting based on the determined pressure distributions from the flowback model \n514\n.', 'Tensile rock failure relates to breakage of the formation rock and is a function of the propped fracture width, the size of the near-wellbore area devoid of proppant, the closure stress, the reservoir pressure, the pressure in the wellbore in front of the fracture, the elastic properties and tensile strength of the rock (to be calibrated) and the pressure history in the wellbore in front of the fracture.', 'Tensile failure occurs if a difference between the stress and the fluid pressure in the formation exceeds an effective formation tensile strength.', 'As noted above, tensile rock failure of the reservoir rock may be determined based on the above-mentioned modeled pressure distributions in the reservoir.', 'Also, the risk of tensile rock failure may be based on the type of reservoir rock.', 'If tensile rock failure is determined and formation failure has been identified as a high impact risk for the well, then the override choke setting from block \n532\n may include a setting to throttle the choke \n508\n further so that the downhole pressure is increased for a time that allows the pressure transient in the formation to dissipate.', 'Solids Formation\n \nThe recommended choke setting from block \n540\n may also be overridden if it is determined at block \n534\n that the measured solids content of the flowback fluid exceeds a predetermined threshold.', 'The measured solids content is based on the output of the solids analyzer \n505\n.', 'If the threshold is exceeded, then a suitable choke control signal that is intended to reduce the solids content in the flowback fluid can be generated at block \n542\n and supplied to the choke \n508\n.', 'Particle concentrations may be monitored during flowback operations by the solids analyzer \n505\n.', 'In one embodiment a continuous solids monitoring acoustic device is used to monitor and determine if solids are being produced at all, if the solids flow rate is continuous or if the solids rate increases at some stages and then stabilizes or disappears.', 'In addition, as part of the solids monitoring process, several samples of solids can be collected in the field to be sent for lab analysis to then define what types of solids were produced (i.e. formation-like solids, precipitation scale or proppant).', 'Some on site analysis may be done depending on the complexity and available technologies.', 'Solids in the flowback fluid may come from the fracture (proppant) and/or from the formation (through formation failure) or even from the wellbore if prior operations did not leave the drain cleared.', 'The presence of proppant in the flowback fluid at the surface may indicate reduction of fracture apertures and the possibility of bed formation in the undulating parts of the horizontal sections of the well piping (e.g., the production liner \n210\n of \nFIG.', '1\n).', 'Also, the presence of formation rock in the flowback fluid at the surface may indicate damage to the formation reservoir and propped fracture network.', 'If reservoir rock is detected, a decision can be made about whether a threshold indicative of damage to the formation reservoir and fracture network has been reached based on both a combination of rate of production of those solids and total amount produced.', 'If proppant is detected, a decision can be made about whether a threshold indicative of damage to the fracture apertures has been reached based on the rate of production and total amount of proppant produced, which can be used to estimate the fraction of proppant returned to the surface.', 'Thus, in one embodiment, the override choke control signal generated at block \n542\n may be based on the measurement of the amount of proppant and/or formation rock returned to the surface.', 'For sand or proppant production, the difference between closure pressure and bottomhole pressure may be monitored to determine if a threshold is exceeded.', 'The closure pressure data may be determined from a post fracture job analysis.', 'In one embodiment, if the difference between closure pressure and bottomhole pressure exceeds a threshold, then the override choke control signal may be generated at block \n542\n, and if the difference is less than the threshold, an override choke control signal may not be generated at block \n542\n.', 'Even if the solids production is not severe enough (above the respective thresholds discussed above) to be indicative of damage to the fractures or to the formation rock, the solids production may still pose problems for production facilities and pipeline components on the surface.', 'For example, the solids production rate may cause problems for the production facilities and the total amount of solids produced may be a problem for filling traps and filters.', 'Flow Measurements', 'At block \n536\n a determination is made whether one or more measured flow rates measured by the multiphase flow meter \n504\n is above a predefined limit.', 'If the limit is exceeded, then a suitable choke control signal setting to override the recommended choke setting of block \n540\n.', 'As an example, if the flow rate of water exceeds a predetermined limit, then a suitable choke control signal that is intended to reduce the flow rate of water can be generated at block \n542\n and supplied to the choke \n508\n.', 'Erosion probes may provide relevant information about the extent of the potential damages and dynamics of the erosion of the production system.', 'Wellhead Pressure\n \nAt block \n538\n a determination is made whether the wellhead pressure is above or below a predefined limit.', 'For example, above a certain limit could correspond to not having enough flow and loading the well with water, while below a certain limit could correspond to some kind of formation failure (e.g. perforation collapse).', 'If the limit is exceeded, then a suitable choke control signal that is intended to reduce the wellhead pressure can be generated at block \n542\n and supplied to the choke \n508\n.', 'While not shown explicitly in \nFIG.', '4\n, flowback data from other neighboring wells may be used as part of the control scheme carried out by the automatic choke control \n512\n.', 'For example, such flowback data can be used to derive one or more of the threshold limits for predicting or detecting the conditions in blocks \n528\n to \n538\n, as described above.', 'One problem with wellhead measurements is that the wellbore storage of fluids causes water, hydrocarbon fluids, and solid production rates at the surface to lag behind the changes to bottomhole pressure that cause such production rate changes at the surface.', 'Pressure information travels at the speed of sound, so that pressure events at a bottomhole location generate a corresponding signal at the wellhead only a few seconds later.', 'However, the corresponding change in the bulk flow of material (water, hydrocarbons, and solids) that accompanies that pressure event, will arrive at the surface minutes to hours later.', 'For example, if the well piping volume is two hundred barrels, and the nominal flowback rate is fifty barrels per hour, then the measured flowrate data reflects what occurred three to four hours previously.', 'In order to account for this inherent production lag time caused by wellbore storage of fluids, the control system \n510\n may be configured to calculate the lag time period between a wellhead pressure change (with corresponding downhole pressure change) and a corresponding change to the production flow rates of fluids and solids at the surface due to the wellbore storage of fluids.', 'This lag time can be used to dynamically correlate the wellhead pressure data \n502\n (with the corresponding determined or measured bottomhole pressure data) over time to fluids and solids production rates at the surface over time.', 'Also, the control system \n510\n may be configured to dynamically adjust the choke control setting based on such correlations.', 'The calculations of the flowback model \n514\n in determining the pressures and fluid compositions in the well including bottomhole pressure and other bottomhole conditions can involve a wide variety of data, including a set point or other predefined parameter, data from at least one other well, data characterizing mineralogy of the hydraulically fractured reservoir, data derived during drilling the well, etc.\n \nAlso note that previously acquired flowback and production data from at least one other well can be used to tune the flowback model \n514\n.', 'Such other well(s) may be geographically nearby (i.e., in the same basin) the well that is undergoing flowback operations.', 'Alternatively, such other well(s) may be located in other basins having similar properties to that of the well that is undergoing flowback operations.', 'In those cases, the flowback model \n514\n is more likely to be more predictive.', 'Previously acquired and stored flowback data from such other well(s) may assist in providing a calibrated control loop where bottomhole pressure upper and lower bounds are estimated to define a safe flowback operational envelope for other subsequent wells.', 'Using a control flow loop that uses historical field data to enhance the current data set may lead to better predictions of bottomhole pressure than can be made before actual separator and fluid composition data is obtained.\n \nFIG.', '5\n shows an example computing system \n300\n that can be used to implement the control system \n510\n or parts thereof.', 'The computing system \n300\n can be an individual computer system \n301\nA or an arrangement of distributed computer systems.', 'The computer system \n301\nA includes one or more analysis modules \n303\n (a program of computer-executable instructions and associated data) that can be configured to perform various tasks according to some embodiments, such as the tasks described above.', 'To perform these various tasks, an analysis module \n303\n executes on one or more processors \n305\n, which is (or are) connected to one or more storage media \n307\n.', 'The processor(s) \n305\n is (or are) also connected to a network interface \n309\n to allow the computer system \n301\nA to communicate over a data network \n311\n with one or more additional computer systems and/or computing systems, such as \n301\nB, \n301\nC, and/or \n301\nD. Note that computer systems \n301\nB, \n301\nC and/or \n301\nD may or may not share the same architecture as computer system \n301\nA, and may be located in different physical locations.', 'The processor \n305\n can include at least a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, digital signal processor (DSP), or another control or computing device.', 'The storage media \n307\n can be implemented as one or more non-transitory computer-readable or machine-readable storage media.', 'Note that while in the embodiment of \nFIG.', '5\n, the storage media \n307\n is depicted as within computer system \n301\nA, in some embodiments, storage media \n307\n may be distributed within and/or across multiple internal and/or external enclosures of computing system \n301\nA and/or additional computing systems.', 'Storage media \n307\n may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices.', 'Note that the computer-executable instructions and associated data of the analysis module(s) \n303\n can be provided on one computer-readable or machine-readable storage medium of the storage media \n307\n, or alternatively, can be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes.', 'Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture).', 'An article or article of manufacture can refer to any manufactured single component or multiple components.', 'The storage medium or media can be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions can be downloaded over a network for execution.', 'It should be appreciated that computing system \n300\n is only one example of a computing system, and that computing system \n300\n may have more or fewer components than shown, may combine additional components not depicted in the embodiment of \nFIG.', '5\n, and/or computing system \n300\n may have a different configuration or arrangement of the components depicted in \nFIG.', '5\n.', 'The various components shown in \nFIG.', '5\n may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.', 'Further, the operations of the workflow described above may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, SOCs, or other appropriate devices.', 'These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of the disclosure.', 'Control System—Flowback Model\n \nFIG.', '6\n illustrates an embodiment of the flowback model \n514\n including sub-models that may be used as part of the flowback model \n514\n.', 'The flowback model \n514\n is a system of mathematical equations that characterize the pressure distributions and fluid flow in the hydraulically fractured reservoir rock and the well piping over time as a function of wellhead pressure.', 'Specifically, the flowback model \n514\n includes coupling logic \n614\n that joins a well model \n642\n and a fracture flow model \n644\n.', 'The well model \n642\n models the flow of flowback fluid in the well piping over time as a function of wellhead pressure.', 'The well model \n642\n receives input from a particle transport model \n646\n and a flow model \n648\n.', 'The particle transport model \n646\n models the movement of solid particles along the well and the flow model \n648\n models the movement of fluids along the well.', 'The fracture flow model \n644\n models the flow of flowback fluid in the hydraulically fractured reservoir rock over time as a function of wellhead pressure.', 'The fracture flow model \n644\n receives input from a fluid-fluid displacement model \n650\n within the fractures, a geomechanical model \n652\n of geomechanical properties of the formation rock, and reservoir model \n654\n that models the inflow of fluid into the fractures.', "The geomechanical model \n652\n models the interaction between the formation's rocks, stresses, pressures, and temperatures and the influence of these parameters on the fractures.", 'The fluid-fluid displacement model \n650\n models the displacement of oil, gas, and water by hydraulic fracturing fluid in the reservoir rock and/or the displacement of the hydraulic fracturing fluid be the reservoir fluids.', 'The reservoir model \n654\n models the physical space of the reservoir (e.g., reservoir \n202\n of \nFIG.', '2\n) by an array of discrete cells, delineated by a grid, which may be regular or irregular.', 'The array of cells is usually three-dimensional, although one-dimensional and two-dimensional models can be used.', 'Values for attributes such as porosity, permeability and water saturation are associated with each cell.', 'The value of each attribute is implicitly deemed to apply uniformly throughout the volume of the reservoir represented by the cell.', 'The flowback model \n514\n may have a plurality of input parameters.', 'As shown in an example in \nFIG.', '7\n, the flowback model \n514\n may have seventeen input parameters related to fractures, the reservoir, the wellbore layout and geometry and completion layout and geometry, and fluids expected to flow in the well.', 'Also, as shown in an example in \nFIG.', '8\n, the flowback model \n514\n may have a plurality of outputs that vary with time including: a one-dimensional (radial direction from the wellbore) pressure distribution along fractures; one-dimensional fluid saturation distributions for oil/gas/water along fractures; a one-dimensional pressure distribution along the length of the well to the surface; and one-dimensional fluid saturation distributions for oil/gas/water along the length of the well to the surface.', 'This pressure distribution along the length of the well over time can be used to characterize the bottomhole pressure over time.', 'Also, the one-dimensional radial distributions of pressure and fluid saturations along the fractures can be modeled at various locations (e.g., in perforation zones \n220\n) along the well.', 'A visual representation of the one-dimensional pressure and fluid saturation distributions is shown in \nFIG.', '9\n as a function of radial distance from the wellbore.', 'The flowback model \n514\n can solve for pressure drop (e.g., pressure differential) in the well, for example, through use of momentum equations.', 'Such momentum equations, for example, may account for factors such as fluid potential energy (e.g., hydrostatic pressure), friction (e.g., shear stress between conduit wall and fluid), and acceleration (e.g., change in fluid velocity).', 'As an example, one or more equations may be expressed in terms of static reservoir pressure, a flowing bottomhole pressure, wellhead pressure, and flowrates for different phases of produced fluids at the surface during the flowback operations.', 'As an example, equations may account for vertical, horizontal or angled arrangements of equipment.', 'In another example, the flowback model may implement equations that include dynamic conservation equations for momentum, mass and energy.', 'As an example, pressure and momentum can be solved implicitly and simultaneously and, for example, conservation of mass and energy (e.g., temperature) may be solved in succeeding separate stages.', 'Various examples of equations may be found in a dynamic multiphase flow simulator such as the simulator of the OLGA™ simulation framework (Schlumberger Limited, Houston, Tex.), which may be implemented for design and diagnostic analysis of the flowback operations for hydraulically fractured tight reservoirs.', 'OLGA, being a transient multi-phase wellbore flow simulator, can be used to calculate the bottomhole pressure at one or more bottomhole locations inside of the well.', 'To do this, OLGA uses the three-fluid mathematical model that is originally developed and validated for the horizontal flow configurations.', 'The mathematical model in OLGA simulator is summarized in K. Bendiksen et al, “The dynamic two-fluid model OLGA: theory and application,” SPE Prod.', 'Eng., 1991, pp. 171-180, herein incorporated by reference in its entirety.', 'Typically, to calculate the bottomhole pressure, the boundary and initial conditions are specified before the simulation.', 'The initial conditions include the distribution of phase volume fractions, velocities, pressure and other variables inside of the well.', 'The boundary conditions typically include the wellhead pressure specified at the outlet of the well and no-flow boundary condition at the bottom of the well.', 'The wellhead pressure can change over in time (transient) and hence specified as a series of time steps.', 'Once these conditions are specified, the simulation is launched.', 'In course of the simulation, the system of conservation equations is solved at each time step to derive the distribution of volume fractions, velocities, pressure (and other variables) in the well, including the bottomhole pressure at one or more bottomhole locations in the well.', 'FIGS.', '11A to 11E\n illustrate features of an exemplary fracture flow model that can be configured to characterize the flowback fluid flow through the fractures of a reservoir.', 'FIG.', '11A\n shows a two dimensional profile through a hydraulically fractured reservoir around a circular wellbore \n1120\n.', 'As shown in this view, a hydraulic fracture network (HFN) \n1122\n is depicted as having a plurality of concentric ellipses \n1130\n and a plurality of radial flow lines \n1132\n.', 'The radial flow lines \n1132\n initiate from a central location about the wellbore \n1120\n and extend radially therefrom.', 'The radial flow lines \n1132\n represent a flow path of fluid from the formation surrounding the wellbore \n1120\n and to the wellbore \n1120\n as indicated by the arrows.', 'The HFN \n1122\n may also be represented in the format as shown in \nFIG.', '11A\n.', 'Due to an assumed contrast between the permeability of the matrix and that of the HFN \n1122\n, global gas flow through the reservoir consisting of both the HFN \n1122\n and the formation matrix can be separated into the gas flow through the HFN \n1122\n and that inside of the matrix blocks \n1128\n.', 'The pattern of gas flow through the HFN \n1122\n may be described approximately as elliptical as shown in \nFIG.', '11A\n.', 'The HFN \n1122\n uses an elliptical configuration to provide a coupling between the matrix and HFN flows that is treated explicitly.', 'A partial differential equation is used to describe fluid flow inside a matrix block that is solved analytically.', 'Three-dimensional gas flow through an elliptic wire mesh HFN can be approximately described by:\n \n \n \n \n \n \n \n \n \n \n \n \n∂\n \n \np\n \nf\n \n \n \n \n∂\n \nt\n \n \n \n-\n \n \n \n1\n \nx\n \n \n\u2062\n \n \n∂\n \n \n∂\n \nx\n \n \n \n\u2062\n \n \n(\n \n \nx\n \n\u2062\n \n \n \n \n\u2062\n \n \nκ\n \nf\n \n \n\u2062\n \n \n \n∂\n \n \np\n \nf\n \n \n \n \n∂\n \nx\n \n \n \n \n)\n \n \n \n \n=\n \n \n \nq\n \ng\n \n \n \n \nϕ\n \nf\n \n \n\u2062\n \n \n \n∂\n \n \np\n \nf\n \n \n \n \n∂\n \np\n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n where t is time, x is the coordinate aligned with the major axis of the ellipse, p\nf \nand ρ\nf \nare fluid pressure and density of fluid, φ\nf \nand κ', 'f \nare the porosity and the x-component of the pressure diffusivity of the HFN, and q\ng \nis the rate of gas flow from the matrix into the HFN.', 'All involved properties may be a function of either t or x or both.', 'For each time t, calculations of fluid pressure using equation (1) may begin from the outmost ring of the elliptical reservoir domain and end at the center of the HFN \n1122\n at wellbore \n1120\n, or in the reverse order.', "Fluid pressure along the elliptical domain's boundary is taken as that of the reservoir before production.", 'It may be assumed that no production takes place outside of the domain.', 'Outside of the HFN, equation (1) still applies nominally, but with q\ng\n=0, φ\nf\n=φ\nm \nand κ\nf\n=κ\nm\n, where φ\nm \nand κ\nm \nare the porosity and the pressure diffusivity of the reservoir matrix.', 'Given q\ng \nthere are various ways available to solve equation (1), either analytically or numerically.', 'Due to the complex nature of the HFN and fluid properties, numerical approaches may be used for the sake of accuracy.', 'An example of numerical solution is given below.', 'Dividing the elliptic reservoir domain containing the HFN into N rings, the rate of gas production from a reservoir matrix into the HFN contained by the inner and outer boundaries of the k-th ring is \n \nq\ngk\n=q\ngxk\nA\nxk\n+q\ngyk\nA\nyk\n\u2003\u2003(2) \n where A\nxk \nand A\nyk \nare the total surface area of the fractures inside of the ring, parallel to the major axis (the x-axis) and the minor axis (they-axis), respectively, and q\ngxk \nand q\ngyk \nare the corresponding rates of fluid flow per unit fracture surface area from the matrix into the fractures parallel to the x- and y-axis, respectively.', 'Fluid pressure p\nf \nand the rate of gas production into the well can be obtained by numerically (either finite difference, finite volume or a similar method) solving equation (1) for any user specified initial and boundary conditions and by coupling the model with a well model.', 'Total surface area of fractures contained inside of the k-th ring can be calculated by\n \n \n \n \n \n \n \n \n \n \nA\n \nxk\n \n \n=\n \n \n4\n \n\u2062\n \n \n \nh\n \nk\n \n \n\u2061\n \n \n[\n \n \n \n \n∑\n \n \nj\n \n=\n \n \n-\n \n \nN\n \nxo\n \n \n \n \n \nN\n \nxo\n \n \n \n\u2062\n \n \n \n \nx\n \nk\n \n2\n \n \n-\n \n \n4\n \n\u2062\n \n \n \n(\n \n \n \njL\n \nmy\n \n \n/\n \nγ\n \n \n)\n \n \n2\n \n \n \n \n \n \n-\n \n \n \n∑\n \n \nj\n \n=\n \n \n-\n \n \nN\n \nxi\n \n \n \n \n \nN\n \nxi\n \n \n \n\u2062\n \n \n \n \nx\n \n \nk\n \n-\n \n1\n \n \n2\n \n \n-\n \n \n4\n \n\u2062\n \n \n \n(\n \n \n \njL\n \nmy\n \n \n/\n \nγ\n \n \n)\n \n \n2\n \n \n \n \n \n \n \n]\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \n \nA\n \nyk\n \n \n=\n \n \n4\n \n\u2062\n \n \nh\n \nk\n \n \n\u2062\n \n \nγ\n \n\u2061\n \n \n[\n \n \n \n \n∑\n \n \ni\n \n=\n \n \n-\n \n \nN\n \nyo\n \n \n \n \n \nN\n \nyo\n \n \n \n\u2062\n \n \n \n \nx\n \nk\n \n2\n \n \n-\n \n \n4\n \n\u2062\n \n \n \n(\n \n \niL\n \nmx\n \n \n)\n \n \n2\n \n \n \n \n \n \n-\n \n \n \n∑\n \n \ni\n \n=\n \n \n-\n \n \nN\n \nyi\n \n \n \n \n \nN\n \nyi\n \n \n \n\u2062\n \n \n \n \nx\n \n \nk\n \n-\n \n1\n \n \n2\n \n \n-\n \n \n4\n \n\u2062\n \n \n \n(\n \n \niL\n \nmx\n \n \n)', '2\n \n \n \n \n \n \n \n]\n \n \n \n \n \n,\n \n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n where γ is the aspect ratio of the elliptical HFN, x\nk \nand h\nk \nare the location and the height of the k-th ring, L\nmx \nand L\nmy \nare the distances between neighboring fractures parallel to the x-axis and the y-axis, respectively, as shown in \nFIG.', '11B\n.', 'The N\nxo \nand N\nxi \nare the number of fractures parallel to and at either side of the x-axis inside the outer and the inner boundaries, respectively, of the k-th ring, and N\nyo \nand N\nyi \nare the number of fractures parallel to and at either side of the y-axis inside the outer and the inner boundaries, respectively, of the k-th ring.', 'The pattern of gas flow through the HFN \n1122\n may also be described based on fluid flow through individual matrix blocks \n1128\n as shown in \nFIG.', '11B\n.', 'FIG.', '11B\n is a detailed view of one of the blocks \n1128\n of HFN \n1122\n of \nFIG.', '11A\n.', 'As shown in this view, the direction of gas flow inside of a matrix block \n1128\n can be approximated as perpendicular to the edges of the matrix block \n1128\n.', 'Fluid flow is assumed to be linear flow toward outer boundaries \n1140\n of the block \n1128\n as indicated by the arrows, with no flow boundaries \n1142\n positioned within the block \n1128\n.', 'Fluid flow inside a rectangular matrix block \n1128\n can be approximately described by\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n∂\n \n \np\n \nm\n \n \n \n \n∂\n \nt\n \n \n \n-\n \n \n \nκ\n \nm\n \n \n\u2062\n \n \n \n \n∂\n \n2\n \n \n\u2062\n \n \np\n \nm\n \n \n \n \n∂\n \n \ns\n \n2\n \n \n \n \n \n \n=\n \n0\n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \np\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \ns\n \n \n)\n \n \n \n=\n \n \np\n \nr\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \np\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n,\n \n \nL\n \ns\n \n \n \n)\n \n \n \n=\n \n \n \np\n \nf\n \n \n\u2061\n \n \n(\n \nt\n \n)', '\u2062\n \n \n \n \n \n\u2062\n \n \n \n∂\n \n \np\n \nm\n \n \n \n \n∂\n \nt\n \n \n \n \n\uf604\n \n \n \ns\n \n=\n \n0\n \n \n \n=\n \n0\n \n \n,\n \n \n \n \n \n(\n \n4\n \n)\n \n \n \n \n \n \n \n where s is the coordinate, aligned with the x-axis or y-axis', ', L is the distance between the fracture surface and the effective no-flow boundary, p\nm \nis fluid pressure and p\nr \nis the reservoir pressure.', 'Equation (4) can be solved to obtain the rate of fluid flow from the matrix into the fractures inside the k-th ring \n \n \n \n \n \n \n \n \n \nq\n \ngxk\n \n \n=\n \n \n \nφ\n \nm\n \n \n\u2062\n \n \n \n∂\n \n \nρ\n \nm\n \n \n \n \n∂\n \np\n \n \n \n\u2062\n \n \n∂\n \n \n∂\n \nt\n \n \n \n\u2062\n \n \n \n∫\n \n0\n \nt\n \n \n\u2062\n \n \n \n \n∂\n \n \np\n \nfk\n \n \n \n \n∂\n \nu\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n[\n \n \n \n \n \nL\n \ny\n \n \n2\n \n \n\u2062\n \n \nerfc\n \n\u2061\n \n \n(\n \n \n \nL\n \ny\n \n \n \n4\n \n\u2062\n \n \n \n \nκ\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n-\n \nu\n \n \n)\n \n \n \n \n \n \n)\n \n \n \n \n+\n \n \n2\n \n\u2062\n \n \n \n \n \nκ\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n-\n \nu\n \n \n)\n \n \n \nπ\n \n \n \n\u2062\n \n \n(\n \n \n1\n \n-\n \n \ne\n \n \n \nL\n \ny\n \n2\n \n \n \n16\n \n\u2062\n \n \n \nκ\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n-\n \nu\n \n \n)\n \n \n \n \n \n \n \n)\n \n \n \n \n]\n \n \n\u2062\n \ndu\n \n \n \n \n \n \n \n \n \n \n(\n \n5\n \n)\n \n \n \n \n \n \n \n \nq\n \ngyk\n \n \n=\n \n \n \nφ\n \nm\n \n \n\u2062\n \n \n \n∂\n \n \nρ\n \nm\n \n \n \n \n∂\n \np\n \n \n \n\u2062\n \n \n∂\n \n \n∂\n \nt\n \n \n \n\u2062\n \n \n \n∫\n \n0\n \nt\n \n \n\u2062\n \n \n \n \n∂\n \n \np\n \nfk\n \n \n \n \n∂\n \nu\n \n \n \n\u2062\n \n \n\u2003\n \n \n \n \n[\n \n \n \n \n \nL\n \nx\n \n \n2\n \n \n\u2062\n \n \nerfc\n \n\u2061\n \n \n(\n \n \n \nL\n \nx\n \n \n \n4\n \n\u2062\n \n \n \n \nκ\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n-\n \nu\n \n \n)\n \n \n \n \n \n \n)\n \n \n \n \n+\n \n \n2\n \n\u2062\n \n \n \n \n \nκ\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n-\n \nu\n \n \n)\n \n \n \nπ\n \n \n \n\u2062\n \n \n(\n \n \n1\n \n-\n \n \ne\n \n \n \nL\n \nx\n \n2\n \n \n \n16\n \n\u2062\n \n \n \nκ\n \nm\n \n \n\u2061\n \n \n(\n \n \nt\n \n-\n \nu\n \n \n)\n \n \n \n \n \n \n \n)\n \n \n \n \n]\n \n \n\u2062\n \ndu\n \n \n,\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n where p\nfk \nis the pressure of the fluid residing in fractures in the k-th ring and ρ\nm \nis the density of the fluid residing in the matrix.', 'The coupling of p\nfk \nand q\ngk \ncalculations can be either explicit or implicit.', 'It may be implicit for the first time step even if the rest of the time is explicit.', 'Conventional techniques may also be used to describe the concept of fluid flow through a dual porosity medium.', 'Some such techniques may involve a one-dimensional pressure solution with constant fracture fluid pressure, and depict an actual reservoir by identifying the matrix, fracture, and vugs therein as shown in \nFIG.', '11C\n, or depicting the reservoir using a sugar cube representation as shown in \nFIG.', '11D\n.', 'Examples of conventional fluid flow techniques are described in Warren et al., “The Behavior of Naturally Fractured Reservoirs”, SPE Journal, Vol. 3, No. 3, September 1963.', 'Examples of fracture modeling that may be used in the modeling described herein are provided in Wenyue Xu et al., “Quick Estimate of Initial Production from Stimulated Reservoirs with Complex Hydraulic Fracture Network,” SPE 146753, SPE Annual Tech.', 'Conf. and Exhibition, Denver, Colo., 30 Oct.-2 Nov. 2011, the entire content of which is hereby incorporated by reference.\n \nFIG.', '11E\n shows a flow chart depicting a method for fracture modeling.', 'In one or more embodiments, one or more of the steps shown in \nFIG.', '11E\n may be omitted, repeated, and/or performed in a different order than the order shown in \nFIG.', '11E\n.', 'Accordingly, the scope of modeling hydraulic fracturing induced fracture networks as a dual porosity system should not be considered limited to the specific arrangement of steps shown in \nFIG.', '11E\n.', 'In element \n1102\n, well data may be loaded for three-dimensional modeling.', 'For example, the data listed below in Table 1 may be obtained for three-dimensional modeling.', 'TABLE 1\n \n \n \n \n \n \nCategory\n \nData Item', 'Well head\n \nLocation (x, y), Kelly bushing, total depth\n \n \n \nWell path\n \nDeviation survey\n \n \n \nWell logs\n \nConventional log and interpretations (gamma,\n \n \n \n \nresistivity, porosity, Sw, density, neutron,\n \n \n \n \ncaliper etc.), Logging', 'While Drilling (LWD)\n \n \n \n \nLithology (ELAN interpretations), Mineralogy\n \n \n \n \n(ECS) and Toc, Sw, Perm, porosity, AdsGas,\n \n \n \n \nfreeGas etc. (Shale Gas Advisor)\n \n \n \n \nLithofacies (Cluster - reservoir quality indicator)\n \n \n \n \nRock mechanical property and stress (DSI dipole\n \n \n \n \nshear sonic imaging/Sonic Scanner/MDT (modular\n \n \n \n \nformation dynamics tester) packer module)\n \n \n \n \nBorehole image (FMI, formation micro images) and\n \n \n \n \ninterpretations; fracture categories, corrections\n \n \n \n \nand analyses\n \n \n \nCore data\n \nLab test of petrophysical (k, phi, sw etc.), and\n \n \n \n \ngeomechanical (UCI (ultrasonic casing imager),\n \n \n \n \nelastic properties, including anisotropy) for\n \n \n \n \npossible log calibration\n \n \n \nIsothermal\n \nShale rock adsorption/desorption test data; gas\n \n \n \n \ncontent (Langmuir pressure and volume constants);\n \n \n \n \nsingle and multi-component data\n \n \n \nWell tops\n \nMarker well name, depth, dip and azimuth if any\n \n \n \nStructure\n \nSurface, faults interpretation if any\n \n \n \nSeismic\n \nOriginal volume, and various derived attributes,\n \n \n \n \nand loading parameters\n \n \n \nVelocity\n \nSonic log and check shots or velocity models or\n \n \n \n \nparameters\n \n \n \nFracturing\n \nStages, gases, liquid and proppants volumes,\n \n \n \nJob\n \nschedules, properties of injected materials\n \n \n \nMicro\n \nVariety of attributes, pumping records, rate,\n \n \n \nSeismic\n \npressure, ISIP (instantaneous shut in pressure) data\n \n \n \nProduction\n \nProduction surveys, tracer test, well testing,\n \n \n \n \nand production dynamic data\n \n \n \nCompletion\n \nWellbore data, perforation, length\n \n \n \nFluid &\n \nGas composition, water and oil, and other PVT\n \n \n \nRock\n \n(pressure-volume-temperature) properties;\n \n \n \n \nsaturation functions\n \n \n \nReports\n \nAny previous studies and reports\n \n \n \n \n \n \n \n \n \n \nIn element \n1104\n, surface and fault interpretations may be performed in the time domain.', 'Specifically, surface seismic interpretation can be accelerated with autotracking, and fault interpretation can be expedited through ant-tracking using simulation software.', 'With the majority of the well data in the depth domain, seismic results may also be depth-converted and integrated.', 'Often, check shots, sonic logs, and velocity data are available to build the velocity model.', 'In one or more embodiments, interval velocities produced for each stratigraphic unit (zone) are satisfactory for modeling reservoirs.', 'In element \n1106\n, depth conversion may be performed to convert time domain seismic information such as original seismic data volumes or any other special seismic attributes, interpreted surfaces, and faults.', 'Depth surfaces and/or well tops may be used to build model horizons.', 'At this stage, the horizons and well controls, together with proper fault modeling, segment definition, and boundary conditions are used to create a three-dimensional structure model (element \n1108\n).', 'The three-dimensional model provides a framework for further geomechanical zone modification, log upscaling, seismic attributes resampling, data analysis, correlation development, fracture simulation driver development, discrete fracture modeling, and reservoir simulation gridding.', 'In element \n1110\n, a discrete fracture network (DFN) may be generated.', 'Specifically, edge enhancement may be performed to identify faults, fractures, and other linear anomalies using seismic data.', 'In this case, the seismic data may be conditioned by reducing noise in the signal, spatial discontinuities in the seismic data (edge detection) are then enhanced, and finally a seismic three-dimensional volume including automated structural interpretations is generated, which significantly improves the fault attributes by suppressing noise and remnants of non-faulting events.', 'Fault patches or planes of discontinuity can then be extracted from the three-dimensional seismic volume.', 'The patches of faults or fractures are analyzed and edited, and fracture/fault patches can be directly converted as a deterministic DFN.', 'In shale gas reservoir applications, the three-dimensional seismic volume is used to identify significant fault and karst features.', 'The karst features may be extracted and modeled as faults in conjunction with production, tracer testing, and well testing analysis to reveal the large-scale reservoir connectivity.', 'A general observation in terms of reservoir connectivity is that wells several miles apart may have pressure communications.', 'The pressure communications may be considered by manually adding fractures in the fracture model.', 'Although open natural fractures may not be identified from core samples, borehole images such as formation micro-images (FMI), OBM (oil based mud) images, UBI (ultrasonic borehole imager) images, and LWD (Logging While Drilling) images may be used to interpret natural fractures (e.g., open, partially opened or healed fractures) and drilling induced fractures, which are subject to easier opening by hydraulic fracturing than virgin shale rock.', 'In view of this, all types of interpreted fractures may be considered as constituting a “natural” or “pre-existing” fracture network that partially controls hydraulic fracture network intensity and distribution.', 'Thus, one use of the “natural” network information is to assist the design of well path and hydraulic fracturing.', 'FMI interpreted fractures (and intensity logs) may also be classified, analyzed, and correlated with rock properties, geomechanical zones, and other seismic drivers.', 'Further, various seismic attributes may be resampled into the three-dimensional model.', 'With flexible functionalities in the three-dimensional model space, different fracture intensity drivers may be evaluated.', 'The fracture intensity drivers include, but are not limited to, distance to faults, lithological properties, discontinuous properties, or neural network train-estimation derived properties (care should be taken to identify correlated drivers).', 'With proper property drivers, fracture intensity three-dimensional distributions may be achieved, mostly with stochastic simulations or possible deterministic methods.', 'Those skilled in the art will appreciate that different types or sets of fracture intensity properties can be simulated separately with different drivers to reflect specific natural characteristics.', 'With known well control fracture dips and azimuths input as constants, two-dimensional or three-dimensional properties, and specific fracture geometry specifications, three-dimensional discrete fracture network (DFN) can be generated.', 'In element \n1114\n, microseismic (MS) mapping and post-hydraulic fracturing (PHF) network modeling may be performed.', 'For example, based on the available field data, a proximal solution may be provided.', 'As discussed above, MS monitoring has been used in the shale gas reservoir to monitor fracture propagation and the hydraulic job process, and to control fracture propagation through pressure/rate change and techniques such as fiber-assisted or particle-assisted diversion.', 'The significant features of aerially similar MS events distribution indicates that the shale gas reservoir PHF system is a fracture network, and therefore various operational techniques may be used to create additional aerial coverage and an intensified PHF network.', 'In one or more embodiments, an MS event envelope is used to estimate a three-dimensional hydraulic fracturing stimulated reservoir volume (ESV) and then hydraulic fracturing job parameters are applied to estimate dynamic and propped fracture conductivity (possible permeability and width estimation).', 'To estimate the PHF network, the MS event envelope may be extracted from the three-dimensional model.', 'In simple cases, a two-dimensional mapview can be used to obtain the outside boundary.', 'Vertically, the fractures growing into a non-reservoir formation may be considered for volume correction when calculating fluid and proppant conservations.', 'With certain fracture propagation model assumptions, fluid and proppant mass conservation and fracture width distribution and fracture network intensity can be estimated and corresponding propped fracture width can be calculated.', 'By applying laboratory results, fracture conductivity (FCD) may be estimated.', '“Natural” fracture DFN within an MS event envelope may be assumed to be opened and propped for evaluation in a base case reservoir simulation.', 'In element \n1116\n, fracture attributes and discrete fracture network (DFN) upscaling may be performed.', 'For example, fracture attributes may be associated with a DFN.', 'During DFN modeling as discussed above with respect to element \n1110\n, geometry parameters may be assigned to each fracture such as: surface area, dip angle, and dip azimuth.', 'Other examples of attributes that may be assigned or calculated are aperture and permeability.', 'The aperture data may be related to the calculations of porosity permeability.', 'For both “natural” fracture networks and PHF networks with proper aperture and permeability, respectively, upscaling may be performed.', 'The “natural” fracture network may serve as a background reservoir, and the PHF network, as modified with the MS and fracture job data, may serve as a stimulated reservoir volume with enhanced reservoir properties.', 'In one or more embodiments, the discrete fracture system may be upscaled to a dual porosity/permeability reservoir model and then use simulator(s) to model the reservoir dynamics.', 'Examples of properties generated by the upscaling process include fracture porosity, fracture permeability, Sigma (shape) factor defining the connectivity between fractures and matrix, and fracture spacing along local directions (I, J, K) for each grid cell.', 'Those skilled in the art will appreciate that the dual porosity modeling approach may not be suitable for all cases.', 'A proper simulation should be based on a proper understanding of the DFN and PHF fracture systems and corresponding shale production mechanism.', 'Elements \n1110\n, \n1114\n and \n1116\n may be combined or replaced with an alternative methodology as shown in element \n1117\n.', 'More specifically, in element \n1117\n fracture geometry is computed, fracturing pressure is estimated, fracture conductivity and distribution of proppants are estimated, and fracture productivity is determined.', 'In element \n1112\n, the structure from element \n1108\n and the DFN from element \n1110\n may be used to perform geomechanical modeling, where the results are used for generating a well path and hydraulic fracturing treatment (HFT) design with stress constraints and fault/karst avoidance.', 'Specifically, the DFN including the FMI interpreted fractures may be used to generate the HFT design, where the natural tendency of the formation to fracture may be taken into account in order to optimize the hydraulic fracturing.', 'In other words, based on the fracture orientations, network distribution and intensity of the natural fracture determined in element \n1110\n, proper well orientation and fracturing stage and perforation cluster designs may be generated to maximize fracture intensity and control PHF network distribution.', 'Further, the results are also fed into element \n1121\n, as expressed below as the geomechanical modeling repeated in element \n1123\n.', 'Some geomechanical and petrophysical properties may be obtained at well location for example through core analysis and log interpretation.', 'Further, varieties of seismic attributes reflect lithofacies and mechanical and petrophysical formation characteristics.', 'A geostatistical approach may be used to model the properties in a three-dimensional distribution using well data as the primary data source and the seismic as secondary constraints.', 'For example, lithofacies representations may correspond to a cluster result derived from a suite of basic logs (gamma, resistivity, density).', 'The clusters (or lithofacies) data is used to classify mechanical and petrophysical properties.', 'Within each cluster, constant values may be assigned, or conduct stochastic simulations may be performed.', "The properties modeled using well logs and seismic include, but are not limited to, cluster facies, porosity, water saturation, permeability, total organic carbon (TOC), shale gas content and Young's modulus, Poisson's ratio, etc.", 'In one or more embodiments, Sonic Scanner/DSI (dipole sonic image) derived parameters may be direction simulated and used to obtain final properties.', 'In element \n1118\n, the petrophysical properties such as effective porosity, water saturation, and gas content from the three-dimensional geological structure model generated in element \n1108\n may be used to estimate gas-in-place (GIP).', 'In this case, the petrophysical properties may also be processed using an uncertainty workflow to rank the risks of various aspects of the wellbore.', 'In element \n1121\n, a reservoir simulation may be performed.', 'The dual porosity reservoir properties (fracture permeability, etc.) upscaled from the DFN in element \n1116\n and petrophysical matrix properties (e.g., phie, Sw, etc.)', 'by stochastic simulation may be utilized by the reservoir simulator.', 'With a known well completion configuration and production control, production history matching may be pursued to confirm or modify the reservoir model, especially the fracture network geometry, fracture connectivity, and permeability.', 'Further, experimental design methodology may be used to perform sensitivity analysis, assist the history-matching process, and improve the reservoir characterization.', 'In addition, a full, automated, history-matching process may be used to link geological model variation and the reservoir simulation in an iterative process.', 'If permeability change versus reservoir pressure is known, the impact of permeability decrease with production of flowback fluid may be considered.', 'In element \n1123\n, geomechanical modeling and stress analysis may be performed.', 'Specifically, FMI interpreted drilling-induced fractures and possible wellbore breakouts may be used to determine stress direction and distribution.', 'Sonic Scanner and DSI (dipole sonic image) data may also be used to estimate mechanical properties of rock formations and stresses.', 'Wire line formation tester (e.g., modular formation dynamics tester or some other tester) tests and interpretation may be used to calibrate in-situ stress data (pore pressure and minimum stress).', 'Further, some seismic attributes may be extracted to guide a three-dimensional stress field distribution.', 'Using reservoir simulation software, a mechanical earth model (MEM) with rock mechanical properties, faults, fractures, overburden, underburden, side burden, complex geological structures, and pore pressure and stress/strain boundary conditions may be generated and used for pore pressure prediction, geomechanical modeling, and wellbore stability analysis.', 'Geomechanical modeling packages (such as a stress analysis simulator) could simulate in-situ stress distribution, stress-sensitive permeability and porosity changes, and study hydraulic fracture propagation mechanism.', 'Coupling geomechanical modeling (stress analysis simulation) with reservoir simulation may optimize reservoir development strategies, wellbore stability analysis, optimum mud weight design, formation subsidence, and casing damage analyses with reservoir depletion.', 'In element \n1124\n, well spacing, hydraulic fracturing design, and/or production optimization may be performed.', 'In the case of production optimization, control parameters of the hydraulic fracturing process may be modified based on the reservoir simulation of element \n1123\n (i.e., where to create the fracture network, how intensified the network needs to be, and how to implement through operations).', 'Further, based on reservoir characterization as proposed above, the following steps may be performed: 1) using the geological modeling result, particularly the DFN network information, geomechanical heterogeneity and stress field, to conduct a geomechanical modeling study to provide qualitative guidance for a well path, well completion, fracture stages and cluster designs; 2) establishing a relationship among reservoir characteristics, job processes, various scenarios (e.g., well lengths, fracture stages, liquid and proppant volumes, etc.), and reservoir production behavior; 3) performing reservoir simulation sensitivity analysis (ensuring that the proper application of the dual porosity model is applied in simulation); 4) extracting guidelines for future design practices and operations.', 'Those skilled in the art will appreciate that portions of \nFIG.', '11E\n may be applied in various field development stages.', 'For example, elements of \nFIG.', '11E\n may be performed to construct structural models and three-dimensional visualizations of a structural surface superimposed with seismic attributes to monitor live fracturing jobs and respond with operation modifications such as fiber diversion (e.g., a stage of slurry containing degradable fibers is used to create a temporary bridge within the fracture, and make a pressure increase and force fracture propagation into another zone or a different area of the same formation).', 'In another example, elements of \nFIG.', '11E\n may be performed to distribute three-dimensional clusters in reservoirs (clusters denoting reservoir quality).', 'Further, geostatistical property modeling may be used to upscale facies log and simulate with seismic attributes and neural network trained-estimation properties.', 'In this case, the significant features of facies continuity may be confirmed with an additional cluster log, where the simulated three-dimensional result is used to guide well path design, targeting the best quality of the reservoir.', 'In yet another example, elements of \nFIG.', '11E\n may be performed to distribute the DFN in a three-dimensional reservoir and analyze the relationship between MS events response and “natural” fracture orientations.', 'In this example, the total set of fractures may be divided into four subsets: N_S:N, N_S:S, E_W:E, and E_W:W. Drilling-induced fractures may be aligned with one subset (e.g., E-W) of natural fractures (thus the minimum stress direction is perpendicular to fracture strike in the E-W set).', 'Following the workflow, the DFN network may be simulated, and MS events may be displayed over the DFN network.', 'The MS events may be controlled by the minimum stress direction and the existing “natural” fractures.', 'Specifically, MS events may align with the subsets of E_W:W and E_W:E, where the N_S sets help create the wide band nature of the MS events.', 'Control System—Choke Control\n \nAs described above, the drawdown pressure can be calculated from the determined pressure distributions output by the flowback model \n514\n (\nFIGS.', '3 and 4\n).', 'For example, \nFIG.', '12\n illustrates schematically localized bottomhole and reservoir pressures at a downstream end of a production liner \n1204\n in a hydraulically fractured reservoir \n1202\n.', 'When the choke \n508\n (\nFIGS.', '3 and 4\n) is partially open and fluids begin to move from the reservoir \n1202\n into the liner \n1204\n, the drawdown pressure will change over time.', 'In the example shown in \nFIG.', '12\n, initially at time t=0, the reservoir pressure is 9,000 psi (radially uniform distribution) and the initial bottomhole pressure is 8,000 psi, resulting in an initial drawdown pressure of 1,000 psi at time t=0.', 'Also, in the example shown in \nFIG.', '12\n, at time t=10 days, after at least some fluid has moved from the reservoir and into the liner \n1204\n, there is a non-uniform radial reservoir pressure distribution in which the pressure at a first, radially proximate region \n1202\na \nis 8,000 psi, at a second, radially distal region \n1202\nb \nis 9,000 psi, and the bottomhole pressure is 7,000 psi.', 'Thus, after 10 days, the average reservoir pressure is 8,500 psi, such that the drawdown pressure is 1,500 psi.', 'Thus, in the example in \nFIG.', '12\n the drawdown pressure increased 500 psi in the span of 10 days.', 'The calculated drawdown pressure in the example of \nFIG.', '12\n may be continuously calculated and compared against a schedule of maximum/minimum allowable drawdown pressures over time as determined from a predetermined functional relationship, such as the curves shown in \nFIG.', '13\n.', 'Such a schedule of drawdown pressures may be used by the automatic choke control \n512\n for determining the recommended choke setting in block \n540\n, as discussed above.', 'FIG.', '13\n illustrates a safe zone \n1302\n in which to conduct the flowback operations.', 'The safe zone \n1302\n is bounded by two drawdown curves: an upper curve \n1304\n for an upper limit of maximum allowable drawdown pressure; and a lower curve \n1306\n for a lower limit of maximum allowable drawdown pressure.', 'The curves \n1304\n and \n1306\n in \nFIG.', '13\n may be obtained experimentally from sampling rock of the reservoir, such as reservoir \n1202\n in the example of \nFIG.', '12\n.', 'For example, strength and permeability testing—ideally as a function of completion fluid type—may be done on each section of the reservoir that is expected to be contacted by the hydraulic fracture network (HFN) to determine the variability in rock strength.', 'The initial flowback strategy may be tailored to the weakest section of the reservoir that would have an impact on production.', 'Without these values it would not be possible to determine the initial drawdown limits in \nFIG.', '13\n, nor how they vary with time.', 'Turning back to \nFIG.', '4\n, at block \n540\n a comparison between the calculated drawdown pressure and the maximum allowable drawdown pressures on curves \n1304\n and \n1306\n may be used to make recommendations for adjustment of the choke \n508\n.', 'For example, if the calculated drawdown pressure is outside of the safe zone \n1302\n in \nFIG.', '13\n, then adjustments to the choke \n508\n may be recommended to increase or decrease the bottomhole pressure.', 'Specifically, if the calculated drawdown pressure at a respective time is above the safe zone \n1302\n (i.e., in the failure zone) in \nFIG.', '13\n, then a recommendation may be generated at block \n540\n to adjust the choke \n508\n to partially or fully close, to thereby limit damage to the reservoir.', 'If the determined drawdown pressure at a respective time is below the safe zone \n1302\n, then a recommendation may be generated at block \n540\n to adjust the choke \n508\n to partially or fully open to increase the flow rate of flowback fluid to improve efficiency of the flowback operation.', 'Also, if the calculated drawdown pressure is within the safe zone \n1302\n of \nFIG.', '13\n, recommendations may be made to adjust the choke \n508\n while still operating in the safe zone \n1302\n.', 'For example, if the calculated drawdown pressure is within the safe zone \n1302\n, there may be an opportunity to increase the flow rate of flowback fluid while still operating in the safe zone \n1302\n.', 'For example, if the target flow rate of oil is higher than the measured flow rate and the calculated drawdown pressure is within the safe zone \n1302\n, then a recommendation can be made to adjust the choke \n508\n to open more to increase the flow of oil in the flowback fluid, while monitoring that the drawdown pressure does not exceed that of the upper curve \n1304\n in \nFIG.', '13\n.', 'Slug Formation\n \nFIG.', '15\n illustrates a ternary diagram \n1550\n that includes vertices that represent single-phase gas, oil and water, while the sides represent two phase mixtures (e.g., gas-oil, oil-water and gas-water) and points within the triangle represents a three-phase mixture.', 'A transition region indicates where the liquid fraction changes from water-in-oil to oil-in-water and vice versa (e.g., consider emulsions).', 'The ternary diagram \n1550\n also indicates some examples of ranges of multiphase flow regimes, which may be affected by one or more factors such as, for example, temperature, pressure, viscosity, density, flow line orientation, etc.', 'The example flow regimes include annular mist, slug flow, and bubble flow; noting that other types of may occur (e.g., stratified, churn, disperse, etc.).', 'Annular mist flow may be characterized by, for example, a layer of liquid on the wall of a pipe and droplets of liquid in a middle gas zone (e.g., mist).', 'Slug flow may be characterized by, for example, a continuous liquid phase and a discontinuous liquid phase that is discontinuous due to separation by pockets of gas.', 'Bubble flow may be characterized by, for example, two continuous liquid phases where at least one of the continuous liquid phases includes gas bubbles.', 'The illustrative graphics of flow regimes in \nFIG.', '15\n correspond to flows in approximately horizontal conduits (e.g., production liner \n210\n of \nFIG.', '1\n)', '; noting that a conduit may be disposed at an angle other than horizontal and that various factors that can influence flow may depend on angle of a conduit.', 'For example, the angle of a conduit with respect to gravity can have an influence on how fluid flows in the conduit.', 'In vertical flow (i.e., in production tubing \n206\n in \nFIG.', '1\n), the slug is an axially symmetrical bullet shape that occupies almost the entire cross-sectional area of the tubing.', 'The table \n1560\n of \nFIG.', '15\n shows viscosity and density as fluid properties.', 'As to one or more other properties, consider, for example, surface tension.', 'As indicated, the table \n1560\n can include information for points specified with respect to the ternary diagram \n1550\n.', 'As an example, factors such as pressure, volume and temperature may be considered, for example, as to values of fluid properties, phases, flow regimes, etc.', 'As an example, information as to flow of fluid may be illustrated as a flow regime map that identifies flow patterns occurring in various parts of a parameter space defined by component flow rates.', 'For example, consider flow rates such as volume fluxes, mass fluxes, momentum fluxes, or one or more other quantities.', 'Boundaries between various flow patterns in a flow regime map may occur where a regime becomes unstable and where growth of such instability causes transition to another flow pattern.', 'As in laminar-to-turbulent transition in single-phase flow, multiphase transitions may be rather unpredictable as they may depend on otherwise minor features of the flow, such as the roughness of the walls or the entrance conditions.', 'Thus, as indicated in the ternary diagram \n1550\n, flow pattern boundaries may lack distinctiveness and exhibit transition zones.', 'As to properties, where fluid is single phase (e.g., water, oil or gas), a single value of viscosity may suffice for given conditions.', 'However, where fluid is multiphase, two or more concurrent phases may occupy a flow space within a conduit (e.g., a pipe).', 'In such an example, a single value of viscosity (e.g., or density) may not properly characterize the fluid in that flow space.', 'Accordingly, as an example, a value or values of mixture viscosities may be used, for example, where a mixture value is a function of phase fraction(s) for fluid in a multiphase flow space.', 'As to surface tension (e.g., σ), it may be defined for gas and/or liquid, for example, where the liquid may be oil or water.', 'Where two-phase liquid-liquid flow exists (e.g., water and oil), then a may reflect the interfacial tension between oil and water (see, e.g., the slug flow regime and the bubble flow regime).', 'Multiphase flow, including slug flow, may be modeled and simulated.', 'Multi-dimensional simulation presents a challenge, however, as it may require an impractical amount of computing resources and/or time.', 'Thus, at least for long pipelines, one-dimensional models may be employed, in which properties of the flow are averaged over the pipe cross-section.', 'The model then describes how these averaged properties vary along the pipeline and with time.', 'Such models may implement various strategies for modeling slug flow.', 'For example, in “slug tracking,” the boundaries (front and tail) of the slugs are followed as they propagate along the pipe.', 'Thus, the slugs and separated zones are represented on a Lagrangian grid, which is superimposed on the Eulerian grid used to solve the basic equations.', 'In another example, “slug capturing,” the underlying equations are resolved on a fine Eulerian grid, including the growth of large waves and the formation of slugs, so that each slug is represented.', 'These models may provide satisfactory results in a wide variety of contexts.', 'However, some such methods of slug flow modeling and simulation may include long computation times, accuracy and/or stability issues, and/or tuning to match experimental or otherwise measured datasets, such as by using an iterative, trial-and-error process.\n \nFIG.', '16\n illustrates an example of a system \n1600\n that includes various management components \n1610\n to manage various aspects of a pipeline environment \n1650\n (e.g., an environment that includes wells, transportation lines, risers, chokes, valves, separators, etc.).', 'For example, the management components \n1610\n may allow for direct or indirect management of design, operations, control, optimization, etc., with respect to the pipeline environment \n1650\n.', 'In turn, further information about the pipeline environment \n1650\n may become available as feedback \n1660\n (e.g., optionally as input to one or more of the management components \n1610\n).', 'In the example of \nFIG.', '16\n, the management components \n1610\n include a pipeline configuration component \n1612\n, an additional information component \n1614\n (e.g., fluid measurement data), a processing component \n1616\n, a simulation component \n1620\n, an attribute component \n1630\n, an analysis/visualization component \n1642\n and a workflow component \n1644\n.', 'In operation, pipeline configuration data and other information provided per the components \n1612\n and \n1614\n may be input to the simulation component \n1620\n.', 'In an example embodiment, the simulation component \n1620\n may rely on pipeline components or “entities” \n1622\n.', 'The pipeline components \n1622\n may include pipe structures and/or equipment.', 'In the system \n1600\n, the components \n1622\n can include virtual representations of actual physical components that are reconstructed for purposes of simulation.', 'The components \n1622\n may include components based on data acquired via sensing, observation, etc. (e.g., the pipeline configuration \n1612\n and other information \n1614\n).', 'An entity may be characterized by one or more properties (e.g., a pipeline model may be characterized by changes in pressure, heat transfer, pipe inclination and geometry, etc.).', 'Such properties may represent one or more measurements (e.g., acquired data), calculations, etc.', 'In an example embodiment, the simulation component \n1620\n may operate in conjunction with a software framework such as an object-based framework.', 'In such a framework, entities may include entities based on pre-defined classes to facilitate modeling and simulation.', 'A commercially available example of an object-based framework is the MICROSOFT® .NET® framework (Redmond, Wash.), which provides a set of extensible object classes.', 'In the .NET® framework, an object class encapsulates a module of reusable code and associated data structures.', 'Object classes can be used to instantiate object instances for use by a program, script, etc.', 'For example, borehole classes may define objects for representing boreholes based on well data.', 'In the example of \nFIG.', '16\n, the simulation component \n1620\n may process information to conform to one or more attributes specified by the attribute component \n1630\n, which may include a library of attributes.', 'Such processing may occur prior to input to the simulation component \n1620\n (e.g., consider the processing component \n1616\n).', 'As an example, the simulation component \n1620\n may perform operations on input information based on one or more attributes specified by the attribute component \n1630\n.', 'In an example embodiment, the simulation component \n1620\n may construct one or more models of the pipeline environment \n1650\n, which may be relied on to simulate behavior of the pipeline environment \n1650\n (e.g., responsive to one or more acts, whether natural or artificial).', 'In the example of \nFIG.', '16\n, the analysis/visualization component \n1642\n may allow for interaction with a model or model-based results (e.g., simulation results, etc.).', 'As an example, output from the simulation component \n1620\n may be input to one or more other workflows, as indicated by a workflow component \n1644\n.', 'As an example, the simulation component \n1620\n may include one or more features of a simulator such as a simulator provided in OLGA® (Schlumberger Limited, Houston Tex.', 'Further, in an example embodiment, the management components \n1610\n may include features of a commercially available framework such as OLGA® or the PETREL® seismic to simulation software framework (Schlumberger Limited, Houston, Tex.).', 'The PETREL® framework provides components that allow for optimization of exploration and development operations.', 'The PETREL® framework includes seismic to simulation software components that can output information for use in increasing reservoir performance, for example, by improving asset team productivity.', 'Through use of such a framework, various professionals (e.g., geophysicists, geologists, pipeline engineers, and reservoir engineers) can develop collaborative workflows and integrate operations to streamline processes.', 'Such a framework may be considered an application and may be considered a data-driven application (e.g., where data is input for purposes of modeling, simulating, etc.).', 'In an example embodiment, various aspects of the management components \n210\n may include add-ons or plug-ins that operate according to specifications of a framework environment.', 'For example, a commercially available framework environment marketed as the OCEAN® framework environment (Schlumberger Limited, Houston, Tex.) allows for integration of add-ons (or plug-ins) into OLGA® or a PETREL® framework workflow.', 'The OCEAN® framework environment leverages NET® tools (Microsoft Corporation, Redmond, Wash.) and offers stable, user-friendly interfaces for efficient development.', 'In an example embodiment, various components may be implemented as add-ons (or plug-ins) that conform to and operate according to specifications of a framework environment (e.g., according to application programming interface (API) specifications, etc.).', 'FIG.', '16\n also shows an example of a framework \n1670\n that includes a model simulation layer \n1680\n along with a framework services layer \n1690\n, a framework core layer \n1695\n and a modules layer \n1675\n.', 'The framework \n1670\n may include the commercially available OCEAN® framework where the model simulation layer \n1680\n may be either OLGA® or the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.', 'In an example embodiment, the PETREL® software may be considered a data-driven application.', 'The PETREL® software can include a framework for model building and visualization.', 'As an example, a framework may include features for implementing one or more mesh generation techniques.', 'For example, a framework may include an input component for receipt of information from interpretation of pipeline configuration, one or more attributes based at least in part on pipeline configuration, log data, image data, etc.', 'Such a framework may include a mesh generation component that processes input information, optionally in conjunction with other information, to generate a mesh.', 'In the example of \nFIG.', '16\n, the model simulation layer \n1680\n may provide domain objects \n1682\n, act as a data source \n1684\n, provide for rendering \n1686\n and provide for various user interfaces \n1688\n.', 'Rendering \n1686\n may provide a graphical environment in which applications can display their data while the user interfaces \n1688\n may provide a common look and feel for application user interface components.', 'As an example, the domain objects \n1682\n can include entity objects, property objects and optionally other objects.', 'Entity objects may be used to geometrically represent wells, surfaces, bodies, reservoirs, etc., while property objects may be used to provide property values as well as data versions and display parameters.', 'For example, an entity object may represent a well where a property object provides log information as well as version information and display information (e.g., to display the well as part of a model).', 'In the example of \nFIG.', '16\n, data may be stored in one or more data sources (or data stores, generally physical data storage devices), which may be at the same or different physical sites and accessible via one or more networks.', 'The model simulation layer \n1680\n may be configured to model projects.', 'As such, a particular project may be stored where stored project information may include inputs, models, results and cases.', 'Thus, upon completion of a modeling session, a user may store a project.', 'At a later time, the project can be accessed and restored using the model simulation layer \n1680\n, which can recreate instances of the relevant domain objects.', 'In the example of \nFIG.', '16\n, the pipeline environment \n1650\n may be outfitted with any of a variety of sensors, detectors, actuators, etc.', 'For example, equipment \n1652\n may include communication circuitry to receive and to transmit information with respect to one or more networks \n1655\n.', 'Such information may include information associated with downhole equipment \n1654\n, which may be equipment to acquire information, to assist with resource recovery, etc.', 'Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.', 'As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc.', 'For example, \nFIG.', '16\n shows a satellite in communication with the network \n1655\n that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).', 'FIG.', '16\n also shows the geologic environment \n1650\n as optionally including equipment \n1657\n and \n1658\n associated with a well.', 'As an example, the equipment \n1657\n and/or \n1658\n may include components, a system, systems, etc. for pipeline condition monitoring, sensing, valve modulation, pump control, analysis of pipeline data, assessment of one or more pipelines \n1656\n, etc.', 'The pipelines \n1656\n may include at least a portion of the well, and may form part of, or be representative of, a network of pipes which may transport a production fluid (e.g., hydrocarbon) from one location to another.', 'As mentioned, the system \n1600\n may be used to perform one or more workflows.', 'A workflow may be a process that includes a number of worksteps.', 'A workstep may operate on data, for example, to create new data, to update existing data, etc.', 'As an example, a workstep may operate on one or more inputs and create one or more results, for example, based on one or more algorithms.', 'As an example, a system may include a workflow editor for creation, editing, executing, etc. of a workflow.', 'In such an example, the workflow editor may provide for selection of one or more pre-defined worksteps, one or more customized worksteps, etc.', 'As an example, a workflow may be a workflow implementable in OLGA® or the PETREL® software, for example, that operates on pipeline configuration, seismic attribute(s), etc.', 'As an example, a workflow may be a process implementable in the OCEAN® framework.', 'As an example, a workflow may include one or more worksteps that access a module such as a plug-in (e.g., external executable code, etc.).\n \nFIG.', '17\n illustrates a flowchart of a method \n1700\n for modeling a slug flow, e.g., in a multiphase fluid flow model, according to an embodiment.', 'The method \n1700\n may be employed as part of a fluid flow or pipeline model.', 'The model may include representations of one or more fluid conduits (e.g., pipes, wells) and/or other pipeline equipment (compressors, pumps, separators, slug catchers, etc.).', 'Such models may be representative of real-world, physical pipelines systems, or may be constructed as part of the planning of such systems.', 'Accordingly, in some embodiments, the method \n1700\n may include creating a multiphase fluid transient flow model, such as by using OLGA® or any other suitable pipeline modeling/simulation system.', 'In another embodiment, the method \n1700\n may include receiving a completed fluid flow model.', 'Either case may be considered as part of receiving a fluid flow model, e.g., as at \n1702\n.', 'As indicated, the model may include a representation of one or more conduits, as well as a flow of multiphase fluid therein.', 'The conduits may be modeled, e.g., according to geometry (e.g., diameter, length, etc.), pressure change, elevation gain, heat transfer, and/or the like.', 'For the remainder of the present description, the model is described in terms of “pipes”; however, it will be readily apparent that the disclosure is not limited to pipes and may apply to any type of fluid conduit.', 'In an embodiment, the multiphase fluid flow may be modeled based on the parameters of the pipes (and/or other equipment), as well as the underlying equations of mass, state, energy, etc.', 'The method \n1700\n may also include determining a slug birth rate in the multiphase fluid flow, as at \n1704\n.', 'The slug birth rate may be determined based on one or more of a variety of factors, which may be provided as part of a slug birth rate model.', 'The birth rate, generally referred to as ‘B’ herein, may thus represent the number of new slugs per length of pipe per second.', 'The slug birth rate may be zero unless conditions exist that allow slugs to form.', 'A first one of such conditions may be known as a “minimum slip criterion” or “slug growth criterion.”', 'More particularly, in an embodiment, the minimum slip criterion may be satisfied if, were a slug to be introduced into the flow, the velocity of the slug front V\nF \nwould exceed the velocity of the slug tail V\nT \n(i.e., V\nF\n−V\nT\n>0).', 'The difference between V\nF \nand V\nT \nmay represent a mean growth rate of slugs, and may also be representative of a distance from the minimum slip boundary, or the degree of instability of the local separated flow.', 'Accordingly, the value of the difference may represent a driving force, and thus an increasing probability, for new slugs to form, as will be described below.', 'For a slug to be counted (e.g., in the determination of N, below) it may have a length of', 'at least the pipe diameter D. Thus, the time for a slug to form may scale as D/(V\nF\n−V\nT\n), and the rate at which new slugs form may scale as (V\nF\n−V\nT\n)/D.', 'To determine slug tail velocity V\nT\n, a correlation for slug tail velocity V\nT \nmay be implemented in terms of mixture velocity u\nM\n, gravity g, pipe diameter D, inclination angle above the horizontal \n8\n, and/or other quantities.', 'Accordingly, slug tail velocity V\nT \nmay be defined as: \n \nV\nT\n=f\n(\nu\nM\n,g,D\n,θ, . . . )', '(6)', 'The slug front velocity V\nF \nmay be given by a mass balance across the slug front: \n (\nV\nF\n−u\nGS\nF\n)', 'α\nGS\nF\n=(\nV\nF\n−u\nGS\nT\n)α\nGB\nT\n\u2003\u2003(7)', 'Solving equation (2) for V\nF\n: \n \n \n \n \n \n \n \n \n \nV\n \nF\n \n \n=\n \n \n \n \n \nα\n \nGB\n \nT\n \n \n\u2062\n \n \nu\n \nGB\n \nT\n \n \n \n-\n \n \n \nα\n \nGS\n \nF\n \n \n\u2062\n \n \nu\n \nGS\n \nF\n \n \n \n \n \n \nα\n \nGB\n \nT\n \n \n-\n \n \nα\n \nGS\n \nF\n \n \n \n \n \n \n \n \n(\n \n8\n \n)\n \n \n \n \n \n \n \n where α\nGS\nF \nand u\nGS\nF \nrepresent the cross-sectional holdup and cross-sectional mean velocity of gas at the front of the slug, respectively, and α\nGB\nT \nand u\nGB\nT \nrepresent the same quantities at the tail of the zone of separated flow immediately ahead of the slug.', 'Further, equations (7) and (8) may be evaluated when slugs are not present.', 'In such case, values for α\nGS\nF \nand u\nGS\nF \nmay be provided (e.g., as hypothetical values), while α\nGB\nT \nand u\nGB\nT \nmay take values corresponding to the separated flow.', 'When the minimum slip criterion (first condition) is satisfied, slugs may grow from the slug precursors, if such precursors are available (second condition).', 'The spatial frequency of slug formation may thus be proportional to the number of large waves (or slug precursors) per unit pipe length N\nW\n.', 'However, the presence (or proximity) of slugs may decrease the subsequent formation of slugs, and thus the birth rate B may take into consideration slugs that have already formed.', 'Accordingly, the second condition that may be satisfied in order for slug flow to exist may be that the density of slugs present in the pipe N (slugs per unit length of pipe) may not exceed the density of large wave slug precursors (i.e., N\nW\n−N>0).', 'To determine the number of slug precursors or large waves, a delay constant may be implemented.', 'As such, the density of large wave slug precursors N\nW \nmay be estimated, as N\nW\n=u\nL\n/(V\nT\nΩD), where Ω is the delay constant and u\nL \nis the local mean liquid velocity.', 'In another embodiment, a mechanistic model for slug initiation frequency may be employed.', 'For example, at the threshold of slug formation, the wave profile may be considered to be similar to the tail profile of an incipient slug, and the wave speed may approach the slug tail velocity.', 'As such, the wavelength of the slug may be estimated using a quasi-steady slug tail profile model.', 'The local slug density N at a particular grid point or control volume may be estimated based on the distances to the nearest slugs (if any) in each direction along the pipeline.', 'If no slugs exist in either direction, then the slug density is zero.', 'In an embodiment, the wave profile may be obtained by solving a first order, ordinary differential equation for liquid holdup αL\nW\n(ξ),\n \n \n \n \n \n \n \n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \n \nα\n \nLW\n \n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nξ\n \n \n \n=\n \n \nZ\n \nY\n \n \n \n \n \n \n(\n \n9\n \n)', 'This may represent a reduced form of a steady-state, two- (or more) fluid model, which may be based at least in part on an assumption that the wave (slug precursor) propagates without changing shape.', 'As such, the flow may be considered quasi-steady in a frame of reference moving with the tail speed.', 'In equation (9), ξ represents the spatial coordinate measured backwards from the wave crest (tail of the slug precursor).', 'In the two-fluid model, Z represents the equilibrium terms: friction and the axial component of gravity, which in the case where the separated flow is stratified are according to equation (10):\n \n \n \n \n \n \n \n \nZ\n \n=\n \n \n \n \n \n \nτ\n \nIW\n \n \n\u2062\n \n \nS\n \nIW\n \n \n \n-\n \n \n \nτ', 'LW\n \n \n\u2062\n \n \nS\n \nLW\n \n \n \n \n \n \nα\n \nLW\n \n \n\u2062\n \nA\n \n \n \n+\n \n \n \n \n \nτ\n \nIW\n \n \n\u2062\n \n \nS\n \nIW\n \n \n \n+\n \n \n \nτ\n \nGW\n \n \n\u2062\n \n \nS\n \nGW\n \n \n \n \n \n \n(\n \n \n1\n \n-\n \n \nα\n \nLW\n \n \n \n)\n \n \n\u2062\n \nA\n \n \n \n-\n \n \n \n(\n \n \n \nρ\n \nL\n \n \n-\n \n \nρ\n \nG\n \n \n \n)\n \n \n\u2062\n \ng\n \n\u2062\n \n \n \n \n\u2062\n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n \n \n \n \n \n \n(\n \n10\n \n)', 'The denominator Y in equation (9) may represent one or more non-equilibrium terms, such as inertial and hydraulic gradient terms, which, for stratified flow, may be:\n \n \n \n \n \n \n \n \nY\n \n=\n \n \n \n \nρ\n \nL\n \n \n\u2062\n \n \n \n \nu\n \n^\n \n \nSL\n \n2\n \n \n \nα\n \nLW\n \n3\n \n \n \n \n+\n \n \n \nρ\n \nG\n \n \n\u2062\n \n \n \n \nu\n \n^\n \n \nSG\n \n2\n \n \n \n \n(\n \n \n1\n \n-\n \n \nα\n \nLW\n \n \n \n)\n \n \n3\n \n \n \n \n-\n \n \n \n(\n \n \n \nρ\n \nL\n \n \n-\n \n \nρ\n \nG\n \n \n \n)\n \n \n\u2062\n \ng\n \n\u2062\n \n \n \n \n\u2062\n \ncos\n \n\u2062\n \n \n \n \n\u2062\n \nθ\n \n\u2062\n \n \nA\n \n \nS\n \nLW\n \n \n \n \n \n \n \n \n \n(\n \n11\n \n)', 'The terms τ\nIW\n, τ\nLW\n, and τ\nGW \nrepresent the shear stresses between the gas and liquid, between the liquid and the pipe wall, and between the gas and the pipe wall, respectively, while S\nIW\n, S\nLW\n, and S\nGW \nrepresent the corresponding perimeter lengths, and the subscript ‘W’ denotes “wave.”', 'A is the pipe cross-sectional area, û\nSL \nand û\nSG \nare the superficial velocities of liquid and gas, respectively, relative to the moving frame of reference, ρ\nL \nand ρ\nG \nare the liquid and gas densities, respectively, g is the acceleration of gravity and θ represents the angle of inclination of the pipe above the horizontal.', 'The mean holdup may be determined by integration over the wave profile:\n \n \n \n \n \n \n \n \n \n \nα\n \nLW\n \n \n_\n \n \n=\n \n \n \n1\n \n \nL\n \nW\n \n \n \n\u2062\n \n \n \n∫\n \n0\n \n \nL\n \nW\n \n \n \n\u2062\n \n \n \n \nα\n \nLW\n \n \n\u2061\n \n \n(\n \nξ\n \n)\n \n \n \n\u2062\n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nξ\n \n \n \n \n \n \n \n \n(\n \n12\n \n)\n \n \n \n \n \n \n \n where L\nW \nis the distance between the tail of one slug precursor and the front of the next.', 'Further, the slug length of the slug precursor may be set to zero, or any other value, for example a length of a few diameters, in order to determine the frequency of slug precursors.', 'Moreover, an approximate solution may be introduced for the wave profile in the exponential form, as equation (13): \n α\nLW\n≈{tilde over (α)}\nLW\n(ξ)=α\nLW\nE\n+(α\nLW\n0\n−α\nLW\nE\n)\ne\n−kξ\n\u2003\u2003(13) \n where α\nLW\nE \nis a hypothetical equilibrium holdup achieved for a very long wave tail, ξ →∞, Z→0, and α\nLW\n0 \nis the hold up at the wave crest (slug tail), which may be set equal to the slug body holdup of the incipient slug.', 'When the void in the slug is neglected, α\nLW\n0 \nmay be set to unity.', 'As such, the mean holdup value of the liquid corresponding to the approximate profile may be: \n \n \n \n \n \n \n \n \n \n \nα\n \nLW\n \n \n_', '≈\n \n \n \nα\n \nLW\n \nE\n \n \n+\n \n \n \n(\n \n \n \nα\n \nLW\n \n0\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n)\n \n \n\u2062\n \n \n1\n \n \nkL\n \nW\n \n \n \n\u2062\n \n \n(\n \n \n1\n \n-\n \n \ne\n \n \nkL\n \nW\n \n \n \n \n)\n \n \n \n \n \n \n \n \n(\n \n14\n \n)', 'In embodiments, the product kL\nW \nmay be about three (or another, moderately large number), so that the stratified zone is long enough for the liquid level to approach the equilibrium value and the exponential term in equation (14) may be neglected.', 'In such a case, L\nW \nmay be determined from:\n \n \n \n \n \n \n \n \n \nL\n \nW\n \n \n≈\n \n \n \n1\n \nk\n \n \n\u2062\n \n \n \n \nα\n \nLW\n \n0\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n \n \n \nα\n \nLW\n \n \n_\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n \n \n \n \n \n \n(\n \n15\n \n)\n \n \n \n \n \n \n \n \nTo estimate the value of k, the spatial derivative of the exponential profile may be given as:\n \n \n \n \n \n \n \n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \n \n \nα\n \n~\n \n \nLW\n \n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nξ\n \n \n \n=\n \n \n \n \n-\n \n \nk\n \n\u2061\n \n \n(\n \n \n \nα\n \nLW\n \n0\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n)\n \n \n \n \n\u2062\n \n \ne\n \n \n-\n \nkξ\n \n \n \n \n=\n \n \n-\n \n \nk\n \n\u2061\n \n \n(\n \n \n \n \nα\n \n~\n \n \nLW\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n)\n \n \n \n \n \n \n \n \n \n(\n \n16\n \n)\n \n \n \n \n \n \n \n so that a value of the exponential coefficient k may be estimated from \n \n \n \n \n \n \n \n \n \nk\n \n≈\n \n \nk\n \nR\n \n \n \n=\n \n \n \n-\n \n \n \n[\n \n \n \n1\n \n \n \nα\n \nLW\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n \n\u2062\n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \n \nα\n \nLW\n \n \n \n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nξ\n \n \n \n \n]\n \n \n \n \nα\n \nLW\n \n \n-\n \n \nα\n \nLW\n \nR\n \n \n \n \n \n=\n \n \n \n \n \n-\n \n1\n \n \n \n \nα\n \nLW\n \nR\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n \n\u2061\n \n \n[\n \n \nZ\n \nY\n \n \n]\n \n \n \n \n \nα\n \nLW\n \n \n-\n \n \nα\n \nLW\n \nR\n \n \n \n \n \n \n \n \n \n(\n \n17\n \n)\n \n \n \n \n \n \n \n Here, α\nLW\nR \nmay be a reference value of the holdup taken at a point along the profile.', 'In an embodiment, the value of α\nLW\nR \nmay be selected such that the half-angle δ subtended by the liquid layer at the pipe center is between the equilibrium value δ\nE \nand the value of the slug tail δ\n0\n, weighted by a fraction c\nK\n: \n δ\nR\n=δ\nE\n+c\nK\n(δ\n0\n−δ\nE\n)\u2003\u2003(18)', 'The fraction c\nK \nmay serve as a tuning variable in the model.', 'The value may be predetermined or received, e.g., from a user, as part of the method \n1700\n.', 'For example, the fraction may be set as 0.18, but in other embodiments, may be any other suitable number.', 'The holdup may be given in terms of the half angle δ by α\nLW\n=(δ−cos δ sin δ)/π.', 'An estimate for the number of precursor waves per unit length may thus be:\n \n \n \n \n \n \n \n \n \nN\n \nW\n \n \n≈\n \n \n \nc\n \nW\n \n \n\u2062\n \n \n \n \n \n \n \nα\n \nLW\n \n \n_\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n \n \n(\n \n \n \nα\n \nLW\n \n0\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n)\n \n \n\u2062\n \n \n(\n \n \n \nα\n \nLW\n \nR\n \n \n-\n \n \nα\n \nLW\n \nE\n \n \n \n)\n \n \n \n \n\u2061\n \n \n[\n \n \n \n-\n \nZ\n \n \nY\n \n \n]\n \n \n \n \n \nα\n \nLW\n \n \n-\n \n \nα\n \nLW\n \nR\n \n \n \n \n \n \n \n \n \n(\n \n19\n \n)\n \n \n \n \n \n \n \n where c\nW \nmay be a free tuning parameter, which may be set, for example, as 1.', 'When the wave propagates without change of form, the liquid flux relative to the moving frame of reference may be constant along the wave profile, such that: \n α\nLW\nû\nLW\n≈û\nSL\n\u2003\u2003(20) \n where û\nLW\n=V\nW\n−u\nLW \nis the liquid velocity (measured backwards) relative to the wave crest (slug tail) and û\nSL\n=V\nW\n−u\nSL \nis the corresponding superficial velocity.', 'Continuity of liquid holdup and flux across the slug tail may give α\nLW\n0\n=α\nLS\nT \nand û\nSL\n=(V\nW\n−u\nLS\nT\n)α\nLS\nT\n, where α\nLS\nT \nand u\nLS\nT \nare the holdup and velocity of liquid, respectively, at the tail of the slug precursor (e.g., the crest of the wave).', 'In some embodiments, gas entrainment may be ignored, and α\nLS\nT\n≈1, δ\n0\n=π, and u\nLS\nT\n=u\nM\n, such that û\nSL\n≈V\nW\n−u\nM\n, where u\nM \nis a local mixture velocity.', 'The mean liquid flux in the wave may be determined as:\n \n \n \n \n \n \n \n \n \nq\n \nL\n \n \n=\n \n \n \n \nα\n \nL\n \n \n\u2062\n \n \nu\n \nL\n \n \n \n=\n \n \n \n1\n \n \nL\n \nW\n \n \n \n\u2062\n \n \n \n∫\n \n0\n \n \nL\n \nW\n \n \n \n\u2062\n \n \n \n \nα\n \nLW\n \n \n\u2061\n \n \n(\n \nξ\n \n)', '\u2062\n \n \n \nu\n \nLW\n \n \n\u2061\n \n \n(\n \nξ\n \n)\n \n \n \n\u2062\n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nξ\n \n \n \n \n \n \n \n \n \n(\n \n21\n \n)\n \n \n \n \n \n \n \n Further, as u\nLW\n=V\nW\n−û\nSL\n/α\nLW\n, liquid flux becomes: \n \n \n \n \n \n \n \n \n \nq\n \nL\n \n \n=\n \n \n \n \n1\n \n \nL\n \nW\n \n \n \n\u2062\n \n \n \n∫\n \n0\n \n \nL\n \nW\n \n \n \n\u2062\n \n \n \n(\n \n \n \n \nV\n \nW\n \n \n\u2062\n \n \nα\n \nLW\n \n \n \n-\n \n \n \nu\n \n^\n \n \nSL\n \n \n \n)', '\u2062\n \nd\n \n\u2062\n \n \n \n \n\u2062\n \nξ\n \n \n \n \n=\n \n \n \n \nV\n \nW\n \n \n\u2062\n \n \n \nα\n \nLW\n \n \n_\n \n \n \n-\n \n \n \nu\n \n^\n \n \nSL\n \n \n \n \n \n \n \n \n(\n \n22\n \n)\n \n \n \n \n \n \n \n yielding: \n \n \n \n \n \n \n \n \n \nV\n \nW\n \n \n=\n \n \n \n \n \nu\n \nM\n \n \n-\n \n \nq\n \nL\n \n \n \n \n1\n \n-\n \n \n \nα\n \nLW\n \n \n_\n \n \n \n \n=\n \n \nu\n \nG\n \n \n \n \n \n \n \n(\n \n23\n \n)\n \n \n \n \n \n \n \n in which u\nG \nis the mean gas velocity \n \nFor a developing flow, the liquid holdup α\nL \nand the flux q\nL \nmay be determined independently.', 'As such, the wave velocity V\nW\n, which may be equal to the gas velocity u\nG \nin the case with no gas entrainment, may differ from the slug tail velocity V\nT\n.', 'This potential inconsistency may be resolved in at least two ways.', 'First, in a steady flow, the wave velocity may be equal to the slug tail velocity, V\nW\n=V\nT\n, which may be regarded as an approximation for unsteady flow.', 'In such case, the wave model may take \nα\nLW\n to be the local value of α\nL \n(and may not use the liquid flux q\nL\n).', 'Second, a local value for the liquid flux q\nL \nmay be determined, and equation (23) may be employed to obtain an adjusted value for the mean holdup corresponding to the wavy flow:\n \n \n \n \n \n \n \n \n \n \nα\n \nLW\n \n \n_\n \n \n=\n \n \n1\n \n-\n \n \n \n \nu\n \nM\n \n \n-\n \n \nq\n \nL\n \n \n \n \nV\n \nT\n \n \n \n \n \n \n \n \n(\n \n24\n \n)', 'In this case, the wave model may use a liquid holdup value \nα\nLW\n corresponding to the local value of q\nL \n(and may not use α\nL\n).', 'In some embodiments, determining a slug death rate model may not be needed, as a slug may simply be considered to be dead with its characteristic length L\nS \napproaches zero.', 'In other embodiments, a slug death rate may be determined.', 'If slugs are present, and the slug tail velocity V\nT \nis greater than the slug front velocity V\nF\n, the slugs may decrease in length.', 'The mean front and tail velocity of relatively short slugs may be considered generally constant, thus the model may neglect slugs for which the tail velocity differs from the standard form.', 'Thus, the rate at which the slugs disappear may be proportional to (V\nT\n−V\nF\n)ψ(0).', 'The function ψ(L\nS\n) represents the probability density function of slugs of length L\nS\n, and ψ(0) represents the probability density of slugs of zero (or substantially zero) length.', 'In some embodiments, ψ(0) may be proportional to N/\nL\nS \n thus the death rate may be estimated by\n \n \n \n \n \n \n \n \n \nD\n \n=\n \n \n \nc\n \nD\n \n \n\u2062\n \n \n \nN\n \n\u2061\n \n \n(\n \n \n \nV\n \nT\n \n \n-\n \n \nV\n \nF\n \n \n \n)\n \n \n \n \n \nL\n \nS\n \n \n_\n \n \n \n \n \n,\n \n \n \nV\n \nT\n \n \n>\n \n \nV\n \nF\n \n \n \n \n \n \n \n(\n \n25\n \n)\n \n \n \n \n \n \n \n where c\nD \nis another dimensionless constant that may be tuned to data.', 'Further, to avoid a potential singularity when \nL\nS\n→0, an upper bound may be imposed for the slug death rate D by adding a constant to the denominator, such as the pipe diameter, thereby yielding: \n \n \n \n \n \n \n \n \n \nD\n \n=\n \n \n \nc\n \nD\n \n \n\u2062\n \n \n \nN\n \n\u2061\n \n \n(\n \n \n \nV\n \nT\n \n \n-\n \n \nV\n \nF\n \n \n \n)\n \n \n \n \n \n \nL\n \nS\n \n \n_\n \n \n+\n \nD\n \n \n \n \n \n,\n \n \n \nV\n \nT\n \n \n>\n \n \nV\n \nF\n \n \n \n \n \n \n \n(\n \n26\n \n)', 'In an embodiment, if both of the first condition (minimum slip criterion) and second conditions (available precursors) are satisfied, the birth rate B may be determined according to the following equation:\n \n \n \n \n \n \n \n \nB\n \n=\n \n \n \n \nc\n \nB\n \n \nD\n \n \n\u2062\n \n \n(\n \n \n \nN\n \nW\n \n \n-\n \nN\n \n \n)', '\u2062\n \n \n(\n \n \n \nV\n \nF\n \n \n-\n \n \nV\n \nT\n \n \n \n)\n \n \n \n \n \n \n \n(\n \n27\n \n)', 'In equation (27), D represents the pipe diameter, and c\nB \nis a constant of proportionality that is determined by matching the model with experimental data and/or field data.', 'The birth rate model gives the birth rate B in terms of at least two factors, which represent the degree of instability of the local stratified flow, and the spatial density of slug precursors (slugs/meter).', 'The method \n1700\n may then proceed to initiating a slug flow in the fluid flow model based at least partially on the slug birth rate, as at \n1706\n.', 'In an embodiment, initiating slug flow may be conducted according to a population equation, which may employ the birth rate and/or death rate calculated above.', 'An example of such a population equation may be as follows:\n \n \n \n \n \n \n \n \n \n \n \n∂\n \nN\n \n \n \n∂\n \nt\n \n \n \n+\n \n \n \n∂\n \n \n∂\n \nx\n \n \n \n\u2062\n \n \n(\n \n \nNU\n \nA\n \n \n)\n \n \n \n \n=\n \n \nB\n \n-\n \nD\n \n \n \n \n \n \n(\n \n28\n \n)\n \n \n \n \n \n \n \n where N is the number of slugs per unit pipe length, U\nA \nis the advection velocity, B is the slug birth rate, and D is the slug death rate.', 'In some embodiments, as mentioned above, a model for slug death may be omitted; as length approaches zero, the slug may be considered dead.', 'In an embodiment, the simulation of the fluid flow model may proceed according to time steps Δt, where the equations describing the state of the cells or control volumes (e.g., lengths of pipe) of the model are resolved after one, some, or each time step.', 'Further, the number of new slugs formed may be generally described in terms of the birth rate B, the control volume length Δz and the time step Δt as: \n Δ\nN=BΔzΔt.', '(29)', 'However, the pipe length Δz and/or the time step Δt may be relatively short, such that ΔN is generally less than one and greater than or equal to zero.', 'Accordingly, embodiments of the present method \n1700\n may employ the ΔN value as a probability.', 'For example, the method \n1700\n may include generating a random or pseudo-random number X, which may be uniformly distributed on the interval', '[0, 1].', 'When ΔN>X, a slug may be initiated, and if ΔN<X, a slug may not be initiated.', 'When one or more slug flows at one or more lengths of pipe, at a time step, are resolved, the method \n1700\n may include displaying data representative of the slug flow, as at \n1708\n.', 'This may take any one or more of a variety of forms and may result in a representation of an underlying object changing, based on the simulation.', 'For example, one or more slugs may be graphically represented in a pipe.', 'In another embodiment, a frequency of slug flow, e.g., as a plot, may be created and/or modified according to the method \n1700\n.', 'In another embodiment, a slug length distribution, e.g., as a plot, may be created and/or modified according to the method \n1700\n.', 'In other embodiments, other types of graphical displays based on data from the underlying actual or hypothetical physical pipeline system may be provided.', 'CONCLUSION', 'The use of the flowback model to determine drawdown pressures, along with chemical analysis of flowback fluids, solids assessment, and accurate flow rates using a multiphase flow meter that will provide data to confirm and validate the results from the model allows for a shift from rule-of-thumb practice to a data-driven approach based on rock-fluid interactions that helps preserve fracture conductivity and hence increases estimated ultimate recovery (EUR) and well production performance.', 'The flowback systems and methods described herein allows for prediction, detection, estimation, and response when there are rapid changes in the bottomhole pressure during flowback.', 'The use of a multiphase flow meter provides high speed, high resolution data, which allows for flow rate adjustments to be made within one well piping volume that may not be possible with other separator/phase monitoring systems.', 'The speed of this measurement allows for novel responses to slugging situations—detection of oscillating or rapidly varying excessive drawdown pressure change rates that are not otherwise detectable.', 'Also, the flowback systems and methods described herein provide automation and connection of the multiphase flow meter with water chemistry measurements such as conductivity and an automated choke that allows for control of downhole pressures in a gradual manner, maintaining conductivity in channels that are only partially propped.', 'Additionally, the flowback systems and methods described herein provide data storage, data integration, and data analytics processes to use as background knowledge to calibrate engineered flowback procedures for subsequent wells.', 'Data can be incorporated into, for example, HRA (Heterogeneous Rock Analysis), or an alternate rock classification system, where the rock type data is processed for flowback management on subsequent wells.', 'There have been described and illustrated herein several embodiments of a flowback system and a flowback control method.', 'While particular embodiments have been described, it is not intended that the disclosure be limited thereto, as it is intended that the disclosure be as broad in scope as the art will allow and that the specification be read likewise.', 'In addition, while particular types of devices have been disclosed, it will be understood that other devices having the same function(s) can be used.', 'For example, and not by way of limitation, multiple single phase flow meters may be used instead of a single multiphase flow meter.', 'It will therefore be appreciated by those skilled in the art that yet other modifications could be made to the provided disclosure without deviating from its spirit and scope as claimed.'] | ['1.', 'A method of determining at least one bottomhole condition in a well, the method comprising:\nmeasuring fluid properties, via one or more sensors, of fluids produced at a surface-location of the well, wherein the well traverses a hydraulically fractured reservoir, wherein the measured fluid properties include flow rates of different fluid phases that are part of the fluids, and wherein the different fluid phases are selected from the group including an oil phase, a gas phase, a water phase, and a solid phase;\nusing a transient fluid flow simulator to determine composition and properties of the fluids in the well between a surface-location of the well and at least one bottomhole-location of the well based on the measured fluid properties and based on calculations involving data characterizing mineralogy of the hydraulically fractured reservoir;\ncalculating at least one bottomhole condition in the well based on the determined composition and properties of the fluids in the well between the surface-location and the at least one bottomhole-location of the well; and\ncontrolling a flowback operation in the well based at least in part on the at least one bottomhole condition; wherein controlling the flowback operation in the well further comprises: calculating a drawdown pressure in the well at a particular time, wherein the drawdown pressure in the well is a function of a rate of a bottomhole pressure change and a bottomhole fluid rate; determining when the calculated drawdown pressure is outside a particular safe zone defined by upper and lower limits on drawdown pressure as a function of time; and adjusting a surface-located choke in response to determining the calculated drawdown pressure is outside the particular safe zone.', '2.', 'The method according to claim 1, wherein:\nthe measured fluid properties include pressure before or at the surface-located choke.', '3.', 'The method according to claim 2, wherein:\nthe surface-located choke includes a variable sized aperture, and the measured fluid properties include pressure downstream of the variable sized aperture of the surface-located choke.', '4.', 'The method according to claim 2, wherein:\nthe surface-located choke includes a variable sized aperture, and the measured fluid properties include pressure upstream of the variable sized aperture of the surface-located choke.', '5.', 'The method according to claim 1, wherein:\nthe transient fluid flow simulator determines the composition and properties of the fluids in the well between the surface-location of the well and the at least one bottomhole-location of the well based further on calculations involving a set point or other predefined parameter.', '6.', 'The method according to claim 1, wherein:\nthe transient fluid flow simulator determines the composition and properties of the fluids in the well between the surface-location of the well and the at least one bottomhole-location of the well based further on calculations involving data from at least one other well.', '7.', 'The method according to claim 1, wherein:\nthe transient fluid flow simulator determines the composition and properties of the fluids in the well between the surface-location of the well and the at least one bottomhole-location of the well based further on calculations involving data derived during drilling the well.', '8.', 'The method according to claim 1, wherein:\nthe at least one bottomhole condition includes pressure in the well at at least one bottomhole location of the well.\n\n\n\n\n\n\n9.', 'The method according to claim 1, wherein:\nthe transient fluid flow simulator determines the composition and properties of the fluids in the well between the surface-location of the well and the at least one bottomhole location of the well for a first period of time based on the measured fluid properties measured over a second period of time that precedes the first period of time.', '10.', 'The method according to claim 9, wherein:\nthe transient fluid flow simulator determines the composition and properties of the fluids in the well for the first period of time based on an extrapolation of the measured fluid properties during the second period of time.', '11.', 'The method according to claim 1, further comprising:\nusing a plurality of transient fluid flow simulators to individually determine the composition and properties of the fluids in the well between the surface-location of the well and at least one bottomhole-location of the well based on the measured fluid properties;\ncomparing the measured fluid properties, respectively, with sets of properties determined by each of the transient fluid flow simulators; and\nselecting at least one of the transient fluid flow simulators based on the comparing, wherein the at least one bottomhole condition in the well is calculated based on the determination of the composition and properties of the fluids in the well determined by the selected at least one of the transient fluid flow simulators, wherein the plurality of transient fluid flow simulators reflect different flowback scenarios.\n\n\n\n\n\n\n12.', 'The method according to claim 1, wherein:\nthe fluid properties of the fluids produced at a surface-location of the well are measured in real-time;\nthe transient fluid flow simulator determines in real-time the composition and properties of the fluids in the well between the surface-location of the well and at least one bottomhole-location of the well based on the real-time measurement of the fluid properties; and\nthe at least one bottomhole condition in the well is calculated in real-time based on the real-time determination of the composition and properties of the fluids in the well, wherein the transient fluid flow simulator is updated in real-time such that determined properties of the fluids at the surface-location in the well matches the measured fluid properties at the surface-location in the well.', '13.', 'The method according to claim 1, wherein:\ncalculating the at least one bottomhole condition in the well includes calculating multiple estimates of bottomhole pressure and a statistical distribution of the bottomhole pressure.', '14.', 'The method according to claim 1, wherein:\nadjusting the surface-located choke comprises closing the surface-located choke when the calculated drawdown pressure is above the particular safe zone or opening the surface-located choke when the calculated drawdown pressure is below the particular safe zone.', '15.', 'A method of determining fracture properties in a hydraulically fractured reservoir, the method comprising:\nmeasuring fluid properties, via one or more sensors, of fluids produced at a surface-location of a well that traverses the hydraulically fractured reservoir, wherein the measured fluid properties include flow rates of different fluid phases that are part of the fluids, and wherein the different fluid phases are selected from the group including an oil phase, a gas phase, a water phase, and a solid phase;\nusing a transient fluid flow simulator to determine at least one fracture property at at least one bottomhole location of the well over time based on the measured fluid properties, wherein the at least one fracture property characterizes fracture conductivity of a fracture in a near-wellbore region adjacent the well; and\ncontrolling a flowback operation in the well based at least in part on the at least one fracture property; wherein controlling the flowback operation in the well further comprises: calculating a drawdown pressure in the well at a particular time, wherein the drawdown pressure in the well is a function of a rate of a bottomhole pressure change and a bottomhole fluid rate; determining when the calculated drawdown pressure is outside a particular safe zone defined by upper and lower limits on drawdown pressure as a function of time; and adjusting a surface-located choke in response to determining the calculated drawdown pressure is outside the particular safe zone.\n\n\n\n\n\n\n16.', 'The method according to claim 15, wherein:\nthe at least one fracture property characterizes unpropped fracture area of a fracture in a near-wellbore region adjacent the well.', '17.', 'The method according to claim 15, further comprising:\nestimating a safe drawdown operating envelope based on the determined at least one fracture property, wherein the safe drawdown operating envelope is defined as a function of bottomhole pressure, rate of bottomhole pressure change, and bottomhole fluid rate, and wherein the safe drawdown operating envelope defines an upper drawdown limit corresponding to a condition where fracture pinch is predicted in a near-wellbore region adjacent the well.', '18.', 'The method according to claim 17, further comprising:\ndetermining a risk of unwanted condition based on the at least one fracture property, wherein the unwanted condition is selected from the group consisting of formation failure, fracture pinchout and a combination thereof,\nwherein the safe drawdown operating envelope defines an upper drawdown limit corresponding to a condition where the fracture pinch is predicted in a near-wellbore region adjacent the well, and wherein the safe drawdown operating envelope is based on the determined risk of unwanted condition.\n\n\n\n\n\n\n19.', 'A method of determining at least one bottomhole condition in a well, the method comprising:\nmeasuring fluid properties, via one or more sensors, of fluids produced at a surface-location of the well, wherein the well traverses a hydraulically fractured reservoir, wherein the measured fluid properties include flow rates of different fluid phases that are part of the fluids, and wherein the different fluid phases are selected from the group including an oil phase, a gas phase, a water phase, and a solid phase;\nusing a transient fluid flow simulator to determine composition and properties of the fluids in the well between a surface-location of the well and at least one bottomhole-location of the well based on the measured fluid properties and based on calculations involving data derived during drilling the well;\ncalculating at least one bottomhole condition in the well based on the determined composition and properties of the fluids in the well between the surface-location and the at least one bottomhole-location of the well; and\ncontrolling a flowback operation in the well based at least in part on the at least one bottomhole condition; wherein controlling the flowback operation in the well further comprises: calculating a drawdown pressure in the well at a particular time, wherein the drawdown pressure in the well is a function of a rate of a bottomhole pressure change and a bottomhole fluid rate; determining when the calculated drawdown pressure is outside a particular safe zone defined by upper and lower limits on drawdown pressure as a function of time; and adjusting a surface-located choke in response to determining the calculated drawdown pressure is outside the particular safe zone.', '20.', 'A method of determining at least one bottomhole condition in a well, the method comprising:\nmeasuring fluid properties, via one or more sensors, of fluids produced at a surface-location of the well, wherein the well traverses a hydraulically fractured reservoir, wherein the measured fluid properties include flow rates of different fluid phases that are part of the fluids, and wherein the different fluid phases are selected from the group including an oil phase, a gas phase, a water phase, and a solid phase;\nusing a transient fluid flow simulator to determine composition and properties of the fluids in the well between a surface-location of the well and at least one bottomhole-location of the well based on the measured fluid properties;\ncalculating at least one bottomhole condition in the well based on the determined composition and properties of the fluids in the well between the surface-location and the at least one bottomhole-location of the well, wherein calculating the at least one bottomhole condition in the well includes calculating multiple estimates of bottomhole pressure and a statistical distribution of the bottomhole pressure; and\ncontrolling a flowback operation in the well based at least in part on the at least one bottomhole condition; wherein controlling the flowback operation in the well further comprises: calculating a drawdown pressure in the well at a particular time, wherein the drawdown pressure in the well is a function of a rate of a bottomhole pressure change and a bottomhole fluid rate; determining when the calculated drawdown pressure is outside a particular safe zone defined by upper and lower limits on drawdown pressure as a function of time; and adjusting a surface-located choke in response to determining the calculated drawdown pressure is outside the particular safe zone.\n\n\n\n\n\n\n21.', 'The method according to claim 20, further comprising:\nmeasuring at least one bottomhole condition of the well at a bottomhole location of the well;\ncomparing the at least one measured bottomhole condition with the calculated at least one bottomhole condition; and\ntuning or validating the transient flow simulator based on the comparison between the at least one measured bottomhole condition with the calculated at least one bottomhole condition.'] | ['FIG.', '1A shows extensive tensile rock failure, which can lead to loss of the production for the treated zone or even sometimes loss of the well.', 'FIG.', '1B shows an excessive amount of proppant that have flowed from the fractures back into the well and to the surface, which can allow the newly formed fractures to reduce in width or close, thereby restricting the flow of hydrocarbons from the reservoir rock.', 'FIG.', '1C shows fines that have flowed from the fractures back into the well, which indicate that fines have been generated in the fracture; such fines can lead to complete plugging of the fracture and loss of the treated zone.', 'FIG.', '1D shows scale that can be produced during flowback.', 'The scale can coat perforations, casing, production tubulars, valves, pumps, and downhole completion equipment, and thus limit production.', '; FIG.', '1A to 1D are illustrations of some types of solids that may flow from a well to the surface during a flowback operation.', '; FIG.', '2 is a schematic illustration of a well that traverses a hydraulically fractured reservoir.; FIG.', '3 is a schematic illustration of an embodiment of a flowback system according to the present disclosure.', '; FIG.', '4 is a schematic illustration of exemplary data flow and associated calculations within the flowback system of FIG.', '3.; FIG.', '5 shows an example computing system that can be used to implement the flowback system or parts thereof of FIGS. 3 and 4.; FIG.', '6 is a schematic representation of the component parts of an exemplary flowback model.; FIG. 7 is a table showing input parameters for an illustrative flowback model.; FIG. 8 is a table showing output parameters for an illustrative flowback model.; FIG.', '9 is a graph of reservoir pressure and fracture fluid saturation versus radial distance from the wellbore at a respective location along a well.; FIG.', '10 is a graph of multiphase flow of oil, water, and gas versus time during an exemplary flowback operation.; FIG.', '11A is a schematic illustration of fluid flow through a dual porosity medium.; FIG.', '11B is a schematic illustration showing fluid flow through in a matrix block shown in FIG.', '11A.; FIGS.', '11C and 11D are schematic diagrams for depicting fluid flow through a medium.; FIG.', '11E depicts an example flow chart of a method for fracture modeling.; FIG.', '12 is a schematic illustration of drawdown pressures at a respective bottomhole position in a well at two different times during an exemplary flowback operation.; FIG.', '13 is an example graph of scheduled maximum allowable drawdown pressure versus time during an exemplary flowback operation.; FIG.', '14 is a graph of total dissolved solids in produced flowback fluid versus time for various wells.; FIG.', '15 illustrates an example of a ternary diagram with an example of an associated table of fluid properties.; FIG.', '16 illustrates an example of a system that includes various management components to manage various aspects of a pipeline environment, according to an embodiment.; FIG.', '17 illustrates a flowchart of a method for modeling slug flow in a multiphase flow according to an embodiment of the present disclosure.; FIG.', '2 shows a schematic of a well 200 of a hydraulically fractured hydrocarbon reservoir 202.', 'While certain elements of the well 200 are illustrated in FIG.', '2, other elements of the well 200 (e.g., blow-out preventers, wellhead “surface tree”) have been omitted for clarity of illustration.', 'The well 200 includes an interconnection of pipes, including vertical and horizontal casing 204, production tubing 206, transitions 208, and a production liner 210 that connect to a processing facility (not shown) at the surface 201.', 'The production tubing 206 extends inside the casing 204 and terminates at a tubing head 212 at or near the surface 201.', 'The casing 204 contacts the wellbore 218 and terminates at casing head 214 at or near the surface 201.', 'The production liner 210 and horizontal casing 204 have aligned radial openings termed “perforation zones” 220 that allow fluid communication between the production liner 210 and the hydraulically fractured reservoir 202.', 'An annular packer 222 is set at a lower end of the production tubing 206 and provides a seal between the production tubing 206 and the casing 204', 'so that fluid in the production liner 210 is directed into the production tubing 206 rather than between the production tubing 206 and the casing 204.; FIG.', '3 illustrates an embodiment of a real-time flowback system 500 that has a plurality of sensors (including a well head pressure sensor 502, a multiphase flow meter 504, a solids analyzer 505, and a chemical analyzer 506), a well-head choke 508, and a control system 510 that dynamically controls the operation of the choke 508 based upon a plurality of inputs from the sensors 502, 504, 505, and 506.', 'An optional bottomhole pressure sensor 501 may also be included.', 'The control system 510 includes a controller 512 that employs a flowback model 514.', 'The control system 510 processes the plurality of inputs to generate an output that includes a choke control signal 516 that is used by the choke 508 to control the drawdown pressure and flow rate of produced flowback fluid 518 during a flowback operation.', 'The control system 510 can be configured to control the drawdown pressure and flow so that the drawdown pressure remains at or below the scheduled maximum allowable drawdown pressure, such as illustrated in FIG.', '13, for example.', 'By controlling the drawdown pressure over time, the above-noted unwanted conditions (including tensile rock failure, excessive proppant flowback, fines migration) can be mitigated if determined or detected by the control system 510, as will be discussed in greater detail below.', 'All of the blocks of the system 500, including the measurements obtained by sensors 502, 504, 505, 506, and 507, and the processing carried out by the control system 510 to control the choke 508, may occur in real-time.; FIG.', '4 shows an exemplary data flow and associated calculations within the flowback system of FIG.', '3.', 'At block 515, the determined multiphase fluid flow rates at the surface may be compared with the corresponding measured multiphase flow rates output by the multiphase flow meter 504.', 'At block 520 at least some of the flowback model parameters in FIG.', '7 may be tuned or refined based on the comparison of the measured and target flow rates at block 515.', 'Also, a validation signal (i.e., valid or invalid) may be output to the choke controller 512 based on the comparison at block 515.', 'The validation signal may be used by the choke controller 512 to denote whether or not the flowback model is valid.', 'In the cases where the model is invalid, a safe mode of operation is followed until the model can be tuned and valid.', 'As an example, such safe mode comprises keeping the current choke setting along unless surface measurements from solids/fluids indicate that the current choke settings corresponds to a danger zone of the system (e.g. a large amount of fines being produced).; FIG.', '5 shows an example computing system 300 that can be used to implement the control system 510 or parts thereof.', 'The computing system 300 can be an individual computer system 301A or an arrangement of distributed computer systems.', 'The computer system 301A includes one or more analysis modules 303 (a program of computer-executable instructions and associated data) that can be configured to perform various tasks according to some embodiments, such as the tasks described above.', 'To perform these various tasks, an analysis module 303 executes on one or more processors 305, which is (or are) connected to one or more storage media 307.', 'The processor(s) 305 is (or are) also connected to a network interface 309 to allow the computer system 301A to communicate over a data network 311 with one or more additional computer systems and/or computing systems, such as 301B, 301C, and/or 301D. Note that computer systems 301B, 301C and/or 301D may or may not share the same architecture as computer system 301A, and may be located in different physical locations.; FIG.', '6 illustrates an embodiment of the flowback model 514 including sub-models that may be used as part of the flowback model 514.', 'The flowback model 514 is a system of mathematical equations that characterize the pressure distributions and fluid flow in the hydraulically fractured reservoir rock and the well piping over time as a function of wellhead pressure.', 'Specifically, the flowback model 514 includes coupling logic 614 that joins a well model 642 and a fracture flow model 644.; FIGS. 11A to 11E illustrate features of an exemplary fracture flow model that can be configured to characterize the flowback fluid flow through the fractures of a reservoir.', 'FIG.', '11A shows a two dimensional profile through a hydraulically fractured reservoir around a circular wellbore 1120.', 'As shown in this view, a hydraulic fracture network (HFN) 1122 is depicted as having a plurality of concentric ellipses 1130 and a plurality of radial flow lines 1132.', 'The radial flow lines 1132 initiate from a central location about the wellbore 1120 and extend radially therefrom.', 'The radial flow lines 1132 represent a flow path of fluid from the formation surrounding the wellbore 1120 and to the wellbore 1120 as indicated by the arrows.', 'The HFN 1122 may also be represented in the format as shown in FIG.', '11A.; FIG.', '11E shows a flow chart depicting a method for fracture modeling.', 'In one or more embodiments, one or more of the steps shown in FIG.', '11E may be omitted, repeated, and/or performed in a different order than the order shown in FIG.', '11E.', 'Accordingly, the scope of modeling hydraulic fracturing induced fracture networks as a dual porosity system should not be considered limited to the specific arrangement of steps shown in FIG.', '11E.; FIG.', '15 illustrates a ternary diagram 1550 that includes vertices that represent single-phase gas, oil and water, while the sides represent two phase mixtures (e.g., gas-oil, oil-water and gas-water) and points within the triangle represents a three-phase mixture.', 'A transition region indicates where the liquid fraction changes from water-in-oil to oil-in-water and vice versa (e.g., consider emulsions).', '; FIG.', '16 illustrates an example of a system 1600 that includes various management components 1610 to manage various aspects of a pipeline environment 1650 (e.g., an environment that includes wells, transportation lines, risers, chokes, valves, separators, etc.).', 'For example, the management components 1610 may allow for direct or indirect management of design, operations, control, optimization, etc., with respect to the pipeline environment 1650.', 'In turn, further information about the pipeline environment 1650 may become available as feedback 1660 (e.g., optionally as input to one or more of the management components 1610).', '; FIG.', '16 also shows an example of a framework 1670 that includes a model simulation layer 1680 along with a framework services layer 1690, a framework core layer 1695 and a modules layer 1675.', 'The framework 1670 may include the commercially available OCEAN® framework where the model simulation layer 1680 may be either OLGA® or the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.', 'In an example embodiment, the PETREL® software may be considered a data-driven application.', 'The PETREL® software can include a framework for model building and visualization.; FIG.', '16 also shows the geologic environment 1650 as optionally including equipment 1657 and 1658 associated with a well.', 'As an example, the equipment 1657 and/or 1658 may include components, a system, systems, etc. for pipeline condition monitoring, sensing, valve modulation, pump control, analysis of pipeline data, assessment of one or more pipelines 1656, etc.', 'The pipelines 1656 may include at least a portion of the well, and may form part of, or be representative of, a network of pipes which may transport a production fluid (e.g., hydrocarbon) from one location to another.; FIG.', '17 illustrates a flowchart of a method 1700 for modeling a slug flow, e.g., in a multiphase fluid flow model, according to an embodiment.', 'The method 1700 may be employed as part of a fluid flow or pipeline model.', 'The model may include representations of one or more fluid conduits (e.g., pipes, wells) and/or other pipeline equipment (compressors, pumps, separators, slug catchers, etc.).', 'Such models may be representative of real-world, physical pipelines systems, or may be constructed as part of the planning of such systems.'] |
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US11098550 | Blowout preventer with wide flange body | Apr 28, 2017 | Matthew D. Givens, Christopher J. Nault, Darrin L. Yenzer, Ray Cummins | Schlumberger Technology Corporation | International Search Report and Written Opinion for corresponding Application No. PCT/US2017/030090, dated Sep. 13, 2017, 16 pages.; International Search Report and Written Opinion for related Application No. PCT/PCT/US2017/030106, dated Sep. 13, 2017, 18 pages.; International Search Report and Written Opinion for related Application No. PCT/PCT/US2017/030099, dated Jul. 25, 2017, 12 pages.; International Preliminary Report on Patentability for the equivalent International patent application PCT/US2017/030090 dated Nov. 15, 2018.; International Preliminary Report on Patentability for the cross referenced International patent application PCT/US2017/030099 dated Nov. 15, 2018.; International Preliminary Report on Patentability for the cross referenced International patent application PCT/US2017/030106 dated Nov. 15, 2018. | 2193110; March 1940; Penick; 2357411; September 1944; Leman; 2517821; August 1950; Herbert; 2749078; June 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October 31, 2013; Fraczek et al.; 20140020905; January 23, 2014; Chen et al.; 20140034293; February 6, 2014; Jahnke; 20140034393; February 6, 2014; Mitjans et al.; 20140174754; June 26, 2014; Smith; 20140183382; July 3, 2014; Carbaugh et al.; 20150176744; June 25, 2015; Glassman et al.; 20150315867; November 5, 2015; Caldwell et al.; 20150361755; December 17, 2015; Holland, Jr.; 20170067583; March 9, 2017; Illakowicz et al.; 20170314358; November 2, 2017; Givens et al.; 20190093438; March 28, 2019; Givens et al.; 20190128085; May 2, 2019; Givens et al. | 203603818; May 2014; CN; 204552679; August 2015; CN; 204944764; January 2016; CN; 480817; March 1938; GB; 2004-059118; July 2004; WO; 2012078780; June 2012; WO | ['Blowout preventers having bodies without flanged necks are provided.', 'In one embodiment, a blowout preventer stack includes first and second blowout preventers having independent and separable main bodies, each including a bore and a ram cavity transverse to the bore.', 'The lower end of the main body of the first blowout preventer is fastened directly to an upper end of the main body of the second blowout preventer without a flanged neck extending the bore between the ram cavities of the first and second blowout preventers.', 'In some instances, the main bodies of the first and second blowout preventers include external connection flanges that extend laterally from ram cavity body portions of the main bodies so as to enable connection of the two main bodies along the sides of the main bodies away from their bores.', 'Additional systems, devices, and methods are also disclosed.'] | ['Description\n\n\n\n\n\n\nCROSS REFERENCE PARAGRAPH\n \nThis application claims the benefit of U.S. Provisional Application No. 62/330,835, entitled “BLOWOUT PREVENTER WITH WIDE FLANGE BODY,” filed May 2, 2016, the disclosure of which is hereby incorporated herein by reference\n \nBACKGROUND', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the presently described embodiments.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present embodiments.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'In order to meet consumer and industrial demand for natural resources, companies often invest significant amounts of time and money in finding and extracting oil, natural gas, and other subterranean resources from the earth.', 'Particularly, once a desired subterranean resource such as oil or natural gas is discovered, drilling and production systems are often employed to access and extract the resource.', 'These systems may be located onshore or offshore depending on the location of a desired resource.', 'Further, such systems generally include a wellhead assembly through which the resource is accessed or extracted.', 'These wellhead assemblies may include a wide variety of components, such as various casings, valves, fluid conduits, and the like, that control drilling or production operations.', 'More particularly, wellhead assemblies often include blowout preventers, such as a ram-type preventer that uses one or more pairs of opposing rams to restrict flow of fluid through the blowout preventer or to shear through a drill string or another object within the blowout preventer.', 'Multiple blowout preventers can be assembled in a blowout preventer stack for use at a well.', 'SUMMARY\n \nCertain aspects of some embodiments disclosed herein are set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms the invention might take and that these aspects are not intended to limit the scope of the invention.', 'Indeed, the invention may encompass a variety of aspects that may not be set forth below.', 'Some embodiments of the present disclosure generally relate to blowout preventers having external connection flanges along the sides of ram cavity body portions to facilitate connection of the blowout preventers to other components.', 'In at least some embodiments, these external connection flanges are provided as part of a wide flange preventer body and allow vertical bore API connections to be omitted from a blowout preventer.', 'This, in turn, allows a reduction in the height of the blowout preventer and in blowout preventer stacks having such a preventer.', 'In some other embodiments, the main body of a blowout preventer includes internal choke and kill line pass-through conduits.', 'Multiple blowout preventers with these internal conduits can be aligned with one another in a blowout preventer stack to form shared choke and kill line conduits extending internally through the blowout preventers.', 'The internal choke and kill line pass-through conduits can be provided in a blowout preventer body with or without vertical bore API connections.', 'Various refinements of the features noted above may exist in relation to various aspects of the present embodiments.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'Again, the brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of some embodiments without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThese and other features, aspects, and advantages of certain embodiments will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:\n \nFIG.', '1\n generally depicts a well apparatus in the form of an offshore drilling system with a drilling rig coupled by a riser to a wellhead assembly in accordance with one embodiment of the present disclosure;\n \nFIG.', '2\n is a block diagram depicting a blowout preventer stack assembly of the apparatus of \nFIG.', '1\n in accordance with one embodiment;\n \nFIG.', '3\n is a perspective view of a blowout preventer having a main body with external connection flanges protruding laterally from sides of a ram cavity body portion in accordance with one embodiment;\n \nFIGS.', '4 and 5\n are cross-sections of the blowout preventer of \nFIG.', '3\n and show certain internal components in accordance with one embodiment;\n \nFIG.', '6\n is a perspective view of the body of the blowout preventer of \nFIG.', '3\n;\n \nFIG.', '7\n is a top plan view of the body of the blowout preventer of \nFIG.', '3\n;\n \nFIG.', '8\n is an elevational view of the body of the blowout preventer of \nFIG.', '3\n;\n \nFIGS.', '9 and 10\n depict outer perimeters of the blowout preventer body of \nFIGS.', '6-8\n lying within reference planes depicted in \nFIGS.', '6 and 8\n;\n \nFIGS.', '11 and 12\n depict modular blowout preventer stacks having multiple blowout preventers with identical main bodies in accordance with certain embodiments;\n \nFIG.', '13\n is a perspective view of a blowout preventer having choke and kill line conduits, with associated valves, integrated into its main body in accordance with one embodiment;\n \nFIG.', '14\n is a top plan view of the blowout preventer of \nFIG.', '13\n;\n \nFIG.', '15\n is a perspective view of the main body of the blowout preventer of \nFIG.', '13\n;\n \nFIG.', '16\n is a section view of the main body depicted in \nFIG.', '15\n, showing the internal choke and kill line conduits with access branches connecting to a main bore, in accordance with one embodiment;\n \nFIG.', '17\n depicts a modular blowout preventer stack having multiple blowout preventers with identical main bodies and internal choke and kill lines integrated into the bodies of the blowout preventers in accordance with one embodiment;\n \nFIG.', '18\n shows a modular blowout preventer stack having multiple blowout preventers with axial spacers for accommodating the use of larger bonnet assemblies in the blowout preventer stack in accordance with one embodiment;\n \nFIG.', '19\n is a perspective view of two blowout preventers with raised faces in a stacked configuration in accordance with one embodiment;\n \nFIG.', '20\n is a perspective view of two blowout preventers like those of \nFIG.', '19\n, but in which the raised faces having partitioning grooves in accordance with one embodiment;\n \nFIG.', '21\n is a top plan view of the blowout preventer stack of \nFIG.', '20\n;\n \nFIGS.', '22 and 23\n are cross-sections of the blowout preventer stack of \nFIG.', '20\n;\n \nFIGS.', '24 and 25\n are detail views showing fasteners that connect flanges of the blowout preventers of \nFIG.', '20\n and inserts for reducing bending stresses on the connection in accordance with one embodiment; and\n \nFIG.', '26\n is an exploded view of the fasteners and inserts of \nFIGS.', '24 and 25\n.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nSpecific embodiments of the present disclosure are described below.', 'In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Moreover, any use of “top,” “bottom,” “above,” “below,” other directional terms, and variations of these terms is made for convenience, but does not require any particular orientation of the components.', 'Turning now to the present figures, a well assembly or apparatus \n10\n is illustrated in \nFIG.', '1\n in accordance with one embodiment.', 'The apparatus \n10\n (e.g., a drilling system or a production system) facilitates access to or extraction of a resource, such as oil or natural gas, from a reservoir through a well \n12\n.', 'The apparatus \n10\n is generally depicted in \nFIG.', '1\n as an offshore drilling apparatus including a drilling rig \n14\n coupled with a riser \n16\n to a wellhead assembly \n18\n installed at the well \n12\n.', 'Although shown here as an offshore system, the well apparatus \n10\n could instead be an onshore system in other embodiments.', 'As will be appreciated, the drilling rig \n14\n can include surface equipment positioned over the water, such as pumps, power supplies, cable and hose reels, control units, a diverter, a gimbal, a spider, and the like.', 'Similarly, the riser \n16\n may also include a variety of components, such as riser joints, flex joints, a telescoping joint, fill valves, and control units, to name but a few.', 'The wellhead assembly \n18\n can include equipment coupled to a wellhead \n20\n, such as to enable the control of fluid from the well \n12\n.', 'The wellhead \n20\n can also include various components, such as casing heads, tubing heads, spools, and hangers.', 'Any suitable blowout preventers, such as ram-type preventers or annular preventers, could be used at one or more locations in the apparatus \n10\n.', 'For instance, blowout preventers can be located at the surface on the drilling rig \n14\n or provided as part of the wellhead assembly \n18\n at the submerged wellhead \n20\n.', 'One example of a blowout preventer stack \n26\n that may be used in the apparatus \n10\n is generally depicted in \nFIG.', '2\n.', 'The blowout preventer stack \n26\n includes ram-type preventers (represented as shear rams \n28\n and pipe rams \n30\n) and an annular preventer \n32\n.', 'The number of ram-type preventers used in the blowout preventer stack \n26\n, as well as their configurations (e.g., ram type, size, and capabilities), can vary between different implementations, as can the number and configurations of annular preventers.', 'In one subsea embodiment, a lower marine riser package (LMRP) \n36\n having an annular preventer \n38\n is attached to the blowout preventer stack \n26\n.', 'It will be appreciated that the lower blowout preventer stack \n26\n and the LMRP \n36\n can include other components in addition to or in place of those depicted in \nFIG.', '2\n.', 'The LMRP \n36\n, for example, can include control pods for controlling operation of the preventers of the lower blowout preventer stack \n26\n and the LMRP \n36\n.', 'In some other embodiments, such as surface embodiments, the LMRP \n36\n is omitted.', 'A ram-type blowout preventer \n40\n is illustrated in \nFIGS.', '3-5\n as an example of a blowout preventer that can be included in a blowout preventer stack \n26\n.', 'The blowout preventer \n40\n includes a hollow main body \n42\n and a main bore \n44\n (which may also be referred to as a drill-through bore) that enables passage of fluid or tubular members through the blowout preventer \n40\n.', 'As will be appreciated, the blowout preventer \n40\n may be coupled to additional blowout preventers of a blowout preventer stack \n26\n or to other equipment, such as via holes \n46\n that receive fasteners \n48\n.', 'Although depicted in the form of bolts and nuts in \nFIG.', '3\n, the fasteners \n48\n could take any other suitable form in different embodiments.', 'Many other blowout preventers include tubular connection necks that extend outwardly from central portions of their main bodies along their main bores.', 'These connection necks lengthen the main bores and increase the height of such blowout preventers.', 'That is, the extensions of the main bores by the connection necks provide additional axial space between central bodies of the preventers for fasteners (e.g., of a bolted or studded connection) to be used.', 'These connection necks typically include flanges that conform to American Petroleum Institute (API) Specification \n6\nA (i.e., the flanges are API flanges), and the flanged connection necks can be referred to as vertical bore API connections.', 'Such an API connection allows fastening of a blowout preventer to another component along the neck (at the flange) and near the main bore over or under a central portion of its body—in the case of a ram-type preventer, over or under a ram cavity portion of the body, for instance.', 'In contrast, the blowout preventer \n40\n does not have a flanged connection neck that extends the main bore \n44\n and facilitates connection to another component.', 'Rather, the depicted blowout preventer \n40\n includes a wide-flange body profile having external connection flanges \n50\n that protrude laterally at sides of the main body \n42\n.', 'This allows the blowout preventer \n40\n to be connected to other blowout preventers or components with fasteners \n48\n positioned alongside the main body \n42\n rather than at necks above and below the main body \n42\n.', 'As shown in \nFIGS.', '3 and 5\n, the connection flanges \n50\n include a bolt pattern with parallel rows of holes \n46\n through which fasteners \n48\n may be installed.', 'Bonnet assemblies \n52\n of the blowout preventer \n40\n include bonnets \n54\n secured to the main body \n42\n.', 'The bonnet assemblies \n52\n include cylinders that house various components that facilitate control of rams \n56\n disposed in a ram cavity \n58\n of the blowout preventer \n40\n.', 'In the presently depicted embodiment, the rams \n56\n operate in response to hydraulic pressure from control fluid routed into the bonnet assemblies \n52\n.', 'More particularly, as illustrated in the cross-sections of \nFIGS. 4 and 5\n, the blowout preventer \n40\n includes rams \n56\n controlled by actuation assemblies \n60\n having operating pistons \n62\n and connecting rods \n64\n.', 'The blowout preventer \n40\n is here depicted as a single-ram blowout preventer having one pair of rams \n56\n.', 'The rams \n56\n in \nFIGS.', '4 and 5\n are generally depicted as pipe rams, which can include sealing elements (also known as ram packers) that cooperate with one another when driven together to seal about a pipe or other tubular member and inhibit flow through the bore \n44\n of the blowout preventer \n40\n.', 'The rams \n56\n could take other forms, however, such as blind rams or shear rams.', 'Further, in other embodiments the blowout preventer \n40\n may have a different number of rams.', 'For example, the blowout preventer \n40\n could instead be a double-ram blowout preventer with two ram cavities and two pairs of rams or a triple-ram blowout preventer with three ram cavities and three pairs of rams.', 'The number of rams, along with their types and sizes, may be selected based on the intended application.', 'In operation, a force (e.g., from hydraulic pressure provided by control fluid) may be applied to the operating pistons \n62\n to drive the rams \n56\n, via the connecting rods \n64\n, into the bore \n44\n of the blowout preventer \n40\n.', 'The connecting rods \n64\n extend through the bonnets \n54\n and enable forces on the pistons \n62\n to be transmitted to the rams \n56\n.', 'Only certain portions of the bonnet assemblies \n52\n have been generally depicted in \nFIGS.', '3-5\n for explanatory purposes, and the skilled artisan will appreciate that the bonnet assemblies \n52\n may have other components.', 'For instance, various seals may be provided between the connecting rods \n64\n and the bonnets \n54\n to inhibit leaking while enabling axial movement of the connecting rods through the bonnets.', 'Although the rams \n56\n are illustrated as hydraulically actuated rams in the presently depicted embodiment, it is noted that the rams \n56\n could be actuated in any other suitable manner as well.', 'In the embodiment shown in \nFIG.', '5\n, each ram \n56\n is controlled by an actuation assembly \n60\n having two pistons \n62\n.', 'Because hydraulic force on the operating pistons \n62\n is proportional to the surface areas to which pressure is applied, the two pistons \n62\n per ram \n56\n allow the pistons \n62\n to cumulatively provide the same reactive surface area as a single, larger piston \n62\n.', 'This, in turn, enables a compact design with bonnet assemblies \n52\n occupying less vertical space along the blowout preventer \n40\n.', 'But in other embodiments each ram \n56\n may be controlled with a different number of pistons \n62\n, such as with a single piston.', 'The blowout preventer \n40\n is depicted in \nFIGS.', '3 and 5\n as having choke and kill line connection assemblies \n70\n and \n72\n mounted to the exterior of the main body \n42\n.', 'Choke and kill lines can be connected to the assemblies \n70\n and \n72\n in fluid communication with the bore \n44\n to allow drilling fluid to enter into the bore \n44\n and to circulate fluid between choke and kill lines to control wellbore pressure.', 'The assemblies \n70\n and \n72\n include valves \n74\n for controlling flow between the choke and kill lines and the bore \n44\n.', 'Additional features of the main body \n42\n of the blowout preventer \n40\n may be better appreciated with reference to \nFIGS.', '6-8\n.', 'As shown in these figures, the main body \n42\n includes a ram cavity body portion \n78\n, which defines the ram cavity \n58\n, and external connection flanges \n50\n protruding laterally from the ram cavity body portion \n78\n.', 'The bore \n44\n extends vertically through the body \n42\n (more particularly, through the ram cavity body portion \n78\n) from an upper surface \n80\n to a lower surface \n82\n.', 'The ram cavity \n58\n extends laterally through the ram cavity body portion \n78\n between opposing ends \n84\n and is transverse to the bore \n44\n, allowing the rams \n56\n to be extended into the bore \n44\n during well control operations.', 'The bonnet assemblies \n52\n may be connected to the opposing ends \n84\n, as shown in \nFIGS.', '3 and 5\n.', 'The ram cavity body portion \n78\n also includes opposing sides \n86\n that run the length of the body \n42\n between the opposing ends \n84\n.', 'The connection flanges \n50\n protrude from these opposing sides \n86\n and allow the blowout preventer \n40\n to be fastened to other components (such as additional blowout preventers) along the sides of the ram cavity body portion \n78\n, rather than above and below the ram cavity body portion \n78\n (as would be the case with vertical bore API connections).', 'In the presently depicted embodiment, the body \n42\n includes an upper pair of connection flanges \n50\n extending laterally from the top of the ram cavity body portion \n78\n and a lower pair of connection flanges \n50\n extending laterally from the bottom of the ram cavity body portion \n78\n, with the upper and lower surfaces \n80\n and \n82\n being rectangular planar surfaces (which may include rounded corners, such as shown in \nFIG.', '7\n) that include sides of the flanges \n50\n.', 'In other instances, the flanges \n50\n could be axially offset (with respect to a central axis \n88\n of the bore \n44\n) from the top and bottom surfaces of the body \n42\n.', 'In at least some embodiments, including that depicted in \nFIGS.', '6-8\n, the body \n42\n is constructed such that the shortest axial distance between a connection flange \n50\n and the ram cavity \n58\n (the distance measured parallel to the central axis \n88\n and generally represented by arrow \n90\n in \nFIG.', '8\n) is less than the shortest radial distance between the connection flange \n50\n and the central axis \n88\n (as generally represented by arrow \n92\n in \nFIG.', '7\n).', 'Omitting vertical bore API connections from the upper and lower surfaces \n80\n and \n82\n allows a reduction in the height of the body \n42\n (generally represented by arrow \n94\n in \nFIG.', '8\n).', 'In some cases, the height of the body \n42\n is reduced to an amount similar to the height of bonnets \n54\n (generally represented by arrow \n96\n in \nFIG.', '8\n) connected to the opposing ends \n84\n.', 'For example, the body \n42\n and an attached bonnet \n54\n can be configured such that the height of the bonnet \n54\n is more than ninety or ninety-five percent of that of the body \n42\n.', 'This allows closer axial spacing of bonnets \n54\n in blowout preventer stacks having multiple blowout preventers \n40\n (compared to a stack of blowout preventers with vertical bore API connections and connected bonnets axially spaced further apart due to the increased height associated with the vertical bore API connections) and may facilitate reductions of both height and weight in such blowout preventer stacks.', 'Though some other embodiments may differ, in at least some embodiments the blowout preventer body \n42\n is widest measured across the external connection flanges \n50\n.', 'Moreover, in the embodiment depicted in \nFIGS.', '6-8\n the outer perimeter of the body \n42\n about its lateral edges is larger at the portions of the body \n42\n including the flanges \n50\n.', 'By way of example, \nFIGS.', '6 and 8\n show parallel planes \n102\n and \n104\n extending through the body \n42\n perpendicular to the bore \n44\n.', 'The plane \n102\n extends through the upper connection flanges \n50\n, while the plane \n104\n extends through the ram cavity \n58\n without passing through any of the connection flanges \n50\n.', 'The two-dimensional profiles of the body \n42\n lying in the planes \n102\n and \n104\n are depicted in \nFIGS.', '9 and 10\n, with an outer perimeter \n108\n of the body \n42\n within the plane \n102\n shown in \nFIG.', '9\n and an outer perimeter \n110\n of the body \n42\n within the plane \n104\n shown in \nFIG.', '10\n.', 'As can be seen from these figures, the cross-sectional area bounded by the perimeter \n108\n is larger than that bounded by the perimeter \n110\n.', 'The blowout preventer \n40\n can be installed with other blowout preventers in a blowout preventer stack, as discussed above.', 'In at least some embodiments, multiple blowout preventers \n40\n with structurally identical bodies \n42\n (each having the same bore, ram cavity, and size) can be used to construct a modular blowout preventer stack.', 'Two examples of such modular blowout preventer stacks \n120\n are depicted in \nFIGS.', '11 and 12\n as having three blowout preventers \n40\n and six blowout preventers \n40\n, respectively, although other numbers of preventers \n40\n could be used in additional embodiments.', 'The blowout preventers \n40\n in the blowout preventer stacks \n120\n of \nFIGS.', '11 and 12\n have independent and separable main bodies \n42\n, as in \nFIGS.', '3-8\n, and each of the preventers \n40\n is fastened directly to adjoining preventers \n40\n in the stack \n120\n via the external connection flanges \n50\n.', 'This is in contrast to other blowout preventer stacks using vertical bore API connections located axially between ram cavity body portions of the preventers or using tie rods to hold the preventers of a stack together without being fastened directly to one another.', 'Although not presently depicted, it will be appreciated that the upper and lower surfaces \n80\n and \n82\n of the blowout preventer bodies \n42\n can include seal grooves about the ends of their bores \n44\n.', 'Any suitable seal ring or gasket can be provided in these seal grooves to inhibit leakage from the bores \n44\n between the blowout preventer bodies \n42\n in the blowout preventer stacks \n120\n.', 'In at least some embodiments, the blowout preventers \n40\n are pre-assembled, with bonnet assemblies \n52\n attached to the bodies \n42\n, prior to integration of the blowout preventers \n40\n in a blowout preventer stack \n120\n.', 'By omitting vertical bore API connections and flanged necks between the blowout preventers \n40\n, the heights of the blowout preventer stacks \n120\n may be substantially reduced.', 'For example, in one embodiment the blowout preventer body \n42\n of each preventer \n40\n may be designed for service with an eighteen-and-three-quarter-inch (approx.', '48-cm) bore at a rated pressure of 15 ksi (approx.', '103 MPa), and the omission of vertical bore API connections allows the height of each preventer to be reduced by approximately sixteen inches (approx.', '41 cm).', 'This height savings, and accompanying weight savings, facilitates the assembly of lighter and shorter blowout preventer stacks.', 'And in at least some embodiments, this makes the blowout preventer stacks easier to handle on drilling rigs, reduces space requirements on the drilling rigs for storing the blowout preventer stacks, and reduces the loads and bending moments on wellheads when installed.', 'Further, although the body sizes of the blowout preventers \n40\n could vary in some other implementations, the ram-type preventers in the blowout preventer stacks \n120\n of \nFIGS.', '11 and 12\n use a blowout preventer body \n42\n with a standardized design common to each ram-type preventer.', 'Even with a standardized body \n42\n, different rams or bonnet assemblies could be used with the blowout preventers \n40\n of a given blowout preventer stack.', 'Using a single, standardized body \n42\n with one size and one configuration (per bore size and per pressure rating) with one ram cavity for each preventer \n40\n may also allow operators to maintain a more efficient capital spares program by having to stock just one body configuration for a given bore size and pressure rating, rather than stocking different bodies with different numbers of ram cavities and configurations, such as singles (with one ram cavity), doubles (with two ram cavities), extended doubles, triples (with three ram cavities), and extended triples.', 'Instead, the number of ram cavities that would be present in a double- or triple-cavity preventer can be provided by a combination of two or three of the single preventer bodies \n42\n.', 'As discussed in additional detail below with respect to \nFIG.', '18\n, one or more spacers can be positioned between single preventer bodies \n42\n to provide axial space for bonnet assemblies taller than a single body \n42\n to be used.', 'As described above, the blowout preventer \n40\n can include choke and kill line connection assemblies \n70\n and \n72\n mounted on the exterior of the blowout preventer body \n42\n.', 'A blowout preventer stack \n120\n including one or more of such blowout preventers \n40\n, such as the blowout preventer stacks \n120\n depicted in \nFIGS.', '11 and 12\n, can have choke and kill lines that run along the outside of the stack \n120\n and are connected to the blowout preventers \n40\n via the external choke and kill line connection assemblies \n70\n and \n72\n.', 'In at least some embodiments, however, a blowout preventer \n40\n instead includes internal choke and kill line pass-through conduits arranged to be aligned with similar internal conduits of other blowout preventers \n40\n.', 'Multiple blowout preventers \n40\n having such internal choke and kill line conduits can be assembled in a blowout preventer stack so as to form a shared, internal choke line conduit and a shared, internal kill line conduit running through the blowout preventer bodies.', 'By way of example, a blowout preventer \n40\n with such internal choke and kill line conduits is illustrated in \nFIGS.', '13 and 14\n, with the main body \n42\n of this preventer \n40\n depicted in \nFIGS.', '15 and 16\n.', 'In this depicted embodiment, the blowout preventer \n40\n is similar to that shown in \nFIG.', '3\n, but its body \n42\n includes protrusions \n130\n and \n132\n extending laterally from opposing sides \n86\n of the ram cavity body portion \n78\n.', 'Pass-through conduits \n136\n and \n138\n extend vertically through the protrusions \n130\n and \n132\n parallel to the bore \n44\n, while valves \n140\n (such as gate valves) are provided to control flow through access branch conduits between the bore \n44\n and the conduits \n136\n and \n138\n.', 'In at least some embodiments, including that shown in \nFIGS.', '13-16\n, the lateral protrusions \n130\n and \n132\n are identical to one another and each of the conduits \n136\n and \n138\n could serve as a choke line conduit or a kill line conduit.', 'For ease of explanation, however, the conduit \n136\n will be referred to as the choke line conduit \n136\n and the conduit \n138\n will be referred to as the kill line conduit \n138\n below.', 'The protrusions \n130\n and \n132\n of the blowout preventer body \n42\n include valve preparation recesses \n144\n for receiving the valves \n140\n.', 'These valve preparation recesses \n144\n are transverse to choke and kill line access branch conduits \n148\n and \n150\n that extend through the body \n42\n to connect the choke line conduit \n136\n and the kill line conduit \n138\n to the bore \n44\n.', 'When installed in these recesses \n144\n, the valves \n140\n control flow between the bore \n44\n and the choke and kill line conduits \n136\n and \n138\n through the access branches \n148\n and \n150\n.', 'The lateral protrusions \n130\n and \n132\n are also depicted in \nFIGS.', '13-16\n as including external connection flanges \n50\n that allow the protrusions of adjacent preventers \n40\n in a blowout preventer stack to be fastened to one another in a manner similar to that described above with respect to the connection flanges \n50\n along the ram cavity body portions \n78\n.', 'Additional blowout preventer stacks \n120\n are depicted in \nFIGS.', '17 and 18\n as having multiple blowout preventers \n40\n with such integral choke and kill lines extending through protrusions of the blowout preventer bodies.', 'In \nFIG.', '17\n, the blowout preventer stack \n120\n is depicted as having five of the blowout preventers \n40\n in a stacked arrangement.', 'The bodies \n42\n of these blowout preventers \n40\n are structurally identical (though the rams of the preventers may vary), and are fastened together via their external connection flanges \n50\n.', 'Further, the drill-through bores \n44\n, the choke line conduits \n136\n, and the kill line conduits \n138\n of the blowout preventers \n40\n are aligned with one another so as to form a shared drill-through bore, a shared choke line conduit, and a shared kill line conduit each extending through the five blowout preventers \n40\n.', 'Although not presently shown, it will be appreciated that any suitable seals could be used to prevent leakage from the shared choke and kill line conduits between adjacent preventers \n40\n.', 'The blowout preventers \n40\n can be pre-assembled, with bonnet assemblies \n52\n attached to the bodies \n42\n and valves \n140\n installed in the valve recesses \n144\n, prior to integration of the blowout preventers \n40\n in a blowout preventer stack \n120\n.', 'In certain embodiments, the integration of the valves \n140\n into the blowout preventer bodies \n42\n allows conventional fabricated choke and kill spools that would be attached to the exterior of the bodies \n42\n to be eliminated, reducing leak paths and increasing reliability of the apparatus.', 'This also allows the valves to be removed for servicing without disconnecting external choke and kill lines of the stack \n120\n.', 'In \nFIG.', '18\n, the blowout preventer stack \n120\n is depicted as having three blowout preventers \n40\n.', 'The upper and lower preventers \n40\n in this blowout preventer stack \n120\n have bonnet assemblies \n156\n, while the middle preventer \n40\n includes bonnet assemblies \n160\n.', 'Although the bonnet assemblies \n156\n are shorter than the main bodies of the blowout preventers \n40\n, the bonnet assemblies \n160\n have a housing that is taller.', 'For example, the bonnet assemblies \n160\n may include larger pistons with greater operational areas (compared to pistons in the bonnet assemblies \n156\n) to allow hydraulic pressure on the larger pistons to cause a greater closing force on the rams, which may be desired for certain shear applications.', 'Spacers \n164\n can be positioned in the stack \n120\n above and below the preventer \n40\n to which the assemblies \n160\n are attached to increase the axial distance of the stack and accommodate the larger bonnet assemblies \n160\n.', 'The blowout preventers \n40\n of \nFIGS.', '13-18\n are depicted as having external connection flanges \n50\n that allow the preventers to be fastened together without vertical bore API connections.', 'In other embodiments, however, the internal choke and kill line conduits described above can be implemented in blowout preventers having such vertical bore API connections.', 'That is, the integration of choke and kill line conduits extending through the blowout preventer bodies, and the sharing of such conduits across multiple blowout preventer bodies in a blowout preventer stack, does not depend on the elimination of vertical bore API connections.', 'Upper and lower ends of blowout preventers, flex joints, connectors, and other components can be provided with raised faces to reduce the area of contact between the connected components.', 'This reduction in the area of contact allows the bolting make-up load in a flanged connection to be concentrated over a smaller area to increase the contact pressure of mating faces, which helps the connection resist leakage due to various separating loads resulting from tensile forces and bending moments.', 'Referring to \nFIG.', '19\n, for example, blowout preventer main bodies \n42\n can include raised faces \n170\n.', 'While a raised face \n170\n is shown on the lower end of the bottom blowout preventer main body \n42\n of the stack depicted in \nFIG.', '19\n, the top blowout preventer body \n42\n may also include a raised face \n170\n on its lower end.', 'In some embodiments, the blowout preventer bodies \n42\n may also or instead include raised faces \n170\n on their upper ends.', 'The depicted raised face \n170\n includes a seal groove \n172\n for receiving a seal ring or gasket.', 'As shown in \nFIG.', '19\n, the raised face \n170\n extends continuously from the bore \n44\n to the outer edge of the raised face \n170\n, with the lone exception of the single seal groove \n172\n.', 'In at least some embodiments, however, the raised face includes at least one additional recess in the raised face \n170\n.', 'This additional recess further increases the contact pressure on the raised face \n170\n for a given bolting make-up load applied via the flanged connection.', 'One example of such an additional recess is shown in \nFIGS.', '20 and 21\n as a recess \n174\n provided in the raised face \n170\n outward of the seal groove \n172\n.', 'In these two figures, the recess \n174\n is shown as a circular groove that is concentric with the circular seal groove \n172\n and with the circular outer perimeter of the raised face \n170\n, and that partitions the raised face \n170\n into inner and outer contact surfaces.', 'But the seal groove \n172\n, the recess \n174\n, and the outer perimeter of the raised face \n170\n may be provided in other shapes in different embodiments, and need not be the same shape.', 'For instance, the raised face \n170\n could have an oval, rectangular, or irregular outer perimeter.', 'Similarly, the recess \n174\n could be provided as an oval, rectangular, or irregular groove.', 'In other instances, the raised face \n170\n may include multiple recesses \n174\n, which may themselves be concentric grooves or have some other shape.', 'Further, the one or more recesses \n174\n could be provided as non-continuous grooves (e.g., semi-circular slots or radial slots) or other indentations (e.g., pockets) in the raised face \n170\n.', 'In certain embodiments in which the recess \n174\n is provided as a groove that partitions the raised face \n170\n into inner and outer contact surfaces, the inner and outer contact surfaces may be stepped such that the inner contact surface protrudes further from the main body \n42\n than does the outer contact surface.', 'In \nFIG.', '22\n, each of the main bodies \n42\n is shown as having upper and lower raised faces \n170\n, and the main bodies \n42\n are coupled together via flanges \n50\n such that adjoining raised faces \n170\n of the two main bodies \n42\n (i.e., at the bottom of the upper main body \n42\n and the top of the lower main body \n42\n) are in contact.', 'A seal ring \n178\n is positioned in the seal grooves \n172\n of the adjoining raised faces \n170\n to inhibit leakage between the main bodies \n42\n from the bore \n44\n.', 'As may be seen in \nFIG.', '22\n, the recesses \n174\n in the raised faces \n170\n reduce the area of contact between the adjoining raised faces \n170\n of the two main bodies \n42\n.', 'Each recess \n174\n can have any desired width and depth.', 'In certain embodiments, for example, the width of the recess \n174\n (measured along the contact surface of the raised face \n170\n) is at least two, three, or four times that of the seal groove \n172\n.', 'Likewise, the depth of the recess \n174\n is at least two, three, or four times that of the seal groove \n172\n in at least some embodiments.', 'The width of the recess \n174\n (again, measured along the contact surface) can also be compared to the width of the raised face \n170\n between the bore \n44\n and the outer perimeter of the raised face \n170\n.', 'The width of the recess \n174\n could be more than one-third or more than one-half of the radial distance from the bore \n44\n to the outer perimeter of the raised face \n170\n, for example.', 'The recess \n174\n can also have various contours.', 'In some embodiments, the recess \n174\n is provided as a groove with a semi-hexagonal shape (like the shape of the seal groove \n172\n), a semi-oval shape, a rectangular shape, or a triangular shape, though the recess \n174\n could have still other shapes (including irregular shapes) in different embodiments.', 'Recesses \n174\n can be formed by removing material from lower-stress areas at the ends of the main bodies \n42\n, which also reduces the weight of the main bodies \n42\n.', 'Additionally, the recesses \n174\n increase connection efficiency by causing increased contact pressure of the mating raised faces \n170\n for a given bolting make-up load in a flanged connection.', 'This facilitates using the same bolts for greater loads (increased capacity) or smaller bolts to provide the original make-up load.', 'Still further, the recesses \n174\n facilitate extension of the outer perimeter of the raised faces \n170\n closer to the outer edge of the flanges, which may decrease stress levels in the ends of the main bodies \n42\n and in the bolting from make-up loads.', 'Although the raised faces \n170\n with recesses \n174\n are shown and discussed above with respect to \nFIGS.', '20-22\n as part of wide-flanged ram-type blowout preventers, the same techniques can be applied to other wide-flanged components or to other components with traditional flanged connections (e.g., components with vertical bore API connections).', 'In many instances, nuts are used with bolts or studs to make-up a flanged connection.', 'An example of this is shown in \nFIG.', '23\n, in which fasteners \n48\n (shown here in the form of nuts and bolts) are used to connect the main bodies \n42\n via the wide flanges \n50\n.', 'In some instances, such as when there is a gap between a flange and a mating surface (e.g., a mating flange or studded surface), fasteners in flanged connections may be subject to bending loads.', 'In the embodiment depicted in \nFIG.', '23\n, the presence of the adjoining raised faces \n170\n cause the mating flanges \n50\n of the two main bodies \n42\n to be spaced apart.', 'When the flanged connection is made-up (e.g., by tightening the nuts on the bolts), the flanges \n50\n can flex toward one another, causing bending stresses on the bolts.', 'Such bending stresses may also be caused by external loading.', 'In some embodiments, bending stresses on fasteners in a flanged connection are reduced through use of shaped elements that facilitate rotation of the flanges relative to the fasteners.', 'By way of example, as generally shown in \nFIG.', '23\n, the flanges \n50\n include shaped inserts to reduce bending stresses on the fasteners \n48\n.', 'Certain aspects of the inserts may be better understood with reference to \nFIGS.', '24-26\n.', 'In \nFIG.', '24\n, inserts \n182\n and \n184\n are shown positioned within counterbores \n186\n of the fastening holes \n46\n in the flanges \n50\n, which are separated by a gap \n190\n.', 'The inserts \n182\n and \n184\n bear against one another, with the inserts \n182\n having a concave bearing surface and the inserts \n184\n having a convex bearing surface.', 'These bearing surfaces are shown in more detail in the exploded view of the fasteners and inserts in \nFIG.', '26\n.', 'As presently depicted, the mating surfaces of the concave inserts \n182\n and the convex inserts \n184\n are spherical, though either or both inserts may instead have a non-spherical bearing surface in other embodiments (e.g., non-spherical, tapered surfaces oriented to facilitate rotation of the flange with respect to a fastener).', 'And while the concave inserts \n182\n are presently depicted as contacting the flange \n50\n with the convex inserts \n184\n contacting the fasteners \n48\n, these inserts could be installed in the reverse order (i.e., with the inserts \n184\n contacting the flanges \n50\n and the inserts \n182\n contacting the fasteners \n48\n).', 'Upon loading of the bolted connection (whether from make-up, end loads, or other external loading) in a manner causing or increasing flexure of the flanges \n50\n, the concave inserts \n182\n move with the flanges \n50\n, which causes the concave inserts \n182\n to slide along and pivot about the convex inserts \n184\n.', 'An example of this is shown in \nFIG.', '25\n, in which the bolted connection is deflected further than shown in \nFIG.', '24\n.', 'The extent of flexure of the flanges \n50\n in \nFIG.', '25\n is exaggerated for the sake of explanation and to better show the pivoting of the concave inserts \n182\n about the convex inserts \n184\n upon flexure of the flanges \n50\n.', 'This relative movement of the concave inserts \n182\n with respect to the convex inserts \n184\n allows the flange \n50\n to move relative to the fastener \n48\n (bolt or stud) extending through the holes \n46\n and reduces the magnitude of bending stresses transferred to the fastener.', 'In at least some embodiments, the concave inserts \n182\n include splits \n194\n (\nFIG.', '26\n) in one or more places to reduce hoop stresses on these inserts within the counterbores \n186\n.', 'The presently described inserts can be used to reduce bending stresses in bolted connections of various wide flange bodies, such as those described above.', 'But the inserts can similarly be used in other flanged connections, including traditional flanged connections, to reduce bending stresses in full accordance with the present technique.', 'Additionally, while certain embodiments are described above as having external connection flanges \n50\n along the sides of ram cavity body portions of blowout preventers, and using fasteners \n48\n in the form of bolts and nuts to join preventers to each other or to other components via these flanges \n50\n, other connection arrangements are also contemplated.', 'For example, clamps (such as C-clamps) could be used, rather than bolts and nuts, to join flanges \n50\n together.', 'In other embodiments, latches, clevis assemblies, keys, or a breech-lock connection could be used to join adjacent preventers, with or without flanges \n50\n.', 'In still another embodiment, the stackable blowout preventer bodies can have a tongue and groove arrangement to facilitate alignment and coupling of the preventers together.', 'While the aspects of the present disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'But it should be understood that the invention is not intended to be limited to the particular forms disclosed.', 'Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.'] | ['1.', 'A blowout preventer apparatus comprising:\na blowout preventer body including: a bore extending axially through the blowout preventer body; a ram cavity extending horizontally through the blowout preventer body and transverse to the bore; opposing external end surfaces extending laterally to define the blowout preventer body and between which the ram cavity extends; opposing external side surfaces extending horizontally between the opposing external end surfaces; and a plurality of external connection flanges extending laterally outwardly from each of the opposing external side surfaces; wherein the opposing external end surfaces are devoid of external connection flanges.', '2.', 'The blowout preventer apparatus of claim 1, wherein the bore extends through the blowout preventer body from an upper surface of the blowout preventer body to a lower surface of the blowout preventer body, and the upper surface of the blowout preventer body or the lower surface of the blowout preventer body is a planar surface that includes a portion of one of the external connection flanges.', '3.', 'The blowout preventer apparatus of claim 2, wherein the planar surface is a rectangular planar surface.', '4.', 'The blowout preventer apparatus of claim 1, wherein each external connection flange has a bolt pattern that facilitates fastening of the blowout preventer body to another component.', '5.', 'The blowout preventer apparatus of claim 1, comprising:\nrams positioned within the ram cavity; and\nbonnet assemblies coupled to the blowout preventer body, wherein the bonnet assemblies include operating pistons coupled to the rams.', '6.', 'The blowout preventer apparatus of claim 1, wherein the blowout preventer body does not include a tubular neck that extends from the blowout preventer body along a central axis of the bore.', '7.', 'The blowout preventer apparatus of claim 1, comprising a blowout preventer stack including the blowout preventer body and additional blowout preventer bodies structurally identical to the blowout preventer body, wherein the blowout preventer body and at least two of the additional blowout preventer bodies are fastened together via their external connection flanges.', '8.', 'A blowout preventer apparatus comprising:\na blowout preventer stack including: a plurality of blowout preventers in a stacked configuration, the plurality of blowout preventers including a first blowout preventer with a first main body and a second blowout preventer having a second main body, the first main body and the second main body of the first and second blowout preventers each define a bore and a ram cavity configured to house rams, wherein the ram cavity extends horizontally and is transverse to the bore;\nwherein a lower end of the first main body of the first blowout preventer defines a first lower flange and a second lower flange, wherein the first lower flange and the second lower flange are laterally separated from each other by the first main body and extend horizontally along opposed external side surfaces of the first main body between opposed external end surfaces of the first main body, wherein the opposed external end surfaces are devoid of flanges;\nwherein an upper end of the second main body of the second blowout preventer defines a first upper flange and a second upper flange, the first lower flange and the second lower flange of the first main body of the first blowout preventer are fastened directly to the first upper flange and the second upper flange of the second main body of the second blowout preventer with a plurality of fasteners.', '9.', 'The blowout preventer apparatus of claim 8, wherein the lower end of the first main body of the first blowout preventer and the upper end of the second main body of the second blowout preventer each include a protrusion that extends laterally from the first main body and the second main body.', '10.', 'The blowout preventer apparatus of claim 8, wherein the first lower flange and the second lower flange are parallel to each other.', '11.', 'The blowout preventer apparatus of claim 8, wherein the first and second blowout preventers are fastened together via keyed engagement between the first and second blowout preventers.', '12.', 'The blowout preventer apparatus of claim 8, wherein the first main body and the second main body of the first and second blowout preventers are structurally identical to one another.', '13.', 'A method of assembling a blowout preventer stack, the method comprising:\naligning a first blowout preventer with a second blowout preventer into a blowout preventer stack, the first blowout preventer comprising a first main body and the second blowout preventer comprising a second main body, wherein the first main body and the second main body of the first blowout preventer and the second blowout preventer, respectively, have a modular design with a bore, a ram cavity, and a common size;\nfastening respective bonnet assemblies to respective opposing external ends of the first main body and the second main body, wherein each of the respective bonnet assemblies comprises an operating piston coupled to a ram; and\nfastening the first blowout preventer and the second blowout preventer directly to one another with a plurality of fasteners that extend through flanges that extend laterally outward from and horizontally along respective opposing external sides of the first main body and the second main body between the respective opposed external ends of the first main body and the second main body, wherein the opposed external ends are devoid of flanges.\n\n\n\n\n\n\n14.', 'The method of claim 13, wherein the respective bonnet assemblies are pre-installed prior to fastening the first blowout preventer and the second blowout preventer directly to one another.'] | ['FIG. 1 generally depicts a well apparatus in the form of an offshore drilling system with a drilling rig coupled by a riser to a wellhead assembly in accordance with one embodiment of the present disclosure;; FIG. 2 is a block diagram depicting a blowout preventer stack assembly of the apparatus of FIG.', '1 in accordance with one embodiment;; FIG. 3 is a perspective view of a blowout preventer having a main body with external connection flanges protruding laterally from sides of a ram cavity body portion in accordance with one embodiment;; FIGS. 4 and 5 are cross-sections of the blowout preventer of FIG.', '3', 'and show certain internal components in accordance with one embodiment;; FIG.', '6 is a perspective view of the body of the blowout preventer of FIG.', '3;; FIG. 7 is a top plan view of the body of the blowout preventer of FIG.', '3;; FIG. 8 is an elevational view of the body of the blowout preventer of FIG.', '3;; FIGS.', '9', 'and 10 depict outer perimeters of the blowout preventer body of FIGS.', '6-8 lying within reference planes depicted in FIGS.', '6 and 8;; FIGS. 11 and 12 depict modular blowout preventer stacks having multiple blowout preventers with identical main bodies in accordance with certain embodiments;; FIG. 13 is a perspective view of a blowout preventer having choke and kill line conduits, with associated valves, integrated into its main body in accordance with one embodiment;; FIG.', '14 is a top plan view of the blowout preventer of FIG.', '13;; FIG.', '15 is a perspective view of the main body of the blowout preventer of FIG.', '13;; FIG.', '16 is a section view of the main body depicted in FIG.', '15, showing the internal choke and kill line conduits with access branches connecting to a main bore, in accordance with one embodiment;; FIG.', '17 depicts a modular blowout preventer stack having multiple blowout preventers with identical main bodies and internal choke and kill lines integrated into the bodies of the blowout preventers in accordance with one embodiment;; FIG.', '18 shows a modular blowout preventer stack having multiple blowout preventers with axial spacers for accommodating the use of larger bonnet assemblies in the blowout preventer stack in accordance with one embodiment;; FIG.', '19 is a perspective view of two blowout preventers with raised faces in a stacked configuration in accordance with one embodiment;; FIG.', '20 is a perspective view of two blowout preventers like those of FIG.', '19, but in which the raised faces having partitioning grooves in accordance with one embodiment;; FIG.', '21 is a top plan view of the blowout preventer stack of FIG.', '20;', '; FIGS.', '22 and 23 are cross-sections of the blowout preventer stack of FIG.', '20;', '; FIGS.', '24 and 25 are detail views showing fasteners that connect flanges of the blowout preventers of FIG.', '20 and inserts for reducing bending stresses on the connection in accordance with one embodiment; and; FIG.', '26 is an exploded view of the fasteners and inserts of FIGS.', '24 and 25.'] |
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US11098546 | Systems and methods for holding wireline device against well | Sep 30, 2019 | Joseph Varkey, Maria Grisanti, Paul Wanjau, David Kim, William Brian Underhill, Nicolas Roumilly, Sebastien Isambert | SCHLUMBERGER TECHNOLOGY CORPORATION | Notice of Allowance issued in U.S. Appl. No. 16/679,366, dated Jan. 1, 2021 (12 pages). | 3233170; February 1966; Rogers; 4438810; March 27, 1984; Wilkinson; 4515010; May 7, 1985; Weido; 4953136; August 28, 1990; Kamata; 5259452; November 9, 1993; Wittrisch; 6006855; December 28, 1999; Howlett; 6026911; February 22, 2000; Angle et al.; 7187620; March 6, 2007; Nutt; 7721809; May 25, 2010; Minto; 7894297; February 22, 2011; Nutt; 9170149; October 27, 2015; Hartog et al.; 9217320; December 22, 2015; Odashima; 20140191762; July 10, 2014; Chen et al.; 20160215579; July 28, 2016; Van Der Ende; 20170285208; October 5, 2017; Castillo; 20180179840; June 28, 2018; Varkey et al.; 20200110235; April 9, 2020; Maida et al. | Foreign Citations not found. | ['A system includes a cable and at least one coupling device installed along the cable.', 'The coupling element has one or more through cavities for receiving the cable, and configured to hold the cable when disposed in the cavity against a surface of the wellbore.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates to systems and methods to improve a signal to noise ratio of wellbore measurements, in particular distributed acoustic sensing measurement.', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, these statements are to be read in this light, and not as admissions of any kind.', 'To locate and extract resources from a well, a wellbore may be drilled into a geological formation.', 'Some wellbores may change direction at some point downhole.', 'The change in direction may be at an angle as high as ninety degrees with respect to the surface, causing the wellbore to become horizontal.', 'Downhole toolstrings and sensors are placed into the wellbore to identify properties of the downhole environment.', 'The cable may also comprise a fiber optic line that enables to provide distributed acoustic sensing.', 'In vertical portions of the wellbore, the downhole toolstrings and sensors may descend into the wellbore using only the force of gravity.', 'However, the downhole toolstrings and sensors may descend into angled portions of the well through the use of additional forces other than gravity.', 'As the wellbore approaches a more horizontal angle, the additional forces play a greater role in propelling the downhole toolstrings and sensors deeper into the wellbore.', 'Once the downhole toolstrings and sensors reach the desired location within the wellbore, the sensors are used to gather data about the geological formation.', 'However, this movement of the toolstrings and sensors may worsen the signal to noise ratio, which could lead to less accurate measurements.', 'In case where a fiber optic is included in the cable, the placement of the cable along the wellbore may have an influence on the signal to noise ratio of the distributed acoustic measurements.', 'SUMMARY\n \nA summary of certain embodiments disclosed herein is set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'The disclosure generally relates to a system comprising a cable and at least one coupling device installed along the cable having one or more through cavities for receiving the cable, and configured to hold the cable when disposed in the cavity against a surface of the wellbore.', 'Such coupling device may hold the cable against the surface of the wellbore in a cased hole and/or open hole configuration.', 'This can lead to more accurate measurements and decrease the signal to noise ratio.', 'Such coupling is particularly interesting when the cable includes fiber optic, for instance when the cable is a wireline cable includes a fiber optic cable.', 'The fiber being coupled to the wellbore, the signal obtained from the formation are better sensed and the signal to noise ratio is improved, enabling to get better insight of the formation characteristics.', 'The disclosure also related to a method for operating a cable in a wellbore.', 'The method includes installing one or more coupling devices along the cable, so that the cable is received in one or more through cavities of the coupling devices, lowering the cable with the installed coupling device into the wellbore, wherein the coupling device holds the cable disposed in the cavity against a surface of the wellbore.', 'In one example, a system includes a cable, a toolstring, and a device.', 'The toolstring may couple to the cable to enable the toolstring to be placed in a wellbore.', 'Further, the toolstring includes sensors configured to collect data of a geological formation.', 'The device may selectively hold the toolstring against a surface of the wellbore.', 'In another example, a cable system includes a cable core that includes fiber optic cables, multiple strength members outside of the cable core, and multiple magnetic strength members outside of the cable core.', 'The multiple magnetic strength members may selectively carry current, and the multiple magnetic strength members may become magnetic or activate an electromagnet electrically coupled to the multiple magnetic strength members when the multiple magnetic strength members carry current.', 'In yet another example, a method for improving the signal to noise ratio, includes lowering a cable and a toolstring into a wellbore.', 'The method includes extending at least one arm of a tractor device coupled to the toolstring, and the at least one arm includes a wheel.', 'The method includes engaging the wheel of the tractor device against a surface of the wellbore, and engaging the wheel of the tractor device propels the toolstring and the cable into the wellbore.', 'The method includes retracting the at least one arm of the tractor device, and retracting the at least one arm disengages the wheel from the surface of the wellbore.', 'The method includes attaching the toolstring to the surface of the wellbore using a device coupled to the toolstring.', 'Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:\n \nFIG.', '1A\n is a schematic diagram of a wireline system that includes a toolstring to detect properties of a wellbore or geological formation adjacent to the toolstring, in accordance with an aspect of the present disclosure;\n \nFIG.', '1B\n is a schematic diagram of a portion of a wireline system according to an embodiment of the disclosure.', 'FIGS.', '2A and 2B\n are cross sections of different embodiments of a cable that can be magnetized, in accordance with an aspect of the present disclosure;\n \nFIG.', '3A\n is a side view of an embodiment of a toolstring with the arms of a tractor device extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '3B\n is a side view of the toolstring of \nFIG.', '3A\n in a wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '3C\n is a side view of the toolstring of \nFIG.', '3A\n with the cable magnetized and the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;\n \nFIG.', '3D\n is a side view of the toolstring of \nFIG.', '3C\n in a wellbore and with the cable magnetized and held to the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '4\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '5A\n is a side view of an embodiment of a toolstring including a timer-activated magnetic device with the arms of the tractor device extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '5B\n is a side view of the toolstring of \nFIG.', '5A\n in a wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '5C\n is a side view of the toolstring of \nFIG.', '5A\n with the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;\n \nFIG.', '5D\n is a side view of the toolstring of \nFIG.', '5C\n in a wellbore and with the selectively magnetic device holding the toolstring to the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '5E\n is a side view of the toolstring of \nFIG.', '5D\n, with an additional toolstring mounted on the cable, in accordance with an aspect of the present disclosure;\n \nFIG.', '6\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure;\n \nFIGS.', '7A-7B\n are cross sections of different embodiments of the cable with a magnetic device coupled to the cable, in accordance with an aspect of the present disclosure;\n \nFIG.', '8A\n is a side view of an embodiment of the magnetic device, in accordance with an aspect of the present disclosure;\n \nFIG.', '8B\n is a side view of multiple magnetic devices of \nFIG.', '8A\n in a wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '8C\n is a side view of the magnetic devices of \nFIG.', '8B\n attached to the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '9A\n is a side view of an embodiment of the toolstring including an anchoring device and a tractor device and the arms of the tractor device are extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '9B\n is a side view of the toolstring of \nFIG.', '9A\n and the side-arm of the anchoring device extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '9C\n is a side view of multiple toolstring of \nFIG.', '9B\n with the arms of the tractor devices retracted and the side-arms of the anchoring devices extended and holding the toolstrings against the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '10\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using an anchoring device, in accordance with an aspect of the present disclosure;\n \nFIG.', '11A\n is a side view of the toolstring of \nFIG.', '9A\n where the anchoring device is activated by a timer device, in accordance with an aspect of the present disclosure;\n \nFIG.', '11B\n is a side view of the toolstring of \nFIG.', '11B\n in a wellbore and with the arms of the tractor device extended, in accordance with an aspect of the present disclosure; and\n \nFIG.', '12\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure.', 'FIG.', '13A\n is a perspective view of a coupling device according to an embodiment of the disclosure,\n \nFIG.', '13B\n is an exploded view of the coupling device of \nFIG.', '13A\n \nFIG.', '13C\n is a cross-section of a variant of the coupling device of \nFIG.', '13A\n \nFIG.', '13D\n is a perspective view of another variant of the coupling device of \nFIG.', '13A\n \nFIG.', '14\n is a view of a system according to an embodiment of the disclosure\n \nFIG.', '15\n is a view of a system according to an embodiment of the disclosure\n \nFIG.', '16\n is a cross-section of a portion of the system of \nFIG.', '15\n.\n \nFIG.', '17\n is a flowchart of a method according to an embodiment of the disclosure.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'The present disclosure relates to devices that improve the signal to noise ratio of sensors in a wellbore.', 'Toolstrings containing sensors may be placed into the wellbore to gather information about the geological formation.', 'In some portions of the wellbore, the tool may require forces in addition to gravity to descend further into the well.', 'Once the tool has reached the desired location in the wellbore, the sensors may gather data about the geological formation.', 'When the sensors are gathering data, movement of the sensors may worsen the signal to noise ratio.', 'Therefore, it is desirable to keep the sensors as steady as is possible when the sensors are gathering data.', 'Accordingly, embodiments of this disclosure relate to a system and method for propelling the toolstring further into the wellbore and for holding the toolstring in a steady position once the toolstring has reached the desired location.', 'That is, some embodiments include a tractor device that includes extendable arms.', 'The arms include drive wheels that may engage the surface of the casing of the wellbore and propel the toolstring further into the wellbore.', 'Some embodiments include a device that may hold the toolstring steady at the desired location in the wellbore.', 'The device may include components within a cable that can be selectively magnetized.', 'When the components are activated and the components becomes magnetized, the cable may attach to the casing of the wellbore.', 'Attaching the cable to the casing of the wellbore may hold the toolstring steady in place.', 'Alternatively, the device may include components within the toolstring that can be selectively magnetized.', 'When the components are activated and the components become magnetized, the toolstring may attach and hold steady against the casing of the wellbore.', 'Alternatively, the device may include components that mechanically hold the toolstring against the casing of the wellbore.', 'The components may include an arm that braces the toolstring against the casing of the wellbore.', 'Further, the device may include multiple devices spread out along the cable.', 'With this in mind, \nFIG.', '1A\n illustrates a well-logging system \n10\n that may employ the systems and methods of this disclosure.', 'The well-logging system \n10\n may be used to convey a toolstring \n12\n through a geological formation \n14\n via a wellbore \n16\n.', 'Further, the wellbore \n16\n may not continue straight down into the geological formation \n14\n, and the wellbore \n16\n may contain a turn \n13\n.', 'The wellbore \n16\n may continue past the turn into the geological formation \n14\n at an angle as high as ninety degrees.', 'In the example of \nFIG.', '1A\n, the toolstring \n12\n is conveyed on a cable \n18\n via a logging winch system (e.g., vehicle) \n20\n.', 'Although the logging winch system \n20\n is schematically shown in \nFIG.', '1A\n as a mobile logging winch system carried by a truck, the logging winch system \n20\n may be substantially fixed (e.g., a long-term installation that is substantially permanent or modular).', 'Any suitable cable \n18\n for well logging may be used.', 'The cable \n18\n may be spooled and unspooled on a drum \n22\n and an auxiliary power source \n24\n may provide energy to the logging winch system \n20\n, the cable \n18\n, and/or the toolstring \n12\n.', 'Moreover, while the toolstring \n12\n is described as a wireline toolstring, it should be appreciated that any suitable conveyance may be used.', 'For example, the toolstring \n12\n may instead be conveyed as a logging-while-drilling (LWD) tool as part of a bottom hole assembly (BHA) of a drill string, conveyed on a slickline or via coiled tubing, and so forth.', 'For the purposes of this disclosure, the toolstring \n12\n may include any suitable measurement tool that uses a sensor to obtain measurements of properties of the geological formation \n14\n.', 'The toolstring \n12\n may use any suitable sensors to obtain any suitable measurement, including resistivity measurements, electromagnetic measurements, radiation-based (e.g., neutron, gamma-ray, or x-ray) measurements, acoustic measurements, and so forth.', 'In general, the toolstring \n12\n may obtain better measurements, having a higher signal-to-noise ration, when the toolstring \n12\n is pressed against the wellbore \n16\n wall.', 'In some cases, the toolstring \n12\n may use fiber optic sensors that obtain wellbore measurements that are greatly improved when the toolstring \n12\n is pressed against the wellbore \n16\n wall.', 'Furthermore, when the cable \n18\n includes fiber optic cables, the signal that is transported over the fiber optic cables may be improved when the cable is generally held taut (rather than, for example, including many turns or kinks that could degrade the signal traveling over the fiber optic cable).', 'The toolstring \n12\n may emit energy into the geological formation \n14\n, which may enable measurements to be obtained by the toolstring \n12\n as data \n26\n relating to the wellbore \n16\n and/or the geological formation \n14\n.', 'When collecting the data \n26\n, it is desirable to keep the toolstring \n12\n as steady as possible in order to improve the signal to noise ratio.', 'Improving the signal to noise ratio allows for more accurate readings.', 'The data \n26\n may be sent to a data processing system \n28\n.', 'For example, the data processing system \n28\n may include a processor \n30\n, which may execute instructions stored in memory \n32\n and/or storage \n34\n.', 'As such, the memory \n32\n and/or the storage \n34\n of the data processing system \n28\n may be any suitable article of manufacture that can store the instructions.', 'The memory \n32\n and/or the storage \n34\n may be read-only memory (ROM), random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive, to name a few examples.', 'A display \n36\n, which may be any suitable electronic display, may display the images generated by the processor \n30\n.', 'The data processing system \n28\n may be a local component of the logging winch system \n20\n (e.g., within the toolstring \n12\n), a remote device that analyzes data from other logging winch systems \n20\n, a device located proximate to the drilling operation, or any combination thereof.', 'In some embodiments, the data processing system \n28\n may be a mobile computing device (e.g., tablet, smart phone, or laptop) or a server remote from the logging winch system \n20\n.', 'In another embodiment, the cable \n18\n including fiber optic cables (i.e. optical fiber) may also be used for measuring one or more parameters of the wellbore \n16\n or formation \n14\n, using distributed techniques.', 'Such measurement is well known as distributed temperature sensing (DTS), in which the sensed parameter is temperature, or distributed acoustic sensing (DAS), in which the sensed parameters includes acoustic waves.', 'DAS is more particularly used to sense the properties of the formation, generally in combination with acoustic sources generating a predetermined acoustic signal, such as seismic sources disposed at the surface, the signal passing through the formation and being received at one or more location of the fiber optic enabling to derive very useful information about the formation properties.', 'In order to have a better transmission of information from the formation to the fiber, having the fiber, and therefore the cable, as close to the borehole wall as possible is very valuable.', 'An example of a system of distributed sensing is described below in relationship with \nFIG.', '1B\n.', 'A distributed sensing system employs an interrogation and acquisition system \n50\n having an optical source \n52\n (e.g., a laser) to generate pulses of optical energy to launch into the optical fiber of the cable \n18\n.', 'As the launched pulses travel along the length of the optical fiber, small imperfections in the fiber reflect a portion of the pulses, generating backscatter.', 'When the fiber is subjected to strain (such as from vibration or acoustic signals propagating through the formation) or temperature changes, the distances between the imperfections change.', 'Consequently, the backscattered light also changes.', 'By monitoring the changes in the backscatter light generated by the fiber in response to interrogating pulses launched by the optical source into the fiber with a detector \n54\n, it is possible to acquire signal therefrom using an acquisition device \n56\n and determine a parameter of the fiber, such as the dynamic strain, or vibration, or the temperature experienced by the fiber.', 'The measured parameter then can be used to derive information about various parameters of interest, such as characteristics of the surrounding earth formation, as already explained above, for instance using the data processing system \n28\n already described in relationship with \nFIG.', '1A\n.', 'The distributed sensing system can be part of or coupled with a processor-based control system (e.g., system \n60\n) used to process the collected data and derive this information.', 'In DAS systems, a narrowband laser is generally used as an optical source \n52\n to generate interrogating pulses of light to launch into the sensing optical fiber.', 'The use of a narrowband laser results in interference between backscatter returned from different parts of the fiber that are occupied by a probe pulse at any one time.', 'This is a form of multi-path interference and gives rise to a speckle-like signal in one dimension (along the axis of the fiber), sometimes referred to as coherent Rayleigh noise or coherent backscatter.', 'The term “phase-OTDR (optical time domain reflectometry)” also is used in this context.', 'The interference modulates both the intensity and the phase of the backscattered light and minute (<<wavelength) changes in the length of a section of fiber are sufficient to radically alter the value of the amplitude and phase.', 'Consequently, the technique can be useful for detecting small changes in strain.', 'Such system is disclosed in particular in U.S. Pat.', 'No. 9,170,149.', 'FIG.', '2A\n depicts an embodiment of a cross-section of a cable \n18\nA.', 'The present embodiment of the cable \n18\nA allows the cable \n18\nA to magnetically attach to the casing \n40\n of the wellbore \n16\n.', 'In doing so, the cable \n18\nA holds the toolstring \n12\n in substantially the same place.', 'In \nFIG.', '2A\n, the cable \n18\nA is designed to function as an electromagnet.', 'The cable \n18\nA includes three different sections, a cable core \n70\n, strength members \n74\n, and magnetic strength members \n72\n.', 'The cable core \n70\n may include fiber optic cables \n81\n and conductors \n85\n.', 'The fiber optic cables \n81\n may include different configurations.', 'For example, the fiber optic cable \n81\n may include an optical core \n78\n and an insulating coating \n80\n followed by a second insulating coating \n76\n.', 'Alternatively, the second insulating coating \n76\n may be replaced by spacers \n84\n followed by an insulating layer \n82\n.', 'While the present embodiment includes three optical cores \n78\n per fiber optic cable \n81\n, it should be appreciated that each fiber optic cable \n81\n may include any suitable number of optical cores, including 1, 2, 3, 4, 5, or 6, or more.', 'The conductors \n85\n include conducting elements \n88\n surrounded by an insulating material \n86\n.', 'Further, the cable core \n70\n may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'The magnetic strength members \n72\n include the strength member \n74\n followed by a layer of insulated strength members/conductors \n75\n (e.g., using bimetallic materials) followed by a layer of durable polymeric electrical insulation \n73\n.', 'In the present embodiment, the magnetic strength members \n72\n are disposed further from the cable core \n70\n than the strength members \n74\n; however, it should be appreciated that the magnetic strength members \n72\n may be disposed closer to the cable core \n70\n than strength members \n74\n.', 'Additionally or alternatively, the magnetic strength members \n72\n may be disposed in a mixed configuration with the strength member \n74\n, with some magnetic strength members \n72\n further from the cable core \n70\n and some closer to the cable core \n70\n than the strength members \n74\n.', 'Each of the strength members \n74\n or a portion of the strength members \n74\n in the armor matrix can be magnetic strength members \n72\n.', 'The quantity, material, size and lay angles of the magnetic strength members \n72\n combined with the electrical current applied can be altered to create an electromagnet of sufficient strength to hold the cable \n18\nA in place against the casing \n40\n of the wellbore \n16\n.', 'Surface and downhole electronics may be configured to turn the magnetic strength members \n72\n on and off.', 'In the “Off” mode, return current is carried by the strength members \n74\n.', 'In the “On” position, current is returned on the magnetic strength members \n72\n and cause the magnetic strength member \n72\n to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', 'A hybrid conductor is a cable that contains multiple strands wrapped around one another, and the strands may be composed of multiple types of metals (e.g., steel, bimetallic, etc.).', 'FIG.', '2B\n depicts a cross-section of an alternative embodiment of the cable \n18\n.', 'A cable \n18\nB is designed to function as an electromagnet, and the cable \n18\nB includes a cable core \n90\n, strength members \n92\n, and magnetic strength members \n94\n.', 'The strength members \n92\n may be magnetic strength members \n94\n.', 'The cable core \n90\n includes fiber optic cables \n81\n, conductors \n85\n, and wires \n98\n.', 'The fiber optic cables \n81\n include the optical cores \n78\n followed by the insulating coating \n80\n.', 'The conductors \n85\n include conducting elements \n88\n surrounded by an insulating material \n86\n.', 'The cable core \n90\n may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'All the strength members \n92\n or a portion of the strength members \n92\n may be replaced with magnetic strength members \n94\n (e.g. bi-metallic) in order to balance the cable \n18\nB safe working load and magnetic anchoring force.', 'The material, quantity, size and lay angles of magnetic strength members \n94\n and the electrical current applied may be configured to create an electromagnet of sufficient strength to hold the cable \n18\nB in place against the casing \n40\n of the wellbore \n16\n.', 'Strength member \n92\n and magnetic strength members \n94\n may be held in place by a filler material \n96\n.', 'The filler material may include insulating elements.', 'Surface and downhole electronics are configured to turn the electromagnet on and off.', 'In the “Off” mode, return current is carried by conductors in the cable core \n90\n.', 'In the “On” position, current is returned on the magnetic strength members \n94\n causing the magnetic strength members \n94\n to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', 'FIG.', '3A\n is a side view of an embodiment of a toolstring \n12\nA attached to the cable \n18\n.', 'The cable \n18\n may be either embodiment depicted in \nFIGS.', '2A and 2B\n.', 'In the present embodiment, the toolstring \n12\nA includes a tractor device \n122\n.', 'The tractor device \n122\n includes arms \n124\n, and each arm \n124\n includes a drive wheel \n126\n.', 'The tractor device \n122\n may include any suitable number of arms \n124\n, including 1, 2, 3, 4, 5, 6, or more.', 'In operation, the cable \n18\n and the toolstring \n12\nA are lowered into the wellbore \n16\n on the cable \n18\n, initially by gravity.', 'The tractor device \n122\n attached to the toolstring \n12\nA is used to continue propelling the toolstring \n12\nA into the hole of the wellbore \n16\n in substantially horizontal (i.e., greater than sixty degrees with respect to the surface of the ground) portions of the wellbore \n16\n.', 'As depicted in \nFIG.', '3B\n, the tractor device \n122\n uses drive wheels \n126\n on arms \n124\n that extend from the toolstring \n12\nA to propel the toolstring \n12\nA down the casing \n40\n of the wellbore \n16\n.', 'FIGS.', '3C and 3D\n are side views of the toolstring \n12\nA with the arms \n124\n of the tractor device \n122\n retracted and the cable \n18\n in the “On” position.', 'Once the cable \n18\n and toolstring \n12\nA are in the desired location, the arms \n124\n on the tractor device \n122\n are withdrawn and the cable \n18\n is turned to the “On” position.', 'The return current is switched to the magnetic strength members \n72\n or \n94\n.', 'Applying electrical current to the magnetic strength members \n72\n or \n94\n allows the cable \n18\n to function as an electromagnet.', 'The strength of the electromagnet may be adjusted by changing amount of current applied or by adjusting the material, quantity, diameters and lay angles of the insulated strength member/conductors.', 'Further, the magnetic strength members \n72\n and \n94\n may be included on a portion of the cable \n18\n.', 'For example, the magnetic strength members \n72\n and \n94\n may be included on a portion of the cable \n18\n near the toolstring \n12\n.\n \nFIG.', '4\n illustrates a flowchart of a method \n130\n for improving the signal to noise ratio.', 'The method \n130\n includes lowering (block \n132\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n130\n includes extending (block \n134\n) the arms \n124\n of the tractor device \n122\n.', 'The method \n130\n includes engaging (block \n136\n) the drive wheels \n126\n of the tractor device \n122\n.', 'The drive wheels \n126\n may be engaged against a surface of the wellbore \n16\n, thereby propelling the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n130\n includes retracting (block \n138\n)', 'the arms \n124\n of the tractor device \n122\n.', 'The method \n130\n includes applying (block \n140\n) current to the magnetic strength members \n72\n or \n94\n of the cable \n18\n.', 'As previously discussed, applying current to the magnetic strength members \n72\n or \n94\n allows the cable \n18\n to function as an electromagnet.', 'The cable \n18\n may then be pulled taught to keep the cable \n18\n steady while the fiber optic cables transmit data.', 'The cable \n18\n being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', 'FIG.', '5A\n is a side view of an embodiment of a toolstring \n12\nB including a timer-activated magnetic device \n170\n with the arms \n164\n of the tractor device \n162\n extended.', 'The timer-activated magnetic device \n170\n is powered by a battery \n174\n and the timer-activated device \n170\n is located in the toolstring \n12', 'B. Before running the toolstring \n12\nB and cable \n18\n into the wellbore \n16\n, the timer \n172\n is set to activate after allowing sufficient time for the cable \n18\n to run into the wellbore \n16\n to the desired location.', 'The cable \n18\n and the toolstring \n12\n are lowered into the wellbore \n16\n on the cable \n18\n, initially by gravity.', 'A tractor device \n162\n attached to the toolstring \n12\n is used to continue running the toolstring \n12\n into the wellbore \n16\n in substantially horizontal portions of the wellbore \n16\n.', 'The current returned through the armor can be used to store energy in the battery \n174\n and extend the magnetic anchoring period.', 'As depicted in \nFIG.', '5B\n, the tractor device \n162\n uses drive wheels \n166\n on arms \n164\n that extend from the toolstring \n12\nB to propel the toolstring \n12\nB down the casing \n40\n of the wellbore \n16\n.\n \nFIGS.', '5C and 5D\n are side views of the toolstring \n12\nB with the arms \n164\n of the tractor device \n162\n retracted.', 'Once the timer \n172\n reaches the end of its time, the timer \n172\n activates a switch \n176\n of the timer-activated magnetic device \n170\n (which will allow time for the toolstring \n12\nB to arrive at the desired downhole location).', 'Activating the switch \n176\n supplies power from the battery \n174\n to the electromagnet \n178\n.', 'Activating the switch \n176\n also causes the drive wheels \n166\n of the tractor device \n162\n to retract into the toolstring \n12\nB.', 'The electromagnet \n178\n holds the toolstring \n12\nB in place against the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n can then be tightened to hold it taut against the casing \n40\n of the wellbore \n16\n, allowing the fiber optics of the cable \n18\n to transmit a strong and consistent signal from downhole formations.', 'FIG.', '5E\n is a side view of the toolstring \n12\nB of \nFIG.', '5D\n, with a second timer-activated magnetic device \n170\n mounted on the cable \n18\n.', 'Multiple timer-activated magnetic devices \n170\n may be located at any suitable location along the length of the cable \n18\n.', 'FIG.', '6\n illustrates a flowchart of a method \n400\n for improving the signal to noise ratio.', 'The method \n400\n includes setting (block \n402\n) the timer \n172\n of the timer-activated magnetic device \n170\n.', 'The method \n400\n includes lowering (block \n404\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n400\n includes extending (block \n406\n) the arms \n164\n of the tractor device \n162\n.', 'The method \n400\n includes engaging (block \n408\n) the drive wheels \n166\n of the tractor device \n162\n.', 'The drive wheels \n166\n may engage a surface of the wellbore \n16\n, thereby driving the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n400\n includes activating (block \n410\n) the switch \n176\n of the timer-activated magnetic device \n170\n.', 'The method \n400\n includes retracting (block \n412\n) the arms \n164\n of the tractor device \n162\n.', 'The method \n400\n includes supplying (block \n414\n) power to the electromagnet \n178\n.', 'In the present embodiment, the power is supplied by a battery \n174\n, but the power may be supplied from other structure, including the cable \n18\n.', 'Supplying power to the electromagnet \n178\n causes the electromagnet \n178\n to attach to the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n may then be pulled taught to keep the cable \n18\n steady while the fiber optic cables transmit data.', 'The cable \n18\n being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', 'FIG.', '7A\n is a cross section of an embodiment of a cable \n18\nC with a magnetic device \n210\nA coupled to the cable \n18\nC.', 'The magnetic device \n210\nA is installed as needed along the cable \n18\nC and is powered by insulated magnetic strength members \n220\n.', 'Insulated magnetic strength members \n220\n include insulation \n222\n (e.g., durable polymetric electrical insulation).', 'A number of strength members \n224\n are replaced by insulated magnetic strength members \n220\n.', 'Insulated magnetic strength members \n220\n can be made out of bimetallic material or any suitable magnetic material.', 'A separate insulated magnetic strength member \n220\n may be used for each magnetic device \n210\nA so that each magnetic device \n210\nA may be operated independently.', 'The magnetic device \n210\nA is installed over the cable \n18\nC in two halves that come together and are held together by a magnetic device casing \n234\n to form a cylinder.', 'The cable \n18\nC includes a cable core \n236\n, strength members \n224\n, and insulated magnetic strength members \n220\n.', 'The cable core \n236\n may include fiber optic cables \n81\n and conductors \n85\n.', 'The fiber optic cables \n81\n may include an optical core \n78\n and an insulating coating \n80\n followed by a second insulating coating \n226\n and an outer insulating layer \n240\n.', 'One side of the cylinder contains an electromagnet \n230\n.', 'The electromagnet \n230\n is a semi-circular-profile iron bar wrapped tightly in insulated copper wire.', 'Non-conductive spacers \n232\n hold the electromagnet \n230\n in place within the gap between the magnetic device casing \n234\n and the cable \n18\nC. One end of an insulated conductive wire \n228\n is attached to the insulated magnetic strength member \n220\n, and the other end is attached to the electromagnet \n230\n.', 'Sufficient slack is allowed in the insulated conductive wires \n228\n to enable the connections to insulated magnetic strength members \n220\n that tend to rotate under longitudinal stress.', 'When current is applied to the insulated magnetic strength members \n220\n, the electromagnet \n230\n is activated and attaches the magnetic device \n210\nA to the casing \n40\n of the wellbore \n16\n.', 'FIG.', '7B\n is a cross section of an embodiment of a cable \n18\nD with a magnetic device \n210\nB coupled to the cable \n18\nD. The cable \n18\nD includes the cable core \n90\n, insulated magnetic strength members \n270\n, strength members \n280\n, and a filler material \n272\n (e.g., an insulating material).', 'The magnetic device \n210\nB is installed along the cable \n18\nD and powered by insulated magnetic strength members \n270\n.', 'A number of strength members \n280\n (e.g., standard armor wire) are replaced by the insulated magnetic strength members \n270\n.', 'The insulated magnetic strength members \n270\n may be made out of bimetallic material or any suitable magnetic material to increase the force of attraction between magnetic device \n210\nB and casing \n40\n of the wellbore \n16\n.', 'The magnetic device \n210\nB is installed over the cable \n18\nD in two halves that come together to form a cylinder.', 'One side contains an electromagnet \n276\n.', 'Spacers \n278\n hold the electromagnet \n276\n in place on the cable \n18\nD. When current is applied to the insulated magnetic strength members \n270\n, the electromagnet \n276\n is activated and attaches the magnetic device \n210\nB to the casing \n40\n of the wellbore \n16\n.', 'Alternatively, the electromagnet \n276\n could be replaced with a permanent magnet.', 'This coupling device is particularly useful in cased hole applications.', 'FIGS.', '8A and 8B\n are a side view of the magnetic device \n210\n.', 'The magnetic device \n210\n may include either the magnetic device \n210\nA or \n210\nB.', 'As shown in \nFIG.', '8B\n, the cable \n18\n may include multiple magnetic devices \n210\n.', 'The magnetic devices \n210\n may be spread along the cable \n18\n at any distance as is desired.', 'FIG.', '8C\n is a side view of the magnetic devices \n210\n attached to the casing \n40\n of the wellbore \n16\n.', 'Once the magnetic device \n210\n has advanced to the desired location in the well, current is applied as described above to activate the electromagnet \n230\n or \n276\n.', 'The magnetic device \n210\n attaches magnetically to the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n is pulled taut and any other magnetic devices \n210\n are also activated to hold the cable \n18\n against the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n can then be tightened to hold it taut against the casing \n40\n of the wellbore \n16\n, thereby allowing the fiber optics of the cable to receive a strong and consistent signal from downhole formations.', 'Pressing the cable \n18\n against the casing \n40\n of the wellbore \n16\n may also press the toolstring \n12\n against the casing \n40\n.', 'FIG.', '9A\n is a side view of an embodiment of a toolstring \n12\nC including an anchoring device \n310\n and a tractor device \n290\n and the arms \n292\n of the tractor device \n290\n are extended.', 'The present embodiment includes two toolstrings \n12\nC, and only one of the toolstrings includes the tractor device \n290\n.', 'The cable \n18\n and the toolstring \n12\nC are lowered into the wellbore \n16\n, initially by gravity.', 'The tractor device \n290\n of the toolstring \n12\nC is used to continue running the toolstring \n12\nC into the wellbore \n16\n in substantially horizontal portions of the well.', 'Once the toolstring \n12\nC is at the desired location, the drive wheels \n294\n of the tractor device \n290\n retract.', 'FIG.', '9B\n is a side view of the toolstring \n12\nC with the anchoring device \n310\n activated.', 'FIG.', '9C\n is a side view of two toolstrings \n12\nC, both with the anchoring device \n310\n activated.', 'The anchoring devices \n310\n in the toolstring \n12\nC are activated by telemetry signals sent through the cable \n18\n from the surface.', 'The telemetry signals cause a switch \n318\n to either engage or disengage.', 'The telemetry signals cause the switch \n318\n to engage once the toolstring \n12\nC has reached the desired location in the wellbore \n16\n.', 'However, while the switch \n318\n is engaged or disengaged by telemetry signals in the present embodiment, it should be noted that the switch \n318\n may be engaged or disengaged by a program designed to engage the switch \n318\n after a sufficient amount of time has passed.', 'The anchoring devices \n310\n have a single side-arm \n312\n that deploys in direction \n314\n to anchor the toolstrings \n12\nC and the cable \n18\n to the casing \n40\n of the wellbore \n16\n when the switch \n318\n is engaged.', 'The side-arm \n312\n of the anchoring device \n310\n swings outward about a hinge \n320\n in the direction \n314\n to wedge the toolstring \n12\nC in place against the casing \n40\n of the wellbore.', 'In the present embodiment, the anchoring device \n310\n is powered by a battery \n316\n; however, it should be appreciated that the anchoring device \n310\n may also be powered by power supplied through the cable \n18\n.', 'FIG.', '10\n illustrates a flowchart of a method \n430\n for improving the signal to noise ratio.', 'The method \n430\n includes lowering (block \n432\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n430\n includes extending (block \n434\n) the arms \n292\n of the tractor device \n290\n.', 'The method \n430\n includes engaging (block \n436\n) the drive wheels \n294\n of the tractor device \n290\n.', 'The drive wheels \n294\n may be engaged against a surface of the wellbore \n16\n, thereby driving the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n430\n includes retracting (block \n438\n) the arms \n292\n of the tractor device \n290\n.', 'Then, the method \n430\n includes detecting (block \n440\n) the position of the toolstring \n12\n using telemetry signals.', 'The method \n430\n includes extending (block \n442\n) the side-arm \n312\n of the anchoring device \n310\n.', 'Extending the side-arm \n312\n wedges the toolstring \n12\n against the casing \n40\n of the wellbore \n16\n.\n \nFIG.', '11A\n is a side view of the toolstring \n12\nC of \nFIG.', '9A\n where the anchoring device \n310\n is activated by a timer device \n322\n. \nFIG.', '11B\n is a side view of the toolstring \n12\nD of \nFIG.', '11A\n in the wellbore \n16\n.', 'The toolstring \n12\nD uses a timer-activated, battery-powered anchoring device \n310\n on the toolstring \n12\nD with a single side-arm \n312\n that deploys to anchor the toolstring \n12\nD in place against the casing \n40\n of the wellbore \n16\n.', 'Before running into the wellbore \n16\n, the timer device \n322\n is set to activate after allowing sufficient time for the cable \n18\n to run into the wellbore \n16\n to the desired location.', 'The cable \n18\n and the toolstring \n12\nD are lowered into the wellbore \n16\n on a cable \n18\n, initially by gravity.', 'A tractor device \n290\n attached to the toolstring \n12\nD is used to continue running the toolstring \n12\nD into the wellbore \n16\n in substantially horizontal portions of the wellbore \n16\n.', 'Once the toolstring \n12\nD is in place in the desired location, the timer device \n322\n activates the switch \n318\n.', 'Activating the switch \n318\n causes the drive wheels \n294\n of the tractor device \n290\n to retract and the anchoring device \n310\n to activate.', 'The side-arm \n312\n of the anchoring device \n310\n swings outward to wedge the toolstring \n12\nD in place against the casing \n40\n of the wellbore \n16\n.', 'FIG.', '12\n illustrates a flowchart of a method \n460\n for improving the signal to noise ratio.', 'The method \n460\n includes setting (block \n462\n) the timer device \n322\n of the anchoring device \n310\n.', 'The method \n460\n includes lowering (block \n464\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n460\n includes extending (block \n466\n) the arms \n292\n of the tractor device \n290\n.', 'The method \n460\n includes engaging (block \n468\n) the drive wheels \n294\n of the tractor device \n290\n.', 'The drive wheels \n294\n may be engaged against a surface of the wellbore \n16\n, thereby driving the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n460\n includes activating (block \n470\n) the switch \n318\n of the timer-activated anchoring device \n310\n.', 'The method \n460\n includes retracting (block \n472\n) the arms \n292\n of the tractor device \n290\n.', 'The method \n460\n includes extending (block \n474\n) the side-arm \n312\n of the anchoring device \n310\n.', 'Extending the side-arm \n312\n wedges the toolstring \n12\n against the casing \n40\n of the wellbore \n16\n.', 'Similarly to what has been described in relationship with \nFIG.', '8A-C\n, the anchoring device may not be disposed in the toolstring but may be disposed around the cable in an device independent from the toolstring having a through cavity for receiving the cable so that the cable extends on each side of the device, exiting the device at both extremities of the cavity.', 'FIGS.', '13A-D\n represent another embodiment of a electromagnetic device according to the disclosure, constituting an alternative of the magnetic device shown on \nFIG.', '8A\n.', 'The electromagnetic device comprises two half-shells \n502\nA, \n502\nB each comprising a body \n504\nA, \n504\nB and a lid \n506\nA, \n506\nB. Each half shell has a recess \n508\n, here a hollow half-cylinder, on an internal surface of the half-shell to receive the cable.', 'The electromagnetic device also comprises an hinge \n510\n for connecting the half-shells together, allowing one half-shell to move relative to the other.', 'The half-shells \n502\nA, \n502\nB are connected by the hinge \n510\n so that in a first open position the half-shells are spread apart allowing access to each of the recesses \n508\n and, in a second position, the recesses \n508\n of both half shells \n502\nA, \n502\nB form a cylindrical cavity to receive the cable \n18\n.', 'Each recess \n508\n extends on the whole length of the half shell along its longitudinal axis so that the cavity is a through cavity when the magnetic device is in the closed position, allowing the cable to extend on each side of the device.', 'The cavity may form a cylinder extending along a linear axis as on \nFIG.', '13A-B\n.', 'In an embodiment shown on \nFIG.', '13C\n, the cavity may form a cylinder extending along a sinusoidal curve to ensure a stronger clamping of the cable, even with the cable having diameter variation, with higher friction generated at locations \n514\n.', 'The body of at least one of the half shell \n502\nA, \n502\nB comprise one or more pockets \n516\n opening on a lateral surface of the body to receive one or more permanent magnet \n518\n so that the magnets are positioned close to the external surface of the magnetic device.', 'In the embodiment shown in \nFIG.', '13A\n each half-shell \n502\nA, \n502\nB includes four permanent magnets so that the permanent magnets are regularly distributed around the entire periphery of the electromagnetic device.', 'The electromagnetic device may therefore be attached on any wall of the borehole, does not need to have its position monitored when installed on the cable and can enable a coupling with the borehole wall even if the cable has twisted in the borehole.', 'To ensure higher magnetic coupling, the permanent magnets \n518\n include a magnetic pole turned toward the external surface of the device and the magnets of each pair of adjacent magnet are configured to have opposite magnetic poles facing the borehole wall \n16\n.', 'The lid \n506\nA, \n506\nB of each half shell is arranged to close the pockets \n516\n, the lid being attached to the corresponding body \n504\nA, \n504\nB via any possible means, in particular a removable connection such as a plurality of screws \n520\n as represented on \nFIG.', '13B\n.', 'In the closed position, the half shells may be attached together via a removable connection such as a screw \n522\n.', 'The electromagnetic device may have an hexagonal axial cross-section when in closed position.', 'In an embodiment shown on \nFIG.', '13D\n, the electromagnetic device comprises on its external surface a wear resistant device.', 'The wear resistant device may comprise a plurality of wear resistant inserts \n524\n, for instance made of diamond, arranged on the external surface of the magnetic device, for instance on each face of the hexagone.', 'The arrangement of the wear resistant inserts may comprise as on \nFIG.', '13D\n wear resistant inserts arranged in parallel so as to form an non-zero angle with the longitudinal axis of the cable (and cavity).', 'Alternatively, other configurations may be possible such as inserts positioned parallel to the longitudinal axis of the cable or not parallel to each other.', 'A wear resistant sleeve may also be arranged around the external surface of the magnetic device as well as wear resistant stripes extending along a face of the body of the magnetic device.', 'Such wear resistant device enable to limit the wear of the magnetic device when the cable moves into the borehole of out of the borehole generating frictional contact between the electromagnetic device and the borehole wall for long distances and enables the electromagnetic devices to have a longer life and to be reused on a higher number of jobs.', 'Many other variants of the embodiment of \nFIG.', '13\n, for instance a device with any number of magnets or any external shape (for instance, cylindrical, octagonal, etc.) are part of the disclosure.', 'FIG.', '14\n represents another device \n600\n for coupling the wireline cable to a borehole wall, either in cased hole or open hole applications.', 'Such device comprises a chassis \n602\n comprising a cavity \n604\n for receiving a wireline cable \n18\n.', 'The cavity \n604\n is a through cavity configured so that its longitudinal axis extends along the longitudinal axis of the chassis \n602\n on the entire length of the sleeve so that the cable can exit the chassis \n602\n at both longitudinal ends.', 'It comprises an opening arranged on an external surface of the chassis \n602\n along a longitudinal axis of the chassis \n602\n.', 'The chassis \n602\n may also comprises elements to maintain the cable within the cavity such as a connection device \n606\n for closing the opening of the cavity by connecting the chassis \n602\n on each side of the opening.', 'Such connection is releasable to enable placement of the cable in the cavity and removal of the cable from the cavity.', 'Gripping members such as restriction compressing the cable may be placed in the cavity, for instance at its longitudinal extremity to avoid that the chassis \n602\n slides along the cable when passing in front of a restriction.', 'The gripping members may comprise a elastomer portion configured to contact the cable.', 'Alternatively, the connecting elements may include the gripping members.', 'In this case, the connecting elements may energize the elastomer portion of the gripping members when torqued onto the body in order to block the cable in the cavity.', 'The device also comprises a tool bias mechanism \n608\n for urging the cavity of the sleeve and therefore the cable against the borehole wall.', 'The tool bias mechanism is therefore arranged on a opposite lateral surface of the chassis \n602\n relative to the cavity \n604\n.', 'The tool bias mechanism in this embodiment is a bow spring, i.e. a curved metal strip having ends coupled to opposite extremities of the chassis \n602\n via respective joints \n610\n.', 'The joints \n610\n can be implemented in any number of ways.', 'In one embodiment, the joints \n610\n allow pivoting and sliding of the bow spring ends relative to chassis \n602\n.', 'In one embodiment, a first joint includes mating pin and hole, and a second joint a includes mating pin and slot.', 'The mating pin and hole at first joint a allow pivoting of the bow spring end relative to the chassis \n602\n.', 'The mating pin and slot at second joint a allow pivoting and sliding of the bow spring end relative to the chassis \n602\n.', 'Thus, the bow spring can expand and contract as the cable is lowered in the borehole.', 'The force of the bow spring is designed to hold the entire chassis \n602\n against a side of the borehole.', 'The coupling device may be instrumented and comprise one or more sensors \n612\n, for instance for determining orientation and/or position of the coupling device \n600\n and the cable \n18\n.', 'This will enable to derive more accurate information relative to the formation as the position of cable, and fiber if any, is known more precisely.', 'The sensor \n612\n may for instance include a geophone, a magnetometer or an accelerometer.', 'The one or more sensors may be MEMS (Micro-Electrico-Mechanical Systems) in order to limit the size of the sensor and therefore of the coupling device.', 'Such coupling device may also comprise a battery in order to operate the sensors autonomously.', 'Such sensor \n612\n may of course be included in any other coupling device, for instance the one described in \nFIG.', '13 or 15\n.', 'Many variants of such coupling device are also part of the current disclosure.', 'For instance, the chassis \n602\n may comprises wear inserts as described in relationship with \nFIG.', '13\n, in particular in the neighbourhood of the opening of the cavity \n604\n, that is likely to contact the borehole wall.', 'The shape of the chassis may also be different from what has been described.', 'In another embodiment shown on \nFIG.', '15\n, also applicable to either cased hole or open hole application, the device \n700\n includes a centralizer \n702\n having a central element \n704\n extending longitudinally and a plurality of centralizing members \n706\n distributed regularly around the central element \n704\n.', 'Each member \n706\n of the centralizer includes a bow spring as disclosed in relationship with \nFIG.', '14\n, having its ends arranged at the extremities of the central element.', 'Such centralizer \n702\n enables the central element to be centered in the borehole \n16\n.', 'It is assumed that having an element centralized in the well indeed enables to have a better coupling in case of wellbore ovality.', 'The device \n700\n also includes on a spacer \n708\n to keep the wireline cable away from the center of the borehole \n16\n.', 'It comprises a plurality of arms \n710\n, each extending at an extremity of the centralizer \n702\n perpendicularly from the central element of the centralizer and having a gripping member \n712\n at the longitudinal end of the arm to grip the cable, including a cavity \n714\n to receive the cable.', 'The spacer \n708\n is configured so that the cable \n18\n extends between the gripping member \n712\n in a direction parallel to the longitudinal axis of the central element.', 'Therefore the longitudinal axis of both arms \n710\n are disposed in a same plane comprising as well the central axis of the centralizer.', 'The cavity \n714\n for receiving the cable has a cylindrical shape and configured to have a longitudinal axis parallel to the central element axis.', 'The gripping member \n712\n grips the cable so that it cannot slide relative to the gripping members.', 'It may be configured to constrain the cable in compression for instance.', 'It may comprise any appropriate design to be able to releasably grip the cable, for instance comprise two portions that are releasably connected to each other and form a cavity having a closed section when connected but opening an access to a portion of the cavity when not connected.', 'The arms \n710\n of the spacer may also comprise, as represented on \nFIG.', '16\n, a first portion \n716\n attached to the centralizer \n702\n and a second portion \n718\n attached to the cavity \n714\n and able to translate along the longitudinal axis of the arm \n710\n relative to the first portion.', 'The arm includes a spring \n720\n energized in the borehole radial direction in order to urge the second portion against the borehole wall and to keep the cable constantly in contact with the borehole wall.', 'Spring stiffness is to be set at max equivalent to the radial stiffness of the centralizer bow springs so that it does not interfere with the centralizing function.', 'Such design enables to vary the distance between the centralizer and the cable when the centralizer passes in a restriction while keeping the cable close to the borehole wall.', 'The disclosure also relates to a method \n800\n explained in relationship with \nFIG.', '17\n.', 'The method includes installing one or more coupling devices on the cable \n18\n, generally at the surface (block \n802\n).', 'The coupling devices are installed so that the cable is received in the through cavity of the coupling device and exits the coupling device at both extremities of the cavity.', 'The coupling devices may for instance be installed between the winch (once the cable is unwound) and the wellbore in particular after the cable has passed on the pulleys that may be seen on \nFIG.', '1A\n.', 'The method then includes lowering the cable (and the coupling devices installed onto it) into the wellbore (block \n804\n).', 'The method also includes holding the cable against a surface of the wellbore (block \n806\n).', 'In some embodiments such operation is triggered by a signal or a timer but with the devices described on \nFIG.', '13-16\n, this operation is performed just as a consequence of including the devices into the borehole as all of them operate through passive forces (magnetic or elastic).', 'When the cable includes a fiber optic cable, the method may also include performing a distributed measurement ie launching interrogating pulses in the fiber optic (block \n808\n), monitoring changes in backscattered light generated by the fiber optic (block \n810\n) and processing the changes to determine one or more characteristic of the formation (block \n812\n).', 'With the foregoing in mind, embodiments presented herein provide devices that are capable of improving the signal to noise ratio of measurements.', 'First, a device may aid in propelling a toolstring to the desired location within the wellbore.', 'Once the toolstring has reached the desired location, another device may be utilized to hold the toolstring steady and in place.', 'Keeping the toolstring steady enables sensors to make more accurate measurements by improving the signal to noise ratio of measurements (e.g., by pressing the toolstring against the wellbore wall and/or by maintaining a taut cable that can transmit fiber optic signals with fewer turns or kinks).', 'With the foregoing in mind, embodiments presented herein provide devices that are capable of improving the signal to noise ratio of measurements.', 'A system according to the disclosure may aid in keeping a cable, in particular having a fiber optic cable, positioned as close as possible to the formation.', 'The coupling of the cable with the borehole wall may be enabled in various ways.', 'It may be beneficial in particular when used in combination with a DAS system sensing one or more parameters of the formation.', 'The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms.', 'For instance, some features disclosed in relationship with one of the coupling device may be arranged on another type of coupling device.', 'For instance, the wear resistant inserts may be arranged and/or sensors may be embarked on any type of coupling.', 'It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.', 'The disclosure generally relates to a system comprising a cable and at least one coupling device installed along the cable having one or more through cavities for receiving the cable, and configured to hold the cable when disposed in the cavity against a surface of the wellbore.', 'Such coupling device may hold the cable against the surface of the wellbore in a cased hole and/or open hole configuration.', 'In an embodiment, the coupling device comprises an electromagnetic device, such as a permanent magnet or electromagnet.', 'In particular, the electromagnetic device may comprise a plurality of magnets distributed within the coupling device.', 'In a particular embodiment, each magnet is disposed so as to have a predetermined magnetic pole facing an external surface of the device, wherein magnets of each pair of adjacent magnets are disposed so that they have opposite magnetic poles facing the external surface.', 'In another embodiment, the at least one coupling device comprises a mechanism for pushing the device away from a first location of the borehole wall and urging the cable against a second opposite location of the borehole wall.', 'The mechanism may comprise an anchoring device having a deployable arm or one or more bow springs.', 'In another embodiment, the coupling device comprises a centralizer, having a central element and a plurality of members disposed around the central element configured to contact the borehole wall and keep the central element at the center of the borehole, and one or more spacers for keeping the cable away from the center element.', 'The one or more members may for instance be bow springs.', 'In such embodiment, the spacer may be configured so that the distance between the cavity and the central element is variable.', 'It may comprise at least an arm having a longitudinal axis perpendicular to the central element having a first portion attached to the central element and a second portion attached to the cavity.', 'The second portion may be able to translate relative to the first portion along the longitudinal axis between a first position closer to the central element and a second position further from the central element.', 'A spring may be energized to urge the second portion in the second position.', 'The cable may be a wireline cable and/or may comprise a fiber optic cable.', 'When the cable includes a fiber optic cable, the system may include an interrogation and acquisition system having an optical source for launching interrogating pulses into the fiber optic cable and a detector monitoring the changes in backscatter light generated by the fiber optic cable in response to the interrogating pulses.', 'In an embodiment, the system comprises a plurality of coupling devices installed around the cable at different locations of the cable.', 'The coupling device may also be configured so that the cable is immobilized in the cavity.', 'It can also be configured to be releasably installed on the cable.', 'In an embodiment, the coupling device includes one or more sensors, in particular an accelerometer and/or a magnetometer and/or a geophone.', 'Such sensors may for instance be powered by a battery installed in the coupling device.', 'Such coupling device may be of any type disclosed above.', 'The disclosure also related to a method for operating a cable in a wellbore.', 'The method includes installing one or more coupling devices along the cable, so that the cable is received in one or more through cavities of the coupling devices, lowering the cable with the installed coupling device into the wellbore, wherein the coupling device holds the cable disposed in the cavity against a surface of the wellbore.', 'In a particular embodiment of the method, when the cable e includes a fiber optic cable, the method may include launching interrogating pulses into the fiber optic cable with an optical source, monitoring changes in backscatter light generated by the fiber optic cable in response to the interrogating pulses with a detector, and processing the changes to determine one or more characteristic of a formation surrounding the wellbore.', 'The disclosure also relates to a system comprising a cable; and a toolstring configured to be coupled to the cable, wherein the toolstring is configured to be placed in a wellbore, wherein the toolstring comprises a sensor configured to obtain measurements within the wellbore.', 'The cable or the toolstring, or both, comprise an electromagnetic device or an anchoring device, or both, configured to selectively hold the toolstring or the cable, or both, against a surface of the wellbore.', 'The electromagnetic device may be coupled directly to the toolstring.', 'The electromagnetic device may powered by a battery.', 'Alternatively, the electromagnetic device is powered by the cable.', 'In an embodiment, the electromagnetic device is activated by a timer device.', 'The toolstring may comprise a tractor device.', 'The system may comprise an anchoring device.', 'The anchoring device may be coupled directly to the toolstring.', 'The anchoring device may be powered by a battery.', 'It may be timer activated and/or activated by a program and/or by telemetry signals.', 'The disclosure also generally relates to a cable system comprising a cable core comprising a fiber optic cable; a plurality of strength members outside of the cable core; and a plurality of magnetic strength members outside of the cable core.', 'The plurality of magnetic strength members may be configured to selectively carry current, and the plurality of magnetic strength members may be configured to become magnetic or activate an electromagnet electrically coupled to the plurality of magnetic strength members when the plurality of magnetic strength members carry current, thereby enabling the cable, when placed into a cased wellbore, to attract to a casing of the wellbore and reduce an attenuation of a signal carried by the fiber optic cable by reducing turns or kinks in the cable.', 'In an embodiment, the plurality of magnetic strength members are insulated.', 'In an embodiment, the electromagnet is held in place by spacers.', 'The disclosure also generally relates to a method for improving a signal to noise ratio of a signal provided over a cable by a toolstring, comprising lowering the cable and the toolstring into a wellbore; extending an at least one arm of a tractor device coupled to the toolstring, wherein the at least one arm comprises a wheel; engaging the wheel of the tractor device against a surface of the wellbore to propel the toolstring and the cable into the wellbore; retracting the at least one arm of the tractor device, wherein retracting the at least one arm disengages the wheel from the surface of the wellbore; and attaching the toolstring to the surface of the wellbore using an electromagnetic device or an anchoring device coupled to the toolstring.', 'The anchoring device may be powered by a battery.', 'The method may comprise setting a timer before lowering and activating a device switch, wherein activating the device switch attaches the toolstring to the surface of the wellbore.', 'In an embodiment, supplying power to the electromagnetic device activates the electromagnetic device, wherein activating the electromagnetic device attaches the toolstring to the surface of the wellbore.', 'In particular, the electromagnetic device may be powered by a battery.', 'The method may also comprise detecting a position of the toolstring with telemetry signals and activating a device switch based on telemetry signals, wherein activating the device switch attaches the toolstring to the surface of the wellbore.'] | ['1.', 'A system, comprising:\na cable, wherein the cable comprises a fiber optic cable; and\nat least one coupling device installed along the cable having one or more through cavities for receiving the cable, and configured to hold the cable when disposed in the cavity against a surface of a wellbore,\nan interrogation and acquisition system having: an optical source for launching interrogating pulses into the fiber optic cable, a detector monitoring the changes in backscatter light generated by the fiber optic cable in response to the interrogating pulses.', '2.', 'The system of claim 1, wherein the at least one coupling device comprising an electromagnetic device.', '3.', 'The system of claim 2, wherein the electromagnetic device includes one or more magnets.', '4.', 'The system of claim 3, wherein the electromagnetic device comprises a plurality of magnets distributed within the coupling device, wherein each magnet is disposed so as to have a predetermined magnetic pole facing an external surface of the device, wherein magnets of each pair of adjacent magnets are disposed so that they have opposite magnetic poles facing the external surface.', '5.', 'The system of claim 1, wherein the at least one coupling device comprises a mechanism for pushing the device away from a first location of the borehole wall and urging the cable against a second opposite location of the borehole wall.', '6.', 'The system of claim 5, wherein the mechanism comprises an anchoring device having a deployable arm.\n\n\n\n\n\n\n7.', 'The system of claim 5, wherein the mechanism comprises one or more bow springs.', '8.', 'The system of claim 1, wherein the at least one coupling device comprises a centralizer, having a central element and a plurality of members disposed around the central element configured to contact the borehole wall and keep the central element at the center of the borehole, and one or more spacers for keeping the cable away from the center element.', '9.', 'The system of claim 1, wherein the at least one coupling device comprises one or more wear resistant element on its external surface.', '10.', 'The system of claim 1, having an acoustic source for generating an acoustic wave in a formation surrounding the borehole and a processing system for deriving one or more characteristic of the formation based on the monitored changes.', '11.', 'The system of claim 1, comprising a plurality of coupling devices installed around the cable at different locations of the cable.', '12.', 'The system of claim 1, wherein the coupling device is configured so that the cable is immobilized in the cavity.', '13.', 'The system of claim 1, wherein the coupling device is configured to be releasably installed on the cable.', '14.', 'The system of claim 1, wherein the coupling device includes one or more sensors.', '15.', 'The system of claim 14, wherein the one or more sensors include at least one of an accelerometer, a magnetometer or a geophone.\n\n\n\n\n\n\n16.', 'A method for operating a cable in a wellbore, wherein the cable includes a fiber optic cable, including:\ninstalling one or more coupling devices along the cable, so that the cable is received in one or more through cavities of the coupling devices,\nlowering the cable with the installed coupling device into the wellbore, wherein the coupling device holds the cable disposed in the cavity against a surface of the wellbore,\nlaunching interrogating pulses into the fiber optic cable with an optical source\nmonitoring changes in backscatter light generated by the fiber optic cable in response to the interrogating pulses with a detector,\nprocessing the changes to determine one or more characteristic of a formation surrounding the wellbore.', '17.', 'A system, comprising:\na cable; and\nat least one coupling device installed along the cable having one or more through cavities for receiving the cable, and configured to hold the cable when disposed in the cavity against a surface of a wellbore, wherein the at least one coupling device comprises a centralizer, having a central element and a plurality of members disposed around the central element configured to contact the borehole wall and keep the central element at the center of the borehole, and one or more spacers for keeping the cable away from the center element.\n\n\n\n\n\n\n18.', 'The system of claim 17, wherein the one or more members are bow springs.', '19.', 'The system of claim 17, wherein the spacer is configured so that the distance between the cavity and the central element is variable.', '20.', 'The system of claim 19, wherein the spacer comprises at least an arm having a longitudinal axis perpendicular to the central element having a first portion attached to the central element and a second portion attached to the cavity, wherein the second portion is able to translate relative to the first portion along the longitudinal axis between a first position closer to the central element and a second position further from the central element and wherein a spring is energized to urge the second portion in the second position.'] | ['FIG.', '1A is a schematic diagram of a wireline system that includes a toolstring to detect properties of a wellbore or geological formation adjacent to the toolstring, in accordance with an aspect of the present disclosure;; FIG.', '1B is a schematic diagram of a portion of a wireline system according to an embodiment of the disclosure.', '; FIGS.', '2A and 2B are cross sections of different embodiments of a cable that can be magnetized, in accordance with an aspect of the present disclosure;; FIG.', '3A is a side view of an embodiment of a toolstring with the arms of a tractor device extended, in accordance with an aspect of the present disclosure;; FIG.', '3B is a side view of the toolstring of FIG.', '3A in a wellbore, in accordance with an aspect of the present disclosure;; FIG.', '3C is a side view of the toolstring of FIG.', '3A with the cable magnetized and the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;; FIG.', '3D is a side view of the toolstring of FIG.', '3C in a wellbore and with the cable magnetized and held to the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG. 4 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '5A is a side view of an embodiment of a toolstring including a timer-activated magnetic device with the arms of the tractor device extended, in accordance with an aspect of the present disclosure;; FIG.', '5B is a side view of the toolstring of FIG.', '5A in a wellbore, in accordance with an aspect of the present disclosure;; FIG.', '5C is a side view of the toolstring of FIG.', '5A with the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;; FIG.', '5D is a side view of the toolstring of FIG.', '5C in a wellbore and with the selectively magnetic device holding the toolstring to the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '5E is a side view of the toolstring of FIG.', '5D, with an additional toolstring mounted on the cable, in accordance with an aspect of the present disclosure;; FIG.', '6 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure;; FIGS.', '7A-7B are cross sections of different embodiments of the cable with a magnetic device coupled to the cable, in accordance with an aspect of the present disclosure;; FIG.', '8A is a side view of an embodiment of the magnetic device, in accordance with an aspect of the present disclosure;; FIG.', '8B is a side view of multiple magnetic devices of FIG.', '8A in a wellbore, in accordance with an aspect of the present disclosure;; FIG.', '8C is a side view of the magnetic devices of FIG.', '8B attached to the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '9A is a side view of an embodiment of the toolstring including an anchoring device and a tractor device and the arms of the tractor device are extended, in accordance with an aspect of the present disclosure;; FIG.', '9B is a side view of the toolstring of FIG.', '9A and the side-arm of the anchoring device extended, in accordance with an aspect of the present disclosure;; FIG.', '9C is a side view of multiple toolstring of FIG.', '9B with the arms of the tractor devices retracted and the side-arms of the anchoring devices extended and holding the toolstrings against the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '10 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using an anchoring device, in accordance with an aspect of the present disclosure;; FIG.', '11A is a side view of the toolstring of FIG.', '9A where the anchoring device is activated by a timer device, in accordance with an aspect of the present disclosure;; FIG.', '11B is a side view of the toolstring of FIG.', '11B in a wellbore and with the arms of the tractor device extended, in accordance with an aspect of the present disclosure; and; FIG.', '12 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure.; FIG.', '13A is a perspective view of a coupling device according to an embodiment of the disclosure,; FIG.', '13B is an exploded view of the coupling device of FIG.', '13A; FIG.', '13C is a cross-section of a variant of the coupling device of FIG.', '13A; FIG.', '13D is a perspective view of another variant of the coupling device of FIG.', '13A; FIG.', '14 is a view of a system according to an embodiment of the disclosure; FIG.', '15 is a view of a system according to an embodiment of the disclosure; FIG.', '16 is a cross-section of a portion of the system of FIG.', '15.; FIG.', '17 is a flowchart of a method according to an embodiment of the disclosure.', '; FIG.', '2A depicts an embodiment of a cross-section of a cable 18A.', 'The present embodiment of the cable 18A allows the cable 18A to magnetically attach to the casing 40 of the wellbore 16.', 'In doing so, the cable 18A holds the toolstring 12 in substantially the same place.', 'In FIG.', '2A, the cable 18A is designed to function as an electromagnet.', 'The cable 18A includes three different sections, a cable core 70, strength members 74, and magnetic strength members 72.', 'The cable core 70 may include fiber optic cables 81 and conductors 85.', 'The fiber optic cables 81 may include different configurations.', 'For example, the fiber optic cable 81 may include an optical core 78 and an insulating coating 80 followed by a second insulating coating 76.', 'Alternatively, the second insulating coating 76 may be replaced by spacers 84 followed by an insulating layer 82.', 'While the present embodiment includes three optical cores 78 per fiber optic cable 81, it should be appreciated that each fiber optic cable 81 may include any suitable number of optical cores, including 1, 2, 3, 4, 5, or 6, or more.', 'The conductors 85 include conducting elements 88 surrounded by an insulating material 86.', 'Further, the cable core 70 may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'The magnetic strength members 72 include the strength member 74 followed by a layer of insulated strength members/conductors 75 (e.g., using bimetallic materials) followed by a layer of durable polymeric electrical insulation 73.', 'In the present embodiment, the magnetic strength members 72 are disposed further from the cable core 70 than the strength members 74; however, it should be appreciated that the magnetic strength members 72 may be disposed closer to the cable core 70 than strength members 74.', 'Additionally or alternatively, the magnetic strength members 72 may be disposed in a mixed configuration with the strength member 74, with some magnetic strength members 72 further from the cable core 70 and some closer to the cable core 70 than the strength members 74.', 'Each of the strength members 74 or a portion of the strength members 74 in the armor matrix can be magnetic strength members 72.', 'The quantity, material, size and lay angles of the magnetic strength members 72 combined with the electrical current applied can be altered to create an electromagnet of sufficient strength to hold the cable 18A in place against the casing 40 of the wellbore 16.', 'Surface and downhole electronics may be configured to turn the magnetic strength members 72 on and off.', 'In the “Off” mode, return current is carried by the strength members 74.', 'In the “On” position, current is returned on the magnetic strength members 72 and cause the magnetic strength member 72 to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', 'A hybrid conductor is a cable that contains multiple strands wrapped around one another, and the strands may be composed of multiple types of metals (e.g., steel, bimetallic, etc.).', '; FIG.', '2B depicts a cross-section of an alternative embodiment of the cable 18.', 'A cable 18B is designed to function as an electromagnet, and the cable 18B includes a cable core 90, strength members 92, and magnetic strength members 94.', 'The strength members 92 may be magnetic strength members 94.', 'The cable core 90 includes fiber optic cables 81, conductors 85, and wires 98.', 'The fiber optic cables 81 include the optical cores 78 followed by the insulating coating 80.', 'The conductors 85 include conducting elements 88 surrounded by an insulating material 86.', 'The cable core 90 may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'All the strength members 92 or a portion of the strength members 92 may be replaced with magnetic strength members 94 (e.g. bi-metallic) in order to balance the cable 18B safe working load and magnetic anchoring force.', 'The material, quantity, size and lay angles of magnetic strength members 94 and the electrical current applied may be configured to create an electromagnet of sufficient strength to hold the cable 18B in place against the casing 40 of the wellbore 16.', 'Strength member 92 and magnetic strength members 94 may be held in place by a filler material 96.', 'The filler material may include insulating elements.', 'Surface and downhole electronics are configured to turn the electromagnet on and off.', 'In the “Off” mode, return current is carried by conductors in the cable core 90.', 'In the “On” position, current is returned on the magnetic strength members 94 causing the magnetic strength members 94 to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', ';', 'FIG.', '3A is a side view of an embodiment of a toolstring 12A attached to the cable 18.', 'The cable 18 may be either embodiment depicted in FIGS.', '2A and 2B. In the present embodiment, the toolstring 12A includes a tractor device 122.', 'The tractor device 122 includes arms 124, and each arm 124 includes a drive wheel 126.', 'The tractor device 122 may include any suitable number of arms 124, including 1, 2, 3, 4, 5, 6, or more.', 'In operation, the cable 18 and the toolstring 12A are lowered into the wellbore 16 on the cable 18, initially by gravity.', 'The tractor device 122 attached to the toolstring 12A is used to continue propelling the toolstring 12A into the hole of the wellbore 16 in substantially horizontal (i.e., greater than sixty degrees with respect to the surface of the ground) portions of the wellbore 16.', 'As depicted in FIG.', '3B, the tractor device 122 uses drive wheels 126 on arms 124 that extend from the toolstring 12A to propel the toolstring 12A down the casing 40 of the wellbore 16.; FIGS.', '3C and 3D are side views of the toolstring 12A with the arms 124 of the tractor device 122 retracted and the cable 18 in the “On” position.', 'Once the cable 18 and toolstring 12A are in the desired location, the arms 124 on the tractor device 122 are withdrawn and the cable 18 is turned to the “On” position.', 'The return current is switched to the magnetic strength members 72 or 94.', 'Applying electrical current to the magnetic strength members 72 or 94 allows the cable 18 to function as an electromagnet.', 'The strength of the electromagnet may be adjusted by changing amount of current applied or by adjusting the material, quantity, diameters and lay angles of the insulated strength member/conductors.', 'Further, the magnetic strength members 72 and 94 may be included on a portion of the cable 18.', 'For example, the magnetic strength members 72 and 94 may be included on a portion of the cable 18 near the toolstring 12.; FIG.', '4 illustrates a flowchart of a method 130 for improving the signal to noise ratio.', 'The method 130 includes lowering (block 132) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 130 includes extending (block 134) the arms 124 of the tractor device 122.', 'The method 130 includes engaging (block 136) the drive wheels 126 of the tractor device 122.', 'The drive wheels 126 may be engaged against a surface of the wellbore 16, thereby propelling the toolstring 12 deeper into the wellbore 16.', 'The method 130 includes retracting (block 138) the arms 124 of the tractor device 122.', 'The method 130 includes applying (block 140) current to the magnetic strength members 72 or 94 of the cable 18.', 'As previously discussed, applying current to the magnetic strength members 72 or 94 allows the cable 18 to function as an electromagnet.', 'The cable 18 may then be pulled taught to keep the cable 18 steady while the fiber optic cables transmit data.', 'The cable 18 being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', '; FIG.', '5A is a side view of an embodiment of a toolstring 12B including a timer-activated magnetic device 170 with the arms 164 of the tractor device 162 extended.', 'The timer-activated magnetic device 170 is powered by a battery 174 and the timer-activated device 170 is located in the toolstring 12B. Before running the toolstring 12B and cable 18 into the wellbore 16, the timer 172 is set to activate after allowing sufficient time for the cable 18 to run into the wellbore 16 to the desired location.', 'The cable 18 and the toolstring 12 are lowered into the wellbore 16 on the cable 18, initially by gravity.', 'A tractor device 162 attached to the toolstring 12 is used to continue running the toolstring 12 into the wellbore 16 in substantially horizontal portions of the wellbore 16.', 'The current returned through the armor can be used to store energy in the battery 174 and extend the magnetic anchoring period.', 'As depicted in FIG.', '5B, the tractor device 162 uses drive wheels 166 on arms 164 that extend from the toolstring 12B to propel the toolstring 12B down the casing 40 of the wellbore 16.; FIGS.', '5C and 5D are side views of the toolstring 12B with the arms 164 of the tractor device 162 retracted.', 'Once the timer 172 reaches the end of its time, the timer 172 activates a switch 176 of the timer-activated magnetic device 170 (which will allow time for the toolstring 12B to arrive at the desired downhole location).', 'Activating the switch 176 supplies power from the battery 174 to the electromagnet 178.', 'Activating the switch 176 also causes the drive wheels 166 of the tractor device 162 to retract into the toolstring', '12B.', 'The electromagnet 178 holds the toolstring 12B in place against the casing 40 of the wellbore 16.', 'The cable 18 can then be tightened to hold it taut against the casing 40 of the wellbore 16, allowing the fiber optics of the cable 18 to transmit a strong and consistent signal from downhole formations.', 'FIG.', '5E is a side view of the toolstring 12B of FIG.', '5D, with a second timer-activated magnetic device 170 mounted on the cable 18.', 'Multiple timer-activated magnetic devices 170 may be located at any suitable location along the length of the cable 18.; FIG.', '6 illustrates a flowchart of a method 400 for improving the signal to noise ratio.', 'The method 400 includes setting (block 402) the timer 172 of the timer-activated magnetic device 170.', 'The method 400 includes lowering (block 404) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 400 includes extending (block 406) the arms 164 of the tractor device 162.', 'The method 400 includes engaging (block 408) the drive wheels 166 of the tractor device 162.', 'The drive wheels 166 may engage a surface of the wellbore 16, thereby driving the toolstring 12 deeper into the wellbore 16.', 'The method 400 includes activating (block 410) the switch 176 of the timer-activated magnetic device 170.', 'The method 400 includes retracting (block 412) the arms 164 of the tractor device 162.', 'The method 400 includes supplying (block 414) power to the electromagnet 178.', 'In the present embodiment, the power is supplied by a battery 174, but the power may be supplied from other structure, including the cable 18.', 'Supplying power to the electromagnet 178 causes the electromagnet 178 to attach to the casing 40 of the wellbore 16.', 'The cable 18 may then be pulled taught to keep the cable 18 steady while the fiber optic cables transmit data.', 'The cable 18 being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', ';', 'FIG.', '7A is a cross section of an embodiment of a cable 18C with a magnetic device 210A coupled to the cable 18C.', 'The magnetic device 210A is installed as needed along the cable 18C and is powered by insulated magnetic strength members 220.', 'Insulated magnetic strength members 220 include insulation 222 (e.g., durable polymetric electrical insulation).', 'A number of strength members 224 are replaced by insulated magnetic strength members 220.', 'Insulated magnetic strength members 220 can be made out of bimetallic material or any suitable magnetic material.', 'A separate insulated magnetic strength member 220 may be used for each magnetic device 210A so that each magnetic device 210A may be operated independently.', 'The magnetic device 210A is installed over the cable 18C in two halves that come together and are held together by a magnetic device casing 234 to form a cylinder.', 'The cable 18C includes a cable core 236, strength members 224, and insulated magnetic strength members 220.', 'The cable core 236 may include fiber optic cables 81 and conductors 85.', 'The fiber optic cables 81 may include an optical core 78 and an insulating coating 80 followed by a second insulating coating 226 and an outer insulating layer 240.', 'One side of the cylinder contains an electromagnet 230.', 'The electromagnet 230 is a semi-circular-profile iron bar wrapped tightly in insulated copper wire.', 'Non-conductive spacers 232 hold the electromagnet 230 in place within the gap between the magnetic device casing 234 and the cable 18C. One end of an insulated conductive wire 228 is attached to the insulated magnetic strength member 220, and the other end is attached to the electromagnet 230.', 'Sufficient slack is allowed in the insulated conductive wires 228 to enable the connections to insulated magnetic strength members 220 that tend to rotate under longitudinal stress.', 'When current is applied to the insulated magnetic strength members 220, the electromagnet 230 is activated and attaches the magnetic device 210A to the casing 40 of the wellbore 16.; FIG.', '7B is a cross section of an embodiment of a cable 18D with a magnetic device 210B coupled to the cable 18D.', 'The cable 18D includes the cable core 90, insulated magnetic strength members 270, strength members 280, and a filler material 272 (e.g., an insulating material).', 'The magnetic device 210B is installed along the cable 18D and powered by insulated magnetic strength members 270.', 'A number of strength members 280 (e.g., standard armor wire) are replaced by the insulated magnetic strength members 270.', 'The insulated magnetic strength members 270 may be made out of bimetallic material or any suitable magnetic material to increase the force of attraction between magnetic device 210B and casing 40 of the wellbore 16.', 'The magnetic device 210B is installed over the cable 18D in two halves that come together to form a cylinder.', 'One side contains an electromagnet 276.', 'Spacers 278 hold the electromagnet 276 in place on the cable 18D.', 'When current is applied to the insulated magnetic strength members 270, the electromagnet 276 is activated and attaches the magnetic device 210B to the casing 40 of the wellbore 16.', 'Alternatively, the electromagnet 276 could be replaced with a permanent magnet.', 'This coupling device is particularly useful in cased hole applications.; FIGS.', '8A and 8B are a side view of the magnetic device 210.', 'The magnetic device 210 may include either the magnetic device 210A or 210B. As shown in FIG.', '8B, the cable 18 may include multiple magnetic devices 210.', 'The magnetic devices 210 may be spread along the cable 18 at any distance as is desired.', 'FIG.', '8C is a side view of the magnetic devices 210 attached to the casing 40 of the wellbore 16.', 'Once the magnetic device 210 has advanced to the desired location in the well, current is applied as described above to activate the electromagnet 230 or 276.', 'The magnetic device 210 attaches magnetically to the casing 40 of the wellbore 16.', 'The cable 18 is pulled taut and any other magnetic devices 210 are also activated to hold the cable 18 against the casing 40 of the wellbore 16.', 'The cable 18 can then be tightened to hold it taut against the casing 40 of the wellbore 16, thereby allowing the fiber optics of the cable to receive a strong and consistent signal from downhole formations.', 'Pressing the cable 18 against the casing 40 of the wellbore 16 may also press the toolstring 12 against the casing 40.; FIG.', '9A is a side view of an embodiment of a toolstring 12C including an anchoring device 310 and a tractor device 290 and the arms 292 of the tractor device 290 are extended.', 'The present embodiment includes two toolstrings 12C, and only one of the toolstrings includes the tractor device 290.', 'The cable 18 and the toolstring 12C are lowered into the wellbore 16, initially by gravity.', 'The tractor device 290 of the toolstring 12C is used to continue running the toolstring 12C into the wellbore 16 in substantially horizontal portions of the well.', 'Once the toolstring 12C is at the desired location, the drive wheels 294 of the tractor device 290 retract.; FIG.', '9B is a side view of the toolstring 12C with the anchoring device 310 activated.', 'FIG.', '9C is a side view of two toolstrings 12C, both with the anchoring device 310 activated.', 'The anchoring devices 310 in the toolstring 12C are activated by telemetry signals sent through the cable 18 from the surface.', 'The telemetry signals cause a switch 318 to either engage or disengage.', 'The telemetry signals cause the switch 318 to engage once the toolstring 12C has reached the desired location in the wellbore 16.', 'However, while the switch 318 is engaged or disengaged by telemetry signals in the present embodiment, it should be noted that the switch 318 may be engaged or disengaged by a program designed to engage the switch 318 after a sufficient amount of time has passed.', 'The anchoring devices 310 have a single side-arm 312 that deploys in direction 314 to anchor the toolstrings 12C and the cable 18 to the casing 40 of the wellbore 16 when the switch 318 is engaged.', 'The side-arm 312 of the anchoring device 310 swings outward about a hinge 320 in the direction 314 to wedge the toolstring 12C in place against the casing 40 of the wellbore.', 'In the present embodiment, the anchoring device 310 is powered by a battery 316; however, it should be appreciated that the anchoring device 310 may also be powered by power supplied through the cable 18.; FIG.', '10 illustrates a flowchart of a method 430 for improving the signal to noise ratio.', 'The method 430 includes lowering (block 432) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 430 includes extending (block 434) the arms 292 of the tractor device 290.', 'The method 430 includes engaging (block 436) the drive wheels 294 of the tractor device 290.', 'The drive wheels 294 may be engaged against a surface of the wellbore 16, thereby driving the toolstring 12 deeper into the wellbore 16.', 'The method 430 includes retracting (block 438) the arms 292 of the tractor device 290.', 'Then, the method 430 includes detecting (block 440) the position of the toolstring 12 using telemetry signals.', 'The method 430 includes extending (block 442) the side-arm 312 of the anchoring device 310.', 'Extending the side-arm 312 wedges the toolstring 12 against the casing 40 of the wellbore 16.; FIG.', '11A is a side view of the toolstring 12C of FIG.', '9A where the anchoring device 310 is activated by a timer device 322.', 'FIG.', '11B is a side view of the toolstring 12D of FIG.', '11A in the wellbore 16.', 'The toolstring 12D uses a timer-activated, battery-powered anchoring device 310 on the toolstring 12D with a single side-arm 312 that deploys to anchor the toolstring 12D in place against the casing 40 of the wellbore 16.', 'Before running into the wellbore 16, the timer device 322 is set to activate after allowing sufficient time for the cable 18 to run into the wellbore 16 to the desired location.', 'The cable 18 and the toolstring 12D are lowered into the wellbore 16 on a cable 18, initially by gravity.', 'A tractor device 290 attached to the toolstring 12D is used to continue running the toolstring 12D into the wellbore 16 in substantially horizontal portions of the wellbore 16.', 'Once the toolstring 12D is in place in the desired location, the timer device 322 activates the switch 318.', 'Activating the switch 318 causes the drive wheels 294 of the tractor device 290 to retract and the anchoring device 310 to activate.', 'The side-arm 312 of the anchoring device 310 swings outward to wedge the toolstring 12D in place against the casing 40 of the wellbore 16.; FIG.', '12 illustrates a flowchart of a method 460 for improving the signal to noise ratio.', 'The method 460 includes setting (block 462) the timer device 322 of the anchoring device 310.', 'The method 460 includes lowering (block 464) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 460 includes extending (block 466) the arms 292 of the tractor device 290.', 'The method 460 includes engaging (block 468) the drive wheels 294 of the tractor device 290.', 'The drive wheels 294 may be engaged against a surface of the wellbore 16, thereby driving the toolstring 12 deeper into the wellbore 16.', 'The method 460 includes activating (block 470) the switch 318 of the timer-activated anchoring device 310.', 'The method 460 includes retracting (block 472) the arms 292 of the tractor device 290.', 'The method 460 includes extending (block 474) the side-arm 312 of the anchoring device 310.', 'Extending the side-arm 312 wedges the toolstring 12 against the casing 40 of the wellbore 16.; FIGS.', '13A-D represent another embodiment of a electromagnetic device according to the disclosure, constituting an alternative of the magnetic device shown on FIG.', '8A. The electromagnetic device comprises two half-shells 502A, 502B each comprising a body 504A, 504B and a lid 506A,', '506B. Each half shell has a recess 508, here a hollow half-cylinder, on an internal surface of the half-shell to receive the cable.', 'The electromagnetic device also comprises an hinge 510 for connecting the half-shells together, allowing one half-shell to move relative to the other.', 'The half-shells 502A, 502B are connected by the hinge 510 so that in a first open position the half-shells are spread apart allowing access to each of the recesses 508 and, in a second position, the recesses 508 of both half shells 502A, 502B form a cylindrical cavity to receive the cable 18.', 'Each recess 508 extends on the whole length of the half shell along its longitudinal axis so that the cavity is a through cavity when the magnetic device is in the closed position, allowing the cable to extend on each side of the device.', 'The cavity may form a cylinder extending along a linear axis as on FIG.', '13A-B. In an embodiment shown on FIG.', '13C, the cavity may form a cylinder extending along a sinusoidal curve to ensure a stronger clamping of the cable, even with the cable having diameter variation, with higher friction generated at locations 514.', 'The body of at least one of the half shell 502A, 502B comprise one or more pockets 516 opening on a lateral surface of the body to receive one or more permanent magnet 518 so that the magnets are positioned close to the external surface of the magnetic device.', 'In the embodiment shown in FIG.', '13A each half-shell 502A, 502B includes four permanent magnets so that the permanent magnets are regularly distributed around the entire periphery of the electromagnetic device.', 'The electromagnetic device may therefore be attached on any wall of the borehole, does not need to have its position monitored when installed on the cable and can enable a coupling with the borehole wall even if the cable has twisted in the borehole.', 'To ensure higher magnetic coupling, the permanent magnets 518 include a magnetic pole turned toward the external surface of the device and the magnets of each pair of adjacent magnet are configured to have opposite magnetic poles facing the borehole wall 16.', 'The lid 506A, 506B of each half shell is arranged to close the pockets 516, the lid being attached to the corresponding body 504A, 504B via any possible means, in particular a removable connection such as a plurality of screws 520 as represented on FIG.', '13B.', 'In the closed position, the half shells may be attached together via a removable connection such as a screw 522.', 'The electromagnetic device may have an hexagonal axial cross-section when in closed position.; FIG.', '14 represents another device 600 for coupling the wireline cable to a borehole wall, either in cased hole or open hole applications.', 'Such device comprises a chassis 602 comprising a cavity 604 for receiving a wireline cable 18.', 'The cavity 604 is a through cavity configured so that its longitudinal axis extends along the longitudinal axis of the chassis 602 on the entire length of the sleeve so that the cable can exit the chassis 602 at both longitudinal ends.', 'It comprises an opening arranged on an external surface of the chassis 602 along a longitudinal axis of the chassis 602.', 'The chassis 602 may also comprises elements to maintain the cable within the cavity such as a connection device 606 for closing the opening of the cavity by connecting the chassis 602 on each side of the opening.', 'Such connection is releasable to enable placement of the cable in the cavity and removal of the cable from the cavity.', 'Gripping members such as restriction compressing the cable may be placed in the cavity, for instance at its longitudinal extremity to avoid that the chassis 602 slides along the cable when passing in front of a restriction.', 'The gripping members may comprise a elastomer portion configured to contact the cable.', 'Alternatively, the connecting elements may include the gripping members.', 'In this case, the connecting elements may energize the elastomer portion of the gripping members when torqued onto the body in order to block the cable in the cavity.'] |
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US11091997 | Estimating nuclear magnetic resonance measurement quality | Oct 18, 2016 | Shin Utsuzawa, Wei Chen, Martin D. Hurlimann, Antoine Marcel Benard, Vasileios Varveropoulos | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in International Patent application PCT/US2016/057440 dated Jan. 26, 2017. 17 pages.; Carr et al., Effects of Diffusion on Free Precession in Nuclear Magnetic Resonance Experiments, Physical Review, vol. 94, No. 3, pp. 630-638, 1954.; Hahn, E. L., Detection of Sea-Water Motion by Nuclear Precession, Journal of Geophysical Research, vol. 65, No. 2, pp. 776-777, 1960.; Benson et al., Profile Amplitude Modulation in Stray-Field Magnetic-Resonance Imaging, Journal of Magnetic Resonance, Series A, vol. 112, pp. 17-23, 1995.; International Preliminary Report on Patentability issued in International Patent application PCT/US2016/057440, dated May 15, 2018, 11 pages.; First Office Action and Search Report issued in Chinese Patent Application 201680068875.2 dated Apr. 16, 2021.; Heider, R., Design and Implementation of a New Magnetic Resonance Tool for the While Drilling Environment, SPWLA 44th Annual Logging Symposium, pp. 1-10, 2003.; Lu et al, Brief Introduction of Key Techniques in NMR Logging While Drilling Tool, Well Logging Technology, vol. 31 No. 2, pp. 107-111, Apr. 2007, contains English Abstract. | 6246236; June 12, 2001; Poitzsch et al.; 6437564; August 20, 2002; Itskovich et al.; 6459263; October 1, 2002; Hawkes et al.; 6492809; December 10, 2002; Speier et al.; 6566874; May 20, 2003; Speier et al.; 6975112; December 13, 2005; Morys et al.; 7268547; September 11, 2007; Kruspe et al.; 20010045892; November 29, 2001; Thomas et al.; 20040251898; December 16, 2004; Morys et al.; 20070222443; September 27, 2007; Blanz; 20080021654; January 24, 2008; Gillen et al.; 20100119138; May 13, 2010; Hulbert; 20160272506; September 22, 2016; Jensen | WO2015031149; March 2015; WO; 2015070874; May 2015; WO; 2015088543; June 2015; WO; WO2016065962; May 2016; WO | ['A system for drilling a borehole is disclosed.', 'The system may include drill string having a bottom hole assembly a nuclear magnetic resonance tool within the bottom hole assembly, and a surface control system including a nuclear magnetic resonance measurement quality map.', 'The control system may be configured to drill a borehole at a first set of drilling parameters and to receive motion properties from the nuclear magnetic resonance tool and adjust the drilling of the bore hole at a second set of drilling parameters.', 'The surface control system may be further configured to adjust the drilling of the bore hole based on the motion properties from the nuclear magnetic resonance tool and the nuclear magnetic resonance measurement quality map.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application claims the benefit of priority of U.S. Provisional Application No. 62/254,052 filed Nov. 11, 2015, which is incorporated herein by reference in its entirety.', 'TECHNICAL FIELD\n \nSome embodiments described herein generally relate to nuclear magnetic resonance measurement and, more specifically, to techniques for estimating nuclear magnetic resonance measurement quality under motion.', 'BACKGROUND', 'In the drilling of oil and gas wells, logging-while-drilling tools may be used to measure the properties of the wellbore and the surrounding formation.', 'One such logging-while-drilling tool is a nuclear magnetic resonance tool.', 'A nuclear magnetic resonance well logging tool may be used to measure the properties of nuclear spins in the formation, such as the longitudinal (or spin-lattice) relaxation time (referred to as T\n1\n), transverse (or spin-spin) relaxation time (referred to as T\n2\n), and diffusion coefficient (D).', 'Knowledge of these nuclear magnetic resonance (NMR) measurement properties can help aid in determination of basic formation properties such as permeability and porosity, as well as the fluid properties such as fluid type and viscosity.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'A system for drilling a borehole is disclosed.', 'The system may include a drill string having a bottom hole assembly, a nuclear magnetic resonance tool within the bottom hole assembly, and a surface control system including a nuclear magnetic resonance measurement quality map.', 'The control system may be configured to drill a borehole at a first set of drilling parameters and to receive motion properties from the nuclear magnetic resonance tool and adjust the drilling of the bore hole at a second set of drilling parameters.', 'The surface control system may be further configured to adjust the drilling of the bore hole based on the motion properties from the nuclear magnetic resonance tool and the nuclear magnetic resonance measurement quality map.', 'A method for mitigating effects of tool motion on a nuclear magnetic resonance measurement is disclosed.', 'The method may include determining an estimate of nuclear magnetic resonance measurement signals as a function of motion of a tool and estimating motion properties of the tool.', 'The method may also include estimating nuclear magnetic resonance measurement quality by correlating the motion properties of the tool and the nuclear magnetic resonance measurement signals.', 'An effect of the motion of the tool on the nuclear magnetic resonance measurement may be mitigated by using the estimated nuclear magnetic resonance measurement quality.', 'A method of operating a logging-while-drilling system is disclosed.', 'The method may include receiving a plurality of bottom hole assembly configurations.', 'A plurality of drilling parameters may also be received.', 'The method may also include receiving a plurality of formation properties.', 'One or more criteria for nuclear magnetic resonance measurement quality may also be received.', 'The method may also include executing a bottom hole assembly dynamics simulation to estimate a correlation of a motion of a nuclear magnetic resonance tool and an estimated nuclear magnetic resonance measurement quality using one or more of the plurality of bottom hole assembly configurations, one or more of the plurality of drilling parameters; one or more of the plurality of formation properties, and at least one of the one or more criteria for nuclear magnetic resonance measurement quality and determining the estimated nuclear magnetic resonance measurement quality for at least one of the plurality of bottom hole assembly configurations.', 'BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS\n \nIn the drawings, sizes, shapes, and relative positions of elements are not drawn to scale.', 'For example, the shapes of various elements and angles are not drawn to scale, and some of these elements may have been arbitrarily enlarged and positioned to improve drawing legibility.\n \nFIG.', '1\n depicts a schematic diagram of a wellsite system, according to one or more embodiments disclosed herein;\n \nFIG.', '2\n depicts an NMR tool movement according to one or more embodiments disclosed herein;\n \nFIG.', '3\n depicts a NMR tool movement according to one or more embodiments disclosed herein;\n \nFIG.', '4\n depicts NMR signal decay due to motion according to one or more embodiments disclosed herein;\n \nFIG.', '5\n depicts NMR signal over time according to one or more embodiments disclosed herein;\n \nFIG.', '6\n depicts NMR signal decay over time according to one or more embodiments disclosed herein;\n \nFIG.', '7\n method of estimating the quality of NMR measurement according to one or more embodiments disclosed herein;\n \nFIG.', '8\n an NMR measurement quality map according to one or more embodiments disclosed herein;\n \nFIG.', '9\n an NMR measurement quality map according to one or more embodiments disclosed herein;\n \nFIG.', '10\n an NMR measurement quality map according to one or more embodiments disclosed herein;\n \nFIG.', '11\n an NMR measurement quality map according to one or more embodiments disclosed herein;\n \nFIG.', '12\n depicts NMR signals according to one or more embodiments disclosed herein;\n \nFIG.', '13\n depicts NMR signals according to one or more embodiments disclosed herein;\n \nFIG.', '14\n depicts an apparent decay time constant of an observed NMR signal verses an intrinsic decay time constant associated with a sample property according to one or more embodiments disclosed herein;\n \nFIG.', '15\n depicts permissible error and estimated error introduced by motion according to one or more embodiments disclosed herein;\n \nFIG.', '16\n depicts normalized NMR signal verses time for a variety of motion velocities according to one or more embodiments disclosed herein;\n \nFIG.', '17\n depicts normalized NMR signal verses time for a variety of motion amplitudes according to one or more embodiments disclosed herein;\n \nFIG.', '18\n depicts tool position verses time according to one or more embodiments disclosed herein;\n \nFIG.', '19\n depicts motion properties verses time according to one or more embodiments disclosed herein;\n \nFIG.', '20\n tool motion displacement verses tool motion velocity according to one or more embodiments disclosed herein;\n \nFIG.', '21\n an NMR measurement quality map overlaid with a tool motion contour map according to one or more embodiments disclosed herein; and\n \nFIG.', '22\n an NMR measurement quality map overlaid with bottom hole assembly trajectory data according to one or more embodiments disclosed herein.', 'DETAILED DESCRIPTION', 'A well site drilling system may be deployed in either onshore or off shore applications.', 'FIG.', '1\n represents a simplified view of a well site system \n5\n that is shown in an onshore application.', 'The well site drilling system \n5\n forms a borehole \n11\n in a subsurface formation \n6\n by rotary drilling.', 'Some embodiments may use vertical drilling techniques, some may use directional drilling techniques, and some may use a combination of both techniques.', 'A drill string \n12\n is suspended within the borehole \n11\n and has a bottom hole assembly (BHA) \n100\n which includes a drill bit \n105\n at its lower end.', 'The surface system of the well site drilling system \n5\n includes a platform and derrick assembly \n10\n positioned over the borehole \n11\n, with the platform and derrick assembly \n10\n including a rotary table \n16\n, kelly \n17\n, hook \n18\n, and rotary swivel \n19\n.', 'In a drilling operation, the drill string \n12\n is rotated by the rotary table \n16\n, which engages the kelly \n17\n at the upper end of the drill string \n12\n.', 'The drill string \n12\n is suspended from the hook \n18\n, attached to a traveling block, not shown, through the kelly \n17\n and the rotary swivel \n19\n which permits rotation of the drill string \n12\n relative to the hook \n18\n.', 'In some embodiments, a top drive system may be used to rotate the drill string \n12\n.', 'Drilling fluid or mud \n26\n may be stored in a pit \n27\n formed at the well site.', 'A pump \n29\n delivers the drilling fluid or mud \n26\n to the interior of the drill string \n12\n via a port in the swivel \n19\n, which causes the drilling fluid or mud \n26\n to flow downwardly through the drill string \n12\n, as indicated by the directional arrow \n8\n in \nFIG.', '1\n.', 'The drilling fluid exits the drill string \n12\n via ports in the drill bit \n105\n or in other parts of the drill string \n12\n, such as a stabilizer, not shown, and then circulates upwardly through the annulus region \n7\n between the outside of the drill string \n12\n and the wall of the borehole \n11\n, as indicated by the directional arrows \n9\n.', 'In this way, the drilling fluid lubricates the drill bit \n105\n and carries formation cuttings up to the surface as it is returned to the pit \n27\n for recirculation.', 'The drill string \n12\n includes the BHA \n100\n.', 'In the illustrated embodiment, the BHA \n100\n is shown as having one measurement-while-drilling (MWD) tool \n130\n and multiple logging-while-drilling (LWD) tools \n120\n.', 'As used herein, the term “module” or “tool” as applied to MWD and LWD tools is understood to mean either a single tool or a suite of multiple tools contained in a single modular device.', 'Additionally, the BHA \n100\n includes a rotary steerable system (RSS) and motor \n150\n and a drill bit \n105\n.', 'The LWD tool \n120\n may be housed in a drill collar and can include one or more types of logging tools.', 'The LWD tool \n120\n may include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment.', 'By way of example, the LWD tool \n120\n may include a nuclear magnetic resonance (NMR) logging tool, and may include capabilities for measuring, processing, and storing information, and for communicating with surface equipment.', 'The MWD tool \n130\n is also housed in a drill collar, and can contain one or more devices for measuring characteristics of the drill string and drill bit.', 'In the present embodiment, the MWD tool \n130\n can include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick/slip measuring device, a direction measuring device, and an inclination measuring device.', 'The MWD tool \n130\n may include an electrical power generation or storage system \n135\n for powering the downhole system.', 'Power generated by or stored in the electrical power generation or storage system \n135\n of the MWD tool \n130\n may be used to power the MWD tool \n130\n and the LWD tool \n120\n.', 'In some embodiments, this apparatus may include a mud turbine generator powered by the flow of the drilling fluid \n26\n.', 'It is understood, however, that other power and/or battery systems may be employed.', 'The operation of the platform and derrick assembly \n10\n of \nFIG.', '1\n may be controlled using control system \n140\n located at the surface.', 'The control system \n140\n may include one or more processor-based computing systems.', 'In the present context, a processor may include a microprocessor, programmable logic devices (PLDs), field-gate programmable arrays (FPGAs), application-specific integrated circuits (ASICs), system-on-a-chip processors (SoCs), or any other suitable integrated circuit capable of executing encoded instructions stored, for example, on tangible computer-readable media (e.g., read-only memory, random access memory, a hard drive, optical disk, flash memory, etc.).', 'Such instructions may correspond to, for instance, workflows and the like for carrying out a drilling operation, algorithms and routines for processing data received at the surface from the BHA \n100\n (e.g., as part of an inversion to obtain one or more desired formation parameters), and so forth.', 'NMR logging tools, such as the LWD tool \n120\n of \nFIG.', '1\n, may use permanent magnets to create a strong static magnetic polarizing field inside the formation.', 'The hydrogen nuclei of water and hydrocarbons are electrically charged spinning protons that create a weak magnetic field, similar to tiny bar magnets.', 'When a strong external magnetic field from the logging tool passes through a formation containing fluids, these spinning protons align themselves like compass needles along the magnetic field.', 'This process, called polarization, increases exponentially with T\n1 \n(longitudinal relaxation time), while the external magnetic field (referred to as the B\n0 \nfield) is applied.', 'In operation, NMR measurements are obtained by applying a second oscillating magnetic field (referred to as the B\n1 \nfield) as a series of pulses from an antenna or coils in the NMR tool, which can be followed by or interleaved with data acquisition.', 'These pulses may be based on the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence or its variants, in which trains of spin echoes are generated by a series of pulses.', 'The pulses cause the aligned protons to tip into a plane perpendicular (transverse) to the direction of the polarization field (B\n0\n).', 'These tipped protons start to precess around the direction of the strong logging-tool magnetic field at a frequency called the Larmor frequency.', 'The precessing protons create an oscillating magnetic field, which generates weak radio signals at this frequency.', 'The total signal amplitude from the precessing hydrogen nuclei (e.g., a few microvolts) is a measure of the total hydrogen content, or porosity, of the formation.', 'The rate at which the precession decays is the transverse relaxation time (T\n2\n), which is indicative of the rate at which the spinning protons lose their alignment within the transverse plane.', 'The rate at which the precession decays can depend on certain factors, such as: the intrinsic bulk-relaxation rate in the fluid; the surface-relaxation rate, which is an environmental effect; and relaxation from diffusion in a polarized field gradient, which is a combination of environmental and tool effects.', 'Additionally, diffusion coefficients (D) can also be measured by applying a set of pulses with variable durations in between to encode the diffusive attenuation in spin echo amplitudes.', 'Further, NMR measurement types can be combined to obtain information regarding the formation and/or the fluids present therein.', 'For instance, T\n2 \nand D measurements can be combined to obtain two-dimensional information on formation fluids.', 'In another example, T\n2 \nand T\n1 \nmeasurements can be combined as well.', 'In general, any NMR measurements including but not limited to the above examples may be combined to obtain multi-dimensional information on the formation or formation fluids.', 'Once the desired NMR data is acquired, mathematical inversion processes can be applied to produce the distribution of measured properties that reflects the anisotropy of formation or formation fluids.', 'For example, the T\n2 \ndistribution represents the distribution of pore sizes within the formation, and the area under the T\n2 \ncurve represents the porosity filled with formation fluids.', 'Interpretation of pore size distribution and logarithmic mean T\n2 \nmay be used for calculating various petrophysical parameters, such as permeability and the amount of free/bound fluid.', 'Complex lateral motion that may be induced during the drilling process can affect NMR measurements.', 'Such motion may have amplitude and frequency spectrums that depend on a number of parameters.', 'For example, the motion can have random and periodic components depending on various parameters, such as weight-on-bit (WOB), rotations per minute (RPM) (or per other unit of time, e.g., seconds), stabilizer size, torque-on-bit (TOB), and/or borehole inclination, among others.', 'The movement of the LWD tool \n120\n may be random motion with a small amplitude, a smooth forward whirl motion with a medium amplitude, a rough backward whirl motion with an even larger amplitude (which is a situation that may occur when a large WOB is applied in drilling vertically), or other types of motion.', 'FIG.', '3\n is a plot of the displacement of an LWD tool \n120\n within a borehole showing displacement perpendicular to the longitudinal axis of the borehole.', 'As described above, NMR measurement may be made by applying two magnetic fields, namely static magnetic field (B\n0\n) and oscillating magnetic field (B\n1\n), to the nuclear spins in the specimen.', 'The distributions of these magnetic fields may be determined by tool geometry.', 'If there is net relative displacement between the tool and the specimen in inhomogeneous magnetic fields, nuclear spins in the specimen experience time-varying magnetic fields.', 'Such variation of magnetic fields can cause signal attenuation, sometimes referred to as motion-induced decay (MID) which may be classified into two categories: (1) displacement-dependent signal loss and (2) velocity-dependent signal loss.', 'Displacement-dependent signal loss is due to the reduced sample volume observed by the tool during NMR measurement.', 'If we consider a constant B\n0 \ngradient g and constant B\n1 \nover the sample volume, excitation slice thickness may be given by:\n \n \n \n \n \n \n \n \n \nΔ\n \n\u2062\n \n \n \n \n\u2062\n \nr\n \n \n=\n \n \n \n \n2\n \n\u2062\n \n \nB\n \n1\n \n \n \ng\n \n \n.\n \n \n \n \n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n \nIn the majority of LWD NMR measurements, both B\n0 \nand B\n1 \nare axisymmetric.', 'Therefore, the resulting sample volume is quasi-cylindrical shell(s), and Δr corresponds to shell thickness.', 'For other NMR tools, sample volume may take a form of slab, cylinder, or more complex shape and, if the displacement is larger than the fraction of Δr, there will be signal loss according to the overlap between excitation and detection volume.', 'The displacement being larger than the fraction of Δr, and the associated signal loss increase with long observation times, for example with T\n2 \nmeasurements.', 'As an example, \nFIG.', '2\n shows a portion of the BHA \n100\n including the LWD tool \n120\n NMR tool within a borehole \n11\n with lateral movement shown by the arrow \n30\n.', 'As shown in \nFIG.', '2\n, the lateral movement changes a region excited for measurement \n32\n.', 'The left side of \nFIG.', '2\n shows the LWD tool \n120\n located at the center of the borehole and the region excited for measurement \n32\n, but if during a time period that is on the order of a targeted time (e.g., a millisecond to several seconds), the LWD tool \n120\n moves laterally in the borehole \n11\n to the position shown on the right side of \nFIG.', '2\n, and it can be seen that the detection region \n34\n, the received slice, of the tool \n120\n does not overlap fully with the excited region \n32\n.', 'The effect of the LWD tool \n120\n motion may appear as additional signal decay that makes apparent T\n2 \nvalue appear shorter than the intrinsic T\n2 \nvalue, resulting in an underestimation of formation permeability.', 'Velocity-dependent NMR signal loss may due to the phase shift acquired by spins moving in a magnetic field gradient.', 'This phase shift corresponds to the rotation of the effective rotation axis around the z-axis.', 'It is analogous to applying pulses with particular phases, which would deviate from the optimal phase for the particular pulse sequence under use.', 'For example, CPMG pulse sequence yields a series of spin echoes by inverting the phase of the spins with refocusing pulses, so that they repeatedly pass through the points of the maximum coherence.', 'Behavior of observed NMR signal depends on the phase of the excitation and refocusing pulses.', 'Consider a spin that is moving at a constant velocity v in a static magnetic field with a linear gradient g.', 'If we assume perfect pulses, extra phase shift acquired at the time of the first echo t=t\nE \nis:\n \n \n \n \n \n \n \n \nϕ\n \n=\n \n \n \n \nγ\n \n\u2062\n \n \n \n \n\u2062\n \n \ngvt\n \nE\n \n2\n \n \n \n4\n \n \n.\n \n \n \n \n \n \n(\n \n2\n \n)\n \n \n \n \n \n \n \n \nIf we assume that the magnetization after the initial 90°\nx \npulse lies on the y-axis, then a 180°\ny \npulse acts like a pulse around an axis that is shifted from the y-axis by φ/2.', 'Magnetization parallel to the effective rotation axis behaves as in the CPMG sequence and preserves the amplitude from echo to echo, while the component perpendicular to the effective rotation axis behaves as in the (unmodified) Carr-Purcell sequence and leads to the odd-even echo oscillations with the overall signal decay, especially when there are any pulse imperfections.', 'Such behavior may be applicable to systems where there is net relative displacement of spins with respect to the B\n0 \nfield, for example, when the tool is stationary and spins are moving, or vice versa.', "The signal loss may be caused by the variation of offset frequency Δω\n0\n=ω\n0\n−ω\nrf\n, where ω\n0\n(r)=γB\n0\n(r) is the Larmor frequency that is determined by local B\n0 \nfield at point r and the gyromagnetic ratio γ of the nucleus (e.g. γ=2π×42.6 MHz T\n−1 \nfor proton (\n1\nH) observed in water and hydrocarbon), and ω\nrf \nis the tool's operating frequency at which signal transmission/reception takes place.", 'Therefore, it is possible to observe the same phenomena by creating a situation where each spin experiences the variation of Δω\n0\n.', 'From Eqs. 1 and 2, the amount of signal loss under the presence of net relative displacement between tool and sample is determined by motion properties, such as velocity and amplitude and a few tool parameters (i.e., g, B\n1\n, t\nE\n) when other factors, such as pulse shape (hence excitation slice profile) and receiver bandwidth, are fixed.', 'The behavior of the NMR signal under motion may be obtained by simulating spin dynamics in varying magnetic fields.', 'FIG.', '4\n shows an example of motion-induced signal decay as a function of the radius of circular motion (increasing radii from line \n120\n to \n128\n), which determines the displacement and velocity of motion with given frequency.', 'FIG.', '4\n shows that the motion with a large amplitude induces a large signal loss at the end of a long CPMG measurement.', 'In addition, motion with large velocity induces initial signal drop as suggested by Eq. 2.\n \nFIG.', '5\n shows another example of motion effect, where constant velocity v=2πrf was realized with different combinations of radius and frequency (increasing values of radii and frequency combinations from line \n130\n to \n136\n).', 'It can be seen that the initial signal decay is similar among different combinations, confirming that it is dictated by velocity.', 'On the other hand, the amount of signal decay and periodic pattern are dependent on the radius and frequency of motion.', 'FIG.', '6\n shows another example of motion effect, where echo spacing t\nE \nwas changed (increased from line \n140\n to \n150\n) while other tool parameters and motion properties were fixed.', 'It can be seen that short t\nE \nleads to less signal decay followed by some recovery after one cycle, while long t\nE \nresults in even-odd echo oscillations and fast signal decay with no recovery.', 'As demonstrated in \nFIGS.', "4-6\n, it is possible to simulate the behavior of the NMR signal under motion with full knowledge of a tool's motion properties.", "Precomputation of the NMR signal behavior and resulting measurement quality based on the velocity and amplitude of a tool's motion, without running a full NMR simulation in real time or in the downhole tool, may aid in determining the signal quality of the NMR signal by, for example, measuring a tool's motion during the tool's operation and the looking up the precomputed, estimated NMR signal quality based on the measured tool motion.\n \nFIG.", '7\n shows a schematic diagram of a method of estimating the quality of NMR measurement \n700\n.', 'This method is based on motion-induced signal loss being determined based on two motion parameters, velocity and displacement, a few tool parameters, for example, g, B\n1\n, t\nE\n, and other factors such as the formation type, for example, carbonate or shale, the well direction, for example, vertical or horizontal, friction factors within the borehole, and BHA configuration, for example, stabilizers near or far from the drill bit.', 'For a given tool and pulse sequence, NMR measurement quality can be obtained with motion properties as the reference indexes and may replace full NMR simulation in job planning and real-time drilling parameter optimization.', 'This can also be used to estimate the benefit of increasing B\n1 \nand/or reducing g and t\nE \nto improve motion sensitivity, as well as to implement self-diagnosis mechanism on a tool to detect, report, and possibly mitigate motion effect.', 'Those of ordinary skill in the art recognize that the other combinations of motion properties, such as acceleration and the history of tool position, may be used to derive the same information, since velocity is the integration of acceleration, and tool position is the integration of velocity.', 'NMR measurement is affected by both velocity and displacement as described by Equations 1 and 2, therefore, in some embodiments, the instantaneous motion property (e.g. velocity at a single measurement timing) and also the time variation of such motion property (which leads to overall displacement) should be known.', 'As discussed above, T\n1\n, T\n2\n, and porosity are the major answer products provided by LWD NMR tools and other time-domain NMR spectrometers (or so called NMR relaxometer).', 'Among them, T\n2 \nand porosity measurements are known to be more sensitive to motion than T\n1\n.', 'For each answer, the permissible error level may be defined to aid in maintaining measurement integrity.', 'Note that permissible error levels may be a function of T\n2 \nand/or the porosity under consideration.', 'For example, measurement of small porosity is associated with inherently large uncertainty regardless of the motion effect.', 'In such a case, it would not make sense to define tight tolerance for motion-induced error.', 'Therefore, permissible error level may be defined either as an absolute value (e.g., porosity unit (pu); in case of small porosity measurement) or a relative value (e.g., percentile; in case of large porosity and T\n1\n/T\n2 \nmeasurements).', 'The NMR measurement quality can be defined in multiple ways.', 'In one embodiment, it may be defined as the maximum T\n2 \nthat can be measured with permissible error level.', 'In another embodiment, it may be defined as the maximum porosity that can be measured with a permissible error level.', 'In yet another embodiment, it may be defined as the classification of measurement, for example, Good, Acceptable, or Bad for given T\n2 \nand/or porosity values.', 'The choices of definitions will depend on the application.', 'For example, if the sample property is unknown, for example in an exploration well, one may want to use the first definition so that the T\n2 \ncomponents below the maximum T\n2 \nor another range of sample properties can be measured.', 'On the other hand, if the target sample properties are known from adjacent wells and/or formation properties (e.g., shale), one may want to use the last definition to avoid putting unnecessary constraints on permissible motion.', 'An NMR measurement quality map may be generated as a function of motion velocity and amplitude and the quality definition.', 'There are multiple ways to determine measurement quality including the use of spin dynamics simulations, motion-induced signal decay, and others.', 'In \nFIG.', '7\n, a method to estimate the quality of NMR measurement \n700\n is depicted.', 'The method may include one or more processes, such as estimating the quality of NMR measurements during tool development as depicted in block \n710\n, estimating the quality of NMR measurements during job planning as depicted in block \n730\n, and/or estimating the quality of NMR measurements during a borehole drilling job as depicted in block \n750\n.', 'At block \n710\n a method for estimating the quality of NMR measurement during development is depicted.', 'At block \n712\n the motion of a tool may be estimated based on motion synthesis wherein tool motion is synthesized based on a variety of tool motion conditions such as in circular, semi-circular, and linear motion with a few parameters, such as motion amplitude and frequency, or through simulation, such as using models of various BHAs or tools.', 'In some embodiments, a particular tool may operate at a few known nodes and the tool motion may be synthesized at each of these nodes.', 'At block \n714\n an NMR measurement quality map is created to estimate NMR measurement quality.', 'In more detail, at block \n720\n an estimate for the signal loss for parameterized motion is generated.', 'The estimate may be based on NMR simulation with specific sample properties as shown at block \n729\n and/or based on motion-induced decay at block \n721\n.', 'If the estimate uses motion-induced decay at block \n721\n, then such decay may be based on NMR simulations with independent of formation \n6\n sample properties.', 'In some embodiments, the estimate at block \n721\n may use motion-induced decay based on established formulas for estimating motion-induced decay, as shown at block \n724\n.', 'At block \n722\n the desired measurement quality is determined.', 'Such measurement quality may include qualitative determinations, such as good, acceptable, and poor, based on various ranges of potential NMR measurement quality.', 'In some embodiments, the definition may also include quantitative determinations, such as maximum T\n2 \nthat can be measured with permissible error level (T\n2,max\n) or T\n2\n.', 'At block \n726\n the estimated signal loss of parameterized motion created at block \n720\n is combined with the defined measurement quality from block \n722\n to derive the measurement quality based on tool motion properties, such as amplitude of tool motion and the velocity of tool motion.', 'The estimation to tool motion from block \n712\n and the NMR measurements quality map from block \n714\n may be used to mitigate tool motion effects.', 'For example, at block \n716\n the information from blocks \n712\n and \n714\n may be used to design the NMR sensor within the NMR tool, such as the tool \n120\n, to mitigate the effect of expected tool motion at block \n716\n and/or to design NMR pulse sequences to mitigate the effect of expected tools at block \n718\n.', 'In some embodiments, at block \n718\n, control signals for a pulse sequence are sent to a NMR measurement tool, such as tool \n120\n.', 'In some embodiments, parameters for the configuration of the tool \n120\n are output.', 'At block \n730\n a method for estimating the quality of NMR measurement during job planning is depicted.', 'Estimates of the quality of NMR measurements may be used to aid in the configuration of the BHA and/or to adjust the drilling parameters that are to be used during the drilling operation.', 'At block \n732\n an estimation of motion of the tool may be created based on simulation of the BHA in operation in a borehole.', 'The simulation may include variations and permutations of BHA configuration, formation properties, and drilling parameters, such as weight-on-bit and RPM, borehole angle, and other parameters.', 'At block \n734\n and/or block \n736\n an estimate of the NMR measurement quality is determined.', 'For example, at block \n736\n, the estimation of motion of the NMR tool created at block \n732\n may be stacked to generate an estimation of motion for a given NMR tool under normal operating condition.', 'In estimating the motion of the NMR tool each operating condition of a BHA, including velocity and amplitude, may be assigned with a weight and then those weights are used to determine an estimate of motion for a given BHA under normal operating condition.', 'For example, if the BHA is expected to be operated under a first condition for 20% of the time, a second condition for 50%, and a third condition for 25%, then then BHA simulation results for the first, second, and third conditions are stacked with the weight of 0.25, 0.50, and 0.25, respectively and yield the stacked motion properties of the NMR tool.', 'Then, by comparing the stacked results of various BHAs, an optimal BHA may be chosen at block \n738\n and the instructions for configuring and/or assembling the BHA may be output.', 'At block \n734\n the individual results for each of the first, second, third, or more operating conditions for a particular BHA configuration may be evaluated to determine which operating conditions for the particular BHA condition yield acceptable or unacceptable results.', 'At block \n739\n, the NMR measurement quality map for the particular BHA may be used to aid in determining drilling parameters for use in drilling a borehole.', 'In some embodiments, at block \n739\n, control signals for adjusting the drilling parameters of a well site system, such as well site system \n5\n may be output.', 'In some embodiments, a control system, such as control system \n140\n, receives drilling parameters and adjusts the drilling of the borehole \n11\n.', 'At block \n750\n a method for estimating the quality of NMR measurement during a job, such as drilling operations, is depicted.', 'Estimating the quality of NMR measurements during drilling operations may be used to flag NMR measurement data that is recorded during excess tool motion and/or may also be used to adjust drilling parameters such as weight-on-bit and rotational speed in real time, during drilling.', 'At block \n752\n an estimation of tool motion may be created based on information gathered from sensors on the BHA.', 'In some embodiments, at block \n754\n, an estimation of tool motion may be created based on NMR signal variation recorded during drilling.', 'At block \n756\n, an estimate of NMR measurement quality may be determined using an estimation of motion crated at block \n752\n or block \n754\n and an NMR measurement quality map, such as the NMR measurement quality map generated at block \n714\n.', 'The estimation of NMR measurement quality may be used at block \n759\n to flag NMR measurement data that is recorded during excess tool motion and/or may also be used to adjust drilling parameters such as weight-on-bit and rotational speed in real time, during drilling.', 'At block \n758\n, an estimate of NMR measurement quality may be determined using an estimation of motion created at block \n752\n or block \n754\n, for example, a formula or equation that is a curve fit of estimated signal decay based on motion as a function of displacement shown in \nFIGS.', '12 and 13\n, as discussed below.', 'For example, a Gaussian or other types of shape mathematically implementable equation, such as a third-order polynomial may be used to represent the motion induced decay as a function of x might be represented as shown in Eq. 2.1, where x is displacement and i corresponds to velocity category given in the legend of \nFIGS.', '12 and/or 13\n.', 'This, when compared to measurement quality map generated at block \n756\n, can reduce the amount of memory used to store information related to the estimate of NMR measurement decay because just a few sets of coefficients for categorized velocity, rather than hundreds of combinations of velocity and displacement and resulting NMR quality as used at block \n756\n.', 'In some embodiments, a formula may be obtained by fitting an NMR measurement quality map with polynomial.', 'In this way, estimated motion may be correlated with a variety of measurement quality definition, for example as defined at block \n722\n.', 'The estimation of NMR measurement quality may be used at block \n759\n to flag NMR measurement data that is recorded during excess tool motion and/or may also be used to adjust drilling parameters such as weight-on-bit and rotational speed in real time, during drilling.', 'In some embodiments, a control system, such as control system \n140\n may indicate, for example, to an operator, that the BHA is exhibiting excess motion.', 'MID\n(\nx\n)=\na\ni\n*x\n3\n+b\ni\n*x\n2\n+c\ni\n*+d\ni\n\u2003\u2003(2.1)', 'In one embodiment, an NMR measurement quality map may be generated by analyzing NMR signal behavior under synthesized motion.', 'Such procedures may be implemented, for example, at block \n712\n or block \n714\n.', 'FIG.', '8\n shows an example of a NMR measurement quality map.', 'NMR signal behavior for use in generating an NMR measurement quality map may be obtained by simulating the evolution of spin ensembles in time-varying magnetic fields.', 'By moving the magnetic fields with respect to spin ensembles, motion effect can be reproduced as was seen in \nFIGS.', '4-6\n.', 'The amount of field variation at given time steps may be obtained by motion synthesis, for example, at block \n712\n and/or motion simulation, for example, at block \n732\n.', 'A range of motion data may be generated using such motion syntheses or simulation.', 'Interpolation methods may also be used to interpolate between the results of two motion conditions to generate additional data and improve the estimate quality of the NMR measurement quality map.', 'FIG.', '8\n shows an example of such maps with T\n2,max \n(i.e., the maximum sample T\n2 \nthat can be measured without compromising data quality in any of three measurements: Porosity, T\n1\n, and T\n2\n) as the quality indicator.', 'This method may use multiple NMR motion simulations to increase the resolution in T\n2,max\n.', "In the NMR measurement quality maps shown herein, the colors of the squares represent the maximum sample's T\n2 \nthat can be measured without compromising data quality.", "For example, the green squares \n160\n indicate a T\n2,max \n(which represents a sample's maximum T\n2 \nthat can measured without compromising data quality) of 3 seconds, yellow squares \n162\n indicate a T\n2,max \nof 100 ms, red squares \n164\n indicate a T\n2,max \nof 5 ms, and black squares \n166\n indicate that the motion-induced error in the measured sample which has a T\n2, sample \nof less than 5 ms may still exceed the permissible error level.", "A tool's sensitivity to motion varies from one tool to another and therefore the NMR measurement quality maps also vary from tool to tool.", 'FIGS.', '8-10\n show examples of NMR measurement quality maps for two different tools.', 'The maps show estimated NMR measurement quality based on T\n2,max\n.', 'The NMR tool used to generate the NMR measurement quality in \nFIG.', '9\n has smaller g, larger B\n1\n, and shorter t\nE \nthan the tool used to generate the NMR measurement quality in \nFIG.', '10\n, thus the tool used to generate the NMR measurement quality of \nFIG.', '9\n has generally better measurement quality under a given set of motion parameters because it has a lower sensitivity to motion.', 'An NMR measurement quality map may also be generated by plotting NMR measurement quality as a function of effective displacement and velocity.', 'The effective displacement is given in the unit of excitation slice thickness:\n \n \n \n \n \n \n \n \n \nd\n \n0\n \n \n=\n \n \n \n \n2\n \n\u2062\n \n \nB\n \n1\n \n \n \ng\n \n \n.', '(\n \n3\n \n)', 'The effective velocity is given in the unit of velocity limit to avoid excess phase shift introduced by motion:\n \n \n \n \n \n \n \n \n \nv\n \n0\n \n \n=\n \n \n \n \n2\n \n\u2062\n \nπ\n \n \n \nγ\n \n\u2062\n \n \n \n \n\u2062\n \n \ngt\n \nE\n \n2\n \n \n \n \n.', '(\n \n4\n \n)\n \n \n \n \n \n \n \n \nFIG.', '11\n is a consolidated measurement quality map obtained by converting the axes of \nFIGS.', '9 and 10\n to effective displacement and velocity.', 'Square markers \n160\n-\n166\n represent the tool in \nFIG.', '9\n, while asterisks \n170\n-\n176\n represent the one in \nFIG.', '10\n.', 'When plotted in this way, the two tools exhibit similar motion response that is characterized by velocity and displacement.', 'This shows that motion sensitivity is largely dependent on three tool parameters, g, B\n1\n, and t\nE\n, in the above equations.', 'In other words, motion tolerance can be improved by reducing g and t\nE \nand/or increasing B\n1\n.', 'Such improvement in motion tolerance would be reflected in the NMR measurement quality maps of \nFIGS.', '8-10\n as an expanded green region \n170\n that extends further in the upper-right direction of the chart.', 'In some embodiments, a NMR measurement quality map may be a lookup table with the velocity and the displacement parameters of tool motion as reference indexes and estimated NMR measurement quality as the result.', 'In some embodiments, continuous T\n2,max \nmay be derived from signal decay induced by motion.', 'Such motion-induced decay (MID) may be calculated by assuming semi-infinite T\n2 \nin the spin dynamics simulation.', 'If there is no motion, such system will return a signal with effectively no decay over the period of measurement.', 'Then any signal decay observed under the presence of motion may be attributed to the motion.', 'FIGS.', '4-6\n are examples of such simulations.', 'The signal decay attributed to tool motion may be used to generate the lookup tables discussed above.', 'In a special case, MID may be derived from net relative displacement.', 'According to Eq. 2, to avoid appreciable phase shifts in NMR signal,\n \n \n \n \n \n \n \n \n \n \nγ\n \n\u2062\n \n \n \n \n\u2062\n \n \ngvt\n \nE\n \n2\n \n \n \n4\n \n \n\u2062\n \n \n \n<<\n \n \nπ\n \n2\n \n \n \n.', '(\n \n5\n \n)', 'Thus, if tool motion, v, is much smaller than the velocity defined by:\n \n \n \n \n \n \n \n \n \nv\n \nph\n \n \n=\n \n \n \n2\n \n\u2062\n \nπ\n \n \n \nγ\n \n\u2062\n \n \n \n \n\u2062\n \n \ngt\n \nE\n \n2\n \n \n \n \n \n \n \n \n(\n \n6\n \n)\n \n \n \n \n \n \n \n then the phase shift introduce by motion is minimal and in some embodiments may be neglected.', 'When above condition is satisfied the motion of the tool is sufficiently slow compared to t\nE \nand the on-resonance spins adiabatically track the effective rotation axis to gradually get off-resonance.', 'This process may be determined by the amplitude of motion and may be irrespective of the speed of motion.', 'FIG.', '12\n shows an example of signal decays for linear motion as a function of displacement and \nFIG.', '13\n shows an example of signal decays for a circular motion as a function of displacement.', 'Each line in the graphs shown in \nFIGS.', '12 and 13\n represent the result for one combination of velocity and amplitude of motion.', 'When the velocity is much smaller than v\nph \ndefined by Eq. 6, the curves fall onto each other regardless of the realization of the combination of amplitude and frequency.', 'When velocity is sufficiently small, less than 0.1 v\nph\n, linear and circular motion exhibit equivalent signal decay up to ˜Δr and suggests that estimating MID under such conditions can be undertaken without knowing or simulating the trajectory of the motion of the tool to a very precise level.', 'When motion velocity is increased, it exhibits initial signal drop due to phase incoherence.', 'Thus, the amount of signal decay based on the displacement and velocity can be estimated without knowing the trajectories of the tools to a very precise degree.', 'Therefore, even when motion simulation and measurements provide information that is not timely correlated with NMR measurement, NMR signal loss can still be estimated when overall, time averaged, or other similar motion properties are provided.', 'Therefore, low resolution tool motion measurement data, for example at a rate of 1 Hertz, may be used to estimate NMR measurement quality.', 'Once MID is obtained, the time constant T\n2,mid \nmay be derived for the decay.', 'Then apparent decay time constant T\n2,app \nof observed NMR signal may be given by:\n \n \n \n \n \n \n \n \n \n1\n \n \nT\n \n \n2\n \n,\n \napp\n \n \n \n \n=\n \n \n \n1\n \n \nT\n \n \n2\n \n,\n \nint\n \n \n \n \n+\n \n \n \n1\n \n \nT\n \n \n2\n \n,\n \nmid\n \n \n \n \n.', '(\n \n7\n \n)\n \n \n \n \n \n \n \n \nHere, T\n2,int \nis the intrinsic decay time constant associated with a sample property.', 'FIG.', '14\n shows an example of T\n2,app \nfor given T\n2,mid\n.', 'Once T\n2,app \nis calculated from Eq. 5, T\n2,max \nmay be obtained by comparing motion-induced error and permissible error, the latter of which is derived from intrinsic uncertainty in the measurement of given T\n2,int\n.', 'The error introduced by motion may be defined as:\n \n \n \n \n \n \n \n \n \nT\n \n \n2\n \n,\n \nerror\n \n \n \n=\n \n \n \nexp\n \n\u2061\n \n \n(\n \n \n\uf603\n \n \nlog\n \n\u2061\n \n \n(\n \n \n \nT\n \n \n2\n \n,\n \nint\n \n \n \n \nT\n \n \n2\n \n,\n \napp\n \n \n \n \n)\n \n \n \n\uf604\n \n \n)\n \n \n \n-\n \n1.\n \n \n \n \n \n \n(\n \n8\n \n)\n \n \n \n \n \n \n \n \nFIG.', '15\n shows the permissible error \n180\n and T\n2,error \n182\n defined above.', 'The intersection of two lines is the T\n2,max \nthat represents the longest T\n2 \nmeasured without having motion-induced error as the dominant uncertainty.', 'Unlike simulating the evolution of spin ensembles in time-varying magnetic fields, discussed above with reference to \nFIGS.', '8-11\n, where the resolution of T\n2,max \nis determined by the number of T\n2 \nvalues used in NMR simulation, simulating motion-induced decay provides a continuous T\n2,max\n.', 'As discussed above, NMR measurement quality under motion may be estimated from two motion properties: velocity and amplitude.', 'To use the NMR measurement quality maps to estimate NMR measurement quality, an estimation of tool motion may be measured or computed.', 'In one embodiment, tool motion may be simulated based on the parameters that affect motion properties in a BHA dynamics simulation.', 'Such simulation may occur at block \n732\n of \nFIG.', '7\n.', 'For instance, in the case of an LWD NMR tool, the parameters for a BHA dynamics simulation may include, for example, the configurations of bottom hole assembly (BHA), formation properties (e.g., lithology), mud properties (e.g., density, viscosity), borehole properties (e.g., size, trajectory), and drilling parameters (e.g., WOB, RPM, mud flow rate).', 'Other factors that may also affect tool motion may also be incorporated in motion estimation.', 'When contributing factors to tool motion are well defined, the range of motion expected for a given system may be estimated.', 'Multiple methods may be used to estimate tool motion, including, for example, analytical modeling, frequency domain modeling, time domain modeling, and others.', 'In some embodiments, tool motion may be measured by sensors such as accelerometers, magnetometers, gyroscopes, calipers, standoff measurement sensors, or a combination of sensors.', 'Such measurement may occur, for example, at block \n752\n of \nFIG.', '7\n.', 'However, motion sensors are may be located away from the NMR sensor, providing data that does not reflect tool motion at the location of the NMR sensor.', 'In such a case, motion measurement may be used to calibrate a motion simulation, or vice versa.', 'In some embodiments, for example wireline tools, rugosity or other borehole imperfections or other interactions between the tool string and the formation can generate motion perpendicular to the main direction of motion of the tool.', 'Such movements may be simulated or measured and correlations between such movements and nuclear magnetic resonance measurement quality may be used to provide an indicator of nuclear magnetic resonance measurement quality or to mitigate tool motion effects on nuclear magnetic resonance measurement quality.', 'In another embodiment, tool motion may be estimated from the NMR signal itself.', 'Such estimates may be based on the principle that motion affects overall echo amplitude, and also the shape and phase of each echo.', 'These behaviors can be characterized for a given tool and environment, and results may be used to estimate motion properties from the echo shape.', 'Such estimation of motion may occur, for example, at block \n754\n of \nFIG.', '7\n.', 'FIG.', '16\n shows an example of the variation of echo shape as a function of motion velocity realized with various frequencies of motion and fixed amplitude.', 'It can be seen that the echo width \n190\n increases with motion frequency.', 'While \nFIG.', '17\n shows the variation of echo shape as a function of motion amplitude.', 'It can be seen that the amplitude of the imaginary part increases with motion amplitude.', 'In another embodiment, motion may be estimated from CPMG obtained with different t\nE\n.', 'As understood from Eq. 2, additional phase shift causes NMR signal loss under motion as a function of t\nE\n2\n.', 'This dependence is shown in \nFIG.', '6\n.', 'Therefore, using multiple CPMG measurements with two or more t\nE \nvalues allows for the estimation of the amount of phase shift introduced by tool motion, from which tool motion velocity may be derived.', 'In the same manner, comparison of signal amplitude at the middle/end of CPMG provides the amplitude of the tool motion.', 'Such multi-t\nE \nsequence provides both the estimate of motion properties and the effect on NMR measurement.', 'The nominal motion properties obtained using either the BHA dynamics simulation method or NMR-based motion estimation method may be used in estimating the NMR measurement quality.', 'Motion properties obtained by simulation, measurement, and/or NMR-based estimation, may exhibit variations over time that lead to different NMR measurement qualities estimated from an NMR measurement quality map.', 'In such a case, a likelihood of motion properties may be represented by a bivariate histogram and/or a contour map that covers the range of possible motion.', 'Such maps may be generated at block \n736\n of \nFIG.', '7\n.', 'FIG.', '18\n shows an example of tool trajectory represented by the time variation of x and y coordinates.', 'That is, \nFIG.', '18\n shows an x-coordinate 200 of the tool trajectory and a y-coordinate 202 of the tool trajectory over time.', 'The patterns are not uniform and show variations in amplitude and velocity of the tool motion.', 'The tool motion properties that may be used to estimate NMR measurement quality include the maximum displacement and mean velocity of a one-second-long observation window \n1810\n.', 'Shifting the observation window \n1810\n along the time axis and recording the maximum displacement and mean velocity at each time step yields the variation of velocity \n210\n and displacement \n212\n over time, as shown in \nFIG.', '19\n.', 'These parameters may be used as the tool motion under a given set of conditions.', 'The maximum displacement and mean velocity of a one-second-long observation window may be plotted as a bivariate histogram, for example, as shown in \nFIG.', '20\n or in a contour map \n220\n, the latter of which may be overlaid onto the NMR measurement quality map as shown in \nFIG.', '21\n.\n \nFIG.', '22\n shows an example NMR measurement quality map for an example LWD NMR tool.', 'The squares \n160\n-\n166\n represent the measurement quality using synthesized circular tool motion of at various velocities and amplitudes.', 'The dots \n230\n-\n236\n represent the nominal properties of simulated BHA trajectories obtained with different combinations of formation and drilling parameters.', 'Color-coded NMR measurement quality is consistent between two datasets, even though the simulated trajectories are highly non-uniform.', 'The data in \nFIG.', '22\n shows that the amount of signal loss is dependent on tool motion velocity and amplitude.', 'Therefore, NMR measurement quality under motion may be estimated by plotting motion properties, corresponding to the dots onto the predefined NMR measurement quality map, the squares, without knowing the exact trajectory of the tool motion.', 'The combination of NMR measurement quality maps with tool motion properties provides for planning optimization and real time optimization and/or quality control.', 'Such planning optimization and real time optimization and/or quality control may occur at blocks \n738\n, \n739\n, and \n759\n.', 'For example, the tool motion measured or simulated while drilling may be applied to an NMR measurement quality map to determine whether the NMR measurement data is likely to have a high quality or a low quality.', 'Such information may be used to change the drilling conditions, for example, if the NMR measurement quality map and tool motion estimation indicates that the NMR measurement quality is in a bad or low quality condition, then the drilling operation may increase or decrease the weight-on-bit, or the rotational speed of the drill string to move the estimated NMR measurement quality to a good condition, according to the NMR measurement quality map.', 'In one embodiment, an NMR measurement quality maps may be used to define the specification of an NMR sensor to mitigate motion effect, such as at block \n716\n of \nFIG.', '7\n.', 'For example, a static field gradient (g=dB\n0\n/dr) plays a role in NMR sensor design, because it is a factor in the motion sensitivity of the tool and also NMR sensitivity, for example, a large static field gradient results in thin slice thickness and therefore, a smaller signal.', 'With B\n0 \nvariation sensitivity, when B\n0 \nchanges due to temperature and/or magnetic debris, a small static field gradient results in a large shift because dr=dB\n0\n/g.', 'This is trade-off relationship and finding an operating point for a tool may include an analysis of each property as a function of g. Under such circumstances, a maximum g that provides acceptable NMR measurement under expected range of motion may be determined by generating an NMR measurement quality map and simulating or estimating tool motion.', 'In another embodiment generating NMR measurement quality maps and simulating or estimating tool motion may be used to optimize an NMR pulse sequence, such as at block \n718\n of \nFIG.', '7\n.', 'From Eq. 2, motion effect may be reduced by reducing echo spacing t\nE\n.', 'However, short t\nE \ndemands more electrical power to transmit B\n1 \npulses.', 'If electrical power supply is not sufficient, high electrical demands may cause the droop of B\n1 \namplitude, which may lead to additional signal decay in NMR measurement.', 'In other words, short t\nE \nmitigates motion risk but at a cost of B\n1 \ndroop risk.', 'This may be mitigated by increasing the flow rate of drilling mud in turbine/alternator that provides electrical power to the tool, but high flow rate could increase tool motion.', 'Under such complex situations, NMR measurement quality maps and simulated or estimated tool motion may be used to make a trade-off between conflicting yet closely coupled objectives.', 'In another embodiment, NMR measurement quality maps and simulated or estimated tool motion may be used to optimize BHA configurations, such as at block \n738\n of \nFIG.', '7\n.', 'For example, an LWD NMR tool may be connected to other tools to configure a BHA, such as BHA \n100\n, that is designed to achieve certain measurement objectives.', 'The other tools may include, but are not limited to, resistivity, nuclear, acoustic, and measurement while drilling (MWD) tools.', 'For a given set of tools, there are some flexibilities in the order in which they are assembled into a BHA.', 'In such an embodiment, BHA motion may be simulated for each configuration with a set of drilling parameters (e.g., WOB, RPM, flow rate), formation and mud properties (e.g., rock strength, friction factor), and well trajectories to cover the expected range of operation.', 'Then, resulting motion may be used to model NMR tool response and associated measurement quality by running a full NMR spin dynamics simulation.', 'It is also possible to estimate NMR measurement quality by overlaying the derived motion properties onto the NMR measurement quality map.', 'In doing so, distribution of motion properties obtained with a unique set of parameters may be stacked together, for example, with appropriate weights reflecting the likelihood of each condition (e.g., 30% of vertical well vs. 70% or horizontal well), in order to obtain a likelihood of motion properties.', 'The tool motion results for each set of motion properties for each BHA configuration may be plotted in a histogram and/or a contour map to represent the likelihood of motion for a given BHA under normal drilling conditions and a particular BHA configuration may be selected from among the multiple BHA candidates based on the priorities for each well.', 'In another embodiment, NMR measurement quality maps and simulated or estimated tool motion may be used to optimize drilling parameters to ensure acceptable NMR measurement quality, such as at block \n739\n of \nFIG.', '7\n.', 'While formation properties and well trajectories are given for each job, BHA configuration and drilling parameters are adjustable to some extent.', 'Therefore, motion properties may be derived for different combinations of drilling parameters and plotted individually on a measurement quality map to determine an operating envelope in which NMR measurement quality is acceptable.', 'In yet another embodiment, NMR measurement quality maps and simulated or estimated tool motion may be used to diagnose measurement quality by a tool itself or at surface equipment, such as controls system \n140\n, that communicates with a BHA, such as BHA \n100\n, such as at block \n759\n of \nFIG.', '7\n.', 'The tool motion properties may come from on-board motion measurement sensors, NMR-based motion estimation, or a combination thereof.', 'The resulting NMR measurement quality estimation information may be transferred to the operator to notify the operator of measurement quality as well as the motion properties to aid in adjusting drilling parameters in real-time.', 'A few example embodiments have been described in detail above; however, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the scope of the present disclosure or the appended claims.', 'Accordingly, such modifications are intended to be included in the scope of this disclosure.', 'Likewise, while the disclosure herein contains many specifics, these specifics should not be construed as limiting the scope of the disclosure or of any of the appended claims, but merely as providing information pertinent to one or more specific embodiments that may fall within the scope of the disclosure and the appended claims.', 'Any described features from the various embodiments disclosed may be employed in combination.', 'In addition, other embodiments of the present disclosure may also be devised which lie within the scope of the disclosure and the appended claims.', 'Additions, deletions and modifications to the embodiments that fall within the meaning and scopes of the claims are to be embraced by the claims.', 'Certain embodiments and features may have been described using a set of numerical upper limits and a set of numerical lower limits.', 'It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, or the combination of any two upper values are contemplated.', 'Certain lower limits, upper limits and ranges may appear in one or more claims below.', 'Numerical values are “about” or “approximately” the indicated value, and take into account experimental error, tolerances in manufacturing or operational processes, and other variations that would be expected by a person having ordinary skill in the art.', 'The various embodiments described above can be combined to provide further embodiments.', 'These and other changes can be made to the embodiments in light of the above-detailed description.', 'In general, in the following claims, the terms used should not be construed to limit the claims to the specific embodiments disclosed in the specification and the claims, but should be construed to include other possible embodiments along with the full scope of equivalents to which such claims are entitled.', 'Accordingly, the claims are not limited by the disclosure.'] | ['1.', 'A method for mitigating effects of tool motion on a nuclear magnetic resonance measurement, comprising:\ndetermining an estimate of motion induced signal loss of nuclear magnetic resonance measurement signals as a function of lateral motion of a tool;\nestimating a velocity and a displacement amplitude of lateral tool motion;\nestimating a nuclear magnetic resonance measurement quality by correlating the velocity and displacement amplitude of the lateral motion and the estimated motion induced signal loss; and\nmitigating an effect of the lateral motion of the tool on the nuclear magnetic resonance measurement by using the estimated nuclear magnetic resonance measurement quality.', '2.', 'The method of claim 1, wherein the estimating the velocity and the displacement amplitude of lateral tool motion includes receiving data obtained by motion sensors on a downhole tool.', '3.', 'The method of claim 1, wherein the determining the estimate of motion induced signal loss of nuclear magnetic resonance measurement signals as a function of lateral motion of a tool includes generating an estimated nuclear magnetic resonance measurement quality map, the quality map providing an estimate of the nuclear magnetic resonance measurement quality as a function of velocity and displacement amplitude.', '4.', 'The method of claim 3, wherein generating an estimated nuclear magnetic resonance measurement quality map includes receiving sample properties of a formation.', '5.', 'The method of claim 1, wherein:\nthe correlating of the velocity and displacement amplitude of the lateral tool motion includes generating a lookup table, the lookup table including the velocity and the displacement amplitude as reference indexes and the estimated motion induced signal loss as a result.', '6.', 'The method of claim 1, wherein the estimating the velocity and displacement amplitude of the lateral tool motion includes:\nexecuting a bottom hole assembly simulation; and\ndetermining the velocity and displacement amplitude from the bottom hole assembly simulation.', '7.', 'The method of claim 6, wherein executing the bottom hole assembly simulation includes configuring the simulation with at least one combination of drilling parameters and formation properties.', '8.', 'The method of claim 1, wherein the estimating the velocity and displacement amplitude of the lateral tool motion includes estimating the velocity and displacement amplitude based on a variation of a magnetic resonance measurement signal from a magnetic resonance measurement tool.', '9.', 'The method of claim 1, determining an estimate of motion induced signal loss of nuclear magnetic resonance measurement signals as a function of lateral motion of a tool includes:\ngenerating an estimated motion induced signal loss as a function of the displacement amplitude and the velocity; and\ngenerating a curve fit formula for the estimated motion induced signal loss as a function of the displacement amplitude and the velocity of the tool.', '10.', 'The method of claim 1, wherein mitigating the effect of the lateral motion of the tool on the nuclear magnetic resonance measurement includes sending an output control signal to a control system of a well site system to adjust drilling parameters of the well site system.', '11.', 'The method of claim 1, further comprising:\nreceiving one or more criteria for nuclear magnetic resonance measurement quality that includes a measured sample property and a permissible error level for a measurement of the measured sample property; and\nthe estimating the nuclear magnetic resonance measurement quality includes generating a nuclear magnetic resonance measurement quality map based on the nuclear magnetic resonance measurement quality, the quality map providing an estimate of the nuclear magnetic resonance measurement quality as a function of velocity and displacement amplitude.\n\n\n\n\n\n\n12.', 'The method of claim 11, wherein the measured sample property is at least one of longitudinal relaxation time, transverse relaxation time, or porosity.'] | ['FIG.', '1 depicts a schematic diagram of a wellsite system, according to one or more embodiments disclosed herein;; FIG.', '2 depicts an NMR tool movement according to one or more embodiments disclosed herein;; FIG.', '3 depicts a NMR tool movement according to one or more embodiments disclosed herein;; FIG.', '4 depicts NMR signal decay due to motion according to one or more embodiments disclosed herein;; FIG.', '5 depicts NMR signal over time according to one or more embodiments disclosed herein;; FIG.', '6 depicts NMR signal decay over time according to one or more embodiments disclosed herein;; FIG.', '7 method of estimating the quality of NMR measurement according to one or more embodiments disclosed herein;; FIG.', '8 an NMR measurement quality map according to one or more embodiments disclosed herein;; FIG.', '9 an NMR measurement quality map according to one or more embodiments disclosed herein;; FIG.', '10 an NMR measurement quality map according to one or more embodiments disclosed herein;; FIG.', '11 an NMR measurement quality map according to one or more embodiments disclosed herein;; FIG.', '12 depicts NMR signals according to one or more embodiments disclosed herein;; FIG.', '13 depicts NMR signals according to one or more embodiments disclosed herein;; FIG.', '14 depicts an apparent decay time constant of an observed NMR signal verses an intrinsic decay time constant associated with a sample property according to one or more embodiments disclosed herein;; FIG.', '15 depicts permissible error and estimated error introduced by motion according to one or more embodiments disclosed herein;; FIG.', '16 depicts normalized NMR signal verses time for a variety of motion velocities according to one or more embodiments disclosed herein;; FIG.', '17 depicts normalized NMR signal verses time for a variety of motion amplitudes according to one or more embodiments disclosed herein;; FIG.', '18 depicts tool position verses time according to one or more embodiments disclosed herein;; FIG.', '19 depicts motion properties verses time according to one or more embodiments disclosed herein;; FIG.', '20 tool motion displacement verses tool motion velocity according to one or more embodiments disclosed herein;; FIG.', '21 an NMR measurement quality map overlaid with a tool motion contour map according to one or more embodiments disclosed herein; and; FIG.', '22 an NMR measurement quality map overlaid with bottom hole assembly trajectory data according to one or more embodiments disclosed herein.; FIG.', '5 shows another example of motion effect, where constant velocity v=2πrf was realized with different combinations of radius and frequency (increasing values of radii and frequency combinations from line 130 to 136).', 'It can be seen that the initial signal decay is similar among different combinations, confirming that it is dictated by velocity.', 'On the other hand, the amount of signal decay and periodic pattern are dependent on the radius and frequency of motion.', '; FIG.', '6 shows another example of motion effect, where echo spacing tE was changed (increased from line 140 to 150) while other tool parameters and motion properties were fixed.', 'It can be seen that short tE leads to less signal decay followed by some recovery after one cycle, while long tE results in even-odd echo oscillations and fast signal decay with no recovery.; FIG.', '7 shows a schematic diagram of a method of estimating the quality of NMR measurement 700.', 'This method is based on motion-induced signal loss being determined based on two motion parameters, velocity and displacement, a few tool parameters, for example, g, B1, tE, and other factors such as the formation type, for example, carbonate or shale, the well direction, for example, vertical or horizontal, friction factors within the borehole, and BHA configuration, for example, stabilizers near or far from the drill bit.; FIG.', '11 is a consolidated measurement quality map obtained by converting the axes of FIGS.', '9 and 10 to effective displacement and velocity.', 'Square markers 160-166 represent the tool in FIG.', '9, while asterisks 170-176 represent the one in FIG.', '10.', 'When plotted in this way, the two tools exhibit similar motion response that is characterized by velocity and displacement.', 'This shows that motion sensitivity is largely dependent on three tool parameters, g, B1, and tE, in the above equations.', 'In other words, motion tolerance can be improved by reducing g and tE and/or increasing B1.', 'Such improvement in motion tolerance would be reflected in the NMR measurement quality maps of FIGS.', '8-10 as an expanded green region 170 that extends further in the upper-right direction of the chart.', '; FIG.', '12 shows an example of signal decays for linear motion as a function of displacement and FIG.', '13 shows an example of signal decays for a circular motion as a function of displacement.', 'Each line in the graphs shown in FIGS.', '12 and 13 represent the result for one combination of velocity and amplitude of motion.', 'When the velocity is much smaller than vph defined by Eq. 6, the curves fall onto each other regardless of the realization of the combination of amplitude and frequency.', 'When velocity is sufficiently small, less than 0.1 vph, linear and circular motion exhibit equivalent signal decay up to ˜Δr and suggests that estimating MID under such conditions can be undertaken without knowing or simulating the trajectory of the motion of the tool to a very precise level.', 'When motion velocity is increased, it exhibits initial signal drop due to phase incoherence.', '; FIG.', '15 shows the permissible error 180 and T2,error 182 defined above.', 'The intersection of two lines is the T2,max that represents the longest T2 measured without having motion-induced error as the dominant uncertainty.', 'Unlike simulating the evolution of spin ensembles in time-varying magnetic fields, discussed above with reference to FIGS. 8-11, where the resolution of T2,max is determined by the number of T2 values used in NMR simulation, simulating motion-induced decay provides a continuous T2,max.; FIG.', '16 shows an example of the variation of echo shape as a function of motion velocity realized with various frequencies of motion and fixed amplitude.', 'It can be seen that the echo width 190 increases with motion frequency.', 'While FIG.', '17 shows the variation of echo shape as a function of motion amplitude.', 'It can be seen that the amplitude of the imaginary part increases with motion amplitude.; FIG.', '18 shows an example of tool trajectory represented by the time variation of x and y coordinates.', 'That is, FIG.', '18 shows an x-coordinate 200 of the tool trajectory and a y-coordinate 202 of the tool trajectory over time.', 'The patterns are not uniform and show variations in amplitude and velocity of the tool motion.', 'The tool motion properties that may be used to estimate NMR measurement quality include the maximum displacement and mean velocity of a one-second-long observation window 1810.', 'Shifting the observation window 1810 along the time axis and recording the maximum displacement and mean velocity at each time step yields the variation of velocity 210 and displacement 212 over time, as shown in FIG.', '19.', 'These parameters may be used as the tool motion under a given set of conditions.', 'The maximum displacement and mean velocity of a one-second-long observation window may be plotted as a bivariate histogram, for example, as shown in FIG.', '20 or in a contour map 220, the latter of which may be overlaid onto the NMR measurement quality map as shown in FIG.', '21.; FIG.', '22 shows an example NMR measurement quality map for an example LWD NMR tool.', 'The squares 160-166 represent the measurement quality using synthesized circular tool motion of at various velocities and amplitudes.', 'The dots 230-236 represent the nominal properties of simulated BHA trajectories obtained with different combinations of formation and drilling parameters.', 'Color-coded NMR measurement quality is consistent between two datasets, even though the simulated trajectories are highly non-uniform.', 'The data in FIG.', '22 shows that the amount of signal loss is dependent on tool motion velocity and amplitude.', 'Therefore, NMR measurement quality under motion may be estimated by plotting motion properties, corresponding to the dots onto the predefined NMR measurement quality map, the squares, without knowing the exact trajectory of the tool motion.'] |
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US11091686 | Compositions and methods for completing subterranean wells | Jan 7, 2016 | Quentin Barral, Nicolas Droger, Slaheddine Kefi, Loic Regnault De La Mothe | SCHLUMBERGER TECHNOLOGY CORPORATION | Heathman et al. (US H1932 H) (Year: 2001).; Daccord et al., “Mud Removal”, Well Cementing—2nd Edition, Houston: Schlumberger, pp. 183-187, 2006.; International Search Report and Written Opinion issued in International Patent Application No. PCT/EP2016/000009 dated Mar. 11, 2016; 10 pages.; Search Report issued in European Patent Appl. No. 15290015.5 dated Jun. 2, 2015; 5 pages. | 5830831; November 3, 1998; Chan et al.; 6035936; March 14, 2000; Whalen; 7618926; November 17, 2009; Pakulski; 20030166472; September 4, 2003; Pursley; 20060073986; April 6, 2006; Jones et al.; 20080274918; November 6, 2008; Quintero; 20090008091; January 8, 2009; Quintero et al.; 20090200033; August 13, 2009; Kakadjian et al.; 20110024113; February 3, 2011; Chen; 20130261033; October 3, 2013; Nguyen | 01/42387; June 2001; WO | No images available | ['Well treatment compositions comprise water, a lipophilic anionic surfactant, a hydrophilic non-ionic surfactant, a second non-ionic surfactant, a water-solubilizing solvent, a water-immiscible solvent and a lipophilic non-ionic surfactant.', 'Optionally, a second solvent may be incorporated.', 'When added to spacer fluids, chemical washes or both, the compositions promote the removal of non-aqueous drilling fluids from casing surfaces.', 'Additionally, the treated casing surfaces are water wet, thereby promoting optimal bonding to cement.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThe statements in this section merely provide background information related to the present disclosure and may not constitute prior art.', 'This disclosure relates to compositions and methods for completing, subterranean wells, in particular, fluid compositions and methods for completion operations during which the fluid compositions are pumped into a wellbore and make contact with subterranean rock formations.', 'In the course of completing oil and gas wells and the like, various types of fluids are circulated in the wellbore.', 'These fluids include, but are not limited to, drilling fluids, spacer fluids, cement slurries and gravel-packing fluids.', 'In addition, these fluids typically contain solid particles.', 'Cement slurries are usually incompatible with most drilling fluids.', 'If the cement slurry and drilling fluid commingle, a highly viscous mass may form that can cause several problems.', 'Cement slurry can channel through the viscous mass.', 'Unacceptably high friction pressures can develop during the cement job.', 'Plugging of the annulus can result in job failure.', 'In all of these situations, zonal isolation may be compromised, and expensive remedial cementing may be required.', 'Consequently, intermediate fluids called preflushes are often pumped as buffers to prevent contact between cement slurries and drilling fluids.', 'Preflushes can be chemical washes that contain no solids or spacer fluids that contain solids and can be mixed at various densities.', 'Chemical washes are preflushes with a density and a viscosity very close to that of water or oil.', 'The simplest chemical wash is fresh water; however, for more efficient drilling-fluid thinning and dispersion, chemical washes that contain dispersants and surfactants are more commonly used.', 'Spacers are preflushes with carefully designed densities and rheological properties.', 'Spacers are more complicated chemically than washes.', 'Viscosifiers are necessary to suspend the solids and control the rheological properties, and usually comprise water-soluble polymers, clays or both.', 'Other chemical components include dispersants, fluid-loss control agents, weighting agents, antifoam agents and surfactants.', 'A thorough discussion concerning the uses and compositions of preflushes may be found in the following publication.', 'Daccord G, Guillot D and Nilsson F: “\nMud Removal\n,” in Nelson E B and Guillot D (eds.):', 'Well Cementing—\n2\nnd \nEdition, Houston: Schlumberger (2006) 183-187.', 'A third option is to use a sacrificial volume of cement slurry, known as a scavenger slurry.', 'The scavenger slurry mixes with the drilling fluid (and will have degraded properties) ahead of the useful volume of cement slurry.', 'For optimal fluid displacement, the density of a spacer fluid should usually be higher than that of the drilling fluid and lower than that of the cement slurry.', 'Furthermore, the viscosity of the spacer fluid is usually designed to be higher than the drilling fluid and lower than the cement slurry.', 'The spacer fluid must remain stable throughout the cementing process (i.e., no free-fluid development and no sedimentation of solids).', 'In addition, it may be necessary to control the fluid-loss rate.', 'Another important function of preflushes is to leave the casing and formation surfaces water wet, thereby promoting optimal bonding with the cement.', 'Achieving water-wet surfaces may be challenging, especially when the drilling fluid has been non-aqueous.', 'Such non-aqueous fluids (NAF) may be oil-base muds or emulsion muds whose external phase is oil-base.', 'For these circumstances, special dispersant and surfactant systems have been developed by the industry.', 'Designing a dispersant/surfactant system for a particular well may be complicated because several parameters must be considered, including the base oil of the NAF, the presence of emulsifiers, the fluid density, bottomhole temperature, presence of brine salts and the chemical nature of the cement system.', 'SUMMARY', 'In an aspect, embodiments relate to well treatment compositions, comprising water, a lipophilic anionic surfactant, a hydrophilic non-ionic surfactant, a second non-ionic surfactant, a water-solubilizing solvent, a water-immiscible solvent and a lipophilic non-ionic surfactant.', 'In a further aspect, embodiments relate to methods for treating a subterranean well having at least one casing string, comprising preparing an aqueous spacer fluid, chemical wash or both and adding a well treatment composition to the fluid, wash or both.', 'The composition comprises water, a lipophilic anionic surfactant, a hydrophilic non-ionic surfactant, a second non-ionic surfactant, a water-solubilizing solvent, a water-immiscible solvent and a lipophilic non-ionic surfactant.', 'Then the fluid, wash or both containing the composition are placed in the well such that the fluid, wash or both flow past the external surface of the casing string.', 'DETAILED DESCRIPTION', "At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another.", 'Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.', 'In addition, the composition used/disclosed herein can also comprise some components other than those cited.', 'In the summary and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context.', 'Also, in the summary and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated.', 'For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10.', 'Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possessed knowledge of the entire range and all points within the range.', 'The authors have discovered improved compositions and methods for removing NAF drilling fluids from casing surfaces and leaving the surfaces water wet.', 'In addition, the compositions may provide improved environmental suitability and compliance with local environmental regulations.', 'In an aspect, embodiments relate to well treatment compositions.', 'The compositions comprise water, a lipophilic anionic surfactant, a hydrophilic non-ionic surfactant, a second non-ionic surfactant, a water-solubilizing solvent, a water-immiscible solvent and a lipophilic non-ionic surfactant.', 'The water concentration may be between 5 and 50 wt %, or may be between 7 and 30 wt %.', 'The lipophilic anionic surfactant concentration may be between 1 and 75 wt %, or may be between 3 and 40 wt %.', 'The hydrophilic non-ionic surfactant concentration may be between 1 and 75 wt %, or may be between 3 and 20 wt %.', 'The second non-ionic surfactant concentration may be between 1 and 75 wt %, or may be between 3 and 50 wt %.', 'The water-solubilizing solvent concentration may be between 3 and 75 wt %, or may be between 15 and 60 wt %.', 'The water-immiscible solvent concentration may be between 3 and 75 wt % or may be between 15 and 60 wt %.', 'The lipophilic non-ionic surfactant concentration may be between 0.5 and 30 wt % or may be between 2 and 15 wt %.', 'The concentration ratio between the anionic surfactant and all three non-ionic surfactants may be between 1:10 and 10:1, or may be between 1:4 and 2:1.', 'The anionic surfactant may comprise oil-soluble alkaline, alkaline earth metal and amine salts of dodecylbenzenesulfonic acid, alkylsulfuric acid, alkylsulfonic acid, alpha olefin sulfonic acid, alkyl sulfosuccinic acid, alkyl ether sulfosuccinic acid, alkyl ether sulfuric acid, alkyl ether sulfonic acid, carboxylic acid, lignosulfonic acid, phosphonate esters, phosphate esters, phosphonated polyglycol ethers or phosphated polyglycol ethers or combinations thereof, wherein the hydrophilic/lipophilic balance (HLB) number is below 30.', 'The HLB number may be below 25.', 'The anionic surfactant may have one, two or three alkyl chains or branched alkyl chains or both.', 'The anionic surfactant may comprise an alkyl sulfosuccinate.', 'The hydrophilic non-ionic surfactant may comprise alkoxylated alcohols, alkoxylated mercaptans, alkoxylated alkylphenols, alkoxylated tristyrylphenols, alkoxylated castor oil, alkoxylated esters, alkoxylated diesters, alkoxylated alkylamines, alkoxylated alkylamides, copolymers of polyalkylene glycol, random sorbitan mono- or polyesters, di-block sorbitan mono- or polyesters, tri-block sorbitan mono- or polyesters, ethoxylated sorbitan monoesters, ethoxylated sorbitan polyesters, betaines, hydroxysultaines, taurines, sarcosinates, alkyl imidazolines, amphoacetates, amphoproprionates, amphosulfonates, alkyl polyglucosides, phosphatidylcholines, lipoamino acids, polypeptides, glycolipids, rhamnolipids or flavolipids or combinations thereof, wherein the HLB number is between 12 and 17.', 'The HLB number may be between 13 and 16.', 'The hydrophilic non-ionic surfactant may comprise an alkyl ethoxylate.', 'The second non-ionic surfactant may comprise alkoxylated alcohols, alkoxylated mercaptans, alkoxylated alkylphenols, alkoxylated tristyrylphenols, alkoxylated castor oil, alkoxylated esters, alkoxylated diesters, alkoxylated alkylamines, alkoxylated alkylamides, copolymers of polyalkylene glycol, random sorbitan mono- or polyesters, di-block sorbitan mono- or polyesters, tri-block sorbitan mono- or polyesters, ethoxylated sorbitan monoesters, ethoxylated sorbitan polyesters, betaines, hydroxysultaines, taurines, sarcosinates, alkyl imidazolines, amphoacetates, amphoproprionates, amphosulfonates, alkyl polyglucosides, phosphatidylcholines, lipoamino acids, polypeptides, glycolipids, rhamnolipids or flavolipids or combinations thereof, wherein the HLB number is between 7 and 14.', 'The HLB number may be between 8 and 13.', 'The second non-ionic surfactant may comprise propoxylated and ethoxylated alcohols.', 'Those skilled in the art will recognize that the hydrophilic non-ionic surfactant and the second non-ionic surfactant may be identical, provided their HLB numbers are within their prescribed ranges.', 'The water-solubilizing solvent may comprise linear or branched small chain alcohols according to the formula C\nx\nH\n(2x+1)', 'OH with x below 7, glycol ethers, dioxolanes, hydroxypyrrolidones, dimethylsulfoxide, dimethylformamide, acetic acid, acetone or amines or combinations thereof.', 'The water-solubilizing solvent may comprise glycol ether.', 'The water-solubilizing solvent may comprise butoxyethanol.', 'The water-immiscible solvent may comprise mineral oil, aliphatic hydrocarbons, aromatic hydrocarbons or both.', 'The lipophilic non-ionic surfactant may comprise cocamide diethanolamide, alkoxylated alcohols, alkoxylated mercaptans, alkoxylated alkylphenols alkoxylated tristyrylphenols, alkoxylated castor oil, alkoxylated esters, alkoxylated diesters, alkoxylated alkylamines, alkoxylated alkylamides, copolymers of polyalkylene glycol, random sorbitan mono- or polyesters, di-block sorbitan mono- or polyesters, tri-block sorbitan mono- or polyesters, ethoxylated sorbitan monoesters, ethoxylated sorbitan polyesters, betaines, hydroxysultaines, taurines, sarcosinates, alkyl imidazolines, amphoacetates, amphoproprionates, amphosulfonates, alkyl polyglucosides, phosphatidylcholines, lipoamino acids, polypeptides, glycolipids, rhamnolipids or flavolipids or combinations thereof, wherein water solubility is less than 1 g per liter.', 'For applications where the drilling fluid base oil is paraffinic or olefinic, the composition may further comprise a second solvent comprising branched long-chain alcohols according to the formula C\nx\nH\n(2x+1)', 'OH with x above 4, propoxylated alcohols, terpenes, pyrrolidones, pyrrolidines, aromatic solvents or halogenated solvents or combinations thereof.', 'The second solvent may comprise 2-ethyl-hexan-1-ol.', 'The second solvent concentration may be between 5 and 50 wt %, or between 10 and 40 wt %.', 'In a further aspect, embodiments relate to methods for treating a subterranean well having at least one casing string.', 'The method comprises preparing an aqueous spacer fluid, chemical wash or both and adding a well treatment composition to the fluid, wash or both.', 'The composition comprises water, a lipophilic anionic surfactant, a hydrophilic non-ionic surfactant, a second non-ionic surfactant, a water-solubilizing solvent, a water-immiscible solvent and a lipophilic non-ionic surfactant.', 'Then the fluid, wash or both containing the composition are placed in the well such that the fluid, wash or both flow past the external surface of the casing string.', 'Details concerning the various compositional components and compositional ratios, including a second solvent, have been described previously.', 'The concentration of the composition in the fluid, wash or both may be between 0.25 and 20 wt %, or between 2.5 and 10 wt %.', 'Further illustration of the disclosure is provided by the following examples.', 'EXAMPLES\n \nAs discussed earlier, effective NAF removal from casing and wellbore surfaces promotes cementing success.', 'Four laboratory methods were used for evaluating the performance of the disclosed compositions, and the methods pertain to the present examples.', 'The first method was a rotor test to evaluate the ability of chemical-wash compositions to remove NAF from casing surfaces at a temperature of 66 deg C.', '[150 deg F.].', 'Unless otherwise noted, the chemical wash solutions were prepared by diluting 10 vol % of the surfactant-solvent composition in water (unsalted case) or water with mass fraction of 5% KCl (5% KCl case).', 'The test equipment was a Chan 35™ rotational rheometer, available from Chandler Engineering, Tulsa, Okla., USA.', 'The rheometer was equipped with a cup with an 85-mm diameter.', 'Two closed rotors, each 76.4 mm high and 40.6 mm in diameter, were employed to simulate the casing surface and provide an evaluation of test repeatability.', 'Both rotors had a sand blasted stainless-steel surfaces with an average roughness of 1.5 μm.', 'A NAF was prepared and sheared at 6000 RPM in a Silverson mixer for 30 minutes, followed by a 16-hour aging period in a rolling oven at the desired test temperature.', 'The NAF was then transferred to one of the Chan 35™ rheometer cups preheated at the test temperature of 66 deg C.', '[150 deg F.].', 'A test rotor was weighted (w\n0\n) and then lowered into the NAF to a depth of 50 mm.', 'The rotor was then rotated within the NAF for one minute at 100 RPM and then left to soak in the NAF for five minutes.', 'Next, the rotor was removed from the NAF and left to drain for two minutes.', 'The bottom of the rotor was wiped clean and then weighed (w\n1\n).', 'The rotor was then remounted on the rheometer and immersed in a cup containing the chemical wash at 66 deg C.', '[150 deg F.] such that the NAF layer was just covered by the chemical wash.', 'The rotor was rotated for 10 minutes at 100 RPM.', 'The rotor when then removed from the chemical wash and left to drain for two minutes.', 'The bottom of the rotor was wiped clean and weighed (w\n2\n).', 'The NAF removal efficiency R was then determined by Eq. 1.\n \n \n \n \n \n \n \n \nR\n \n=\n \n \n \n \nw\n \n1\n \n \n-\n \n \nw\n \n2\n \n \n \n \n \nw\n \n1\n \n \n-\n \n \nw\n \n0\n \n \n \n \n \n \n \n \n(\n \n \nEq\n \n.', '\u2062\n \n1\n \n \n)', 'The tests were repeated at least twice, and the results were averaged to obtain a final result.', 'Rotor surface wettability is estimated by placing a droplet of water on the surface after cleaning and measuring contact angle.', 'It is desirable to achieve an R value higher than 75% with a water-wet surface (contact angle lower than 30°).', 'The second method involved spacer fluids containing the disclosed compositions, and determined the amount of spacer fluid necessary to invert a NAF emulsion, causing the external phase to become aqueous.', 'The method used a Waring blender equipped with a glass bowl.', 'The glass bowl was modified such that two electrodes were placed horizontally across the glass wall.', 'The distance between the electrodes was 2.4 cm.', 'The electrodes were connected to AC current through a potentiometer.', 'The method consisted of the following steps.', '1.', 'The spacer fluid and NAF were conditioned separately in atmospheric consistometers at the desired test temperature for 30 minutes.', '2. 400 mL of spacer fluid were poured into the glass bowl and mixed at 1000 RPM.', '3.', 'The electrical current between the electrodes immersed in the spacer fluid was adjusted to be 3 mA.\n \n4.', 'The glass bowl was emptied and cleaned.', '5. 400 mL of NAF were poured into the glass bowl and mixed at 1000 RPM.', '6. Spacer fluid was added incrementally to the NAF in the glass bowl.', 'After each addition, a 14-mL sample was collected for measuring rheological properties with a Malvern Bohlin rheometer.', 'As the spacer was added, the conductivity of the fluid was continuously measured.', 'When the conductivity of the test fluid reached 1.5 mA, the NAF was considered to have converted from a resistive fluid to a conductive fluid.', 'Under these conditions, in the absence of solvent or surfactant in the spacer fluid, the inversion regularly occurs at a spacer/NAF ratio of about 55/45.', 'Achieving inversion at spacer/NAF ratios below 35/65 is desirable.', 'The third method was a rheological compatibility evaluation between the NAF and the spacer fluid.', 'The viscosities of both pure fluids at a shear rate of 170 s\n−1 \nwere first determined.', 'As described earlier, samples of spacer-fluid/NAF ratio mixtures were gathered during the NAF stability testing.', 'The viscosity of each sample was determined and compared to the higher value between pure NAF viscosity and pure spacer viscosity.', 'The difference between the mixture and pure viscosities (mixture minus pure) is called the “R-index.”', 'The highest R-index that occurs across the spacer-fluid/NAF ratio spectrum is called the “absolute R-index.”', 'The lower the absolute R-index, the more compatible the fluids are.', 'In case, all sample viscosities are lower than pure NAF viscosity and pure spacer viscosity, a negative R-index is determined by taking the difference between the lowest sample viscosity and the lower value between pure NAF viscosity and pure spacer viscosity.', 'Achieving an absolute R-index between −10 and +10 is desirable.', 'The fourth method was the measurement of the effect of the disclosed compositions on cement slurry thickening time.', 'The cement slurry density was 1970 kg/m\n3 \n(16.4 lbm/gal).', 'The composition was Lehigh Class', 'H+25 g/L potassium chloride+3', 'g/L sodium polynaphthalene sulfonate+3.7 g/L polypropylene glycol+7 g/L D177 UNISET retarder (available from Schlumberger)+40 g/L D168 UNIFLAC fluid loss control agent (available from Schlumberger).', '600 mL of base slurry were prepared in a Waring blender.', 'The spacer fluid and cement slurry were conditioned separately in atmospheric consistometers at the desired test temperature for 30 minutes.', '540 mL of cement slurry and 60 mL of spacer were both mixed with a spatula (90% of cement volume mixed with 10% of spacer volume).', 'Thickening-time tests were performed according to the recommended procedure published in the following document—Recommended Practice for Testing Well Cements, ANSI/API Recommended Practice 10B-2, 1st Edition, Washington D.C.:', 'American Petroleum Institute (2005).', 'The relative difference of thickening time at 100 Bc, consistency is evaluated between spacer-contaminated cements with or without the surfactant-solvent spacer additive.', 'Achieving a relative difference of thickening time lower than 10% is desirable.', 'In the present examples, one non-aqueous (NAF) drilling fluids was used: RHELIANT™ (Synth. B), available from M-I SWACO, Houston, Tex., USA.', 'The RHELIANT™ (Synth. B) formulation was based on synthetic oil (Synthetic B from M-I SWACO), with a 77/23 oil/water ratio.', 'The drilling fluid was weighted with barite to a density of 1600 kg/m\n3 \n(13.4 lbm/gal).', 'The two spacer fluids that were tested in the present examples were MUDPUSH™ II spacer fluids, available from Schlumberger, one with a mass fraction of 5% by weight of water of potassium chloride in water (5% KCl case), the other one without potassium chloride (unsalted case), both weighted with barite to a density of 1740 kg/m\n3 \n(14.5 lbm/gal).', 'Unless otherwise noted, the spacer solutions were prepared by diluting 10 vol % of the surfactant-solvent composition in MUDPUSH™ II spacer fluids.', 'Example 1\n \nThe following surfactant-solvent blend was prepared in a beaker with a magnetic stirrer, and agitated until the solution was homogeneous.\n \n5 wt % sodium dioctylsulfosuccinate in glycol-water solution (Geropon™ DOS PG, available from Rhodia).', '13 wt % branched alcohol EO/PO (Antarox™ LA-EP 16, available from Rhodia)\n \n10 wt % water\n \n46 wt % solketal\n \n28 wt % mineral oil (Exxsol™ D100, available from ExxonMobil Chemical)\n \n3 wt % cocamide diethanolamide (Mackamide™ C5 available from Rhodia)', 'Geropon™ DOS PG is an anionic surfactant with an HLB of 23.', 'Antarox™ LA-EP 16 is a non-ionic surfactant with an HLB of 13.1.', 'Solketal is a mutual solvent.', 'Mackamide C5 is a non-ionic surfactant with a water solubility of 15-30 mg/L.\n \nRotor tests (unsalted and 5% KCl cases) conducted with the drilling fluid had the following results.', 'RHELIANT™ (Synth B): R=94% (unsalted case) and 75% (5% KCl case), both with final rotor surfaces being water-wet.', 'An emulsion inversion test was performed with the unsalted MUDPUSH II spacer in contact with the RHELIANT™ (Synth B) drilling fluid.', 'The emulsion inverted when the spacer/drilling-fluid ratio was 25/75.', 'Another stability test was performed with 5% KCl MUDPUSH, II spacer in contact with the RHELIANT™ (Synth B) drilling fluid.', 'The emulsion inverted when the spacer/drilling-fluid ratio was 35/65.\n \nRheological compatibility tests were performed.', 'The absolute R-indices associated with the unsalted and salted spacers were −3 and −2, respectively.', 'For the salted case, the influence of the surfactant-solvent blend on the cement thickening time is shown in Table 1.\n \n \n \n \n \n \n \n \nTABLE 1\n \n \n \n \n \n \n \n \nEffect of surfactant-solvent combination on cement slurry thickening time\n \n \n \n(salted case).', 'Thickening Time @ \n \n \n \n \n55° C. (131° F.)\n \n \n \n \n \n \n \n \n \n \n \n30 Bc\n \n100 Bc\n \n \n \n \n(hr:min)\n \n(hr:min)\n \n \n \n \n \n \nNo surfactant-\n \n3:15\n \n3:52\n \n \n \nsolvent\n \n \n \n \n \n90% Cement\n \n5:40\n \n6:08\n \n \n \ncontaminated with 10% salted\n \n \n \n \n \nspacer without surfactant-\n \n \n \n \n \nsolvent\n \n \n \n \n \n90% Cement\n \n5:15\n \n6:06\n \n \n \ncontaminated with 10% salted\n \n \n \n \n \nspacer with 3 gal/bbl surfactant-\n \n \n \n \n \nsolvent\n \n \n \n \n \n \n \n \n \n \nExample 2\n \nThe following surfactant-solvent blend was prepared in a beaker with a magnetic stirrer, and agitated until the solution was homogeneous.', '5 wt % Geropon™ DOS PG\n \n13 wt', '% Antarox™ LA-EP 16\n \n10 wt % water\n \n46 wt % butoxyethanol\n \n28 wt %', 'Exxsol™ D100\n \n3 wt % Mackamide™ C5\n \nButoxyethanol is a mutual solvent.', 'Rotor tests (unsalted and 5% KCl cases) conducted with the drilling fluid had the following results.', 'RHELIANT™ (Synth B): R=89% (unsalted case) and 85% (5% KCl case), both with final rotor surfaces being water-wet.', 'Example 3\n \nThe following surfactant-solvent blend was prepared in a beaker with a magnetic stirrer, and agitated until the solution was homogeneous.', '17 wt % Geropon™ DOS PG\n \n43 wt %', 'Antarox™ LA-EP 16\n \n31 wt % water\n \n9 wt % solketal\n \nRotor tests (unsalted and 5% KCl cases) conducted with the drilling fluid had the following results.', 'RHELIANT™ (Synth B): R=1% (unsalted case) and 0% (5% KCl case), both with final rotor surfaces being oil-wet.', 'Example 4\n \nThe following surfactant-solvent blend was prepared in a beaker with a magnetic stirrer, and agitated until the solution was homogeneous.', '8.5 wt % Geropon™', 'DOS PG\n \n21.5 wt % Antarox™ LA-EP', '16\n \n15.5 wt % water\n \n54.5 wt % solketal\n \nRotor tests (unsalted and 5% KCl cases) conducted with the drilling fluid had the following results.', 'RHELIANT™ (Synth B): R=0% (unsalted case) and 0% (5% KCl case), both with final rotor surfaces being oil-wet.', 'Example 5\n \nThe following surfactant-solvent blend was prepared in a beaker with a magnetic stirrer, and agitated until the solution was homogeneous.', '5 wt % Geropon™ DOS PG\n \n13 wt', '% Antarox™ LA-EP 16\n \n10 wt % water\n \n36 wt % solketal\n \n36 wt %', 'Exxsol™ D100\n \nRotor test conducted with the drilling fluid had the following results.', 'RHELIANT™ (Synth B): R=15% (5% KCl case), with final rotor surface being oil-wet.', 'Example 6\n \nThe following surfactant-solvent blend was prepared in a beaker with a magnetic stirrer, and agitated until the solution was homogeneous.', '8.5 wt % Geropon™', 'DOS PG\n \n21.5 wt % Antarox™ LA-EP 16\n \n20 wt % water\n \n45 wt %', 'Exxsol™ D100\n \n5 wt % Mackamide™ C5\n \nRotor test conducted with the drilling fluid had the following results.', 'RHELIANT™ (Synth B): R=6% (5% KCl case), with final rotor surface being oil-wet.', 'Example 7\n \nThe following surfactant-solvent blend was prepared in a beaker with a magnetic stirrer, and agitated until the solution was homogeneous.', '50 wt % butoxyethanol\n \n45 wt %', 'Exxsol™ D100\n \n5 wt % Mackamide™ C5\n \nRotor tests (unsalted and 5% KCl cases) conducted with the drilling fluid had the following results.', 'RHELIANT™ (Synth B): R=90% (unsalted case) and 42% (5% KCl case), both with final rotor surfaces being oil-wet.'] | ['1.', 'A method for removing non-aqueous fluids from a subterranean well having at least one casing string, comprising:\ni. preparing an aqueous spacer fluid, a chemical wash, or both;\nii.', 'adding a well treatment composition to the aqueous spacer fluid, the chemical wash, or both, the well treatment composition comprising: (a) water; (b) a lipophilic anionic surfactant; (c) a first hydrophilic non-ionic surfactant; (d) a second hydrophilic non-ionic surfactant; (e) a water-solubilizing solvent; (f) a water-immiscible solvent; and (g) a lipophilic non-ionic surfactant;\niii. placing the aqueous spacer fluid, the chemical wash or both containing the well treatment composition in the well such that the aqueous spacer fluid, the chemical wash, or both, flow past the external surface of the casing string, wherein the well treatment composition is homogeneous.', '2.', 'The method of claim 1, wherein the concentration of the well treatment composition in the aqueous spacer fluid, the chemical wash, or both is between 0.25% and 20% by weight.', '3.', 'The method of claim 1, wherein the lipophilic anionic surfactant comprises oil-soluble alkaline, alkaline earth metal and amine salts of dodecylbenzenesulfonic acid, alkylsulfuric acid, alkylsulfonic, acid, alpha olefin sulfonic acid, alkyl sulfosuccinic acid, alkyl ether sulfosuccinic acid, alkyl ether sulfuric acid, alkyl ether sulfonic acid, carboxylic acid, lignosulfonic acid, phosphonate esters, phosphate esters, phosphonated polyglycol ethers or phosphated polyglycol ethers or combinations thereof, wherein the HLB number is below 30;\nwherein the hydrophilic non-ionic surfactant comprises alkoxylated alcohols, wherein the HLB number is between 12 and 17.', '4.', 'The method of claim 1, wherein the second hydrophilic non-ionic surfactant comprises alkoxylated alcohols, wherein the HLB number is between 7 and 14; wherein the water-solubilizing solvent comprises linear small chain alcohols according to the formula CxH(2x+1)OH with x below 7.\n\n\n\n\n\n\n5.', 'The method of claim 1, wherein the water-immiscible solvent comprises aliphatic hydrocarbons.', '6.', 'The method of claim 1, wherein the lipophilic non-ionic surfactant comprises alkoxylated alcohols having a water solubility lower than 1 g per liter.', '7.', 'The method of claim 1, wherein the well treatment composition further comprises a second solvent comprising branched long-chain alcohols according to the formula CxH(2x+1)OH with x above 4, propoxylated alcohols, terpenes, pyrrolidones, pyrrolidines, aromatic solvents or halogenated solvents, or combinations thereof.', '8.', 'The method of claim 1, wherein a concentration ratio between the lipophilic anionic surfactant and all three non-ionic surfactants is between 1:10 and 10:1.\n\n\n\n\n\n\n9.', 'The method of claim 1, wherein a concentration ratio between the lipophilic anionic surfactant and all three non-ionic surfactants is between 1:4 and 2:1.\n\n\n\n\n\n\n10.', 'The method of claim 1, wherein the first hydrophilic non-ionic surfactant comprises a first HLB number, and the second hydrophilic non-ionic surfactant comprises a second HLB number that is different than the first HLB number.', '11.', 'The method of claim 1, wherein a first concentration of the water is between 5 and 50% by weight, wherein a second concentration of the lipophilic anionic surfactant is between 1 and 75% by weight, wherein a third concentration of the first hydrophilic non-ionic surfactant is between 1 and 75% by weight, wherein a fourth concentration of the second hydrophilic non-ionic surfactant is between 1 and 75% by weight, wherein a fifth concentration of the water-solubilizing solvent is between 3 and 75% by weight, wherein a sixth concentration of the water-immiscible solvent is between 3 and 75% by weight, and wherein a seventh concentration of the lipophilic non-ionic surfactant is between 0.5 and 30% by weight.'] | ['No Captions Available'] |
USD930034 | Display screen or portion thereof with graphical user interface | Jan 22, 2019 | Benoit Foubert, Staffan Karl Eriksson, Muhsen Al-Qubaisi | Schlumberger Technology Corporation | “VERIFi”, Sep. 26, 2015, posted at thechargepoint.com, [site visited Jun. 16, 2020]. http://web.archive.org/web/20150926120945/http://www.thechargepoint.com/technology/verifi (Year: 2015).; “Imperial iManifold—Smart Phone & Tablet Compatible HVAC Digital Manifold”, May 7, 2014, posted at youtube.com, [site visited Jun. 16, 2020]. https://www.youtube.com/watch?v=n0T_Ed6i-Yc (Year: 2014). | D307127; April 10, 1990; Simons; 7143363; November 28, 2006; Gaynor; D688680; August 27, 2013; Fleischmann; D701226; March 18, 2014; Jung; D703689; April 29, 2014; Kim; D748126; January 26, 2016; Sarukkai; D753176; April 5, 2016; Barbato; D760244; June 28, 2016; Lv; D771103; November 8, 2016; Eder; D775658; January 3, 2017; Luo; D777200; January 24, 2017; Luo; D786304; May 9, 2017; Cronin; D795900; August 29, 2017; Bischoff; D798311; September 26, 2017; Golden; D800769; October 24, 2017; Hennessy; D808983; January 30, 2018; Narinedhat; D809535; February 6, 2018; Park; D824417; July 31, 2018; Narinedhat; D829739; October 2, 2018; Lavin, Jr.; D869477; December 10, 2019; Yoon; D878391; March 17, 2020; Zeng; 10794153; October 6, 2020; Meehan; 20070136679; June 14, 2007; Yang; 20130345978; December 26, 2013; Lush; 20140028682; January 30, 2014; Omiya; 20180106134; April 19, 2018; Meehan | Foreign Citations not found. | ['No Abstract Available'] | ['Description\n\n\n\n\n\n\n \nFIG.', '1\n is a front view of a display screen or portion thereof with graphical user interface in a first embodiment showing the first image in a sequence of our new design;\n \nFIG.', '2\n is a front view of the second image thereof;\n \nFIG.', '3\n is a front view of the third image thereof;\n \nFIG.', '4\n is a front view of a display screen or portion thereof with graphical user interface in a second embodiment showing the first image in a sequence of our new design;\n \nFIG.', '5\n is a front view of the second image thereof; and,\n \nFIG.', '6\n is a front view of the third image thereof.', 'The broken lines in the drawings illustrate a display screen or portions thereof or environment and form no part of the claimed design.', 'The appearance of the transitional image sequentially transitions between the images shown in \nFIGS.', '1-3\n and in \nFIGS.', '4-6\n.', 'The process or period in which one image transitions to another image forms no part of the claimed design.'] | ['The ornamental design for a display screen or portion thereof with graphical user interface, as shown and described.'] | ['FIG.', '1 is a front view of a display screen or portion thereof with graphical user interface in a first embodiment showing the first image in a sequence of our new design;; FIG.', '2 is a front view of the second image thereof;; FIG.', '3 is a front view of the third image thereof;; FIG. 4 is a front view of a display screen or portion thereof with graphical user interface in a second embodiment showing the first image in a sequence of our new design;; FIG.', '5 is a front view of the second image thereof; and,; FIG.', '6 is a front view of the third image thereof.'] |
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US11097929 | Top-mounted hoist for use in a derrick or drilling mast of an oil and gas rig | Mar 11, 2019 | Dag Holen, Erling Tambs, Rolf Gullaksen | Schlumberger Technology Corporation | NPL References not found. | 4393944; July 19, 1983; Gugger; 4872517; October 10, 1989; Shaw; 5107940; April 28, 1992; Berry; 6056060; May 2, 2000; Abrahamsen; 20050077049; April 14, 2005; Moe; 20160060976; March 3, 2016; Plain; 20160060977; March 3, 2016; Plain; 20160137466; May 19, 2016; Eriksson et al.; 20180305982; October 25, 2018; Aas; 20180313173; November 1, 2018; McBeath; 20190071938; March 7, 2019; Taraldrud | Foreign Citations not found. | ['Embodiments of a top-mounted hoisting system include a single-layer winch drum located at an uppermost end of a derrick or drilling mast, a drill string handling tool, and one or more drill lines extending from the single layer winch drum to the drill string handling tool.', 'The drill string handling tool may be a top drive.', 'When the drill line is connected directly to the lifted load, the drill line experiences far less load cycles than when the line runs through crown and travelling blocks.', 'If the drum diameter is large enough, cut-and-slip operations may be eliminated, and the drill line may be replaced at longer time intervals.', 'Embodiments provide for lower weight and may provide lower cost as a result.', 'The top-mounted drum does not take up any space on the drill floor and less total length of drill line is also required than if the drum was floor-mounted.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'The present disclosure relates to drawworks used in a derrick or a drilling mast of an oil or gas drilling rig.', 'More particularly, the disclosure relates to the drawworks winch and winch drum, and how these are connected to the lifted load.', 'The drawworks of an oil or gas drilling rig typically includes a large-diameter steel spool or winch drum, brakes, a power source, and assorted auxiliary devices.', 'The primary function of the drawworks is to reel out and reel in the drill line in a controlled fashion.', 'The drill line may be a ¾ inch to 2¼ inch (19 mm to 57 mm) diameter, multi-thread, twisted wire rope.', 'The wire rope may include a polymer or plastic insert.', 'The drill line spooled on the winch drum is reeled over a hoist that includes a plurality of sheaves to gain mechanical advantage in a block-and-tackle or pulley fashion.', 'The sheaves may be located in a crown block located toward a top end of the drilling mast and in a traveling block located below the crown block.', 'This reeling out and in of the drill line causes the traveling block, and whatever may be hanging underneath it, to be lowered into or raised out of the wellbore.', 'The reeling out of the drill line may be powered by gravity and reeling in may be powered by an electric or hydraulic motor or a diesel engine connected to the winch drum\n \nAs a precaution against drill line failure due to fatigue, the work done by the drill line is closely monitored and limited.', 'The work is commonly measured as the cumulative product of the load lifted (e.g., in tons) and the distance lifted or lowered (e.g., in miles).', 'After a predetermined limit of ton-miles, slip-and-cut operations are performed.', 'New drill line is unspooled from a storage reel and slipped through the crown block and traveling block sheaves and the winch drum, with the excess on the drum end cut off and discarded.', 'Slip-and-cut operations can become more difficult as drill line diameter increases and can be very difficult at or above 2¼ inch (57 mm) drill line.', 'As load lifting requirements increase—for example, greater than 1250 tons to 1500 tons or more—drill line could increase above 2¼ inch.', 'The winch drum is drill- or rig-floor mounted, taking up valuable space on the floor.', 'When floor-mounted, the mast must typically support additional loads from the drill line running from the drawworks to the mast top (fast line) and the dead end running back down to the dead line anchor.', 'Additionally, the winch drum usually includes multiple layers of drill line wrapped about it.', 'The overlying layers of drill line place significant force on the underlying layers when under load, further increasing wear and tear.', 'Further, in order to lift the load, the drill line runs through the crown and travelling blocks through a number of sheaves, typically 8-16 times faster than the lifted load, leading to a short drill line fatigue life.', 'US 2016/0137466 A1 to Eriksson (National Oilwell Varco Norway AS) attempts to reduce the wear-and-tear problem by providing a single-layer, helical grooved, winch drum.', 'A single-layer drum can deliver constant line speed.', 'When the single layer winch is connected directly to the lifted load, wire tension is also the same as the lifted load.', 'So, due to this, we may need several drill lines in parallel to take the load.', 'When the drill line is connected directly to the load, it will go through much less load cycles, and with a large drum, the fatigue life of the drill line can be several years, even with intense use.', 'However, the prior art single-layer winch is still floor-mounted below the hoist or sheaves.', 'When the single layer winch is floor mounted, the derrick or mast must resist two times the hook load.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining or limiting the scope of the claimed subject matter as set forth in the claims.', 'Embodiments of a top-mounted hoisting system of this disclosure comprise a drawworks winch including a single-layer winch drum located at an uppermost end of a derrick or drilling mast, a drill string handling tool, and one or more drill lines extending from the single layer winch drum to the drill string handling tool, wraps of each drill line about the drum being on the same level as the wraps of the other drill lines.', 'The drum may include electric or hydraulic motors.', 'In some embodiments, the drill string handling tool may be a top drive.', 'The one or more drill lines may be connected to a guide dolly containing the top drive.', 'In embodiments in which two or more drill lines extend from the winch drum, the top-mounted hoisting system includes equalizers configured to equalize line pull.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a side elevation view of a derrick or drilling mast including an embodiment of a top-mounted hoisting system of this disclosure.', 'FIG.', '2\n is a side elevation view of the top-mounted hoist of \nFIG.', '1\n.', 'FIGS.', '3A and 3B\n are enlarged views of section \n3\n of \nFIG.', '2\n.', 'The subject disclosure is further described in the following detailed description, and the accompanying drawing and schematic of non-limiting embodiment of the subject disclosure.', 'The features depicted in the figures are not necessarily shown to scale.', 'Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form, and some details of elements may not be shown in the interest of clarity and conciseness.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'Referring to the drawings, embodiments of a top-mounted hoisting system S of this disclosure include a drawworks \n5\n having a single-layer winch drum \n10\n containing a wire rope \n11\n and mounted toward or at the uppermost end \n13\n of a derrick or drilling mast M.', 'Because the drum is single layer, each wrap of the rope \n11\n about the drum \n10\n is at the same level as all other wraps of the rope about the drum \n10\n.', 'The winch drum \n10\n may be powered by a plurality of motors \n15\n connected to gears \n31\n.', 'Gears \n31\n may include a gearbox connected to an internal tooth ring on each side of the drum.', 'The winch drum \n10\n may include spaced apart sections \n10\nA, each section \n10\nA containing wire rope \n11\n.', 'The wire rope \n11\n may provide one or more drill lines \n17\n that extend downward from the drum \n10\n to support a drill string handling tool T configured to rotate a drill string.', 'For example, a first drill line \n17\n may be wrapped in a single layer about one section \n10\nA of the drum \n10\n and a second drill line \n17\n may be wrapped about another different section \n10\nA of the drum \n10\n.', 'An end \n27\n of the drill line \n17\n is directly connected to the drill string handling tool T. Clamps or anchors \n29\n may be used to connect the end \n27\n to the tool T.', 'In embodiments, the drill string handling tool T may be a top drive \n19\n.', 'The top drive \n19\n may be connected to a guide dolly \n21\n that rides along a vertically oriented dolly track \n23\n running a length of the mast M.', 'As the drill line \n17\n is reeved in and out, dolly \n21\n (and therefore top drive \n19\n) is moved up and down.', 'The top drive \n19\n may include of one or more electric or hydraulic motors connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drill string itself.', 'The number of drill lines \n17\n for a given application depends, in part, on wire diameter and may be determined using means known in the art.', 'Regardless of the number of lines \n17\n, this top-mounted, single-layer configuration provides longer life for the drill line without the need for slip-and-cut operations.', 'Because of the single-layer, line hoisting may be accomplished with electric motors or hydraulic motors \n15\n.', 'Where multiple drill lines \n17\n extend downward from the drum \n10\n, line equalizers \n25\n of a kind known in the art may be connected toward or at an end \n27\n of the lines \n17\n.', 'Because the drum \n10\n is mounted above the drill string handling tool T, toward or at the uppermost end \n13\n of the derrick or drilling mast M, the mast M must only support the weight of the drum \n10\n and the hook load, the hook load typically being orders of magnitude above the weight of the drum \n10\n.', 'In order to achieve this, a larger diameter drum \n10\n should be used in connection with the single layer.', 'By way of a non-limiting example, in some embodiments the derrick is 160 ft high, the drill string handling tool is 20 ft. long and supported by four 2½ in.', 'lines \n17\n.', 'The drum may have a diameter of approximately 3000 mm to 4000 mm and a length from 1600 mm to 2000 mm to allow for this travel.', 'As persons skilled in the art would recognize, drum size strongly depends on what wire solutions are selected for a given application.', 'For example, the drum must be large enough to allow full travel of the top drive, but the drum length will depend on how the drill line is connected in the dead end, the number of dead wraps, and the amount of separation between each line in a multi-line configuration.', 'If a single-layer winch drum \n10\n was located on the drill floor F, the demand placed on the mast M would be at least twice the hook load.', 'Therefore, embodiments of this disclosure provide for lower weight, and may provide lower cost as a result, compared to prior art systems.', 'Additionally, the top-mounted drum \n10\n does not take up any space on the drill floor F. Less total length of drill line is also required than if the drum was located on the drill floor.', 'Embodiments of a method of this disclosure include supporting a drill string handling tool T by at least one drill line \n17\n wrapped about a single-layer winch drum \n10\n located at an uppermost end \n13\n of a derrick or drilling mast M, one end \n27\n of the at least one drill line \n17\n connected to the drill string handling tool T, all wraps of the at least one drill line \n17\n being on a same level.', 'For example, a first drill line \n17\n may be wrapped in a single layer about one section \n10\nA of the drum \n10\n and a second drill line \n17\n may be wrapped about another different section \n10\nA of the drum \n10\n, the lines \n17\n being a single layer wrap and having an end \n27\n connected to the drill string handling tool T.', 'The method may include actuating the single-layer winch drum \n10\n to vertically raise or lower the drill string handling tool', 'T.', 'The method may also include mounting the single-layer winch drum \n10\n to the uppermost end \n13\n of the derrick or drilling mast M and connecting the end \n27\n of the drill line \n17\n to the drill string handing tool', 'T.', 'The maximum load supported by the derrick or drilling mast M during rotation of the drill string is the weight of the drum plus the hook load.', 'The method (and system) may operate with very high efficiency due to very little loss due to reeving and inertia.', 'While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.', 'Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.', 'The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical.', 'Further, if any claims appended to the end of this specification contain one or more elements designated as “means for” or “step for” performing a function, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f).', 'However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).'] | ['1.', 'A top-mounted hoisting system for use in a derrick or drilling mast, the top-mounted hoisting system comprising:\na single-layer winch drum located at an uppermost end of the derrick or drilling mast;\na first drill line wrapped about a section of the single-layer winch drum, all wraps of the first drill line being on a same level;\na drill string handling tool located below the single-layer winch drum;\nan end of the first drill line connected to the drill string handling tool; and\na second drill line wrapped about another section of the single-layer winch drum and having an end connected to the drill string handling tool, all wraps of the second drill line being on a same level,\nwherein the first and second drill lines each include a line equalizer located toward a respective connected end.', '2.', 'The top-mounted hoisting system of claim 1, wherein the drill string handling tool is configured to rotate a drill string.', '3.', 'The top-mounted hoisting system of claim 1, further comprising:\nthe drill string handling tool including a top drive.', '4.', 'The top-mounted hoisting system of claim 3, further comprising:\nthe top drive including a guide dolly configured for vertical displacement along the derrick or drilling mast.', '5.', 'The top-mounted hoisting system of claim 1, further comprising:\nthe single-layer winch drum including at least one electric motor or hydraulic motor.', '6.', 'A top-mounted hoisting system comprising:\na single-layer winch drum located at an uppermost end of a derrick or drilling mast;\na first drill line wrapped about the single-layer winch drum, all wraps of the first drill line being on a same level;\na top drive located below the single-layer winch drum;\nan end of the first drill line connected to the top drive; and\na second drill line wrapped about another section of the single-layer winch drum and having an end connected to a drill string handling tool, all wraps of the second drill line being on a same level,\nwherein the first and second drill lines each include a line equalizer located toward a respective connected end.', '7.', 'The top-mounted hoisting system of claim 6, further comprising:\nthe top drive including a guide dolly configured for vertical displacement along the derrick or drilling mast.', '8.', 'The top-mounted hoisting system of claim 6, further comprising:\nthe single-layer winch drum including at least one electric motor or hydraulic motor.', '9.', 'A method of handling a drill string, the method comprising:\nsupporting a drill string handling tool by a first drill line and a second drill line each wrapped about a single-layer winch drum located at an uppermost end of a derrick or drilling mast,\nwherein respective ends of the first drill line and the second drill line are connected to the drill string handling tool,\nwherein all wraps of the first drill line and the second drill line are on a same level, and\nwherein the first and second drill lines each include a line equalizer located toward the respective connected end.\n\n\n\n\n\n\n10.', 'The method of claim 9, further comprising:\nactuating the single-layer winch drum to vertically raise or lower the drill string handling tool.\n\n\n\n\n\n\n11.', 'The method of claim 9, wherein the drill string handling tool is configured to rotate the drill string.', '12.', 'The method of claim 9, wherein the drill string handling tool includes a top drive.', '13.', 'The method of claim 9, further comprising:\nmounting the single-layer winch drum to the uppermost end of the derrick or drilling mast.'] | ['FIG.', '1 is a side elevation view of a derrick or drilling mast including an embodiment of a top-mounted hoisting system of this disclosure.', '; FIG.', '2 is a side elevation view of the top-mounted hoist of FIG.', '1.; FIGS.', '3A and 3B are enlarged views of section 3 of FIG.', '2.'] |
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US11098540 | Horizontal pipe connection and length detection system | Dec 27, 2019 | Kevin Jonah, Kevin Denness | Schlumberger Technology Corporation | NPL References not found. | 10519729; December 31, 2019; Jonah; 20070221385; September 27, 2007; Braun et al.; 20100135750; June 3, 2010; Tarique; 20110030942; February 10, 2011; Orgeron; 20150240576; August 27, 2015; Dore; 20160060980; March 3, 2016; Magnuson | Foreign Citations not found. | ['A tubular handling apparatus for a drilling system, a method for handling tubulars, and a drilling system.', 'The apparatus includes a first trough configured to receive at least a first tubular and a second tubular, a first skate movable along the first trough and configured to engage a first end of the first tubular, and a second skate movable along the first trough and configured to engage a second end of the second tubular.', 'The first and second skates are configured to push a third end of the first tubular into engagement with a fourth end of the second tubular in the first trough.', 'The apparatus also includes a tongs configured to engage the first and second tubulars in the first trough and apply torque thereto.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a continuation application of U.S. patent application Ser.', 'No. 15/176,701 filed Jun. 8, 2016 which claims priority to United States Patent Application having Ser.', 'No. 62/172,539, which was filed on Jun. 8, 2015.', 'Both applications are incorporated herein by reference in their entirety.', 'BACKGROUND\n \nDrilling operations are conducted on a drill rig that includes a drilling platform located above the drilling location.', 'A derrick is provided on the platform to raise, support, and rotate a drill string.', 'The drill string includes a bottom-hole assembly, which generally includes a drill bit for boring into the ground.', 'As the drilling operation is conducted, drill pipes are connected end-to-end to form the drill string.', 'The drill pipes are provided on a rack and individually rolled onto a horizontal support, such as a catwalk.', 'Both the rack and catwalk are generally located adjacent to the drilling platform with the catwalk being generally positioned perpendicular to the platform.', 'Once on the catwalk, one end of the drill pipe is attached to a hoist connected to the derrick and raised to a vertical position on the drilling platform.', 'The lower end of the tubular is then oriented over the existing drill string and connected to the upper end of thereof.', 'The upper end of the drill pipe is attached to a drilling device, such as a top drive.', 'The drill pipe is then connected to the drill string, forming a continuation thereof, by rotating the drill pipe relative to the drill string, a process known as “making up” the drill pipe.', 'Individual lengths of drill pipe are relatively short, e.g., about 10-15 meters each.', 'To reduce the number of times the drilling device is disconnected from the drill string and a new drill pipe is connected to the drilling device and the upper end of the drill string, the drill pipes may be assembled into stands of two or more pipes prior to being moved over well center.', 'Generally, the pipes in the individual stands are not fully torqued together.', 'The stands of pipe are fully torqued once they are brought into connection with the drill string, e.g., using an iron roughneck.', 'SUMMARY\n \nEmbodiments of the disclosure may provide an apparatus for handling tubulars in a drilling system.', 'The apparatus includes a first trough configured to receive at least a first tubular and a second tubular, a first skate movable along the first trough and configured to engage a first end of the first tubular, and a second skate movable along the first trough and configured to engage a second end of the second tubular.', 'The first and second skates are configured to push a third end of the first tubular into engagement with a fourth end of the second tubular in the first trough.', 'The apparatus also includes a tongs configured to engage the first and second tubulars in the first trough and apply torque thereto.', 'Embodiments of the disclosure may also provide a method for handling tubulars in a drilling system.', 'The method includes receiving a first tubular and a second tubular into a first trough, moving the first and second tubulars together in the first trough using a first skate that engages a first end of the first tubular, and a second skate that engages a second end of the second tubular, connecting together a third end of the first tubular and a fourth end of the second tubular by applying torque thereto, and determining a distance between the first and second skates after connecting together the first and second tubulars.', 'The distance corresponds to a length of the first and second tubulars after being connected together.', 'Embodiments of the disclosure may also provide a drilling system that includes a drilling platform positioned over a well, a V-door extending from the drilling platform, the drilling platform being configured to receive a tubular stand via the V-door, and a catwalk positioned adjacent to the V-door, the V-door being configured to receive the tubular stand from the catwalk.', 'The catwalk includes a first trough configured to receive at least a first tubular and a second tubular, a first skate movable along the first trough and configured to engage a first end of the first tubular, and a second skate movable along the first trough and configured to engage a second end of the second tubular.', 'The first and second skates are configured to push a third end of the first tubular into engagement with a fourth end of the second tubular in the first trough.', 'The catwalk also includes a tongs configured to engage the first and second tubulars in the first trough and apply torque thereto.', 'It will be appreciated that the foregoing summary is intended merely to introduce a subset of the features described below, and therefore is not to be considered exhaustive or otherwise limiting.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThe accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the present teachings and together with the description, serve to explain the principles of the present teachings.', 'In the figures:\n \nFIG.', '1A\n illustrates a plan view of a drilling system including an apparatus for handling tubulars, according to an embodiment.', 'FIG.', '1B\n illustrates a side, elevation view of a portion of the drilling system, according to an embodiment.\n \nFIG.', '1C\n illustrates an end view of a portion of the drilling system, according to an embodiment.\n \nFIG.', '2\n illustrates a flowchart of a method for handling tubulars in a drilling system, according to an embodiment.\n \nFIG.', '3\n illustrates a plan view of the drilling system after tubulars have been loaded into a first trough of the apparatus, according to an embodiment.\n \nFIG.', '4\n illustrates a plan view of the drilling system after the tubulars have been connected together by operation of the apparatus, according to an embodiment.\n \nFIG.', '5\n illustrates a plan view of the drilling system, showing the tubulars being transferred from the second trough to a platform over a well, according to an embodiment.\n \nFIG.', '6\n illustrates a schematic view of a computing system, according to an embodiment.', 'DETAILED DESCRIPTION\n \nReference will now be made in detail to embodiments, examples of which are illustrated in the accompanying drawings and figures.', 'In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the invention.', 'However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details.', 'In other instances, well-known methods, procedures, components, circuits, and networks have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.', 'It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms.', 'These terms are only used to distinguish one element from another.', 'For example, a first object or step could be termed a second object or step, and, similarly, a second object or step could be termed a first object or step, without departing from the scope of the present disclosure.', 'The first object or step, and the second object or step, are both, objects or steps, respectively, but they are not to be considered the same object or step.', 'The terminology used in the description herein is for the purpose of describing particular embodiments and is not intended to be limiting.', 'As used in this description and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise.', 'It will also be understood that the term “and/or” as used herein refers to and encompasses any possible combinations of one or more of the associated listed items.', 'It will be further understood that the terms “includes,” “including,” “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.', 'Further, as used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context.', 'FIG.', '1A\n illustrates a plan view of a drilling system \n100\n, according to an embodiment.', 'The drilling system \n100\n includes a drilling platform \n102\n and an apparatus for handling tubulars, e.g., a catwalk \n104\n.', 'An inclined surface or “V-door” \n103\n may extend between the platform \n102\n and the catwalk \n104\n.', 'The drilling platform \n102\n may support drilling equipment, such as a derrick, drilling device (e.g., top drive, kelly, etc.), slips, and the like.', 'The platform \n102\n may thus be positioned over the well center \n106\n, and may be configured to deploy oilfield tubulars (e.g., drill pipe) into the well, via the well center \n106\n, e.g., as part of a drilling operation.', 'The catwalk \n104\n may be configured to feed stands of two or more of the oilfield tubulars to the drilling equipment.', 'In some embodiments, the oilfield tubulars of the stands may be fully-torqued in the catwalk \n104\n, e.g., in a horizontal orientation, before being fed to the drilling equipment.', 'In the specifically illustrated embodiment, the catwalk \n104\n is configured to handle and connect together two tubulars \n108\n, \n110\n at a time; however, it will be appreciated that in other embodiments, the catwalk \n104\n may be configured to handle three, four, or more tubulars at a time.', 'In an embodiment, the catwalk \n104\n may include a surface \n112\n, in which a first or “make-up” trough \n114\n may be defined, generally in parallel to a second or “main” trough \n116\n.', 'The troughs \n114\n, \n116\n may extend generally from or near a first end \n117\n to or toward a second end \n119\n of the catwalk \n104\n in a lengthwise direction, as shown\n \nA pipe rack \n118\n may be positioned off to one side of the catwalk \n104\n, and may be configured to hold the tubulars \n108\n, \n110\n prior to the tubulars \n108\n, \n110\n being loaded into the catwalk \n104\n, e.g., by inclining the rack \n118\n so as to allow the tubulars \n108\n, \n110\n to move (e.g., roll) into the make-up trough \n114\n by gravity.', 'In some embodiments, the tubulars \n108\n, \n110\n may roll to the side of the surface \n112\n and side indexers may be employed to transfer the tubulars \n108\n, \n110\n to the surface \n112\n.', 'The tubulars \n108\n, \n110\n may thus be held in the rack \n108\n in a generally parallel orientation to the troughs \n114\n, \n116\n.', 'The speed of the indexers may be computer-controlled, e.g., using a processor, as will be described in greater detail below.', 'Prior to entering the rack \n118\n, the tubulars \n108\n, \n110\n may be held in tubs.', 'Further, the make-up trough \n114\n may be positioned in between the rack \n118\n and the main trough \n116\n, such that the tubulars \n108\n, \n110\n fed into the catwalk \n104\n from the rack \n118\n reach the make-up trough \n114\n first.', 'In some embodiments, the rack \n118\n may be configured to hold two unconnected pipes \n108\n, \n110\n generally end-to-end, such that both are fed at the same time into the make-up trough \n114\n, as will be described in greater detail below.', 'In other embodiments, the rack \n118\n may hold one stack or row of tubulars, and may dispense the tubulars \n108\n, \n110\n consecutively into the make-up trough \n114\n.', 'For example, the tubulars \n108\n, \n110\n may each have two ends \n300\n, \n302\n, \n304\n, \n306\n, as shown.', 'In the rack \n118\n and/or in the make-up trough \n114\n, the tubulars \n108\n, \n110\n may be positioned such that ends \n304\n, \n306\n are proximate to one another, while ends \n300\n, \n302\n are distal.', 'The catwalk \n104\n may also include two skates \n120\n, \n122\n and four sets of spinners \n124\n, \n126\n, \n128\n, \n130\n.', 'The skates \n120\n, \n122\n may be movable, generally along a line in the lengthwise direction of the catwalk \n104\n (e.g., between the ends \n117\n, \n119\n), in the make-up trough \n114\n, and may be configured to move the tubulars \n108\n, \n110\n therein.', 'The skates \n120\n, \n122\n may be driven to move by drivers \n132\n, \n133\n, respectively.', 'The drivers \n132\n, \n133\n may be hydraulic, gear-driven, worm drives, etc.', 'The skates \n120\n, \n122\n may be configured to engage an end of the tubulars \n108\n, \n110\n and push the tubulars \n108\n, \n110\n.', 'In some embodiments, one or both of the tubulars \n108\n, \n110\n may also include a clamp or gripping member, which may enable the skate(s) \n120\n, \n122\n to grab and drag or pull one of the tubulars \n108\n, \n110\n.', 'Further, the drivers \n132\n, \n134\n and/or skates \n120\n, \n122\n may be provided with an encoder or another measurement device configured to track a position of the skate \n120\n, \n122\n, e.g., relative to the other.', 'The position of the skates \n120\n, \n122\n and/or the rate at which the drivers \n132\n, \n134\n move the skates \n120\n, \n122\n may be computer-controlled.', 'Further, the measurement recorded by the measurement device may be transmitted to such computer-controls, as will be described in greater detail below.', 'The spinners \n124\n, \n126\n, \n128\n, \n130\n may be wheels, cylindrical rollers, or the like that may be configured to rotate the tubulars \n108\n, \n110\n generally about their longitudinal axes in the make-up trough \n114\n, so as to connect together the two tubulars \n108\n, \n110\n in the make-up trough \n114\n.', 'The spinners \n124\n, \n126\n, \n128\n, \n130\n may be computer-controlled.', 'The catwalk \n104\n may also include a tongs \n134\n.', 'The tongs \n134\n may include, for example, two sets of jaws configured to engage the tubulars \n108\n, \n110\n, respectively.', 'The tongs \n134\n may thus be configured to rotate the tubulars \n108\n, \n110\n relative to one another, whether by rotating both tubulars \n108\n, \n110\n in opposite directions or by holding one tubular \n108\n, \n110\n stationary and rotating the other.', 'The tongs \n134\n may be configured to apply sufficient torque to fully make-up a connection between the tubulars \n108\n, \n110\n.', 'The tongs \n134\n may also be computer-controlled.', 'The catwalk \n104\n may further include one or more kicking devices (four shown: \n136\n, \n138\n, \n140\n, \n142\n).', 'The kicking devices \n136\n, \n138\n, \n140\n, \n142\n may extend across the make-up trough \n114\n, such that they are generally positioned under the tubulars \n108\n, \n110\n received therein.', 'For example, the kicking devices \n136\n, \n138\n may be positioned so as to engage the tubular \n108\n, and the kicking devices \n140\n, \n142\n may be positioned so as to engage the tubular \n110\n.', 'The kicking devices \n136\n, \n138\n, \n140\n, \n142\n may be configured to lift or pivot from the surface \n112\n, thereby lifting the tubulars \n108\n, \n110\n out of the trough \n114\n, upon which the tubulars \n108\n, \n110\n, which may be connected together at this point, roll into the main trough \n116\n.', 'The kicking devices \n136\n, \n138\n, \n140\n, \n142\n may be computer-controlled.', 'A main skate \n144\n may be positioned in the main trough \n116\n and may be movable therein, generally along a line between the ends \n117\n, \n119\n, e.g., lengthwise along the catwalk \n104\n.', 'The main skate \n144\n may be formed similarly to the skates \n120\n, \n122\n, but may be positioned to move the tubulars \n108\n, \n110\n in the main trough \n116\n toward the V door \n103\n and toward the platform \n102\n, e.g., through engaging an end of the tubular \n110\n, as will be described in greater detail below.', 'The main skate \n144\n may be driven by a driver \n146\n, which may be hydraulic, gear-driven, etc.', 'The position of the main skate \n144\n and/or the rate at which the main skate \n144\n travels may be computer-controlled, e.g., using a processor, as will be described in greater detail below.', 'Additionally, the catwalk \n104\n may include a reader \n150\n.', 'The reader \n150\n may be positioned proximal to the main trough \n116\n, e.g., near the end \n117\n adjacent to the V door \n103\n.', 'The reader \n150\n may be configured to read an identifier associated with one or more of the tubulars \n108\n, \n110\n, e.g., as the tubulars \n108\n, \n110\n are moved from the catwalk \n104\n to the V door \n103\n and toward the platform \n102\n.', 'For example, the identifier may be stored in a database associated with a length of the tubulars \n108\n, \n110\n.', 'This database may be employed as a pipe tally, which may store details related to the individual tubulars \n108\n, \n110\n or stands of tubulars \n108\n, \n110\n.', 'This pipe tally may then be employed to determine a drilling depth based on the length of the drill string that includes the tubulars \n108\n, \n110\n.', 'In an embodiment, the identifier may be stored in an radiofrequency identification (RFID) tag that may be attached to or within the tubulars \n108\n, \n110\n.', 'In such an embodiment, the reader \n150\n may be an RFID tag reader.', 'In other embodiments, the identifier may be stored as a bar code, QR code, a magnetic code, etc. in or on the tubulars \n108\n, \n110\n and the reader \n150\n may be appropriately configured to read the identifier from the tubular \n108\n, \n110\n.', 'FIG.', '1B\n illustrates a side, elevation view of part of the drilling system \n100\n, according to an embodiment.', 'As shown, the V-door \n103\n may extend at an incline relative to the surface \n112\n, so as to connect the catwalk \n104\n with the platform \n102\n.\n \nFIG.', '1C\n illustrates an end view of the catwalk \n104\n, taking along line C-C in \nFIG.', '1B\n, according to an embodiment.', 'In particular, \nFIG.', '1C\n illustrates an embodiment of the surface \n112\n of the catwalk \n104\n, in which the make-up trough \n114\n and the main trough \n116\n are defined.', 'Further, one of the sets of spinners \n124\n is visible, shown as two cylinders in this embodiment.', 'Referring now to \nFIG.', '2\n, there is shown a flowchart of a method \n200\n for connecting together stands of tubulars in a catwalk, according to an embodiment.', 'The method \n200\n may proceed by operation of the drilling system \n100\n, and may thus be understood with reference thereto.', 'However, it will be appreciated that the method \n200\n may be executed through operation of other systems, and thus is not limited to any particular structure unless otherwise stated herein.', 'To facilitate the description of the method \n200\n, the drilling system \n100\n is shown at various stages thereof in \nFIGS.', '3-5\n.', 'The method \n200\n may begin by receiving the tubulars \n108\n, \n110\n from the rack \n118\n and into the make-up (e.g., first) trough \n114\n, as at \n202\n.', 'This is shown in \nFIG.', '3\n.', 'As mentioned above, the tubulars \n108\n, \n110\n may be received generally at the same time from the rack \n118\n, e.g., spaced axially apart and rolled into the make-up trough \n114\n on either side of the tongs \n134\n.', 'In other embodiments, the tubulars \n108\n, \n110\n may be received consecutively, e.g., the tubular \n110\n may be received first, then pushed toward the end \n119\n, making room for reception of the tubular \n108\n thereafter.', 'Once loaded into the make-up trough \n114\n, the skates \n120\n, \n122\n may engage opposing ends \n300\n, \n302\n of the tubulars \n108\n, \n110\n, respectively, as at \n204\n.', 'This is also shown in \nFIG.', '3\n.', 'For example, the end \n300\n may be the box end of the tubular \n108\n, and the end \n302\n may be the pin end of the tubular \n110\n.', 'The skates \n120\n, \n122\n may be moved, so as to push the other (e.g., third and fourth) ends \n304\n, \n306\n of the tubulars \n108\n, \n110\n, respectively, together, as at \n206\n.', 'The ends \n304\n, \n306\n may be pin and box ends, respectively, which may be configured to be connected together.', 'Further, the ends \n304\n, \n306\n may be pushed together to meet within the tongs \n134\n, as the tubulars \n108\n, \n110\n may be received into the make-up trough \n114\n on either side of the tongs \n134\n, or may otherwise be moved together within the make-up trough \n114\n.', 'When the ends \n204\n, \n206\n are pushed together, the spinners \n124\n, \n126\n, \n128\n, \n130\n may be employed to rotate the tubulars \n108\n, \n110\n relative to one another in the make-up trough \n114\n, as at \n206\n.', 'For example, the spinners \n124\n, \n126\n may rotate the tubular \n108\n in one circumferential direction, and the spinners \n128\n, \n130\n may rotate the tubular \n110\n in an opposite circumferential direction.', 'In some embodiments, one of the pairs of spinners \n124\n, \n126\n or \n128\n, \n130\n may be replaced with a clamp or another member configured to hold the tubular \n108\n or \n110\n in place while the other tubular \n110\n or \n108\n is rotated, thereby again providing for the relative rotation therebetween.', 'In either case, the relative rotation may cause the tubulars \n108\n, \n110\n to be connected together, e.g., by advancing the threads of the ends \n304\n, \n306\n together.', 'The spinners \n124\n, \n126\n, \n128', ', \n130\n may cause the ends \n204\n, \n206\n to “shoulder” together, such that the sealing faces of the ends \n304\n, \n306\n generally engaging one another, but may not provide a full make-up torque.', 'Once the spinners \n124\n, \n126\n, \n128\n, \n130\n have finished connecting together the tubulars \n108\n, \n110\n, the tongs \n134\n may be engaged to apply torque thereto, as at \n210\n.', 'For example, the tubulars \n108\n, \n110\n may be rolled into the make-up trough \n114\n on either side of the tongs \n134\n, and the movement of the skates \n120\n, \n122\n may drive the tubulars \n108\n, \n110\n into engagement generally within the tongs \n134\n.', 'In other embodiments, the tongs \n134\n may include a door, allowing the tubulars \n108\n, \n110\n to be laterally received therein.', 'The tongs \n134\n may apply torque to the tubulars \n108\n, \n110\n, tightening the connection therebetween, such that the connection may not be further torqued on the platform \n102\n when made up to the drill string and run into the well \n106\n.', 'In other embodiments, the tongs \n134\n may provide additional torque to the connection between the tubulars \n108\n, \n110\n, but the connection may be further torqued by equipment on the drilling platform.', 'The skates \n120\n, \n122\n may be configured to continue applying force to the ends \n200\n, \n202\n of the tubulars \n108\n, \n110\n during the connection therebetween.', 'Accordingly, as the ends \n204\n, \n206\n are received into one another during the connection process, the skates \n120\n, \n122\n may advance linearly along therewith.', 'Once the connection is made, e.g., before or after application of torque by the tongs \n134\n, the distance between the skates \n120\n, \n122\n may be determined, as at \n212\n.', 'For example, as mentioned above, encoders (schematically depicted) \n147\n, \n149\n on the skates \n120\n, \n122\n and/or the drivers \n132\n, \n133\n may be provided to determine the position of the skates \n120\n, \n122\n.', 'The relative position thereof may reveal the distance therebetween, from which, in turn, the length of the combination of the tubulars \n108\n, \n110\n may be determined with precision, e.g., by communication with a processor \n250\n.', 'Once the connection between the tubulars \n108\n, \n110\n is torqued by the tongs \n134\n, the tubulars \n108\n, \n110\n may be transferred to the main trough \n116\n, as at \n214\n.', 'For example, the kicking devices \n136\n, \n138\n, \n140\n, \n142\n may engage the tubulars \n108\n, \n110\n and may lift the tubulars \n108\n, \n110\n out of the make-up trough \n114\n, such that the tubulars \n108\n, \n110\n may proceed (e.g., roll) along the surface \n112\n and transfer into the main trough \n116\n. \nFIG.', '4\n illustrates the tubulars \n108\n, \n110\n having been transferred into the main trough \n116\n.', 'Once in the main trough \n116\n, the main skate \n144\n may engage the end \n202\n of the tubular \n110\n.', 'The tubulars \n108\n, \n110\n may thus be pushed (or may be pulled, e.g., using an elevator that may grab the opposite end \n200\n) up the V-door \n103\n and onto the platform \n102\n, as at \n216\n.', 'This is shown in \nFIG.', '5\n.', 'The main trough \n116\n may be aligned with the well \n106\n, and thus transfer of the tubulars \n108\n, \n110\n therefrom may be accomplished by sliding the tubulars \n108\n, \n110\n along the length of the catwalk \n104\n, toward the platform \n102\n.', 'As a result, the tubulars \n108\n, \n110\n may be received by equipment on the platform \n102\n at well center, facilitating connection of the tubulars \n108\n, \n110\n with the drill string, for running into the well \n106\n.', 'During this movement, the tubulars \n108\n, \n110\n may move past the reader \n150\n, such that the reader \n150\n acquires the identifier from the tubulars \n108\n, \n110\n, as at \n218\n.', 'The identifier may then be communicated from the reader \n150\n to the processor \n250\n, which may store the identifier in association with the length of the tubulars \n108\n, \n110\n determined by the distance between the skates \n120\n, \n122\n, as at \n220\n.', 'While the tubulars \n108\n, \n110\n are in the main trough \n116\n or once the tubulars \n108\n, \n110\n are removed therefrom, another pair (or triplet, etc.) of tubulars may be received into the make-up trough \n114\n, beginning the method \n200\n again.', 'In some embodiments, the methods of the present disclosure may be executed by a computing system.', 'FIG.', '6\n illustrates an example of such a computing system \n600\n, in accordance with some embodiments.', 'The computing system \n600\n may include a computer or computer system \n601\nA, which may be an individual computer system \n601\nA or an arrangement of distributed computer systems.', 'The computer system \n601\nA includes one or more analysis modules \n602\n that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein.', 'To perform these various tasks, the analysis module \n602\n executes independently, or in coordination with, one or more processors \n604\n, which is (or are) connected to one or more storage media \n606\n.', 'The processor(s) \n604\n is (or are) also connected to a network interface \n607\n to allow the computer system \n601\nA to communicate over a data network \n609\n with one or more additional computer systems and/or computing systems, such as \n601\nB, \n601\nC, and/or \n601\nD (note that computer systems \n601\nB, \n601\nC and/or \n601\nD may or may not share the same architecture as computer system \n601\nA, and may be located in different physical locations, e.g., computer systems \n601\nA and \n601\nB may be located in a processing facility, while in communication with one or more computer systems such as \n601\nC and/or \n601\nD that are located in one or more data centers, and/or located in varying countries on different continents).', 'A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.', 'The storage media \n606\n may be implemented as one or more computer-readable or machine-readable storage media.', 'Note that while in the example embodiment of \nFIG.', '6\n storage media \n606\n is depicted as within computer system \n601\nA, in some embodiments, storage media \n606\n may be distributed within and/or across multiple internal and/or external enclosures of computing system \n601\nA and/or additional computing systems.', 'Storage media \n606\n may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLU-RAY® disks, or other types of optical storage, or other types of storage devices.', 'Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes.', 'Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture).', 'An article or article of manufacture may refer to any manufactured single component or multiple components.', 'The storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.', 'In some embodiments, the computing system \n600\n contains one or more measurement module(s) \n608\n.', 'The measurement module(s) \n608\n may be used to perform at least a portion of one or more embodiments of the methods disclosed herein (e.g., method \n200\n).', 'It should be appreciated that computing system \n600\n is only one example of a computing system, and that computing system \n600\n may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of \nFIG.', '6\n, and/or computing system \n600\n may have a different configuration or arrangement of the components depicted in \nFIG.', '6\n.', 'The various components shown in \nFIG.', '6\n may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.', 'Further, the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices.', 'These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of protection of the invention.', 'The foregoing description, for purpose of explanation, has been described with reference to specific embodiments.', 'However, the illustrative discussions above are not intended to be exhaustive or limiting to the precise forms disclosed.', 'Many modifications and variations are possible in view of the above teachings.', 'Moreover, the order in which the elements of the methods described herein are illustrate and described may be re-arranged, and/or two or more elements may occur simultaneously.', 'The embodiments were chosen and described in order to best explain the principals of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosed embodiments and various embodiments with various modifications as are suited to the particular use contemplated.'] | ['1.', 'A tubular handling apparatus for a drilling system, comprising:\na first trough configured to receive at least a first tubular and a second tubular;\na first skate movable along the first trough and configured to engage a first end of the first tubular;\na second skate movable along the first trough and configured to engage a second end of the second tubular, wherein the first and second skates are configured to push a third end of the first tubular into engagement with a fourth end of the second tubular in the first trough;\na tongs configured to engage the first and second tubulars in the first trough and apply torque thereto to connect the first and second tubulars; and\na second trough extending generally parallel to the first trough, the first and second troughs being generally horizontal, wherein the second trough is configured to receive the connected first and second tubulars from the first trough.', '2.', 'The apparatus of claim 1, further comprising a measuring device configured to measure a distance between the first and second skates, wherein the distance corresponds to a length of the first and second tubulars when connected together.', '3.', 'The apparatus of claim 2, wherein the measuring device comprises one or more encoders coupled to the skates or drivers configured to move the skates, wherein the one or more encoders are configured to provide information from which the distance is determined.', '4.', 'The apparatus of claim 1, further comprising one or more kicking devices configured to transfer the first and second tubulars from the first trough to the second trough after connecting together the first and second tubulars in the first trough.', '5.', 'The apparatus of claim 1, further comprising one or more spinners configured to engage the first tubular, the second tubular, or both in the first trough, the one or more spinners being configured to rotate the first and second tubulars relative to one another.', '6.', 'A method for handling tubulars in a drilling system, the method comprising:\nreceiving a first tubular and a second tubular into a first trough;\nmoving the first and second tubulars together in the first trough using a first skate that engages a first end of the first tubular, and a second skate that engages a second end of the second tubular;\nconnecting together a third end of the first tubular and a fourth end of the second tubular by applying torque thereto;\ndetermining a distance between the first and second skates after connecting together the first and second tubulars, wherein the distance corresponds to a length of the first and second tubulars after being connected together; and\ntransferring the connected first and second tubulars to a second trough extending generally parallel to the first trough, the first and second troughs being generally horizontal.\n\n\n\n\n\n\n7.', 'The method of claim 6, wherein connecting together the first and second tubulars comprises:\nrotating the first tubular relative to the second tubular using one or more spinners in the first trough; and\ntorqueing a connection between the first and second tubulars using a tongs that engages the first and second tubulars in the first trough.', '8.', 'The method of claim 6, wherein receiving the first and second tubulars comprises receiving the first tubular on a first side of a tongs and receiving the second tubular on a second side of the tongs.\n\n\n\n\n\n\n9.', 'The method of claim 8, wherein pushing the first and second tubulars together comprises pushing the third end of the first tubular and the fourth end of the second tubular into engagement within the tongs.', '10.', 'The method of claim 8, wherein the first and second tubulars are received in the first trough substantially simultaneously.'] | ['FIG.', '1A illustrates a plan view of a drilling system including an apparatus for handling tubulars, according to an embodiment.;', 'FIG.', '1B illustrates a side, elevation view of a portion of the drilling system, according to an embodiment.;', 'FIG.', '1C illustrates an end view of a portion of the drilling system, according to an embodiment.; FIG.', '2 illustrates a flowchart of a method for handling tubulars in a drilling system, according to an embodiment.; FIG.', '3 illustrates a plan view of the drilling system after tubulars have been loaded into a first trough of the apparatus, according to an embodiment.; FIG.', '4 illustrates a plan view of the drilling system after the tubulars have been connected together by operation of the apparatus, according to an embodiment.; FIG.', '5 illustrates a plan view of the drilling system, showing the tubulars being transferred from the second trough to a platform over a well, according to an embodiment.; FIG.', '6 illustrates a schematic view of a computing system, according to an embodiment.;', 'FIG.', '1A illustrates a plan view of a drilling system 100, according to an embodiment.', 'The drilling system 100 includes a drilling platform 102 and an apparatus for handling tubulars, e.g., a catwalk 104.', 'An inclined surface or “V-door” 103 may extend between the platform 102 and the catwalk 104.', 'The drilling platform 102 may support drilling equipment, such as a derrick, drilling device (e.g., top drive, kelly, etc.), slips, and the like.', 'The platform 102 may thus be positioned over the well center 106, and may be configured to deploy oilfield tubulars (e.g., drill pipe) into the well, via the well center 106, e.g., as part of a drilling operation.', ';', 'FIG.', '1B illustrates a side, elevation view of part of the drilling system 100, according to an embodiment.', 'As shown, the V-door 103 may extend at an incline relative to the surface 112, so as to connect the catwalk 104 with the platform 102.; FIG.', '1C illustrates an end view of the catwalk 104, taking along line C-C in FIG.', '1B, according to an embodiment.', 'In particular, FIG.', '1C illustrates an embodiment of the surface 112 of the catwalk 104, in which the make-up trough 114 and the main trough 116 are defined.', 'Further, one of the sets of spinners 124 is visible, shown as two cylinders in this embodiment.'] |
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US11098554 | Expanding and collapsing apparatus and methods of use | Dec 23, 2016 | Gareth Edward George Brown | SCHLUMBERGER TECHNOLOGY CORPORATION | Examination Report issued in the related GB Application 1622147.5, dated Jan. 31, 2019 (2 pages).; International Search and Written Opinion issued in the related PCT Application PCT/GB2016/054064, dated May 8, 2017 (11 pages).; International Preliminary Report on Patentability issued in the related PCT Application PCT/GB2016/054064, dated Jun. 26, 2018 (7 pages).; Combined Search and Examination Report issued in the related GB Application 1622148.3, dated Jun. 21, 2017 (9 pages).; Examination Report issued in the related GB Application 1622148.3, dated Jul. 24, 2019 (4 pages).; International Search and Written Opinion issued in the related PCT Application PCT/GB2016/054065, dated May 8, 2017 (10 pages).; International Preliminary Report on Patentability issued in the related PCT Application PCT/GB2016/054065, dated Jun. 26, 2018 (6 pages).; Combined Search and Examination Report issued in the related GB Application 1622150.9, dated Mar. 31, 2017 (5 pages).; International Search and Written Opinion issued in the related PCT Application PCT/GB2016/054066, dated May 8, 2017 (9 pages).; International Preliminary Report on Patentability issued in the related PCT Application PCT/GB2016/054066, dated Jun. 26, 2018 (6 pages).; Combined Search and Examination Report issued in the related GB Application 1622151.9, dated Apr. 27, 2017 (5 pages).; Examination Report issued in the related GB Application 1622151.9, dated Jan. 24, 2019 (3 pages).; International Search and Written Opinion issued in the related PCT Application PCT/GB2016/054067, dated May 8, 2017 (11 pages).; International Preliminary Report on Patentability issued in the related PCT Application PCT/GB2016/054067, dated Jun. 26, 2018 (7 pages).; Combined Search and Examination Report issued in the related GB Application 1622152.5, dated Apr. 27, 2017 (7 pages).; International Search and Written Opinion issued in the related PCT Application PCT/GB2016/054058, dated Jun. 21, 2017 (12 pages).; International Preliminary Report on Patentability issued in the related PCT Application PCT/GB2016/054058, dated Jun. 26, 2018 (8 pages).; Combined Search and Examination Report issued in the related GB Application 1622147.5, dated Apr. 27, 2017 (7 pages).; Office Action received in U.S. Appl. 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No. 16/066,050 dated Feb. 22, 2021, 26 pages. | 9043; June 1852; Wright; 758186; April 1904; Morton; 865998; September 1907; Cook; 1594259; July 1926; Hardman; 1776415; September 1930; Class; 2169735; August 1939; Keller; 2052846; September 1939; Ryba; 2287205; June 1942; Stone; 2355308; August 1944; Kurzina, Jr.; 2609836; September 1952; Knox; 2613763; October 1952; Campbell; 2701615; February 1955; Riordan, Jr.; 3572627; March 1971; Jones; 3603411; September 1971; Link; 3915424; October 1975; LeRouax; 3937412; February 10, 1976; Damour; 4460150; July 17, 1984; Turlak et al.; 4842082; June 27, 1989; Springer; 5341888; August 30, 1994; Deschutter; 5507465; April 16, 1996; Borle; 5678635; October 21, 1997; Dunlap et al.; 5685078; November 11, 1997; Obst et al.; 6598672; July 29, 2003; Bell et al.; 7290603; November 6, 2007; Hiorth et al.; 7389822; June 24, 2008; Lohbeck; 7921921; April 12, 2011; Bishop et al.; 7992634; August 9, 2011; Angelle et al.; 8083001; December 27, 2011; Conner 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20190368274; December 5, 2019; Brown | 295473; December 1953; CH; 814546; September 1951; DE; 1775899; October 1971; DE; 0533326; March 1993; EP; 2996816; April 2014; FR; 191010637; March 1911; GB; 601318; May 1948; GB; 1452272; October 1976; GB; 1484814; September 1977; GB; 2127068; April 1984; GB; 2097491; February 1985; GB; 2488152; August 2012; GB; S643330; January 1989; JP; 2000120365; April 2000; JP; 2017109506; June 2017; WO; 2017109508; June 2017; WO; 2017109509; June 2017; WO; 2017109510; June 2017; WO; 2017109511; June 2017; WO | ['The invention provides an expanding and/or collapsing apparatus and a method of use.', 'The apparatus comprises a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis.', 'The ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements.', 'The plurality of elements is operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure.', 'Applications of the invention include oilfield devices, including anti-extrusion rings, plugs, packers, locks, patching tools, connection systems, and variable diameter tools run in a wellbore.'] | ['Description\n\n\n\n\n\n\nThis application is the U.S. National Stage of International Application No.', 'PCT/GB2016/054058, filed Dec. 23, 2016.', 'This application also claims the benefit of GB patent application No. 1522725.9, filed Dec. 23, 2015, the contents of both of which are hereby incorporated by reference in their entirety.', 'The present invention relates to an expanding and collapsing apparatus and methods of use, and in particular aspects, to an expanding apparatus in the form of a ring, operable to move between a collapsed condition and an expanded condition.', 'The invention also relates to tools and devices incorporating the expansion apparatus and methods of use.', 'Preferred embodiments of the invention relate to oilfield apparatus (including but not limited to downhole apparatus and wellhead apparatus) incorporating the apparatus and methods of use.\n \nBACKGROUND TO THE INVENTION\n \nIn many fields of mechanical engineering, and in the field of hydrocarbon exploration and production in particular, it is known to provide expansion mechanisms for the physical interaction of tubular components.', 'Expansion mechanisms may expand outwardly to engage an external surface, or may collapse inwardly to engage an internal surface.', 'Applications are many and varied, but in hydrocarbon exploration and production include the actuation and setting of flow barriers and seal elements such as plugs and packers, anchoring and positioning tools such as wellbore anchors, casing and liner hangers, and locking mechanisms for setting equipment downhole.', 'Other applications include providing mechanical support or back up for elements such as elastomers or inflatable bladders.', 'A typical anti-extrusion ring is positioned between a packer or seal element and its actuating slip members, and is formed from a split or segmented metallic ring.', 'During deployment of the packer or seal element, the segments move to a radially expanded condition.', 'During expansion and at the radially expanded condition, spaces are formed between the segments, as they are required to occupy a larger annular volume.', 'These spaces create extrusion gaps, which may result in failure of the packer or seal under working conditions.', 'Various configurations have been proposed to minimise the effect of spaces between anti-extrusion segments, including providing multi-layered rings, such that extrusion gaps are blocked by an offset arrangement of segments.', 'For example, U.S. Pat.', 'No. 6,598,672 describes an anti-extrusion rings for a packer assembly which has first and second ring portions which are circumferentially offset to create gaps in circumferentially offset locations.', 'U.S. Pat.', 'No. 2,701,615 discloses a well packer comprising an arrangement of crowned spring metal elements which are expanded by relative movement.', 'Other proposals, for example those disclosed in U.S. Pat.', 'Nos. 3,572,627, 7,921,921, US 2013/0319654, U.S. Pat.', 'Nos. 7,290,603 and 8,167,033 include arrangements of circumferentially lapped segments.', 'U.S. Pat.', 'No. 3,915,424 describes a similar arrangement in a drilling BOP configuration, in which overlapping anti-extrusion members are actuated by a radial force to move radially and circumferentially to a collapsed position which supports annular sealing elements.', 'Such arrangements avoid introducing extrusion gaps during expansion, but create a ring with uneven or stepped faces or flanks.', 'These configurations do not provide an unbroken support wall for a sealing element, are spatially inefficient, and may be difficult to reliably move back to their collapsed configurations.', 'U.S. Pat.', 'No. 8,083,001 proposes an alternative configuration in which two sets of wedge shaped segments are brought together by sliding axially with respect to one another to create an expanded gauge ring.', 'In anchoring, positioning, setting, locking and connection applications, radially expanding and collapsing structures are typically circumferentially distributed at discrete locations when at their increased outer diameter.', 'This reduces the surface area available to contact an auxiliary engagement surface, and therefore limits the maximum force and pressure rating for a given size of device.', 'SUMMARY OF THE INVENTION', 'It is amongst the claims and objects of the invention to provide an expanding and collapsing apparatus and methods of use which obviate or mitigate disadvantages of previously proposed expanding and collapsing apparatus.', 'It is amongst the aims and objects of the invention to provide an oilfield apparatus, including a downhole apparatus or a wellhead apparatus, incorporating an expanding and collapsing apparatus, which obviates or mitigates disadvantages of prior art oilfield apparatus.', 'Further aims and objects of the invention will be apparent from reading the following description.', 'According to a first aspect of the invention, there is provided an apparatus comprising: a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements on actuation by an axial force;\n \nand wherein the plurality of elements is operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure.', 'The collapsed condition may be a first condition of the apparatus, and the expanded condition may be a second condition of the apparatus.', 'Thus the apparatus may be normally collapsed, and may be actuated to be expanded.', 'Alternatively, the expanded condition may be a first condition of the apparatus, and the collapsed condition may be a second condition of the apparatus.', 'Thus the apparatus may be normally expanded, and may be actuated to be collapsed.', 'The plane of the ring structure may be perpendicular to the longitudinal axis.', 'The ring structure, and its plane of orientation, may be operable to move on the apparatus during expansion and/or collapsing.', 'The movement of the plane may be an axial sliding movement, during expanding and/or collapsing of the ring structure.', 'The ring structure may comprise one or more ring surfaces, which may be presented to an auxiliary surface, for example the surface of a tubular, when actuated to an expanded condition or a collapsed condition.', 'The one or more ring surfaces may include a ring surface which is parallel to the longitudinal axis of the apparatus.', 'Alternatively, or in addition, the one or more ring surfaces may include a surface which is perpendicular to the longitudinal axis of the apparatus, and/or a surface which is inclined to the longitudinal axis of the apparatus.', 'The ring surface may be an outer ring surface, and may be a substantially cylindrical surface.', 'The ring surface may be arranged to contact or otherwise interact with an inner surface of a tubular or bore.', 'Alternatively, the ring surface may be an inner surface of the ring structure, and may be a substantially cylindrical surface.', 'The ring surface may be arranged to contact or otherwise interact with an outer surface of a tubular or cylinder.', 'The ring surface may be substantially smooth.', 'Alternatively, the ring surface may be profiled, and/or may be provided with one or more functional formations thereon, for interacting with an auxiliary surface.', 'In the collapsed condition, the elements may be arranged generally at collapsed radial positions, and may define a collapsed outer diameter and inner diameter of the ring structure.', 'In the expanded condition, the elements may be arranged generally at expanded radial positions, and may define an expanded outer diameter and inner diameter of the ring structure.', 'The ring surface may be located at or on the expanded outer diameter of the ring structure, or may be located at or on the collapsed inner diameter of the ring structure.', 'In the collapsed condition, the elements may occupy a collapsed annular volume, and in the expanded condition the elements may occupy an expanded annular volume.', 'The collapsed annular volume and the expanded annular volume may be discrete and separated volumes, or the volumes may partially overlap.', 'The elements may be configured to move between their expanded and collapsed radial positions in a path which is tangential to a circle described around and concentric with the longitudinal axis.', 'Preferably, each element of the ring structure comprises a first contact surface and second contact surface respectively in abutment with first and second adjacent elements.', 'The elements may be configured to slide relative to one another along their respective contact surfaces.', 'The first contact surface and/or the second contact surface may be oriented tangentially to a circle described around and concentric with the longitudinal axis.', 'The first contact surface and the second contact surface are preferably non-parallel.', 'The first contact surface and the second contact surface may converge towards one another in a direction towards an inner surface of the ring structure (and may therefore diverge away from one another in a direction away from an inner surface of the ring structure).', 'At least some of the elements are preferably provided with interlocking profiles for interlocking with an adjacent element.', 'Preferably the interlocking profiles are formed in the first and/or second contact surfaces.', 'Preferably, an element is configured to interlock with a contact surface of an adjacent element.', 'Such interlocking may prevent or restrict separation of assembled adjacent elements in a circumferential and/or radial direction of the ring structure, while enabling relative sliding movement of adjacent elements.', 'Preferably, at least some of, and more preferably all of, the elements assembled to form a ring are identical to one another, and each comprises an interlocking profile which is configured to interlock with a corresponding interlocking profile on another element.', 'The interlocking profiles may comprise at least one recess such as groove, and at least one protrusion, such as a tongue or a pin, configured to be received in the groove.', 'The interlocking profiles may comprise at least one dovetail recess and dovetail protrusion.', 'The first and second contact surfaces of an element may be oriented on first and second planes, which may intersect an inner surface of the ring at first and second intersection lines, such that a sector of an imaginary cylinder is defined between the longitudinal axis and the intersection lines.', 'The central angle of the sector may be 45 degrees or less.', 'Such a configuration corresponds to eight or more elements assembled together to form the ring structure.', 'Preferably, the central angle of the sector is 30 degrees or less, corresponding to twelve or more elements assembled together to form the ring.', 'More preferably, the central angle of the sector is in the range of 10 degrees to 20 degrees, corresponding to eighteen to thirty-six elements assembled together to form the ring.', 'In a particular preferred embodiment, the central angle of the sector is 15 degrees, corresponding to twenty-four elements assembled together to form the ring structure.', 'Preferably, an angle described between the first contact and second contact surfaces corresponds to the central angle of the sector.', 'Preferably therefore, an angle described between the first contact and second contact surfaces is in the range of 10 degrees to 20 degrees, and in a particular preferred embodiment, the angle described between the first contact and second contact surfaces is 15 degrees, corresponding to twenty-four elements assembled together to form the ring structure.', 'In a preferred embodiment, the apparatus comprises a support surface for the ring structure.', 'The support surface may be the outer surface of a mandrel or tubular.', 'The support surface may support the ring structure in a collapsed condition of the apparatus.', 'The support surface may be the inner surface of a mandrel or tubular.', 'The support surface may support the ring structure in an expanded condition of the apparatus.', 'In some embodiments, the apparatus is operated in its expanded condition, and in other embodiments, the apparatus is operated in its collapsed condition.', 'Preferably, elements forming the ring structure are mutually supportive in an operating condition of the apparatus.', 'Where the operating condition of the apparatus its expanded condition (i.e. when the apparatus is operated in its expanded condition), the ring structure is preferably a substantially solid ring structure in its expanded condition, and the elements may be fully mutually supported.', 'Where the operating condition of the apparatus its collapsed condition (i.e. when the apparatus is operated in its collapsed condition), the ring structure is preferably a substantially solid ring structure in its collapsed condition, and the elements may be fully mutually supported.', 'The apparatus may comprise a formation configured to impart a radial expanding or collapsing force component to the elements of a ring structure from an axial actuation force.', 'The apparatus may comprise a pair of formations configured to impart a radial expanding or collapsing force component to the elements of a ring structure from an axial actuation force.', 'The formation (or formations) may comprise a wedge or wedge profile, and may comprise a cone wedge or wedge profile.', 'The apparatus may comprise a biasing means, which may be configured to bias the ring structure to one of its expanded or collapsed conditions.', 'The biasing means may comprise a circumferential spring, a garter spring, or a spiral retaining ring.', 'The biasing means may be arranged around an outer surface of a ring structure, to bias it towards a collapsed condition, or may be arranged around an inner surface of a ring structure, to bias it towards an expanded condition.', 'One or more elements may comprise a formation such as a groove for receiving the biasing means.', 'Preferably, grooves in the elements combine to form a circumferential groove in the ring structure.', 'Multiple biasing means may be provided on the ring structure.', 'The apparatus may comprise a secondary expanding and collapsing mechanism operable to move the ring structure between a first expanded condition to a second expanded condition on actuation by an axial force.', 'The ring structure may be a first ring structure, and the apparatus may comprise at least one additional ring structure, wherein the additional ring structure is operable to move the first ring structure from an intermediate expanded condition to a fully expanded condition.', 'The apparatus may comprise at least one pair of additional ring structures, wherein the pair of additional ring structures are operable to move the first ring structure from an intermediate expanded condition to a fully expanded condition.', 'The pair of additional ring structures may be disposed (axially) on either side of the first ring structure, and may act together to move the ring structure from an intermediate expanded condition to a fully expanded condition.', 'The additional ring structure may comprise a plurality of elements assembled together to form a ring structure, and may be oriented in a plane around a longitudinal axis.', 'The additional ring structure may be operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements on actuation by an axial force.', 'The plurality of elements of the additional ring structure may be operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in the plane of the additional ring structure, in a direction tangential to a circle concentric with the additional ring structure.', 'In other respects, the additional ring structure and its elements may have features in common with the ring structure described herein.', 'The additional ring structure, and/or its elements, may be operable to transfer an axial actuation force to the elements of the first ring structure.', 'The additional ring structure, and/or its elements may comprise one or more wedge profiles, which may be conical wedge profiles.', 'The one or more wedge profiles may be defined by an outer surface of the elements of the additional ring structure.', 'The apparatus may comprise a plurality of additional ring structures, which may be arranged in functional pairs, and/or which may be operable to move the first ring structure from an intermediate expanded condition to a subsequent intermediate expanded condition, or a fully expanded condition.', 'Preferably, each additional ring structure comprises a biasing means, which may be configured to bias the first ring structure to one of its expanded or collapsed conditions.', 'The biasing means may comprise a circumferential spring, a garter spring, or a spiral retaining ring.', 'Preferably, the biasing means of the first and additional ring structures are selected to define a sequence of expanding and collapsing of the apparatus.', 'Preferably, the biasing means of the first and additional ring structures are selected to expand the centremost ring structure before an adjacent pair of additional ring structures.', 'The biasing means additional ring structures may be selected to expand a first pair of additional ring structures before an adjacent pair of additional ring structures located axially outside of the first pair or additional ring structures.', 'Preferably, a functional pair of additional ring structures and/or the elements thereof is symmetrical about a centre ring structure.', 'Each of a functional pair of additional ring structures and/or the elements thereof may be configured to move axially with respect to one another on the apparatus, and may be configured to move into abutment with one another.', 'Preferably, each of a functional pair of additional ring structures and/or the elements thereof are configured to limit the travel of a corresponding additional ring structures and/or the elements thereof.', 'The surfaces of the plurality of elements may be configured to be presented directly against a surface with which it interacts, such as a borehole wall.', 'Alternatively, or in addition, the apparatus may comprise an intermediate structure or material disposed between the surfaces of the elements and a surface with which it interacts.', 'In one embodiment, the elements of the ring structure are configured to conform, deform or compress in a collapsed condition to form a fluid barrier or seal with an object in the throughbore.', 'The elements may be formed, at least partially, from a compressible and/or resilient material, such as an elastomer, rubber or polymer.', 'Alternatively, or in addition, the elements may be formed, at least partially, from a metal or metal alloy, and may be coated or covered with a compressible and/or resilient material, such as an elastomer, rubber or polymer.', 'According to a second aspect of the invention, there is provided an expanding and collapsing ring apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements on actuation by an axial force;\n \nwherein the plurality of elements is operable to be moved between the expanded and collapsed conditions in a plane perpendicular to the longitudinal axis, by sliding with respect to an adjacent pair of elements.', 'Embodiments of the second aspect of the invention may include one or more features of the first aspect of the invention or its embodiments, or vice versa.', 'According to a third aspect of the invention, there is provided an expanding and collapsing ring apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements on actuation by an axial force;\n \nwherein the plurality of elements is operable to be moved between the expanded and collapsed conditions by sliding relative to one another in directions tangential to a circle concentric with the longitudinal axis.', 'Embodiments of the third aspect of the invention may include one or more features of the first or second aspects of the invention or their embodiments, or vice versa.', 'According to a fourth aspect of the invention, there is provided an expanding and collapsing ring apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition on actuation by an axial force;\n \nwherein in the expanded condition, the plurality of elements combine to form a solid ring structure having a substantially smooth outer surface.', 'Preferably, the plurality of elements combine to form a solid ring structure having a substantially smooth outer surface in the collapsed condition and/or in a partially expanded or partially collapsed condition.', 'Preferably, the plurality of elements combine to form a solid ring structure in a number of intermediate positions between a collapsed condition and an expanded condition, and most preferably all intermediate positions, having a substantially smooth outer surface.', 'The substantially smooth outer surface may comprise a smooth circular profile in a plane parallel to the plane of the ring structure.', 'The substantially smooth outer surface may be substantially unbroken.', 'Preferably, the smooth outer surface comprises one or more smooth side surfaces.', 'The substantially smooth outer surface may comprise a smooth radially extending surface, and may comprise a first side of an annular projection defined by the ring structure in its expanded condition.', 'The smooth surface may comprise a first side and an opposing second side of an annular projection defined by the ring structure in its expanded condition.', 'Thus one or more flanks or faces of the ring structure, which are the surfaces presented in the longitudinal direction, may have smooth surfaces.', 'Preferably, the plurality of elements is operable to be moved between the expanded and collapsed conditions in the plane of the ring structure.', 'The plurality of elements may be operable to be moved between the expanded and collapsed conditions by sliding with respect to an adjacent pair of elements.', 'Sliding may be in a direction tangential to a circle concentric with the ring structure.', 'Embodiments of the fourth aspect of the invention may include one or more features of the first to third aspects of the invention or their embodiments, or vice versa.', 'According to a fifth aspect of the invention, there is provided an oilfield tool comprising the apparatus of any of the first to fourth aspects of the invention.', 'The oilfield tool may be a downhole tool.', 'Alternatively, the oilfield tool may comprise a wellhead tool.', 'The downhole tool may comprise a downhole tool selected from the group consisting of a plug, a packer, an anchor, a tubing hanger, or a downhole locking tool.', 'The plug may be a bridge plug, and may be a retrievable bridge plug.', 'Alternatively, the plug may be a permanent plug.', 'Embodiments of the fifth aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'According to a sixth aspect of the invention, there is provided variable diameter downhole tool, the tool comprising an apparatus according to a previous aspect of the invention.', 'The downhole tool may be selected from the group consisting of a wellbore centraliser, a wellbore broach tool, and a wellbore drift tool.', 'The downhole tool may be a stabiliser tool.', 'The downhole tool may be a stabilising and centring tool, and/or may be configured for use with non-sealing devices, including drilling, milling and cutting tools.', 'Embodiments of the sixth aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'According to a seventh aspect of the invention, there is provided a connector system comprising a first connector and a second connector, wherein one of the first and second connectors comprises the apparatus of any of the first to fourth aspects of the invention.', 'Embodiments of the seventh aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'According to an eighth aspect of the invention, there is provided a patch apparatus for a fluid conduit or tubular, the patch apparatus comprising the apparatus of any of the first to fourth aspects of the invention.', 'Embodiments of the eighth aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'According to a ninth aspect of the invention, there is provided a method of expanding an apparatus, the method comprising:\n \nproviding an apparatus comprising a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis;\n \nimparting an axial force to the ring structure to move the plurality of elements by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure; thereby moving the ring structure from a collapsed condition to an expanded condition.', 'Embodiments of the ninth aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'According to a tenth aspect of the invention, there is provided a method of collapsing an apparatus, the method comprising:\n \nproviding an apparatus comprising a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis;\n \nreleasing or reducing an axial force from the ring structure to move the plurality of elements by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure, thereby moving the ring structure from an expanded condition to a collapsed condition.\n \nEmbodiments of the tenth aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'According to a further aspect of the invention, there is provided an apparatus comprising: a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements;\n \nand wherein the plurality of elements is operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure.', 'According to a further aspect of the invention, there is provided an expanding and collapsing ring apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements;\n \nwherein the plurality of elements is operable to be moved between the expanded and collapsed conditions in a plane perpendicular to the longitudinal axis, by sliding with respect to an adjacent pair of elements.', 'According to a further aspect of the invention, there is provided an expanding and collapsing ring apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements;\n \nwherein the plurality of elements is operable to be moved between the expanded and collapsed conditions by sliding relative to one another in directions tangential to a circle concentric with the longitudinal axis.', 'According to a further aspect of the invention, there is provided an expanding and collapsing ring apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition;\n \nwherein in the expanded condition, the plurality of elements combine to form a solid ring structure having a substantially smooth outer surface.', 'According to a further aspect of the invention, there is provided a method of expanding an apparatus, the method comprising:\n \nproviding an apparatus comprising a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis;\n \nimparting a force to or releasing a force from the ring structure to move the plurality of elements by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure; thereby moving the ring structure from a collapsed condition to an expanded condition.', 'According to a further aspect of the invention, there is provided a method of collapsing an apparatus, the method comprising:\n \nproviding an apparatus comprising a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis;\n \nreleasing a force from or imparting a force to the ring structure to move the plurality of elements by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure, thereby moving the ring structure from an expanded condition to a collapsed condition.', 'According to a further aspect of the invention, there is provided fluid conduit tool comprising the apparatus according to any previous aspect of the invention.', 'The fluid conduit tool may be configured for use in pipelines or other fluid conduits, which may be surface fluid conduits or subsea fluid conduits, and may be oilfield or non-oilfield fluid conduits.', 'Embodiments of the further aspects of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThere will now be described, by way of example only, various embodiments of the invention with reference to the drawings, of which:\n \nFIGS.', '1A to 1D\n are respectively perspective, first end, part sectional and second end views of an apparatus according to a first embodiment of the invention, shown in a collapsed condition;\n \nFIGS.', '2A to 2D\n are respectively perspective, first side, part sectional and second side views of the apparatus of \nFIGS.', '1A to 1D\n, shown in an expanded condition;\n \nFIGS.', '3A and 3B\n are geometric representations of an element of the apparatus of \nFIGS.', '1A to 1D\n, shown from one side;\n \nFIGS.', '4A to 4F\n are respectively first perspective, second perspective, plan, first end, lower, and second end views of an element of the apparatus of \nFIGS.', '1A to 1D\n;\n \nFIGS.', '5A and 5B\n are respectively perspective and sectional views through a retrievable bridge plug incorporating apparatus according to an embodiment of the invention, shown in a run position;\n \nFIG.', '6\n is a sectional view of the apparatus of \nFIGS.', '5A and 5B\n, shown in a set position;\n \nFIG.', '7\n is a sectional view of the apparatus of \nFIGS.', '5A and 5B\n, shown in a pull position;\n \nFIGS.', '8A to 8D\n are respectively first perspective, second perspective, third perspective, fourth perspective, plan, end, lower, first side and second side views of a ring segment of apparatus of \nFIGS.', '5A and 5B\n;\n \nFIGS.', '9A to 9D\n are respectively first perspective, second perspective, third perspective, fourth perspective, plan, end, lower, first side and second side views of a slip segment of the apparatus of \nFIGS.', '5A and 5B\n;\n \nFIGS.', '10A and 10B\n are respectively perspective and sectional views of a permanent plug according to an alternative embodiment of the invention, shown in a run position;\n \nFIGS.', '11A and 11B\n are respectively first and second perspective views of a slip segment of the apparatus of \nFIGS.', '10A and 10B\n;\n \nFIGS.', '12A and 12B\n are respectively first and second perspective views of a ring segment according to an alternative embodiment of the invention;\n \nFIGS.', '13A to 13D\n are respectively first sectional, second sectional, isometric, and cross sectional views of a lock apparatus according to an embodiment of the invention, shown in a run position;\n \nFIGS.', '14A to 14D\n are respectively first sectional, second sectional, isometric, and cross sectional views of the apparatus of \nFIGS.', '13A to 13D\n, shown in a set position;\n \nFIGS.', '15A to 15D\n are respectively perspective, perspective cut-away, sectional and cross-sectional views of a quick connect apparatus according to an embodiment of the invention, shown in a lock out position;\n \nFIGS.', '16A to 16C\n are respectively perspective, sectional and cross-sectional views of the apparatus of \nFIGS.', '15A to 15D\n, shown in a release position;\n \nFIGS.', '17A to 17C\n are respectively perspective, sectional and end views of an apparatus according to an alternative embodiment of the invention, shown in a collapsed condition;\n \nFIGS.', '18A to 18C\n are respectively perspective, sectional and end views of the apparatus of \nFIGS.', '17A to 17C\n, shown in an expanded condition;\n \nFIG.', '19\n is a geometric representation of a centre element of the apparatus of \nFIGS.', '17A to 17C\n, shown from one side;\n \nFIGS.', '20A to 20F\n are respectively first perspective, second perspective, plan, first end, lower, and second end views of a centre element of the apparatus of \nFIGS.', '17A to 17C\n;\n \nFIG.', '21\n is a geometric representation of an outer element of the apparatus of \nFIGS.', '17A to 17C\n, shown from one side;\n \nFIG.', '22A to 22H\n are respectively first perspective, second perspective, third perspective, fourth perspective, plan, first end, lower, and second end views of an outer element of the apparatus of \nFIGS.', '17A to 17C\n;\n \nFIGS.', '23A to 23C\n are respectively perspective, sectional and end views of an apparatus according to an alternative embodiment of the invention, shown in a collapsed condition;\n \nFIGS.', '24A to 24C\n are respectively perspective, sectional and end views of the apparatus of \nFIGS.', '23A to 23C\n, shown in an expanded condition;\n \nFIGS.', '25A and 25B\n are respectively perspective and sectional views of an apparatus according to an alternative embodiment of the invention, shown in a collapsed condition;\n \nFIGS.', '26A to 26D\n are respectively perspective, first sectional, end, and second sectional views of the apparatus of \nFIGS.', '25A and 25B\n, shown in an expanded condition;\n \nFIG.', '27\n is a geometric representation of a centre element of the apparatus of \nFIGS.', '25A and 25B\n, shown from one side;\n \nFIGS.', '28A to 28F\n are respectively first to fourth perspective, first end, and second end views of a centre element of the apparatus of \nFIGS.', '25A and 25B\n;\n \nFIGS.', '29A and 29B\n are respectively perspective and sectional views of a patch apparatus according to an embodiment of the invention, shown in a collapsed condition;\n \nFIGS.', '30A and 30B\n are respectively perspective and sectional views of the apparatus of \nFIGS.', '29A and 29B\n, shown in an expanded condition;\n \nFIG.', '31\n is a side view of an apparatus according to an alternative embodiment of the invention in a first, collapsed condition;\n \nFIG.', '32\n is a side view of the apparatus of \nFIG.', '31\n a second, collapsed condition;\n \nFIGS.', '33A and 33B\n are respectively plan and isometric views of an element of the apparatus of \nFIGS.', '31 and 32\n;\n \nFIGS.', '34A and 34B\n are respectively plan and isometric views of a second element of the apparatus of \nFIGS.', '31 and 32\n;\n \nFIGS.', '35A and 35B\n are respectively isometric and sectional views of a drift tool according to an embodiment of the invention, shown in a run position;\n \nFIGS.', '36A and 36B\n are respectively isometric and sectional views of the apparatus of \nFIGS.', '35A and 35B\n, shown in an alternative run position;\n \nFIGS.', '37A and 37B\n are respectively isometric and sectional views of the apparatus of \nFIGS.', '35A and 35B\n, shown in a collapsed position;\n \nFIGS.', '38A and 38B\n are respectively isometric and sectional views of a broaching tool apparatus according to an embodiment of the invention, shown in a run position; and\n \nFIGS.', '39A and 39B\n are respectively isometric and sectional views of the apparatus of \nFIGS.', '38A and 38B\n, shown in a collapsed position.', 'DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS\n \nReferring firstly to \nFIGS.', '1 to 4\n, the principles of the invention will be described with reference to an expanding apparatus in accordance with the first embodiment.', 'In this embodiment, the expanding apparatus, generally depicted at \n10\n, comprises an expanding ring structure configured to be expanded from a first collapsed or unexpanded condition (shown in \nFIGS.', '1A to 1D\n) and a second expanded condition (shown in \nFIGS.', '2A to 2D\n).', 'The apparatus of this and other embodiments may be referred to as “expanding apparatus” for convenience, as they are operable to move to an expanded state from a normal collapsed state.', 'However, the apparatus may equally be referred to as a collapsing apparatus, or an expanding or collapsing apparatus, as they are capable of being expanded or collapsed depending on operational state.', 'The expanding apparatus \n10\n comprises a plurality of elements \n12\n assembled together to form a ring structure \n11\n.', 'The elements \n12\n define an inner ring surface which is supported by the outer surface of cylinder \n14\n.', 'Each element comprises an inner surface \n20\n, an outer surface \n21\n and first and second contact surfaces \n22\n, \n23\n.', 'The first and second contact surfaces are oriented in non-parallel planes, which are tangential to a circle centred on the longitudinal axis of the apparatus.', 'The planes converge towards the inner surface of the element.', 'Therefore, each element is in the general form of a wedge, and the wedges are assembled together in a circumferentially overlapping fashion to form the ring structure \n11\n.', 'In use, the first and second contact surfaces of adjacent elements are mutually supportive.', 'As most clearly shown in \nFIGS.', '3A and 3B\n, when the ring structure is expanded to its optimal outer diameter', ', the orientation planes of the first and second contact surfaces intersect an inner surface of the ring structure, and together with the longitudinal axis of the apparatus, the lines of intersection define a sector of a cylinder.', 'In this case, the ring structure is formed from twenty-four identical elements, and the central angle θ\n1 \nis 15 degrees.', 'The angle described between the orientation planes of the first and second contact surface is the same as the central angle of the cylindrical sector, so that the elements are arranged rotationally symmetrically in the structure.', 'As shown in \nFIG.', '3B\n, each element is based on a notional wedge-shaped segment of a ring centred on an axis, with each notional wedge-shaped segment being inclined with respect to the radial direction of the ring.', 'The nominal outer diameter of the segment is at the optimum expansion condition of the ring (with radius shown at r\n1\n).', 'The orientation planes of the first and second contact surfaces of the element are tangential to a circle with radius r\n3 \nconcentric with the ring at points t\n1\n, t\n2\n.', 'The angle described between the tangent points is equal to the angle θ\n1 \nof the segment.', 'The orientation planes of the first and second contact surfaces of each notional wedge-shaped segment intersect one another on a radial plane P which bisects radial planes located at the tangent points (i.e. is at an angle of θ\n1\n/2 to both).', 'This intersection plane P defines the expanding and collapsing path of the segment.', 'In the configuration shown in \nFIGS.', '1 and 2\n, notional wedge-shaped segments are modified by removal of the tips \n29\n of the wedges, to provide a curved or arced inner surface \n20\n with radius r\n2 \nwhen the ring is in its expanded condition shown in \nFIGS.', '2A and 2D\n.', 'The modification of the wedge-shaped elements can be thought of as an increase in diameter of an internal bore through the ring structure by 2(r\n2\n−r\n3\n), or a truncation of the inner diameter.', 'This change in the inner diameter from the notional inner diameter r\n3 \nto which the contact surfaces are tangential to a truncated inner diameter r\n2\n, has the effect of changing an angle between the contact surfaces and the radial plane from the centre of the ring.', 'Taking angle θ\n2 \nto be the angle described between the contact surface and a radial plane defined between the centre point of the ring structure and the point at which the orientation surface meets or intersects a circle at the radial position of the inner surface, θ\n2 \nis changed in dependence on the amount by which the segment has its inner diameter truncated.', 'For the notional wedge shaped segment, the orientation planes of the contact surfaces are tangential to a circle at the inner diameter at r\n3 \n(i.e. angle θ\n2 \nis 90 degrees).', 'For the modified elements \n12\n, the orientation planes of the contact surfaces instead intersect a circle at the (increased) inner diameter at r\n2 \nand are inclined at a reduced angle θ\n2\n.', 'The angle θ\n2 \nat which the segment is inclined is related to the amount of material removed from the notional wedge-shaped segment, but is independent from the central angle θ\n1 \nof the wedge.', 'Angle θ\n2 \nis selected to provide element dimensions suitable for manufacture, robustness, and fit within the desired annular volume and inner and outer diameters of the collapsed ring.', 'As the angle θ\n2 \napproaches 90 degrees, a shallower, finer wedge profile is created by the element, which may enable optimisation of the collapsed volume of the ring structure.', 'Although a shallower, finer wedge profile may have the effect of reducing the size of the gaps created at the inner surface of the ring in the collapsed condition and/or enabling a more compact collapsed condition, there are some consequences.', 'These include the introduction of flat sections at the inner surfaces of the elements, which manifest as spaces at the inner diameter of the ring when in an expanded or partially expanded condition.', 'When θ\n2\n=90 degrees, all the segments are purely tangential to inner diameter, the collapsed volume for a given outer diameter and inner diameter is most efficient, but the inner surface of the ring structure is polygonal with flat sections created by each segment.', 'In some configurations, these flat sections may be undesirable.', 'There may also be potential difficulties with manufacture of the elements and robustness of the elements and assembled ring structure.', 'However, in many applications, where the profile of the inner surface of the expanded ring is not critical, for example when the inner diameter of the ring structure is floating, and/or the true inner diameter is defined by an actuation wedge profile rather than the inner surface of the ring, this compromise may not be detrimental to the operation of the apparatus, and the reduced collapse volume may justify an inclination angle θ\n2 \nof (or approaching) 90 degrees.', 'In the apparatus of \nFIGS. 1 to 4\n, the angle θ\n2 \nis 75 degrees.', 'Relaxing θ\n2 \nto a reduced angle provides a smooth outer diameter and inner diameter profile to the expanded ring, as a portion of the inner circular arc is retained at the expense of slightly increased collapsed volume.', 'It should be noted that the angle θ\n2 \nis independent from the angle θ\n1\n.', 'Where the ring structure is desired to have a circular inner surface, preferred arrangements may have an angle θ\n2 \nwhich is in the range of (90 degrees-2θ\n1\n) to 90 degrees inclusive, and particularly preferred arrangements have an angle θ\n2 \nin the range of 70 degrees to 90 degrees (most preferably in the range of 73 degrees to 90 degrees).', 'In general, to provide sufficient truncation of the inner diameter to retain a useful portion of an inner arc and provide a smooth inner surface to the ring structure, a maximum useful value of θ\n2 \nis (90 degrees-θ\n1\n/2).', 'This would be 82.5 degrees in the described arrangements.', 'In other configurations, also in accordance with embodiments of the invention (and as will be described below) the geometry of the notional wedge-shaped segments forming the elements may be unmodified (save for the provision of functional formations such as for interlocking and/or retention of the elements), without the removal of material from the tip of the notional wedge-shaped segments.', 'Such embodiments may be preferred when there is no requirement for the ring structure to have a circular inner surface.', 'As most clearly shown in \nFIGS.', '4A to 4F\n, the first and second contact surfaces of the element have corresponding interlocking profiles \n24\n formed therein, such that adjacent elements can interlock with one another.', 'In this case, the interlocking profiles comprise a dovetail groove \n25\n and a corresponding dovetail tongue \n26\n.', 'The interlocking profiles resist circumferential and/or radial separation of the elements in the ring structure, but permit relative sliding motion between adjacent elements.', 'The interlocking profiles also facilitate smooth and uniform expansion and contraction of the elements during use.', 'It will be appreciated that alternative forms of interlocking profiles, for example comprising recesses and protrusions of other shapes and forms, may be used within the scope of the invention.', 'The elements are also provided with inclined side wall portions \n27\n, which may facilitate deployment of the apparatus in use.', 'The side wall portions are formed in an inverted cone shape which corresponds to the shape and curvature of the actuating cone wedges profiles when the apparatus is in its maximum load condition (typically at its optimum expansion condition).', 'Each element is also provided with a groove \n28\n, and in the assembled ring structure, the grooves are aligned to provide a circular groove which extends around the ring.', 'The groove accommodates a biasing element (not shown), for example a spiral retaining ring of the type marketed by Smalley Steel Ring Company under the Spirolox brand, or a garter spring.', 'In this case, the biasing means is located around the outer surface of the elements, to bias the apparatus towards the collapsed condition shown in \nFIGS.', '1A to 1D\n.', 'Although one groove for accommodating a biasing means is provided in this embodiment, in alternative embodiments of the apparatus, multiple grooves and biasing means may be provided.', 'The apparatus \n10\n comprises a wedge member \n16\n, which in this case is an annular ring having a conical surface \n18\n opposing one side of the ring structure \n11\n.', 'The wedge angle corresponds with the angle of the inclined conical side walls \n27\n of the elements.', 'A corresponding wedge shaped profile (not shown) is optionally provided on the opposing side of the ring structure to facilitate expansion of the ring elements.', 'In alternative embodiments of the invention this optional additional wedge may be substituted with an abutment shoulder.', 'Operation of the expansion apparatus will now be described.', 'In the first, collapsed or unexpanded condition, shown most clearly in \nFIG.', '10\n, the elements are assembled in a ring structure \n11\n which extends to a first outer diameter.', 'In this embodiment, and as shown in \nFIGS.', '1B and 10\n, the wedge member \n16\n defines the maximum outer diameter of the apparatus in the first condition.', 'The elements are biased towards the unexpanded condition by a spiral retaining ring (not shown), and are supported on the inner surface by the outer surface of the cylinder \n14\n.', 'In use, an axial actuation force is imparted on the wedge member \n16\n.', 'Any of a number of suitable means known in the art can be used for application of the axial actuation force, for example, the application of a force from an outer sleeve positioned around the cylinder.', 'The force causes the wedge member \n16\n to move axially with respect to the cylinder, and transfer a component of the axial force onto the recessed side wall of the elements.', 'The angle of the wedge transfers a radial force component to the elements \n12\n, which causes them to slide with respect to one another along their respective contact surfaces.', 'The movement of the expanding elements is tangential to a circle defined around the longitudinal axis of the apparatus.', 'The contact surfaces of the elements mutually support one another before, during, and after expansion.', 'The radial position of the elements increases on continued application of the axial actuation force until the elements are located at a desired outer radial position.', 'This radial position may be defined by a controlled and limited axial displacement of the wedge member, or alternatively can be determined by an inner surface of a bore or tubular in which the apparatus is disposed.', 'FIGS.', '2A to 2D\n show clearly the apparatus in its expanded condition.', 'At an optimal expansion condition, shown in \nFIGS.', '2B and 2D\n, the outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements.', 'The outer surface of the expansion apparatus can be optimised for a specific diameter, to form a perfectly round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.', 'It is a feature of the invention that the elements are mutually supported before, throughout, and after the expansion, and do not create gaps between the individual elements during expansion or at the fully expanded position.', 'In addition, the arrangement of elements in a circumferential ring, and their movement in a plane perpendicular to the longitudinal axis, facilitates the provision of smooth side faces or flanks on the expanded ring structure.', 'With deployment of the elements in the plane of the ring structure, the overall width of the ring structure does not change.', 'This enables use of the apparatus in close axial proximity to other functional elements.', 'The apparatus has a range of applications, some of which are illustrated in the following example embodiments.', 'However, additional applications of the apparatus are possible which exploit its ability to effectively perform one or more of blocking or sealing an annular path; contacting an auxiliary surface; gripping or anchoring against an auxiliary surface; locating or engaging with radially spaced profiles; and/or supporting a radially spaced component.', 'There will now be described an application of the expansion apparatus of the invention to a downhole oilfield apparatus, specifically a retrievable bridge plug.', 'A retrievable bridge plug is a downhole tool which is located and set in order to isolate a part of the wellbore, in a way that enables it to be unset and retrieved from the wellbore after use.', 'A typical retrievable bridge plug includes an arrangement of slips for anchoring the plug in the well, and a seal element for creating a fluid seal.', 'Slips used in bridge plugs are typically expensive to manufacture, as they may be required to be milled, turned, machined, wire cut and/or heat treated.', 'Moreover, slips used in bridge plugs conventionally work for a particular range of tubing weights.', 'This may require the wellbore contractor to have an inventory of slips for a single plug, which will be installed depending on where in the completion the plug is required to be placed.', 'The arrangement of slips and their deployment mechanism increases the axial length of the tool, which is generally undesirable and may be a critical issue in some applications.', 'In addition, an unsupported seal assembly may have a tendency to deform and fail through an extrusion gap between the maximum outer diameter of a gauge ring which supports the seal and the surrounding bore to which the seal element has been expanded.', 'The expansion apparatus of the invention offers a number of advantages in a bridge plug application, as will be apparent from the following description.\n \nFIG.', '5A\n is an isometric view of a retrievable bridge plug according to an embodiment of the invention, into which an expansion apparatus has been incorporated to perform anchoring and anti-extrusion functions.', 'FIG.', '5B\n is a longitudinal section through the bridge plug, generally shown at \n50\n, in a run position.', 'The plug \n50\n comprises a housing assembly \n51\n, and upper and lower connectors \n52\n, \n53\n for connecting the plug into a tool string.', 'The housing assembly \n51\n comprises upper and lower housing subs \n54\n, \n55\n located on a mandrel \n56\n on either side of a seal and anchor assembly \n57\n.', 'An actuation sleeve \n58\n connects the upper and lower housing subs on the mandrel.', 'The slip and seal assembly \n57\n comprises an expanding slip assembly \n60\n, an expanding anti-extrusion ring \n61\n, and an elastomeric seal element \n62\n disposed between the expanding slip assembly \n60\n and the expanding anti-extrusion ring \n61\n.', 'The expanding anti-extrusion ring \n61\n is similar to the expansion apparatus \n10\n, and will be understood from \nFIGS.', '1 to 4\n and the accompanying description.', 'FIGS.', '8A to 8D\n show the individual elements \n63\n of the expanding anti-extrusion ring \n61\n in more detail.', 'The elements \n63\n are similar to the elements \n12\n, and comprise inner and outer surfaces \n70\n, \n71\n, and first and second contact surfaces \n72\n, \n73\n.', 'The first and second contact surfaces are oriented in non-parallel planes, which are tangential to a circle centred on the longitudinal axis of the apparatus.', 'The elements \n63\n also comprise corresponding interlocking profiles \n74\n.', 'The elements \n63\n are slightly longer in an axial direction of the tool, and comprise a pair of grooves \n75\n for accommodating a pair of biasing springs.', 'The slip assembly \n60\n is also constructed and operated according to the principles of the invention.', 'The assembly \n60\n comprises a ring structure formed from a number of individual expansion slip elements, which interlock to create the ring structure.', 'Perspective views of the expansion slip elements \n77\n are provided in \nFIGS.', '9A to 9D\n.', 'Each slip element \n77\n is similar in form and function to the elements \n12\n and \n63\n, and their operation will be understood from the foregoing description.', 'However, in this embodiment, the outer surface of the element is provided with engaging means \n78\n defined by a series of grooves \n81\n and ridges \n82\n in the outer surface \n79\n, disposed on either side of retaining ring grooves \n80\n.', 'In this embodiment, the slip elements \n77\n are bidirectional; the engaging means on respective sides of the of the slip surface are asymmetrically formed in opposing directions, to provide an anchoring forces which resist movement in both upward and downward directions.', 'Operation of the bridge plug will now be described with particular reference to \nFIGS.', '5B, 6 and 7\n.', 'When the plug is located at the desired position in the wellbore, it is ready to be set, and a setting tool is used to impart a force to the plug in a manner known in the art.', 'In this example embodiment, a setting tool (not shown) impart a downward force on the outer housing \n51\n relative to the mandrel \n56\n, resulting in a relative movement between the housing and the mandrel.', 'The downward axial force is transferred from the upper housing sub \n54\n to the actuation sleeve \n58\n via upper shear screws \n64\n.', 'An initial downward force on the outer housing with respect to the mandrel causes lower shear screws \n65\n to shear, enabling the upper housing sub \n54\n and actuation sleeve \n58\n to move downward with respect to the lower housing sub \n55\n.', 'Downward movement of the actuation sleeve \n58\n moves the fixed upset wedge profile \n66\n of the actuation sleeve towards the slip assembly \n60\n, to impart an axial force on the slip assembly \n60\n.', 'The slip assembly is axially compressed between the wedge profile \n66\n of the actuation sleeve and a lower wedge profile \n67\n on the lower housing sub \n55\n.', 'The slip elements slide with respect to one another in a tangential direction and move to their radially extended positions, in the manner described with reference to \nFIGS.', '1 and 2\n.', 'The outer surface of the ring structure formed by the slip elements is moved into engagement with the inner surface of the wellbore, where the engaging means anchors the slips at the plug to the wellbore.', 'As the upper housing sub moves downwards with respect to the mandrel, a ratchet sleeve \n49\n and ratchet clip locks the position of the sub \n54\n, and prevents return movement of the housing and release of the slips.', 'A further downward force on the upper housing sub with respect to the inner mandrel causes the upper shear screws \n64\n to shear, which enables the upper housing sub \n54\n to move downwards with respect to the mandrel \n56\n and the actuation sleeve \n58\n.', 'Movement of the upper housing assembly \n54\n imparts an axial force on the anti-extrusion ring \n60\n between a wedge profile \n68\n of the upper housing sub \n54\n and a movable wedge member \n69\n disposed between the seal assembly \n62\n and the anti-extrusion ring \n60\n.', 'The axial force results in radial deployment of the element in the manner described above.', 'The downward force also acts on the movable wedge member \n69\n to compress the seal element \n62\n between the wedge \n69\n and the upset profile \n66\n on the slip actuation sleeve.', 'The compressed seal \n62\n is expanded in a radial direction into contact with the surrounding wellbore wall.', 'The expanded condition is shown in \nFIG.', '6\n, with the position locked by the ratchet sleeve \n49\n and ratchet clip to prevent return movement of the housings and release of the slips and anti-extrusion ring \n61\n.', 'The anti-extrusion ring \n61\n provides a full extrusion barrier at the upper end of the seal element \n62\n.', 'The expanded slip assembly \n60\n provides a similar anti-extrusion barrier at the lower end of the seal \n62\n, in addition to its anchoring functionality.', 'By appropriate using shear screws \n64\n, \n65\n, the plug is made operable to fully deploy the anti-extrusion ring before the seal element is fully compressed.', 'This ensures that there is a fully contained volume, with little or no extrusion gap, into which the seal element is compressed.', 'In a preferred embodiment of the anti-extrusion ring is fully expanded before the seal element begins to be compressed.', 'FIG.', '7\n shows the plug \n50\n in a pull position.', 'A release tool is run to the plug and engages with a ratchet release sleeve \n48\n, to move it downwards with respect to the mandrel.', 'Movement of the release sleeve releases keys which support the ratchet sleeve \n49\n on the mandrel.', 'With the ratchet released, the upper and lower housings and actuation sleeve may move upwards relative to the mandrel, to release the actuation force on the slips and seal, resulting in their collapse.', 'Movement of the sleeve relative to the housing subs results in engagement of an upper ratchet lock-out mechanism \n59\na \nbetween the upper end of the actuation sleeve and the upper housing sub and a lower ratchet lock-out mechanism \n59\nb \nbetween the lower end of the actuation sleeve and the lower housing sub.', 'With these components locked together, relative movement of the wedge elements is prevented, to stop expansion of the respective expansion components during pulling out of hole (for example if a restriction is encountered during pulling).', 'Referring now to \nFIGS.', '10A to 11B\n, there is shown the application of the invention to a permanent plug, in accordance with an alternative embodiment.', 'FIG.', '10A\n is a perspective view of the permanent plug, generally depicted at \n100\n, and \nFIG.', '10B\n is a longitudinal sectional view.', 'In each of \nFIGS. 10A and 10B\n, the plug is shown in a set position.', 'The plug \n100\n is similar to the retrievable plug \n50\n, and is general form and function will be understood from \nFIGS.', '5 to 7\n and the accompanying description.', 'However, the plug \n100\n is designed to be permanently installed in a wellbore, and therefore lacks the retrievable functionality of the plug \n50\n.', 'The plug \n100\n comprises an upper slip assembly \n101\n, and a lower slip assembly \n102\n, positioned either side of an elastomeric seal element \n103\n disposed on a mandrel \n104\n.', 'A housing \n105\n enables a downward force to be imparted to the slip assemblies \n101\n, \n103\n, with the wedge members directing a radial expansion force to slip elements, resulting in relative tangential sliding movement of the individual slip elements.', 'The plug \n100\n differs from the plug \n50\n in that the anti-extrusion functionality is provided by a pair of slip assemblies rather than providing a dedicated anti-extrusion ring.', 'FIGS.', '11A and 11B\n are perspective views of individual slip elements \n107\na\n, \n107\nb \nused respectively in the upper and lower slip assemblies \n101\n, \n102\n.', 'The slip elements are similar to the slip elements \n77\n, and function in the same manner.', 'However, in this embodiment, because a slip assembly is provided above and below the seal element, the engagement profiles on the slips are not bidirectional.', 'Instead, the engagement profiles \n108\na\n, \n108\nb \nof the respective slip assemblies are unidirectional.', 'The elements of the upper slip assembly are arranged to engage a surrounding surface and resist movement in one direction, whereas the slip elements of the lower assembly are arranged with engaging means configured to resist movement in the opposite direction.', 'Together, the upper and lower slip assemblies provide bidirectional anchoring of the plug in the wellbore.', 'The angles of the respective wedges and the corresponding surfaces in the slip assemblies, along with the retaining force of the biasing means, are selected so that the lower slip assembly can be deployed by an axial force which is directed through the elastomeric seal element.', 'In other words, the axial force required to press the seal element between the anti-extrusion surfaces created by the slip assemblies is greater, and preferably much greater, than the force required to deploy the slip assemblies.', 'This facilitates a full and proper deployment of the slip assemblies before the elastomeric seal element is radially expanded by compression between the wedges.', 'The slip elements \n107\na\n, \n107\nb \nof this embodiment are also provided with anti-rotation pegs \n109\n.', 'These pegs are received in corresponding slots in the actuating wedge surfaces, and ensure that the slip elements are not able to rotate with respect to the mandrel and the rest of the plug \n100\n.', 'This configuration prevents the mandrel and other components of the plug from rotating with respect to the slip assemblies if the plug is required to be drilled in order to remove it from the wellbore.', 'It will be appreciated that alternative configurations may be applied to permanent plug applications, and in particular, that a permanent plug may be configured without slip assemblies being disposed above and below the seal elements.', 'By way of example, \nFIGS.', '12A and 12B\n are respectively perspective views of an expansion element of an anti-extrusion ring, and a bidirectional slip element, both of which may be used in permanent plug configurations.', 'The expansion element of \nFIG.', '12A\n is configured to create an anti-extrusion ring structure which functions in the same way as the anti-extrusion ring structure \n61\n of the plug \n50\n, with the addition of anti-rotation pegs.', 'The slip element of \nFIG.', '12B\n is similar in form and function to the slip element \n77\n, and is assembled to a bidirectional slip assembly and operates in the same manner as the slip assembly \n60\n of plug \n50\n, with the addition of anti-rotation pegs.', 'The foregoing embodiments describe the application of the principles of the invention to wellbore plugs, but it will be apparent from the description that the anti-extrusion ring configurations described with reference to \nFIGS.', '5 to 12\n may be applied to tools and devices other than downhole plugs.', 'For example, the system may be used to provide an anti-extrusion ring or back-up ring for a wide range of expanding, radially expanding or swelling elements.', 'For example, the apparatus may be used as an anti-extrusion or back-up ring for compressible, inflatable and/or swellable packer systems.', 'Alternatively, or in addition, the expansion apparatus may provide support or back-up for any suitable flow barrier or seal element in the fluid conduit.', 'This may function to improve the integrity of the fluid barrier or seal, and/or enable a reduction in the axial length of the seal element or flow barrier without compromising its functionality.', 'Furthermore, the slip assembly applications of the invention as described in the foregoing embodiments may be used to anchor any of a wide range of tools in the wellbore, and are not limited to bridge plug applications.', 'For example, the slip assemblies may be used to anchor drilling, milling or cutting equipment; perforating gun assemblies; or intervention tools deployed by wireline or other flexible conveyance systems.', 'The invention also has benefits in creating a seal and/or filling an annular space, and an example application will be described with reference to \nFIGS.', '13A to 14D\n, in which the invention is applied to a downhole locking tool.', 'A typical locking tool uses one or more radially expanding components deployed on a running tool.', 'The radially expanding components engage with a pre-formed locking profile at a known location in the wellbore completion.', 'A typical locking profile and locking mechanism includes a recess for mechanical engagement by the radially expanding components of the locking tool.', 'A seal bore is typically provided in the profile, and a seal on the locking tool is designed to seal against the seal bore.', 'The present embodiment of the invention provides benefits over conventional locking mechanisms as will be apparent from the description below.', 'FIGS.', '13A and 13B\n are first and second longitudinal sectional views through a locking tool according to an embodiment of the invention.', 'FIG.', '13C\n is an isometric view of a locking tool, and \nFIG.', '13D\n is a cross section which shows the position of the longitudinal sections of \n13\nA and \n13\nB.', 'In all of \nFIGS.', '13A to 13D\n, the locking tool is shown in a run position.', 'FIGS.', '14A to 14D\n are equivalent views of the locking tool in a set position.', 'The locking tool, generally depicted at \n130\n, comprises an upper housing \n131\n, which provides an upper connecting profile, and a lower housing \n132\n.', 'In the run position, the upper and lower housings \n131\n, \n132\n are assembled on a mandrel \n133\n in an axially separated position.', 'The upper housing \n131\n is secured on the mandrel by a set of shear screws \n134\n.', 'An actuation sleeve \n135\n is disposed on the mandrel \n133\n, and connects the upper housing with the lower housing.', 'A lower part \n135\na \nof the actuation sleeve is cylindrical, and a lower end of the actuation sleeve is provided with a conical wedge profile \n136\n.', 'An upper part \n135\nb \nof the actuation sleeve has part cylindrical sections removed, such that only parts of the actuation sleeve, circumferentially separated around the sleeve, extend to its upper end and engage with the upper housing.', 'Windows \n137\n formed by removing part sections of the actuation sleeve correspond to the locations of detent fingers \n138\n of the mandrel \n133\n, and accommodate radially extending formations \n139\n at the end of the detent fingers.', 'The locking tool also comprises a locking and sealing assembly, generally shown at \n140\n, located in an annular space between first and second subs of the lower housing.', 'The locking and sealing assembly is formed from two axially separated ring structures \n141\na\n, \n141\nb\n, each formed from a plurality of elements.', 'Disposed between upper and lower ring structures is an elastomeric seal \n142\n on a support.', 'Individual elements assembled to form the ring structures are similar to the elements \n12\n and \n63\n, and their form and function will be understood from \nFIGS.', '1 to 4 and 8\n and their accompanying descriptions.', 'In particular, each element comprises a pair of planar contact surfaces which mutually supporting adjacent elements, and the contact surfaces are oriented on tangential planes.', 'In the run position, the ring structures \n141\na\n, \n141\nb \nare flush with the immediately adjacent outer diameter of the outer housing.', 'In an alternative configuration, the ring structures may be recessed with respect to the outer housing, such that they have a reduced outer diameter.', 'The outer diameter of the seal element is less than the outer diameter of the ring structures in their retracted position, such that the elastomeric seal element is recessed in the tool.', 'Operation of the locking tool will now be described with additional reference to \nFIGS.', '14A to 14D\n.', 'The locking tool \n130\n is run into the wellbore to a location in the completion which comprises a locking profile, generally shown at \n148\n.', 'The locking and sealing assembly \n140\n is positioned so that it is aligned with a locking recess \n146\n in the locking profile.', 'Alignment of the locking and sealing assembly with the locking profile is ensured by the provision of a no-go profile \n143\n on the lower housing assembly, and a corresponding no-go profile \n144\n on the completion at a defined axial separation from the locking profile.', 'With the locking tool in position and the no-go profile engaged, a downward force imparted on the upper housing \n131\n is transferred to the actuation sleeve \n135\n.', 'The lower housing \n132\n and mandrel \n133\n is held up by the no-go, and the shear screws \n134\n shear, enabling the actuation sleeve to move downwards relative to the lower housing until the wedge profile \n136\n of the actuation sleeve is brought into contact with the upper ring structure \n141\na\n.', 'The downward movement of the actuation sleeve imparts an axial force which is transferred through the elastomeric seal element \n142\n and to the lower ring structure \n141\nb\n, to axially compress the locking and sealing assembly \n140\n against a shoulder \n144\n defined by the lowermost housing sub.', 'As described with reference to previous embodiments, the wedge profiles direct a component of the axial force in a radially outward direction, to force the elements of the upper ring structure to a radially outward position.', 'The actuation sleeve passes under the upper ring structure so that it is fully deployed, and subsequently forces the elastomeric seal and its support radially outward.', 'The actuation sleeve continues downward movement to engagement with the lower ring structure, forcing its elements to a radially outward position, and into engagement with the locking profile.', 'The actuation sleeve \n135\n continues to move downwards through the housing until it reaches an abutment surface of an o-ring seal protection collar \n145\n which has a shape corresponding to the wedge profile \n136\n.', 'The o-ring seal protection collar \n145\n is moved off-seat to complete the sealing mechanism of the lock, with the o-ring sealing on the outer diameter of the actuation sleeve.', 'A continued downward force causes the upper housing to move with respect to the mandrel, until detent fingers \n138\n on the mandrel engage with a corresponding profile in the upper housing.', 'The detent fingers \n138\n are configured such that if the lock is not fully set, they will present an obstacle in the bore through the mandrel.', 'This enables verification, for example with a drift tool, that the locking mechanism is in a fully set position.', 'Engagement of the detent fingers prevents the upper and lower housings from being separated, which would enable the actuation sleeve to be withdrawn and the locking mechanism to be retracted.', 'The locking mechanism is therefore locked into engagement with the locking profile.', 'One advantage of the locking mechanism described with respect to \nFIGS.', '13A to 14D\n is that the locking mechanism is provided with an integrated seal element, and does not require a seal assembly at an axially separated point.', 'This enables a reduction in the length of the tool.', 'The integrated seal is surrounded at its upper and lower edges by the surfaces of the ring structures, which avoid extrusion of the seal.', 'In addition, each of the ring structures provides a smooth, unbroken circumferential surface which engages the locking recess, providing upper and lower annular surfaces in a plane perpendicular to the longitudinal axis of the bore.', 'This annular surface is smooth and unbroken around the circumference of the ring structures, and therefore the lock is in full abutment with upper and lower shoulders defined in the locking profile.', 'This is in contrast with conventional locking mechanisms which may only have contact with a locking profile at a number of discrete, circumferentially-separated locations around the device.', 'The increased surface contact provided by this embodiment of the invention enables a locking mechanism which can support larger axial loads being directed through the lock, and therefore the lock can be rated to a higher maximum working pressure.', 'Alternatively, an equivalent pressure rating can be provided in a lock which has reduced size and/or mass.', 'Another advantage of this embodiment of the invention is that the seal bore (i.e. the part of the completion with which the elastomer creates a seal) can be recessed in the locking profile.', 'In this embodiment, the inner diameter of the locking profile on either side of the lock recess \n146\n is less than the inner diameter of the seal bore.', 'The benefit of this configuration is that the seal bore is protected from the passage of tools and equipment through the locking profile.', 'This avoids impact with the seal bore which would tend to damage the seal bore, reducing the likelihood of reliably creating a successful seal.', 'In the foregoing embodiment, the benefits of the principles of the invention to a downhole locking mechanism are described.', 'Similar benefits may be delivered in latching arrangements used in connectors, such as so called “quick connect” mechanisms used for latched connection of tubular components.', 'Such an example application will be described with reference to \nFIGS.', '15A to 16C\n.', 'The connection system, generally shown at \n150\n, comprises a male connector \n151\n and a female connector \n152\n. \nFIG.', '15A\n is an isometric view of a male connector of a connection system according to an embodiment of the invention, and \nFIG.', '15B to 15D\n are respectively partially cut away isometric, longitudinal section and cross sectional views of an assembled pair of the male connector and a female connector according to an embodiment of the invention.', 'All of \nFIGS.', '15A to 15D\n show the apparatus in an expanded condition.', 'FIGS.', '16A to 16C\n are equivalent views which show the connection apparatus in a collapsed release condition.', 'The male connector \n151\n comprises an outer housing \n153\n disposed over an inner mandrel \n154\n which defines a throughbore through the connector.', 'The female connector \n152\n comprises a throughbore, which is continuous with the throughbore of the inner mandrel.', 'A first end of the inner mandrel is sized to fit into an opening in the female connector.', 'The outer housing \n153\n partially surrounds the mandrel \n154\n, and over a portion of its length has a throughbore formed to an inner diameter larger than the outer diameter of the mandrel, such that an annular space \n155\n is formed between the inner mandrel and the outer housing when the two are assembled together.', 'The annular space between the outer housing and the inner mandrel accommodates a support sleeve \n156\n and a biasing means in the form of a coil spring \n157\n.', 'The spring \n157\n functions to bias the support sleeve to a position in which it is disposed under an expansion apparatus \n158\n which forms a latching ring for the connection system.', 'An inner surface of the expansion apparatus is supported on the outer surface of the support sleeve.', 'The support sleeve is also mechanically coupled to an external sleeve \n159\n, disposed on the outside of the outer housing by pins extending through axially oriented slots in the outer housing.', 'The female connector \n152\n also comprises an annular recess \n160\n which is sized and shaped to receive the expansion apparatus in a latched position.', 'The annular recess is profiled with chamfered edges, to correspond to the inclined surfaces at the outside of the expansion apparatus \n158\n.', 'The expansion apparatus \n158\n of this embodiment of the invention is similar to the expansion apparatus described with reference to previous embodiments of the invention, and is assembled from multiple elements \n162\n.', 'However, a significant difference is that the expansion apparatus \n158\n is biased towards an expanded condition to provide a latching ring for the connection system.', 'This is achieved by the provision of grooves on the inner surfaces of the elements which make up the ring structure, to accommodate a circumferential spring element \n161\n.', 'The circumferential spring element \n161\n supports the elements of the ring in their optimum concentric state, which in this case is their radially expanded position.', 'The profile of the elements is such that they are wider at their inner surface than their outer surface, and wider than the tapered groove through which the ring structure extends.', 'This prevents the elements of the ring structure from being pushed out of the male connector by the circumferential spring element when the system is disconnected.', 'A disconnection of the connection system \n150\n will now be described, with additional reference to \nFIGS.', '16A to 16C\n.', 'FIGS.', '15A to 15D\n show the default, normally expanded position of the connector system \n150\n and its expansion apparatus \n158\n.', 'The circumferential spring element of the expansion apparatus biases the elements outward into the position shown at \nFIG.', '15A\n, and they are radially supported in that position by the support sleeve.', 'The external sleeve \n159\n allows the support sleeve \n156\n to be retracted against the biasing force of the spring \n157\n.', 'Withdrawal of the support sleeve \n156\n from beneath the expansion apparatus \n158\n enables the ring to be collapsed to a reduced radial position, shown in \nFIGS.', '16A to 16C\n.', 'The presence of the circumferential spring element \n161\n retains the elements in an outward expanded condition, but with the support sleeve \n156\n retracted, an axial force which acts separate the male and female parts of the connector will impart an axial force on the elements of the ring structure, via the chamfered edges of the recess \n160\n.', 'The profile of the recesses and the elements directs a radial force component which tends to cause the elements to collapse against the force of the spring element.', 'The elements are collapsed to a reduced diameter position which allows the male and female connectors to be separated.', 'When the expansion apparatus is clear of the female connector, the force of the spring element will tend to expand the elements to their radially expanded positions.', 'Releasing the external sleeve will position the support sleeve under the ring structure to support it in the expanded condition.', 'To connect the connectors of the connection system, the external sleeve is retracted to withdraw the support sleeve from beneath the elements.', 'An axial force which inserts the male connector into the female connector causes the elements to be brought into abutment with a shoulder at the opening of the female connector.', 'The inclined surface of the ring element radially collapses the elements against the force of the circumferential spring element, until the ring structure is able to pass through the bore opening to the latching position.', 'When the ring structure is aligned with the recess, the circumferential spring element pushes the elements into the recess.', 'Release of the external sleeve positions the support sleeve beneath the ring element and the connector is latched.', 'In its latched position and when in operation, a raised internal pressure in the throughbore of the connection system acts to radially compress and clamp the male connector, the support sleeve, and the ring structure together.', 'This resists or prevents retraction of the external sleeve and support sleeve, maintaining the connection in a failsafe latched condition.', 'A significant advantage of the connection system of this embodiment of the invention is that the expansion apparatus forms a solid and smooth ring in its expanded latched position.', 'An arrangement of radially split elements would, when expanded, form a ring with spaces between elements around the sides.', 'In contrast, the provision of a continuous engagement surface which surrounds the expansion ring and provides full annular contact with the recess provides a latch capable of supporting larger axial forces, and therefore the connection system can be rated to a higher maximum working pressure.', 'In addition, the by minimising or eliminating gaps between elements, the device is less prone to ingress of foreign matter which could impede the collapsing action of the mechanism.', 'The principles of the connection system of this embodiment may also be applied to subsea connectors such as tie-back connectors.', 'In alternative embodiments, the external sleeve for retracting the support sleeve may be hydraulically actuated, rather than manually as shown in the described embodiments.', 'The principles of the invention may be extended to multi-stage or telescopic expansion apparatus, which have applications to systems in which an increased expansion ratio is desirable.', 'The following embodiments of the invention describe examples of such apparatus.', 'Referring firstly to \nFIGS.', '17A to 18C\n, there is shown a two-stage expansion apparatus in accordance with an embodiment of the invention.', 'FIGS.', '17A to 17C\n are respectively perspective, longitudinal sectional, and end views of the apparatus in a first, collapsed condition.', 'FIGS.', '18A to 18C\n are equivalent views of the apparatus in an expanded condition.', 'The apparatus, generally depicted at \n170\n, comprises an expansion assembly \n171\n formed from three ring structures \n172\n, \n173\na\n, \n173\nb\n, each of which is formed from separate elements in the manner described with reference to \nFIGS.', '1 to 4\n.', 'The ring structures \n172\n, \n173\na\n, \n173\nb \nare disposed on a mandrel \n174\n between a wedge portion \n175\n which is fixed on a mandrel, and a moveable wedge member \n176\n.', 'A centre ring structure \n172\n is formed from a number of individual centre elements \n177\n assembled together.', 'The centre elements \n177\n are similar to the elements \n12\n and \n77\n described with reference to previous embodiments of the invention.', 'FIG.', '19\n is a geometric representation of a centre element of the apparatus of \nFIGS.', '17A to 17C\n, shown from one side, and \nFIGS.', '20A to 20F\n are respectively first perspective, second perspective, plan, first end, lower, and second end views of a centre element \n177\n.', 'The Figures show the inner and outer surfaces, first and second contact surfaces, interlocking profiles, and grooves for retaining circumferential springs which are equivalent in form and function to the features of the elements \n12\n and \n77\n.', 'Biasing means in the form of a circumferential spring retains the centre ring structure in its collapsed condition.', 'Disposed on either side of the centre ring structure are first and second outer ring structures \n173\na\n, \n173\nb \nin the form of wedge ring structures.', 'The wedge ring structures are also assembled from an arrangement of elements which, again, are similar in form and function to the elements \n12\n and \n77\n.', 'However, instead of providing an outer surface which is substantially parallel to the longitudinal axis of the apparatus, the outer surfaces of the outer elements are inclined to provide respective wedge surfaces \n178\na\n, \n178\nb \nwhich face the centre ring structure \n172\n.', 'FIG.', '21\n is a geometric representation of an outer element \n182\n of the apparatus of \nFIGS.', '17A to 17C\n, shown from one side, and \nFIGS.', '22A to 22H\n are respectively first perspective, second perspective, third perspective, fourth perspective, plan, first end, lower, and second end views of an outer element \n182\n.', 'The Figures show the inner and outer surfaces \n183\n, \n184\n, first and second contact surfaces \n185\n, \n186\n, interlocking profiles \n187\n, \n188\n, and grooves \n189\n for retaining circumferential springs which are equivalent in form and function to the features of the elements \n12\n and \n77\n.', 'In the assembled ring structure, the outer elements and the centre elements are nested with one another, and the outer surfaces \n184\n of the outer elements define respective wedge profiles for corresponding centre elements \n177\n during a first expansion stage as will be described below.', 'Biasing means in the form of a circumferential spring retains the outer rings structure in their collapsed conditions, with the sequencing of the expanding and collapsing movement controlled by the selection of the relative strengths of the biasing means of the centre ring and the outer rings.', 'In a first, collapsed condition, the elements of the centre ring structure and the elements of the first and second outer ring structures, have a maximum outer diameter which is less than or equal to the outer diameter of the wedge profile \n175\n and wedge member \n176\n.\n \nOperation of this embodiment of the apparatus will be described, with additional reference to \nFIGS.', '18A to 18C\n.', 'In common with other embodiments, the apparatus is actuated to be radially expanded to a second diameter by an axial actuation force which moves the cone wedge member \n176\n on the mandrel and relative to the ring structure.', 'The axial actuation force acts through the ring structures \n173\na\n, \n173\nb \nto impart axial and radial force components onto the elements.', 'Radial expansion of the ring structures \n173\na\n, \n173\nb \nis resisted by their respective circumferential springs arranged in grooves \n179\n, and the forces are transferred to the centre ring structure \n172\n.', 'The elements of centre ring experience an axial force from the wedge surfaces \n178\na\n, \n178\nb \nof the elements of the outer ring structures, which is translated to a radial expansion force on the elements of the centre ring structure \n172\n.', 'The radial expansion force overcomes the retaining force of a circumferential spring in the groove \n181\n (which is selected to be weaker than the retaining forces of the circumferential springs in the outer rings), and the elements slide with respect to one another to expand the centre ring structure as the outer ring structures move together.', 'The pair of outer rings is brought together until the elements of the centre ring structure are expanded on the wedge profiles of the outer elements.', 'In this condition, the first expansion stage is complete, but the centre ring is not yet expanded to its optimum outer diameter.', 'The elements of the wedge ring structure \n173\na\n, \n173\nb \nare symmetrical about a centre line of the ring structure, and are configured to be brought into abutment with one another under a central line under the centre segments.', 'This design defines an end point of the axial travel of an outer ring structure, and prevents its elements from over-travelling.', 'This abutment point changes the mode of travel of an outer ring from axial displacement (during which it expands an adjacent ring which is disposed towards the centre of the apparatus by a wedging action) into a tangential sliding movement of elements within the ring, to cause it to expand radially on the apparatus.', 'The outer ring structures \n173\na \nand \n173\nb \nhave been brought together into abutment, and further application of an axial actuation force causes the elements of the respective outer ring structures to experience a radial force component from the wedge \n175\n and the wedge profile \n176\n.', 'The radial force directs the elements of the outer ring structures to slide with respect to one another into radially expanded conditions.', 'The radial movement of the elements of the outer rings is the same as the movement of the elements of the centre ring structure and the elements described with reference to previous embodiments: the elements slide with respect to one another in a tangential direction, while remaining in mutually supportive planar contact.', 'As the outer ring structures expand, a radial force is imparted to the elements of the centre ring, which continue to slide with respect to one another in a tangential direction to their fully expanded condition.', 'The resulting expanded condition is shown in \nFIGS.', '18A to 18C\n.', 'The apparatus forms an expanded ring structure which is solid, with no gaps between its elements, and which has a smooth circular outer surface at its full expanded condition.', 'In addition, both of the annular surfaces or flanks of the expanded ring are smooth.', 'The outer diameter of the expanded ring is significantly greater than the outer diameter of the ring structures (and wedges) in their collapsed state, with the increased expansion resulting from the two stage mechanism.', 'Collapsing of the apparatus to a collapsed condition is achieved by releasing the axial actuation force.', 'The sequence of collapsing is the reverse of the expanding process: the outer ring structures are collapsed first under the higher retaining forces of their respective biasing springs.', 'Collapse of the outer rings also brings the centre ring structure from is fully expanded condition to an intermediate condition.', 'Further separation of the wedge profiles collapses the centre ring structure under the retaining force of its biasing spring, back to the collapsed position shown in \nFIGS.', '17A and 17B\n.', 'The principles of the two-stage expansion mechanism can be extended to other multi-stage expanding and collapsing apparatus.', 'FIGS.', '23A to 24C\n show such an apparatus, which has a four-stage expansion system.', 'FIGS.', '23A to 23C\n are respectively perspective, longitudinal sectional, and end views of the apparatus in a first, collapsed condition.', 'FIGS.', '18A to 18C\n are equivalent views of the apparatus in an expanded condition.', 'The apparatus, generally shown at \n190\n, is similar to the apparatus \n170\n, and its form and function will be understood from \nFIGS.', '17 and 18\n and the accompanying description.', 'However, the apparatus \n190\n differs in that it comprises a centre ring structure \n191\n formed from individual elements, and three pairs of outer ring structures \n192\n, \n193\n, \n194\n (each consisting of upper and lower ring structures \n192\na\n, \n192\nb\n, \n193\na\n, \n193\nb\n, \n194\na\n, \n194\nb\n) disposed on a mandrel \n197\n between wedge \n195\n and wedge profile \n196\n.', 'In successive stages of actuation, the centre ring structure \n191\n is deployed to a first intermediate expanded state, and first, second, and third pairs of outer ring structures are deployed to their radially expanded states, from the inside of the apparatus adjacent to the centre ring, to the outside.', 'At each stage, the centre ring structure is deployed to successive intermediate expanded states, until it is fully expanded as shown in \nFIGS.', '24A to 24C\n.', 'The outer diameter of the expanded ring is significantly greater than the outer diameter of the ring structures (and wedges) in their collapsed state, with the increased expansion resulting from the four-stage mechanism.', 'Sequencing of the expansion is designed to be from the inside to the outside by selection of biasing springs with successively higher retaining forces (moving from the inside or centre of the apparatus to the outermost rings).', 'Collapsing of the apparatus to a collapsed condition is achieved by releasing the axial actuation force, and the sequence of collapsing is the reverse of the expanding process.', 'FIGS.', '25A to 26D\n show a multi-stage expanding and collapsing system in accordance with an alternative embodiment of the invention.', 'FIGS.', '25A and 25B\n are respectively perspective and longitudinal sectional views of the apparatus in a first, collapsed condition.', 'FIGS.', '26A and 26B\n are equivalent views of the apparatus in an expanded condition; \nFIG.', '26C\n is an end view and \nFIG.', '26D\n is a section through line D-D of \nFIG.', '26B\n.', 'The apparatus, generally shown at \n280\n, is similar to the apparatus \n170\n and \n190\n, and its form and function will be understood from \nFIGS.', '17 to 24\n and the accompanying description.', 'However, the apparatus \n280\n differs in that it comprises pairs of ring structures \n281\n, \n282\n, \n283\n formed from individual elements with geometry different from those of previous embodiments.\n \nFIG.', '27\n is a geometric representation of a centre element of the apparatus of \nFIGS.', '25A and 25B\n, shown from one side, and \nFIGS.', '28A to 28F\n are respectively first perspective, second perspective, plan, first end, lower, and second end views of a centre element \n284\n.', 'The Figures show the inner and outer surfaces, first and second contact surfaces, interlocking profiles, and grooves for retaining circumferential springs which are equivalent in form and function to the features of the elements \n12\n and \n77\n.', 'Each element is effectively a segment of a ring which has its nominal outer diameter at the optimum expansion condition of the ring, but which has been inclined at an angle θ\n2 \nwith respect to a radial direction.', 'However, in this embodiment, θ\n2 \nis 90 degrees, and a shallower, finer wedge profile is created by the element.', 'The orientation planes of the contact surfaces are tangential to the circle described by the inner surface of the ring structure in its collapsed condition.', 'This enables optimisation of the collapsed volume of the ring structure, by reducing the size of the gaps created at the inner surface of the ring in the collapsed condition and enabling a more compact collapsed condition.', 'These include the introduction of flat sections \n285\n at the inner surface of the elements (visible in \nFIG.', '26D\n), which manifest as spaces at the inner diameter of the ring when in an expanded or partially expanded condition.', 'In the construction shown, the profile of the inner surface of the expanded ring is not critical, as the inner diameter of the ring structure is floating, and the true inner diameter is defined by the actuation wedge profiles \n286\n, \n287\n rather than the inner surface of the ring.', 'The spaces are therefore not detrimental to the operation of the apparatus, and the apparatus benefits from a reduced collapse volume.', 'The elements \n284\n also differ from the elements of previous embodiments of the invention in that the interlocking profiles formed by grooves and tongues are inverted, such that the groove \n288\n is in the inner surface of the element, and the tongue \n289\n is in the outer surface.', 'This increases the engagement length between adjacent elements.', 'The elements \n290\n of the ring structures \n282\n and \n283\n are similarly formed, with angle θ\n2 \nat 90 degrees, with the orientation planes of their contact surfaces being tangential to the circle described by the inner surface of the ring structure in its collapsed condition.', 'It should be noted that in other embodiments, different angles θ\n2 \nmay be adopted, including those which are in the range of 80 degrees to 90 degrees (most preferably tending towards 90 degrees).', 'Operation of the expanding and collapsing apparatus is the same as that described with reference to \nFIGS.', '23 and 24\n, with the centre ring structure \n281\n being deployed to a first intermediate expanded state, and first and second pairs of outer ring structures being deployed to their radially expanded states, in sequence from the inside of the apparatus adjacent to the centre ring \n281\n, to the outside.', 'Sequencing of the expansion is designed to be from the inside to the outside by selection of biasing springs with successively higher retaining forces (moving from the inside or centre of the apparatus to the outermost rings).', 'Collapsing of the apparatus to a collapsed condition is achieved by releasing the axial actuation force, and the sequence of collapsing is the reverse of the expanding process.', 'The apparatus \n280\n, by virtue of the compact collapsed inner volumes achievable with the finer wedge profiles, is capable of increased expansion ratios.', 'In this example, the apparatus \n280\n is configured to have the same expansion ratio as the apparatus \n190\n, with only two pairs of expanding ring structure compared with the three pairs in the apparatus \n190\n.', 'This reduces the axial length of the apparatus and greatly reduces the number of parts required.', 'The particularly high expansion ratios achieved with the multi-stage expansion embodiments of the invention enable application to a range of operations.', 'For example, the apparatus may form part of a mechanically actuated, high expansion, production packer or high expansion annular flow barrier.', 'Particular applications include (but are not limited to) cement stage packers or external casing packers for openhole applications.', 'The expansion ratios achievable also enable use of the apparatus in through-tubing applications, in which the apparatus is required to pass through a tubing or restriction of a first inner diameter, and by expanded into contact with a tubing of a larger inner diameter at a greater depth in the wellbore.', 'For example, the apparatus may be used in a high expansion retrievable plug, which is capable of passing through a production tubing to set the plug in a larger diameter liner at the tailpipe.', 'An application of the multi-stage expansion apparatus of \nFIGS.', '17 and 18\n to a fluid conduit patch tool and apparatus will now be described with reference to \nFIGS.', '29A to 30B\n.', 'A typical patching application requires the placement and setting of a tubular section over a damaged part of a fluid conduit (such as a wellbore casing).', 'A patch tool comprises a tubular and a pair of setting mechanisms axially separated positions on the outside of the conduit for securing the tubular to the inside of the fluid conduit.', 'It is desirable for the setting mechanisms to provide an effective flow barrier, but existing patch systems are often deficient in providing a fluid-tight seal with the inner surface of the fluid conduit.\n \nFIGS.', '29A and 29B\n show a high expansion patching tool, generally depicted at \n210\n, from perspective and longitudinal sectional views shown in a collapsed, run position.', 'FIGS.', '30A and 30B\n are equivalent views of the apparatus in an expanded condition.', 'The patching tool comprises a tubular section \n211\n, and a pair of expansion assemblies \n212\na\n, \n212\nb \n(together \n212\n) in axially separated positions on the section.', 'The distance between the assemblies \n212\na\n, \n212\nb \nis selected to span the damaged section of a fluid conduit to be patched.', 'Each of the assemblies \n212\n comprises a pair of expansion apparatus \n213\na\n, \n213\nb\n, disposed on either side of an elastomeric seal element \n214\n.', 'The expansion apparatus \n213\n are similar in form and function to the expansion apparatus \n170\n, and their operation will be described with reference to \nFIGS.', '17 and 18\n.', 'Each comprises a centre ring structure and a pair of outer ring structures.', 'A pair of cone wedge members \n215\n is provided on either side of the expansion apparatus \n213\n.', 'The elastomeric seal elements \n214\n are profiled such that an axially compressive force deforms the elastomeric material, and brings first and second halves \n214\na\n, \n214\nb \nof the seal element together around a deformation recess \n216\n.', 'The patch tool is, like other embodiments of the invention, configured to be actuated by an axial force.', 'The axial force acts to radially expand the expansion apparatus \n213\n in the manner described with reference to \nFIGS.', '17 and 18\n, and into contact with the fluid conduit to be patched.', 'The elastomeric seals are deformed by the axial force via the cone wedges \n215\n, to change shape and fill an enclosed annular space formed between a pair of expansion apparatus \n213\na\n, \n213\nb\n.', 'The expanded condition is shown in \nFIGS.', '30A', 'and 30B\n.', 'The expansion apparatus may provide sufficient frictional force with the inner surface of the conduit being patched to secure the patch tool in the conduit.', 'This may be facilitated by providing engaging profiles on the expansion apparatus (for example, similar to the expansion slips described with reference to \nFIGS.', '9, 11 and 12\n).', 'Alternatively (or in addition), separate anchor mechanisms may be provided.', 'The patching tool \n210\n provides a pair of effective seals which are fully supported by the expansion apparatus, each of which forms a solid anti-extrusion ring.\n \nFIGS.', '31 to 34B\n show a multi-stage expanding and collapsing system in accordance with an alternative embodiment of the invention.', 'FIGS.', '31 and 32\n are respectively side views of the apparatus in a first, collapsed condition and second expanded condition.', 'FIGS.', '33A and 33B\n are respectively plan and isometric views of the a first set of elements of the apparatus; \nFIGS.', '34A and 34B\n are respectively plan and isometric views of a second set of elements of the apparatus.', 'The apparatus, generally shown at \n380\n, is similar to the apparatus \n170\n, \n190\n, and \n280\n, with a central ring structure \n381\n formed from an assembly of elements \n384\n, and two pairs of ring structures \n382\na\n, \n382\nb \n(together \n382\n), \n383\na \nand \n383\nb \n(together \n383\n).', 'The form and function of the apparatus will be understood from \nFIGS.', '17 to 26\n and the accompanying description.', 'However, the apparatus \n380\n differs in that it comprises pairs of ring structures \n382\n, \n383\n formed from individual elements with geometry different from those of previous embodiments.', 'FIGS.', '33A and 33B\n are respectively plan and isometric views of an element \n385\n, from which the outer ring structures \n383\na\n, \n383\nb \nare assembled. \nFIGS.', '34A and 35B\n are respectively plan and isometric views of an element \n386\n, from which the intermediate ring structures \n382\na\n, \n382\nb \nare assembled.', 'The Figures show the outer surfaces, first contact surfaces, and interlocking tongues.', 'The external profiles of the elements \n385\n, \n386\n are modified by provision of additional chamfers \n387\n, \n388\n.', 'These chamfers modify the external profile of the elements, so that when assembled into a ring, the inward facing flank (i.e. the flank facing the centre ring) has an at least partially smoothed conical surface.', 'This facilitates the deployment of the apparatus; the smoother conical surface improves the sliding action of the elements the centre ring \n381\n on the conical profiles of the rings \n382\na\n, \n382\nb \nas the elements are brought together to expand the centre ring.', 'Similarly, the smoothed inward facing flank of the rings \n383\na\n, \n383\nb \nfacilitate the sliding of the elements \n382\na \nof the rings \n382\na\n, \n383\nb \nduring their expansion.', 'The smoothed cones assist a supporting ring in punching under the adjacent ring with a smooth action,\n \nThe outer surfaces \n389\n, \n390\n of the elements \n385\n, \n386\n are profiled such that the ring structures \n382\n, \n383\n define smooth conical surfaces on their outward facing flanks when in their expanded condition.', 'These conical surfaces combine in the assembled, expanded apparatus, to provide a substantially or fully smooth surface which is suitable for abutment with and/or support of an adjacent element such as an elastomer.', 'The elements \n385\n, \n386\n also differ from the elements of previous embodiments of the invention in that the biasing means in the form of garter springs are not mounted in external grooves.', 'Instead, apertures \n391\n, \n392\n are provided in the elements for receiving the garter springs (or an alternative biasing means).', 'The garter spring may be threaded through each segment and then joined to make a continuous loop upon assembly.', 'By providing the biasing means in-board of the external surface, it may be better protected from damage.', 'In addition, the external profile of the elements is simplified and is more supportive of adjacent elements.', 'as supportive as possible.', 'This configuration also facilitates location of the biasing means directly over the dovetail feature, so that the biasing force acts centrally to avoid canting and jamming.', 'It will be appreciated that “single stage” expansion apparatus, for example as described with reference to \nFIGS.', '1 to 4\n, may be used in a patching tool and method of use.', 'Indeed, in some applications this may desirable, as the resulting patched tubular can have an inner diameter close to the inner diameter of the fluid conduit that has been patched, mitigating the reduction to bore size.', 'However, the patching tool \n170\n has the advantage of high expansion for a slim outer diameter profile, which enables the tool to be run through a restriction in the fluid conduit, to patch a damaged part of the conduit which has a larger inner diameter than the restriction.', 'For example, the patching tool could be run through a part of the fluid conduit that has already been patched, either by conventional means or by a patching tool based on a single-stage expansion apparatus.', 'Higher expansion ratio patching tools could be used, based on expansion apparatus having three or more stage deployment.', 'In the foregoing embodiments, where the expanding and collapsing apparatus is used to create a seal, the seal is typically disposed between two expanding ring structures.', 'In alternative embodiments (not illustrated), an expanding ring structure can be used to provide a seal, or at least a restrictive flow barrier directly.', 'To facilitate this, the elements which are assembled together to create the ring structures may be formed from a metal or a metal alloy which is fully or partially coated or covered with a polymeric, elastomeric or rubber material.', 'An example of such a material is a silicone polymer coating.', 'In one embodiment, all surfaces of the elements may be coated, for example by a dipping or spraying process, and the mutually supportive arrangement of the elements keeps them in compression in their operating condition.', 'This enables the ring structures themselves to function as flow barriers, and in some applications, the seal created is sufficient to seal against differential pressures to create a seal.', 'Alternatively, or in addition, the elements themselves may be formed from a compressible and/or resilient material, such as an elastomer, rubber or polymer.', 'In a further alternative embodiment of the invention (not illustrated) the characteristics of the expanding/collapsing apparatus are exploited to provide a substrate which supports a seal or other deformable element.', 'As described herein, the expanded ring structures of the invention provide a smooth circular cylindrical surface at their optimum expanded conditions.', 'This facilitates their application as a functional endo-skeleton for a surrounding sheath.', 'In one example application, a deformable elastomeric sheath is provided over an expanding ring structure \n10\n, as described with reference to \nFIGS.', '1 to 4\n.', 'When in its collapsed condition, the sheath is supported by the collapsed ring structures.', 'The ring structure are deployed in the manner described with reference to \nFIGS.', '1 and 2\n, against the retaining force of the circumferential spring element and any additional retaining force provided by the sheath, and the sheath is deformed to expand with the ring structure into contact with the surrounding surface.', 'The sheath is sandwiched between the smooth outer surface of the ring structure and the surrounding surface to create a seal.', 'Although the example above is described with reference to a single-stage expanding apparatus, it will be appreciated that a multistage expanding apparatus (for example the apparatus \n170\n) could be used.', 'In addition, the expanding apparatus may be used as an endo-skeleton to provide structural support for components other than deformable sheaths, including tubulars, expanding sleeves, locking formations and other components in fluid conduits or wellbores.', 'Additional applications of the principles of the invention include variable diameter tools.', 'Examples will be described with reference to \nFIGS.', '35A to 39B\n.', 'FIGS.', '35A and 35B\n are respectively perspective and longitudinal sectional views of a variable diameter drift tool according to an embodiment of the invention, shown in a first run position.', 'FIGS.', '36A and 36B\n, are equivalent views of the drift tool in an alternative run position, and \nFIGS.', '37A and 37B\n are equivalent views of the drift tool in a collapsed position.', 'The drift tool, generally depicted at \n230\n, comprises a central core \n231\n, upper and lower housings \n232\na\n, \n232\nb\n, and upper and lower connectors \n233\na\n, \n234\na \nfor connecting the tool to a tool string or other conveyance.', 'Disposed between the upper and lower housings is an expanding and collapsing apparatus \n234\n, which provides the variable diameter functionality of the tool.', 'The expanding and collapsing apparatus \n234\n comprises a ring structure \n235\n assembled from a plurality of elements \n236\n.', 'The elements \n236\n are similar to the elements \n12\n and \n77\n of previous embodiments, and their assembly and expanding and collapsing functionality will be understood from \nFIGS.', '1 to 4\n and the accompanying text.', 'The elements \n236\n differ from the elements previously described in their outer profile.', 'The elements are not, in this embodiment, designed to create a smooth outer ring surface, but instead are designed to present a fluted surface at their optimal and intermediate expanded positions.', 'This is to permit fluid to pass the tool as it is being run in a wellbore in an expanded condition.', 'In addition, the ring structure \n235\n defines a central portion \n237\n, in which the ring surface is substantially parallel to the longitudinal axis of the tool, and upper and lower tapered portions \n238\na\n, \n238\nb\n.', 'The tapered portions facilitate the passage of the tool in the wellbore without being hung up on minor restrictions on the bore.', 'The upper and lower housings \n232\na\n, \n232\nb \ndefine cone wedge profiles \n239\n which impart radial force components on the elements \n236\n from an axial actuation force during expansion of the ring structure \n235\n.', 'Upper and lower shear screws \n240\na\n, \n240\nb \nsecure the upper and lower housings to the core \n231\n via the connectors \n233\na\n, \n233\nb.', 'The position and separation of the cone wedges \n239\n on the core \n231\n determines the expanded position of the ring structure \n235\n and the outer diameter of the tool.', 'This can be adjusted by setting the position of the upper connector \n233\na \nwith respect to the core \n231\n by means of locking screws or pins \n241\n.', 'Locking collars \n242\na\n, \n242\nb \nare able to lock the position of the housing in the desired condition with respect to the ring structure.', 'In the position shown in \nFIGS.', '35A and 35B', ', the core \n231\n is fully retracted into a bore \n243\n in the upper connector, which draws the upper and lower housings together and brings the wedge profiles \n239\n together.', 'An axial force is imparted on the wedges \n239\n which is directed radially to the elements of the ring structure \n235\n to expand the ring structure to its maximum outer diameter.', 'In the position shown in \nFIGS.', '36A and 36B\n, the core \n231\n is only partially retracted into the bore \n243\n in the upper connector, which partially lengthens the tool and enables the wedges \n239\n to be partially separated.', 'This enables the elements of the ring structure \n235\n to partially collapse to an intermediate outer diameter under the force of a circumferential retaining spring (not shown).', 'An axial force from coil springs \n244\n in the housings extends the housings to partially cover the tapered portions of the ring structure.', 'Locking collars \n242\na\n, \n242\nb \nare repositioned to lock position of the housing in the desired condition with respect to the ring structure.', 'It will be appreciated that in embodiments of the invention, the position of the core with respect to the upper connector may be adjusted continuously or to a number of discrete positions, to provide a continuously variable diameter, or a number of discrete diameters.', 'The tool \n230\n is designed to be retrieved to surface to be adjusted, but other embodiments may comprise mechanisms for automated and/or remote adjustment of the core position and the outer diameter.', 'Such variants may include an electric motor which actuates rotation of a threaded connection to change the relative position of the wedges and the diameter of the ring structure.\n \nFIGS.', '37A and 37B\n show the tool \n230\n in a collapsed condition, in which the ring structure is fully collapsed to be flush with the principle outer diameter of the tool housings.', 'This collapsed position is actuated by a jar up force on the tool string.', 'The jarring force acts through the core and shears through the lower shear screws \n240\nb\n, disconnecting the lower housing from the lower connector.', 'This enables downward movement of the lower housing with respect to the lower connector, and separates the wedges \n239\n to collapse the ring structure.', 'A jar-down collapse condition (not shown) can alternatively be created by imparting a jar down force on the tool.', 'The downward force shears the upper shear screws \n240\na\n, disconnecting the upper housing from the upper connector.', 'This enables upward movement of the upper housing with respect to the upper connector, and separates the wedges \n239\n to collapse the ring structure.', 'The tool \n230\n is configured as a drift tool, which is run to verify or investigate the drift diameter of a wellbore.', 'The tool may also be configured as a centralising tool, which has variable diameter to set variable stand-off of a tool string.', 'A further variation is described with reference to \nFIGS.', '38A to 39B\n.', 'FIGS.', '38A and 38B\n are respectively perspective and longitudinal sectional views of a variable diameter wellbore broaching tool, generally depicted at \n260\n, according to an embodiment of the invention, shown in a first run position.', 'FIGS.', '39A and 39B\n, are equivalent views of the tool in a collapsed position.', 'The wellbore broaching tool \n260\n is similar to the drift tool \n230\n, with like components indicated by like reference numerals incremented by 30.', 'In this embodiment, the outer surfaces of the elements \n266\n which make up the ring structure are provided with abrasive cutting formations or teeth, which are designed to remove material from the inner surface of a wellbore.', 'The position and separation of the cone wedges \n269\n on the core \n261\n determines the expanded position of the ring structure \n265\n and the outer diameter of the tool.', 'This can be adjusted by setting the position of the upper connector \n263\na \nwith respect to the core \n261\n by means of locking screws or pins \n261\n.', 'Locking collars \n262\na\n, \n262\nb \nare able to lock the position of the housing in the desired condition with respect to the ring structure.', 'In common with the previous embodiment of the invention, the position of the core with respect to the upper connector may be adjusted continuously or to a number of discrete positions, to provide a continuously variable diameter, or a number of discrete diameters.', 'The tool \n260\n is designed to be retrieved to surface to be adjusted, but other embodiments may comprise mechanisms for automated and/or remote adjustment of the core position and the outer diameter.', 'A further application of the invention is to a variable diameter centralising and/or stabilising tool, which may be used in a variety of downhole applications with non-sealing devices.', 'These include, but are not limited to, drilling, milling and cutting devices.', 'The tool may be similar to the drift tool \n230\n and the broaching tool \n260\n, with the outer surface of the elements designed to contact and engage with a borehole wall at a location axially displaced from (for example) a drill bit, milling head, or cutting tool.', 'The tool may be provided with a bearing assembly to facilitate rotation of a mandrel with respect to the expanding ring structure, or to permit rotation of a drilling, milling or cutting tool.', 'The diameter of the tool can be controlled to provide a centralising and/or stabilising engagement force to support the wellbore operation.', 'The invention can be used in a similar manner to stabilise, centre, or anchor a range of non-sealing devices or tools.', 'The invention provides an expanding and collapsing apparatus and methods of use.', 'The apparatus comprises a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis.', 'The ring structure is operable to be moved between an expanded condition and a collapsed condition on actuation by an axial force.', 'The plurality of elements are operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in the plane of the ring structure.', 'The invention provides an expanding and/or collapsing apparatus and a method of use.', 'The apparatus comprises a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis.', 'The ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements on actuation by an axial force.', 'The plurality of elements is operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure.', 'Applications of the invention include oilfield devices, including anti-extrusion rings, plugs, packers, locks, patching tools, connection systems, and variable diameter tools run in a wellbore.', 'The invention in its various forms benefits from the novel structure and mechanism of the apparatus.', 'At an optimal expansion condition, shown in \nFIGS.', '2B and 2D\n, the outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements, and therefore the apparatus can be optimised for a specific diameter, to form a perfectly round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.', 'It is a feature of the invention that the elements are mutually supported before, throughout, and after the expansion, and do not create gaps between the individual elements during expansion or at the fully expanded position.', 'In addition, the arrangement of elements in a circumferential ring, and their movement in a plane perpendicular to the longitudinal axis, facilitates the provision of smooth side faces or flanks on the expanded ring structure.', 'With deployment of the elements in the plane of the ring structure, the width of the ring structure does not change.', 'This enables use of the apparatus in close axial proximity to other functional elements.', 'In addition, each of the ring structures provides a smooth, unbroken circumferential surface which may be used in engagement or anchoring applications, including in plugs, locks, and connectors.', 'This may provide an increased anchoring force, or full abutment with upper and lower shoulders defined in a locking or latching profile, enabling tools or equipment be rated to a higher maximum working pressure.', 'The invention also enables high expansion applications.', 'Various modifications to the above-described embodiments may be made within the scope of the invention, and the invention extends to combinations of features other than those expressly claimed herein.', 'In particular, the different embodiments described herein may be used in combination, and the features of a particular embodiment may be used in applications other than those specifically described in relation to that embodiment.'] | ['1.', 'An apparatus comprising:\na plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis;\nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements on actuation by an axial force;\nwherein each element of the ring structure comprises a first contact surface and a second contact surface, where each first contact surface abuts a first adjacent element and each second contact surface abuts a second adjacent element;\nand wherein the plurality of elements is operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure.', '2.', 'The apparatus according to claim 1, wherein the ring structure comprises one or more ring surfaces configured to be presented to an auxiliary surface when actuated to the expanded condition or the collapsed condition.', '3.', 'The apparatus according to claim 2, wherein the ring surface is a substantially cylindrical surface arranged to contact or otherwise interact with an inner surface of a tubular or bore.', '4.', 'The apparatus according to claim 2, wherein the ring surface is substantially smooth.', '5.', 'The apparatus according to claim 2, wherein the ring surface is provided with one or more functional formations thereon, for interacting with an auxiliary surface.', '6.', 'The apparatus according to claim 1, wherein the elements are configured to move between their expanded and collapsed conditions in a path which is tangential to a circle described around and concentric with the longitudinal axis.', '7.', 'The apparatus according to claim 1, wherein the elements are configured to slide relative to one another along their respective contact surfaces.', '8.', 'The apparatus according to claim 7, wherein the first contact surface and/or the second contact surface are oriented tangentially to a circle described around and concentric with the longitudinal axis.', '9.', 'The apparatus according to claim 7, wherein the first contact surface and the second contact surface converge towards one another in a direction towards an inner surface of the ring structure.', '10.', 'The apparatus according to claim 1, wherein the elements are provided with interlocking profiles for interlocking with an adjacent element.', '11.', 'The apparatus according to claim 10,\nwherein the elements are configured to slide relative to one another along their respective contact surfaces; and\nwherein the interlocking profiles are formed in the first contact surface and/or the second contact surface, and each element is configured to interlock with an adjacent element such that contact surfaces of respective elements are in abutment.', '12.', 'The apparatus according to claim 1, wherein the apparatus comprises a support surface for the ring structure, wherein the support surface is an outer surface of a mandrel or tubular, and wherein the support surface supports the ring structure in the collapsed condition of the apparatus.', '13.', 'The apparatus according to claim 1, wherein the apparatus comprises a support surface for the ring structure, wherein the support surface is an inner surface of a mandrel or tubular, and wherein the support surface supports the ring structure in the expanded condition of the apparatus.', '14.', 'The apparatus according to claim 1, wherein the apparatus is operated in its expanded condition, and elements forming the ring structure are mutually supportive in the expanded condition of the apparatus.', '15.', 'The apparatus according to claim 1, wherein an operating condition of the apparatus is its expanded condition, wherein the ring structure is a substantially solid ring structure in the expanded condition, and wherein the elements are fully mutually supported in the expanded condition.', '16.', 'The apparatus according to claim 1, wherein an operating condition of the apparatus is its collapsed condition, wherein the ring structure is a substantially solid ring structure in the collapsed condition, and wherein the elements are fully mutually supported in the in the collapsed condition.', '17.', 'The apparatus according to claim 1, comprising a formation configured to impart a radial expanding or collapsing force component to the elements of the ring structure from an axial actuation force.', '18.', 'The apparatus according to claim 1, comprising a biasing means configured to bias the ring structure to one of its expanded or collapsed conditions.\n\n\n\n\n\n\n19.', 'The apparatus according to claim 1, comprising a secondary expanding and collapsing mechanism operable to move the ring structure between a first expanded condition to a second expanded condition on actuation by the axial force.', '20.', 'The apparatus according to claim 1, wherein the ring structure is a first ring structure, and the apparatus comprises at least one additional ring structure, wherein the additional ring structure is operable to move the first ring structure from an intermediate expanded condition to a fully expanded condition.', '21.', 'The apparatus according to claim 20, wherein the ring structure is a first ring structure, and the apparatus comprises at least one pair of additional ring structures, wherein the pair of additional ring structures is operable to move the first ring structure from an intermediate expanded condition to a fully expanded condition.', '22.', 'The apparatus according to claim 20, wherein a plurality of elements of the additional ring structure is operable to be moved between expanded and collapsed conditions by sliding with respect to one another in a plane of the additional ring structure, in a direction tangential to a circle concentric with the additional ring structure.', '23.', 'The apparatus according to claim 20, comprising a plurality of additional ring structures arranged in functional pairs, operable to move the first ring structure from an intermediate expanded condition to a subsequent intermediate expanded condition, or a fully expanded condition.', '24.', 'An oilfield tool comprising the apparatus of claim 1.\n\n\n\n\n\n\n25.', 'The oilfield tool according to claim 24, configured as a downhole tool selected from the group consisting of: a plug, a packer, an anchor, a tubing hanger, or a downhole locking tool.\n\n\n\n\n\n\n26.', 'The oilfield tool according to claim 25, configured as a retrievable bridge plug.', '27.', 'The oilfield tool according to claim 25, configured as a permanent plug.', '28.', 'A variable diameter downhole tool comprising an apparatus according to claim 1.\n\n\n\n\n\n\n29.', 'The variable diameter downhole tool according to claim 28, selected from the group consisting of a wellbore centraliser, a wellbore broach tool, and a wellbore drift tool.', '30.', 'A connector system comprising a first connector and a second connector, wherein one of the first connector and the second connector comprises the apparatus of claim 1.\n\n\n\n\n\n\n31.', 'A patch apparatus for a fluid conduit or tubular, the patch apparatus comprising the apparatus of claim 1.\n\n\n\n\n\n\n32.', 'A method of expanding an apparatus, the method comprising:\nproviding an apparatus comprising a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis, wherein each element of the ring structure comprises a first contact surface and a second contact surface, where each first contact surface abuts a first adjacent element and each second contact surface abuts a second adjacent element; and\nimparting an axial force to the ring structure to move the plurality of elements by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure; thereby moving the ring structure from a collapsed condition to an expanded condition.\n\n\n\n\n\n\n33.', 'A method of collapsing an apparatus, the method comprising:\nproviding an apparatus comprising a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis, wherein each element of the ring structure comprises a first contact surface and a second contact surface, where each first contact surface abuts a first adjacent element and each second contact surface abuts a second adjacent element; and\nreleasing or reducing an axial force from the ring structure to move the plurality of elements by sliding with respect to one another in the plane of the ring structure, in a direction tangential to a circle concentric with the ring structure, thereby moving the ring structure from an expanded condition to a collapsed condition.'] | ['FIGS.', '1A to 1D are respectively perspective, first end, part sectional and second end views of an apparatus according to a first embodiment of the invention, shown in a collapsed condition;; FIGS.', '2A to 2D are respectively perspective, first side, part sectional and second side views of the apparatus of FIGS.', '1A to 1D, shown in an expanded condition;; FIGS.', '3A and 3B are geometric representations of an element of the apparatus of FIGS.', '1A to 1D, shown from one side;; FIGS.', '4A to 4F are respectively first perspective, second perspective, plan, first end, lower, and second end views of an element of the apparatus of FIGS.', '1A to 1D;; FIGS.', '5A and 5B are respectively perspective and sectional views through a retrievable bridge plug incorporating apparatus according to an embodiment of the invention, shown in a run position;; FIG.', '6 is a sectional view of the apparatus of FIGS.', '5A and 5B, shown in a set position;; FIG. 7 is a sectional view of the apparatus of FIGS.', '5A and 5B, shown in a pull position;; FIGS.', '8A to 8D are respectively first perspective, second perspective, third perspective, fourth perspective, plan, end, lower, first side and second side views of a ring segment of apparatus of FIGS.', '5A and 5B;; FIGS.', '9A to 9D are respectively first perspective, second perspective, third perspective, fourth perspective, plan, end, lower, first side and second side views of a slip segment of the apparatus of FIGS.', '5A and 5B;; FIGS.', '10A and 10B are respectively perspective and sectional views of a permanent plug according to an alternative embodiment of the invention, shown in a run position;; FIGS.', '11A and 11B are respectively first and second perspective views of a slip segment of the apparatus of FIGS.', '10A and 10B;; FIGS.', '12A and 12B are respectively first and second perspective views of a ring segment according to an alternative embodiment of the invention;; FIGS.', '13A to 13D are respectively first sectional, second sectional, isometric, and cross sectional views of a lock apparatus according to an embodiment of the invention, shown in a run position;; FIGS.', '14A to 14D are respectively first sectional, second sectional, isometric, and cross sectional views of the apparatus of FIGS.', '13A to 13D, shown in a set position;; FIGS.', '15A to 15D are respectively perspective, perspective cut-away, sectional and cross-sectional views of a quick connect apparatus according to an embodiment of the invention, shown in a lock out position;; FIGS. 16A to 16C are respectively perspective, sectional and cross-sectional views of the apparatus of FIGS.', '15A to 15D, shown in a release position;; FIGS.', '17A to 17C are respectively perspective, sectional and end views of an apparatus according to an alternative embodiment of the invention, shown in a collapsed condition;; FIGS.', '18A to 18C are respectively perspective, sectional and end views of the apparatus of FIGS.', '17A to 17C, shown in an expanded condition', ';; FIG. 19 is a geometric representation of a centre element of the apparatus of FIGS.', '17A to 17C, shown from one side;; FIGS.', '20A to 20F are respectively first perspective, second perspective, plan, first end, lower, and second end views of a centre element of the apparatus of FIGS.', '17A to 17C;', '; FIG.', '21 is a geometric representation of an outer element of the apparatus of FIGS.', '17A to 17C, shown from one side;', '; FIG.', '22A to 22H are respectively first perspective, second perspective, third perspective, fourth perspective, plan, first end, lower, and second end views of an outer element of the apparatus of FIGS.', '17A to 17C;; FIGS.', '23A to 23C are respectively perspective, sectional and end views of an apparatus according to an alternative embodiment of the invention, shown in a collapsed condition;; FIGS. 24A to 24C are respectively perspective, sectional and end views of the apparatus of FIGS.', '23A to 23C, shown in an expanded condition;; FIGS.', '25A and 25B are respectively perspective and sectional views of an apparatus according to an alternative embodiment of the invention, shown in a collapsed condition;; FIGS.', '26A to 26D are respectively perspective, first sectional, end, and second sectional views of the apparatus of FIGS.', '25A and 25B, shown in an expanded condition;; FIG.', '27 is a geometric representation of a centre element of the apparatus of FIGS.', '25A and 25B, shown from one side;; FIGS.', '28A to 28F are respectively first to fourth perspective, first end, and second end views of a centre element of the apparatus of FIGS.', '25A and 25B;; FIGS.', '29A and 29B are respectively perspective and sectional views of a patch apparatus according to an embodiment of the invention, shown in a collapsed condition;; FIGS.', '30A and 30B are respectively perspective and sectional views of the apparatus of FIGS.', '29A and 29B, shown in an expanded condition;; FIG.', '31 is a side view of an apparatus according to an alternative embodiment of the invention in a first, collapsed condition;; FIG.', '32 is a side view of the apparatus of FIG.', '31 a second, collapsed condition;; FIGS.', '33A and 33B are respectively plan and isometric views of an element of the apparatus of FIGS.', '31 and 32;; FIGS.', '34A and 34B are respectively plan and isometric views of a second element of the apparatus of FIGS.', '31 and 32;; FIGS.', '35A and 35B are respectively isometric and sectional views of a drift tool according to an embodiment of the invention, shown in a run position;; FIGS.', '36A and 36B are respectively isometric and sectional views of the apparatus of FIGS.', '35A and 35B, shown in an alternative run position;; FIGS.', '37A and 37B are respectively isometric and sectional views of the apparatus of FIGS.', '35A and 35B, shown in a collapsed position;; FIGS.', '38A and 38B are respectively isometric and sectional views of a broaching tool apparatus according to an embodiment of the invention, shown in a run position; and; FIGS.', '39A and 39B are respectively isometric and sectional views of the apparatus of FIGS.', '38A and 38B, shown in a collapsed position.;', 'FIGS.', '2A to 2D show clearly the apparatus in its expanded condition.', 'At an optimal expansion condition, shown in FIGS.', '2B and 2D, the outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements.', 'The outer surface of the expansion apparatus can be optimised for a specific diameter, to form a perfectly round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.;', 'FIG.', '5A is an isometric view of a retrievable bridge plug according to an embodiment of the invention, into which an expansion apparatus has been incorporated to perform anchoring and anti-extrusion functions.', 'FIG.', '5B is a longitudinal section through the bridge plug, generally shown at 50, in a run position.; FIG.', '7 shows the plug 50 in a pull position.', 'A release tool is run to the plug and engages with a ratchet release sleeve 48, to move it downwards with respect to the mandrel.', 'Movement of the release sleeve releases keys which support the ratchet sleeve 49 on the mandrel.', 'With the ratchet released, the upper and lower housings and actuation sleeve may move upwards relative to the mandrel, to release the actuation force on the slips and seal, resulting in their collapse.', 'Movement of the sleeve relative to the housing subs results in engagement of an upper ratchet lock-out mechanism 59a between the upper end of the actuation sleeve and the upper housing sub and a lower ratchet lock-out mechanism 59b between the lower end of the actuation sleeve and the lower housing sub.', 'With these components locked together, relative movement of the wedge elements is prevented, to stop expansion of the respective expansion components during pulling out of hole (for example if a restriction is encountered during pulling).; FIGS.', '11A and 11B are perspective views of individual slip elements 107a, 107b used respectively in the upper and lower slip assemblies 101, 102.', 'The slip elements are similar to the slip elements 77, and function in the same manner.', 'However, in this embodiment, because a slip assembly is provided above and below the seal element, the engagement profiles on the slips are not bidirectional.', 'Instead, the engagement profiles 108a, 108b of the respective slip assemblies are unidirectional.', 'The elements of the upper slip assembly are arranged to engage a surrounding surface and resist movement in one direction, whereas the slip elements of the lower assembly are arranged with engaging means configured to resist movement in the opposite direction.', 'Together, the upper and lower slip assemblies provide bidirectional anchoring of the plug in the wellbore.', 'The angles of the respective wedges and the corresponding surfaces in the slip assemblies, along with the retaining force of the biasing means, are selected so that the lower slip assembly can be deployed by an axial force which is directed through the elastomeric seal element.', 'In other words, the axial force required to press the seal element between the anti-extrusion surfaces created by the slip assemblies is greater, and preferably much greater, than the force required to deploy the slip assemblies.', 'This facilitates a full and proper deployment of the slip assemblies before the elastomeric seal element is radially expanded by compression between the wedges.; FIGS.', '13A and 13B are first and second longitudinal sectional views through a locking tool according to an embodiment of the invention.', 'FIG.', '13C is an isometric view of a locking tool, and FIG.', '13D is a cross section which shows the position of the longitudinal sections of 13A and 13B. In all of FIGS.', '13A to 13D, the locking tool is shown in a run position.', 'FIGS.', '14A to 14D are equivalent views of the locking tool in a set position.; FIG.', '21 is a geometric representation of an outer element 182 of the apparatus of FIGS.', '17A to 17C, shown from one side, and FIGS.', '22A to 22H are respectively first perspective, second perspective, third perspective, fourth perspective, plan, first end, lower, and second end views of an outer element 182.', 'The Figures show the inner and outer surfaces 183, 184, first and second contact surfaces 185, 186, interlocking profiles 187, 188, and grooves 189 for retaining circumferential springs which are equivalent in form and function to the features of the elements 12 and 77.', 'In the assembled ring structure, the outer elements and the centre elements are nested with one another, and the outer surfaces 184 of the outer elements define respective wedge profiles for corresponding centre elements 177 during a first expansion stage as will be described below.', 'Biasing means in the form of a circumferential spring retains the outer rings structure in their collapsed conditions, with the sequencing of the expanding and collapsing movement controlled by the selection of the relative strengths of the biasing means of the centre ring and the outer rings.; FIGS.', '25A to 26D show a multi-stage expanding and collapsing system in accordance with an alternative embodiment of the invention.', 'FIGS.', '25A and 25B are respectively perspective and longitudinal sectional views of the apparatus in a first, collapsed condition.', 'FIGS.', '26A and 26B are equivalent views of the apparatus in an expanded condition; FIG.', '26C is an end view and FIG.', '26D is a section through line D-D of FIG.', '26B.', 'The apparatus, generally shown at 280, is similar to the apparatus 170 and 190, and its form and function will be understood from FIGS.', '17 to 24 and the accompanying description.', 'However, the apparatus 280 differs in that it comprises pairs of ring structures 281, 282, 283 formed from individual elements with geometry different from those of previous embodiments.; FIG.', '27 is a geometric representation of a centre element of the apparatus of FIGS.', '25A and 25B, shown from one side, and FIGS.', '28A to 28F are respectively first perspective, second perspective, plan, first end, lower, and second end views of a centre element 284.', 'The Figures show the inner and outer surfaces, first and second contact surfaces, interlocking profiles, and grooves for retaining circumferential springs which are equivalent in form and function to the features of the elements 12 and 77.; FIGS.', '29A and 29B show a high expansion patching tool, generally depicted at 210, from perspective and longitudinal sectional views shown in a collapsed, run position.', 'FIGS.', '30A and 30B are equivalent views of the apparatus in an expanded condition.; FIGS.', '31 to 34B show a multi-stage expanding and collapsing system in accordance with an alternative embodiment of the invention.', 'FIGS.', '31 and 32 are respectively side views of the apparatus in a first, collapsed condition and second expanded condition.', 'FIGS.', '33A and 33B are respectively plan and isometric views of the a first set of elements of the apparatus; FIGS.', '34A and 34B are respectively plan and isometric views of a second set of elements of the apparatus.', 'The apparatus, generally shown at 380, is similar to the apparatus 170, 190, and 280, with a central ring structure 381 formed from an assembly of elements 384, and two pairs of ring structures 382a, 382b (together 382), 383a and 383b (together 383).', 'The form and function of the apparatus will be understood from FIGS.', '17 to 26 and the accompanying description.', 'However, the apparatus 380 differs in that it comprises pairs of ring structures 382, 383 formed from individual elements with geometry different from those of previous embodiments.; FIGS.', '33A and 33B are respectively plan and isometric views of an element 385, from which the outer ring structures 383a, 383b are assembled.', 'FIGS.', '34A and 35B are respectively plan and isometric views of an element 386, from which the intermediate ring structures 382a, 382b are assembled.', 'The Figures show the outer surfaces, first contact surfaces, and interlocking tongues.', 'The external profiles of the elements 385, 386 are modified by provision of additional chamfers 387, 388.', 'These chamfers modify the external profile of the elements, so that when assembled into a ring, the inward facing flank (i.e. the flank facing the centre ring) has an at least partially smoothed conical surface.', 'This facilitates the deployment of the apparatus; the smoother conical surface improves the sliding action of the elements the centre ring 381 on the conical profiles of the rings 382a, 382b as the elements are brought together to expand the centre ring.', 'Similarly, the smoothed inward facing flank of the rings 383a, 383b facilitate the sliding of the elements 382a of the rings 382a, 383b during their expansion.', 'The smoothed cones assist a supporting ring in punching under the adjacent ring with a smooth action,; FIGS.', '35A and 35B are respectively perspective and longitudinal sectional views of a variable diameter drift tool according to an embodiment of the invention, shown in a first run position.', 'FIGS.', '36A and 36B, are equivalent views of the drift tool in an alternative run position, and FIGS.', '37A and 37B are equivalent views of the drift tool in a collapsed position.; FIGS.', '37A and 37B show the tool 230 in a collapsed condition, in which the ring structure is fully collapsed to be flush with the principle outer diameter of the tool housings.', 'This collapsed position is actuated by a jar up force on the tool string.', 'The jarring force acts through the core and shears through the lower shear screws 240b, disconnecting the lower housing from the lower connector.', 'This enables downward movement of the lower housing with respect to the lower connector, and separates the wedges 239 to collapse the ring structure.'] |
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US11098532 | Cutting elements having non-planar surfaces and tools incorporating the same | Sep 5, 2018 | Xiaoge Gan, Anjie Dong, Gerard Johnson, Michael George Azar, Huimin Song, Youhe Zhang, Venkatesh Karuppiah | SCHLUMBERGER TECHNOLOGY CORPORATION | First Office Action and Search Report issued in Chinese Patent Application 201811030199.7 dated Apr. 16, 2021, 14 pages. | 4679639; July 14, 1987; Barr; 5078219; January 7, 1992; Morrell; 5460233; October 24, 1995; Meany; 5871060; February 16, 1999; Jensen; 6550556; April 22, 2003; Midlemiss et al.; 7363992; April 29, 2008; Stowe; 7703559; April 27, 2010; Shen; 7730977; June 8, 2010; Achilles; 7757785; July 20, 2010; Zhang; 7798257; September 21, 2010; Shen et al.; 8087478; January 3, 2012; Patel; 8096372; January 17, 2012; Shen et al.; 8113303; February 14, 2012; Zhang et al.; 8191656; June 5, 2012; Dourfaye et al.; 8919462; December 30, 2014; Digiovanni et al.; 9103174; August 11, 2015; Digiovanni et al.; 9376867; June 28, 2016; Digiovanni et al.; 10287825; May 14, 2019; Chen; 10400517; September 3, 2019; Borge; 20070235230; October 11, 2007; Cuillier; 20100084198; April 8, 2010; Durairajan; 20140182947; July 3, 2014; Bhatia et al.; 20150047910; February 19, 2015; Chen et al.; 20150047913; February 19, 2015; Durairajan et al.; 20160130882; May 12, 2016; Digiovanni et al.; 20170044836; February 16, 2017; Digiovanni et al. | 202380981; August 2012; CN; 202451062; September 2012; CN; 106703704; May 2017; CN | ['A cutting element includes a body, a non-planar cutting face formed on a first end of the body, and an edge formed around a perimeter of the cutting face.', 'The cutting face includes a central raised portion, and the edge has an edge angle defined between the cutting face and a side surface of the body.', 'The edge angle varies around the perimeter of the cutting face and includes an acute edge angle defined by a portion of the cutting face extending downwardly from the edge to a depth from the cutting angle.', 'The portion of the edge defining the acute edge angle may be directly adjacent: a side surface of the cutting element; a bevel of the cutting element; or a flat region at the perimeter of the cutting element or bevel.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application claims the benefit of, and priority to, U.S. Patent Application No. 62/554,128, filed Sep. 5, 2017, which application is expressly incorporated herein by this reference in its entirety.', 'BACKGROUND\n \nFixed cutter drill bits are widely used in the petroleum and mining industry for drilling wellbores through earth formations.', 'Such bits include a bit body with a threaded connection at a first end for attaching to a drill string, and cutting structure formed at an opposite end for drilling through earth formation.', 'The cutting structure includes blades that extend radially outwardly from a longitudinal axis of the bit body.', 'Ultrahard compact cutters are mounted in pockets formed in the blades and affixed thereto by brazing.', 'Fluid ports are also positioned in the bit body to distribute fluid around the cutting structure of the bit to cool the cutters and to flush formation cuttings away from the cutters and borehole bottom during drilling.', 'Cutters used for fixed cutter drill bits can include ultrahard compacts which include a layer of ultrahard material bonded to a substrate of less hard material through a high pressure/high temperature process.', 'For example, cutters may be formed having a substrate or support stud made of carbide (e.g., tungsten carbide), and an ultrahard cutting surface layer or “table” made of a polycrystalline diamond or polycrystalline boron nitride material deposited onto or otherwise bonded to the substrate at an interface surface.', 'Cutters are conventionally cylindrical in form with circular cross sections.', 'In mounting cutters on a bit, a trade off exists between the depth of cutter setting into the bit body and the remaining cutter exposure available for drilling.', 'Cutters are typically mounted with about one-half of the cutter body exposed for drilling, with the other half being embedded within the blade.', 'For drilling applications where cutters may become exposed to high impact loads, such as in drilling rock formations tough in shear or in high speed drilling applications, more than half of the cutter body surface may be embedded in the pocket within the blade to provide sufficient braze strength for retaining the cutters in place during drilling.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter', 'According to some embodiments, a cutting element includes a body, a non-planar cutting face formed on a first end of the body, and an edge formed around a perimeter of the cutting face.', 'The cutting face includes a central raised portion, and the edge has an edge angle defined between the cutting face and a side surface of the body.', 'The edge angle varies around the perimeter of the cutting face and includes an acute edge angle defined by a portion of the cutting face extending downwardly from the edge to a depth from the cutting angle.', 'In accordance with one or more additional embodiments, a cutting element includes a body, a non-planar cutting face, and an edge extending around a perimeter of the non-planar cutting face.', 'A height may be measured between a base surface of the body and the non-planar cutting face and is variable around the perimeter.', 'A first portion of the edge extends higher than a second portion of the edge, and an edge angle defined between the non-planar cutting face and a side surface of the body is less than 90° in at least one section of the first portion of the edge and greater than 90° at the second portion of the edge.', 'In some embodiments, a cutting element includes a substrate and a cutting layer.', 'The cutting layer is on the substrate and defines a cutting edge, a non-planar cutting face opposite the substrate, and an impact resistant feature at an interface between the cutting edge and the non-planar cutting face.', 'Another example cutting element includes a substrate, a cutting layer on the substrate at an interface, and a non-planar cutting face formed on the cutting layer opposite the interface.', 'The non-planar cutting face includes at least three raised portions forming a generally sinusoidal cross-sectional profile when viewed along a cross-sectional plane intersecting an entire length of the cutting element.', 'In further examples, a drill bit includes a body and cutting structure that defines a cutting profile.', 'Cutting elements as disclosed herein may be on the cutting profile.', 'Other aspects and advantages of embodiments of the present disclosure will be apparent from the following description and the appended claims.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nFIG.', '1\n is a perspective view of a cutting element according to embodiments of the present disclosure.', 'FIG.', '2\n is a cross-sectional view of a cutting element according to embodiments of the present disclosure.', 'FIG.', '3\n is a cross-sectional view of a cutting element according to embodiments of the present disclosure.', 'FIG.', '4\n is a cross-sectional view of a cutting element according to embodiments of the present disclosure.\n \nFIG.', '5\n is a cross-sectional view of a cutting element according to embodiments of the present disclosure.', 'FIGS.', '6-1 and 6-2\n are cross-sectional views of the cutting element of \nFIG.', '3\n engaging a formation at different depths of cut.\n \nFIGS.', '7-1 to 7-3\n are perspective, top, and cross-sectional view, respectively, of a cutting element according to embodiments of the present disclosure.', 'FIGS.', '8-1 to 8-3\n are perspective and various cross-sectional views, respectively, of a cutting element according to embodiments of the present disclosure.', 'FIGS.', '9-1 and 9-2\n are cross-sectional and perspective views, respectively, of a cutting element according to embodiments of the present disclosure.', 'FIGS.', '10-1 and 10-2\n are side and top views, respectively, of a cutting element according to embodiments of the present disclosure.', 'FIGS.', '10-3 to 10-9\n are various cross-sectional views of the cutting element of \nFIGS.', '10-1 and 10-2\n.', 'FIGS.', '11-1 to 11-6\n are views of a cutting element according to additional embodiments of the present disclosure.', 'FIGS.', '12-1 to 12-3\n are views of another cutting element according to embodiments of the present disclosure.\n \nFIG.', '13\n is a schematic, top view of a cutting element according to embodiments of the present disclosure.', 'FIG.', '14\n is a side view of profiles of different cutting edges of cutting elements according to embodiments of the present disclosure.', 'FIG.', '15\n shows a cutting element according to embodiments of the present disclosure.\n \nFIG.', '16\n shows a drill bit according to embodiments of the present disclosure.', 'FIGS.', '17-1 and 17-2\n are cross-sectional views of a cutting element at different orientations within a cutter pocket according to embodiments of the present disclosure.', 'FIG.', '18\n shows a hole opener according to embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'Cutting elements according to the present disclosure may include cutting elements having a non-planar cutting face that includes a geometry with an edge angle formed around a portion of the edge of the cutting face, where an edge angle refers to the angle measured between the cutting face and the side surface of the cutting element along the edge.', 'As described herein, a non-planar cutting face may include one or more cutting edge portions having an acute or 90° edge angle and one or more edge portions having an edge angle greater than or equal to 90°.', 'For example, an edge formed around a perimeter of a non-planar cutting face may include an alternating pattern of acute and/or right edge angle portions spaced apart by obtuse and/or right edge angle portions.', 'Non-planar cutting faces according to embodiments of the present disclosure may be symmetric about a plane extending longitudinally through the cutting element.', 'For example, as described in some of the embodiments disclosed herein, a non-planar cutting face may have a generally sinusoidal cross-sectional profile that is symmetric along a plane perpendicular to the cross-sectional profile.', 'In some embodiments, a non-planar cutting face may have one or more plane of symmetry, including but not limited to, two planes of symmetry where the two planes are perpendicular to each other, or three planes of symmetry.', 'Further, non-planar cutting faces according to embodiments of the present disclosure may include multiple edge angle portions formed around the edge of the cutting face (e.g., a single acute/right edge angle portion forming less than the entire edge of the cutting face and the remaining portion(s) of the edge having right/obtuse edge angle portions, or multiple spaced apart acute/right edge angle portions), such that asymmetry is formed around a central longitudinal axis of the cutting element.\n \nFIGS.', '1 and 2\n are perspective and cross-sectional views, respectively, of an example of a cutting element according to embodiments of the present disclosure.', 'The cross-sectional view shown in \nFIG.', '2\n is taken at a plane extending along and intersecting a longitudinal axis \n101\n of the cutting element \n100\n.', 'The cutting element \n100\n includes a body \n110\n and a cutting face \n120\n formed at a first end portion of the body \n110\n.', 'The cutting face \n120\n in \nFIGS.', '1 and 2\n has a wavy, undulating geometry, having a central raised region \n122\n and two outer raised regions \n124\n spaced apart from and on opposite sides of the cutting face \n120\n.', 'The undulating surface geometry of the cutting face \n120\n is symmetric about the plane of the cross-sectional view in \nFIG.', '2\n, as well as symmetric about a plane perpendicular to the cross-sectional plane, where both planes of symmetry extend along and intersect with the longitudinal axis \n101\n.', 'In the illustrated embodiment, the cutting face \n120\n has two-fold rotational symmetry (discrete rotational symmetry of the second order) about the longitudinal axis \n101\n, where the geometric configuration of the cutting element is the same when the cutting face is rotated 180° around the longitudinal axis.', 'In some embodiments, a cutting face may be asymmetric, having one-fold rotational symmetry (where the geometric configuration of the cutting element remains the same after a complete 360° rotation about the longitudinal axis), for example, when the cutting face surface geometry includes a single outer raised region formed along less than the entire perimeter of the cutting face.', 'In some embodiments, a cutting face may have three-fold rotational symmetry (where the geometric configuration of the cutting element is the same when the cutting face is rotated 120° around the longitudinal axis), for example, when the cutting face surface geometry includes three outer raised regions formed along the perimeter of the cutting face.', 'In some embodiments, a cutting face may have four-fold (or more) rotational symmetry.', 'An edge \n130\n is formed around a perimeter of the cutting face \n120\n at the junction between the cutting face \n120\n and a side surface \n112\n of the cutting element \n100\n.', 'In some embodiments, such as shown in \nFIGS.', '1 and 2\n, the edge \n130\n may include a chamfer or bevel \n132\n formed at the junction between the cutting face \n120\n and the side surface \n112\n, while in other embodiments, at least part of an edge may be formed at the junction of the cutting face and side surface without a bevel.', 'The shape of an edge \n130\n may be described according to its cross-sectional profile along a plane intersecting the edge and perpendicular to the side surface at the edge.', 'For example, a profile of an edge may include a curved transition between the cutting face and side surface portions at the edge, a bevel formed at the junction between the cutting face and side surface portions at the edge, or an angled transition between the cutting face and side surface portions at the edge.', 'Further, an edge may have an edge angle defined between the cutting face and the side surface of the cutting element.', 'For example, as shown in \nFIG.', '2\n, a line tangent to the cutting face \n120\n at edge \n130\n and a line tangent to the side surface \n112\n at edge \n130\n intersect to define an edge angle \n134\n.', 'The edge angle \n134\n varies around the perimeter of the cutting face \n120\n in the illustrated embodiment.', 'For example, the portions of the edge \n130\n shown in the cross-sectional profile of \nFIG.', '2\n have an acute edge angle \n134\n.', 'Other portions of the edge \n130\n may have right or obtuse edge angles, such as shown along the portions of the edge \n130\n bordering or proximate a central raised region \n122\n in the cutting face \n120\n in \nFIG.', '1\n.', 'Depending on the orientation of the cutting element in a cutting tool and the relative orientation between the tool and the formation being engaged by the tool, certain portions of the edge may act as a cutting edge, which contacts and engages the formation.', 'In some embodiments, cutting elements may be in a cutter pocket formed on a cutting tool such that an acute edge angle portion of the edge forms the cutting edge of the cutting element.', 'In some embodiments, cutting elements may be oriented in a cutter pocket formed on a cutting tool such that a right or obtuse edge angle portion of the edge forms the cutting edge of the cutting element.', 'Further, in some embodiments, a cutting element having a non-planar surface geometry, such as disclosed herein, may be rotated within a cutter pocket to alter the edge angle portion acting as the cutting edge, thereby altering the effective back rake angle (or engagement angle).', 'In some embodiments, a cutting element having a first surface geometry (e.g., a planar or non-planar surface geometry) may be replaced with a cutting element having a non-planar surface geometry described herein to alter the edge angle acting as the cutting edge, thereby altering the engagement angle of the cutting element.', 'As used herein, an engagement angle refers to the angle measured between a line tangent to the portion of the cutting face to engage a formation and a line perpendicular to the formation being engaged (or working surface).', 'The portion of a cutting face that engages a formation may depend on, for example, the distance the cutting element protrudes (extension height) from an outermost surface of the cutting tool on which the cutting element is disposed and the depth of cut of the cutting element.', 'With cutting elements having a non-planar cutting face geometry at the cutting edge, such as disclosed herein, the engagement angle measured along the engagement area of the non-planar cutting face may vary along the depth of cut.', 'FIGS.', '3-5\n show examples of three different cutting profiles of a cutting element positioned at a given orientation.', 'As shown, although each cutting element is oriented in the same position, the different surface geometry along the engagement area of the cutting face provides different engagement angles with respect to a formation being engaged.\n \nFIG.', '3\n is a cross-sectional view of a cutting element \n300\n having a non-planar cutting face \n320\n formed at a first end of a body \n310\n.', 'The cutting element \n300\n may be in a cutter pocket (not shown) and have an acute edge angle portion of the edge \n330\n that forms the cutting edge \n331\n of the cutting element.', 'As the cutting element is engaged with and moved across a formation \n350\n, an engagement area \n321\n of the cutting face \n320\n extends the depth of cut into the formation \n350\n.', 'An engagement angle \n360\n is defined between the line \n355\n perpendicular to the formation \n350\n being cut and the line \n325\n tangent to the engagement area \n321\n of the cutting face \n320\n.', 'In the embodiment shown, the engagement area \n321\n of the cutting face \n320\n has a concave cross-sectional profile, and thus, the engagement angle \n360\n varies along the depth of cut.', 'In some embodiments, a cross-sectional profile of an engagement area of a non-planar cutting face may have a planar region, where the engagement angle is constant along the depth of cut for the planar region.', 'However, in some embodiments, the engagement area has both planar and non-planar regions or may be entirely non-planar, where the engagement angle may vary along the depth of cut engaging the varying regions of the engagement area.', 'According to embodiments of the present disclosure, an engagement angle \n360\n formed at an acute edge angle portion of a cutting element may be positive, for example, within a range having a lower limit, an upper limit, or both lower and upper limits including any of 00, 2°, 5°, 10°, 15°, 20°, 25°, 30°, 40°, 50°, or any values therebetween, where any relatively lower value may be selected in combination with any relatively higher value.', 'If engagement angles disclosed herein were to be considered in terms of back rake angles for conventional cutting angles, positive back rake angles may not be achievable at the values described herein.', 'Further, in some embodiments of the present disclosure, an engagement angle \n360\n varying along a depth of cut may have a difference in value of greater than 2°, for example, up to 5°, up to 10°, or more.', 'For example, an engagement angle formed along an engagement area having a concave cross-sectional profile may have a difference in engagement angles along the depth of cut of ranging from about 5° to about 15°, or more, depending on the radius of curvature of the concave cross-sectional profiles.\n \nFIG.', '4\n is a cross-sectional view of a cutting element \n400\n in a cutter pocket at the same orientation (i.e., same angle between the longitudinal axis of the cutting element and the line perpendicular to the formation) as the cutting element \n300\n of \nFIG.', '3\n, where the cutting element \n400\n is positioned in the cutter pocket to have a right edge angle portion of the edge \n430\n form the cutting edge \n431\n of the cutting element.', 'As the cutting element is engaged with and moved across a formation \n450\n, an engagement area \n421\n of the cutting face \n420\n extends the depth of cut into the formation \n450\n.', 'An engagement angle \n460\n is defined between the line \n455\n perpendicular to the formation \n450\n being cut and the line \n425\n tangent to the engagement area \n421\n of the cutting face \n420\n.', 'In the embodiment shown, the cutting element \n400\n may have a non-planar cutting face \n420\n formed at a first end of the body \n410\n, where the non-planar cutting face includes a linear ridge extending between opposite sides of the edge \n430\n, and where the cross section is taken along the linear ridge.', 'The linear ridge may have a planar cross-sectional profile forming the right edge angle.', 'In some embodiments, other cutting face geometries may form a right edge angle, for example a planar cutting face.', 'According to embodiments of the present disclosure, an engagement angle formed at a right edge angle portion of a cutting element may be negative, for example, having a lower limit, an upper limit, or both lower and upper limits including any of 0°, −2°, −5°, −10°, −15°, −20°, −25°, −30°, or any values therebetween, where any relatively lower value may be selected in combination with any relatively higher value.', 'The engagement angle may be constant along the planar cross-sectional profile of the engagement area \n421\n.\n \nFIG.', '5\n is a cross-sectional view of a cutting element \n500\n in a cutter pocket at the same orientation as the cutting elements \n300\n, \n400\n of \nFIGS.', '3 and 4\n, where the cutting element \n500\n is positioned in the cutter pocket to have an obtuse edge angle portion of the edge \n530\n form the cutting edge \n531\n of the cutting element.', 'The obtuse edge angle portion of the edge \n530\n may be formed by a convex ridge extending between opposite sides of the edge \n530\n, where the convex ridge has a convex profile extending outwardly from a base surface of the cutting element \n500\n.', 'In some embodiments, other cutting face geometries may form an obtuse edge angle, for example, a planar surface extending upwardly and radially inward from the edge.', 'As the cutting element is engaged with and moved across a formation \n550\n, an engagement area \n521\n of the cutting face \n520\n extends the depth of cut into the formation \n550\n.', 'An engagement angle \n560\n is defined between the line \n555\n perpendicular to the formation \n550\n being cut and the line \n525\n tangent to the engagement area \n521\n of the cutting face \n520\n.', 'According to embodiments of the present disclosure, an engagement angle formed at an obtuse edge angle portion of a cutting element may be negative, for example, within a range having a lower limit, an upper limit, or lower and upper limits including any of −5°, −10°, −15°, −25°, −30°, −40°, −50°, or any value therebetween, where any relatively lower value may be selected in combination with any relatively higher value.', 'The engagement angle may vary along the convex cross-sectional profile of the engagement area \n521\n.', 'In some embodiments, an engagement angle varying along a depth of cut may have a difference in value of greater than 2°, for example, up to 5°, up to 10°, or more.', 'For example, an engagement angle formed along an engagement area having a convex cross-sectional profile may have a difference in engagement angles along the depth of cut of ranging from about 5° to about 15°, or more, depending on the radius of curvature of the convex cross-sectional profile.', 'In embodiments having an obtuse edge angle with a planar surface forming the engagement area cross-sectional profile, the engagement angle may be constant or varied along the depth of cut.', 'FIGS.', '3-5\n show how cutting elements having non-planar cutting faces according to embodiments of the present disclosure may be rotated and positioned within a cutter pocket at a given orientation to vary the engagement angle of the cutting element.', 'Similarly, cutting elements having a first type of cutting face surface geometry (e.g., a planar cutting face or a non-planar cutting face) may be replaced with cutting elements having a non-planar cutting face according to embodiments of the present disclosure to alter the engagement angle.', 'Further, an engagement angle formed by a non-planar cutting face according to embodiments of the present disclosure may vary depending on the depth of cut.', 'For example, \nFIGS.', '6-1 and 6-2\n show the cutting element shown in \nFIG.', '3\n cutting at different depths of cut.', 'Due to the curved profile of the cutting face region contacting the formation \n350\n being cut, the engagement angle \n360\n at the surface of the formation in the relatively deeper depth of cut shown in \nFIG.', '6-1\n is relatively smaller than the engagement angle \n360\n at the surface of the formation in the relatively shallower depth of cut shown in \nFIG.', '6-2\n.', 'Non-planar cutting faces according to embodiments of the present disclosure may include an undulating surface geometry, where relatively raised portions form two opposite sides of the edge of a cutting element.', 'In some embodiments, at least one raised portion may be formed between the outer raised portions at the edge and spaced apart by relatively depressed portions.', 'For example, a single central raised portion in the shape of a ridge may be spaced between outer raised portions at a cutting element edge, or more than one ridge may be spaced between outer raised portions of a cutting element edge, where each raised portion may be spaced apart from each other by a relatively depressed portion.', 'In some embodiments, a single central raised portion may be dome shaped, i.e., the central raised portion does not extend across the entire diameter of the cutting element but may be spaced a distance from the entire periphery.', 'It is envisioned that the single central raised portion may be axisymmetric or not.', 'In some embodiments, the single central raised portion may extend across a full width or diameter of the cutter, although in other embodiments a single central raised portion may extend along a partial width or diameter of the cutter.', 'In embodiments in which a raised portion extends across a partial width or diameter of the cutter, the raised portion may extend from an outer edge toward a center or axis of the cutting face, or may extend from the center of the cutting face radially outward in a single or in each of opposing directions toward an outer edge.', 'FIGS.', '7-1 to 7-3\n are perspective, top, and cross-sectional views, respectively, of a cutting element \n600\n having a non-planar cutting face \n620\n according to embodiments of the present disclosure.', 'The non-planar cutting face \n620\n has an undulating surface geometry, where relatively raised portions \n622\n form two opposite sides of the edge \n630\n of the cutting element, and a central raised portion \n624\n is formed between and spaced apart from the outer raised portions \n622\n by relatively depressed portions \n626\n.', 'The central raised region \n624\n of the non-planar cutting face \n620\n forms a ridge extending between opposite sides of the perimeter of the cutting face \n620\n and through a central region of the cutting face \n620\n.', 'Non-planar cutting face geometries according to embodiments of the present disclosure may be formed on an elliptical cylinder shaped body \n610\n, such as shown in \nFIGS.', '7-1 to 7-3\n, or on bodies having other geometries, such as cylindrically shaped bodies (e.g., as shown in \nFIGS.', '1 and 2\n) or a rounded rectangular prism shaped body.', 'As shown, a cutting element body \n610\n includes a side surface \n612\n that joins the cutting face \n620\n at edge \n630\n.', 'The edge \n630\n has an acute edge angle \n660\n portion formed at the outer raised portions \n622\n between a line \n625\n tangent to the cutting face at the acute edge angle portion and the line tangent to the side surface \n612\n.', 'The acute edge angle \n660\n be in a range, for example, that is greater than 35°, greater than 45°, or greater than 60° and up to 89°.', 'According to embodiments of the present disclosure, a portion of a cutting element edge may have an acute edge angle defined by a portion of the cutting face extending downwardly from the edge toward a central region of the cutting face to a depth from the cutting edge.', 'For example, as shown in the cross-sectional view of \nFIG.', '7-3\n, an acute edge angle portion formed at the edge \n630\n may be defined by a raised portion \n622\n of the cutting face extending downwardly from the edge \n630\n toward a central region of the cutting face to depth \n640\n.', 'The depth \n640\n may range, for example, from about 0.5 cm to about 2 cm.', 'In some embodiments, a depth of an acute edge angle portion may be less than 2%, less than 5%, or less than 10% of the total depth of the cutting element.', 'Further, cutting elements of the present disclosure may include a cutting layer on a substrate at an interface, where the cutting face is formed on the cutting layer opposite the interface.', 'A portion of a cutting face forming an acute edge angle portion may extend downwardly from the edge toward a central region of the cutting face to a depth ranging from less than about 5%, less than 25%, less than 50%, less than 75%, at least 5%, at least 10%, at least 50%, at least 75%, or between 5% and 75% of a total thickness of the cutting layer.', 'For example, \nFIGS.', '8-1 to 8-3\n show a cutting element \n900\n according to embodiments of the present disclosure that includes a body having a cutting layer \n914\n on a substrate \n916\n at an interface \n915\n.', 'A cutting face \n920\n is formed on the cutting layer \n914\n opposite the interface \n915\n.', 'An edge \n930\n is formed at the junction of the cutting face \n920\n and a side surface \n912\n, where the edge \n930\n extends around a perimeter of the cutting face \n920\n.', 'The edge \n930\n has different heights (e.g., relative to the interface \n915\n or a base of the substrate \n916\n), wherein at least one high portion \n932\n of the edge has an acute edge angle formed between a portion of the cutting face \n920\n and the side surface \n912\n of the cutting element \n900\n along the high portion \n932\n of the edge \n930\n.', 'The acute edge angle portion (forming the high portion \n932\n) is formed by a portion of the cutting face \n920\n extending downwardly from the edge \n930\n toward a lower point or lower region of the cutting face \n920\n at depth \n940\n.', 'The depth \n940\n may be less than 50% of a total thickness \n918\n of the cutting layer \n914\n in some embodiments.', 'The edge \n930\n further includes a low portion \n934\n, wherein the low portion \n934\n of the edge is a right edge angle portion having a right angle formed between a planar portion of the cutting face \n920\n (having a planar cross-sectional profile) and the side surface \n912\n of the cutting layer \n914\n along the right edge angle portion of the edge.', 'In some embodiments, a low portion of an edge may be an obtuse edge angle portion having an obtuse angle formed between a convex portion of the cutting face and the side surface of the cutting element along the low portion of the edge.', 'In yet other embodiments, a low portion of an edge may also be an acute edge angle portion having an acute angle formed between a concave portion of the cutting face and the side surface of the cutting element along the low portion of the edge.', 'In such embodiments, the high portion(s) of the edge may be formed of portions of the cutting face having a relatively smaller radius of curvature (or steeper sloping planar surfaces) extending from the high portion(s) of the edge toward a central region of the cutting face when compared with the portions of the cutting face forming the low portion(s) of the edge.', 'Referring still to \nFIGS.', '8-1 to 8-3\n, two low portions \n934\n are at the outer ends of a linear depressed region \n926\n, where the linear depressed region \n926\n spaces apart two outer raised portions forming the high portions \n932\n of the edge \n930\n.', 'The linear depressed region \n926\n extends across a minor diameter \n902\n of the cutting face \n920\n and has a planar cross-sectional profile along a cross-section taken through the minor diameter \n902\n, where the planar portion of the cutting face \n920\n forms the right edge angle portion (see cross-section of \nFIG.', '8-3\n).', 'The cross-sectional profile of the cutting face \n920\n taken through the major diameter \n904\n (see cross-section shown in \nFIG.', '8-2\n) has a concave profile, where the cutting face \n920\n extends downwardly from the high portions \n932\n toward a central region (the linear depressed region \n926\n) of the cutting face to depth \n940\n.', 'The concave profile may have a radius of curvature, which may range, for example, up to two times the major diameter \n904\n, up to four times the major diameter \n904\n, up to six times the major diameter \n904\n, or up to eight times the major diameter \n904\n.', 'In other embodiments, the concave profile may include linear segments that form a piecewise continuous profile.', 'An edge of a cutting element according to embodiments of the present disclosure may have a bevel formed around the entire edge (such as the bevel shown in edge \n930\n in \nFIGS.', '8-1 to 8-3\n), or a bevel/chamfer may be formed around less than the entire edge, such as along high portions of the edge.', 'In some embodiments, a curved transition surface may be formed at the junction of the cutting face and the side surface of a cutting element.', 'A transition surface, such as a bevel, chamfer, or a curved transition surface, may have a relatively small size compared with the size of the cutting element, and thus may be negligible or close to negligible when measuring the diameter of the cutting face and the height of the side surface of a cutting element.', 'For example, a bevel or a curved transition surface may have a height of less than 2%, or in some embodiments, less than 5% of the total height of the cutting element and may have a radial distance of less than 1%, or in some embodiments, less than 3%.', 'In the embodiment shown in \nFIGS.', '8-1 to 8-3\n, the interface \n915\n is planar, where the thickness of the cutting layer \n914\n is greatest at the high portions \n932\n of the edge \n930\n and smallest along the depressed region \n926\n and low portions \n934\n of the edge \n930\n.', 'In some embodiments, an interface between a substrate and a cutting layer may be non-planar.', 'For example, an interface may have a non-planar geometry corresponding in shape and orientation to a non-planar cutting face of the cutting element.', 'In such embodiments, the thickness of the cutting layer may be uniform along the entire cutting layer.', 'In some embodiments, an interface may have a non-planar geometry that does not correspond in shape and/or orientation to a non-planar cutting face.', 'According to embodiments of the present disclosure, a cutting element may include a sloped side surface extending radially outward in a direction from a base surface of the cutting element toward the cutting face of the cutting element.', 'The entire side surface or less than the entire side surface of a cutting element may be sloped outwardly in a direction from the base surface toward the cutting face of the cutting element.', 'For example, as shown in \nFIGS.', '8-1 to 8-3\n, a portion of the side surface \n912\n around the cutting layer \n914\n may be sloped, while the entire side surface \n912\n around the substrate \n916\n may be parallel with a longitudinal axis of the cutting element \n900\n.', 'The sloped portion of the side surface \n912\n around the cutting layer \n914\n extends radially outward in a direction from the interface \n915\n to the high portions \n932\n of the edge \n930\n.', 'The remaining portions of the side surface \n912\n extend parallel with a longitudinal axis of the cutting element, from the interface \n915\n to the base surface of the cutting element and from the low portions \n934\n of the edge \n930\n to the base surface of the cutting element.', 'In some embodiments, the side surface of a substrate of a cutting element may extend substantially parallel with a longitudinal axis of the cutting element, and the side surface around the entire perimeter of the cutting layer of the cutting element may extend in a radially outward direction from the interface to the edge.', 'In some embodiments, the entire side surface of a cutting element may extend radially outward from the base surface of the cutting element to the cutting face of the cutting element.', 'In some embodiments, the side surface around one or more portions of the cutting element perimeter may have an outwardly sloping profile from the base surface to the cutting face, while one or more other portions of the side surface may extend substantially parallel to the longitudinal axis from the base surface to the cutting face.', 'For example, \nFIGS.', '9-1 and 9-2\n are views of an example cutting element \n200\n having a portion of the side surface \n212\n sloping outwardly from a base surface \n213\n to a cutting face edge \n230\n of the cutting element \n200\n.', 'The cutting element \n200\n has a non-planar cutting face \n220\n according to embodiments of the present disclosure, where the side surface \n212\n includes portions \n217\n that are outwardly sloping in a direction from the base surface \n213\n to the cutting face \n220\n, and portions \n215\n that are parallel with a central longitudinal axis \n201\n of the cutting element \n200\n.', 'The cross-sectional profile of the cutting face \n220\n has a sinusoidal shape, wherein the cross-sectional profile is at a plane extending along and intersecting with the central longitudinal axis \n201\n.', 'Two outer raised portions \n222\n and a central raised portion \n224\n spaced apart by depressed regions \n226\n form the sinusoidal cross-sectional profile.', 'The two outer raised portions \n222\n and the central raised portion \n224\n extend the same height and form the highest portions around an edge \n230\n.', 'However, in other embodiments, raised portions forming a non-planar cutting face may extend different heights.', 'The outer raised portions \n222\n form a first high portion and a second high portion of the edge \n230\n, and the central raised portion \n224\n extends linearly across the cutting face from a third high portion of the edge \n230\n to a fourth high portion of the edge \n230\n.', 'Outwardly sloping portions \n217\n of the side surface \n212\n extend between the base surface \n213\n to the first and second high portions formed along the outer raised portions \n222\n, and portions \n215\n of the side surface \n212\n parallel to the longitudinal axis extend between the base surface \n213\n to the third and fourth high portions of the edge \n230\n.', 'According to embodiments of the present disclosure, a cutting element may include a body, a non-planar cutting face, a height measured between a base surface of the body and the non-planar cutting face, and an edge extending around a perimeter of the non-planar cutting face, where the height of the edge varies around the perimeter.', 'A first portion of the edge may extend higher than a second portion of the edge, and an edge angle defined between the non-planar cutting face and a side surface of the body at the first portion of the edge may be less than 90°.', 'In some embodiments, the first portion of the non-planar cutting face forming the first portion of the edge may have a curved region, such that the curved region of the non-planar cutting face may have a concave profile at the first portion of the edge to form the edge angle of less than 90° (an acute edge angle).', 'In some embodiments, the first portion of the non-planar cutting face forming the first portion of the edge may have a downwardly sloping planar region to a depth from the edge, such that the planar region of the non-planar cutting face may have a planar profile at the first portion of the edge to form the edge angle of less than 90°.', 'The edge angle at the second portion of the edge may be greater than or equal to 90°.', 'For example, in some embodiments, a second portion of the non-planar cutting face forming the second portion of the edge may have a curved region, such that the curved region of the non-planar cutting face may have a convex profile at the first portion of the edge to form an edge angle of greater than 90° (an obtuse edge angle).', 'Non-planar cutting faces according to embodiments of the present disclosure may have a symmetric geometry relative to a plane extending through the second portion of the edge and a central longitudinal axis of the cutting element.', 'FIGS.', '10-1 to 10-9\n show an example of a cutting element according to embodiments of the present disclosure.', 'FIG.', '10-1\n is a side view of the cutting element \n700\n, and \nFIG.', '10-2\n is a top view of the cutting element \n700\n.', 'FIGS.', '10-3 to 10-9\n are cross-sectional views of the cutting element \n700\n taken along cross sections F-F, E-E, D-D, C-C, B-B, A-A, and Center-Center shown in \nFIG.', '10-2\n.', 'The cutting element \n700\n has a body \n710\n, a non-planar cutting face \n720\n, a height \n705\n measured between a base surface \n713\n of the body and the non-planar cutting face \n720\n, and an edge \n730\n extending around a perimeter of the non-planar cutting face \n720\n.', 'The height \n705\n of the edge varies around the perimeter, where a first portion \n732\n of the edge \n730\n may extend higher than a second portion \n734\n of the edge \n730\n.', 'An edge angle defined between the non-planar cutting face \n720\n and a side surface \n712\n of the body \n710\n at the first portion \n732\n of the edge may be less than 90°, and the edge angle at the second portion \n734\n of the edge may be greater than or equal to 90°.', 'A convex raised portion \n724\n of the cutting face \n720\n may be formed at a central region of the cutting face \n720\n, spaced between the two first portions \n732\n of the edge having edge angles less than 90° and spaced between the two second portions \n734\n of the edge having edge angles of about 90°.', 'The convex raised portion \n724\n extends a height less than the first portions \n732\n of the edge \n730\n.', 'Further, the second portions \n734\n of the edge also extend a height less than the first portions \n732\n.', 'In some embodiments, the second portion \n734\n may also extend a height less than the convex raised portion \n724\n, but it may be greater than convex raised portions \n724\n in other embodiments.', 'According to embodiments of the present disclosure, a cutting element may include a body, a non-planar cutting face, a height measured between a base surface of the body and the non-planar cutting face, and an edge extending around a perimeter of the non-planar cutting face, where the height of the edge varies around the perimeter.', 'The edge may include two or more high portions having an acute edge angle formed between the non-planar cutting face and a side surface of the body, where the high portions are spaced apart around the edge.', 'In some embodiments, a high portion at an end of a cutting element may include a planar, flat, or right surface adjacent an acute edge angle portion.', 'FIGS.', '11-1 to 11-5\n, for instance, illustrate various views of a cutting element \n1300\n in accordance with some embodiments of the present disclosure.', 'FIG.', '11-1\n is a perspective view of the cutting element \n1300\n, and \nFIGS.', '11-2 and 11-3\n are side views of the cutting element \n1300\n.', 'FIG.', '11-4\n is a top view of the cutting element \n1300\n, and \nFIG.', '11-5\n is an enlarged view of a raised portion of the edge of the cutting element \n1300\n of \nFIG.', '11-2\n.', 'The cutting element \n1300\n is similar to the cutting element \n700\n of \nFIGS.', '10-1 and 10-2\n, and has a body \n1310\n, a non-planar cutting face \n1320\n (with two outer raised regions \n1332\n and a central raised portion \n1336\n), and an edge \n1330\n extending around a perimeter of the non-planar cutting face \n1320\n.', 'The height of the edge \n1330\n varies around the perimeter of the cutting element \n1300\n, where the first, raised portion \n1332\n of the edge \n1330\n may extend higher than a second, depressed portion \n1334\n of the edge \n1330\n.', 'In the illustrated embodiment, the cutting element \n1330\n also includes the third, central raised portion \n1336\n.', 'The third portion \n1336\n may be a dome in a center of the cutting element \n1300\n (see \nFIG.', '11-4\n), a ridge across the cutting element \n1300\n (compare with \nFIG.', '13\n), or another shape of raised portion.', 'The cutting element \n1300\n differs from the cutting element \n700\n of \nFIGS.', '10-1 and 10-2\n, in that the first portion \n1332\n may not have an edge angle less than 90° at the intersection with the bevel \n1331\n (or with the side surface if there is no bevel \n1331\n).', 'Rather, the first portion \n1332\n may include a generally flat portion \n1335\n and an optional inclined portion \n1339\n.', 'The edge angle of the flat portion \n1335\n (measured between the flat portion \n1335\n and the side of the cutting element \n1330\n) may be about 90°, while the edge angle \n1337\n of the inclined portion \n1339\n may be an acute angle.', 'The acute edge angle \n1337\n as measured between lines tangent to the inclined portion \n1339\n and the side of the cutting element \n1330\n is, in this embodiment, in a range that is greater than 35°, greater than 45°, or greater than 60° and up to 89°.', 'For instance, the acute edge angle \n1337\n may be between 65° and 75°.', 'At the first portion \n1332\n, the non-planar cutting face \n1320\n may be piecewise continuous.', 'For instance, adjacent the edge \n1330\n, the first, raised portion \n1332\n may start from a flat top surface and transition into a valley of the second, depressed portion \n1334\n (e.g., at an acute edge angle \n1337\n of 50° to 85°).', 'The flat portion \n1335\n has been found to provide increased edge durability, and the size of the flat portion may be varied to achieve desired cutting efficiency and durability for a specific application.', 'As shown in \nFIG.', '11-4\n, the flat portion \n1335\n is, in some embodiments, formed as a chordal area, or chordal flat.', 'The radial length \n1333\n of the flat portion \n1335\n (i.e., the distance between the innermost portion of the flat and the outer side surface) is, in some embodiments, in a range between 0.25 mm to 4 mm, between 0.5 mm and 2.5 mm, or between 1 mm and 2 mm.', 'In some embodiments, the length \n1333\n is expressed as a percentage of the diameter of the cutting element \n1300\n, or as a percentage of the major or minor diameter for an elliptical cutting element.', 'For instance, the length \n1333\n may be in a range having a lower limit, an upper limit, or lower and upper limits including any of 2%, 5%, 8%, 10%, 13%, 17%, 20% of the diameter, or any values therebetween.', 'In some embodiments, the length \n1333\n may be between 2.5% and 13.5%, between 3.5% and 7.5%, or between 5% and 10% of the diameter (or width) of the cutting element \n1300\n.', 'While the flat portion \n1335\n has been described as a chordal area, in other embodiments, the flat portion \n1335\n may have other shapes.', 'For instance, the flat portion \n1335\n may not extend across a full chordal width.', 'In other embodiments, the flat portion \n1335\n may be annular and extend around a full or partial circumference of the cutting edge \n1330\n.', 'In such embodiments, the length \n1333\n of the flat portion \n1335\n may be generally constant around the full or partial circumference of the cutting edge \n1330\n, rather than as shown in \nFIG.', '11-4\n, have a variable length \n1333\n that is greatest at the center and which decreases toward each outer end.', 'In still other embodiments, the length \n1333\n may vary around an annular or other shaped flat region \n1335\n.', 'Two flat regions \n1335\n are shown in \nFIGS.', '11-1 to 11-6\n; however, more or fewer flat regions \n1335\n may be used in other embodiments.', 'For instance, in some embodiments, three or four flat region \n1335\n may be included and spaced at equal or unequal angular intervals along the circumference of the cutting edge \n1330\n.', 'In other embodiments, a single flat region may be used (e.g., an annular flat region).', 'In still other embodiments, the flat regions \n1335\n may be described in terms of the amount of circumferential coverage provided to the cutting edge \n1330\n, rather than the number of flat regions.', 'For instance, as shown in \nFIG.', '11-4\n, one of the flat regions \n1335\n may extend provide circumferential coverage \n1338\n to between 40° and 60° of the cutting edge \n1330\n.', 'The two flat regions \n1335\n may therefore provide coverage to between 80° and 120° of the cutting edge \n330\n (i.e., between about 20% and about 35% of the periphery of the cutting edge \n1330\n).', 'As discussed herein, however, the number, length, and shape of the flat regions \n1335\n may vary.', 'Thus, by increasing or decreasing the length \n1333\n of the flat regions \n1335\n, or by increasing or decreasing the number of flat regions \n1335\n, the amount of coverage could be within a range including a lower limit, an upper limit, or lower and upper limits that include any of 5%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, and 100% of the cutting edge circumference or perimeter, or any values therebetween.', 'For instance, in some embodiments, the total circumferential coverage \n1338\n for the one or more flat regions \n1335\n is greater than 20%, less than 75%, between 5% and 75%, between 10% and 50%, or between 25% and 30%.', 'The third, raised portion \n1336\n may be formed at a central region of the cutting face \n1320\n, spaced between the two first, raised portions \n1332\n of the edge \n1320\n having a flat portion \n1337\n and an inclined portion \n1339\n, in which the inclined portion of the edge angles less than 90°.', 'The raised portion \n1336\n may also be spaced between the two second, depressed portions \n1334\n of the edge having edge angles of about 90° or greater.', 'The raised portion \n1336\n may be raised and may extend a height less than, equal to, or greater than the first portions \n1332\n of the edge \n1330\n.', 'Further, the depressed portions \n1334\n of the edge also extend a height less than the raised portions \n1332\n.', 'In some embodiments, the depressed portions \n1334\n also extend a height less than the central raised portion \n1336\n, but it may be greater than convex raised portions \n1336\n in other embodiments.', 'FIG.', '11-6\n is a schematic, cross-sectional view of the cutting element \n1300\n having a non-planar cutting face \n1320\n formed at a first end of a body \n1310\n.', 'The cutting element \n1300\n may be in a cutter pocket (not shown) and have a flat portion \n1335\n and an acute edge angle portion \n1339\n of the edge \n1330\n that forms a portion of the cutting edge of the cutting element.', 'As the cutting element is engaged with and moved across a formation \n1350\n, an engagement area \n1321\n of the cutting face \n1320\n extends the depth of cut into the formation \n1350\n.', 'An engagement angle \n1360\n is defined between the line \n1355\n perpendicular to the formation \n1350\n being cut and the line \n1325\n tangent to the acute edge angle portion \n1339\n in the engagement area \n1321\n of the cutting face \n1320\n.', 'In the embodiment shown, the engagement area \n1321\n of the cutting face \n1320\n has a partially flat and partially concave cross-sectional profile, and thus, the engagement angle \n1360\n varies along the depth of cut.', 'In at least some embodiments, a flat region \n1335\n or other impact resistant feature on cutting edge \n1330\n or at the interface between the cutting edge \n1330\n and the non-planar cutting face \n1320\n has a radial length that is fully within the engagement area \n1321\n.', 'Stated another way, the depth of cut of the cutting face \n1320\n may be greater than the radial length of the flat region \n1335\n.', 'According to embodiments of the present disclosure, an engagement angle \n1360\n formed at an acute edge angle portion of a cutting element may be positive, for example, within a range having a lower limit, an upper limit, or both lower and upper limits including any of 00, 2°, 5°, 10°, 15°, 20°, 25°, 30°, 40°, 50°, or any values therebetween, where any relatively lower value may be selected in combination with any relatively higher value.', 'Further, in some embodiments of the present disclosure, an engagement angle \n1360\n varying along a depth of cut may have a difference along a non-flat portion that has a value greater than 2°, for example, up to 5°, up to 10°, or more.', 'For example, an engagement angle formed along an engagement area having a concave cross-sectional profile \n1339\n may have a difference in engagement angles along the depth of cut of ranging from about 5° to about 15°, or more, depending on the radius of curvature of the concave cross-sectional profiles.', 'In some embodiments, a raised portion of an edge may include multiple portions, but may not include a flat portion.', 'FIGS.', '12-1 to 12-3\n, for instance, illustrate an example embodiment of a cutting element \n1400\n that includes a continuous, piecewise acute angle portion. \nFIG.', '12-1\n is a perspective view of the cutting element \n1400\n, \nFIG.', '12\n is a side view of the cutting element \n1400\n.', 'FIG.', '12-3\n is an enlarged view of a raised portion of the edge of the cutting element \n1400\n of \nFIG.', '12-2\n.', 'The cutting element \n1400\n is similar to the cutting element \n1300\n of \nFIGS.', '11-1 to 11-4\n, and has a body \n1410\n, a non-planar cutting face \n1420\n, and an edge \n1430\n extending around a perimeter of the non-planar cutting face \n1420\n.', 'The height of the edge \n1430\n varies around the perimeter of the cutting element \n1400\n, where a first, raised portion \n1432\n of the edge \n1430\n may extend higher than a second, depressed portion \n1434\n of the edge \n1430\n.', 'In the illustrated embodiment, the cutting element \n1430\n also includes a third, central raised portion \n1436\n.', 'The third portion \n1436\n may be a dome in a center of the cutting element \n1400\n as discussed with respect to cutting element \n1300\n, may be a ridge across the cutting element (compare with \nFIG.', '13\n), or may have some other shape.', 'The cutting element \n1400\n differs from the cutting element \n1300\n of \nFIGS.', '11-1 to 11-5\n, in that the first portion \n1432\n has two portions \n1435\n, \n1439\n that each have an edge angle \n1437\n, \n1441\n that is less than 90°.', 'In particular, a first inclined portion \n1435\n immediately adjacent the bevel \n1431\n may be inclined to be at a first acute edge angle \n1437\n.', 'The acute edge angle \n1437\n as measured between lines tangent to the first inclined portion \n1435\n and the side of the cutting element \n1430\n is, in this embodiment, in a range that is greater than 45°, greater than 60°, or greater than 70° and up to 89°.', 'For instance, the acute edge angle \n1437\n may be between 60° and 89°, or between 75° and 85°.', 'The second inclined portion \n1435\n may be adjacent the first inclined portion \n1435\n, and may extend toward a recessed portion \n1434\n.', 'The acute edge angel \n1441\n of the second inclined portion \n1435\n is, in this embodiment, in a range that is greater than 35°, greater than 45°, or greater than 60° and up to 89°.', 'For instance, the acute edge angle \n1337\n may be between 50° and 80°, or between 65° and 75°.\n \nFIG.', '13\n is a top view of a cutting element \n1500\n similar to cutting elements \n1300\n and \n1400\n of \nFIGS.', '11-1 to 12-3\n, and includes a non-planar cutting face that is piecewise continuous, with portions of differing heights.', 'For instance, adjacent an edge raised portions include first and second sections \n1535\n, \n1539\n.', 'The first section \n1535\n may be planar and at a 90° angle relative to a side of the cutting element \n1500\n, or at an acute edge angle relative to the side of the cutting element \n1500\n.', 'In some embodiments, the first section \n1535\n is a chordal area.', 'The second section \n1539\n may be an inclined section that is at a lesser edge angle relative to the side of the cutting element \n1500\n than is the raised portion \n1535\n.', 'In some embodiments, the second section \n1539\n is an area bounded by two chords.', 'The chord nearer the first section \n1535\n may be at a higher elevation and have a shorter length as compared to the chord farther from the first section \n1535\n.', 'The second section \n1539\n may be planar, concave, convex, have other shapes, or include combinations of the foregoing.', 'A depressed portion \n1534\n of the non-planar cutting face may be between the second section \n1539\n and a raised central portion \n1536\n.', 'The raised central portion \n1536\n may extend across a full width of the cutting element \n1500\n to form a ridge.', 'The depressed portion \n1534\n may also be defined by two chords.', 'The two chords are optionally at about the same height or elevation.', 'The depressed portion \n1534\n and/or the raised central portion \n1534\n may be planar or curved.', 'For instance, the depressed portion \n1534\n may be concave, while the central portion \n1534\n may be convex.', 'Features of different embodiments described herein may be used in combination.', 'For instance, a single cutting tool may include cutting elements of different configurations.', 'In other embodiments, a single cutting element may include different features described herein. \nFIG.', '14\n, for instance, illustrates examples of four different cutting edge profiles according to illustrative embodiments of the present disclosure.', 'Cutting edge \n1601\n is similar to the cutting edge profile to the cutting edge in the embodiment described with respect to \nFIGS.', '3, 6-1, and 6-2\n,', 'and includes a bevel adjacent a raised portion defining an acute edge angle.', 'Cutting edge \n1602\n generally follows a path similar to the cutting edge \n1601\n, and includes a bevel and a raised portion defining an acute edge angle; however, the cutting edge \n1602\n includes a compound, or piece-wise continuous raised portion that creates two separate angles.', 'In this manner, the cutting edge \n1602\n is similar to the cutting edge of the embodiment described with respect to \nFIGS.', '12-1 to 12-3\n.', 'In some embodiments, the cutting edge \n1602\n may provide increased impact resistance at the cutting edge, when compared to the cutting edge \n1601\n.', 'Cutting edge \n1603\n is similar to the embodiment described with respect to \nFIGS.', '11-1 to 11-6\n and includes a bevel adjacent a raised portion.', 'The raised portion includes a generally flat region that transitions to an inclined region defining an acute edge angle.', 'The inclined region may be linear or curved.', 'The length of the flat region, angle of the inclined region, and the like may vary in accordance with different embodiments, including those disclosed herein.', 'In embodiments tested by the Applicant of the present disclosure in which a flat region had a length between 5% and 10% of the diameter of the cutting element, and a single flat region covered between 10% and 17.5% of the circumference of the cutting element, impact resistant improved by more than 300% when compared to a cutting edge such as cutting edge \n1601\n, that did not include a similar flat region.', 'Accordingly, in at least some embodiments, each flat region at a cutting edge may also be referred to as an impact resistant feature.', 'Cutting edge \n1604\n is a composite cutting edge profile that combines aspects of the cutting edges \n1602\n, \n1603\n.', 'In this particular embodiment, the cutting edge \n1604\n includes a bevel adjacent a flat region.', 'The flat region transitions to an inclined region that itself includes a piecewise continuous, or compound portion with two or more separate angles.', 'In some embodiments, the radially outermost inclined region adjacent the flat region may be linear in a profile or cross-sectional view, although such region may be contoured (concave, convex, wavy, etc.) in other embodiments.', 'The radially inner portion of the inclined portion may similarly be linear or contoured in a profile or cross-sectional view.', 'FIG.', '15\n shows another example of a cutting element \n20\n having a non-planar cutting face \n22\n at a first end of the cutting element body \n21\n, where three high portions \n24\n are spaced apart around the edge \n25\n of the cutting face \n22\n.', 'Each of the high portions \n24\n has an acute edge angle formed between the non-planar cutting face \n22\n and a side surface \n23\n of the body \n21\n.', 'The portions of the non-planar cutting face \n22\n at the high portions \n24\n may extend downwardly from the edge \n25\n and radially inward toward a central longitudinal axis \n26\n of the cutting element \n20\n.', 'The high portions \n24\n may be spaced apart around the edge \n25\n by relatively low portions \n28\n formed around the edge \n25\n.', 'A right edge angle or an obtuse edge angle may be formed between the cutting face \n22\n and the side surface \n23\n at the low portions \n28\n.', 'In some embodiments, more than three relatively high portions (e.g., four high portions, five high portions or more) may be spaced apart around an edge of a non-planar cutting face on a cutting element by three or more relatively low portions of the edge, where the relatively high portions may have an acute edge angle formed between the cutting face and a side surface of the cutting element, and the relatively low portions may have edge angles greater than the edge angles of the high portions.', 'In some embodiments, a cutting element may have a single relatively high portion formed around the edge of a non-planar cutting face, where the high portion may have an acute edge angle and the remaining portion(s) of the edge may have an edge angle greater than the edge angle of the high portion.', 'Cutting elements according to embodiments of the present disclosure may be secured to, or otherwise positioned on a cutting tool in an orientation to have a selected effective back rake, or engagement angle.', 'For example, \nFIG.', '16\n shows an example of a drill bit \n800\n having a cutting element \n850\n according to embodiments of the present.', 'The bit \n800\n includes a bit body \n810\n having a longitudinal axis \n805\n extending therethrough and a plurality of blades \n820\n extending outwardly from the body \n810\n.', 'Cutter pockets are formed in the blades \n820\n in a selected orientation for receiving cutting elements.', 'Cutting elements \n860\n having planar cutting faces \n862\n are optionally in some of the cutter pockets, and cutting elements \n850\n having non-planar cutting faces \n852\n according to embodiments disclosed herein are disposed in some cutter pockets.', 'The non-planar cutting faces \n852\n include at least one acute edge angle portion \n854\n of the cutting element edge oriented as a cutting edge to engage a formation during drilling.', 'According to embodiments of the present disclosure, at least one cutting element having a non-planar cutting face as disclosed herein may be on a cutting tool, such as the drill bit \n800\n shown in \nFIG.', '16\n, to form the cutting profile of the cutting tool.', 'The engagement angle formed between the cutting elements \n850\n, \n860\n as they engage a formation may depend on the orientation of the cutter pocket in which the cutting elements are positioned, and the surface geometry of the cutting faces \n852\n, \n862\n.', 'For example, an engagement angle may be varied by varying the orientation of a cutter pocket relative to the bit (varying the angle between the line tangent to the cutter pocket side wall relative to the cutting tool axis), and/or, an engagement angle may be varied by varying the surface geometry of a non-planar cutting face (e.g., such that a selected edge angle is provided as the cutting edge).', 'In some embodiments, an engagement angle formed between a formation and a non-planar cutting element (having different edge angles formed around the edge of the non-planar cutting face) may be varied by rotating the non-planar cutting element within a cutter pocket to provide the different edge angles of the non-planar cutting face as the cutting edge.', 'Accordingly, non-planar cutting elements according to embodiments disclosed herein may be used to alter one or more engagement angles on a cutting profile of an already formed cutting tool.', 'Thus, in some embodiments, rather than (or in addition to) designing or altering a cutter pocket orientation relative to the cutting tool in which the cutter pocket is formed in order to provide a selected engagement angle between a cutting element in the cutter pocket and a formation, a non-planar cutting element according to embodiments of the present disclosure may be in an already formed cutter pocket to have an edge angle oriented in the cutting edge position in the cutter pocket in order to provide the selected engagement angle.', 'In some embodiments, non-planar cutting elements \n850\n, \n852\n may have a desired engagement angle while the cutter pocket is at a back rake angle that is between 5° and 50° or between 10° and 45°.', 'This may include non-planar cutting elements \n850\n, \n852\n in the cone, nose, shoulder, or gage regions of the bit, or in any combination of the cone, nose, shoulder, and gage regions of the bit.\n \nFIGS.', '17-1 and 17-2\n show an example of how an engagement angle may be altered using a cutting element according to embodiments of the present disclosure.', 'In \nFIGS.', '17-1 and 17-2\n, two different orientations of a cutting element \n1000\n within a cutter pocket \n1100\n are illustrated.', 'The cutter pocket \n1100\n has a bottom wall \n1101\n (shown as interfacing a base surface of the cutting element \n1000\n) and a side wall \n1102\n (shown as interfacing a side surface of the cutting element \n1000\n) and is formed along a cutting portion of a cutting tool \n1200\n.', 'The cutting element \n1000\n has a non-planar cutting face \n1002\n that includes different edge angles along the perimeter of the cutting face \n1002\n.', 'At a first rotational orientation in the cutter pocket \n1100\n, a first acute edge angle portion of the cutting face \n1002\n is positioned as a cutting edge \n1003\n of the cutting element, where the first acute edge angle at the cutting edge \n1003\n forms a positive engagement angle \n1300\n.', 'At a second rotational orientation in the cutter pocket \n1100\n, a second acute edge angle portion of the cutting face \n1002\n is positioned as the cutting edge \n1003\n, where the second acute edge angle at the cutting edge \n1003\n forms a negative engagement angle \n1302\n.', 'As shown, the engagement angle formed by a cutting element according to embodiments of the present disclosure may be altered within a single cutter pocket by rotating the cutting element within the cutter pocket to provide a different edge angle portion at the cutting edge.', 'In some embodiments, a cutting element according to embodiments of the present disclosure may be rotated within a single cutter pocket from a position having an acute edge angle portion of the cutting element at the cutting edge to a position having a right edge angle portion at the cutting edge and/or to a position having an obtuse edge angle portion at the cutting edge.', 'Further, as shown in \nFIG.', '17-1\n, a positive engagement angle \n1300\n may be formed by a cutting element \n1000\n according to embodiments of the present disclosure when the cutter pocket \n1100\n in which the cutting element \n1000\n is located would otherwise orient a conventional cutting element to have a negative back rake angle.', 'As shown, the cutter pocket \n1100\n may be oriented to have a line \n1103\n tangent to the side wall \n1102\n extending at an acute angle \n1400\n with a longitudinal axis \n1202\n of the cutting tool \n1200\n on which the cutting element \n1000\n is disposed.', 'If a cutting element having a planar surface (or having a right edge angle portion positioned to be the cutting edge) were to be in the cutter pocket \n1100\n, the back rake angle at the cutting edge would be negative.', 'According to embodiments of the present disclosure, an engagement angle may be altered by rotating a cutting element according to embodiments of the present disclosure within a cutter pocket formed on a cutting tool, such as a drill bit.', 'For example, a drill bit may include a bit body having a longitudinal axis extending there through, at least one blade extending outwardly from the bit body, a cutter pocket formed in an outermost surface of the at least one blade, the cutter pocket having a side wall and a bottom wall, wherein a line tangent to the side wall extends downwardly from the longitudinal axis at an acute angle.', 'A non-planar cutting element may be disposed in the cutter pocket, where the non-planar cutting element may include a body, a non-planar cutting face, and a cutting edge extending around a perimeter of the cutting face, and wherein a plane tangent to a portion of the cutting face at the cutting edge forms a positive engagement angle (or effective back rake) with the longitudinal axis of the drill bit.', 'Non-planar cutting elements according to embodiments of the present disclosure may be disposed on a variety of downhole cutting tools, including, for example, drill bits, reamers, and other hole opening tools.', 'For example, \nFIG.', '18\n shows an example of a hole opener \n830\n that includes one or more cutting elements \n840\n of the present disclosure.', 'The hole opener \n830\n includes a tool body \n832\n and a plurality of blades \n838\n disposed at selected azimuthal locations about a circumference thereof.', 'The hole opener \n830\n generally includes connections \n834\n, \n836\n (e.g., threaded connections) so that the hole opener \n830\n may be coupled to adjacent drilling tools that include, for example, a drill string and/or bottom hole assembly (BHA) (not shown).', 'The tool body \n832\n generally includes a bore there through so that drilling fluid may flow through the hole opener \n830\n as it is pumped from the surface (e.g., from surface mud pumps (not shown)) to a bottom of the wellbore (not shown).', 'While embodiments of the present disclosure have been described with respect to drill bits and other cutting tools for use in downhole applications, the present disclosure is not limited to such environments, and may be used in other environments, including manufacturing, and utility line placement.', 'Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure.', 'A stated value or terms such as “about,” “approximately,” “generally,” and the like, should therefore be interpreted broadly enough to encompass values, orientations, or features that are at least close enough to the stated value, orientation, or feature to perform a desired function or achieve a desired result.', 'Stated values, features, and orientations include at least the variation to be expected in a suitable manufacturing or production process, and may further include deviations that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value, orientation, or feature.', 'Where a range of values includes various lower or upper limits, any two values may define the bounds of the range, or any single value may define an upper limit (e.g., up to 50%) or a lower limit (at least 50%).', 'While embodiments of the present disclosure have been described with respect to the provided drawings, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the present disclosure and the claims.', 'Accordingly, the scope of the claims should include not only the embodiments disclosed but also such combinations of features now known or later discovered, or equivalents within the scope of the concepts disclosed and the full scope of the claims to which applicants are entitled to patent protection.'] | ['1.', 'A cutting element, comprising:\na substrate; and\na cutting layer on the substrate, the cutting layer defining a cutting edge, a non-planar cutting face opposite the substrate, and at least one impact resistant feature at an interface between the cutting edge and the non-planar cutting face, wherein the at least one impact resistant feature extends around less than 75% of a perimeter of the cutting edge, the non-planar cutting face including at least two raised portions including: a central raised portion; and a first raised edge portion comprising: a first section nearest the cutting edge forming at least a portion of the at least one impact resistant feature, wherein the first section has a first edge angle with a side surface of the cutting layer; and a second section adjacent the first section having a second edge angle less than the first edge angle.', '2.', 'The cutting element of claim 1, wherein the first edge angle defines an acute angle with the side surface of the cutting layer.', '3.', 'The cutting element of claim 2, the central raised portion defining an obtuse angle with the side surface of the cutting layer.', '4.', 'The cutting element of claim 1, the first section of the first raised edge portion having a radial length that is between 5% and 10% of a width of the cutting layer.', '5.', 'The cutting element of claim 4, the first section of the first raised edge portion extending around between 10% and 50% of the perimeter of the cutting edge.', '6.', 'The cutting element of claim 2, the edge angle of the second section being between 60° and 75°.', '7.', 'The cutting element of claim 1, the non-planar cutting face including:\nthe central raised portion across a full width of the cutting element;\nthe first raised edge portion spaced apart from the central raised portion by a first depressed portion; and\na second raised edge portion spaced apart from the central raised edge portion by a second depressed portion.', '8.', 'The cutting element of claim 7, a cross-sectional profile of the non-planar cutting face having a sinusoidal shape on a plane extending along and intersecting a central longitudinal axis of the cutting element, the first raised edge portion, and the second raised edge portion.', '9.', 'The cutting element of claim 1, wherein the cutting edge comprises a high portion and a low portion, the first raised edge portion being located at the high portion a first height from the low portion, the central raised portion being located at a second height from the low portion, and the first height of the first raised edge portion is greater than the second height of the central raised portion.', '10.', 'The cutting element of claim 1, wherein the first raised edge portion provides circumferential coverage to between 40° to 60° of the cutting edge.', '11.', 'The cutting element of claim 1, the first section of the first raised edge portion forms a chordal area.', '12.', 'A cutting element, comprising:\na substrate; and\na cutting layer on the substrate, the cutting layer defining a cutting edge, a non-planar cutting face opposite the substrate, and at least one impact resistant feature at an interface between the cutting edge and the non-planar cutting face, wherein the at least one impact resistant feature extends around less than 75% of a perimeter of the cutting edge, the non-planar cutting face including at least two raised portions including: a central raised portion; and a raised edge portion spaced apart from the central raised portion by a depressed portion, the raised edge portion including at least one flat region defining a planar portion of the cutting face.', '13.', 'The cutting element of claim 12, the at least one flat region having a radial length that is between 0.25 mm to 4 mm.\n\n\n\n\n\n\n14.', 'The cutting element of claim 12, the at least one flat region extending around between 10% and 50% of the perimeter of the cutting edge.', '15.', 'The cutting element of claim 12, wherein the raised edge portion provides circumferential coverage to between 40° to 60° of the cutting edge.', '16.', 'The cutting element of claim 12, wherein the raised edge portion includes an inclined portion having an acute edge angle with a side surface of the cutting layer, the inclined portion is between the at least one flat region and the depressed portion, and the acute edge angle is greater than 60°.', '17.', 'The cutting element of claim 12, wherein the cutting edge comprises a high portion and a low portion, the raised edge portion being located at the high portion a first height from the low portion, the central raised portion being located at a second height from the low portion, and the first height of the raised edge portion is greater than the second height of the central raised portion.', '18.', 'The cutting element of claim 17, the central raised portion comprising a dome.', '19.', 'The cutting element of claim 12, the at least one flat region forms a chordal area.', '20.', 'A cutting element, comprising:\na substrate; and\na cutting layer on the substrate, the cutting layer defining a cutting edge, a non-planar cutting face opposite the substrate, and at least one impact resistant feature at an interface between the cutting edge and the non-planar cutting face, wherein the at least one impact resistant feature extends around less than 75% of a perimeter of the cutting edge, the non-planar cutting face including at least three raised portions including: a central raised portion; a first raised edge portion spaced apart from the central raised portion by a first depressed portion, the first raised edge portion including at least one flat region defining a planar portion of the cutting face, the at least one flat region forming the at least one impact resistant feature; and a second raised edge portion spaced apart from the central raised portion by a second depressed portion.'] | ['FIG.', '1 is a perspective view of a cutting element according to embodiments of the present disclosure.', '; FIG.', '2 is a cross-sectional view of a cutting element according to embodiments of the present disclosure.', '; FIG.', '3 is a cross-sectional view of a cutting element according to embodiments of the present disclosure.', '; FIG.', '4 is a cross-sectional view of a cutting element according to embodiments of the present disclosure.', '; FIG.', '5 is a cross-sectional view of a cutting element according to embodiments of the present disclosure.; FIGS.', '6-1 and 6-2 are cross-sectional views of the cutting element of FIG.', '3 engaging a formation at different depths of cut.; FIGS.', '7-1 to 7-3 are perspective, top, and cross-sectional view, respectively, of a cutting element according to embodiments of the present disclosure.', '; FIGS. 8-1 to 8-3 are perspective and various cross-sectional views, respectively, of a cutting element according to embodiments of the present disclosure.', '; FIGS. 9-1 and 9-2 are cross-sectional and perspective views, respectively, of a cutting element according to embodiments of the present disclosure.; FIGS.', '10-1 and 10-2 are side and top views, respectively, of a cutting element according to embodiments of the present disclosure.; FIGS.', '10-3 to 10-9 are various cross-sectional views of the cutting element of FIGS.', '10-1 and 10-2.; FIGS.', '11-1 to 11-6 are views of a cutting element according to additional embodiments of the present disclosure.', '; FIGS.', '12-1 to 12-3 are views of another cutting element according to embodiments of the present disclosure.', '; FIG. 13 is a schematic, top view of a cutting element according to embodiments of the present disclosure.', '; FIG.', '14 is a side view of profiles of different cutting edges of cutting elements according to embodiments of the present disclosure.; FIG.', '15 shows a cutting element according to embodiments of the present disclosure.; FIG.', '16 shows a drill bit according to embodiments of the present disclosure.; FIGS.', '17-1 and 17-2 are cross-sectional views of a cutting element at different orientations within a cutter pocket according to embodiments of the present disclosure.', '; FIG.', '18 shows a hole opener according to embodiments of the present disclosure.; FIGS.', '1', 'and 2 are perspective and cross-sectional views, respectively, of an example of a cutting element according to embodiments of the present disclosure.', 'The cross-sectional view shown in FIG.', '2 is taken at a plane extending along and intersecting a longitudinal axis 101 of the cutting element 100.', 'The cutting element 100 includes a body 110 and a cutting face 120 formed at a first end portion of the body 110.', 'The cutting face 120 in FIGS.', '1 and 2 has a wavy, undulating geometry, having a central raised region 122 and two outer raised regions 124 spaced apart from and on opposite sides of the cutting face 120.', 'The undulating surface geometry of the cutting face 120 is symmetric about the plane of the cross-sectional view in FIG.', '2, as well as symmetric about a plane perpendicular to the cross-sectional plane, where both planes of symmetry extend along and intersect with the longitudinal axis 101.; FIGS.', '3-5 show examples of three different cutting profiles of a cutting element positioned at a given orientation.', 'As shown, although each cutting element is oriented in the same position, the different surface geometry along the engagement area of the cutting face provides different engagement angles with respect to a formation being engaged.', '; FIG.', '3 is a cross-sectional view of a cutting element 300 having a non-planar cutting face 320 formed at a first end of a body 310.', 'The cutting element 300 may be in a cutter pocket (not shown) and have an acute edge angle portion of the edge 330 that forms the cutting edge 331 of the cutting element.', 'As the cutting element is engaged with and moved across a formation 350, an engagement area 321 of the cutting face 320 extends the depth of cut into the formation 350.', 'An engagement angle 360 is defined between the line 355 perpendicular to the formation 350 being cut and the line 325 tangent to the engagement area 321 of the cutting face 320.', 'In the embodiment shown, the engagement area 321 of the cutting face 320 has a concave cross-sectional profile, and thus, the engagement angle 360 varies along the depth of cut.', 'In some embodiments, a cross-sectional profile of an engagement area of a non-planar cutting face may have a planar region, where the engagement angle is constant along the depth of cut for the planar region.', 'However, in some embodiments, the engagement area has both planar and non-planar regions or may be entirely non-planar, where the engagement angle may vary along the depth of cut engaging the varying regions of the engagement area.', '; FIG.', '4 is a cross-sectional view of a cutting element 400 in a cutter pocket at the same orientation (i.e., same angle between the longitudinal axis of the cutting element and the line perpendicular to the formation) as the cutting element 300 of FIG.', '3, where the cutting element 400 is positioned in the cutter pocket to have a right edge angle portion of the edge 430 form the cutting edge 431 of the cutting element.', 'As the cutting element is engaged with and moved across a formation 450, an engagement area 421 of the cutting face 420 extends the depth of cut into the formation 450.', 'An engagement angle 460 is defined between the line 455 perpendicular to the formation 450 being cut and the line 425 tangent to the engagement area 421 of the cutting face 420.', 'In the embodiment shown, the cutting element 400 may have a non-planar cutting face 420 formed at a first end of the body 410, where the non-planar cutting face includes a linear ridge extending between opposite sides of the edge 430, and where the cross section is taken along the linear ridge.', 'The linear ridge may have a planar cross-sectional profile forming the right edge angle.', 'In some embodiments, other cutting face geometries may form a right edge angle, for example a planar cutting face.; FIG.', '5 is a cross-sectional view of a cutting element 500 in a cutter pocket at the same orientation as the cutting elements 300, 400 of FIGS.', '3 and 4, where the cutting element 500 is positioned in the cutter pocket to have an obtuse edge angle portion of the edge 530 form the cutting edge 531 of the cutting element.', 'The obtuse edge angle portion of the edge 530 may be formed by a convex ridge extending between opposite sides of the edge 530, where the convex ridge has a convex profile extending outwardly from a base surface of the cutting element 500.', 'In some embodiments, other cutting face geometries may form an obtuse edge angle, for example, a planar surface extending upwardly and radially inward from the edge.', 'As the cutting element is engaged with and moved across a formation 550, an engagement area 521 of the cutting face 520 extends the depth of cut into the formation 550.', 'An engagement angle 560 is defined between the line 555 perpendicular to the formation 550 being cut and the line 525 tangent to the engagement area 521 of the cutting face 520.; FIGS.', '3-5 show how cutting elements having non-planar cutting faces according to embodiments of the present disclosure may be rotated and positioned within a cutter pocket at a given orientation to vary the engagement angle of the cutting element.', 'Similarly, cutting elements having a first type of cutting face surface geometry (e.g., a planar cutting face or a non-planar cutting face) may be replaced with cutting elements having a non-planar cutting face according to embodiments of the present disclosure to alter the engagement angle.; FIGS. 7-1 to 7-3 are perspective, top, and cross-sectional views, respectively, of a cutting element 600 having a non-planar cutting face 620 according to embodiments of the present disclosure.', 'The non-planar cutting face 620 has an undulating surface geometry, where relatively raised portions 622 form two opposite sides of the edge 630 of the cutting element, and a central raised portion 624 is formed between and spaced apart from the outer raised portions 622 by relatively depressed portions 626.', 'The central raised region 624 of the non-planar cutting face 620 forms a ridge extending between opposite sides of the perimeter of the cutting face 620 and through a central region of the cutting face 620.; FIGS.', '10-1 to 10-9 show an example of a cutting element according to embodiments of the present disclosure.', 'FIG.', '10-1 is a side view of the cutting element 700, and FIG.', '10-2 is a top view of the cutting element 700.', 'FIGS.', '10-3 to 10-9 are cross-sectional views of the cutting element 700 taken along cross sections F-F, E-E, D-D, C-C, B-B, A-A, and Center-Center shown in FIG.', '10-2.', 'The cutting element 700 has a body 710, a non-planar cutting face 720, a height 705 measured between a base surface 713 of the body and the non-planar cutting face 720, and an edge 730 extending around a perimeter of the non-planar cutting face 720.', 'The height 705 of the edge varies around the perimeter, where a first portion 732 of the edge 730 may extend higher than a second portion 734 of the edge 730.', 'An edge angle defined between the non-planar cutting face 720 and a side surface 712 of the body 710 at the first portion 732 of the edge may be less than 90°, and the edge angle at the second portion 734 of the edge may be greater than or equal to 90°.; FIG.', '11-6 is a schematic, cross-sectional view of the cutting element 1300 having a non-planar cutting face 1320 formed at a first end of a body 1310.', 'The cutting element 1300 may be in a cutter pocket (not shown) and have a flat portion 1335 and an acute edge angle portion 1339 of the edge 1330 that forms a portion of the cutting edge of the cutting element.', 'As the cutting element is engaged with and moved across a formation 1350, an engagement area 1321 of the cutting face 1320 extends the depth of cut into the formation 1350.', 'An engagement angle 1360 is defined between the line 1355 perpendicular to the formation 1350 being cut and the line 1325 tangent to the acute edge angle portion 1339 in the engagement area 1321 of the cutting face 1320.', 'In the embodiment shown, the engagement area 1321 of the cutting face 1320 has a partially flat and partially concave cross-sectional profile, and thus, the engagement angle 1360 varies along the depth of cut.', 'In at least some embodiments, a flat region 1335 or other impact resistant feature on cutting edge 1330 or at the interface between the cutting edge 1330 and the non-planar cutting face 1320 has a radial length that is fully within the engagement area 1321.', 'Stated another way, the depth of cut of the cutting face 1320 may be greater than the radial length of the flat region 1335.', '; FIG.', '13 is a top view of a cutting element 1500 similar to cutting elements 1300 and 1400 of FIGS.', '11-1 to 12-3, and includes a non-planar cutting face that is piecewise continuous, with portions of differing heights.', 'For instance, adjacent an edge raised portions include first and second sections 1535, 1539.', 'The first section 1535 may be planar and at a 90° angle relative to a side of the cutting element 1500, or at an acute edge angle relative to the side of the cutting element 1500.', 'In some embodiments, the first section 1535 is a chordal area.', 'The second section 1539 may be an inclined section that is at a lesser edge angle relative to the side of the cutting element 1500 than is the raised portion 1535.', 'In some embodiments, the second section 1539 is an area bounded by two chords.', 'The chord nearer the first section 1535 may be at a higher elevation and have a shorter length as compared to the chord farther from the first section 1535.', 'The second section 1539 may be planar, concave, convex, have other shapes, or include combinations of the foregoing.', '; FIG.', '15 shows another example of a cutting element 20 having a non-planar cutting face 22 at a first end of the cutting element body 21, where three high portions 24 are spaced apart around the edge 25 of the cutting face 22.', 'Each of the high portions 24 has an acute edge angle formed between the non-planar cutting face 22 and a side surface 23 of the body 21.', 'The portions of the non-planar cutting face 22 at the high portions 24 may extend downwardly from the edge 25 and radially inward toward a central longitudinal axis 26 of the cutting element 20.', 'The high portions 24 may be spaced apart around the edge 25 by relatively low portions 28 formed around the edge 25.', 'A right edge angle or an obtuse edge angle may be formed between the cutting face 22 and the side surface 23 at the low portions 28.; FIGS.', '17-1 and 17-2 show an example of how an engagement angle may be altered using a cutting element according to embodiments of the present disclosure.', 'In FIGS.', '17-1 and 17-2, two different orientations of a cutting element 1000 within a cutter pocket 1100 are illustrated.', 'The cutter pocket 1100 has a bottom wall 1101 (shown as interfacing a base surface of the cutting element 1000) and a side wall 1102 (shown as interfacing a side surface of the cutting element 1000) and is formed along a cutting portion of a cutting tool 1200.', 'The cutting element 1000 has a non-planar cutting face 1002 that includes different edge angles along the perimeter of the cutting face 1002.', 'At a first rotational orientation in the cutter pocket 1100, a first acute edge angle portion of the cutting face 1002 is positioned as a cutting edge 1003 of the cutting element, where the first acute edge angle at the cutting edge 1003 forms a positive engagement angle 1300.', 'At a second rotational orientation in the cutter pocket 1100, a second acute edge angle portion of the cutting face 1002 is positioned as the cutting edge 1003, where the second acute edge angle at the cutting edge 1003 forms a negative engagement angle 1302.', 'As shown, the engagement angle formed by a cutting element according to embodiments of the present disclosure may be altered within a single cutter pocket by rotating the cutting element within the cutter pocket to provide a different edge angle portion at the cutting edge.', 'In some embodiments, a cutting element according to embodiments of the present disclosure may be rotated within a single cutter pocket from a position having an acute edge angle portion of the cutting element at the cutting edge to a position having a right edge angle portion at the cutting edge and/or to a position having an obtuse edge angle portion at the cutting edge.'] |
|
US11091975 | Expandable metal packer system and methodology with annulus pressure compensation | Mar 27, 2018 | Samuel Roselier, Romain Neveu, Jean-Louis Saltel | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 6640893; November 4, 2003; Rummel; 7306033; December 11, 2007; Gorrara; 7591321; September 22, 2009; Whitsitt et al.; 9217308; December 22, 2015; Wood; 20060042801; March 2, 2006; Hackworth et al.; 20160097254; April 7, 2016; Wood et al.; 20160341003; November 24, 2016; Saltel et al. | 2206879; July 2010; EP; WO2016/005292; January 2016; WO | ['A technique facilitates use of a packer in a borehole or within other tubular structures.', 'The packer may be constructed with a tubing, a metal sealing element mounted around the tubing, and a differential pressure valve system.', 'The metal sealing element may be expanded under fluid pressure for sealing engagement with a surrounding wall surface.', 'Additionally, the differential pressure valve system is placed in fluid communication with the interior of the metal sealing element and comprises a plurality of valves which operate automatically to increase pressure within the metal sealing element when certain pressure differentials occur.', 'The differential pressure valve system enables the packer to hold against higher differential pressures and also may be constructed so the packer is less sensitive to thermal variations.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThe present document is based on and claims priority to EP Application Serial No.: 17290044.1, filed Mar. 27, 2017, which is incorporated herein by reference in its entirety.', 'In many well applications, packers are used to seal off sections of a wellbore.', 'The packers are delivered downhole via a well string and then set against the surrounding wellbore surface to provide annular barriers between the adjacent uphole and downhole sections of wellbore.', 'In various applications, each packer comprises an elastomeric element which may be expanded radially into sealing engagement with the surrounding borehole surface.', 'Additionally, some applications utilize an expandable metal packer or packers.', 'Such expandable metal packers use a deformable metal membrane which is deformed permanently by the pressure of inflating fluid.', 'However, the seal between the deformable metal membrane and the surrounding wall surface may be susceptible to pressure differentials formed between sections of the annulus on uphole and downhole sides of the deformable metal membrane.', 'SUMMARY\n \nIn general, a system and methodology are provided for utilizing a packer in a borehole or within other tubular structures.', 'The packer may be constructed with a tubing, a metal sealing element mounted around the tubing, and a differential pressure valve system.', 'The metal sealing element may be expanded under fluid pressure for sealing engagement with a surrounding wall surface.', 'Additionally, the differential pressure valve system is placed in fluid communication with the interior of the metal sealing element and comprises a plurality of valves which operate automatically to increase pressure within the metal sealing element when certain pressure differentials occur.', 'The differential pressure valve system enables the packer to hold against higher differential pressures and also may be constructed so the packer is less sensitive to thermal variations.', 'However, many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nCertain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements.', 'It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:\n \nFIG.', '1\n is a cross-sectional illustration of an example of an expandable metal packer mounted along a tubing string in a borehole, according to an embodiment of the disclosure;\n \nFIG.', '2\n is a schematic illustration of an example of an expandable metal packer positioned along a tubing, according to an embodiment of the disclosure;\n \nFIG.', '3\n is a schematic illustration similar to that of \nFIG.', '2\n but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '4\n is a schematic illustration similar to that of \nFIG.', '2\n but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '5\n is a schematic illustration similar to that of \nFIG.', '2\n but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure;\n \nFIG.', '6\n is a schematic illustration similar to that of \nFIG.', '2\n but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure; and\n \nFIG.', '7\n is a schematic illustration similar to that of \nFIG.', '2\n but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure.', 'DETAILED DESCRIPTION', 'In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure.', 'However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.', 'The disclosure herein generally involves a system and methodology for utilizing a packer in a borehole or within other tubular structures.', 'For example, one or more of the packers may be deployed downhole into a wellbore via a well string.', 'The packer or packers may then be actuated to a set position to form a seal with the surrounding wellbore surface, e.g. an interior casing surface or an openhole surface, and to isolate sections of the annulus along the well string.', 'By way of example, the packer may be an expandable metal packer constructed with a metal sealing element and a differential pressure valve system.', 'The metal sealing element may be mounted around a tubing which may be part of a well string or other tubing string.', 'In some applications, the packer may comprise a section of tubing, e.g. mandrel, which forms part of the overall tubing string.', 'When the packer is positioned at a desired location within the borehole or other tubular structure, the metal sealing element may be expanded under fluid pressure for sealing engagement with a surrounding wall surface.', 'For example, the metal sealing element may be a permanently deformable metal bladder, e.g. membrane, which is deformed downhole via the fluid pressure, e.g. hydroforming.', 'It should be noted “tubing” refers generally to tubular structures and includes various types of casing.', 'For example, the tubing may comprise production casing, intermediate casing, surface casing, or other types of casing and the tubing string may be in the form of a casing string.', 'In this embodiment, the differential pressure valve system may be constructed to enable the expandable metal packer to hold against high differential pressures with little or no sensitivity to thermal variations.', 'By way of example, the differential pressure valve system may comprise a plurality of valves in fluid communication with the interior of the metal sealing element.', 'The plurality of valves operates automatically to increase pressure within the metal sealing element when certain pressure differentials occur.', 'For example, the individual valves actuate automatically to different positions when relatively higher pressures occur in the annulus uphole or downhole from the metal sealing element to allow the relatively higher pressure access to an interior of the metal sealing element.', 'Thus, the valves automatically compensate for the pressure differential.', 'The valve system also may be constructed so the expandable metal packer is less sensitive to thermal variations.', 'Referring generally to \nFIG.', '1\n, an example of a well system \n20\n is illustrated as deployed in a borehole \n22\n, e.g. a wellbore.', 'The well system \n20\n comprises an expandable metal packer \n24\n mounted along a tubing \n26\n which may be part of an overall tubing string \n28\n, e.g. a well production or casing string.', 'In some embodiments, the expandable metal packer \n24\n may comprise an internal packer tubing \n30\n, e.g. a packer mandrel, which may be part of the overall tubing \n26\n.', 'For example, the packer tubing/mandrel \n30\n may be constructed to facilitate incorporation of the expandable metal packer \n24\n into the overall tubing string \n28\n.', 'In the embodiment illustrated, the expandable metal packer \n24\n comprises a metal sealing element \n32\n.', 'The metal sealing element \n32\n may be expanded radially outwardly in a direction away from a central axis \n34\n of tubing string \n28\n.', 'As illustrated, the metal sealing element \n32\n may be expanded outwardly until it engages a surrounding wall surface \n36\n, e.g. a surrounding casing or open hole wellbore wall, in sealing engagement.', 'By way of example, the metal sealing element \n32\n may comprise a metal membrane, e.g. bladder, or other metal structure which may be plastically deformed into a permanent expanded structure engaging surrounding wall surface \n36\n.', 'In some embodiments, the metal sealing element \n32\n is expanded via fluid pressure, e.g. via a hydroforming process.', 'For example, high pressure fluid may be delivered along an interior \n38\n of tubing \n26\n and directed into an interior \n40\n of metal sealing element \n32\n via a passage or passages \n41\n extending through a wall of tubing \n26\n as illustrated.', 'According to the embodiment illustrated, the expandable metal packer \n24\n further comprises a valve system \n42\n which may be referred to as a differential pressure valve system.', 'The valve system \n42\n comprises a plurality of valves \n44\n which may be automatically shifted in response to pressure differentials occurring on opposite axial sides of the metal sealing element \n32\n in an annulus \n46\n between tubing \n26\n and surrounding wall surface \n36\n.', 'For reference, the pressure differential results from a differential between a higher annulus pressure on one axial side of metal sealing element \n32\n (e.g. a first annulus section \n48\n) and a relatively lower annulus pressure on the other axial side of metal sealing element \n32\n (e.g. a second annulus section \n50\n) or vice versa.', 'In the example illustrated, at least one valve \n44\n is positioned on one axial side of metal sealing element \n32\n and at least one valve \n44\n is positioned on the opposite axial side of metal sealing element \n32\n.', 'The valves \n44\n are constructed and arranged to automatically shift in a manner which allows the relatively higher pressure on one side of the metal sealing element \n32\n access to the interior \n40\n of the metal sealing element \n32\n.', 'The higher pressure provides additional expansion pressure for biasing the metal sealing element \n32\n into a more secure sealing engagement with the surrounding wall surface \n36\n.', 'In this manner, the valve system \n42\n enables the expandable metal packer \n24\n to hold a sealed engagement with the surrounding wall surface \n36\n against higher pressure differentials.', 'The valve system \n42\n also may be constructed to enable this annulus pressure compensation without detrimental sensitivity to thermal variations.', 'In some embodiments, the expandable metal packer \n24\n comprises an expansion valve \n52\n which is positioned to control flow of the pressurized fluid from the interior \n38\n of tubing \n26\n to the interior \n40\n of metal sealing element \n32\n during setting of packer \n24\n.', 'The expansion valve \n52\n may be positioned in fluid communication with the passage or passages \n41\n along, for example, an exterior of tubing \n26\n.', 'In some embodiments, the expansion valve \n52\n also may be operable to close off flow through the passage(s) \n41\n and to open a flow path between the annulus \n46\n and the interior \n40\n of metal sealing element \n32\n.', 'Referring generally to \nFIG.', '2\n, an embodiment of the expandable metal packer \n24\n is illustrated.', 'In this example, the metal sealing element \n32\n is illustrated in a radially contracted position prior to setting of expandable metal packer \n24\n.', 'This radially contracted position may be used as a run-in-hole position which allows the expandable metal packer \n24\n and tubing string \n28\n to be run downhole to a desired position along borehole \n22\n.', 'In the embodiment illustrated, valve system \n42\n comprises at least one valve \n44\n on one axial side of metal sealing element \n32\n and at least one valve \n44\n on the opposite side of metal sealing element \n32\n.', 'It should be noted that some applications may utilize a plurality of the valves \n44\n located on each axial side of metal sealing element \n32\n.', 'By way of example, each valve \n44\n may be a shiftable valve having a piston \n54\n slidably mounted in a piston housing \n56\n.', 'Depending on the parameters of a given application, each piston housing \n56\n may comprise a plurality of ports \n58\n to enable fluid communication with various regions.', 'For example, each piston housing \n56\n may be ported to communicate with interior \n40\n of metal sealing element \n32\n; to communicate with annulus \n46\n on a side of the metal sealing element \n32\n common with that piston housing \n56\n; and to communicate with annulus \n46\n on an opposite side of the metal sealing element \n32\n.', 'In other words, each valve \n44\n may be ported to interior \n40\n of metal sealing element \n32\n and to both first annulus section \n48\n and second annulus section \n50\n of the annulus \n46\n.', 'Communication between the ports \n58\n and the corresponding pressure regions may be accomplished via suitable flow conduits.', 'By way of example, each valve \n44\n may comprise a port \n58\na \ncoupled with an outlet fluid conduit \n60\n in communication with interior \n40\n.', 'Additionally, each valve \n44\n may comprise a separate port \n58\nb \ncoupled with an inlet fluid conduit \n62\n in communication with annulus \n46\n on the common side of metal sealing element \n32\n.', 'Each valve \n44\n also may comprise a port \n58\nc \nin communication with annulus \n46\n on an opposite side of the metal sealing element \n32\n via a crossover fluid conduit \n64\n.', 'According to an embodiment, the ports \n58\nc \nand corresponding crossover fluid conduits \n64\n may be constructed to reduce the amount of fluid which circulates through the crossover fluid conduit \n64\n.', 'In this example, the amount of fluid flowing through port \n58\nc \nof each valve \n44\n can be a relatively small amount sufficient for sliding of the corresponding piston \n54\n.', 'In a variety of packer applications, very little space is available for crossover fluid conduits \n64\n and therefore such conduits may be constructed from small-diameter pipes (e.g. pipes with diameters ranging from 0.05 to 0.2 inches) or other suitably small conduits.', 'To avoid plugging of the small crossover fluid conduits \n64\n with dirty well fluid, the crossover fluid conduits and the corresponding valve chambers within piston housing \n56\n may initially be filled with a clean fluid \n65\n, e.g. a clean oil.', 'In some applications, the clean fluid \n65\n may be contained in crossover fluid conduits \n64\n via a suitable containment mechanism, such as an elastic membrane.', 'The elastic membrane or other containment mechanism serves to contain the clean fluid \n65\n within the conduit \n64\n while enabling communication of annulus pressure from the opposite side of metal sealing element \n32\n.', 'As illustrated, each piston \n54\n may be biased toward a default position by a spring \n66\n.', 'Each spring \n66\n may be positioned within piston housing \n56\n between a given piston surface and an interior piston housing surface.', 'Each piston \n54\n also may comprise a seal or a plurality of seals \n68\n such as O-ring seals or other suitable seals.', 'The appropriate seals \n68\n are positioned around the corresponding piston \n54\n for sealing and sliding engagement with an interior surface of the corresponding piston housing \n56\n.', 'Additionally, each piston \n54\n may comprise surface areas acted on by fluid pressure.', 'For example, each piston \n54\n may comprise a larger diameter portion having relatively larger surface areas \n70\n and a smaller diameter portion having a relatively smaller surface area \n72\n.', 'It should be noted the surface areas \n70\n, \n72\n are effectively established by the diameters of the corresponding seals \n68\n disposed about the relatively smaller and larger diameter portions of the piston \n54\n.', 'In the example illustrated, the relatively smaller surface area \n72\n is exposed to pressures at inlet fluid conduit \n62\n.', 'The relatively larger surface areas \n70\n (on opposite sides of the larger diameter portion of each piston \n54\n) are exposed to pressures at outlet fluid conduit \n60\n and crossover fluid conduit \n64\n, respectively.', 'Thus, each piston \n54\n has surface areas acted on by pressures from opposite sides of the metal sealing element \n32\n.', 'The different surface areas \n70\n, \n72\n enable actuation of one or both valves according to pressure differentials in the annulus on opposite sides of the metal sealing element, as described in greater detail below.', 'In some embodiments, different valves \n44\n may have pistons \n54\n with different surface areas relative to the pistons \n54\n of other valves \n44\n so as to enable a desired automatic shifting of specific valves \n44\n when exposed to certain pressure differentials.', 'The arrangement and configuration of valves \n44\n allows valve system \n42\n to function automatically as a differential pressure valve system.', 'According to an embodiment, the valve \n44\n on the side of metal sealing element \n32\n corresponding with first annulus section \n48\n may have spring \n66\n positioned to act against the relatively larger surface area \n70\n of piston \n54\n, as illustrated.', 'The valve \n44\n on the other side of metal sealing element \n32\n corresponding with second annulus section \n50\n may have spring \n66\n positioned to act against the relatively smaller surface area \n72\n of piston \n54\n.', 'The surface areas \n70\n, \n72\n as well as the springs \n66\n are selected so the valve(s) \n44\n on each side of metal sealing element \n32\n open or close off flow through the corresponding outlet conduits \n60\n at predetermined pressure differentials.', 'In the example illustrated, the valve \n44\n on the side of first annulus section \n48\n has a spring \n66\n rated to open for flow through outlet conduit \n60\n when the pressure acting on the opposite valve \n44\n is greater (e.g. the spring \n66\n is rated to open when P\nValve2\n>P\nValve1\n).', 'In this example, the valve on the side of second annulus section \n50\n has a spring \n66\n rated to close off flow through the corresponding outlet conduit \n60\n when the pressure acting on the opposite valve \n44\n equals the pressure in first annulus section \n48\n minus the pressure in second annulus section \n50\n (e.g. the spring is rated to open when P\nValve1\n=P\nAnnulus1\n−P\nAnnulus2 \nin the range 100-500 psi).', 'As illustrated in \nFIG.', '3\n, the metal sealing element \n32\n may be expanded radially into sealing engagement with the surrounding wall surface \n36\n at a desired location along borehole \n22\n.', 'Once the metal sealing element \n32\n is sufficiently expanded, the expandable metal packer \n24\n is considered set and the annulus sections \n48\n, \n50\n are isolated from each other along the overall annulus \n46\n.', 'In various embodiments, the metal sealing element \n32\n is plastically deformed when expanded radially to the set position.', 'According to the embodiment illustrated, the metal sealing element \n32\n is expanded radially to the set position via a pressurized fluid \n74\n.', 'The pressurized fluid \n74\n may be directed through the interior \n38\n of tubing \n26\n to passage(s) \n41\n.', 'At this stage, the expansion valve \n52\n allows the pressurized fluid \n74\n to travel out of tubing \n26\n through passage(s) \n41\n, through the expansion valve \n52\n, through inlet conduit \n62\n, and into the corresponding valve \n44\n.', 'The corresponding spring \n66\n and the pressure of fluid \n74\n ensure the corresponding piston \n54\n is held in an open flow position as illustrated in \nFIG.', '3\n.', 'The open flow position allows the pressurized fluid \n74\n to flow through the corresponding valve \n44\n, into outlet conduit \n60\n, and then into interior \n40\n of metal sealing element \n32\n.', 'As the pressurized fluid \n74\n continues to flow into interior \n40\n the metal sealing element \n32\n is forced to expand outwardly and into sealing engagement with the surrounding wall surface \n36\n, e.g. into a casing surface or open borehole surface.', 'After the metal sealing element \n32\n is set against the surrounding wall surface \n36\n, the expansion valve \n52\n is actuated to close off flow through passage(s) \n41\n and to open communication with the second annulus section \n50\n of annulus \n46\n, as illustrated in \nFIG.', '4\n.', 'By way of example, the expansion valve \n52\n may be constructed to close passage \n41\n at a preset pressure while simultaneously opening fluid communication with second annulus section \n50\n of annulus \n46\n.', 'An example of a pressure actuated valve that may be utilized as an expansion valve is described in US patent publication 2006/042801A1.', 'However, expansion valve \n52\n also may be in the form of an electrically actuated valve or other suitable valve which may be controlled to selectively block flow from the interior \n38\n of tubing \n26\n and to selectively open communication between valve system \n42\n and the annulus.', 'Differential pressures in annulus \n46\n automatically shift valve system \n42\n to different operational positions to enable the expandable metal packer \n24\n to hold against high differential pressures once expansion valve \n52\n operates to close off communication through passage(s) \n41\n.', 'In some embodiments, the valve system \n42\n also may function to enable the expandable metal packer to hold against high differential pressures without detrimental sensitivity to thermal variations acting on the packer \n24\n.', 'When a pressure differential occurs in annulus \n46\n and has a relatively higher pressure in the second annulus section \n50\n relative to the first annulus section \n48\n, the valve system \n42\n automatically shifts to the operational position illustrated in \nFIG.', '5\n.', 'In this situation, the higher pressure in second annulus section \n50\n acts on the corresponding valve \n44\n via inlet conduit \n62\n and holds the piston \n54\n/valve \n44\n in an open flow position.', 'This allows the high-pressure fluid to flow through the common side valve \n44\n, through the corresponding outlet conduit \n60\n, and into interior \n40\n of metal sealing element \n32\n.', 'The high-pressure fluid also communicates with the valve \n44\n on an opposite side of the metal sealing element \n32\n via the corresponding crossover passageway \n64\n to hold the opposite valve in a closed position as illustrated.', 'Consequently, the higher pressure acting in second annulus section \n50\n is directed to interior \n40\n to help ensure the metal sealing element \n32\n remains sealed against the surrounding wall surface \n36\n while experiencing the pressure differential.', '(It should be noted expansion valve \n52\n and the corresponding passage \n41\n have not been shown in \nFIGS.', '5-7\n.)', 'It should be noted that if the pressure differential is within a predetermined range, the valve system \n42\n may tend to maintain the valves \n44\n in a closed position on both axial sides of metal sealing element \n32\n, as illustrated in \nFIG.', '6\n.', 'The springs \n66\n and the piston surface areas \n70\n, \n72\n may cause the pistons \n54\n on both sides of metal sealing element \n32\n to remain in the closed position over a certain range of differential pressures.', 'For the purpose of providing an example, if the pressure P in first annulus section \n48\n is within a predetermined range relative to the pressure in second annulus section \n50\n, this pressure P is insufficient to move the piston \n54\n of the common side valve \n44\n against the force of the corresponding spring \n66\n.', 'This same pressure P is able to act against the larger surface area \n70\n of the piston \n54\n in the valve \n44\n on an opposite side of the metal sealing element \n32\n via the corresponding crossover conduit \n64\n.', 'The biasing force of the spring \n66\n in the opposite side valve \n44\n is overcome and the corresponding piston \n54\n is shifted to a closed flow position, as illustrated on the right side of \nFIG.', '6\n.', 'However, the valve system \n42\n may be constructed as illustrated to maintain specific valves \n44\n in desired closed or open positions and this ability can be used to render the valve system \n42\n and expandable metal packer \n24\n insensitive to thermal variations.', 'For temperature insensitivity, for example, the diameters established by seals \n68\n may be varied slightly to create “instability”.', 'The instability is useful to reduce the potential for the piston \n54\n to become stuck in an undesirable position, e.g. between two ports \n58\n.', 'For example, the diameters may be selected so the position of pistons \n54\n illustrated in \nFIG.', '6\n is possible for one scenario of annulus pressures and packer internal pressure (pressure in interior \n40\n).', 'Consequently, a variation in the packer internal pressure causes at least one of the pistons \n54\n to slide in a desired direction.', 'The variation in pressure within interior \n40\n may be due to thermal effects such as a build-up of pressure due to a thermal cycle.', 'The change in packer internal pressure due to such thermal effects may thus be used to automatically shift the desired piston or pistons \n54\n so as to limit the sensitivity of the system to those thermal variations.', 'Referring generally to \nFIG.', '7\n, if the pressure in first annulus section \n48\n becomes sufficiently greater than the pressure in second annulus section \n50\n this relatively high pressure in first annulus section \n48\n is able to automatically transition valve system \n42\n as illustrated.', 'In this situation, the relatively higher pressure in first annulus section \n48\n is able to shift the piston \n54\n of the common side valve \n44\n against the bias of the corresponding spring \n66\n as illustrated on the left side of \nFIG.', '7\n.', 'The higher pressure fluid in first annulus section \n48\n is thus able to flow through the common side valve \n44\n, through the corresponding outlet conduit \n60\n, and into interior \n40\n of metal sealing element \n32\n.', 'The relatively higher pressure fluid also communicates with the valve \n44\n on an opposite side of the metal sealing element \n32\n via the corresponding crossover passageway \n64\n.', 'The pressure communicated through crossover passageway \n64\n is sufficient to hold the opposite valve \n44\n in a closed position as illustrated on the right side of \nFIG.', '7\n.', 'Consequently, the higher pressure acting in first annulus section \n48\n is directed to interior \n40\n to help ensure the metal sealing element \n32\n remains sealed against the surrounding wall surface \n36\n while experiencing the pressure differential.', 'Effectively, the valve system \n42\n may be used for automatically changing pressure within the metal sealing element \n32\n via the differential pressure valve system \n42\n according to the level of the pressure differential and according to the direction of the pressure differential (higher pressure in annulus section \n48\n or in annulus section \n50\n).', 'In some embodiments, the expandable metal sealing element \n32\n may be combined with additional sealing elements \n76\n such as those illustrated via dashed lines in \nFIG.', '7\n.', 'By way of example, the expandable metal sealing element \n32\n may comprise an expandable metal bladder combined with a plurality of additional sealing elements \n76\n.', 'The additional sealing elements \n76\n may be formed from an elastomeric material or other suitable material to facilitate sealing engagement with the surrounding wall surface \n36\n, e.g. surrounding casing surface or open wellbore surface, when the expandable metal packer \n24\n is set.', 'Examples of the additional sealing elements \n76\n include bonded rubber seals, sections of rubber mounted to metal sealing element \n32\n, O-ring seals, or other suitable seals.', 'The sealing elements/seals \n76\n may be mounted in corresponding grooves \n78\n formed in or around the metal sealing element \n32\n.', 'In some embodiments, the sealing elements \n76\n may comprise back-up rings combined with the elastomeric seals to provide better resistance with respect to extrusion.', 'The valve system \n42\n enables use of expandable metal packer \n24\n as an isolation device in a variety of operations and environments which may be subjected to high differential pressures.', 'For example, the expandable metal packer \n24\n may be used in well applications and in other applications in which isolation between sections of a tubular structure is desired.', 'The expandable metal packer \n24\n may be constructed with various types and sizes of metal sealing elements \n32\n depending on the parameters of a given operation.', 'In a variety of well applications, the metal sealing element \n32\n may be formed from a plastically deformable metal membrane, bladder, or other metal structure which may be radially expanded via fluid pressure.', 'Similarly, the valve system \n42\n may utilize single valves \n44\n or plural valves \n44\n on each axial side of metal sealing element \n32\n.', 'The structure of each valve \n44\n may be selected according to the parameters of a given use and/or environment.', 'For example, the valves \n44\n may comprise various types of pistons, seals, springs, piston housings, and/or other components.', 'The relative surface areas provided by the piston/seals may be selected according to the anticipated pressures and the desired operation of the overall valve system \n42\n.', 'The overall tubing string \n28\n also may utilize many types of components and have various configurations suited for the operation and environment in which it is utilized.', 'Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.'] | ['1.', 'A system for use in a well, comprising:\na tubing;\nan expandable metal packer mounted along the tubing, the expandable metal packer having a metal sealing element which may be expanded radially outwardly into sealing engagement with a surrounding wall surface;\nan expansion valve positioned to control flow of a pressurized fluid from an interior of the tubing to an interior of the metal sealing element to enable expansion of the metal sealing element into the sealing engagement with the surrounding wall surface; and\na differential pressure valve system comprising a plurality of shiftable valves which automatically respond to pressure differentials occurring between opposite axial sides of the metal sealing element in an annulus between the tubing and the surrounding wall surface, the plurality of shiftable valves automatically shifting to allow the relatively higher pressure of the pressure differential access to the interior of the metal sealing element to enable the metal sealing element to hold against the differential pressure.', '2.', 'The system as recited in claim 1, wherein the expansion valve is shiftable to block communication between the interior of the tubing and the interior of the metal sealing element.', '3.', 'The system as recited in claim 2, wherein the expansion valve opens communication with the annulus upon blocking communication between the interior of the tubing and the interior of the metal sealing element.', '4.', 'The system as recited in claim 1, wherein the a plurality of shiftable valves comprises a first shiftable valve located in the annulus on a first axial side of the metal sealing element and a second shiftable valve located in the annulus on a second axial side of the metal sealing element.', '5.', 'The system as recited in claim 4, wherein each shiftable valve comprises a piston slidably mounted in a piston housing and biased toward a default position via a spring.', '6.', 'The system as recited in claim 5, wherein the piston housing of each shiftable valve is ported to the interior of the metal seal element; to the annulus on a side of the metal sealing element common with the piston housing; and to the annulus on an opposite side of the metal sealing element via a crossover fluid conduit filled with a clean fluid.', '7.', 'The system as recited in claim 6, wherein the first shiftable valve automatically shifts to a closed position blocking flow into the metal sealing element and the second shiftable valve automatically shifts to an open position allowing flow into the metal sealing element upon the occurrence of a pressure differential with a sufficiently higher pressure in the annulus on the side of the second valve compared to the pressure in the annulus on an opposite side of the metal sealing element.', '8.', 'The system as recited in claim 7, wherein the second shiftable valve automatically shifts to a closed position blocking flow into the metal sealing element and the first shiftable valve automatically shifts to an open position allowing flow into the metal sealing element upon the occurrence of a pressure differential with a sufficiently higher pressure in the annulus on the side of the first valve compared to the pressure in the annulus on an opposite side of the metal sealing element.', '9.', 'The system as recited in claim 8, wherein the first shiftable valve and the second shiftable valve are both shifted to a closed position during a predetermined differential pressure range with respect to pressures in the annulus on opposite sides of the metal sealing element.', '10.', 'A system, comprising: an expandable metal packer having a metal sealing element which is radially expandable by fluid entering an interior of the metal sealing element under pressure; and\na valve system in communication with the metal sealing element to enable an increase in pressure in the interior of the metal sealing element when sufficient pressure differentials act on the metal sealing element after radial expansion of the metal sealing element, the valve system comprising a pair of valves, each valve being in fluid communication with the interior of the metal sealing element and with annulus regions on both sides of the metal sealing element.', '11.', 'The system as recited in claim 10, further comprising a tubing, the metal sealing element being positioned around the tubing.', '12.', 'The system as recited in claim 11, further comprising an expansion valve positioned to control flow of a pressurized fluid from an interior of the tubing to the interior of the metal sealing element to enable expansion of the metal sealing element into sealing engagement with a surrounding wall surface.', '13.', 'The system as recited in claim 11, wherein the pair of valves comprises valves positioned on opposite axial sides of the metal sealing element.', '14.', 'The system as recited in claim 11, wherein the metal sealing element is constructed to permanently deform into sealing engagement with a surrounding wall surface when radially expanded, the metal sealing element being combined with additional sealing elements to ensure isolation of sections of an annulus between the tubing and the surrounding wall surface.', '15.', 'The system as recited in claim 14, wherein each valve of the pair of valves comprises a piston slidably mounted in a piston housing.', '16.', 'The system as recited in claim 15, wherein each piston has surface areas acted on by pressures from opposite sides of the metal sealing element, the surface areas having different sizes selected to enable actuation of one or both valves according to the pressure differential in the annulus between opposite sides of the metal sealing element.', '17.', 'A method, comprising:\nproviding a packer with a tubing, a metal sealing element mounted around the tubing, and a differential pressure valve system;\nmoving the packer downhole into a borehole;\nsetting the packer by expanding the metal sealing element via a fluid under pressure until the metal sealing element seals against a surrounding wall surface, and delivering the fluid under pressure through an interior of the tubing;\nautomatically changing pressure within the metal sealing element via the differential pressure valve system according to a direction and level of a pressure differential occurring in an annulus between the tubing and the surrounding wall surface;\nusing the differential pressure valve system to automatically compensate for thermal effects acting on the packer; and\nusing an expansion valve to control flow of the fluid under pressure from the interior of the tubing to an interior of the metal sealing element;\nwherein providing comprises providing the differential pressure valve system with a plurality of shiftable valves comprising a first shiftable valve located in the annulus on a first axial side of the metal sealing element and a second shiftable valve located in the annulus on a second axial side of the metal sealing element, each shiftable valve comprising a piston slidably mounted in a piston housing and biased toward a default position via a spring, each piston housing being ported to: the interior of the metal sealing element; the annulus on a side of the metal sealing element common with the piston housing; and the annulus on an opposite side of the metal sealing element via a crossover fluid conduit initially filled with a clean fluid.'] | ['FIG.', '1 is a cross-sectional illustration of an example of an expandable metal packer mounted along a tubing string in a borehole, according to an embodiment of the disclosure;; FIG.', '2 is a schematic illustration of an example of an expandable metal packer positioned along a tubing, according to an embodiment of the disclosure;; FIG.', '3 is a schematic illustration similar to that of FIG.', '2', 'but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure;', '; FIG. 4 is a schematic illustration similar to that of FIG.', '2', 'but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure;', '; FIG. 5 is a schematic illustration similar to that of FIG.', '2', 'but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure;', '; FIG.', '6 is a schematic illustration similar to that of FIG.', '2', 'but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure; and; FIG. 7 is a schematic illustration similar to that of FIG.', '2', 'but showing the expandable metal packer in a different operational position, according to an embodiment of the disclosure.'] |
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US11099168 | Methods and apparatus for water detection in multiphase flows | Jul 23, 2018 | Cheng-Gang Xie, Massimiliano Fiore | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in the related PCT Application PCT/US2019/042800 dated Oct. 24, 2019 (7 pages).; Kjetil Folgerø, Andreas Linge Tomren, Stig Frøyen, Permittivity calculator. Method and tool for calculating the permittivity of oils from PVT data, 30th International North Sea Flow Measurement Workshop Oct. 23-26, 2012 (15 pages). | 5736637; April 7, 1998; Evans; 5854820; December 29, 1998; Slijkerman et al.; 6831470; December 14, 2004; Xie et al.; 7469188; December 23, 2008; Wee; 7503227; March 17, 2009; Davis; 7631543; December 15, 2009; Wee; 8076950; December 13, 2011; Wee; 8224588; July 17, 2012; Wee; 8522534; September 3, 2013; Yoshida et al.; 8536883; September 17, 2013; Xie et al.; 8570050; October 29, 2013; Nyfors; 8686745; April 1, 2014; Kirkaune; 9528869; December 27, 2016; Xie et al.; 9588071; March 7, 2017; Nyfors; 9638556; May 2, 2017; Xie et al.; 9645130; May 9, 2017; Xie et al.; 20070151806; July 5, 2007; Boyle; 20080319685; December 25, 2008; Xie et al.; 20100064820; March 18, 2010; David; 20110291845; December 1, 2011; Rice; 20130110411; May 2, 2013; Black et al.; 20130144548; June 6, 2013; Xie; 20130327154; December 12, 2013; Xie et al.; 20140331783; November 13, 2014; Xie; 20150346117; December 3, 2015; Nyfors; 20160131601; May 12, 2016; Sharma; 20170160069; June 8, 2017; Folgero; 20180364083; December 20, 2018; Janssens | 2008030912; March 2008; WO; 2009101392; August 2009; WO; WO2015185450; December 2015; WO; 2018160927; September 2018; WO | ['Methods and apparatus for detecting water in multiphase flows are disclosed.', 'An example apparatus includes a conduit including an inlet to receive a multiphase flow and an electromagnetic sensor coupled to a liquid-rich region of the conduit to measure a permittivity of the multiphase flow, and a water detection manager to determine that water is detected in the multiphase flow based on the permittivity.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates generally to hydrocarbon production and, more particularly, to methods and apparatus for water detection in multiphase flows.', 'DESCRIPTION OF THE RELATED ART\n \nMost oil-gas wells produce a mixture of oil, water, and gas.', 'During hydrocarbon production, a determination of flow rates of individual phases (e.g., oil, gas, water, etc.) of a multiphase flow is desirable.', 'The individual phase flow rates can be derived from the measured phase volume fractions and phase flow velocities.', 'A determination of other properties of the multiphase mixture is also desirable, including the presence and salinity of produced water or injected water.', 'Such properties can be used to determine information about the mixture and may affect other measurements being made on the multiphase mixture.', 'SUMMARY\n \nCertain aspects of some embodiments disclosed herein are set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms the invention might take and that these aspects are not intended to limit the scope of the invention.', 'Indeed, the invention may encompass a variety of aspects that may not be set forth below.', 'An example apparatus includes a conduit including an inlet to receive a multiphase flow and an electromagnetic sensor coupled to a liquid-rich region of the conduit to measure a permittivity of the multiphase flow, and a water detection manager to determine that water is detected in the multiphase flow based on the permittivity.', 'An example method includes determining a first permittivity and a second permittivity of a multiphase flow based on electromagnetic data obtained from an electromagnetic sensor, comparing a difference between the first permittivity and the second permittivity to a water detection threshold, and in response to the difference satisfying the water detection threshold, generating an alert indicating that water is detected in the multiphase flow.', 'An example non-transitory computer readable storage medium comprising instructions which, when executed, causes a machine to at least determine a first permittivity and a second permittivity of a multiphase flow based on electromagnetic data obtained from an electromagnetic sensor, compare a difference between the first permittivity and the second permittivity to a water detection threshold, and generate an alert indicating that water is detected in the multiphase flow when the difference satisfies the water detection threshold.', 'Various refinements of the features noted above may exist in relation to various aspects of the present embodiments.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'Again, the brief summary presented above is intended just to familiarize the reader with certain aspects and contexts of some embodiments without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n illustrates an example multiphase flow measurement system including an example water detection manager apparatus for determining liquid properties of a multiphase flow.\n \nFIG.', '2\n depicts an example table including example parameters associated with a multiphase flow.\n \nFIG.', '3\n is a block diagram of an example implementation of the example multiphase flow measurement system of \nFIG.', '1\n including the example water detection manager apparatus of \nFIG.', '1\n.', 'FIG.', '4\n depicts an example graph generated by the example water detection manager apparatus of \nFIGS.', '1 and/or 3\n to implement the examples disclosed herein.', 'FIG.', '5\n depicts example machine readable instructions that may be executed to implement the example water detection manager apparatus of \nFIGS.', '1 and/or 3\n that may be used to implement the examples disclosed herein.', 'FIG.', '6\n is a flowchart representative of machine readable instructions that may be executed to implement the example water detection manager apparatus of \nFIGS.', '1 and/or 3\n.\n \nFIG.', '7\n is a block diagram of an example processing platform structured to execute the instructions of \nFIGS.', '5 and/or 6\n to implement the example water detection manager apparatus of \nFIGS.', '1 and/or 3\n.', 'The figures are not to scale.', 'Wherever possible, the same reference numbers will be used throughout the drawing(s) and accompanying written description to refer to the same or like parts.', 'DETAILED DESCRIPTION', 'It is to be understood that the present disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below for purposes of explanation and to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'When introducing elements of various embodiments, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Moreover, any use of “top,” “bottom,” “above,” “below,” other directional terms, and variations of these terms is made for convenience, but does not mandate any particular orientation of the components.', 'Most oil-gas wells produce oil, gas, and water from an earth formation.', 'For example, a flow of fluid including oil, gas, and water is considered a three-phase flow, or a multiphase flow or multiphase mixture.', 'In such examples, the three-phase flow includes one gas phase corresponding to the gas component of the flow and two liquid phases corresponding to the oil and water components of the flow.', 'It is desirable during an oilfield operation (e.g., well test operation, an oil and/or gas production operation, etc.) to perform flow measurements to determine the flow rates of individual phases of the multiphase flow.', 'In particular, measurement of the volume fractions and flow velocities of for example, oil, gas, and water in a conduit, such as a pipe, is highly desirable.', 'It is also desirable to determine properties of the multiphase mixture, such as the presence and salinity of water in the mixture, as this provides information about the mixture and may affect other measurements being made on the multiphase mixture.', 'In general, a determination of properties of a multiphase flow can be difficult due to a wide variety of flow regimes the multiphase flow can exhibit.', 'For example, three phases of a multiphase flow can be mixed together with one phase as the continuous phase and the remaining two phases dispersed within the multiphase flow.', 'Primarily, there is phase separation between gas and liquid with the liquid often moving at a much lower velocity than the gas.', 'Additionally, flow phase and velocity distributions of a multiphase flow may alter both spatially and temporally.', 'Sudden or gradual variation in flow rates of one phase or another may cause a change in flow regime.', 'Also, due to the high pressure encountered deep underground or below seabed, a flow that is mixed or in bubble-flow regime can become dominated by a discernible high gas fraction as the pressure drops nearer the ground or subsea surface and the gas expands and/or comes out of solution.', 'Prior implementations to measure multiphase flows used multiphase flowmeters and sensors to determine properties of the multiphase flows.', 'In some prior implementations, the multiphase flowmeters included electromagnetic (EM) sensors such as radiofrequency (RF) and/or microwave sensors, electrical (e.g., capacitance, conductance) impedance sensors, to measure some of the properties including a permittivity and/or a conductivity of the multiphase flow through a conduit (e.g., a pipe).', 'In such implementations, the multiphase flowmeter measured the permittivity and/or the conductivity at liquid-rich region(s) of the conduit (e.g., in the underside of a horizontal blind-tee section, in a near-wall region (e.g., a near inner-wall region) of a vertical pipe section).', 'The multiphase flowmeter typically determined properties of the liquid phase of the multiphase flow including water conductivity (salinity).', 'However, these prior implementations did not teach the determination a presence of water in the multiphase flow or in a wet-gas flow stream.', 'Examples disclosed herein include water detection manager apparatus to detect a presence of water in a multiphase flow and/or a wet-gas flow stream.', 'In some disclosed examples, the water detection manager apparatus detects the presence of water by determining a mixture permittivity and/or a mixture conductivity of the multiphase flow.', 'In some disclosed examples, the water detection manager apparatus determines the mixture permittivity and/or the mixture conductivity by obtaining measurements from one or more EM sensors at a high data acquisition rate (e.g., 5 kilohertz (kHz) measurement rate, 10 kHz measurement rate, etc.).', 'In some disclosed examples, the one or more EM sensors include an RF/microwave open-coaxial probe (e.g., a microwave frequency open-coaxial reflection probe), an RF/microwave local transmission measurement sensor, etc.', 'In some disclosed examples, one or more probes are installed at a liquid-rich region of a horizontal blind-tee end-flange, or at a vertical pipe near wall region, or at a vertical pipe end-flange to obtain the sensor measurements.', 'Example water detection manager apparatus disclosed herein can detect the presence of water in either horizontal or vertical conduits.', 'For flow-assurance purposes, detecting the presence of water in multiphase flows is important for oilfield operations (e.g., providing an alert of the risk of the formation of hydrates in the flow line) when a flow-stream water-to-liquid ratio (WLR) is very low and/or a gas volume fraction (GVF) is very high.', 'In some disclosed examples, the water detection manager apparatus can set a WLR measured by a multiphase flowmeter (e.g., a dual-energy gamma-ray based multiphase flowmeter (MPFM)) to zero to avoid and/or otherwise prevent reporting of non-physical (e.g., negative) time-averaged WLR values and, thus, improve an accuracy or a confidence in flow rate measurements of oil and gas phases in a multiphase flow.\n \nFIG.', '1\n illustrates an example multiphase flow measurement system \n100\n including an example water detection manager \n102\n to determine liquid properties of a multiphase flow \n104\n.', 'In \nFIG.', '1\n, the multiphase flow measurement system \n100\n includes an example blind tee \n106\n.', 'The blind tee \n106\n of \nFIG.', '1\n includes an example inlet \n108\n, a first example conduit \n110\n, an example outlet \n112\n, an example end (flange) section \n114\n, and a second example conduit \n116\n.', 'In \nFIG.', '1\n, the first conduit \n110\n is a horizontal blind tee conduit and the second conduit \n116\n is a vertical blind tee conduit.', 'At the downstream of the outlet \n112\n, a multiphase flowmeter may be installed (not shown in \nFIG.', '1\n).', 'In operation, the multiphase flow \n104\n enters the blind tee \n106\n through the inlet \n108\n, travels along the first conduit \n110\n, through the second conduit \n116\n, and out through the outlet \n112\n.', 'The end section \n114\n operates as a barrier that forces the movement of the multiphase flow \n104\n into the second conduit \n116\n.', 'In general, the blind tee \n106\n is configured so that the first conduit \n110\n is approximately horizontal and the second conduit \n116\n is approximately vertical.', 'In some examples, the horizontal orientation of the first conduit \n110\n enables an example bottom section \n118\n of the first conduit \n110\n to be liquid rich and an example upper section \n120\n of the first conduit \n110\n to be gas rich.', 'Alternatively, the flow in the second conduit \n116\n may not flow vertically upward, but may be arranged to flow vertically downward, or at another angle relative to the first conduit \n110\n.', 'In some examples, the bottom section \n118\n of the first conduit \n110\n includes liquid rich regions even in multiphase flows with high gas-to-liquid ratios (e.g., wet gas with gas volume fraction (GVF) >95%).', 'In some examples, liquid rich regions can be produced in the blind tee \n106\n proximate the end section \n114\n and/or beneath an example opening \n122\n of the second conduit \n116\n.', 'In some examples, the first conduit \n110\n can be about 5 meters or less in length (e.g., 0.5 meters, 1.5 meters, 2.5 meters, etc.).', 'Alternatively, the first conduit \n110\n may be more than 5 meters in length.', 'In some examples, more pronounced liquid rich regions can be produced when the end section \n114\n and the opening \n122\n are separated by a section of the first conduit \n110\n, as illustrated in \nFIG.', '1\n.', 'In the illustrated example of \nFIG.', '1\n, a first example electromagnetic (EM) sensor \n124\n or a second example EM sensor \n126\n is disposed below a central axis \n128\n of the first conduit \n110\n.', 'In \nFIG.', '1\n, the EM sensor(s) \n124\n, \n126\n are coupled to the water detection manager \n102\n.', 'Alternatively, the EM sensor(s) \n124\n, \n126\n may be disposed above the central axis \n128\n.', 'In \nFIG.', '1\n, the first EM sensor \n124\n is coupled to the first conduit \n110\n and is disposed in the bottom section \n118\n directly below the opening \n122\n.', 'In \nFIG.', '1\n, the second EM sensor \n126\n is coupled to the end section \n114\n of the first conduit \n110\n and is disposed in the bottom section \n118\n.', 'Additionally or alternatively, one or more of the EM sensors \n124\n, \n126\n may be disposed on the underside of the first conduit \n110\n, in the bottom section \n118\n, and/or coupled with the end section \n114\n below the central axis \n128\n.', 'Additionally or alternatively, EM sensor(s) \n124\n, \n126\n may be installed at the liquid-rich region of a vertical pipe end flange, or at the near inner-wall liquid-rich region of a vertical pipe section.', 'In the illustrated example of \nFIG.', '1\n, the water detection manager \n102\n can determine properties of the liquid phase (e.g., water conductivity/salinity, water volume fraction, WLR, etc.) of the multiphase flow \n104\n based on the positioning of the EM sensor(s) \n124\n, \n126\n in the blind tee \n106\n as depicted in \nFIG.', '1\n and/or in other examples as described above.', 'In some examples, the water detection manager \n102\n can determine the properties of the gas phase (e.g., permittivity change with pressure and/or temperature) of the multiphase flow \n104\n based on alternative positions of the EM sensor(s) \n124\n, \n126\n or in combination with additional EM sensor(s) coupled to the blind tee \n106\n.', 'For example, the water detection manager \n102\n can determine the gas phase properties based on one or more of the EM sensors \n124\n, \n126\n being disposed on the topside of the first conduit \n110\n, in the upper section \n120\n above the central axis \n128\n, near the inlet \n108\n, etc.', 'In other examples, in addition to the EM sensor(s) \n124\n, \n126\n, additional EM sensor(s) can be disposed on the topside of the first conduit \n110\n, in the upper section \n120\n above the central axis \n128\n, near the inlet \n108\n, etc.', 'In \nFIG.', '1\n, the water detection manager \n102\n determines the properties of the liquid phase of the multiphase flow \n104\n that is present in a shallow measurement zone (e.g., about 2 millimeters (mm) depth of investigation) of the EM sensor(s) \n124\n, \n126\n, by obtaining sensor measurements from the EM sensor(s) \n124\n, \n126\n.', 'In \nFIG.', '1\n, the EM sensor(s) \n124\n, \n126\n are RF/microwave frequency open-coaxial (reflection) probes (e.g., substantially similar to sensors described in U.S. Pat.', 'No. 9,638,556, entitled “COMPACT MICROWAVE WATER-CONDUCTIVITY PROBE WITH INTEGRAL SECOND PRESSURE BARRIER,” filed Dec. 16, 2015, which is incorporated by reference herein in its entirety).', 'Alternatively, the EM sensor(s) \n124\n, \n126\n may be RF/microwave-based magnetic-dipole antennas, RF/microwave local transmission measurement antennas, RF/microwave local resonance measurement antennas, millimeter-wave sensors, or electrical impedance (e.g., capacitance, conductance, etc.)', 'measurement electrodes or probes (e.g., an electrical impedance local measurement sensor).', 'In the illustrated example of \nFIG.', '1\n, the EM sensor(s) \n124\n, \n126\n measure, at one or more chosen measurement frequencies, one or more properties of the multiphase flow \n104\n.', 'For example, the EM sensor(s) \n124\n, \n126\n can perform sensor measurements (e.g. reflection measurements of amplitude-attenuation and phase-shift of the reflected RF signals relative to those of the incident signals) of the multiphase flow \n104\n and generate electromagnetic data based on the sensor measurements.', 'The water detection manager \n102\n can obtain the electromagnetic data from the EM sensor(s) \n124\n, \n126\n and determine a dielectric constant, or a permittivity (e.g., an electrical permittivity, a fluid permittivity, etc.), and/or a conductivity (e.g., an electrical conductivity, a fluid conductivity, etc.) of the multiphase flow \n104\n based on the electromagnetic data.', 'In some examples, the water detection manager \n102\n determines a presence of water in the multiphase flow \n104\n based on values of permittivity and/or conductivity of the water phase being substantially higher than those of the hydrocarbon phase(s) (e.g., gas and/or oil), as shown in an example table \n200\n depicted in \nFIG.', '2\n.', 'In the table \n200\n of \nFIG.', '2\n, a gas (e.g., a gas phase) has an example (relative) permittivity range of 1.0-1.1.', 'The relative permittivity of the table \n200\n represents a ratio of an absolute permittivity of a material relative to the absolute permittivity of vacuum.', 'In the table \n200\n of \nFIG.', '2\n, oil (e.g., an oil phase) has an example (relative) permittivity range of 2.0-2.7.', 'In the table \n200\n of \nFIG.', '2\n, water (e.g., a water phase) has an example (relative) permittivity of approximately 80 at 20 degrees Centigrade (deg C.) with no salt content, and NaCl-based brines have example (relative) permittivities in the range approximately [20, 80] depending on NaCl mass concentration dissolved in brine (i.e. salinity) and temperature.', 'For example, pure water with no salt content (salinity zero) can have a relative permittivity of approximately 80 at 20 deg C. In such examples, at the same temperature of 20 deg C., the relative permittivity of water can decrease from approximately 80 to approximately 45 as the NaCl salt mass concentration in water (or salinity) increases to 260 kppm (thousand parts per million, or 26%).', 'At the same salinity, brine relative permittivity decreases with increasing temperature.', 'In the illustrated example of \nFIG.', '2\n, the table \n200\n depicts example conductivity values in Siemens per meter (S/m) for gas, oil, and water/brine.', 'In the table \n200\n of \nFIG.', '2\n, gas has an example conductivity of 0.0 S/m, oil has an example conductivity of approximately 0.0 S/m, water has an example conductivity of approximately 0.0 S/m with no salt content (and at DC or a low measurement frequency), and NaCl-based brines have example conductivities in the range approximately [0, 80] S/m depending on NaCl mass concentration dissolved in brine and temperature.', 'For example, pure water with no salt content can have a conductivity of approximately 0 S/m at 20 deg C. In such examples, at the same temperature of 20 deg C., the conductivity of the water can increase from approximately 0 S/m to approximately 25 S/m as the salt concentration increases to 260 kppm.', 'NaCl-based brine conductivity changes approximately 2% per deg C. temperature change.', 'As noted in the table \n200\n of \nFIG.', '2\n, the permittivity for gas is pressure (p) and temperature (T) dependent.', 'For example, the dielectric constant of methane gas increases with pressure at a fixed temperature.', 'For example, at a pressure of approximately 100 bar and 100 deg C., the dielectric constant of methane gas is 1.07.', 'Also noted in the table \n200\n of \nFIG.', '2\n, the permittivity values and/or ranges are given for light to heavy oil and are pressure, temperature, and measurement frequency dependent.', 'Further noted in the table \n200\n of \nFIG.', '2\n, the permittivity and conductivity values for water/brine correspond to temperatures in a range of 20 to 120 deg C. and where a range of salinity of sodium chloride (NaCl) is 0 to 260 kppm.', 'In some examples, the water detection manager \n102\n of \nFIG.', '1\n can detect a presence of water based on the permittivity and conductivity values of the water phase being substantially higher than the gas and oil phases as shown in the table \n200\n of \nFIG.', '2\n.', 'For example, the water detection manager \n102\n can calculate a permittivity value of the multiphase flow \n104\n local to the EM sensor(s) \n124\n, \n126\n and determine that the multiphase flow \n104\n includes water based on the calculated (flow mixture) permittivity value being substantially higher (e.g., more than 5 times higher, etc.)', 'than the permittivity values of \nFIG.', '2\n for the gas and oil phases.', 'In other examples, the water detection manager \n102\n can calculate a conductivity value of the multiphase flow \n104\n and determine that the multiphase flow \n104\n includes brine based on the calculated (flow mixture) conductivity value being substantially higher than a conductivity threshold value (e.g., higher than 0.5 S/m etc.).', 'Turning back to \nFIG.', '1\n, the water detection manager \n102\n can obtain EM sensor (raw) measurement data, or EM data, at substantially high data acquisition frequencies (e.g., 5 kHz, 10 kHz, etc.).', 'For example, the water detection manager \n102\n can include RF and/or microwave measurement electronics to rapidly acquire RF and/or microwave measurement data from the EM sensor(s) \n124\n, \n126\n.', 'The water detection manager \n102\n can process the EM data substantially instantaneously (e.g., at 5 Hz, 10 Hz, 15 Hz, etc.) to calculate mixture parameters associated with the multiphase flow \n104\n over a moving (e.g., rolling) short-time window (e.g., a time window of Δt=50 ms, 100 ms, 1000 ms, etc.).', 'Alternatively, the water detection manager \n102\n can process the EM data at any other specified processing rate.', 'For example, there are at least one hundred EM data samples rapidly acquired over each short-time window Δt, for the water detection manager \n102\n to calculate one or more mixture parameters that represent a characteristic and/or a quantification of the multiphase flow \n104\n local to a measurement zone of the EM sensor(s) \n124\n, \n126\n, as described below in mixture parameters (1)-(8):\n \nMixture Parameter (1): Mixture Permittivity Average (ε\navg\n(Δt))', 'Mixture Parameter (2): Mixture Permittivity Minimum (ε\nmin\n(Δt))\n \nMixture Parameter (3): Mixture Permittivity Maximum (ε\nmax\n(Δt))\n \nMixture Parameter (4): Mixture Permittivity Standard Deviation (ε\nstd\n(Δt))\n \nMixture Parameter (5): Mixture Conductivity Average (σ\navg\n(Δt))', 'Mixture Parameter (6): Mixture Conductivity Minimum (σ\nmin\n(Δt))\n \nMixture Parameter (7): Mixture Conductivity Maximum (σ\nmax\n(Δt))\n \nMixture Parameter (8): Mixture Conductivity Standard Deviation (σ\nstd\n(Δt))', 'Additionally or alternatively, the water detection manager \n102\n can calculate fewer or more mixture parameters than the mixture parameters (1)-(8) as described above.', 'Additionally or alternatively, the water detection manager \n102\n can determine other parameters, for example the water-detection occurrence frequency over a relatively long duration of time (e.g., number of positive water-detection events calculated every 60 seconds(s)), and the water salinity (e.g. determined based on one or more of Mixture Parameters (1)-(8) above, such as the ratio of the water-rich Mixture Conductivity Maximum to the water-rich Mixture Permittivity Maximum).', 'In the multiphase flow measurement system \n100\n of \nFIG.', '1\n, the water detection manager \n102\n is communicatively coupled to an example network \n130\n.', 'The network \n130\n of the illustrated example of \nFIG.', '1\n is the Internet.', 'However, the network \n130\n can be implemented using any suitable wired and/or wireless network(s) including, for example, one or more data buses, one or more Local Area Networks (LANs), one or more wireless LANs, one or more cellular networks, one or more private networks, one or more public networks, etc.', 'In some examples, the network \n130\n enables the water detection manager \n102\n to be in communication with another multiphase flow measurement system \n100\n and/or with an external computing device (e.g., a database, a server, etc.) coupled to the network \n130\n.', 'In some examples, the network \n130\n enables the water detection manager \n102\n to communicate with the external computing device to store the information obtained and/or processed by the water detection manager \n102\n.', 'In such examples, the network \n130\n enables the water detection manager \n102\n to retrieve and/or otherwise obtain the stored information for processing.', 'In the illustrated example of \nFIG.', '1\n, the water detection manager \n102\n generates a report including one or more mixture parameters associated with the multiphase flow \n104\n and transmits the report to another computing device via the network \n130\n.', 'For example, the network \n130\n can be a cloud-based network, which can perform cloud-based data storage, analytics, big data analysis, deep machine learning, etc., to enable multi-well, multi-field reservoir-scale modeling, digital oilfield high-efficiency operations and automation, oil-gas production management and/or optimization based on information obtained and/or processed by the water detection manager \n102\n.', 'In some examples, the water detection manager \n102\n can be an Internet of Things (IoT) device enabled to facilitate capturing, communicating, analyzing, and acting on data generated by networked objects and machines.', 'In some examples, the water detection manager \n102\n generate an alert such as displaying an alert on a user interface, propagating an alert message throughout a process control network (e.g., transmitting an alert to another computing device via the network \n130\n), generating an alert log and/or an alert report, etc.', 'For example, the water detection manager \n102\n can generate an alert corresponding to a characterization of the multiphase flow \n104\n including a detection of water in the multiphase flow \n104\n.\n \nFIG.', '3\n is a block diagram of an example implementation of the multiphase flow measurement system \n100\n of \nFIG.', '1\n including the water detection manager \n102\n of \nFIG.', '1\n.', 'The water detection manager \n102\n obtains EM data from the EM sensor(s) \n124\n, \n126\n and calculates one or more mixture parameters associated with the multiphase flow \n104\n of \nFIG.', '1\n based on the EM data.', 'The water detection manager \n102\n can detect a presence of water in the multiphase flow based on the one or more mixture parameters.', 'The water detection manager \n102\n can generate and transmit a report including the one or more mixture parameters and/or the water detection determination result to another computing device via the network \n130\n.', 'Additionally or alternatively, the water detection manager \n102\n can generate and propagate based on the one or more mixture parameters and/or the water detection determination result to another computing device via the network \n130\n.', 'In \nFIG.', '3\n, the water detection manager \n102\n includes an example collection engine \n310\n, an example measurement configurator \n320\n, an example parameter calculator \n330\n, an example water detector \n340\n, an example report generator, and an example database \n360\n.', 'In the illustrated example of \nFIG.', '3\n, the water detection manager \n102\n includes the example collection engine \n310\n to control a device and/or receive data from the device communicatively coupled to the water detection manager \n102\n.', 'For example, the collection engine \n310\n can implement RF/microwave sensor electronics to receive and/or otherwise obtain data from the EM sensor(s) \n124\n, \n126\n.', 'In some examples, the collection engine \n310\n instructs the EM sensor(s) \n124\n, \n126\n to transmit data to the collection engine \n310\n.', 'In other examples, the collection engine \n310\n receives data from the EM sensor(s) \n124\n, \n126\n without instructing the EM sensor(s) \n124\n, \n126\n to transmit the data.', 'In some examples, the collection engine \n310\n controls the EM sensor(s) \n124\n, \n126\n by directing the EM sensor(s) \n124\n, \n126\n to excite a signal at a specified frequency (e.g., a measurement frequency).', 'For example, the EM sensor(s) \n124\n, \n126\n can operate at one measurement frequency or a plurality of measurement frequencies.', 'In the illustrated example of \nFIG.', '3\n, the water detection manager \n102\n includes the measurement configurator \n320\n to adjust an operation of a device communicatively coupled to the water detection manager \n102\n and/or a configuration used by the parameter calculator \n330\n to calculate mixture parameters.', 'In some examples, the measurement configurator \n320\n adjusts an operation of one or both EM sensors \n124\n, \n126\n by decreasing or increasing an excitation frequency of one or both EM sensors.', 'In some examples, the measurement configurator \n320\n adjusts an acquisition frequency of the collection engine \n310\n.', 'In some examples, the measurement configurator \n320\n changes a processing frequency, a type of measurement window used (e.g., a moving window, an exponential moving average, etc.), and/or a measurement window interval (Δt) used by the parameter calculator \n330\n to calculate mixture parameters associated with the multiphase flow \n104\n of \nFIG.', '1\n.', 'In the illustrated example of \nFIG.', '3\n, the water detection manager \n102\n includes the parameter calculator \n330\n to calculate and/or otherwise determine one or more mixture parameters associated with the multiphase flow \n104\n of \nFIG.', '1\n.', 'For example, the parameter calculator \n330\n can calculate one or more of the mixture parameters (1)-(8) as described above at a processing frequency.', 'For example, the parameter calculator \n330\n can determine the mixture parameters (1)-(8) every 50 ms, 100 ms, 1000 ms, etc., and/or any other processing frequency.', 'In the illustrated example of \nFIG.', '3\n, the water detection manager \n102\n includes the water detector \n340\n to determine a presence of water in the multiphase flow \n104\n based on one or more mixture parameters associated with the multiphase flow \n104\n.', 'In some examples, the water detector \n340\n compares a permittivity (e.g., a maximum permittivity, a minimum permittivity, etc.) of the multiphase flow \n104\n to a water detection threshold and determines that water is present based on the comparison.', 'For example, the water detector \n340\n can determine that the permittivity satisfies the water detection threshold based on the permittivity being substantially greater (e.g., more than twice) than the oil permittivity, or other the water detection threshold.', 'In some examples, the water detector \n340\n compares a permittivity difference to the water detection threshold and determines that water is present based on the comparison.', 'For example, the permittivity difference can be a difference between a maximum permittivity (ε\nmax\n) and a minimum permittivity (ε\nmin\n) during a time period or window period (Δt).', 'For example, the water detector \n340\n can determine that the permittivity difference satisfies the water detection threshold based on the permittivity difference being greater (e.g., substantially greater) than the water detection threshold.', 'In some examples, the water detector \n340\n sets a flag (e.g., a water detection flag) when water is detected based on the permittivity, the permittivity difference, etc.', 'As used herein, the flag is an indicator variable in computer and/or machine readable instructions.', 'In some examples, the water detector \n340\n compares a conductivity of the multiphase flow \n104\n to the water detection threshold and determines that water is present based on the comparison.', 'For example, the water detector \n340\n can determine that the conductivity satisfies the water detection threshold based on the conductivity being greater (e.g., substantially greater) than the water detection threshold.', 'In some examples, the water detector \n340\n compares a conductivity difference to the water detection threshold and determines that water is present based on the comparison.', 'For example, the conductivity difference can be a difference between a maximum conductivity (σ\nmax\n) and a minimum conductivity (σ\nmin\n) during a time period or window period (Δt).', 'For example, the water detector \n340\n can determine that the conductivity difference satisfies the water detection threshold based on the conductivity difference being greater (e.g., substantially greater) than the water detection threshold.', 'In some examples, the water detector \n340\n sets a flag (e.g., a water detection flag) when water is detected based on the conductivity, the conductivity difference, etc.', 'In the illustrated example of \nFIG.', '3\n, the water detection manager \n102\n includes the report generator \n350\n to generate a report or a log associated with the multiphase flow \n104\n of \nFIG.', '1\n.', 'In some examples, the report generator \n350\n generates a report including one or more mixture parameters (e.g., the mixture parameters (1)-(8)) with respect to time or an oilfield operation.', 'In some examples, the report generator \n350\n generates a report including a water detection determination result, a water detection occurrence frequency (e.g. a quantity of positive water detection flags per 60 s time period), water salinity, etc., and/or a combination thereof.', 'For example, the report can include an indication that water is detected or not detected for one or more time periods (e.g., measurement time periods).', 'In some examples, the report generator \n350\n generates an alert based on a value of a mixture parameter and/or a water detection determination result.', 'For example, the report generator \n350\n can generate an alert (e.g., to flag the need to inject hydrate inhibitor, corrosion inhibitor, etc.)', 'when water is detected in the multiphase flow \n104\n.', 'For example, the alert can include an indication that water is detected or not detected, a water detection occurrence frequency, and/or the salinity of water in the multiphase flow \n104\n.', 'In some examples, the report generator \n350\n transmits the report and/or the alert to another computing device communicatively coupled to the water detection manager \n102\n via the network \n130\n.', 'In some examples, the report generator \n350\n can set a WLR measured by a multiphase flowmeter (e.g., a gamma-ray based multiple phase flowmeter (MPFM)) to zero based on a no water detection result (e.g., no water detected) in the multiphase flow \n104\n.', 'For example, the report generator \n350\n can set the WLR to zero to avoid and/or otherwise prevent a reporting of non-physical (e.g., negative) time-averaged WLR values to improve an accuracy in flow rate measurements of oil and gas phases made by the MPFM.', 'For example, the report generator \n350\n can generate and transmit an alert indicating that water is not detected in the multiphase flow \n104\n to a MPFM communicatively coupled to the network \n130\n.', 'In response to receiving the alert, the MPFM or a control system communicatively coupled to the MPFM can set the WLR to zero.', 'Alternatively, the MPFM may be communicatively coupled to the water detection manager \n102\n without the network \n130\n (e.g., the water detection manager is directly coupled to the MPFM).', 'In the illustrated example of \nFIG.', '3\n, the water detection manager \n102\n includes the database \n360\n to record data (e.g., EM data, mixture parameters, water detection determination results, water salinity, excitation frequencies of the EM sensor(s) \n124\n, \n126\n, etc.).', 'The database \n360\n can be implemented by a volatile memory (e.g., a Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS Dynamic Random Access Memory (RDRAM), etc.)', 'and/or a non-volatile memory (e.g., flash memory).', 'The database \n360\n can additionally or alternatively be implemented by one or more double data rate (DDR) memories, such as DDR, DDR2, DDR3, mobile DDR (mDDR), etc.', 'The database \n360\n can additionally or alternatively be implemented by one or more mass storage devices such as hard disk drive(s), compact disk drive(s) digital versatile disk drive(s), etc.', 'While in the illustrated example the database \n360\n is illustrated as a single database, the database \n360\n can be implemented by any number and/or type(s) of databases.', 'Furthermore, the data stored in the database \n360\n can be in any data format such as, for example, binary data, comma delimited data, tab delimited data, structured query language (SQL) structures, etc.', 'In some examples, the database \n360\n can be cloud-based to enable synchronous retrieving and updating.', 'While an example manner of implementing the water detection manager \n102\n of \nFIG.', '1\n is illustrated in \nFIG.', '3\n, one or more of the elements, processes, and/or devices illustrated in \nFIG.', '3\n may be combined, divided, re-arranged, omitted, eliminated, and/or implemented in any other way.', 'Further, the example collection engine \n310\n, the example measurement configurator \n320\n, the example parameter calculator \n330\n, the example water detector \n340\n, the example report generator \n350\n, the example database \n360\n, and/or, more generally, the example water detection manager \n102\n of \nFIG.', '1\n may be implemented by hardware, software, firmware, and/or any combination of hardware, software, and/or firmware.', 'Thus, for example, any of the example collection engine \n310\n, the example measurement configurator \n320\n, the example parameter calculator \n330\n, the example water detector \n340\n, the example report generator \n350\n, the example database \n360\n, and/or, more generally, the example water detection manager \n102\n could be implemented by one or more analog or digital circuit(s), logic circuits, programmable processor(s), programmable controller(s), graphics processing unit(s) (GPU(s)), digital signal processor(s) (DSP(s)), application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)), field programmable gate array(s) (FPGA(s)), and/or field programmable logic device(s) (FPLD(s)).', 'When reading any of the apparatus or system claims of this patent to cover a purely software and/or firmware implementation, at least one of the example collection engine \n310\n, the example measurement configurator \n320\n, the example parameter calculator \n330\n, the example water detector \n340\n, the example report generator \n350\n, and/or the example database \n360\n is/are hereby expressly defined to include a non-transitory computer readable storage device or storage disk such as a memory, a digital versatile disk (DVD), a compact disk (CD), a Blu-ray disk, etc., including the software and/or firmware.', 'Further still, the example water detection manager \n102\n of \nFIG.', '1\n may include one or more elements, processes, and/or devices in addition to, or instead of, those illustrated in \nFIG.', '3\n, and/or may include more than one of any or all of the illustrated elements, processes, and devices.', 'As used herein, the phrase “in communication,” including variations thereof, encompasses direct communication and/or indirect communication through one or more intermediary components, and does not require direct physical (e.g., wired) communication and/or constant communication, but rather additionally includes selective communication at periodic intervals, scheduled intervals, aperiodic intervals, and/or one-time events.\n \nFIG.', '4\n depicts an example graph \n400\n generated by the water detection manager \n102\n of \nFIGS.', '1 and/or 3\n to implement the examples disclosed herein.', 'In \nFIG.', '4\n, the water detection manager \n102\n generates the graph \n400\n based on a maximum permittivity (ε\nmax\n) and a permittivity difference (ε\nmax\n−ε\nmin\n) with respect to time.', 'In \nFIG.', '4\n, the graph \n400\n is based on the multiphase flow \n104\n of \nFIG.', '1\n where the multiphase flow \n104\n is a wet-gas flow with a GVF of 99.5% and with increasing WLR over time.', 'In \nFIG.', '4\n, the water detection manager \n102\n detects the presence of water when water-volume fraction (WVF) (e.g., WVF=WLR*(1−GVF)) is increased from a WVF of 0 to 250 parts per million (ppm) (and higher), by determining one or more mixture parameters, comparing the one or more mixture parameters to a threshold, and determining that the one more mixture parameters satisfy the threshold based on the comparison.', 'In the illustrated example of \nFIG.', '4\n, the water detection manager \n102\n calculates mixture parameters including the maximum permittivity and the permittivity difference at a chosen or determined time interval (e.g., a determined relatively short time interval).', 'For example, the water detection manager \n102\n can determine the mixture parameters every 100 ms, 500 ms, etc., based on raw EM data rapidly acquired at a data acquisition rate of 10 kHz from the EM sensor(s) \n124\n, \n126\n of \nFIG.', '1\n.', 'In \nFIG.', '4\n, the water detection manager \n102\n during a first example time period from 10:45 to 11:00 calculates values for the maximum permittivity and the permittivity difference', 'and', 'compares the values to an example water detection threshold \n402\n.', 'In \nFIG.', '4\n, the water detection threshold \n402\n is described below in Equation (1): \n water detection threshold=(ε\noil\n−ε\ngas\n)', '+δε\nnoise\n\u2003\u2003Equation (1)', 'In the example of Equation (1) above, ε\noil \nrepresents the permittivity of the oil phase of the multiphase flow \n104\n, ε\ngas \nrepresents the permittivity of the gas phase of the multiphase flow \n104\n, and δε\nnoise \nrepresents the permittivity noise.', 'In \nFIG.', '4\n, the permittivity noise is set to 0.1 to account for an uncertainty in oil/gas permittivity values.', 'Alternatively, the permittivity noise may be set to any other value.', 'In other examples, the permittivity noise is much less than 0.01 when related to the measured mixture permittivity standard deviation ε\nstd\n(Δt) induced by measurement noise of the EM sensor(s) \n124\n, \n126\n and/or EM electronics receiving the EM data from the EM sensor(s) \n124\n, \n126\n (e.g., the collection engine \n310\n of \nFIG.', '3\n).', 'For example, measurement noise in the EM sensor(s) \n124\n, \n126\n and/or EM electronics can be determined based on the permittivity average and standard deviation values when performing static gas or static oil measurements.', 'In the illustrated example of \nFIG.', '4\n, the water detection manager \n102\n determines that no water is detected during the time period 10:45 to 11:00 based on the permittivity difference (ε\nmax\n−ε\nmin\n) not being greater than the water detection threshold \n402\n.', 'In \nFIG.', '4\n, the water detection manager \n102\n determines that water is detected during the time periods of 11:00 to 11:15, 11:15 to 11:30, and 11:30 to 11:45 by determining that the permittivity difference is greater than the water detection threshold \n402\n.', 'In some examples, the increasing permittivity difference (ε\nmax\n−ε\nmin\n) indicates an increase in the liquid WLR.', 'Flowcharts representative of example hardware logic, machine readable instructions, hardware implemented state machines, and/or any combination thereof for implementing the water detection manager \n102\n of \nFIGS.', '1', 'and/or 3\n are shown in \nFIGS.', '5-6\n.', 'The machine readable instructions may be an executable program or portion of an executable program for execution by a computer processor such as the processor \n712\n shown in the example processor platform \n700\n discussed below in connection with \nFIG.', '7\n.', 'The program may be embodied in software stored on a non-transitory computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a DVD, a Blu-ray disk, or a memory associated with the processor \n712\n, but the entire program and/or parts thereof could alternatively be executed by a device other than the processor \n712\n and/or embodied in firmware or dedicated hardware.', 'Further, although the example program is described with reference to the flowcharts illustrated in \nFIGS.', '5-6\n, many other methods of implementing the example water detection manager \n102\n may alternatively be used.', 'For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated, or combined.', 'Additionally or alternatively, any or all of the blocks may be implemented by one or more hardware circuits (e.g., discrete and/or integrated analog and/or digital circuitry, an FPGA, an ASIC, a comparator, an operational-amplifier (op-amp), a logic circuit, etc.) structured to perform the corresponding operation without executing software or firmware.', 'As mentioned above, the example processes of \nFIGS.', '5-6\n may be implemented using executable instructions (e.g., computer and/or machine readable instructions) stored on a non-transitory computer and/or machine readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory, and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information).', 'As used herein, the term non-transitory computer readable medium is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media.', '“Including” and “comprising” (and all forms and tenses thereof) are used herein to be open ended terms.', 'Thus, whenever a claim employs any form of “include” or “comprise” (e.g., comprises, includes, comprising, including, having, etc.) as a preamble or within a claim recitation of any kind, it is to be understood that additional elements, terms, etc. may be present without falling outside the scope of the corresponding claim or recitation.', 'As used herein, when the phrase “at least” is used as the transition term in, for example, a preamble of a claim, it is open-ended in the same manner as the term “comprising” and “including” are open ended.', 'The term “and/or” when used, for example, in a form such as A, B, and/or C refers to any combination or subset of A, B, C such as (1) A alone, (2) B alone, (3) C alone, (4) A with B, (5) A with C, (6) B with C, and (7) A with B and with C.\n \nFIG.', '5\n depicts example source code \n500\n representative of example computer readable instructions that can be executed to implement the example water detection manager \n102\n of \nFIGS.', '1 and/or 3\n that can be used to implement the examples disclosed herein.', 'For example, the source code \n500\n can be used to implement the process of \nFIG.', '6\n.', 'In the source code \n500\n, the water detection manager \n102\n executes an example function or process (int getWaterDetection) to determine whether water is detected in the multiphase flow \n104\n of \nFIG.', '1\n.', 'In the source code \n500\n of \nFIG.', '5\n, the water detection manager \n102\n makes water detection determination results immune to potentially small drifts in the multiphase flow measurement system \n100\n by comparing one or more mixture parameters to at least two different water detection thresholds.', 'For example, the water detection manager \n102\n immunizes potential drifts in one or both EM sensors \n124\n, \n126\n of \nFIG.', '1\n, EM sensor electronics included in the water detection manager \n102\n, etc., by comparing the one or more mixture parameters to at least two different water detection thresholds as depicted in the source code \n500\n.', 'In the source code \n500\n of \nFIG.', '5\n, the water detection manager \n102\n compares a permittivity difference during a time window Δt (ε\nmax\n(Δt)−ε\nmin\n(Δt)) to a first water detection threshold ((ε\noil\n(p,T)−ε\ngas\n(p,T))+δε\nnoise\n) determined at the measured multiphase-flow pressure p and temperature T.', 'For example, the water detector \n340\n of \nFIG.', '3\n can compare the permittivity difference to the first water threshold and determine that water is present in the multiphase flow \n104\n based on the comparison.', 'The water detection manager \n102\n uses the mixture permittivity maximum (ε\nmax\n(Δt)) to capture a water-rich data point and uses the mixture permittivity minimum (ε\nmin\n(Δt)) to capture a gas-rich data point for, in some examples, at least 1000 data points rapidly acquired during the time window Δt.', 'In the source code \n500\n, oil and gas permittivity pressure-volume-temperature (PVT) models are used to track the changes in the oil permittivity (ε\noil\n(p,T) and the gas permittivity (ε\ngas\n(p,T)) of the multiphase flow \n104\n.', 'The PVT models are generated based on obtaining and/or otherwise determining the densities and chemical compositions of the oil and gas included in the multiphase flow \n104\n.', 'For example, the densities and chemical compositions can be determined by performing gas chromatograph analysis of samples of oil and gas included in the multiphase flow \n104\n.', 'In the source code \n500\n of \nFIG.', '5\n, if the water detection manager \n102\n determines that the permittivity difference is greater than the first water detection threshold, then the water detection manager \n102\n sets the water detection flag (waterDetectionFlag) to true indicating that water is present in the multiphase flow \n104\n.', 'If the water detection manager \n102\n determines that the permittivity difference is not greater than the first water detection threshold, then the water detection manager \n102\n compares the maximum permittivity during the time window (ε\nmax\n(Δt)) to a second water detection threshold (ε\noil\n(p,T)+δε\noil\n).', 'In some examples, the uncertainty in the oil permittivity (δε\noil\n) is chosen to include an absolute (RF electronics) baseline drift in the permittivity measurement (e.g., by choosing δε\noil \nto be in a range of 1.0 to 1.5).', 'In the source code \n500\n of \nFIG.', '5\n, if the water detection manager \n102\n determines that the maximum permittivity is greater than the second water detection threshold, then the water detection manager \n102\n sets the water detection flag to true indicating that water is present in the multiphase flow \n104\n.', 'If the water detection manager \n102\n determines that the maximum permittivity is not greater than the second water detection threshold, then the water detection manager \n102\n sets the water detection flag to false indicating that water is absent from and/or otherwise present in a negligible amount in the multiphase flow \n104\n.', 'In response to setting the water detection flag, the source code \n500\n returns a value of the water detection flag.', 'In some examples, the quantity of true water detection occurrences can be accumulated over a specified time duration (e.g., every 10 s, every 60 s, etc.) to calculate and/or otherwise determine a water detection occurrence frequency.', 'FIG.', '6\n is a flowchart representative of example machine readable instructions \n600\n that can be executed to implement the water detection manager \n102\n of \nFIGS.', '1 and/or 3\n to detect a presence of water in the multiphase flow \n104\n of \nFIG.', '1\n.', 'The machine readable instructions \n600\n begin at block \n602\n, at which the water detection manager \n102\n configures electromagnetic sensor(s).', 'For example, the measurement configurator \n320\n of \nFIG.', '3\n can configure one or both EM sensors \n124\n, \n126\n of \nFIG.', '1\n to excite EM energy into the multiphase flow \n104\n at a specified RF/microwave frequency.', 'At block \n604\n, the water detection manager \n102\n obtains electromagnetic data associated with a multiphase flow.', 'For example, the collection engine \n310\n of \nFIG. 3\n can obtain EM data from one or both EM sensors \n124\n, \n126\n associated with the multiphase flow \n104\n.', 'At block \n606\n, the water detection manager \n102\n calculates mixture parameter(s) associated with the multiphase flow.', 'For example, the parameter calculator \n330\n can calculate one or more of the mixture parameters (1)-(8) as described above.', 'At block \n608\n, the water detection manager \n102\n compares mixture parameter(s) to water detection threshold(s).', 'For example, the water detector \n340\n can compare the permittivity difference to the first water detection threshold as described above in connection with the source code \n500\n of \nFIG.', '5\n.', 'In other examples, the water detector \n340\n can compare the maximum permittivity to the second water detection threshold as described above in connection with the source code \n500\n of \nFIG.', '5\n.', 'At block \n610\n, the water detection manager \n102\n determines whether a water detection threshold has been satisfied.', 'For example, the water detector \n340\n can determine that the permittivity difference satisfies the first water detection threshold based on the difference.', 'In such examples, the water detector \n340\n can determine that the first water detection threshold is satisfied based on the permittivity difference being greater than the first water detection threshold.', 'If, at block \n610\n, the water detection manager \n102\n determines that the water detection threshold has not been satisfied, control proceeds to block \n614\n to set a water detection flag.', 'For example, the water detector \n340\n can set the water detection flag to false indicating that water is not detected in the multiphase flow \n104\n.', 'If, at block \n610\n, the water detection manager \n102\n determines that the water detection threshold has been satisfied, then, at block \n612\n, the water detection manager \n102\n detects water in the multiphase flow.', 'For example, the water detector \n340\n can determine that water is detected in the multiphase flow \n104\n.', 'In response to detecting water in the multiphase flow, the water detection manager \n102\n sets the water detection flag at block \n614\n.', 'For example, the water detector \n340\n can set the water detection flag to true indicating that water is detected in the multiphase flow \n104\n.', 'In response to setting the water detection flag at block \n614\n, the water detection manager \n102\n determines whether to continue monitoring the multiphase flow at block \n616\n.', 'For example, the collection engine \n310\n can determine to continue obtaining EM data from the EM sensor(s) \n124\n, \n126\n associated with the multiphase flow \n104\n.', 'If, at block \n616\n, the water detection manager \n102\n determines to continue monitoring the multiphase flow, control returns to block \n604\n to obtain electromagnetic data associated with the multiphase flow.', 'If, at block \n616\n, the water detection manager \n102\n determines not to continue monitoring the multiphase flow, then, at block \n618\n, the water detection manager \n102\n generates and transmits a report and/or an alert.', 'For example, the report generator \n350\n can generate a report including the water detection determination result (e.g., a value of the water detection flag), one or more mixture parameters, the graph \n400\n of \nFIG.', '4\n, etc., and/or a combination thereof.', 'In such examples, the report generator \n350\n can generate an alert indicating whether water is detected in the multiphase flow \n104\n.', 'In such examples, the report generator \n350\n can transmit the report and/or the alert to an external computing device via the network \n130\n of \nFIG.', '1\n.', 'In such examples, a MPFM communicatively coupled to the network \n130\n can set a WLR used by the MPFM to calculate flow rate measurements of the multiphase flow \n104\n to zero when water is not detected for a relatively long duration (e.g. every 60 s, every 300 s, etc.) to improve an accuracy of the calculated measurements.', 'In response to generating and transmitting the report and/or the alert, the machine readable instructions \n600\n conclude.', 'Alternatively, the machine readable instructions \n600\n can be executed using mixture parameters based on mixture conductivity data (e.g., σ\nmin\n(Δt), σ\nmax\n(Δt), etc.)', 'when water with a conductivity value larger than a threshold is used (e.g., a threshold of 0.5 S/m, 1.0 S/m, 1.5 S/m, etc.).', 'FIG.', '7\n is a block diagram of an example processor platform \n700\n structured to execute the instructions of \nFIGS.', '5-6\n to implement the water detection manager \n102\n of \nFIGS.', '1 and/or 3\n.', 'The processor platform \n700\n can be, for example, a server, a personal computer, a workstation, a self-learning machine (e.g., a neural network), a mobile device (e.g., a cell phone, a smart phone, a tablet such as an iPad™), a personal digital assistant (PDA), an Internet appliance, a headset or other wearable device, or any other type of computing device.', 'The processor platform \n700\n of the illustrated example includes a processor \n712\n.', 'The processor \n712\n of the illustrated example is hardware.', 'For example, the processor \n712\n can be implemented by one or more integrated circuits, logic circuits, microprocessors, GPUs, DSPs, or controllers from any desired family or manufacturer.', 'The hardware processor may be a semiconductor based (e.g., silicon based) device.', 'In this example, the processor \n712\n implements the example collection engine \n310\n, the example measurement configurator \n320\n, the example parameter calculator \n330\n, the example water detector \n340\n, and the example report generator \n350\n of \nFIG.', '3\n.', 'The processor \n712\n of the illustrated example includes a local memory \n713\n (e.g., a cache).', 'The processor \n712\n of the illustrated example is in communication with a main memory including a volatile memory \n714\n and a non-volatile memory \n716\n via a bus \n718\n.', 'The volatile memory \n714\n may be implemented by Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS® Dynamic Random Access Memory (RDRAM®), and/or any other type of random access memory device.', 'The non-volatile memory \n716\n may be implemented by flash memory and/or any other desired type of memory device.', 'Access to the main memory \n714\n, \n716\n is controlled by a memory controller.', 'The processor platform \n700\n of the illustrated example also includes an interface circuit \n720\n.', 'The interface circuit \n720\n may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), a Bluetooth® interface, a near field communication (NFC) interface, and/or a PCI express interface.', 'In the illustrated example, one or more input devices \n722\n are connected to the interface circuit \n720\n.', 'The input device(s) \n722\n permit(s) a user to enter data and/or commands into the processor \n712\n.', 'The input device(s) \n722\n can be implemented by, for example, an audio sensor, a microphone, a camera (still or video), a keyboard, a button, a mouse, a touchscreen, a track-pad, a trackball, an isopoint device, and/or a voice recognition system.', 'One or more output devices \n724\n are also connected to the interface circuit \n720\n of the illustrated example.', 'The output devices \n724\n can be implemented, for example, by display devices (e.g., a light emitting diode (LED), an organic light emitting diode (OLED), a liquid crystal display (LCD), a cathode ray tube display (CRT), an in-place switching (IPS) display, a touchscreen, etc.), a tactile output device, a printer, and/or speaker.', 'The interface circuit \n720\n of the illustrated example, thus, typically includes a graphics driver card, a graphics driver chip, and/or a graphics driver processor.', 'The interface circuit \n720\n of the illustrated example also includes a communication device such as a transmitter, a receiver, a transceiver, a modem, a residential gateway, a wireless access point, and/or a network interface to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network \n726\n.', 'The communication can be via, for example, an Ethernet connection, a digital subscriber line (DSL) connection, a telephone line connection, a coaxial cable system, a satellite system, a line-of-site wireless system, a cellular telephone system, etc.', 'The network \n726\n implements the example network \n130\n of \nFIGS.', '1 and/or 3\n.', 'The processor platform \n700\n of the illustrated example also includes one or more mass storage devices \n728\n for storing software and/or data.', 'Examples of such mass storage devices \n728\n include floppy disk drives, hard drive disks, compact disk drives, Blu-ray disk drives, redundant array of independent disks (RAID) systems, and digital versatile disk (DVD) drives.', 'The machine executable instructions \n732\n of \nFIGS.', '5-6\n may be stored in the mass storage device \n728\n, in the volatile memory \n714\n, in the non-volatile memory \n716\n, and/or on a removable non-transitory computer readable storage medium such as a CD or DVD.', 'In the specification and appended claims: the terms “connect,” “connection,” “connected,” “in connection with,” and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements;” and the term “set” is used to mean “one element” or “more than one element.”', 'Further, the terms “couple,” “coupling,” “coupled,” “coupled together,” and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements.”', 'As used herein, the terms “up” and “down,” “upper” and “lower,” “upwardly” and downwardly,” “upstream” and “downstream;” “above” and “below;” and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure.', 'From the foregoing, it will be appreciated that example methods, apparatus, and systems have been disclosed that detect water in multiphase flows.', 'The above-disclosed examples describe detecting the presence of water in a multiphase or a wet-gas flow stream by interpreting mixture parameters including mixture permittivity and/or mixture conductivity obtained at high data sampling or acquisition frequencies by one or more electromagnetic sensors.', 'The above-disclosed examples improve an accuracy of flow rate measurements of individual phases of the multiphase flow by setting a WLR to zero when water is not detected in the multiphase flow.', 'The above-disclosed examples also improve flow assurance and/or water processing facility planning of oilfield gas-oil production operations, by transmitting alert of the risks of hydrate formation (blockage) and/or corrosions in the flowline when water is detected in the multiphase flow.', 'Alternatively, the above-disclosed methods and apparatus can be applicable to other electromagnetic measurement techniques, such as sensors based on (local) RF/microwave transmission measurement, (local) electrical impedance (e.g., capacitance, conductance, inductance, etc.) measurement, etc., and/or a combination thereof.', 'Example 1 includes an apparatus, comprising a conduit including an inlet to receive a multiphase flow, and an electromagnetic sensor coupled to a liquid-rich region of the conduit to measure a permittivity of the multiphase flow, and a water detection manager to determine that water is detected in the multiphase flow based on the permittivity.', 'Example 2 includes the apparatus of example 1, wherein the liquid-rich region is disposed at an underside of a horizontal blind tee conduit or disposed at a near-wall region of a vertical conduit.', 'Example 3 includes the apparatus of example 1, wherein the electromagnetic sensor is a radiofrequency (RF) or a microwave frequency open-coaxial probe, an rf/microwave local transmission measurement sensor, an rf/microwave local resonance sensor, a millimeter-wave sensor, or an electrical impedance local measurement sensor, the electromagnetic sensor to operate at one measurement frequency or a plurality of measurement frequencies.', 'Example 4 includes the apparatus of example 1, wherein the permittivity is a first permittivity, the water detection manager further including a parameter calculator to determine the first permittivity and a second permittivity of the multiphase flow based on electromagnetic data obtained from the electromagnetic sensor, and a water detector to compare a difference between the first permittivity and the second permittivity to a water detection threshold, and determine that water is detected in the multiphase flow based on the comparison.', 'Example 5 includes the apparatus of example 4, further including a report generator to generate a report including at least one of the first permittivity, the second permittivity, or an indication that water is detected in the multiphase flow.', 'Example 6 includes the apparatus of example 4, further including a report generator to generate an alert indicating that water is not detected in the multiphase flow, the alert causing a water-to-liquid ratio to be set to zero for a flowmeter measuring the multiphase flow.', 'Example 7 includes a method, comprising determining a first permittivity and a second permittivity of a multiphase flow based on electromagnetic data obtained from an electromagnetic sensor, comparing a difference between the first permittivity and the second permittivity to a water detection threshold, and in response to the difference satisfying the water detection threshold, generating an alert indicating that water is present in the multiphase flow.', 'Example 8 includes the method of example 7, wherein the electromagnetic sensor is measuring a liquid-rich region disposed at an underside of a horizontal blind tee conduit or disposed at a near-wall region of a vertical conduit.', 'Example 9 includes the method of example 7, wherein the electromagnetic sensor is a radiofrequency (RF) or microwave frequency open-coaxial probe, an rf/microwave local transmission measurement sensor, an rf/microwave local resonance sensor, a millimeter-wave sensor, or an electrical impedance local measurement sensor.', 'Example 10 includes the method of example 9, wherein the electromagnetic sensor operates at one measurement frequency or a plurality of measurement frequencies.', 'Example 11 includes the method of example 7, further including in response to the difference satisfying the water detection threshold, generating a report including at least one of the first permittivity, the second permittivity, or an indication that water is detected in the multiphase flow.', 'Example 12 includes the method of example 7, further including in response to determining that water is absent in the multiphase flow, causing a water-to-liquid ratio to be set to zero for a flowmeter measuring the multiphase flow.', 'Example 13 includes the method of example 7, wherein the water detection threshold is a first water detection threshold, and further including comparing the first permittivity to a second water detection threshold, and in response to the first permittivity satisfying the second water detection threshold, generating an alert indicating that water is detected in the multiphase flow based on the comparison.', 'Example 14 includes the method of example 13, further including in response to determining that water is detected in the multiphase flow, generating a report including at least one of the first permittivity and an indication that water is detected in the multiphase flow.', 'Example 15 includes a non-transitory computer readable storage medium comprising instructions which, when executed, causes a machine to at least determine a first permittivity and a second permittivity of a multiphase flow based on electromagnetic data obtained from an electromagnetic sensor, compare a difference between the first permittivity and the second permittivity to a water detection threshold, and generate an alert indicating that water is detected in the multiphase flow when the difference satisfies the water detection threshold.', 'Example 16 includes the non-transitory computer readable storage medium of example 15, wherein the electromagnetic sensor is a radiofrequency (RF) or microwave frequency open-coaxial probe, an rf/microwave local transmission measurement sensor, an rf/microwave local resonance sensor, a millimeter-wave sensor, or an electrical impedance local measurement sensor, the electromagnetic sensor to operate at one measurement frequency or a plurality of measurement frequencies.', 'Example 17 includes the non-transitory computer readable storage medium of example 15, further including instructions which, when executed, cause the machine to at least generate a report including at least one of the first permittivity, the second permittivity, or an indication that water is detected in the multiphase flow when the difference satisfies the water detection threshold.', 'Example 18 includes the non-transitory computer readable storage medium of example 15, further including instructions which, when executed, cause the machine to at least cause a water-to-liquid ratio to be set to zero for a flowmeter measuring the multiphase flow when water is not detected in the multiphase flow.', 'Example 19 includes the non-transitory computer readable storage medium of example 15, wherein the water detection threshold is a first water detection threshold, and further including instructions which, when executed, cause the machine to at least compare the first permittivity to a second water detection threshold, and generate an alert indicating that water is detected in the multiphase flow based on the comparison when the first permittivity satisfies the second water detection threshold.', 'Example 20 includes the non-transitory computer readable storage medium of example 19, further including instructions which, when executed, cause the machine to at least generate a report including at least one of the first permittivity and an indication that water is not detected in the multiphase flow when water is not detected in the multiphase flow.', 'Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.'] | ['1.', 'An apparatus, comprising:\na conduit including: an inlet to receive a multiphase flow; an electromagnetic sensor coupled to a liquid-rich region of the conduit to obtain a plurality of permittivity measurements of the multiphase flow; and a water detection manager to determine that water is detected in the multiphase flow based on the plurality of permittivity measurements, the water detection manager including: a parameter calculator to determine a maximum of the plurality of permittivity measurements and a minimum of the plurality of permittivity measurements, and a difference between the maximum and the minimum; and a water detector to: compare the difference to a water detection threshold; and determine that water is detected in the multiphase flow based on the comparison.', '2.', 'The apparatus of claim 1, wherein the liquid-rich region is disposed at an underside of a horizontal blind tee conduit or disposed at a near-wall region of a vertical conduit.', '3.', 'The apparatus of claim 1, wherein the electromagnetic sensor is a radiofrequency (RF) or a microwave frequency open-coaxial probe, an RF/microwave local transmission measurement sensor, an RF/microwave local resonance sensor, a millimeter-wave sensor, or an electrical impedance local measurement sensor, the electromagnetic sensor to operate at one measurement frequency or a plurality of measurement frequencies.', '4.', 'The apparatus of claim 1, further including a report generator to generate a report including at least one of the maximum permittivity, the minimum permittivity, or an indication that water is detected in the multiphase flow.', '5.', 'The apparatus of claim 1, further including a report generator to generate an alert indicating that water is not detected in the multiphase flow, the alert causing a water-to-liquid ratio to be set to zero for a flowmeter measuring the multiphase flow.', '6.', 'A method, comprising:\ndetermining a maximum permittivity and a minimum permittivity of a multiphase flow during a measurement duration based on electromagnetic data obtained from an electromagnetic sensor;\ncomparing a difference between the maximum permittivity and the minimum permittivity to a water detection threshold; and\nin response to the difference satisfying the water detection threshold, generating an alert indicating that water is present in the multiphase flow.', '7.', 'The method of claim 6, wherein the electromagnetic sensor is measuring a liquid-rich region disposed at an underside of a horizontal blind tee conduit or disposed at a near-wall region of a vertical conduit.', '8.', 'The method of claim 6, wherein the electromagnetic sensor is a radiofrequency (RF) or microwave frequency open-coaxial probe, an RF/microwave local transmission measurement sensor, an RF/microwave local resonance sensor, a millimeter-wave sensor, or an electrical impedance local measurement sensor.\n\n\n\n\n\n\n9.', 'The method of claim 8, wherein the electromagnetic sensor operates at one measurement frequency or a plurality of measurement frequencies.', '10.', 'The method of claim 6, further including in response to the difference satisfying the water detection threshold, generating a report including at least one of the maximum permittivity, the minimum permittivity, or an indication that water is detected in the multiphase flow.', '11.', 'The method of claim 6, further including in response to determining that water is absent in the multiphase flow, causing a water-to-liquid ratio to be set to zero for a flowmeter measuring the multiphase flow.', '12.', 'The method of claim 6, wherein the water detection threshold is a first water detection threshold, and further including:\ncomparing the maximum permittivity to a second water detection threshold; and\nin response to the maximum permittivity satisfying the second water detection threshold, generating an alert indicating that water is detected in the multiphase flow based on the comparison.', '13.', 'The method of claim 12, further including in response to determining that water is detected in the multiphase flow, generating a report including at least one of the maximum permittivity and an indication that water is detected in the multiphase flow.', '14.', 'A non-transitory computer readable storage medium comprising instructions which, when executed, causes a machine to at least:\ndetermine a maximum permittivity and a minimum permittivity of a multiphase flow based on electromagnetic data obtained from an electromagnetic sensor during a measurement duration;\ncompare a difference between the maximum permittivity and the minimum permittivity to a water detection threshold; and\ngenerate an alert indicating that water is detected in the multiphase flow when the difference satisfies the water detection threshold.', '15.', 'The non-transitory computer readable storage medium of claim 14, wherein the electromagnetic sensor is a radiofrequency (RF) or microwave frequency open-coaxial probe, an RF/microwave local transmission measurement sensor, an RF/microwave local resonance sensor, a millimeter-wave sensor, or an electrical impedance local measurement sensor, the electromagnetic sensor to operate at one measurement frequency or a plurality of measurement frequencies.', '16.', 'The non-transitory computer readable storage medium of claim 14, further including instructions which, when executed, cause the machine to at least generate a report including at least one of the maximum permittivity, the minimum permittivity, or an indication that water is detected in the multiphase flow when the difference satisfies the water detection threshold.', '17.', 'The non-transitory computer readable storage medium of claim 14, further including instructions which, when executed, cause the machine to at least cause a water-to-liquid ratio to be set to zero for a flowmeter measuring the multiphase flow when water is not detected in the multiphase flow.', '18.', 'The non-transitory computer readable storage medium of claim 14, wherein the water detection threshold is a first water detection threshold, and further including instructions which, when executed, cause the machine to at least:\ncompare the maximum permittivity to a second water detection threshold; and\ngenerate an alert indicating that water is detected in the multiphase flow based on the comparison when the maximum permittivity satisfies the second water detection threshold.', '19.', 'The non-transitory computer readable storage medium of claim 18, further including instructions which, when executed, cause the machine to at least generate a report including at least one of the maximum permittivity and an indication that water is not detected in the multiphase flow when water is not detected in the multiphase flow.'] | ['FIG. 1 illustrates an example multiphase flow measurement system including an example water detection manager apparatus for determining liquid properties of a multiphase flow.; FIG.', '2 depicts an example table including example parameters associated with a multiphase flow.; FIG.', '3 is a block diagram of an example implementation of the example multiphase flow measurement system of FIG.', '1 including the example water detection manager apparatus of FIG.', '1.; FIG.', '4 depicts an example graph generated by the example water detection manager apparatus of FIGS.', '1 and/or 3 to implement the examples disclosed herein.; FIG.', '5 depicts example machine readable instructions that may be executed to implement the example water detection manager apparatus of FIGS. 1 and/or 3 that may be used to implement the examples disclosed herein.; FIG.', '6 is a flowchart representative of machine readable instructions that may be executed to implement the example water detection manager apparatus of FIGS. 1 and/or 3.; FIG. 7 is a block diagram of an example processing platform structured to execute the instructions of FIGS.', '5 and/or 6 to implement the example water detection manager apparatus of FIGS. 1 and/or 3.; FIG. 1 illustrates an example multiphase flow measurement system 100 including an example water detection manager 102 to determine liquid properties of a multiphase flow 104.', 'In FIG.', '1, the multiphase flow measurement system 100 includes an example blind tee 106.', 'The blind tee 106 of FIG. 1 includes an example inlet 108, a first example conduit 110, an example outlet 112, an example end (flange) section 114, and a second example conduit 116.', 'In FIG.', '1, the first conduit 110 is a horizontal blind tee conduit and the second conduit 116 is a vertical blind tee conduit.', 'At the downstream of the outlet 112, a multiphase flowmeter may be installed (not shown in FIG. 1).; FIG.', '3 is a block diagram of an example implementation of the multiphase flow measurement system 100 of FIG.', '1 including the water detection manager 102 of FIG.', '1.', 'The water detection manager 102 obtains EM data from the EM sensor(s) 124, 126 and calculates one or more mixture parameters associated with the multiphase flow 104 of FIG.', '1 based on the EM data.', 'The water detection manager 102 can detect a presence of water in the multiphase flow based on the one or more mixture parameters.', 'The water detection manager 102 can generate and transmit a report including the one or more mixture parameters and/or the water detection determination result to another computing device via the network 130.', 'Additionally or alternatively, the water detection manager 102 can generate and propagate based on the one or more mixture parameters and/or the water detection determination result to another computing device via the network 130.', 'In FIG.', '3, the water detection manager 102 includes an example collection engine 310, an example measurement configurator 320, an example parameter calculator 330, an example water detector 340, an example report generator, and an example database 360.; FIG.', '4 depicts an example graph 400 generated by the water detection manager 102 of FIGS.', '1 and/or 3 to implement the examples disclosed herein.', 'In FIG. 4, the water detection manager 102 generates the graph 400 based on a maximum permittivity (εmax) and a permittivity difference (εmax−εmin) with respect to time.', 'In FIG. 4, the graph 400 is based on the multiphase flow 104 of FIG.', '1 where the multiphase flow 104 is a wet-gas flow with a GVF of 99.5% and with increasing WLR over time.', 'In FIG. 4, the water detection manager 102 detects the presence of water when water-volume fraction (WVF) (e.g., WVF=WLR*(1−GVF)) is increased from a WVF of 0 to 250 parts per million (ppm) (and higher), by determining one or more mixture parameters, comparing the one or more mixture parameters to a threshold, and determining that the one more mixture parameters satisfy the threshold based on the comparison.; FIG.', '5 depicts example source code 500 representative of example computer readable instructions that can be executed to implement the example water detection manager 102 of FIGS. 1 and/or 3 that can be used to implement the examples disclosed herein.', 'For example, the source code 500 can be used to implement the process of FIG.', '6.', 'In the source code 500, the water detection manager 102 executes an example function or process (int getWaterDetection) to determine whether water is detected in the multiphase flow 104 of FIG.', '1.; FIG. 6 is a flowchart representative of example machine readable instructions 600 that can be executed to implement the water detection manager 102 of FIGS.', '1 and/or 3 to detect a presence of water in the multiphase flow 104 of FIG.', '1.', 'The machine readable instructions 600 begin at block 602, at which the water detection manager 102 configures electromagnetic sensor(s).', 'For example, the measurement configurator 320 of FIG.', '3 can configure one or both EM sensors 124, 126 of FIG.', '1 to excite EM energy into the multiphase flow 104 at a specified RF/microwave frequency.', '; FIG. 7 is a block diagram of an example processor platform 700 structured to execute the instructions of FIGS.', '5-6 to implement the water detection manager 102 of FIGS. 1 and/or 3.', 'The processor platform 700 can be, for example, a server, a personal computer, a workstation, a self-learning machine (e.g., a neural network), a mobile device (e.g., a cell phone, a smart phone, a tablet such as an iPad™), a personal digital assistant (PDA), an Internet appliance, a headset or other wearable device, or any other type of computing device.'] |
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US11091972 | Non-explosive downhole perforating and cutting tools | Jul 27, 2020 | Hongfa Huang, Delbert Taylor | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written opionion issued in the related PCT application PCT/2015/056161, dated Dec. 21, 2015 (16 pages).; International Preliminary Report on Patentability issued in the related PCT application PCT/2015/056161, dated May 2, 2017 (12 pages).; Yehuda Meir and Eli Jerby, Underwater Microwave Ignition of Hydrophobic Thermite Powder Enabled by Magnetic Encapsulation, Conference: 14th International Conference on Microwave and High Frequency Heating, Nottingham, UK, Sep. 2013 (4 pages).; Extended Search Report issued in the related EP Application 17193207.2 dated May 18, 2018 (8 pages).; Extended Search Report issued in the related EP Application 15855623.3 dated Jun. 29, 2018 (7 pages).; Office Action issued in the related U.S. Appl. No. 15/275,948 dated Jul. 3, 2018 (20 Pages).; Exam Report issue in the related EP Application No. 17193207.2 dated Apr. 9, 2019, 6 pages.; Office Action issued in the related U.S. Appl. No. 15/520,853 dated Mar. 19, 2019, 32 pages.; International Search Report and Written Opinion of International Patent Application No. PCT/US2018/065590 dated Mar. 27, 2019, 13 pages.; Office Action issued in the related U.S. Appl. No. 15/275,948 dated Jun. 4, 2019, 18 pages.; Office Action issued in the related U.S. Appl. No. 15/988,098 dated Dec. 26, 2019, 40 pages.; Communication pursuant to Article 94(3) EPC issued in the related EP Application 15855623.3 dated Jan. 27, 2020, 6 pages.; Notice of Allowance issued in the related U.S. Appl. No. 15/988,098 dated May 20, 2020, 15 pages.; International Preliminary Report on Patentability issued in the related PCT application PCT/2018/065590 dated Jun. 25, 2020, 9 pages. | RE20832; August 1938; Wells; 2191783; February 1940; Wells; 2286075; June 1942; Evans; 2789004; April 1957; Foster; 3318381; May 1967; Brandt; 4125161; November 14, 1978; Chammas; 4216721; August 12, 1980; Marziano et al.; 4298063; November 3, 1981; Regalbuto; 4585158; April 29, 1986; Wardlaw, III; 4598789; July 8, 1986; Robertson; 4619318; October 28, 1986; Terrell; 4808037; February 28, 1989; Wade; 4996922; March 5, 1991; Halcomb et al.; 5129305; July 14, 1992; Reilly; 5411049; May 2, 1995; Colvard; 5435394; July 25, 1995; Robertson; 5833001; November 10, 1998; Song et al.; 6131801; October 17, 2000; Hagen; 6186226; February 13, 2001; Robertson; 6598679; July 29, 2003; Robertson; 6766744; July 27, 2004; Song et al.; 6925937; August 9, 2005; Robertson; 7124820; October 24, 2006; Wardlaw; 7290609; November 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20140251612; September 11, 2014; Powers; 20140251812; September 11, 2014; Powers; 20140262249; September 18, 2014; Willberg et al.; 20150034317; February 5, 2015; Skjold; 20160214176; July 28, 2016; Bruck et al.; 20160369597; December 22, 2016; Robertson et al.; 20170241227; August 24, 2017; Tallini et al.; 20170335846; November 23, 2017; Huang et al.; 20180085850; March 29, 2018; Huang | 2065750; July 1981; GB; 2013135583; September 2013; WO; 2014138444; September 2014; WO; 2016069305; May 2016; WO; 2016161283; October 2016; WO | ['A non-explosive downhole tool for creating openings in tubulars and or earthen formations includes a carrier holding a non-explosive material, such as thermate, a head connected with the carrier and having a port to eject a product of the ignited material from the head and a communication path extending from the material to the port and a moveable member in a closed position blocking the communication path and in an open position opening the communication path.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a continuation of U.S. patent application Ser.', 'No. 15/520,853 filed 21 Apr. 2017, now U.S. Pat.', 'No. 10,724,320, which is a National Phase filing of PCT Application No.', 'PCT/US2015/056161 filed 19 Oct. 2015 which claims priority to U.S. Provisional Application Ser.', 'No. 62/073,929 filed 31 Oct. 2014, and U.S. Provisional Application Ser.', 'No. 62/086,412 filed 2 Dec. 2014, and U.S. Provisional Application Ser.', 'No. 62/090,643 filed 11 Dec. 2014, and U.S. Provisional Application Ser.', 'No. 62/090,643 filed 11 Dec. 2014, and U.S. Provisional Application Ser.', 'No. 62/165,655 filed 22 May 2015, all of which are herein incorporated by reference.', 'BACKGROUND\n \nThis section provides background information to facilitate a better understanding of the various aspects of the disclosure.', 'It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.', 'Perforating techniques have been implemented in hydrocarbon wells to create a fluid communication channel between a pay zone and the wellbore, penetrating through a casing or liner that separates the wellbore from the formation.', 'Common tools used in perforating operations include a gun that carries shaped charges into the wellbore and a firing head which initiates detonation of the shaped charges.', 'A detonation cord may extend from the firing head to each of the shaped charges in a gun.', 'The shaped charges are explosive and propel a jet outwardly to form perforations in the casing or liner and into the formation.', 'Various techniques and tools exist for cutting pipe.', 'Selection of a particular tool or technique may depend on the type of pipe, the location of the pipe, as well as the ambient conditions surrounding the pipe.', 'In the production of hydrocarbon fluids, such as oil and natural gas, wells may be drilled into which pipes, tools, and other items may be run.', 'Occasionally, to enable at least partial removal of the pipes, tools, and other items, cutters may be deployed.', 'Conventionally, two types of specially designed cutters have been employed: a jet cutter which projects a force from an explosion to cut the items, and a chemical cutter which may project a caustic acid to cut through the items.', 'Use of these types of cutters, however, is limited due to high pressure and high temperature constraints\n \nSUMMARY', 'In accordance with an embodiment a non-explosive downhole tool for creating openings in tubulars includes a carrier holding a non-explosive material, such as thermate, a head connected with the carrier and having a port to eject a product of the ignited material from the head and a communication path extending from the material to the port and a moveable member in a closed position blocking the communication path and in an open position opening the communication path.', 'An example of a method of creating an opening in a tubular includes disposing a non-explosive tool in a tubular that is disposed in a wellbore, igniting a thermate material in the tool and displacing a moveable member in response to a product (e.g., gas and or molten material) produced by the ignited thermate material thereby opening a port in the tool and directing the product through the port and onto the tubular thereby creating an opening in the tubular.', 'A non-explosive downhole tubular cutter in accordance to an embodiment includes a carrier body holding a thermate material, a head connected to carrier body that has a diverter section that is axially moveable relative to a diverter section from a closed position in contact with the diverter section to an open position forming a 360 degree port between the axially separated body and diverter section in response to ignition of the thermate material and a channel extending through the diverter section from the thermate material to the port.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The disclosure is best understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIGS.', '1 and 1A\n illustrate a non-explosive downhole tool arranged in a perforating or puncher configuration according to one or more aspects of the disclosure disposed in a wellbore.\n \nFIGS.', '2 and 2A\n illustrate a non-explosive downhole tool arranged in a cutter configuration according to one or more aspects of the disclosure disposed in a wellbore.\n \nFIGS.', '3 and 4\n illustrate an embodiment of a non-explosive energy source in the form of a thermate pellet according to one or more aspects of the disclosure.', 'FIGS.', '5 and 6\n illustrate a non-explosive downhole tool having a penetrator head arranged in a cutter configuration according to one or more aspects of the disclosure.\n \nFIG.', '7\n illustrates a diverter section of a penetrator head in accordance to one or more aspects of the disclosure along a line I-I of \nFIG.', '6\n.\n \nFIG.', '8\n illustrates a penetrator head arranged in a cutter configuration according to one or more aspects of the disclosure.', 'FIGS.', '9 and 10\n illustrate non-explosive downhole tool with penetrator heads arranged in a cutter configuration according to one or more aspects of the disclosure.', 'FIGS.', '11 to 13\n illustrate non-explosive downhole tools utilizing one-way check devices in the penetrator head according to one or more aspects of the disclosure.', 'FIGS.', '14 to 19\n illustrate non-explosive downhole tools utilizing a shifting piston disposed in a cylinder of a penetrator head to selectively open ejection ports according to one or more aspects of the disclosure.', 'FIG.', '20\n illustrate an example of a non-explosive downhole tool utilizing a plurality of non-explosive thermate charges in accordance to one or more aspects of the disclosure.\n \nFIG.', '21\n illustrates non-explosive thermate charges operationally connected with a fuse cord according to one or more aspects of the disclosure.\n \nFIG.', '22\n illustrates a non-explosive fuse cord according to one or more aspects of the disclosure.\n \nFIG.', '23\n illustrates non-explosive thermate charges including igniters according to one or more aspects of the disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements.', 'Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements.', 'Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element are may be utilized to more clearly describe some elements.', 'Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.', 'Further, as used herein, “thermite” may refer to composition that includes a metal powder fuel and a metal oxide which when ignited produces an exothermic reaction.', 'For example, in some embodiments, the thermite may take the form of a mixture of aluminum powder, and a powdered iron oxide.', 'As used herein, “thermate” may refer to a thermite with metal nitrate additives.', 'In some embodiments, a metal carbonate may be added instead of or in addition to the nitrate.', 'For example, a thermate may take the form of aluminum powder, a powdered iron oxide, and barium nitrate.', 'It should be appreciated that for both the thermate and thermite compositions, various different materials may be implemented other than the examples noted.', 'Generally, tools and techniques for forming perforations in and through casing, cement, formation rock and cutting tubulars in downhole conditions under high pressure are disclosed.', 'The downhole tool may take the form of a thermate perforating or cutting tool that operates by directing gas at high temperatures (e.g., approximately 2500-3500 degrees C. or higher) towards objects to be perforated or cut.', 'The gas is thrust outwardly from the tool under pressure and may melt, burn and/or break the objects to be cut or perforated.', 'In accordance to embodiments, the energy source material produces a gas to thrust molten metal from the tool to create the desired perforation or cutting opening.', 'In some embodiments, the tool may be used in a perforating gun or on a perforating tool string for perforating operations.', 'In some embodiments, the tool may replace a perforating gun in a perforating string.', 'The tool may be ignited at the same time as a perforating gun or at a different time from the perforating gun.', 'Additionally, it should be appreciated, that the tool may be deployed independent from a tool string or a perforating string and may be conveyed downhole via any suitable conveyance (e.g., tubing string, wireline, coiled tubing, and so on).', 'The downhole tool is both concise and reliable under high pressures and it may use the downhole wellbore pressure to help seal the tool.', 'Additionally, once the tool is open, it will not trap pressure.', 'FIGS.', '1 and 1A\n illustrate non-exclusive examples of a non-explosive downhole tool \n10\n arranged in a perforating or puncher configuration deployed in a wellbore \n12\n (i.e., borehole, well) extending from a surface \n14\n.', 'FIGS.', '2 and 2A\n illustrate non-exclusive examples of a non-explosive downhole tool \n10\n arranged in a cutter configuration deployed in a wellbore \n12\n.', 'The wellbore \n12\n may be lined with casing \n16\n.', 'In \nFIG.', '2\n, a tubular such as a tubing string \n18\n is deployed in the wellbore inside of the outer casing \n16\n.', 'The downhole tool \n10\n is illustrated deployed in the wellbore on a conveyance \n20\n, such as and without limitation, wireline and tubing.', 'With reference to \nFIGS. 1, 1A, 2 and 2A\n, the non-explosive downhole tool \n10\n generally includes a firing head \n22\n, a housing or carrier body \n24\n, an igniter \n26\n (e.g., a thermal generator) in operational contact with a non-explosive energy source \n28\n, and one or more ports \n32\n (e.g., ejection or discharge ports) for emitting a product \n34\n (e.g., hot gas and or molten material) jet of the ignited energy source \n28\n to create openings \n36\n (i.e., perforations, cuts, etc.) in one or more of the surrounding tubulars \n16\n, \n18\n and the surrounding formation \n38\n.', 'In \nFIG.', '1\n the non-explosive downhole tool \n10\n is utilized to create and opening \n36\n through the casing \n16\n and extending into the surrounding formation \n38\n.', 'When used as a puncher, the opening may be only created through an inner tubular, such as a tubing string.', 'In a perforating or puncher configuration as illustrated by way of example in \nFIGS. 1 and 1A\n, one or more ports \n32\n are selectively in communication with the energy source \n28\n and arranged in a circumferential and/or axial pattern.', 'In a cutting configuration as illustrated by way of example in \nFIGS. 2 and 2A\n, a single port \n32\n is selectively in communication with the energy source \n28\n and the single port is a 360 degree or substantially a 360 degree circumferential opening formed about the tool so that the jet cuts the surrounding tubular as illustrated in \nFIG.', '2\n.', 'In accordance to some embodiments, a cutting configuration may have multiple ports \n32\n spaced circumferentially in a manner to create a cutting type of opening \n36\n.', 'In accordance with embodiments the ports \n32\n may be selectively in communication with the energy source \n28\n, for example closed until the energy source \n28\n is ignited.', 'In \nFIGS.', '1A and 2A\n a holding element, generally identified with the numeral \n50\n, is illustrated that may maintain the ports \n32\n in a closed or blocked position until the energy source \n28\n is ignited.', 'In the examples of \nFIGS.', '1A and 2A\n the holding element \n50\n is in the form of a thin, or a weakened wall portion of the carrier body, or constructed of a material having a lower melting temperature than the carrier body \n24\n.', 'Accordingly, ignition of the energy source \n28\n will melt or otherwise eliminate or operate the holding element \n50\n to an open position.', 'Other types of holding elements may be utilized with reference to the tool \n10\n of \nFIGS.', '1A and 2A\n.', 'In the embodiments depicted in \nFIGS.', '1 and 2\n the ports \n32\n are provided with a head \n30\n, which may be referred to as a penetrator head.', 'The penetrator head \n30\n may be an independent element attached to the carrier body \n24\n at a joint \n40\n for example by threading or welding.', 'In some embodiments, the penetrator head \n30\n and the carrier body may be portions of a unitary tool body.', 'In some embodiments, the carrier body \n24\n may be smaller than the penetrator head \n30\n.', 'In some cases, the downhole tool \n10\n may be utilized to cut or perforate a large diameter tubular (e.g., casing) and the penetrator head \n30\n may be configured and dimensioned to place the head in close proximity to the tubular whereas the carrier body \n24\n may remain a standard size.', 'For example, if a 7 inch tubular (e.g., casing) is to be cut or perforated, a 6 inch penetrator head \n30\n may be coupled to a 3.5 inch carrier body \n24\n.', 'In another example, if a 9⅝ inch tubular is to be cut or perforated, an 8⅝ inch penetrator head \n30\n may be coupled with a 3.5 inch carrier body \n24\n.', 'The weight of the downhole tool \n10\n may thus be reduced.', 'It should be appreciated that although the penetrator head \n30\n is illustrated as being on the bottom of the tool \n10\n, it may be positioned at the top or any other suitable location.', 'It will also be recognized by those skilled in the art with benefit of this disclosure that multiple penetrator heads \n30\n may be installed sequentially, for example to provide a perforating cluster.', 'In accordance with one or more embodiments, the energy source \n28\n is a thermate material and it may take any suitable form and in some embodiments may take the form of a powder, or powder pellets.', 'Table 1 sets forth various possible constituent parts that may be used to create the thermate material for use in the tool.', 'The powders may generally be a fine powder and the sensitivity of the mixture may depend upon the powder mesh size.', 'As the mesh size decreases, the sensitivity increases.', 'In some embodiments, a slight over supply of metal fuel may be provided than theoretically calculated.', 'In some embodiments, the thermate material may contain between approximately 3-7 percent or more of thermite powder (e.g., approximately 5% 10%, 15%, 20% or more) and either approximately 3-7% or more (e.g., approximately 5%, 10%, 15%, 20% or more) or metal carbonate or metal nitrate.', 'The additives for binding, for example as listed in Table 1, may be in powder form or any other suitable form.', 'TABLE 1\n \n \n \n \n \n \nMetal\n \n \n \n \nPowder\n \n \n \nFuel\n \nMetal oxide\n \nMetal Carbonate\n \nMetal Nitrate\n \nAdditives\n \n \n \n \n \n \n \n \nAl, Be,\n \nBi2O3, CoO,\n \nBaCO3, CaCO3,\n \nBa(NO3)2,\n \nEpoxy, Polymer,\n \n \n \nTi, Ta,\n \nCo3O4, Cr2O3,\n \nMgCO3, K2CO3,\n \nCa(NO3)2,\n \nStarch\n \n \n \nY, Zr,\n \nCuO, Cu2O,\n \nLi2CO3, SrCO3,\n \nLiNO3 KNO3,\n \n \n \nZn, Fe,\n \nFe2O3, Fe3O4,\n \n \nMg(NO3)2,\n \n \n \nMg, Si\n \nI2O5, MnO2,\n \n \nSr(NO3)2,\n \n \n \n \nNiO, Ni2O3,\n \n \n \n \nPbO2, PbO,\n \n \n \n \nPb3O4, SnO2,\n \n \n \n \nWO2, WO3\n \n \n \n \n \n \n \n \n \n \nThe energy source or material \n28\n, e.g., a thermate material, may be referred to as the pyrotechnic or energetic material.', 'The nitrates and/or carbonates produce gas to drive molten metal, i.e., product \n34\n, out of the ports \n32\n to create the opening(s) \n36\n in the surrounding elements.', 'Upon ignition, the metal fuel reacts with the metal oxide exchanging the metal in the metal oxide, while releasing heat sufficient to melt the metal.', 'Additionally, the metal carbonate or metal nitrate decomposes into metal or metal oxide and gas.', 'For example, the reaction of aluminum and iron oxide, and the decomposition of Strontium nitrate are shown below.', 'The reaction for other compositions listed in Table 1 is similar to that shown below.', 'The reactants of oxygen can also burn aluminum or other materials.', '8AL+3Fe3O4→4AL2O3+9Fe \n Sr(NO3)2→SR+2NO2+O2', 'The chemical reactions produce high temperatures (e.g., above approximately 2500 degrees C. in some cases, such as above approximately 3000 degrees C.).', 'In a closed chamber, e.g., one mole, 211 grams of Strontium nitrate offers, 3 moles of gas which can effectively raise the pressure inside the carrier body \n24\n.', 'The molten metal may be broken down into fine drops in the high pressure and high temperature environment and a product jet \n34\n of high temperature gas with the molten metal is pushed out by the pressure to perform the cutting or perforating.', 'The molten metal may exit the tool \n10\n under pressure by gas jets shooting through ports \n32\n in the tool.', 'In some embodiments, the ports may be exposed upon formation of gas inside.', 'The product \n34\n increases the pressure inside the tool to force open the ports or translate a part of the tool to open the ports.', 'Accordingly, communication between the ports \n32\n and the energy source \n28\n may be blocked prior to ignition of the energy source \n28\n.', 'For example, hydraulic communication may be blocked between the ports \n32\n and the energy source \n28\n to seal the unignited energy source \n28\n from the wellbore environment and fluids.', 'The igniter \n26\n may take any suitable form (e.g., electric, chemical) and in one embodiment may take the form of an exploding bridgewire (EBW).', 'The EBW igniter may be one marketed and sold by Teledyne, Inc., for example an SQ-80 igniter which is a thermite filled exploding bridgewire igniter.', 'The EBW ignites the thermite in the igniter and ignites the energy source \n28\n, e.g., thermate material.', 'In some embodiments, the igniter \n26\n may be provided in multiple parts.', 'For example, the igniter \n26\n may be provided in two parts, for example the EBW and a thermite pocket, and the parts may remain separated until the downhole tool \n10\n is ready to be used at a field site.', 'Other examples of igniters \n26\n include without limitation, electrical spark and electrical match igniters that are in contact with the energy source \n28\n or in contact with a thermite material and chemical igniters.', 'Additionally, the igniter \n26\n may be positioned at any suitable position within the carrier body \n24\n.', 'For example, the igniter \n26\n may be positioned at or near the top, at or near the bottom, or any position in the middle and in contact with the energy source \n28\n.', 'If the igniter \n26\n is not embedded in the energy source material or within a distance to ignite the energy source then it may be connected by a fuse cord utilizing a non-explosive energetic material such as thermite or thermate.', 'A fuse cord may also be utilized to connect multiple tools \n10\n to fire in sequence.', 'For example with reference to \nFIG.', '1\n, a tool string may include more than one energy source \n28\n and penetrator head \n30\n section.', 'An example of a fuse cord according to embodiments disclosed herein is further described below with reference to \nFIG.', '22\n below.', 'The openings \n36\n in the surrounding elements are created by the product \n34\n jet flowing out of the tool \n10\n through the ports \n32\n.', 'The temperature of the product \n34\n may be high enough to change the steel of the surrounding tubulars from a solid phase to a liquid and possibly to a gas, while the oxygen in product \n34\n assists in burning the metal alloys.', 'When perforating, the openings \n36\n may extend into the formation similar to an explosive shaped charge jet.', 'With reference to \nFIGS.', '3 and 4\n, an energy source \n28\n is formed as pellets \n42\n, for example thermate powder pellets.', 'Pellets \n42\n maybe formed by pressing thermate material \n28\n into a thin wall tube \n44\n.', 'The tube \n44\n can be made of any suitable material such as plastic, cardboard, metal, and so forth.', 'FIG.', '4\n illustrates a top view of a pellet \n42\n in accordance with an example embodiment.', 'Various pellet shapes can be used to achieve a suitable burn at a desired burn rate.', 'In some embodiments, the pellets \n42\n may have one more holes \n46\n.', 'The holes \n46\n may be located at or near the center, or they may be distributed around the pellets \n42\n with or without a center hole.', 'With reference to \nFIGS.', '5, 6 and 8 to 10\n embodiments of a penetrator head \n30\n arranged in a cutter or cutting configuration with a port \n32\n formed as a 360 degree circumferential opening are illustrated.', 'Refer now to \nFIGS.', '5 and 6\n illustrating a non-explosive downhole tool \n10\n having a penetrator head \n30\n in accordance to one or more embodiments.', 'In \nFIG.', '5\n, penetrator head \n30\n is shown in a closed, or pre-ignition, position with communication blocked through port \n32\n between the external environment and energy source \n28\n for example by seals \n48\n (i.e., seal elements).', 'FIG.', '6\n illustrates the ejection port \n32\n opened and the hot product \n34\n jet of gas and molten metal being ejected from the penetrator head \n30\n in response to ignition of the energy source \n28\n.', 'Port \n32\n is maintained in a closed position by a holding element, generally identified with reference number \n50\n.', 'As will be understood by those skilled in the art with reference to this disclosure the holding element may take various forms and configurations.', 'With additional reference to \nFIGS.', '1 and 2\n, the port \n32\n is opened in response to the pressure of the gasses produced by ignition of the energy source \n28\n overcoming the pressure in the external environment, i.e., the wellbore \n12\n pressure, acting on the moveable body \n56\n and a preloaded force which is provided in \nFIGS.', '5, 6 and 8\n by the holding element \n50\n which is depicted as shear element (e.g., pin, screw) which identified specifically with the reference number \n49\n.', 'The penetrator head \n30\n illustrated in \nFIGS.', '5, 6 and 8 to 10\n include a diverter section \n52\n having one or more vents or channels \n54\n providing a communication path between energy source \n28\n and ejection port \n32\n. \nFIG.', '7\n illustrates a sectional view of a diverter section \n52\n of penetrator head \n30\n along the line I-I of \nFIG.', '6\n.', 'Port \n32\n is formed between the diverter section \n52\n and a moveable body \n56\n (e.g., cutter body) which is disposed with a shaft \n58\n and moveable relative to diverter section \n52\n.', 'Moveable body \n56\n is held in the closed position relative to the diverter section \n52\n by the holding element \n50\n.', 'In the embodiment of \nFIGS.', '5 and 6\n, moveable body \n56\n moves relative to or on shaft \n58\n.', 'In \nFIGS.', '5 and 6\n the holding element \n50\n is a shear member oriented generally perpendicular to the longitudinal axis of the tool and attached to the shaft \n58\n and the moveable body is located between the shear element \n50\n and the diverter section.', 'With reference to \nFIGS.', '5, 6 and 8 to 10\n a retaining member \n60\n is located, for example connected to shaft \n58\n, to maintain moveable body \n56\n in connection with the diverter section \n52\n when the port \n32\n has been opened.', 'In \nFIGS.', '5, 6 and 8', 'retaining member \n60\n is depicted as a lug connected to shaft \n58\n and positioning a retaining base \n62\n.', 'As will be understood by those skilled in the art with benefit of this disclosure, the retaining member \n60\n and retaining base \n62\n may be a single, unitary member, and or the retaining member \n60\n may directly connect the moveable body \n56\n with the shaft \n58\n.', 'The size of the ejection port \n32\n in accordance to embodiments is determined by the distance the moveable body \n56\n moves relative to the diverter section \n52\n upon actuation to the open position.', 'For example, in the embodiments of \nFIGS. 5 and 8\n, the penetrator head \n30\n is shown in a closed position with a gap \n64\n formed between the moveable body \n56\n and the retaining member base that is equivalent to the size of port \n32\n when open as illustrated for example in \nFIG.', '6\n.\n \nFIG.', '8\n illustrates a penetrator head \n30\n in a cutting configuration utilizing a holding element \n50\n, in the form of a shear member \n49\n (e.g., pin or screw), directly connecting the moveable body \n56\n with diverter section \n52\n when in the closed position.', 'Moveable body \n56\n is disposed with and moveable along shaft \n58\n in this example.', 'With reference to \nFIGS.', '2 and 5-8\n, upon activation of igniter \n26\n the energy source \n28\n, e.g., thermate material, is ignited producing high temperature and pressure product \n34\n (gas and/or molten metal) which is communicated through diverter channels \n54\n and against moveable body \n56\n.', 'When the force of the high pressure gas acting on moveable body \n56\n overcomes the force of the shear element and the wellbore pressure acting on the moveable body \n56\n, the shear element parts and releases moveable body \n56\n to move relative to diverter section \n52\n thereby opening port \n32\n.', 'As will be understood by those skilled in the art with benefit of this disclosure, holding element \n50\n may be replaced with a device other than a shear element.', 'Referring now to \nFIGS.', '9 and 10\n a penetrator head \n30\n is illustrated in a cutter configuration in which the moveable body \n56\n moves with shaft \n58\n relative to the diverter section \n52\n.', 'Shaft \n58\n extends through the diverter section \n52\n and has a piston head \n66\n connected to a first or top end \n57\n and the retaining member \n60\n and moveable body \n56\n connected proximate to the bottom end \n59\n.', 'Piston head \n66\n includes one or more pathways \n68\n to communicate the gasses produced from the ignition of the energy source \n28\n.', 'The pathways \n68\n are depicted aligned with the diverter channels \n54\n of the diverter section \n52\n for example with an anti-rotation element \n70\n connected between the diverter section and the piston head \n66\n.', 'In \nFIG.', '9\n the moveable body \n56\n is maintained in the closed position by a holding element \n50\n in the form of a ring \n51\n (e.g., C-ring) which is operationally connected between the piston head \n66\n and the diverter section \n52\n.', 'An axial gap \n64\n is provided between piston head \n66\n and the diverter section \n52\n when the moveable body is in the closed position corresponding to the size of the ejection port \n32\n when it is opened.', 'Ignition of the energy source \n28\n creates high pressure gas which acts on piston head \n66\n and urging it axially downward away from the energy source \n28\n.', 'When the downward force of piston head \n66\n overcomes the opposing force of the external pressure acting on the moveable body \n56\n and the force of holding element \n50\n, moveable body \n56\n moves opening port \n32\n and allowing the high temperature and high pressure gas to be ejected to cut, perforate or otherwise create openings.', 'In this example, the energy source pressure acting on piston head \n66\n expands the holding element \n50\n into a recess \n72\n of the diverter section allowing the piston head \n66\n and moveable body \n56\n to move.', 'In \nFIG.', '10\n the holding element \n50\n is in the form of a dissipating element \n53\n, e.g., a burn element.', 'Dissipating element \n53\n dissolves, melts, deforms or otherwise dissipates to allow the moveable body \n56\n to move from the closed to an open position.', 'For example, in \nFIG.', '10\n the dissipating element \n53\n is in the form of a standoff member, e.g, a cylindrical member or ring, disposed between the piston head \n66\n and the diverter section \n52\n.', 'Dissipating element \n53\n is formed of a material that melts, burns, deforms or otherwise degrades when exposed to the temperature and oxygen of the gas (product \n34\n) produced by the ignited energy source \n28\n which is greater than the temperature of the environmental temperature.', 'Accordingly, upon ignition of the energy material \n28\n the preload force of the dissipating element \n53\n is eliminated by the destruction or degradation of the dissipating element.', 'When the force of the pressure of the product \n34\n acting on piston head \n66\n overcomes the force of the environmental pressure acting on the moveable body \n56\n, the moveable body is displaced thereby opening the communication path between the thermate material the ejection port \n32\n.', 'Refer now to \nFIGS.', '11 to 13\n illustrating additional embodiments of non-explosive downhole tools \n10\n.', 'The penetrator heads \n30\n in \nFIGS.', '11 to 13\n may be utilized in a perforating or a cutting configuration.', 'Penetrator head \n30\n is connected to a carrier body \n24\n at a joint \n40\n.', 'Penetrator head \n30\n includes a body \n74\n that forms one or more ports \n32\n for ejecting the gas produced by the ignited energy source \n28\n.', 'Ports \n32\n are oriented radially relative to the longitudinal axis of the tool \n10\n.', 'The one or more ports \n32\n are selectively in communication with the energy source \n28\n through a channel \n54\n (e.g., a diverter channel).', 'A holding element generally denoted by the numeral \n50\n, maintains the ports \n32\n in the closed position.', 'In the embodiments of \nFIGS.', '11 to 13\n, the holding element \n50\n is illustrated in the form of one-way valves (i.e., check valves) which are specifically identified with reference number \n55\n.', 'The one-way valves \n55\n are oriented to permit the product \n34\n produced from ignition of energy source \n28\n to pass from the carrier body \n24\n through the communication path to the ejection ports \n32\n and to seal the energy source \n28\n from hydraulic communication in the direction from the environment through the ejection port \n32\n and communication path to the thermate.', 'Accordingly, the one-way valves \n55\n (i.e., moveable member, or valve member \n86\n (\nFIG.', '13\n)) are biased with a preload force to the closed position for example by a biasing element \n76\n at the surface ambient conditions.', 'When deployed in a wellbore (\nFIGS.', '1 and 2\n)', ', the wellbore pressure will reinforce the sealing of the one-way valves.', 'The one-way valves remain closed until the pressurized product of the ignited energy source \n28\n overcomes the preload force on the check valve and the environmental pressure.', 'In accordance to some embodiments the body \n74\n may be constructed of steel and the inner chambers, such as channel \n54\n (e.g., communication path), may include an inner layer or sleeve \n78\n constructed of a material having a high melting point to withstand the high temperatures of the product \n34\n.', 'For example, the inner sleeve \n78\n may be constructed of materials such as and without limitation to ceramics, graphite, carbon fiber, molybdenum, tantalum, and tungsten.', 'The inner layer \n78\n may be located proximate the ports \n32\n so that the ports \n32\n maintain their size to provide a focused product jet \n34\n.', 'The size of the ports \n32\n may dictate the performance of the penetrator head \n30\n.', 'In accordance to an embodiment, the ports \n32\n may have a diameter less than about one-inch in diameter.', 'In accordance to some embodiments, the ports \n32\n may be less than about one-half inch in diameter.', 'With reference to \nFIG.', '11\n, a one-way valve \n55\n is positioned in the communication path between each individual port \n32\n and the energy source \n28\n.', 'In the depicted example the one-way valves \n55\n seal the diverting channel \n54\n from the external environment until opened.', 'With reference to \nFIG.', '12\n, the holding element \n50\n is in the form of a single one-way valve \n55\n positioned in the channel \n54\n between the energy source \n28\n and all of the ports \n32\n.', 'In this example, the portion of the channel \n54\n downstream of the one-way valve \n55\n may be enclosed and referred to as a chamber or reservoir \n80\n.', 'The ports \n32\n are in communication with the reservoir \n80\n portion of the channel \n54\n.', 'The reservoir \n80\n is enclosed so that the hot gas is ejected through the ports \n32\n.', 'The inner layer \n78\n of high melting point material may maintain the integrity of the port \n32\n sizes.', 'The bottom end \n82\n of the body \n74\n closing the reservoir \n80\n may include an inner layer \n78\n of high melting point material or be constructed of a high melting point material.\n \nFIG.', '13\n illustrates a penetrator head \n30\n in a perforating configuration with multiple ports \n32\n oriented in a radial direction from the longitudinal axis of the tool \n10\n and spaced circumferentially and axially about the penetrator head \n30\n for example in a spiral pattern.', 'The one-way valve \n55\n is located in the channel \n54\n upstream of all of the ports \n32\n.', 'As will be understood by those skilled in the art with benefit of the disclosure the one-way valve may be arranged in various configurations.', 'In the depicted example, the biasing member \n76\n may be supported in the channel \n54\n, or the flow path of channel \n54\n, by a pin hole \n84\n such that when the high pressure product \n34\n moves the valve element \n86\n off of the valve seat the product \n34\n and any molten material can flow around the valve element \n86\n and biasing element and eject out of the ports \n32\n.', 'The channel \n54\n may be constructed of or lined with a high melting point temperature for example to maintain the size of the ports \n32\n.', 'Refer now to \nFIGS.', '14 to 19\n illustrating embodiments of a non-explosive downhole tool \n10\n utilizing a shifting piston \n88\n to selectively open the ports \n32\n of the penetrator head \n30\n to eject high pressure product \n34\n from the ignition of energy source \n28\n.', 'The penetrator head \n30\n may be arranged in a perforating configuration or in a cutter configuration, for example, with multiple ports arranged to create a substantially 360 degree opening about the penetrator head.', 'In the depicted embodiments the penetrator head \n30\n includes a body \n74\n forming a longitudinally extending cylinder \n90\n extending from a top end \n89\n to a bottom end \n91\n.', 'The shifting piston \n88\n is moveably disposed in the cylinder \n90\n.', 'The shifting piston \n88\n may include a seal \n48\n (sealing element), for example an O-ring, to provide a hydraulic seal between the shifting piston and the cylinder wall.', 'One or more radially extending ports \n32\n are formed through the body \n74\n between the cylinder \n90\n and the external environment.', 'Although not specifically illustrated in \nFIGS.', '14 to 19\n the cylinder \n90\n may constructed of or include an inner layer of a high melting material such as described with reference to \nFIGS.', '11 and 12\n.', 'The top end \n89\n of the cylinder is in communication with the energy source \n28\n in the carrier body \n24\n for example through channels \n54\n for example formed through a diverter section \n52\n of the body \n74\n.', 'In the closed position the shifting piston \n88\n is located toward the top end \n89\n of the cylinder \n90\n such that the seal \n48\n is positioned energy source \n28\n and the downstream ports \n32\n.', 'The bottom end \n91\n of the cylinder \n90\n is in communication with the external environment so that shifting piston \n88\n can move within cylinder \n90\n.', 'Shifting piston \n88\n and thus ports \n32\n are maintained in a closed position by a holding element generally identified with reference number \n50\n.', 'Referring now to \nFIGS.', '14 and 15\n in which the holding element \n50\n is in the form of a ring \n51\n (e.g., C-ring) which is operationally connected between the shifting piston \n88\n and the wall (body \n74\n) of the cylinder \n90\n.', 'In \nFIG.', '14\n, shifting piston \n88\n is in the closed position located adjacent to the top end \n89\n of the cylinder and providing a hydraulic seal, across seal element \n48\n, between the ports \n32\n and the communication channel(s) \n54\n to the energy source \n28\n.', 'In \nFIG.', '15\n the energy source \n28\n, e.g. thermate material, has been ignited producing a hot pressurized product \n34\n that acts on shifting piston \n88\n and has shifted the shifting piston \n88\n to the open position with the seal \n48\n located downstream of the ports \n32\n relative to the channels \n54\n.', 'To displace the shifting piston \n88\n the force of the product \n34\n acting on shifting piston \n88\n must overcome the force of the environmental pressure, for example the wellbore pressure in \nFIGS.', '1 and 2\n, acting on the shifting piston \n88\n and the force required to release holding element \n50\n.', 'In this example, the preloaded holding force is released upon expanding ring \n51\n into the recess \n72\n in the cylinder wall.', 'In \nFIGS.', '14 and 15\n, a base element \n92\n is positioned at the bottom end \n91\n of the cylinder \n90\n to hold the shifting piston \n88\n in the cylinder after it has been moved to the open position.', 'A vent \n94\n provides hydraulic communication between the bottom end of the cylinder and the external environment.\n \nFIG.', '16\n illustrates another embodiment of a downhole tool \n10\n and penetrator head \n30\n.', 'In this embodiment, shifting piston \n88\n is maintained in the closed position by a holding element \n50\n in the form a shear member \n49\n.', 'In this example a shear member \n49\n is connected to the shifting piston \n88\n through a shaft \n58\n which extends through the diverter section \n52\n of the body \n74\n.', 'For example, shifting piston \n88\n may be disposed in cylinder \n90\n into a closed position with the seal \n48\n located upstream of the ports \n32\n and the shaft extending through the diverter section \n52\n to the top of the penetrator head.', 'The shear element \n49\n may then connect the shaft and the shifting piston in the closed position.', 'For example, in \nFIG.', '16\n a piston head \n66\n with pathways \n68\n is positioned at the top end of the body \n74\n and connected to shaft \n58\n via the shear element \n49\n.', 'The penetrator head \n30\n can then be connected to the carrier body \n24\n.', 'After the shifting piston \n88\n is located in the cylinder a base element \n92\n, with a vent \n94\n, may be connected to block the bottom end \n91\n of the cylinder to contain the shifting piston when it is released from the shear element \n49\n.', 'An anti-rotation member \n70\n is depicted connecting piston head \n66\n with body \n74\n such that the pathways \n68\n are aligned and in communication with the channels \n54\n.', 'With reference to \nFIGS.', '1 and 2\n, downhole tool \n10\n is disposed in a wellbore in a closed position as illustrated in \nFIG.', '16\n.', 'Upon ignition of the energy source \n28\n a hot and high pressure product \n34\n is produced and communicated through channels \n54\n to cylinder \n90\n exert a downward force on the shifting piston.', 'When the downward force overcomes the force from the wellbore pressure acting on the shifting piston and the preload force of the shear member \n49\n (i.e., holding element \n50\n) the shear member is parted and the shifting piston moves to an open position allowing the high pressure product \n34\n to be ejected out of the ports \n32\n to create an opening \n36\n for example in the form of perforations or a cut.', 'FIG.', '17\n illustrates a downhole tool \n10\n and penetrator head \n30\n utilizing a holding element \n50\n in the form of a dissipating element \n53\n to selectively maintain the shifting piston \n88\n in a closed position with a preloaded force.', 'Similar to \nFIGS.', '10 and 16\n, a piston head \n66\n is located above the diverter section \n52\n and connected to the shifting piston \n88\n by a shaft \n58\n.', 'An anti-rotation member \n70\n may maintain pathways \n68\n of the piston head \n66\n aligned with the diverter channels \n54\n.', 'Dissipating element \n53\n dissolves, melts, deforms or otherwise dissipates to allow the moveable body \n56\n to move from the closed to an open position.', 'For example, in \nFIG.', '16\n the dissipating element \n53\n is in the form of a standoff member disposed between the piston head \n66\n and the diverter section \n52\n of the body \n74\n.', 'Dissipating element \n53\n is formed of a material that melts or deforms when exposed to the temperature of the product \n34\n produced by the ignited energy source \n28\n which is greater than the temperature of the environmental temperature.', 'Accordingly, upon ignition of the energy material \n28\n the preload force of the dissipating element \n53\n is eliminated by the destruction, or deformation, of the dissipating element.', 'When the force of the pressure of the product \n34\n acting on the shifting piston and piston head overcomes the force of the environmental pressure action on the shifting piston \n88\n, the shifting piston is moved to the open position with the seal \n48\n downstream of ports \n32\n.', 'In \nFIG.', '17\n, the bottom end \n91\n is illustrated as open as the shifting piston \n88\n is held in the cylinder by the connection of the shifting piston to the piston head \n66\n for example by a connector \n96\n, for example a bolt.\n \nRefer now to \nFIGS.', '18 and 19\n which illustrate embodiments of a downhole tool \n10\n and penetrator head \n30\n that utilize holding element \n50\n in the form of a ring \n51\n (e.g., C-ring) to hold the shifting piston in the closed position under a preload force.', 'In each of the embodiments the shifting piston \n88\n is connected to a piston head \n66\n disposed upstream of the diverter section \n52\n and channels \n54\n thereby maintaining the shifting piston in the cylinder \n90\n after it has been released from the holding element and moved to the open position.', 'In \nFIG.', '18\n, the ring type holding element \n50\n, \n51\n is connected between the piston head \n66\n and the body \n74\n above the diverter section \n52\n and channels \n54\n.', 'In \nFIG.', '19\n the ring type holding element \n51\n is connected between the shifting piston \n88\n and the cylinder wall (i.e., body \n74\n).', 'When the downward force on the shifting piston \n88\n overcomes the force from the environmental pressure and the preload force, the ring type holding member is expanded into the recess \n72\n and releasing shifting piston \n88\n to move to the open position.', 'Refer now to \nFIGS.', '20 to 23\n illustrating various aspects of a non-explosive downhole tool \n10\n.', 'FIG.', '20\n illustrates an example of a downhole tool \n10\n arranged as a perforating or puncher type of tool.', 'The depicted downhole tool \n10\n comprises a plurality of thermate penetrator heads, generally identified with the numeral \n30\n and identified specifically with the number \n98\n.', 'The thermate penetrator heads \n30\n, \n98\n are located on a loading tube \n100\n in a desired axial and or circumferential pattern.', 'In the embodiment of \nFIG.', '20\n the loading tube is disposed in a carrier body \n24\n.', 'Examples of thermate penetrator heads \n30\n, \n98\n are described with reference to \nFIGS.', '21 and 23\n below.', 'The tool \n10\n is conveyed on a conveyance \n20\n, e.g. wireline or tubing, into a wellbore for example as illustrated in \nFIGS.', '1 and 2\n.', 'The non-explosive downhole tool \n10\n includes a firing head \n22\n and an igniter \n26\n.', 'The igniter \n26\n may be initiated for example in response to an electrical signal which may be transmitted via conveyance \n20\n.', 'Each of the thermate penetrator heads \n30\n, \n98\n may be positioned adjacent to a respective scallop \n102\n formed in the carrier body \n24\n.', 'A single fuse cord \n104\n, comprising thermite or thermate', ', interconnects all of the thermate penetrator heads \n30\n, \n98\n to a single igniter \n26\n.', 'As will be understood by those skilled in the art with benefit of this disclosure, tool \n10\n may be constructed and utilized without a carrier body \n24\n (e.g., gun carrier).', 'Upon ignition of the thermate penetrator heads \n30\n, \n98\n a product \n34\n jet is discharged radially from the tool \n10\n.', 'The product \n34\n jet may include gas and a molten metal for example from the thermate chemical reaction and from the melting of the carrier body \n24\n at scallops \n102\n.', 'With reference to \nFIGS.', '21 and 23\n the thermate penetrator heads \n30\n, \n98\n comprise a casing or housing \n106\n filled with a thermate material as the energy source \n28\n.', 'The housing \n106\n comprises a discharge or ejection port \n32\n and an ignition point \n110\n opposite the ejection port \n32\n.', 'The ejection port \n32\n may be closed by a holding mechanism, for example a weakened portion of the housing, prior to igniting the thermate charge.', 'Similarly, the ignition point may be a weakened portion of the housing or an opening.', 'In \nFIG.', '21\n the thermate penetrator heads \n30\n, \n98\n are ignited by a thermate or thermite fuse cord \n104\n that is disposed adjacent to the ignition point \n110\n which in this example is a thin-wall section of the housing.', 'The high temperature of the ignited fuse cord \n104\n will ignite the thermate energy source \n28\n which will produce molten metal that is ejected with a gas jet through the ejection port \n32\n.', 'An example of a fuse cord \n104\n is described with reference to \nFIG.', '22\n.', 'Fuse cord \n104\n includes a sleeve \n112\n filled with thermite or thermate, which is generally identified with the numeral \n114\n.', 'The material \n114\n may be the same material that is used for the energy source \n28\n.\n \nFIG.', '23\n illustrates the thermate or thermite fuse cord replaced with an ignition line \n116\n, i.e., an electric line.', 'In this example, each of the thermate penetrator heads \n30\n, \n98\n includes an igniter \n26\n that is located at the ignition point \n110\n.', 'The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure.', 'Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the disclosure.', 'The scope of the invention should be determined only by the language of the claims that follow.', 'The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group.', 'The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.', 'Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.'] | ['1.', 'A non-explosive downhole cutting or perforation tool for creating openings in tubulars and or earthen formations, the tool comprising:\na carrier holding a thermate material;\nan igniter in operational contact with the thermate material;\na head connected with the carrier and having a port to eject a product produced from ignition of the thermate material and a communication path extending from the thermate material to the port; and\na one-way valve in a closed position blocking the communication path and in an open position opening the communication path, wherein the one-way valve is operated from the closed position to the open position in response to ignition of the thermate material.', '2.', 'The tool of claim 1, comprising a holding element applying a preload force to a moveable member of the one-way valve.', '3.', 'The tool of claim 1, comprising a holding element applying a preload force to a moveable member of the one-way valve, wherein the holding element comprises one of a shear member, a C- ring, a biasing element and a dissipating element.', '4.', 'The tool of claim 1, wherein the head has a larger outside diameter than the carrier.', '5.', 'The tool of claim 1, wherein the port forms substantially a 360 degree opening.', '6.', 'The tool of claim 1, where the head comprises two or more ports arranged circumferentially and or axially relative to one another.', '7.', 'The tool of claim 1, wherein the port is a substantially 360 degree opening formed between the moveable member in the open position and a first body of the head.', '8.', 'The tool of claim 7, comprising a holding element applying a preload force to a moveable member of the one-way valve, wherein the holding element is one of a dissipating member and a c-ring.', '9.', 'The tool of claim 7, comprising a shear member connected between the first body and the head when in the closed position.', '10.', 'The tool of claim 1, wherein the one-way valve comprises a piston disposed in an axial cylinder in the communication path.', '11.', 'The tool of claim 10, comprising a dissipating element applying a preload force to hold the piston in the closed position, wherein the dissipating element degrades in response to exposure to the product.', '12.', 'The tool of claim 10, comprising a holding element applying a preload force to maintain the piston in the closed position, the holding element comprising one of a shear member and a c-ring.', '13.', 'A method of creating an opening in a tubular, comprising:\ndisposing a non-explosive cutting or perforation tool in a tubular in a wellbore, the tool comprising a thermate material, a one-way valve, and an ejection port;\nigniting the thermate material;\noperating the one-way valve in response to a product produced by the ignited thermate material;\nopening the port by operating the one-way valve; and\ndirecting the product through the port and onto the tubular thereby creating an opening in the tubular.', '14.', 'The method of claim 13, wherein the port is a substantially 360 degree opening.\n\n\n\n\n\n\n15.', 'The method of claim 13, wherein the opening the port comprises axially moving a moveable member of the one-way valve relative to a first body, wherein the open port is a substantially 360 degree opening.\n\n\n\n\n\n\n16.', 'The method of claim 13, wherein the opening the port comprises displacing a moveable member of the one-way valve disposed in a communication path between the port and the thermate material.', '17.', 'A non-explosive downhole tubular cutter, the cutter comprising:\na carrier body holding a thermate material;\na head connected to the carrier body and comprising a diverter section and a body axially moveable relative to the diverter section from a closed position in contact with the diverter section to an open position forming a 360 degree port between the body and the diverter section in response to ignition of the thermate material, the head having a larger outside diameter than the carrier body, wherein the body is part of a one-way valve; and\na channel extending through the diverter section from the thermate material to the port.', '18.', 'The cutter of claim 17, comprising a holding element connected between the diverter section and the body to apply a preload force to urge the body to the closed position.'] | ['FIGS. 1 and 1A illustrate a non-explosive downhole tool arranged in a perforating or puncher configuration according to one or more aspects of the disclosure disposed in a wellbore.; FIGS. 2 and 2A illustrate a non-explosive downhole tool arranged in a cutter configuration according to one or more aspects of the disclosure disposed in a wellbore.; FIGS. 3 and 4 illustrate an embodiment of a non-explosive energy source in the form of a thermate pellet according to one or more aspects of the disclosure.; FIGS. 5 and 6 illustrate a non-explosive downhole tool having a penetrator head arranged in a cutter configuration according to one or more aspects of the disclosure.', '; FIG.', '7 illustrates a diverter section of a penetrator head in accordance to one or more aspects of the disclosure along a line I-I of FIG.', '6.; FIG. 8 illustrates a penetrator head arranged in a cutter configuration according to one or more aspects of the disclosure.; FIGS. 9 and 10 illustrate non-explosive downhole tool with penetrator heads arranged in a cutter configuration according to one or more aspects of the disclosure.; FIGS.', '11 to 13 illustrate non-explosive downhole tools utilizing one-way check devices in the penetrator head according to one or more aspects of the disclosure.; FIGS.', '14 to 19 illustrate non-explosive downhole tools utilizing a shifting piston disposed in a cylinder of a penetrator head to selectively open ejection ports according to one or more aspects of the disclosure.; FIG.', '20 illustrate an example of a non-explosive downhole tool utilizing a plurality of non-explosive thermate charges in accordance to one or more aspects of the disclosure.', '; FIG.', '21 illustrates non-explosive thermate charges operationally connected with a fuse cord according to one or more aspects of the disclosure.;', 'FIG.', '22 illustrates a non-explosive fuse cord according to one or more aspects of the disclosure.', '; FIG.', '23 illustrates non-explosive thermate charges including igniters according to one or more aspects of the disclosure.; FIGS. 1 and 1A illustrate non-exclusive examples of a non-explosive downhole tool 10 arranged in a perforating or puncher configuration deployed in a wellbore 12 (i.e., borehole, well) extending from a surface 14.', 'FIGS.', '2 and 2A illustrate non-exclusive examples of a non-explosive downhole tool 10 arranged in a cutter configuration deployed in a wellbore 12.', 'The wellbore 12 may be lined with casing 16.', 'In FIG.', '2, a tubular such as a tubing string 18 is deployed in the wellbore inside of the outer casing 16.', 'The downhole tool 10 is illustrated deployed in the wellbore on a conveyance 20, such as and without limitation, wireline and tubing.', '; FIG.', '8 illustrates a penetrator head 30 in a cutting configuration utilizing a holding element 50, in the form of a shear member 49 (e.g., pin or screw), directly connecting the moveable body 56 with diverter section 52 when in the closed position.', 'Moveable body 56 is disposed with and moveable along shaft 58 in this example.; FIG. 13 illustrates a penetrator head 30 in a perforating configuration with multiple ports 32 oriented in a radial direction from the longitudinal axis of the tool 10 and spaced circumferentially and axially about the penetrator head 30 for example in a spiral pattern.', 'The one-way valve 55 is located in the channel 54 upstream of all of the ports 32.', 'As will be understood by those skilled in the art with benefit of the disclosure the one-way valve may be arranged in various configurations.', 'In the depicted example, the biasing member 76 may be supported in the channel 54, or the flow path of channel 54, by a pin hole 84 such that when the high pressure product 34 moves the valve element 86 off of the valve seat the product 34 and any molten material can flow around the valve element 86 and biasing element and eject out of the ports 32.', 'The channel 54 may be constructed of or lined with a high melting point temperature for example to maintain the size of the ports 32.; FIG.', '16 illustrates another embodiment of a downhole tool 10 and penetrator head 30.', 'In this embodiment, shifting piston 88 is maintained in the closed position by a holding element 50 in the form a shear member 49.', 'In this example a shear member 49 is connected to the shifting piston 88 through a shaft 58 which extends through the diverter section 52 of the body 74.', 'For example, shifting piston 88 may be disposed in cylinder 90 into a closed position with the seal 48 located upstream of the ports 32 and the shaft extending through the diverter section 52 to the top of the penetrator head.', 'The shear element 49 may then connect the shaft and the shifting piston in the closed position.', 'For example, in FIG.', '16 a piston head 66 with pathways 68 is positioned at the top end of the body 74 and connected to shaft 58 via the shear element 49.', 'The penetrator head 30 can then be connected to the carrier body 24.', 'After the shifting piston 88 is located in the cylinder a base element 92, with a vent 94, may be connected to block the bottom end 91 of the cylinder to contain the shifting piston when it is released from the shear element 49.', 'An anti-rotation member 70 is depicted connecting piston head 66 with body 74 such that the pathways 68 are aligned and in communication with the channels 54.', 'With reference to FIGS.', '1 and 2, downhole tool 10 is disposed in a wellbore in a closed position as illustrated in FIG.', '16.', 'Upon ignition of the energy source 28 a hot and high pressure product 34 is produced and communicated through channels 54 to cylinder 90 exert a downward force on the shifting piston.', 'When the downward force overcomes the force from the wellbore pressure acting on the shifting piston and the preload force of the shear member 49 (i.e., holding element 50) the shear member is parted and the shifting piston moves to an open position allowing the high pressure product 34 to be ejected out of the ports 32 to create an opening 36 for example in the form of perforations or a cut.; FIG.', '17 illustrates a downhole tool 10 and penetrator head 30 utilizing a holding element 50 in the form of a dissipating element 53 to selectively maintain the shifting piston 88 in a closed position with a preloaded force.', 'Similar to FIGS.', '10 and 16, a piston head 66 is located above the diverter section 52 and connected to the shifting piston 88 by a shaft 58.', 'An anti-rotation member 70 may maintain pathways 68 of the piston head 66 aligned with the diverter channels 54.; FIG.', '23 illustrates the thermate or thermite fuse cord replaced with an ignition line 116, i.e., an electric line.', 'In this example, each of the thermate penetrator heads 30, 98 includes an igniter 26 that is located at the ignition point 110.'] |
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US11091689 | Emulsions containing water-soluble acid retarding agents and methods of making and using | Aug 30, 2016 | Christopher Daeffler, Mohan Kanaka Raju Panga | Schlumberger Technology Corporation | International Search Report and Written Opinion issued in International Patent Appl. No. PCT/US2016/49335 dated Nov. 17, 2016; 9 pages.; Bonn, M.; Bakker, H. J.; Rago, G.; Pouzy, F.; Siekierzycka, J. R.; Brouwer, A. M.; Bonn, D. “Suppression of Proton Mobility by Hydrophobic Hydration” J. Am. Chem. Soc. 2009, 131, 17070-17071.; Xu, J.; Yamashita, T.; Agmon, N.; Voth, G. A. On the Origin of Proton Mobility Suppression in Aqueous Solutions in Amphiphiles. J. Phys. Chem. B. 2013, 117, 15426-15435.; Crowe, C.W.; McGowan, G. R.; Baranet, S. E. “Investigation f Retarded Acids Provides Better Understanding of Their Effectiveness and Potential Benefits”, SPE 18222, SPE Production Engineering, May 1990, pp. 166-170.; Scherubel, G. A; Crowe, C. 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2015; Lien et al.; 20150240147; August 27, 2015; Jiang et al.; 20160298024; October 13, 2016; Panga et al. | 2247833; March 2005; RU; 00019062; April 2000; WO; 0019062; April 2000; WO; 2004005672; January 2004; WO; 2011148282; December 2011; WO; 2015020688; February 2015; WO | ['Described herein is a multi-phase aqueous composition containing a surfactant; a first phase comprising water, an acid, and a water-soluble acid retarding agent; and a second phase selected from the group consisting of an immiscible organic phase, a gas, and combinations thereof.', 'Further described are methods of making and using such compositions.'] | ['Description\n\n\n\n\n\n\nRELATED APPLICATION INFORMATION', 'This application claims the benefit of U.S. Provisional Application Ser.', 'No. 62/213,986 filed Sep. 3, 2015, which is incorporated herein in its entirety.', 'FIELD', 'The disclosure relates to emulsions and/or foams containing water-soluble acid retarding agents, and to methods of making and using.', 'Such emulsions and/or foams including acid-in-oil (A/O) or oil-in-acid (O/A) emulsions.', 'BACKGROUND\n \nThis section provides background information to facilitate a better understanding of the various aspects of the disclosure.', 'It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.', 'Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, commonly referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation.', 'Once a wellbore is drilled, various forms of well completion components may be installed in order to control and enhance the efficiency of producing the various fluids from the reservoir.', 'Well treatment methods often are used to increase hydrocarbon production by using a chemical composition, such as a treatment fluid.', 'Stimulation operations may be performed to facilitate production of fluids from subsurface formations by increasing the net permeability of a reservoir.', 'There are two main stimulation techniques: matrix stimulation and fracturing.', 'Matrix stimulation is accomplished, typically in sandstone rich formations, by injecting a fluid (e.g., acid or solvent) to dissolve and/or disperse materials that impair well production.', 'Specifically, matrix stimulation may be performed (1) by injecting chemicals into the wellbore to react with and dissolve the damage and (2) by injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (e.g., instead of removing the damage, redirecting the migrating oil around the damage).', 'Fracturing involves injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel through which hydrocarbon can more readily move from the formation and into the wellbore.', 'In carbonate formations, the goal of matrix stimulation is to create new, unimpaired flow channels from the formation to the wellbore.', 'Matrix stimulation, typically called matrix acidizing when the stimulation fluid is an acid, generally is used to treat the near-wellbore region.', 'In a matrix acidizing treatment, the acid used (for example hydrochloric acid for carbonates) is injected at a pressure low enough to prevent formation fracturing.', 'When injected at low rates into carbonate formations, the acid can form conductive wormholes that extend radially from the wellbore.', 'Acids can also be injected into subterranean formation at rates high enough to cause fracturing.', 'In this case, the acid unevenly dissolves the walls of the fracture, so that when the injection is stopped and the fracture closes, conductive channels to the well remain.', 'One of the problems often encountered in the application of acids, especially inorganic acids, at elevated carbonate reservoir temperatures, is their excessive reaction rate toward carbonate originating from a lack of restriction to the mobility of the protons.', 'For example, HCl is very reactive, and at higher temperatures (such as 200° F. and higher) and/or low injection rates, favors facial dissolution over wormholing.', 'For this reason, less reactive acid formulations have been pursued.', 'One approach is to use organic acids such as formic and acetic acid.', "Organic acids have higher pK\na\n's than HCl, but will not completely spend in the reservoir.", 'Numerous approaches have been applied toward retarding the acid reactivity, mainly via physical means.', 'For example, it is common in oilfield operations to encapsulate inorganic acid into shells of polymer gel, linear or crosslinked, or light oils in the presence of surfactant and/or chelating agent.', 'Each of these options offers a certain level of performance, but at the same time brings several undesirable side effects.', 'At present, acid treatments are plagued by two primary limitations namely, limited radial penetration and severe corrosion to pumping and wellbore tubing.', 'Both effects are associated with the higher-than-desired reaction rate (or spending rate) of inorganic acids, such as HCl, toward carbonate surface, in particular at higher temperatures.', 'Limitations on radial penetration are caused by the fact that as soon as the acid, in particular inorganic acids, such as by nonlimiting example, HCl, is introduced into the formation or wellbore, it reacts instantaneously with the formation matrix and/or the wellbore scaling.', 'In practice, the dissolution is so rapid that the injected acid is spent by the time it reaches no more than a few inches beyond the wellbore, incapable of generating much desired fracture length far from the wellbore.', 'Organic acids (e.g., formic acid, acetic acid and/or lactic acid and its polymeric version) are sometimes used to address limitations on radial penetration since organic acids react more slowly than inorganic acids.', 'Increasingly, retarded acid systems, which use techniques such as gelling the acid or oil-wetting the formation, are used.', 'Each of such alternatives, however, has associated drawbacks and is an imperfect solution to limited radial penetration.', 'Other limitations related to the use of acids are: 1) very high miscibility of acids with water when the potential for undesirable migration of the acid-bearing fluid into a water-saturated zone is a concern; and 2) iron precipitation, especially in sour wells, where the iron sulfide scale formed in boreholes, tubulars, and/or formations is dissolved by the acid with the formation of hydrogen sulfide (H\n2\nS) and undesirable iron precipitates such as ferric hydroxide or ferrous sulfide that affect the permeability of the formation.', 'Therefore, acid treatment fluids often contain additives to minimize iron precipitation and H\n2\nS evolution, for example by sequestering the iron ions in solution, or by reducing ferric ions to the more soluble ferrous form of iron.', 'The performance of a fracture acidizing treatment job may be measured by the length of the fracture that is effectively acidized.', 'The distance a reactive acid travels along the fracture (e.g., acid penetration depth), is governed by the acid flow (injection) rate and the acid reaction (spending) rate at the rock surface.', 'In most of the circumstances encountered in acid treatment, the reaction rate between acid and rock is very fast, and the rate determining step is acid mass transfer from bulk to rock surface.', 'In fracture acidizing, the treatment fluid used is injected at a pressure high enough to cause formation fracturing, designed to open sustained flowpath network that connects limestone and/or dolomite reservoirs to the wellbore.', 'In order to achieve deeper penetration in fracture acidizing, it is often desirable to retard the acid in such treatments as well.', 'Common approaches to acid retardation for fracture acidizing include gelling and to a minor extent chemical intervention.', 'Each of these methodologies brings certain advantages that are invariably accompanied by a set of disadvantages.', 'For example, gelled acids provide moderate retardation in the temperature range of 80 to 200° F.', 'As gels exhibit high viscosity and low friction loss, they function primarily as diverting agents, contributing to fluid loss reduction.', 'It is also common practice to retard acid using surfactants, although limited acid retardation is obtained.', 'However, the deployment of surfactant alone also carries a few unwanted effects.', 'For example, it could strip any existing coating on carbonate surfaces and as such act as an accelerator.', 'Therefore, retardation schemes relying on surfactant films are often unreliable and ineffective.', 'Furthermore, the attempt to use biodegradable, solid acid precursors such as polylactic acid in acidizing treatments has been plagued by the intrinsic disadvantage of very small acid capacity, leading to prohibitive costs and cumbersome dependency on formation temperature range which governs the rate of degradation.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'In a first aspect of the disclosure, a multi-phase aqueous composition(s) include: a surfactant; a first phase including water, an acid, and a water-soluble acid retarding agent; and a second phase selected from the group consisting of an immiscible organic phase, a gas, and combinations thereof.', 'In another aspect of the disclosure, method(s) include treating a subterranean formation fluidly coupled to a wellbore with a treatment fluid including the multi-phase aqueous composition.', 'In another aspect of the disclosure, method(s) include: treating a subterranean formation fluidly coupled to a wellbore with a treatment fluid including a multi-phase aqueous composition containing: \n \na surfactant including a foaming agent;\n \na first phase including water, an acid, and a water-soluble acid retarding agent; and\n \na second phase including a gas selected from the group consisting of nitrogen, carbon dioxide, oxygen, helium, argon, hydrogen, methane or ethane, or a combination thereof; wherein the multi-phase aqueous composition is in the form of a foam.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nCertain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements.', 'It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:\n \nFIG.', '1\n depicts an example of equipment used to treat a wellbore and/or a formation fluidly coupled to the wellbore according to some embodiments of the disclosure;\n \nFIG.', '2\n shows pore volumes to break through versus interstitial velocity curves for aqueous acid solutions based upon tests performed at 70° F., according to the disclosure;\n \nFIG.', '3\n shows pore volumes to break through versus interstitial velocity curves for aqueous acid solutions based upon tests performed at 200° F., according to the disclosure;\n \nFIGS.', '4A-4E\n depict face dissolution of core samples evaluated in accordance with the disclosure; and,\n \nFIG.', '5\n shows calcium generation concentration versus time curves for some aqueous acid solutions evaluated, according to the disclosure.', 'DETAILED DESCRIPTION', 'The following description of the variations is merely illustrative in nature and is in no way intended to limit the scope of the disclosure, its application, or uses.', 'The description and examples are presented herein solely for the purpose of illustrating the various embodiments of the disclosure and should not be construed as a limitation to the scope and applicability of the disclosure.', 'While the compositions of the present disclosure are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials.', 'In addition, the composition can also comprise some components other than the ones already cited.', 'In the summary of the disclosure and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context.', 'Also, in the summary of the disclosure and this detailed description, it should be understood that a concentration or amount range listed or described as being useful, suitable, or the like, is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated.', 'For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10.', 'Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors had possession of the entire range and all points within the range.', 'Unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or.', 'For example, a condition A or B is satisfied by anyone of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).', 'In addition, use of the “a” or “an” are employed to describe elements and components of the embodiments herein.', 'This is done merely for convenience and to give a general sense of concepts according to the disclosure.', 'This description should be read to include one or at least one and the singular also includes the plural unless otherwise stated.', 'The terminology and phraseology used herein is for descriptive purposes and should not be construed as limiting in scope.', 'Language such as “including,” “comprising,” “having,” “containing,” or “involving,” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited.', 'Also, as used herein any references to “one embodiment” or “an embodiment” means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment.', 'The appearances of the phrase “in one embodiment” in various places in the specification are not necessarily referring to the same embodiment.', 'The terms “formation” or “subterranean formation” as utilized herein should be understood broadly, and are used interchangeably.', 'A formation includes any underground fluidly porous formation, and can include without limitation any oil, gas, condensate, mixed hydrocarbons, paraffin, kerogen, water, and/or CO\n2 \naccepting or providing formations.', 'A formation can be fluidly coupled to a wellbore, which may be an injector well, a producer well, and/or a fluid storage well.', 'The wellbore may penetrate the formation vertically, horizontally, in a deviated orientation, or combinations of these.', 'The formation may include any geology, including at least a sandstone, limestone, dolomite, shale, tar sand, and/or unconsolidated formation.', 'The wellbore may be an individual wellbore and/or a part of a set of wellbores directionally deviated from a number of close proximity surface wellbores (e.g. off a pad or rig) or single initiating wellbore that divides into multiple wellbores below the surface.', 'The term “oilfield treatment fluid” as utilized herein should be understood broadly.', 'In certain embodiments, an oilfield treatment fluid includes any fluid having utility in an oilfield type application, including a gas, oil, geothermal, or injector well.', 'In certain embodiments, an oilfield treatment fluid includes any fluid having utility in any formation or wellbore described herein.', 'In certain embodiments, an oilfield treatment fluid includes a matrix acidizing fluid, a wellbore cleanup fluid, a pickling fluid, a near wellbore damage cleanup fluid, a surfactant treatment fluid, an unviscosified fracture fluid (e.g. slick water fracture fluid), and/or any other fluid consistent with the fluids otherwise described herein.', 'An oilfield treatment fluid may include any type of additive known in the art, which are not listed herein for purposes of clarity of the present description, but which may include at least friction reducers, inhibitors, surfactants and/or wetting agents, fluid diverting agents, particulates, acid retarders (except where otherwise provided herein), organic acids, chelating agents, energizing agents (e.g. CO\n2 \nor N\n2\n), gas generating agents, solvents, emulsifying agents, flowback control agents, resins, breakers, and/or non-polysaccharide based viscosifying agents.', 'The term “high pressure pump” as utilized herein should be understood broadly.', 'In certain embodiments, a high pressure pump includes a positive displacement pump that provides an oilfield relevant pumping rate—for example at least 0.5 barrels per minute (bpm), although the specific example is not limiting.', 'A high pressure pump includes a pump capable of pumping fluids at an oilfield relevant pressure, including at least 500 psi, at least 1,000 psi, at least 2,000 psi, at least 5,000 psi, at least 10,000 psi, up to 15,000 psi, and/or at even greater pressures.', 'Pumps suitable for oilfield cementing, matrix acidizing, and/or hydraulic fracturing treatments are available as high pressure pumps, although other pumps may be utilized.', 'The term “treatment concentration” as utilized herein should be understood broadly.', 'A treatment concentration in the context of an HCl concentration is a final concentration of the fluid before the fluid is positioned in the wellbore and/or the formation for the treatment, and can be any concentration necessary to provide sufficient acidic function.', 'The treatment concentration may be the mix concentration available from the HCl containing fluid at the wellsite or other location where the fluid is provided from.', 'The treatment concentration may be modified by dilution before the treating and/or during the treating.', 'Additionally, the treatment concentration may be modified by the provision of additives to the fluid.', 'In certain embodiments, a treatment concentration is determined upstream of additives delivery (e.g. at a blender, hopper, or mixing tub) and the concentration change from the addition of the additives is ignored.', 'In certain embodiments, the treatment concentration is a liquid phase or acid phase concentration of a portion of the final fluid—for example when the fluid is an energized or emulsified fluid.', 'Multi-phase aqueous compositions described below and useful in accordance with the disclosure exhibit a retarded acid reactivity that facilitates greater depth of fracture and/or matrix acidizing.', 'The multi-phase aqueous composition can comprise, consist of, or consist essentially of: a surfactant; a first phase comprising water, an acid, and a water-soluble acid retarding agent; and a second phase selected from the group consisting of an immiscible organic phase, a gas, and combinations thereof.', 'The acid in the first phase can be selected from the group consisting of hydrochloric acid (HCl), nitric acid, phosphoric acid, sulfuric acid, hydrofluoric acid, hydrobromic acid, perchloric acid, hydrogen iodide, alkanesulfonic acids, arylsulfonic acids, acetic acid, formic acid, alkyl carboxylic acids, acrylic acid, lactic acid, glycolic acid, malonic acid, fumaric acid, citric acid, tartaric acid, or their derivatives, and mixtures thereof.', 'Generally, an acid is transported to a wellsite.', 'According to some embodiments, the acid is present in the multi-phase aqueous compositions in an amount up to about 36 wt %, or from about 7.5 to about 36 wt %, or from about 7.5 to about 28 wt %, or from about 7.5 to about 20 wt %, based on the total weight of the composition.', 'In some other embodiments, acid is present in the multi-phase aqueous compositions in an amount of at least about 37 wt %,', 'In some embodiments, an acid that has shown particular utility in the multi-phase aqueous composition(s) according to the disclosure is hydrochloric acid.', 'In some other embodiments, the multi-phase aqueous composition may include an amount of hydrofluoric acid (HF).', 'HF exhibits distinct reactions from HCl, and is useful in certain applications to enhance the activity of the resulting multi-phase aqueous solution.', 'For example, HF is utilized in the cleanup of sandstone formations where HCl alone is not effective for removing certain types of formation damage.', 'It is believed that the present multi-phase aqueous solution will have effects with HF similarly to the observed effects with HCl.', 'Accordingly, multi-phase solutions can be formulated with a total acid amount that is much higher than presently attainable formulations.', 'In yet another embodiment, the HF is present in the multi-phase aqueous composition in an amount of at least 0.25% by weight.', 'The HF may be present in addition to the amount of HCl, and/or as a substitution for an amount of the HCl.', 'The water-soluble acid retarding agent has utility in retarding the rate at which the acid solution reacts with carbonate-mineral, or other surfaces inside the formation.', 'Thus, the water-soluble acid retarding agent may slow the reactivity of the acid towards the carbonate-mineral surfaces, without compromising its acid capacity.', 'Such retardation is useful in the context of stimulating or improving production from subterranean formations that contain hydrocarbons, steam, geothermal brines and other valuable materials as known in the art.', 'Slowing the rate of reaction may allow deeper penetration of the acid into the subterranean formations than regular acid, thereby increasing the formation permeability and productivity.', 'Water-soluble acid retarding agents, as used herein, includes any water-soluble material that reduces acid activity through a mechanism other than mere dilution.', 'The water-soluble retarding agents of the first phase can be selected from the group consisting of a salt, urea or one if its derivatives, an alpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol with one to five carbons, a surfactant having a structure in accordance with Formula I, and combinations thereof:\n \n \n \n \nin which R\n1 \nis a hydrocarbyl group that may be branched or straight chained, aromatic, aliphatic or olefinic and contains from about 1 to about 26 carbon atoms and may include an amine; R\n2 \nis hydrogen or an alkyl group having from 1 to about 4 carbon atoms; R\n3 \nis a hydrocarbyl group having from 1 to about 5 carbon atoms; and Y is an electron withdrawing group.', 'Such salt(s) can comprise: i) a cation selected from the group consisting of lithium, sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium, strontium, barium, scandium, yttrium, titanium, zirconium, hafnium, vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium, nickel, palladium, platinum, copper, silver, gold, zinc, cadmium, mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium, alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium, and combinations thereof; and \n \nii) an anion selected from the group consisting of fluoride, chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfite nitrate, alkanesulfonates, arylsulfonates, acetate, formate, and combinations thereof.', 'The amount of water-soluble acid retarding agent(s) present in the composition can be any concentration necessary to provide sufficient acid retardation function.', 'According to the present embodiments, the water-soluble acid retarding agent(s) is added to the first phase of the multi-phase aqueous composition in an amount up to its solubility limit in the first phase.', 'According to some embodiments, the water-soluble acid retarding agent is present in the multi-phase aqueous compositions in an amount of up to about 40 wt %, from about 1 to about 40 wt %, from about 5 to about 35 wt %, or from about 5 to about 20 wt %, based on the total weight of the multi-phase aqueous composition.', 'In some embodiments, the first phase of the multi-phase aqueous composition may include HCl as the acid in a weight fraction exceeding 37%, based on the total weight of the composition.', 'The water-soluble acid retarding agent present in some multi-phase aqueous compositions useful in accordance with the disclosure allows the HCl fraction to exceed the 37% normally understood to be the limit of HCl solubility at atmospheric pressure.', 'Such water-soluble acid retarding agents include at least one salt compound and urea, or urea derivative.', 'Above 37%, normally, the evolution of HCl gas from the solution prevents the HCl fraction from getting any higher.', 'In one or more embodiments, the HCl weight fraction of the multi-phase aqueous solution may be as high as 45.7 wt %.', 'Without being bound by any particular theory, inventors envisage mechanisms that inhibit acid activity.', 'The first involves the disruption of the hydrogen-bonded network of water.', 'In the Grotthuss proton-hopping mechanism, protons move in water not through Brownian motion, but rather charge transport through shifting hydrogen bonds.', 'Solutes are known to disrupt the Grotthuss mechanism by interacting with water themselves, rather than allowing protons to associate freely.', 'This slows the proton transport to the wormhole wall during a matrix acidizing treatment.', 'The introduction of solutes such as the water-soluble acid retarding agent(s) also has a similar second effect by simply replacing water.', 'The lack of water molecules crowds the fluid and limits the diffusion of protons.', 'A second mechanism involves the dissociation of acids in solution.', "As mentioned, organic acids have higher pK\na\n's than HCl, making the protons from these acids less available for reaction.", 'In some aspects of the disclosure, compounds that lower the polarizability (as indicated by the dielectric constant) of water are used, which therefore decrease the proton dissociation of acids.', 'It is believed that aqueous solutes can modify the activity of acids in water in one or both of these mechanisms.', 'A parameter that quantifies the retardation of the acid is the retardation factor.', 'As described herein, the retardation factor indicates the ratio of apparent surface reaction rates.', 'According to the present embodiments, the retardation factor of the multi-phase aqueous composition is higher or equal to a retardation factor of a second solution of acid of a same concentration as the acid comprised in the multi-phase aqueous composition without the water-soluble acid retarding agent.', 'For example, in various embodiments, the multi-phase aqueous composition may exhibit an acid retardation factor higher than or equal to about 3, at least about 5, or at least about 11 at about 70° F. At about 200° F., the composition may exhibit an acid retardation factor higher than or equal to about 3, higher than or equal to about 5, or even higher than or equal to about 7.', 'Water can be present in the first phase of the multi-phase aqueous composition in an amount sufficient to dissolve the acid and the water-soluble acid retarding agent.', 'According to embodiments according to the disclosure, the water concentration included in the multi-phase aqueous composition may be greater than 0 wt % and lower or equal to 80 wt %, based on the total weight of the multi-phase aqueous composition.', 'In various embodiments, the water concentration may be lower than 60 wt %, or lower than 40 wt % or lower than 20 wt %, and equal to or higher than 8 wt %, or equal to or higher than 10 wt %, or lower than 8 wt %, based on the total weight of the multi-phase aqueous composition.', 'According to some embodiments, an amount of water is mixed with a water-soluble acid retarding agent, where the amount of water is present in an amount between 0.3 and 5 times the mass of the water-soluble acid retarding agent, where any lower limit can be 0.35, 0.4, or 0.45 and any upper limit can be 1.0, 1.2, 1.25, where any lower limit can be combined with any upper limit.', 'The procedure further includes dissolving an amount of acid into the combined amount of water and water-soluble acid retarding agent in the first phase.', 'The acid, such as HCl, may be added by any method, such as bubbling HCl gas through the solution.', 'The dissolving of the HCl may occur after dissolving of the water-soluble acid retarding agent, simultaneous with the dissolving of the water-soluble acid retarding agent, or at least partially before the dissolving of the water-soluble acid retarding agent.', 'The amount of HCl gas is in a molar ratio of between 4.0 and 0.5 times the amount of the water-soluble acid retarding agent.', 'In yet another embodiment, the procedure includes dissolution of at least a portion of the water-soluble acid retarding agent in the water during the dissolution of the HCl in the combined water and water-soluble acid retarding agent.', 'Example operations include beginning the dissolution of the HCl and adding the water-soluble acid retarding agent as a solid or a solution, providing some of the water-soluble acid retarding agent in solution with the water and some of the water-soluble acid retarding agent as a solid, and/or providing the water-soluble acid retarding agent as a solid in the water and dissolving the HCl into the water while dissolving the water-soluble acid retarding agent.', 'According to some embodiments, the gas can be selected from the group consisting of nitrogen, carbon dioxide, oxygen, helium, argon, hydrogen, methane or ethane, or a combination thereof.', 'According to some embodiments, the immiscible organic phase can be any organic material at least partially immiscible in water.', 'The immiscible organic phase can be selected from the group consisting of alkanes, cycloalkanes, aromatic compounds, heteroaromatic compounds, and combinations thereof.', 'The foaming agent can be selected from the group consisting of an ethoxylated nonionic surfactant, a cationic surfactant, an anionic surfactant, a zwitterionic surfactant and combinations thereof.', 'According to some embodiments, the multi-phase aqueous composition can be in the form of a foam.', 'In such embodiments, and in other embodiments, the surfactant can be the foaming agent and the second phase can comprise the gas.', 'According to some embodiments, the second phase comprises the immiscible organic phase and the multi-phase aqueous composition can be in the form of an emulsion where the first phase is a continuous phase and the second phase is a discontinuous phase and is stabilized by the surfactant, referred to as an oil in acid (O/A) emulsion.', 'In such embodiments, the surfactant can be an ethoxylated nonionic surfactant of the structure RO(CH\n2\nCH\n2\nO)\nn\nH, where R can be any alkyl group of 6 to 18 carbons, and 1≤n≤10.', 'The multi-phase aqueous composition in the form of an O/A emulsion can be pumped through a wellbore and into a subterranean carbonate containing formation at a rate at which the formation does not fracture.', 'In accordance with some embodiments, the formation bears petroleum deposits, potentially with precipitated paraffins or asphaltenes that are causing formation damage.', 'The multi-phase aqueous composition in the form of an O/A emulsion can perform two functions as it enters the formation of interest.', 'It can create a conductive wormhole, longer than an unretarded acid would in a matrix acidizing treatment.', 'Also, the internal oil phase will dissolve the organic damage, also improving production.', 'According to some embodiments, the second phase comprises the immiscible organic phase and the multi-phase aqueous composition can be in the form of an emulsion where the second phase is a continuous phase and the first phase is a discontinuous phase and is stabilized by the surfactant, referred to as an acid in oil (A/O) emulsion.', 'In such embodiments, the surfactant can be a cationic surfactant of the structure [RNXYZ]\n+\n A\n−\n, where R is an alkyl chain of 10 to 18 carbons.', 'X, Y and Z are selected from the group consisting of methyl, ethyl, hydroxyethyl or benzyl.', 'X, Y and Z can be the same or different.', 'A is an anion selected from the group consisting of fluoride, chloride, bromide, iodide, acetate, sulfate, alkylsulfonate or arylsulfonate.', 'The multi-phase aqueous composition in the form of an A/O emulsion can be pumped through a wellbore and into a subterranean carbonate containing formation at a rate that will not create enough pressure to fracture the formation.', 'As the emulsified acid enters the formation, conductive wormholes are formed that extend radially from the wellbore.', 'Normalized to treatment volume, wormholes formed from emulsified acids and acids with water-soluble retarding agents tend to extend farther than those from straight acid.', 'A combination of the two chemistries is expected to improve wormhole penetration even further.', 'In accordance with some embodiments, the multi-phase aqueous composition in the form of an A/O emulsion can be pumped into the carbonate formation at rates that are high enough to create a fracture in the formation.', 'The emulsified acid flows into the fracture, growing its length and height while dissolving conductive channels that create pathways from the distal parts of the formation to the wellbore.', 'The A/O emulsion will prevent leak-off of the acid into the formation, meaning that more acid will be spent on the fracture surface.', 'The water-soluble retarding agent will slow the reaction of HCl with fracture surface and carve out longer channels in the fracture.', 'In accordance with some embodiments, method(s) can comprise, consist of, or consist essentially of providing the multi-phase aqueous compositions, as described herein, and treating a formation fluidly coupled to a wellbore with an oilfield treatment fluid comprising the multi-phase aqueous composition.', 'In accordance with some embodiments, the multi-phase aqueous composition can be in the form of a foam prepared by: introducing the acid, the water-soluble retarding agent and the foaming agent into a carbonate formation, reacting the acid with the carbonate formation, generating carbon dioxide, entraining the carbon dioxide into the foaming agent of the multi-phase aqueous composition, creating a low-density foam that will help lift the spent (reduced acid content) multi-phase aqueous composition from the formation of the well and aid in returning the well to production.', 'Additionally, if the formation already contains gases, such as low molecular weight hydrocarbons (methane, ethane, propane, etc), hydrogen sulfide or carbon dioxide, these can also form part of the foam.', 'In accordance with some embodiments, method(s) can comprise, consist of, or consist essentially of treating a formation fluidly coupled to a wellbore with an oilfield treatment fluid comprising the multi-phase aqueous composition(s) in the form of a foam, as described in embodiments herein, where the surfactant comprises a foaming agent, and the second phase comprises the gas.', 'At pumping rates high enough to fracture the formation, the multi-phase aqueous composition in the form of a foam can enter the fracture, but not much of the fluid in such foam will enter the porous medium composing the walls of the fracture.', "The acid's reaction rate has also been retarded, and coupled with lower losses to the formation, should create a stimulated zone that extends further from the wellbore.", 'In accordance with some embodiments, the multi-phase aqueous composition in the form of a foam can be used to divert fluids from a high permeability zone to low permeability zone in the reservoir.', 'The multi-phase aqueous composition in the form of a foam can create high pressure drop due to multiphase flow in the porous media.', 'This excessive pressure build up in the wellbore helps in diverting acid to low permeability zones.', 'In some embodiments, injecting the multi-phase aqueous composition in the form of a foam below the fracture pressure of the reservoir will allow the multi-phase aqueous composition in the form of a foam to enter the formation and penetrate farther into the reservoir than a regular acid treatment.', 'The pressure build up will help in diverting a part of the multi-phase aqueous composition in the form of a foam into the low permeability zone.', 'The resulting treatment will have deeper acid penetration in both low and high permeability zones compared to a regular acid treatment.', 'In some embodiments, the multi-phase aqueous composition in the form of a foam can also be formed by: i) introducing the surfactant and the first phase into the formation, and ii) separately introducing the gas into the formation for contact with the surfactant and the first phase with sufficient energy to form the multi-phase aqueous composition in the form of a foam.', 'Further, it is also within the scope of the present disclosure that the multi-phase aqueous compositions may be combined with one or more other additives known to those of skill in the art, such as, but not limited to, corrosion inhibitors, scale inhibitors, foaming agents, hydrogen sulfide scavengers, reducing agents and/or chelants, and the like.', 'The corrosion inhibitor is typically provided in liquid form and is mixed with the other components of the treatment fluid at the surface and then introduced into the formation.', 'The corrosion inhibitor system is present in the treatment fluid in an amount of from about 0.2% to about 5% or about 0.2% to about 3% by total weight of the treatment fluid.', 'The corrosion inhibitor used with the fluids of the present disclosure includes an alkyl, alkenyl, alycyclic or aromatic substituted aliphatic ketone, which includes alkenyl phenones, or an aliphatic or aromatic aldehyde, which includes alpha, or beta-unsaturated aldehydes, or a combination of these.', 'Alkyl, alycyclic or aromatic phenone and aromatic aldehyde compounds may also be used in certain applications.', 'Other unsaturated ketones or unsaturated aldehydes may also be used.', 'Alkynol phenone, aromatic and acetylenic alcohols and quaternary ammonia compounds, and mixtures of these may be used, as well.', 'These may be dispersed in a suitable solvent, such as an alcohol, and may further include a dispersing agent and other additives.', 'Chelating agents are materials that are employed, among other uses, to control undesirable reactions of metal ions.', 'In oilfield chemical treatments, chelating agents are frequently added to matrix stimulation acids to prevent precipitation of solids (metal control) as the acids spend on the formation being treated.', 'These precipitates include iron hydroxide and iron sulfide.', 'In addition, chelating agents are used as components in many scale removal/prevention formulations.', 'Two different types of chelating agents may be used: polycarboxylic acids (including aminocarboxylic acids and polyaminopolycarboxylic acids) and phosphonates.', 'The non-surface active substituted ammonium containing aminoacid derivatives may act as chelating agents when present in the treatment fluid in amount of from about 0.05% to about 10% or from about 1 wt % to about 5 wt %, based upon total weight percent of the treatment fluid.', 'Some embodiments according to present disclosure are methods for treating a formation penetrated by a wellbore.', 'The methods involve providing an oilfield treatment fluid including the multi-phase aqueous composition(s) described in this disclosure to a high pressure pump and operating the high pressure pump to treat at least one of a wellbore and the formation fluidly coupled to the wellbore.', 'The operation of the pump may include at least one of (i) injecting the oilfield treatment fluid into the formation at matrix rates; (ii) injecting the oilfield treatment fluid into the formation at a pressure equal to a pressure that fractures the formation; and (iii) contacting at least one of the wellbore and the formation with the oilfield treatment fluid.', 'Referring now to \nFIG.', '1\n, a system \n100\n used to treat a wellbore \n106\n and/or a formation \n108\n fluidly coupled to the wellbore \n106\n is depicted.', 'The formation \n108\n may be any type of formation with a bottom hole temperature up to about 204° C. (400° F.).', 'In various embodiments the temperature is at least 38° C. (100° F.).', 'The temperature may also range from about 38° C. to about 204° C.', 'The wellbore \n106\n is depicted as a vertical, cased and cemented wellbore \n106\n, having perforations providing fluid communication between the formation \n108\n and the interior of the wellbore \n106\n.', 'However, the particular features of the wellbore \n106\n are not limiting, and the example provides an example context \n100\n for a procedure.', 'The system \n100\n includes a high-pressure pump \n104\n having a source of the multi-phase aqueous composition \n102\n, as described herein.', 'The high pressure pump \n104\n is fluidly coupled to the wellbore \n106\n, through high pressure lines \n120\n in the example.', 'The example system \n100\n includes tubing \n126\n in the wellbore \n106\n.', 'The tubing \n126\n is optional and non-limiting.', 'In various embodiments, the tubing \n106\n may be omitted, a coiled tubing unit (not shown) may be present, and/or the high pressure pump \n104\n may be fluidly coupled to the casing or annulus \n128\n.', 'The tubing or casing may be made of steel.', 'Certain additives (not shown) may be added to the multi-phase aqueous composition \n102\n to provide, or as a part of, an oilfield treatment fluid.', 'Additives may be added at a blender (not shown), at a mixing tub of the high pressure pump \n104\n, and/or by any other method.', 'In one or more embodiments, a second fluid \n110\n may be a diluting fluid, and the multi-phase aqueous composition \n102\n combined with some amount of the second fluid \n110\n may make up the oilfield treatment fluid.', 'The diluting fluid may contain no acid, and/or acid at a lower concentration than the multi-phase aqueous composition \n102\n.', 'The second fluid \n110\n may additionally include any other materials to be added to the oilfield treatment fluid, including additional amounts of a water-soluble acid retarding agent.', 'In certain embodiments, an additional water-soluble acid retarding agent solution \n112\n is present and may be added to the multi-phase aqueous composition \n102\n during a portion when the multi-phase aqueous composition \n102\n is being utilized.', 'The additional water-soluble acid retarding agent solution \n112\n may include the same or a different water-soluble acid retarding agent from the multi-phase aqueous composition \n102\n, and/or may include water-soluble acid retarding agent at a distinct concentration from the multi-phase aqueous composition.', 'The high pressure pump \n104\n can treat the wellbore \n106\n and/or the formation \n108\n, for example by positioning fluid therein, by injecting the fluid into the wellbore \n106\n, and/or by injecting the fluid into the formation \n108\n.', 'Example and non-limiting operations include any oilfield treatment without limitation.', 'Potential fluid flows include flowing from the high-pressure pump \n104\n into the tubing \n126\n, into the formation \n108\n, and/or into the annulus \n128\n.', 'The fluid may be recirculated out of the well before entering the formation \n108\n, for example utilizing a back side pump \n114\n.', 'Referring still to \nFIG.', '1\n, the annulus \n128\n is shown in fluid communication with the tubing \n126\n.', 'In various embodiments, the annulus \n128\n and the tubing \n126\n may be isolated (e.g. with a packer).', 'Another example fluid flow includes flowing the oilfield treatment fluid into the formation at a matrix rate (e.g. a rate at which the formation is able to accept fluid flow through normal porous flow), and/or at a rate that produces a pressure exceeding a hydraulic fracturing pressure.', 'The fluid flow into the formation may be either flowed back out of the formation, and/or flushed away from the near wellbore area with a follow up fluid.', 'Fluid flowed to the formation may be flowed to a pit or containment (not shown), back into a fluid tank, prepared for treatment, and/or managed in any other manner known in the art.', 'Acid remaining in the returning fluid may be recovered or neutralized.', 'Another example fluid flow includes the multi-phase aqueous composition \n102\n including an acid and water-soluble acid retarding agent.', 'The example fluid flow includes a second aqueous solution \n116\n including water-soluble acid retarding agent.', 'The fluid flow includes, sequentially, a first high pressure pump \n104\n and a second high pressure pump \n118\n treating the formation \n108\n.', 'As seen in \nFIG.', '1\n, the second high-pressure pump \n118\n is fluidly coupled to the tubing \n126\n through a second high pressure line \n122\n.', 'The fluid delivery arrangement is optional and non-limiting.', 'In one embodiment, a single pump may deliver both the multi-phase aqueous solution \n102\n and the second aqueous solution \n116\n.', 'In yet another example, either the multi-phase aqueous solution \n102\n or the second aqueous solution \n116\n may be delivered first, and one or more of the solutions \n102\n, \n116\n may be delivered in multiple stages, including potentially some stages where the solutions \n102\n, \n116\n are mixed.', 'The following examples are presented to further illustrate the preparation and properties of the wellbore fluids of the present disclosure and should not be construed to limit the scope of the disclosure, unless otherwise expressly indicated in the appended claims.', 'EXAMPLES\n \nEmulsions were prepared from an aqueous phase containing hydrochloric acid (15% w/v, that is, 15 g HCl/100 ml water) and a water-soluble retarding agent (19% w/v, either magnesium chloride or urea) and a diesel fuel organic phase.', 'The emulsions were ˜70% aqueous phase and ˜30% organic phase by volume.', 'Different surfactants useful for i) creating an acid-in-oil (A/O) emulsion, and ii) creating an oil-in-acid (O/A) emulsion, were added at 0.5% to create and stabilize the emulsions.', 'In this non-limiting example, the A/O emulsion is stabilized by a cationic surfactant and the O/A emulsion is stabilized by an ethoxylated nonionic surfactant.', 'The mixtures were homogenized by vigorous shaking, and allowed to stand.', 'The A/O emulsions (containing either magnesium chloride or urea) separated ˜10% of their volume as top oil.', 'Both required over one hour for separation, indicating a very stable emulsion.', 'The O/A emulsions containing magnesium chloride and urea in the aqueous phase required 22 minutes and 15 minutes, respectively, to fully separate.', 'Various formulations were prepared using different retarding agents and HCl as the acid.', 'A series of tests were conducted to evaluate these formulations.', 'To fully assess the properties of the prepared formulations, the tests were conducted in an autoclave under up to 3000 psi hydrostatic pressure, with the thermal energy transmitted through a silicone oil bath.', 'To determine the retardation factor (RF) of certain additives, formation response tests were conducted with different acid formulations.', 'In the experiments, Indiana limestone cores, which were 1 inch in diameter by 6 inches in length, were held at ˜2800 psi confining pressure to ensure that no fluids channeled around the sides, and were heated to desired temperature.', 'The acid fluids were flowed through the core, with a ˜1200 psi back pressure, which were conditions provided so the acid will preferentially form wormholes.', 'When the wormhole extended the entire length of the core, the pressure drops across the core approached zero, which was indicative that the fluid was no longer flowing through porous medium, but rather what approximated a tortuous pipe.', 'The number of pore volumes of fluid required to create the wormholes was a function of the acid injection velocity (u\ni \nFIGS.', '2 and 3\n).', 'The optimal injection velocity (u\ni-opt\n) is that which requires the lowest number of pore volumes for the wormhole to break through the core.', 'Using this approach, pore volume to break through (PV\nBT\n) curves versus interstitial velocity curves were generated and the u\ni-opt \nand RF calculated for each acid formulation (Table 1) at 70° F. (\nFIG.', '2\n) and 200° F. (\nFIG.', '3\n).', 'TABLE 1\n \n \n \n \n \n \n \n \nRetardation Factors of Acid Formulations\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nRetarding\n \nRetarding Agent\n \nEstimated\n \n \n \n \nTemperature\n \nAgent\n \nconcentration\n \nretardation\n \n \n \nEntry\n \n(° F.)', 'Additive\n \n(% by weight)\n \nfactor (RF)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n1\n \n70\n \nnone\n \n—\n \n—\n \n \n \n2\n \n \nurea\n \n18.5\n \n3.3\n \n \n \n3\n \n \nN,N′-dimethyl\n \n27\n \n5.8\n \n \n \n \n \nurea (DMU)\n \n \n \n4\n \n \nMgCl\n2\n \n19\n \n10.9\u2002\n \n \n \n5\n \n200\n \nnone\n \n—\n \n—\n \n \n \n6\n \n \nurea\n \n18.5\n \n1.3\n \n \n \n7\n \n \nMgCl\n2\n \n19\n \n3.1\n \n \n \n \n \n \n \n \n \n \nThe estimated retardation factor was calculated according to the following equation:\n \n \n \n \n \n \nRF\n \nx\n \n \n∼\n \n \n \n(\n \n \n \nu\n \n \n \ni\n \n-\n \nopt\n \n \n,\n \nHCl\n \n \n \n \nu\n \n \n \ni\n \n-\n \nopt\n \n \n,\n \nx\n \n \n \n \n)\n \n \n2\n \n \n \n \n \n \nAll aqueous fluids evaluated contained hydrochloric acid (15% weight/volume) and a corrosion inhibitor (0.6% by volume).', 'The results demonstrate that compounds which disrupt the hydrogen bonding network of water and its dielectric constant are able to retard the activity of acid in subterranean formations.', 'In particular, magnesium chloride (MgCl\n2\n) used as a retarding agent showed significant retardation at similar or lower concentrations than the other retarding evaluated.', 'Wormholes in carbonate formations can acquire different structures depending on the rate of acid injection.', 'At very low injection rates, there is no wormhole at all, as only the face of the formation dissolves.', 'Wormholes that do form at low injection rates tend to be broad and conical.', 'Close to the optimum injection rate, a dominant, narrow wormhole forms with a small amount of branching.', 'When the injection rate is increased past the optimum injection rate, the acid is forced into less permeable zones and creates a ramified (highly branched) wormhole.', 'Ramified structures will transition to uniformly dissolved rock at very high injection rates.', 'By comparing the characteristics of the injection face of the cores from the acid injection experiment described in evaluations above, estimates of the wormhole characteristics can be made.', 'Table 2 provides the low acid injection rates, break through times and pore volumes, from the evaluations above at 200° F., and \nFIGS.', '4A-4C\n graphically illustrate the core face images and break through characteristics at low acid injection rates at 200° F.\n \n \n \n \n \n \n \n \nTABLE 2\n \n \n \n \n \n \n \n \nCore face images and break through characteristics at\n \n \n \nlow acid injection rates at 200° F.\n \n \n \n \n \n \n \n \n \n \nFluid =>\n \n \n \n \n \n \n \n \n \n \n \n \n \n15% HCl +\n \n15% HCl +\n \n \n \n \n15% HCl\n \n18.5% urea\n \n19% MgCl\n2\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nInjection rate (ml/min)\n \n0.2\n \n0.3\n \n0.2\n \n \n \nBreak through time\n \n>3:30\n \n>1:30\n \n0:34\n \n \n \n(h:mm)', 'Pore volumes to break\n \n>3.4\n \n>3\n \n0.53\n \n \n \nthrough\n \n \n \n \n \n \n \n \n \n \nIn the tests performed at 200° F., the core faces treated with 15% HCl (\nFIG.', '4A\n) and 15% HCl with urea (\nFIG.', '4B\n), both showed a large amount of core facial dissolution \n402\n and developing conical wormholes \n404\n.', 'In both cases, however, the confining pressure punctured the sleeve holding the core because too much of the rock face dissolved.', 'For the 15% HCl with MgCl\n2 \nfluid (\nFIG.', '4C\n)', ', the entry wormhole was much smaller and the wormholes \n406\n broke through to the opposite face in a timely fashion, 34 minutes with 0.53 pore volumes to break through.', 'These indicate that at lower injection rates, retarded acid with MgCl\n2 \nwas effective.', 'Table 3 provides the results of the same experiment conducted at 250° F., with similar comparative results both in data and facial dissolution as shown in \nFIG.', '4D\n (for HCl alone) and \nFIG.', '4E\n (for HCl with MgCl\n2\n).', 'A large amount of core facial dissolution \n402\n and a developing conical wormholes \n404\n occurred with HCl alone, while little facial dissolution and a narrower wormhole \n406\n resulted with the HCl and MgCl\n2 \nmixture.', 'TABLE 3\n \n \n \n \n \n \n \n \nCore break through characteristics at low acid injection\n \n \n \nrates at 250° F.\n \n \n \n \n \n \n \n \n \n \n \nFluid =>\n \n \n \n \n \n \n \n \n \n \n \n \n15% HCl\n \n15% HCl + 19% MgCl\n2\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nInjection rate (ml/min)\n \n0.4\n \n0.4\n \n \n \n \nBreak through time\n \n>2:05\n \n0:13\n \n \n \n \n(h:mm)', 'Pore volumes to break\n \n>4\n \n0.34\n \n \n \n \nthrough\n \n \n \n \n \n \n \n \n \n \n \nIn another example, rotating disk experiments were performed to characterize the relative surface reaction rates of acidic solutions.', 'The experiment was conducted by spinning a marble or limestone disk, at ambient temperature and 1250 rpm, in an acid formulation, and periodically sampling the solution.', 'The samples were then analyzed for the calcium concentration as a function of time, which gives the rate constant of calcite (CaCO\n3\n) dissolution by hydrochloric acid containing solutions.', 'A decrease in rate constant indicates an acid retarding agent formulation whose surface reaction is retarded relative to hydrochloric acid alone, without any retarding agent.', 'The plot in \nFIG.', '5\n illustrates slower dissolution rate, or slower rate of Ca\n2+\n ions liberation over time, for the 15% HCl solution containing MgCl\n2 \ncompared with unmodified 15% HCl within 10 minutes.', 'The results in \nFIG.', '5\n are a comparison of 15% HCl alone to 15% HCl mixed with 18.7% MgCl\n2 \nretarding agent.', 'The foregoing description of the embodiments has been provided for purposes of illustration and description.', 'Example embodiments are provided so that this disclosure will be sufficiently thorough, and will convey the scope to those who are skilled in the art.', 'Numerous specific details are set forth such as examples of specific components, devices, and methods, to provide a thorough understanding of embodiments of the disclosure, but are not intended to be exhaustive or to limit the disclosure.', 'It will be appreciated that it is within the scope of the disclosure that individual elements or features of a particular embodiment are generally not limited to that particular embodiment, but, where applicable, are interchangeable and can be used in a selected embodiment, even if not specifically shown or described.', 'The same may also be varied in many ways.', 'Such variations are not to be regarded as a departure from the disclosure, and all such modifications are intended to be included within the scope of the disclosure.', 'Also, in some example embodiments, well-known processes, well-known device structures, and well-known technologies are not described in detail.', 'Further, it will be readily apparent to those of skill in the art that in the design, manufacture, and operation of apparatus to achieve that described in the disclosure, variations in apparatus design, construction, condition, erosion of components, gaps between components may present, for example.', 'Although the terms first, second, third, etc. may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms.', 'These terms may be only used to distinguish one element, component, region, layer or section from another region, layer or section.', 'Terms such as “first,” “second,” and other numerical terms when used herein do not imply a sequence or order unless clearly indicated by the context.', 'Thus, a first element, component, region, layer or section discussed below could be termed a second element, component, region, layer or section without departing from the teachings of the example embodiments.', "Spatially relative terms, such as “inner,” “outer,” “beneath,” “below,” “lower,” “above,” “upper,” and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated in the figures.", 'Spatially relative terms may be intended to encompass different orientations of the device in use or operation in addition to the orientation depicted in the figures.', 'For example, if the device in the figures is turned over, elements described as “below” or “beneath” other elements or features would then be oriented “above” the other elements or features.', 'Thus, the example term “below” can encompass both an orientation of above and below.', 'The device may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein interpreted accordingly.', 'Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.'] | ['1.', 'A two-phase aqueous composition comprising: a surfactant having a structure in accordance with Formula I:\nwherein R1 is CH3(CH2)7CH═CH—(CH2)11, R2 is hydrogen, R3 is (CH2)3—N—(CH3)2—CH2— and Y is COO−; a first phase comprising water, HCl, and acid retarder MgCl2; and a second phase consisting of nitrogen, wherein the MgCl2 is present in the first phase at a concentration of about 19 wt %.', '2.', 'The two-phase aqueous composition of claim 1, wherein the surfactant is a foaming agent and the second phase comprises the nitrogen.', '3.', 'The two-phase aqueous composition of claim 2, wherein the two-phase aqueous composition is a foam.', '4.', 'A method, comprising: a) providing a two-phase aqueous composition comprising: a surfactant having a structure an accordance with Formula I:\nwherein R1 is CH3—(CH2)7—CH═CH—(CH2)11, R2 is hydrogen, R3 is (CH2)3—N—(CH3)2—CH2— and Y is COO−; a first phase comprising water, HCl, and acid retarder MgCl2; a second phase consisting of nitrogen; and b) treating a subterranean formation fluidly coupled to a wellbore with an oilfield treatment fluid comprising the two-phase aqueous composition;\nwherein the MgCl2 is present in the aqueous composition at a concentration of about 19 wt %;\nwherein the treating is an acidizing operation performed at treating pressures less than, higher than or equal to a formation fracturing pressure.', '5.', 'A method comprising: a) treating a subterranean formation fluidly coupled to a wellbore with an oilfield treatment fluid comprising a two-phase aqueous composition comprising: a surfactant comprising a foaming agent; a first phase comprising water, HCl, and acid retarder MgCl2; a second phase consisting of nitrogen; wherein the two-phase aqueous composition is a foam, wherein the surfactant has a structure an accordance with Formula I:\nwherein R1 is CH3—(CH2)7—CH═CH—(CH2)11, R2 is hydrogen, R3 is (CH2)3—N—(CH3)2—CH2— and Y is COO−;\nwherein the MgCl2 is present in the aqueous composition at a concentration of about 19 wt %;\nwherein the treating is an acidizing operation performed at treating pressures less than, higher than or equal to a formation fracturing pressure.', '6.', 'The method of claim 5, wherein the two-phase aqueous composition is formed by: i) introducing the surfactant and the first phase into the subterranean formation, and ii) separately introducing the nitrogen into the subterranean formation for contact with the surfactant and the first phase with sufficient energy to form a foam.'] | ['FIG.', '1 depicts an example of equipment used to treat a wellbore and/or a formation fluidly coupled to the wellbore according to some embodiments of the disclosure;; FIG.', '2 shows pore volumes to break through versus interstitial velocity curves for aqueous acid solutions based upon tests performed at 70° F., according to the disclosure;; FIG.', '3 shows pore volumes to break through versus interstitial velocity curves for aqueous acid solutions based upon tests performed at 200° F., according to the disclosure;; FIGS.', '4A-4E depict face dissolution of core samples evaluated in accordance with the disclosure; and,; FIG.', '5 shows calcium generation concentration versus time curves for some aqueous acid solutions evaluated, according to the disclosure.'] |
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US11095859 | CCTV system | Apr 10, 2020 | Espen Pettersen, Anstein Jorud | Schlumberger Technology Corporation | NPL References not found. | 4610005; September 2, 1986; Utasi; 6629572; October 7, 2003; Womer et al.; 7584796; September 8, 2009; Ayling; 8215417; July 10, 2012; Annaiyappa et al.; 8392552; March 5, 2013; Alexander; 9464492; October 11, 2016; Austetjord et al.; 10012068; July 3, 2018; OReilly; 10246952; April 2, 2019; Trydal et al.; 20020060093; May 23, 2002; Womer et al.; 20040212679; October 28, 2004; Jun; 20050109537; May 26, 2005; Ayling; 20070119622; May 31, 2007; Ayling; 20080173480; July 24, 2008; Annaiyappa et al.; 20100147510; June 17, 2010; Kwok; 20120243945; September 27, 2012; Swingler et al.; 20130345878; December 26, 2013; Austefjord et al.; 20140085463; March 27, 2014; Kwon; 20140348385; November 27, 2014; Kozicz et al.; 20150145991; May 28, 2015; Russell; 20150363738; December 17, 2015; Haci; 20160160631; June 9, 2016; OReilly; 20160292513; October 6, 2016; Kozicz et al.; 20160358435; December 8, 2016; Lee; 20170037691; February 9, 2017; Savage; 20170061791; March 2, 2017; Cherewka; 20170064256; March 2, 2017; Richardson et al.; 20170182406; June 29, 2017; Castiglia et al.; 20170193693; July 6, 2017; Robert; 20170306710; October 26, 2017; Trydal et al.; 20170374437; December 28, 2017; Schwarzkopf et al.; 20180012125; January 11, 2018; Ladha et al.; 20190016418; January 17, 2019; Vandenworm; 20190078426; March 14, 2019; Zheng | Foreign Citations not found. | ['A closed-circuit television (CCTV) system for use at a well construction system to form a well at an oil/gas wellsite.', 'The CCTV system includes a video output device and video cameras at the well construction system.', 'A control system is communicatively connected with each video camera and the video output device.', 'The control system receives video display settings from a human wellsite operator, receives the video signals from the video cameras, and automatically displays on the video output device one or more of the received video signals based on the video display settings.'] | ['Description\n\n\n\n\n\n\nPRIORITY CLAIM', 'This application claims priority as a continuation application of U.S. patent application Ser.', 'No. 15/908,396, with the same title, filed Feb. 28, 2018, which is incorporated by reference herein in its entirety.', 'BACKGROUND OF THE DISCLOSURE\n \nWells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other materials that are trapped in subterranean formations.', 'The wells are drilled into the subterranean formations using a drill bit attached to a lower end of a drill string.', 'The well construction utilizes various wellsite equipment operating in a coordinated manner.', 'The wellsite equipment can be grouped into subsystems, and each subsystem may perform different operations controlled by a corresponding controller.', 'One such example is a closed circuit television (CCTV) system.', 'The CCTV system provides a display of wellsite equipment so that a human operator can view the well construction progress.', 'The operator manually controls the CCTV system, such as by selecting video camera feeds to monitor different well construction equipment and operations, and perhaps adjusting camera settings for different environmental conditions at the wellsite.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus including a closed-circuit television (CCTV) system for use at a well construction system to form a well at an oil/gas wellsite.', 'The CCTV system includes video cameras at different locations within the well construction system.', 'Each video camera generates a corresponding video signal.', 'The CCTV system also includes a video output device.', 'The apparatus also includes a control system communicatively connected with each video camera and the video output device.', 'The control system includes a processor and a memory operable to store computer programs that utilize video display settings.', 'The control system receives the video display settings from a human wellsite operator, receives the video signals from the video cameras, and automatically displays one or more of the received video signals on the video output device based on the video display settings.', 'The present disclosure also introduces an apparatus including a well construction system that includes components collectively operable to construct a well at an oil/gas wellsite via multiple operations, video cameras at different locations in the well construction system and generating corresponding video signals, a video output device, and a control system having a processor and a memory storing an executable code.', 'The control system receives the video signals and video display settings that include associations between the operations and the video cameras.', 'During each operation, one or more of the video signals received from the one or more video cameras associated with that operation are automatically displayed on the video output device.', 'The present disclosure also introduces a method including constructing a well at an oil/gas wellsite by operating a well construction system to perform a plurality of operations, and by operating a control system having a processor and a memory storing an executable code.', 'The control system receives video signals from video cameras each positioned at a different location in the well construction system.', 'The control system also receives video display settings including associations between the operations and the video cameras.', 'During each operation, a video output device automatically displays one or more of the video signals received from the one or more video cameras associated with that operation.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is best understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '4\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '5\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '6\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '7\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '8\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.\n \nFIG.', '9\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '10\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '11\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '12\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure describes many example implementations for different aspects introduced herein.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are merely examples, and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various implementations described herein.', 'Moreover, the formation of a first feature over or on a second feature in the description that follows may include implementations in which the first and second features are formed in direct contact, and may also include implementations in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.\n \nFIG.', '1\n is a schematic view of at least a portion of an example implementation of a well construction system \n100\n according to one or more aspects of the present disclosure.', 'The well construction system \n100\n represents an example environment in which one or more aspects described below may be implemented.', 'Although the well construction system \n100\n is depicted as an onshore implementation, the aspects described below are also applicable to offshore and inshore implementations.', 'The well construction system \n100\n is depicted in relation to a wellbore \n102\n formed by rotary and/or directional drilling from a wellsite surface \n104\n and extending into a subterranean formation \n106\n.', 'The well construction system \n100\n includes surface equipment \n110\n located at the wellsite surface \n104\n and a drill string \n120\n suspended within the wellbore \n102\n.', 'The surface equipment \n110\n may include a mast, a derrick, and/or another wellsite structure \n112\n disposed over a rig floor \n114\n.', 'The drill string \n120\n may be suspended within the wellbore \n102\n from the wellsite structure \n112\n.', 'The wellsite structure \n112\n and the rig floor \n114\n are collectively supported over the wellbore \n102\n by legs and/or other support structures \n113\n.', 'The drill string \n120\n may comprise a bottom-hole assembly (BHA) \n124\n and means \n122\n for conveying the BHA \n124\n within the wellbore \n102\n.', 'The conveyance means \n122\n may comprise drill pipe, heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough logging condition (TLC) pipe, coiled tubing, and/or other means for conveying the BHA \n124\n within the wellbore \n102\n.', 'A downhole end of the BHA \n124\n may include or be coupled to a drill bit \n126\n.', 'Rotation of the drill bit \n126\n and the weight of the drill string \n120\n collectively operate to form the wellbore \n102\n.', 'The drill bit \n126\n may be rotated from the wellsite surface \n104\n and/or via a downhole mud motor (not shown) connected with the drill bit \n126\n.', 'The BHA \n124\n may also include various downhole tools \n180\n, \n182\n, \n184\n.', 'One or more of such downhole tools \n180\n, \n182\n, \n184\n may be or comprise an acoustic tool, a density tool, a directional drilling tool, an electromagnetic (EM) tool, a formation sampling tool, a formation testing tool, a gravity tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a sampling while drilling (SWD) tool, a seismic tool, a surveying tool, and/or other measuring-while-drilling (MWD) or logging-while-drilling (LWD) tools.', 'One or more of the downhole tools \n180\n, \n182\n, \n184\n may be or comprise an MWD or LWD tool comprising a sensor package \n186\n operable for the acquisition of measurement data pertaining to the BHA \n124\n, the wellbore \n102\n, and/or the formation \n106\n.', 'One or more of the downhole tools \n180\n, \n182\n, \n184\n and/or another portion of the BHA \n124\n may also comprise a telemetry device \n187\n operable for communication with the surface equipment, such as via mud-pulse telemetry.', 'One or more of the downhole tools \n180\n, \n182\n, \n184\n and/or another portion of the BHA \n124\n may also comprise a downhole processing device \n188\n operable to receive, process, and/or store information received from the surface equipment, the sensor package \n186\n, and/or other portions of the BHA \n124\n.', 'The processing device \n188\n may also store executable programs and/or instructions, including for implementing one or more aspects of the operations described herein.', 'The wellsite structure \n112\n may support a top drive \n116\n operable to connect (perhaps indirectly) with an uphole end of the conveyance means \n122\n, and to impart rotary motion \n117\n and axial motion \n135\n to the drill string \n120\n and the drill bit \n126\n.', 'However, a kelly and rotary table (neither shown) may be utilized instead of or in addition to the top drive \n116\n to impart the rotary motion \n117\n.', 'The top drive \n116\n and the connected drill string \n120\n may be suspended from the wellsite structure \n112\n via hoisting equipment, which may include a traveling block \n118\n, a crown block (not shown), and a drawworks \n119\n storing a support cable or line \n123\n.', 'The crown block may be connected to or otherwise supported by the wellsite structure \n112\n, and the traveling block \n118\n may be coupled with the top drive \n116\n, such as via a hook.', 'The drawworks \n119\n may be mounted on or otherwise supported by the rig floor \n114\n.', 'The crown block and traveling block \n118\n comprise pulleys or sheaves around which the support line \n123\n is reeved to operatively connect the crown block, the traveling block \n118\n, and the drawworks \n119\n (and perhaps an anchor).', 'The drawworks \n119\n may thus selectively impart tension to the support line \n123\n to lift and lower the top drive \n116\n.', 'The drawworks \n119\n may comprise a drum, a frame, and a prime mover (e.g., an engine or motor) (not shown) operable to drive the drum to rotate and reel in the support line \n123\n, causing the traveling block \n118\n and the top drive \n116\n to move upward.', 'The drawworks \n119\n may be operable to release the support line \n123\n via a controlled rotation of the drum, causing the traveling block \n118\n and the top drive \n116\n to move downward.', 'The top drive \n116\n may include a grabber, a swivel (neither shown), a tubular handling assembly \n127\n terminating with an elevator \n129\n, and a drive shaft \n125\n operatively connected with a prime mover (not shown).', 'The drill string \n120\n may be mechanically coupled to the top drive shaft \n125\n with or without a sub saver between the drill string \n120\n and the top drive shaft \n125\n.', 'The prime mover may drive the top drive shaft \n125\n, such as through a gear box or transmission (not shown), to rotate the top drive shaft \n125\n and, therefore, the drill string \n120\n, which in conjunction with operation of the drawworks \n119\n may advance the drill string \n120\n into the formation \n106\n and form the wellbore \n102\n.', 'The tubular handling assembly \n127\n and the elevator \n129\n may permit the top drive \n116\n to handle tubulars (e.g., drill pipes, drill collars, casing joints, and the like, that are not mechanically coupled to the drive shaft \n125\n).', 'For example, when the drill string \n120\n is being tripped into or out of the wellbore \n102\n, the elevator \n129\n may grasp the tubulars of the drill string \n120\n such that the tubulars may be raised and/or lowered via the hoisting equipment mechanically coupled to the top drive \n116\n.', 'The grabber may include a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the top drive shaft \n125\n.', 'The top drive \n116\n may have a guide system (not shown), such as rollers that track up and down a guide rail (not shown) on the wellsite structure \n112\n.', 'The guide system may aid in keeping the top drive \n116\n aligned with the wellbore \n102\n, and in preventing the top drive \n116\n from rotating during drilling by transferring reactive torque to the wellsite structure \n112\n.', 'The drill string \n120\n may be conveyed within the wellbore \n102\n through a plurality of well control devices disposed at the wellsite surface \n104\n on top of the wellbore \n102\n and below the rig floor \n114\n.', 'The well control devices may be operable to control pressure within the wellbore \n102\n via a series of pressure barriers formed between the wellbore \n102\n and the wellsite surface \n104\n.', 'The well control devices may include a blowout preventer (BOP) stack \n130\n and an annular fluid control device \n132\n, such as an annular preventer and/or a rotating control device (RCD).', 'The well control devices may be mounted on top of a wellhead \n134\n.', 'The well construction system \n100\n may include a drilling fluid circulation system operable to circulate fluids between the surface equipment \n110\n and the drill bit \n126\n during drilling and other operations.', 'For example, the drilling fluid circulation system may be operable to inject a drilling fluid from the wellsite surface \n104\n into the wellbore \n102\n via an internal fluid passage \n121\n extending longitudinally through the drill string \n120\n.', 'The drilling fluid circulation system may comprise a pit, a tank, and/or other fluid container \n142\n holding drilling fluid \n140\n, and a pump \n144\n operable to move the drilling fluid \n140\n from the container \n142\n into the fluid passage \n121\n of the drill string \n120\n via a fluid conduit \n146\n extending from the pump \n144\n to the top drive \n116\n and an internal passage extending through the top drive \n116\n.', 'The fluid conduit \n146\n may comprise one or more of a pump discharge line, a stand pipe, a rotary hose, and a gooseneck (not shown) connected with a fluid inlet of the top drive \n116\n.', 'The pump \n144\n and the container \n142\n may be fluidly connected by a fluid conduit \n148\n.', 'A flow rate sensor \n150\n may be operatively connected along the fluid conduit \n146\n to measure flow rate of the drilling fluid \n140\n being pumped downhole.', 'The flow rate sensor \n150\n may be operable to measure volumetric and/or mass flow rate of the drilling fluid \n140\n.', 'The flow rate sensor \n150\n may be an electrical flow rate sensor operable to generate an electrical signal and/or information indicative of the measured flow rate.', 'The flow rate sensor \n150\n may be a Coriolis flowmeter, a turbine flowmeter, or an acoustic flowmeter, among other examples.', 'A fluid level sensor \n152\n may be mounted or otherwise disposed in association with the container \n142\n, and may be operable to measure the level of the drilling fluid \n140\n within the container \n142\n.', 'The fluid level sensor \n152\n may be an electrical fluid level sensor operable to generate signals or information indicative of the amount (e.g., level, volume) of drilling fluid \n140\n within the container \n142\n.', 'The fluid level sensor \n152\n may comprise conductive, capacitive, vibrating, electromechanical, ultrasonic, microwave, nucleonic, and/or other example sensors.', 'A flow check valve \n154\n may be connected downstream from the pump \n144\n to prevent the drilling or other fluids from backing up through the pump \n144\n.', 'A pressure sensor \n156\n may be connected along the fluid conduit \n146\n, such as to measure the pressure of the drilling fluid \n140\n being pumped downhole.', 'The pressure sensor \n156\n may be connected close to the top drive \n116\n, such as may permit the pressure sensor \n156\n to measure the pressure within the drill string \n120\n at the top of the internal passage \n121\n or otherwise proximate the wellsite surface \n104\n.', 'The pressure sensor \n156\n may be an electrical sensor operable to generate electric signals and/or other information indicative of the measured pressure.', 'During drilling operations, the drilling fluid may continue to flow downhole through the internal passage \n121\n of the drill string \n120\n, as indicated in \nFIG.', '1\n by directional arrow \n158\n.', 'The drilling fluid may exit the BHA \n124\n via ports \n128\n in the drill bit \n126\n and then circulate uphole through an annular space (“annulus”) \n108\n of the wellbore \n102\n defined between an exterior of the drill string \n120\n and the wall of the wellbore \n102\n, such flow being indicated in \nFIG.', '1\n by directional arrows \n159\n.', 'In this manner, the drilling fluid \n140\n lubricates the drill bit \n126\n and carries formation cuttings uphole to the wellsite surface \n104\n.', 'The returning drilling fluid may exit the annulus \n108\n via a wing valve, a bell nipple, or another ported adapter \n136\n.', 'The ported adapter \n136\n may be disposed below the annular fluid control device \n132\n, above the BOP stack \n130\n, or at another location along the well control devices permitting ported access or fluid connection with the annulus \n108\n.', 'The drilling fluid exiting the annulus \n108\n via the ported adapter \n136\n may be directed into a fluid conduit \n160\n, and may pass through various equipment fluidly connected along the conduit \n160\n prior to being returned to the container \n142\n for recirculation.', 'For example, the drilling fluid may pass through a choke manifold \n162\n connected along the conduit \n160\n.', 'The choke manifold \n162\n may include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow from the choke manifold \n162\n.', 'Backpressure may be applied to the annulus \n108\n by variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold \n162\n.', 'The greater the restriction to flow through the choke manifold \n162\n, the greater the backpressure applied to the annulus \n108\n.', 'Thus, downhole pressure (e.g., pressure at the bottom of the wellbore \n102\n around the BHA \n124\n or at a particular depth along the wellbore \n102\n) may be regulated by varying the backpressure at an upper (i.e., uphole) end (e.g., within an upper portion) of the annulus \n108\n proximate the wellsite surface \n104\n.', 'Pressure maintained at the upper end of the annulus \n108\n may be measured via a pressure sensor \n164\n connected along the conduit \n160\n between the ported adapter \n136\n and the choke manifold \n162\n.', 'A fluid valve \n166\n may be connected along the conduit \n160\n to selectively fluidly isolate the annulus \n108\n from the choke manifold \n162\n and/or other surface equipment \n110\n fluidly connected with the conduit \n160\n.', 'The fluid valve \n166\n may be or comprise fluid shut-off valves, such as ball valves, globe valves, and/or other types of fluid valves, which may be selectively opened and closed to permit and prevent fluid flow therethrough.', 'The fluid valve \n166\n may be actuated remotely by a corresponding actuator operatively coupled with the fluid valve \n166\n.', 'The actuator may be or comprise an electric actuator, such as a solenoid or motor, or a fluid actuator, such as pneumatic or hydraulic cylinder or rotary actuator.', 'The fluid valve \n166\n may also or instead be actuated manually, such as by a corresponding lever.', 'A flow rate sensor \n168\n may be connected along the fluid conduit \n160\n to monitor the flow rate of the returning drilling fluid or another fluid being discharged from the wellbore \n102\n.', 'Before being returned to the container \n142\n, the drilling fluid may be cleaned and/or reconditioned by solids and gas control equipment \n170\n, which may include one or more of shakers, separators, centrifuges, and other drilling fluid cleaning devices.', 'The solids control equipment \n170\n may be operable for separating and removing solid particles \n141\n (e.g., drill cuttings) from the drilling fluid returning to the surface \n104\n.', 'The solids and gas control equipment \n170\n may also comprise fluid reconditioning equipment, such as may remove gas and/or finer formation cuttings \n143\n from the drilling fluid.', 'The fluid reconditioning equipment may include a desilter, a desander, a degasser \n172\n, and/or the like.', 'The degasser \n172\n may form or be mounted in association with one or more portions of the solids and gas control equipment \n170\n.', 'The degasser \n172\n may be operable for releasing and/or capturing formation gasses entrained in the drilling fluid discharged from the wellbore \n102\n.', 'Intermediate tanks/containers (not shown) may be utilized to hold the drilling fluid \n140\n between the various portions of the solids and gas control equipment \n170\n.', 'The degasser \n172\n may be fluidly connected with one or more gas sensors \n174\n (e.g., gas detectors and/or analyzers) via a fluid conduit \n176\n, such as may permit the formation gasses released and/or captured by the degasser \n172\n to be directed to and analyzed by the gas sensors \n174\n.', 'The gas sensors \n174\n may be operable for generating signals or information indicative of the presence and/or quantity of formation gasses released and/or captured by the degasser \n172\n.', 'The gas sensors \n174\n may be or comprise qualitative gas analyzers, which may be utilized for safety purposes, such as to detect presence of hazardous gases entrained within the drilling fluid.', 'The gas sensors \n174\n may also or instead be or comprise quantitative gas analyzers, which may be utilized to detect levels or quantities of certain formation gasses, such as to perform formation evaluation.', 'One or more gas sensors \n178\n (e.g., qualitative gas analyzers) may also or instead be located at the rig floor \n114\n, such as to detect hazardous gasses being released from the wellbore \n102\n.', 'The cleaned/reconditioned drilling fluid may be transferred to the fluid container \n142\n, and the solid particles \n141\n removed from the fluid may be transferred to a solids container \n143\n (e.g., a reserve pit).', 'The container \n142\n may include an agitator (not shown) to maintain uniformity of the drilling fluid \n140\n therein.', 'A hopper (not shown), such as may be disposed in a flowline between the container \n142\n and the pump \n144\n, may be utilized to introduce chemical additives, such as caustic soda, into the drilling fluid \n140\n.', 'The surface equipment \n110\n may include tubular handling equipment operable to store, move, connect, and disconnect tubulars to assemble and disassemble the conveyance means \n122\n of the drill string \n120\n during drilling operations.', 'For example, a catwalk \n131\n may be utilized to convey tubulars from a ground level, such as along the wellsite surface \n104\n, to the rig floor \n114\n, permitting the tubular handling assembly \n127\n to grab and lift the tubulars above the wellbore \n102\n for connection with previously deployed tubulars.', 'The catwalk \n131\n may have a horizontal portion and an inclined portion that extends between the horizontal portion and the rig floor \n114\n.', 'The catwalk \n131\n may comprise a skate \n133\n movable along a groove (not shown) extending longitudinally along the horizontal and inclined portions of the catwalk \n131\n.', 'The skate \n133\n may be operable to convey (e.g., push) the tubulars along the catwalk \n131\n to the rig floor \n114\n.', 'The skate \n133\n may be driven along the groove by a drive system (not shown), such as a pulley system or a hydraulic system, among other examples.', 'Additionally, one or more racks (not shown) may adjoin the horizontal portion of the catwalk \n131\n.', 'The racks may have a spinner unit (not shown) for transferring tubulars to the groove of the catwalk \n131\n.', 'An iron roughneck \n151\n may be positioned on the rig floor \n114\n.', 'The iron roughneck \n151\n may comprise a torqueing portion \n153\n, such as may include a spinner and a torque wrench comprising a lower tong and an upper tong.', 'The torqueing portion \n153\n of the iron roughneck \n151\n may be moveable toward and at least partially around the drill string \n120\n, such as may permit the iron roughneck \n151\n to make up and break out connections of the drill string \n120\n.', 'The torqueing portion \n153\n may also be moveable away from the drill string \n120\n, such as may permit the iron roughneck \n151\n to move clear of the drill string \n120\n during drilling operations.', 'The spinner of the iron roughneck \n151\n may be utilized to apply low torque to make up and break out threaded connections between tubulars of the drill string \n120\n, and the torque wrench may be utilized to apply a higher torque to tighten and loosen the threaded connections.', 'A reciprocating slip \n161\n may be located on the rig floor \n114\n, such as may accommodate therethrough the conveyance means \n122\n during make up and break out operations and during the drilling operations.', 'The reciprocating slip \n161\n may be in an open position during drilling operations to permit advancement of the drill string \n120\n therethrough, and in a closed position to clamp an upper end of the conveyance means \n122\n (e.g., assembled tubulars) to thereby suspend and prevent advancement of the drill string \n120\n within the wellbore \n102\n, such as during the make up and break out operations.', 'During drilling operations, the hoisting equipment lowers the drill string \n120\n while the top drive \n116\n rotates the drill string \n120\n to advance the drill string \n120\n downward within the wellbore \n102\n and into the formation \n106\n.', 'During the advancement of the drill string \n120\n, the reciprocating slip \n161\n is in an open position, and the iron roughneck \n151\n is moved away or is otherwise clear of the drill string \n120\n.', 'When the upper portion of the tubular in the drill string \n120\n that is made up to the top drive shaft \n125\n is near the reciprocating slip \n161\n and/or the rig floor \n114\n, the top drive \n116\n ceases rotating and the reciprocating slip \n161\n closes to clamp the tubular made up to the top drive shaft \n125\n.', 'The grabber of the top drive \n116\n then clamps the upper portion of the tubular made up to the top drive shaft \n125\n, and the top drive shaft \n125\n rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaft \n125\n and the made up tubular.', 'The grabber of the top drive \n116\n may then release the tubular of the drill string \n120\n.', 'Multiple tubulars may be loaded on the rack of the catwalk \n131\n and individual tubulars (or stands of two or three tubulars) may be transferred from the rack to the groove in the catwalk \n131\n, such as by the spinner unit.', 'The tubular positioned in the groove may be conveyed along the groove by the skate \n133\n until an end of the tubular projects above the rig floor \n114\n.', 'The elevator \n129\n of the top drive \n116\n then grasps the protruding end, and the drawworks \n119\n is operated to lift the top drive \n116\n, the elevator \n129\n, and the new tubular.', 'The hoisting equipment then raises the top drive \n116\n, the elevator \n129\n, and the tubular until the tubular is aligned with the upper portion of the drill string \n120\n clamped in the slip \n161\n.', 'The iron roughneck \n151\n is moved toward the drill string \n120\n, and the lower tong of the torqueing portion \n153\n clamps onto the upper portion of the drill string \n120\n.', 'The spinning system rotates the new tubular (e.g., a threaded male end) into the upper portion of the drill string \n120\n (e.g., a threaded female end).', 'The upper tong then clamps onto the new tubular and rotates with high torque to complete making up the connection with the drill string \n120\n.', 'In this manner, the new tubular becomes part of the drill string \n120\n.', 'The iron roughneck \n151\n then releases and moves clear of the drill string \n120\n.', 'The grabber of the top drive \n116\n may then clamp onto the drill string \n120\n.', 'The top drive shaft \n125\n (e.g., a threaded male end) is brought into contact with the drill string \n120\n (e.g., a threaded female end) and rotated to make up a connection between the drill string \n120\n and the top drive shaft \n125\n.', 'The grabber then releases the drill string \n120\n, and the reciprocating slip \n161\n is moved to the open position.', 'Drilling operations may then resume.', 'The tubular handling equipment may further include a tubular handling manipulator (PHM) \n163\n disposed in association with a fingerboard \n165\n.', 'Although the PHM \n163\n and the fingerboard \n165\n are shown supported on the rig floor \n114\n, one or both of the PHM \n163\n and fingerboard \n165\n may be located on the wellsite surface \n104\n or another area of the well construction system \n100\n.', 'The fingerboard \n165\n provides storage (e.g., temporary storage) of tubulars (or stands of two or three tubulars) \n111\n during various operations, such as during and between tripping out and tripping in the drill string \n120\n.', 'The PHM \n163\n may be operable to transfer the tubulars \n111\n between the fingerboard \n165\n and the drill string \n120\n (i.e., space above the suspended drill string \n120\n).', 'For example, the PHM \n163\n may include arms \n167\n terminating with clamps \n169\n, such as may be operable to grasp and/or clamp onto one of the tubulars \n111\n.', 'The arms \n167\n of the PHM \n163\n may extend and retract, and/or at least a portion of the PHM \n163\n may be rotatable and/or movable toward and away from the drill string \n120\n, such as may permit the PHM \n163\n to transfer the tubular \n111\n between the fingerboard \n165\n and the drill string \n120\n.', 'To trip out the drill string \n120\n, the top drive \n116\n is raised, the reciprocating slip \n161\n is closed around the drill string \n120\n, and the elevator \n129\n is closed around the drill string \n120\n.', 'The grabber of the top drive \n116\n clamps the upper portion of the tubular made up to the top drive shaft \n125\n.', 'The top drive shaft \n125\n then rotates in a direction reverse from the drilling rotation to break out the connection between the top drive shaft \n125\n and the drill string \n120\n.', 'The grabber of the top drive \n116\n then releases the tubular of the drill string \n120\n, and the drill string \n120\n is suspended by (at least in part) the elevator \n129\n.', 'The iron roughneck \n151\n is moved toward the drill string \n120\n.', 'The lower tong clamps onto a lower tubular below a connection of the drill string \n120\n, and the upper tong clamps onto an upper tubular above that connection.', 'The upper tong then rotates the upper tubular to provide a high torque to break out the connection between the upper and lower tubulars.', 'The spinning system then rotates the upper tubular to separate the upper and lower tubulars, such that the upper tubular is suspended above the rig floor \n114\n by the elevator \n129\n.', 'The iron roughneck \n151\n then releases the drill string \n120\n and moves clear of the drill string \n120\n.', 'The PHM \n163\n may then move toward the tool string \n120\n to grasp the tubular suspended from the elevator \n129\n.', 'The elevator \n129\n then opens to release the tubular.', 'The PHM \n163\n then moves away from the tool string \n120\n while grasping the tubular with the clamps \n169\n, places the tubular in the fingerboard \n165\n, and releases the tubular for storage in the fingerboard \n165\n.', 'This process is repeated until the intended length of drill string \n120\n is removed from the wellbore \n102\n.', 'The surface equipment \n110\n of the well construction system \n100\n may also comprise a control center \n190\n (e.g., a cabin, a trailer, a facility, etc.) from which various portions of the well construction system \n100\n, such as the hoisting system, the tubular handling system, the drilling fluid circulation system, the well control devices, and the BHA \n124\n, among other examples, may be monitored and controlled.', 'The control center \n190\n may be located on the rig floor \n114\n or another location of the well construction system \n100\n, such as the wellsite surface \n104\n.', 'The control center \n190\n may contain or comprise a processing device \n192\n (e.g., a controller, a control system, a computer, etc.)', 'operable to provide control of one or more portions of the well construction system \n100\n and/or operable to monitor operations of one or more portions of the well construction system \n100\n.', 'For example, the processing device \n192\n may be communicatively connected with the various surface and downhole equipment described herein, and may be operable to receive signals from and transmit signals to such equipment to perform various operations described herein.', 'The processing device \n192\n may store executable programs, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of the operations described herein.', 'The processing device \n192\n may be communicatively connected with a human operator control workstation \n197\n from which various wellsite equipment or portions of the well construction system \n100\n may be monitored and controlled.', 'The operator workstation \n197\n may be operable for entering or otherwise communicating commands to the processing device \n192\n by a human wellsite operator \n195\n, and for displaying or otherwise communicating information from the processing device \n192\n to the wellsite operator \n195\n.', 'The operator workstation \n197\n may comprise a plurality of human-machine interface (HMI) devices, including one or more input devices \n194\n (e.g., a keyboard, a mouse, a joystick, a touchpad, etc.) and one or more output devices \n196\n (e.g., a video monitor, a printer, audio speakers, etc.).', 'The control center \n190\n may contain or comprise the operator workstation \n197\n.', 'Communication between the control center \n190\n, the processing device \n192\n, the input and output devices \n194\n, \n196\n of the operator workstation \n197\n, and the various wellsite equipment may be via wired and/or wireless communication means.', 'However, for clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure.', 'The well construction system \n100\n also includes stationary and/or mobile video cameras \n198\n disposed or utilized at various locations within the well construction system \n100\n.', 'The video cameras \n198\n capture videos of various components, portions, or subsystems of the well construction system \n100\n, and perhaps wellsite operators (humans) \n195\n and the actions they perform, during or otherwise in association with the wellsite operations, including while performing repairs to the well construction system \n100\n during a breakdown.', 'For example, the video cameras \n198\n may capture videos of the entire well construction system \n100\n and/or specific portions of the well construction system \n100\n, such as the top drive \n116\n, the iron roughneck \n151\n, the PHM \n163\n, the fingerboard \n165\n, and/or the catwalk \n131\n, among other examples.', 'The video cameras \n198\n generate corresponding video signals comprising or otherwise indicative of the captured videos.', 'The video cameras \n198\n may be in signal communication with the control center \n190\n, such as may permit the video signals to be transmitted to the processing device \n192\n and, thus, permit the wellsite operators \n195\n to view various portions or components of the well construction system \n100\n on one or more of the output devices \n196\n.', 'The processing device \n192\n or another portion of the control center \n190\n may be operable to record the video signals generated by the video cameras \n198\n.', 'Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in \nFIG.', '1\n.', 'Additionally, various components and/or subsystems of the well construction system \n100\n shown in \nFIG.', '1\n may include more or fewer components than as described above and depicted in \nFIG.', '1\n.', 'For example, various engines, motors, hydraulics, actuators, valves, and/or other components not explicitly described herein may be included in the well construction system \n100\n, and are within the scope of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of a control system \n200\n for the well construction system \n100\n according to one or more aspects of the present disclosure.', 'The following description refers to \nFIGS.', '1 and 2\n collectively.', 'The control system \n200\n may include a wellsite computing resource environment \n205\n, which may be located at the wellsite \n104\n as part of the well construction system \n100\n.', 'The wellsite computing resource environment \n205\n may include a coordinated control device \n204\n and/or a supervisory control system \n207\n.', 'The control system \n200\n may further include a remote computing resource environment \n206\n, which may be located offsite (i.e., not at the wellsite \n104\n).', 'The remote computing resource environment \n206\n may be communicatively connected with the wellsite computing resource environment \n206\n via a communication network.', 'A “cloud” computing environment is one example of a remote computing resource.', 'The cloud computing environment may communicate with the wellsite computing resource environment \n205\n via a network connection, such as via a wide-area-network (WAN), a local-area-network (LAN), and/or other networks also within the scope of the present disclosure.', 'The wellsite computing resource environment \n205\n may be or comprise at least a portion of the control center \n190\n and/or the processing device \n192\n described above.', 'As described above, the well construction system \n100\n may include various subsystems with different actuators and sensors for performing operations of the well construction system \n100\n, and these may be monitored and controlled via the wellsite computing resource environment \n205\n, the remote computing resource environment \n206\n, and/or local controllers \n241\n-\n247\n (e.g., control systems) of the corresponding subsystems.', 'The wellsite computing resource environment \n205\n may also provide for secured access to well construction system data, such as to facilitate onsite and offsite user devices monitoring the well construction system \n100\n, to send control processes to the well construction system \n100\n, and the like.', 'The various subsystems of the well construction system \n100\n may include a rig control (RC) system \n211\n, a fluid control (FC) system \n212\n, a managed pressure drilling control (MPDC) system \n213\n, a gas monitoring (GM) system \n214\n, a CCTV system \n215\n, a choke pressure control (CPC) system \n216\n, and a well control (WC) system \n217\n.', 'These subsystems \n211\n-\n217\n may include one or more of the components described above with respect to the well construction system \n100\n, such as described in the examples below.', 'The RC system \n211\n may include the wellsite structure \n112\n, the hoisting equipment (e.g., the drawworks \n119\n and the top drive \n116\n), drill string rotating equipment (e.g., the top drive \n116\n and/or the rotary table and Kelly), the reciprocating slip \n161\n, the drill pipe handling equipment (e.g., the catwalk \n131\n, the PHM \n163\n, the fingerboard \n165\n, and the iron roughneck \n151\n), electrical generators, and other equipment.', 'Accordingly, the RC system \n211\n may perform power generation and drill pipe handling, hoisting, and rotation operations.', 'The RC system \n211\n may also serve as a support platform for drilling equipment and staging ground for rig operations, such as connection make up and break out operations described above.', 'The FC system \n212\n may include the drilling fluid \n140\n, the pumps \n144\n, valves \n166\n, drilling fluid loading equipment, the solids and gas treatment equipment \n170\n, and/or other fluid control equipment.', 'Accordingly, the FC system \n212\n may perform fluid operations of the well construction system \n100\n.', 'The MPDC system \n213\n may include the RCD \n132\n, the choke manifold \n162\n, the downhole pressure sensors \n186\n, and/or other equipment.', 'The GM system \n214\n may comprise the gas sensors \n174\n, \n178\n and/or other equipment.', 'The CCTV system \n215\n may include the video cameras \n198\n, one or more other input devices (e.g., a keyboard, a touchscreen, etc.), one or more video output devices (e.g., video monitors), various communication equipment (e.g., modems, network interface cards, etc.), and/or other equipment.', 'The CCTV system \n215\n may be utilized to configure the CCTV system \n215\n, capture real-time video of various portions or subsystems \n211\n-\n217\n of the well construction system \n100\n, and display video signals from the video cameras \n198\n on the video output devices to display in real-time the various portions or subsystems \n211\n-\n217\n of the well construction system \n100\n.', 'Video captured by the video cameras \n198\n may also be stored on a memory device associated with the wellsite computing resource environment \n205\n or another portion of the control system \n200\n, and viewed by the operator \n195\n on a video output device.', 'The CPC system \n216\n may comprise the choke manifold \n162\n and/or other equipment, and the WC system \n217\n may comprise the well control devices (e.g., the BOP stack \n130\n, the annular fluid control device \n132\n, etc.) and/or other equipment.', 'The control system \n200\n may be in real-time communication with the various components of the subsystems \n211\n-\n217\n.', 'For example, the local controllers \n241\n-\n247\n may be in communication with various portions of corresponding subsystems \n211\n-\n217\n (e.g., sensors \n221\n-\n227\n and actuators \n231\n-\n237\n, shown in \nFIG.', '3\n) via local communication networks (not shown), and the wellsite computing resource environment \n205\n may be in communication with the subsystems \n211\n-\n217\n via a data bus or network \n202\n.', 'As described below, data or sensor signals generated by various sensors of the subsystems \n211\n-\n217\n may be made available for use by processes or devices of the control system \n200\n.', 'Similarly, data or control signals generated by the processes or devices of the control system \n200\n may be automatically communicated to various actuators of the subsystems \n211\n-\n217\n, perhaps pursuant to predetermined programming, such as to facilitate well construction operations or processes described herein.', 'Via the coordinated control device \n204\n and the local controllers \n241\n-\n247\n, the control system \n200\n may be operable to monitor various sensors of the wellsite subsystems \n211\n-\n217\n in real-time, and to provide real-time control commands to such subsystems \n211\n-\n217\n, such that sensor data generated by the various sensors may be utilized to provide real-time control commands to the subsystems \n211\n-\n217\n and other subsystems of the well construction system \n100\n.', 'Data may be generated by both sensors and computation, and may be utilized for coordinated control among two or more of the subsystems \n211\n-\n217\n, such as for bottom-hole pressure control.', 'FIG.', '3\n is a schematic view of an example implementation of the control system \n200\n shown in \nFIG.', '2\n according to one or more aspects of the present disclosure.', 'The following description refers to \nFIGS.', '1-3\n collectively.', 'FIG.', '3\n also depicts the above-described subsystems \n211\n-\n217\n of the well construction system \n100\n, such as the RC system \n211\n, the FC system \n212\n, the MPDC system \n213\n, the GM system \n214\n, the CCTV system \n215\n, the CPC system \n216\n, and the WC system \n217\n.', 'An example implementation of the well construction system \n100\n may include one or more onsite user devices \n219\n, such as may be communicatively connected or otherwise interact with an information technology (IT) system \n218\n of the wellsite computing resource environment \n205\n.', 'The onsite user devices \n219\n may be or comprise stationary and/or portable user devices stationed at the well construction system \n100\n.', 'For example, the onsite user devices \n219\n may include a desktop computer, a laptop computer, a smartphone or other portable smart device, a personal digital assistant (PDA), a tablet/touchscreen computer, a wearable computer, and/or other devices.', 'The onsite user devices \n219\n may be or comprise the operator workstation \n197\n shown in \nFIG.', '1\n and described above.', 'The onsite user devices \n219\n may be operable to communicate with the wellsite computing resource environment \n205\n, such as via the IT system \n218\n, and/or the remote computing resource environment \n206\n, such as via a network \n208\n.', 'The IT system \n218\n may include communication conduits, software, computers, and other IT equipment facilitating communication between one or more portions of the wellsite computing resource environment \n205\n, and/or between the wellsite computing resource environment \n205\n and another portion of the well construction system \n100\n, such as the remote computing resource environment \n206\n.', 'The control system \n200\n may include (or otherwise be utilized in conjunction with) one or more offsite user devices \n220\n.', 'The offsite user devices \n220\n may be or comprise a desktop computer, a laptop computer, a smartphone and/or other portable smart device, a PDA, a tablet/touchscreen computer, a wearable computer, and/or other devices.', 'The offsite user devices \n220\n may be operable to receive and/or transmit information (e.g., for monitoring functionality) from and/or to the well construction system \n100\n, such as by communication with the wellsite computing resource environment \n205\n via the network \n208\n.', 'The offsite user devices \n220\n may be utilized for monitoring functions, but may also provide control processes for controlling operation of the various subsystems \n211\n-\n218\n of the well construction system \n100\n.', 'The offsite user devices \n220\n and/or the wellsite computing resource environment \n205\n may also be operable to communicate with the remote computing resource environment \n206\n via the network \n208\n.', 'The network \n208\n may be a WAN, such as the internet, a cellular network, a satellite network, other WANs, and/or combinations thereof.', 'The subsystems \n211\n-\n217\n of the well construction system \n100\n may include sensors, actuators, and controllers.', 'The controllers may be programmable logic controllers (PLCs) and/or other controllers having aspects similar to the example processing device \n600\n shown in \nFIG.', '12\n.', 'The RC system \n211\n may include one or more sensors (S) \n221\n, one or more actuators (A) \n231\n, and one or more controllers \n241\n.', 'The FC system \n212\n may include one or more sensors \n222\n, one or more actuators \n232\n, and one or more controllers \n242\n.', 'The MPDC system \n213\n may include one or more sensors \n223\n, one or more actuators \n233\n, and one or more controllers \n243\n.', 'The GM system \n214\n may include one or more sensors \n224\n, one or more actuators \n234\n, and one or more controllers \n244\n.', 'The CCTV system \n215\n may include one or more sensors \n225\n, one or more actuators \n235\n, and one or more controllers \n245\n.', 'The controller \n245\n of the CCTV system \n215\n may be or comprise a network server, such as may be operable to selectively grant and forbid access priority and privileges to the video cameras \n198\n and historical video recordings, serve live video from the video cameras \n198\n to the client computers (e.g., workstations \n197\n), and serve historical video to the client computers.', 'The server may also operate as a gateway for user authentication and control signals (e.g., pan/tilt, zoom, focus, iris, presets, etc.), as described below.', 'The CPC system \n216\n may include one or more sensors \n226\n, one or more actuators \n236\n, and one or more controllers \n246\n.', 'The WC system \n217\n may include one or more sensors \n227\n, one or more actuators \n237\n, and one or more controllers \n247\n.', 'The sensors \n221\n-\n227\n may include sensors utilized for operation of the well construction system \n100\n.', 'For example, the sensors \n221\n-\n227\n may include cameras, position sensors, pressure sensors, temperature sensors, flow rate sensors, vibration sensors, current sensors, voltage sensors, resistance sensors, gesture detection sensors or devices, voice actuated or recognition devices or sensors, and/or other examples.', 'The sensors \n221\n-\n227\n may be operable to provide sensor data to the wellsite computing resource environment \n205\n, such as to the coordinated control device \n204\n.', 'For example, the sensors \n221\n-\n227\n may provide sensor data (S Data) \n251\n-\n257\n, respectively.', 'The sensor data \n251\n-\n257\n may include signals or information indicative of equipment operation status (e.g., on or off, up or down, set or release, etc.), drilling parameters (e.g., depth, hook load, torque, etc.), auxiliary parameters (e.g., vibration data of a pump), and/or other examples.', 'The acquired sensor data \n251\n-\n257\n may include or be associated with a timestamp (e.g., date and/or time) indicative of when the sensor data \n251\n-\n257\n was acquired.', 'The sensor data \n251\n-\n257\n may also or instead be aligned with a depth or other drilling parameter.', 'Acquiring the sensor data \n251\n-\n257\n at the coordinated control device \n204\n may facilitate measurement of the same physical properties at different locations of the well construction system \n100\n, wherein the sensor data \n251\n-\n257\n may be utilized for measurement redundancy to permit continued well construction operations.', 'Measurements of the same physical properties at different locations may also be utilized for detecting equipment conditions among different physical locations at the wellsite surface \n104\n or within the wellbore \n102\n.', 'Variation in measurements at different wellsite locations over time may be utilized to determine equipment performance, system performance, scheduled maintenance due dates, and the like.', 'For example, slip status (e.g., set or unset) may be acquired from the sensors \n221\n and communicated to the wellsite computing resource environment \n205\n.', 'Acquisition of fluid samples may be measured by a sensor, such as the sensors \n186\n, \n223\n, and related with bit depth and time measured by other sensors.', 'Acquisition of data from the video cameras \n198\n, \n225\n may facilitate detection of arrival and/or installation of materials or equipment at the well construction system \n100\n.', 'The time of arrival and/or installation of materials or equipment may be utilized to evaluate degradation of material, scheduled maintenance of equipment, and other evaluations.', 'The coordinated control device \n204\n may facilitate control of one or more of the subsystems \n211\n-\n217\n at the level of each individual subsystem \n211\n-\n217\n.', 'For example, in the FC system \n212\n, sensor data \n252\n may be fed into the controller \n242\n, which may respond to control the actuators \n232\n.', 'However, for control operations that involve multiple systems, the control may be coordinated through the coordinated control device \n204\n.', 'For example, coordinated control operations may include the control of downhole pressure during tripping.', 'The downhole pressure may be affected by both the FC system \n212\n (e.g., pump rate), the MPDC \n213\n (e.g., choke position of the MPDC), and the RC system \n211\n (e.g. tripping speed).', 'Thus, when it is intended to maintain certain downhole pressure during tripping, the coordinated control device \n204\n may be utilized to direct the appropriate control commands to two or more (or each) of the participating subsystems.', 'Control of the subsystems \n211\n-\n217\n of the well construction system \n100\n may be provided via a three-tier control system that includes a first tier of the local controllers \n241\n-\n247\n, a second tier of the coordinated control device \n204\n, and a third tier of the supervisory control system \n207\n.', 'Coordinated control may also be provided by one or more controllers \n241\n-\n247\n of one or more of the subsystems \n211\n-\n217\n without the use of a coordinated control device \n204\n.', 'In such implementations of the control system \n200\n, the wellsite computing resource environment \n205\n may provide control processes directly to these controllers \n241\n-\n247\n for coordinated control.', 'The sensor data \n251\n-\n257\n may be received by the coordinated control device \n204\n and utilized for control of the subsystems \n211\n-\n217\n.', 'The sensor data \n251\n-\n257\n may be encrypted to produce encrypted sensor data \n271\n.', 'For example, the wellsite computing resource environment \n205\n may encrypt sensor data from different types of sensors and systems to produce a set of encrypted sensor data \n271\n.', 'Thus, the encrypted sensor data \n271\n may not be viewable by unauthorized user devices (either offsite user devices \n220\n or onsite user devices \n219\n) if such devices gain access to one or more networks of the well construction system \n100\n.', 'The encrypted sensor data \n271\n may include a timestamp and an aligned drilling parameter (e.g., depth) as described above.', 'The encrypted sensor data \n271\n may be communicated to the remote computing resource environment \n206\n via the network \n208\n and stored as encrypted sensor data \n272\n.', 'The wellsite computing resource environment \n205\n may provide the encrypted sensor data \n271\n, \n272\n available for viewing and processing offsite, such as via the offsite user devices \n220\n.', 'Access to the encrypted sensor data \n271\n, \n272\n may be restricted via access control implemented in the wellsite computing resource environment \n205\n.', 'The encrypted sensor data \n271\n, \n272\n may be provided in real-time to offsite user devices \n220\n such that offsite personnel may view real-time status of the well construction system \n100\n and provide feedback based on the real-time sensor data.', 'For example, different portions of the encrypted sensor data \n271\n, \n272\n may be sent to the offsite user devices \n220\n.', 'The encrypted sensor data \n271\n, \n272\n may be decrypted by the wellsite computing resource environment \n205\n before transmission, and/or decrypted on the offsite user device \n220\n after encrypted sensor data is received.', 'The offsite user device \n220\n may include a thin client (not shown) configured to display data received from the wellsite computing resource environment \n205\n and/or the remote computing resource environment \n206\n.', 'For example, multiple types of thin clients (e.g., devices with display capability and minimal processing capability) may be utilized for certain functions or for viewing various sensor data \n251\n-\n257\n.', 'The wellsite computing resource environment \n205\n may include various computing resources utilized for monitoring and controlling operations, such as one or more computers having a processor and a memory.', 'For example, the coordinated control device \n204\n may include a processing device, such as the processing device \n600\n shown in \nFIG.', '12\n, having a processor and memory for processing the sensor data, storing the sensor data, and issuing control commands responsive to the sensor data.', 'As described above, the coordinated control device \n204\n may control various operations of the subsystems \n211\n-\n217\n via analysis of sensor data \n251\n-\n257\n from one or more of the wellsite subsystems \n211\n-\n217\n to facilitate coordinated control between the subsystems \n211\n-\n217\n.', 'The coordinated control device \n204\n may generate control data \n273\n (e.g., signals, commands, coded instructions) to execute control of the subsystems \n211\n-\n217\n.', 'The coordinated control device \n204\n may transmit the control data \n273\n to one or more subsystems \n211\n-\n217\n.', 'For example, control data (C Data) \n261\n may be sent to the RC system \n211\n, control data \n262\n may be sent to the FC system \n212\n, control data \n263\n may be sent to the MPDC system \n213\n, control data \n264\n may be sent to the GM system \n214\n, control data \n265\n may be sent to the CCTV system \n215\n, control data \n266\n may be sent to the CPC system \n216\n, and control data \n267\n may be sent to the WC system \n217\n.', 'The control data \n261\n-\n267\n may include, for example, human operator commands (e.g., turn on or off a pump, switch on or off a valve, update a physical property set-point, etc.).', 'The coordinated control device \n204\n may include a fast control loop that directly obtains sensor data \n251\n-\n257\n and executes, for example, a control algorithm.', 'The coordinated control device \n204\n may include a slow control loop that obtains data via the wellsite computing resource environment \n205\n to generate control commands.', 'The coordinated control device \n204\n may intermediate between the supervisory control system \n207\n and the local controllers \n241\n-\n247\n of the subsystems \n211\n-\n217\n, such as may permit the supervisory control system \n207\n to control the subsystems \n211\n-\n217\n.', 'The supervisory control system \n207\n may include, for example, devices for entering control commands to perform operations of the subsystems \n211\n-\n217\n.', 'The coordinated control device \n204\n may receive commands from the supervisory control system \n207\n, process such commands according to a rule (e.g., an algorithm based upon the laws of physics for drilling operations), and provide control data to one or more subsystems \n211\n-\n217\n.', 'The supervisory control system \n207\n may be provided by the wellsite operator \n195\n and/or process monitoring and control program.', 'In such implementations, the coordinated control device \n204\n may coordinate control between discrete supervisory control systems and the subsystems \n211\n-\n217\n while utilizing control data \n261\n-\n267\n that may be generated based on the sensor data \n251\n-\n257\n received from the subsystems \n211\n-\n217\n and analyzed via the wellsite computing resource environment \n205\n.', 'The coordinated control device \n204\n may receive the control data \n251\n-\n257\n and then dispatch control data \n261\n, including interlock commands, to each subsystem \n211\n-\n217\n.', 'The coordinated control device \n204\n may also or instead just listen to the control data \n251\n-\n257\n being dispatched to each subsystem \n221\n-\n227\n and then initiate the machine interlock commands to the relevant local controller \n241\n-\n247\n.', 'The coordinated control device \n204\n may run with different levels of autonomy.', 'For example, the coordinated control device \n204\n may operate in an advice mode to inform wellsite operators \n195\n to perform a specific task or take specific corrective action based on sensor data \n251\n-\n257\n received from the various subsystems \n211\n-\n217\n.', 'While in the advice mode, the coordinated control device \n204\n may, for example, advise or instruct the wellsite operator \n195\n to perform a standard work sequence when gas is detected on the rig floor \n114\n, such as to close the annular BOP \n132\n.', 'Furthermore, if the wellbore \n102\n is gaining or losing drilling fluid \n140\n, the coordinated control device \n204\n may, for example, advise or instruct the wellsite operator \n195\n to modify the density of the drilling fluid \n140\n, modify the pumping rate of the drilling fluid \n140\n, and/or modify the pressure of the drilling fluid within the wellbore \n102\n.', 'The coordinated control device \n204\n may also operate in a system/equipment interlock mode, whereby certain operations or operational sequences are prevented based on the received sensor data \n251\n-\n257\n.', 'While operating in the interlock mode, the coordinated control device \n204\n may manage interlock operations among the various equipment of the subsystems \n211\n-\n217\n.', 'For example, if a pipe ram of the BOP stack \n130\n is activated, the coordinated control device \n204\n may issue an interlock command to the RC system controller \n241\n to stop the drawworks \n119\n from moving the drill string \n120\n.', 'However, if a shear ram of the BOP stack \n130\n is activated, the coordinated control device \n204\n may issue an interlock command to the controller \n241\n to operate the drawworks \n119\n to adjust the position of the drill string \n120\n within the BOP stack \n130\n before activating the shear ram, so that the shear ram does not align with a shoulder of the tubulars forming the drill string \n120\n.', 'The coordinated control device \n204\n may also operate in an automated sequence mode, whereby certain operations or operational sequences are automatically performed based on the received sensor data \n251\n-\n257\n.', 'For example, the coordinated control device \n204\n may activate an alarm and/or stop or reduce operating speed of the pipe handling equipment when a wellsite operator \n195\n is detected close to a moving iron roughneck \n151\n, the PHM \n163\n, or the catwalk \n131\n.', 'As another example, if the wellbore pressure increases rapidly, the coordinated control device \n204\n may close the annular BOP \n132\n, close one or more rams of the BOP stack \n130\n, and/or adjust the choke manifold \n162\n.', 'The wellsite computing resource environment \n205\n may comprise or execute a monitoring process \n274\n (e.g., an event detection process) that may utilize the sensor data \n251\n-\n257\n to determine information about status of the well construction system \n100\n and automatically initiate an operational action, a process, and/or a sequence of one or more of the subsystems \n211\n-\n217\n.', 'The monitoring process \n274\n may initiate the operational action to be caused by the coordinated control device \n204\n.', 'Depending on the type and range of the sensor data \n251\n-\n257\n received, the operational actions may be executed in the advice mode, the interlock mode, or the automated sequence mode.', 'For example, the monitoring process \n274\n may determine a drilling state, equipment health, system health, a maintenance schedule, or combination thereof, and initiate an advice to be generated.', 'The monitoring process \n274\n may also detect abnormal drilling events, such as a wellbore fluid loss and gain, a wellbore washout, a fluid quality issue, or an equipment event based on job design and execution parameters (e.g., wellbore, drilling fluid, and drill string parameters), current drilling state, and real-time sensor information from the surface equipment \n110\n (e.g., presence of hazardous gas at the rig floor, presence of human wellsite operators in close proximity to moving pipe handling equipment, etc.) and the BHA \n124\n, initiating an operational action in the automated mode.', 'The monitoring process \n274\n may be connected to the real-time communication network \n202\n.', 'The coordinated control device \n204\n may initiate a counteractive measure (e.g., a predetermined action, process, or operation) based on the events detected by the monitoring process \n274\n.', 'The term “event” as used herein may include, but not be limited to, an operational and safety related event described herein and/or another operational and safety related event that can take place at a well construction system.', 'The events described herein may be detected by the monitoring process \n274\n based on the sensor data \n251\n-\n257\n (e.g., sensor signals or information) received and analyzed by the monitoring process \n274\n.', 'The wellsite computing resource environment \n205\n may also comprise or execute a control process \n275\n that may utilize the sensor data \n251\n-\n257\n to optimize drilling operations, such as the control of drilling equipment to improve drilling efficiency, equipment reliability, and the like.', 'For example, the acquired sensor data \n252\n may be utilized to derive a noise cancellation scheme to improve electromagnetic and mud pulse telemetry signal processing.', 'The remote computing resource environment \n206\n may comprise or execute a control process \n276\n substantially similar to the control process \n275\n that may be provided to the wellsite computing resource environment \n205\n.', 'The monitoring and control processes \n274\n, \n275\n, \n276\n may be implemented via, for example, a control algorithm, a computer program, firmware, or other hardware and/or software.', 'The wellsite computing resource environment \n205\n may include various computing resources, such as a single computer or multiple computers.', 'The wellsite computing resource environment \n205\n may further include a virtual computer system and a virtual database or other virtual structure for collected data, such as may include one or more resource interfaces (e.g., web interfaces) that facilitate the submission of application programming interface (API) calls to the various resources through a request.', 'In addition, each of the resources may include one or more resource interfaces that facilitate the resources to access each other (e.g., to facilitate a virtual computer system of the computing resource environment to store data in or retrieve data from the database or other structure for collected data).', 'The virtual computer system may include a collection of computing resources configured to instantiate virtual machine instances.', 'A wellsite operator \n195\n may interface with the virtual computer system via the offsite user device \n220\n or the onsite user device \n219\n.', 'Other computer systems or computer system services may be utilized in the wellsite computing resource environment \n205\n, such as a computer system or computer system service that provides computing resources on dedicated or shared computers/servers and/or other physical devices.', 'The wellsite computing resource environment \n205\n may include a single server (in a discrete hardware component or as a virtual server) or multiple servers (e.g., web servers, application servers, or other servers).', 'The servers may be, for example, computers arranged in physical and/or virtual configuration.', 'The wellsite computing resource environment \n205\n may also include a database that may be or comprise a collection of computing resources that run one or more data collections.', 'Such data collections may be operated and managed by utilizing API calls.', 'The data collections, such as the sensor data \n251\n-\n257\n, may be made available to other resources in the wellsite computing resource environment \n205\n, or to user devices (e.g., onsite user device \n219\n and/or offsite user device \n220\n) accessing the wellsite computing resource environment \n205\n.', 'The remote computing resource environment \n206\n may include computing resources similar to those described above, such as a single computer or multiple computers (in discrete hardware components or virtual computer systems).', 'The wellsite computing resource environment \n205\n may facilitate an integral display or output means showing various information, such as the sensor data \n251\n-\n257\n, the control data \n261\n-\n267\n, processes taking place, events being detected, and drilling equipment operation status and control information.', 'The wellsite computing resource environment \n205\n may be communicatively connected with one or more HMI devices.', 'The HMI devices may include one or more input devices for receiving commands from the wellsite operators \n195\n to control the actuators \n231\n-\n237\n of a selected one of the subsystems \n211\n-\n217\n.', 'The input means may be provided via hardware controls, such as physical buttons, slider bars, switches/rotary switches, joysticks, keyboards, mice, and the like.', 'The HMI devices may also include one or more output devices, such as video output devices (e.g., LCD screens), printers, and audio speakers.', 'The HMI devices may be implemented as part of, or utilized in association with, the onsite and/or offsite user devices \n219\n, \n220\n.', 'Selected information from the operations of the subsystems \n211\n-\n217\n may be shown to the wellsite operator \n195\n via multiple display screens.', 'Each display screen may display information related to a corresponding subsystem \n211\n-\n217\n and other selected information.', 'Each display screen may integrate selected sensor data \n251\n-\n257\n from the corresponding subsystem \n211\n-\n217\n with information from the monitoring process \n274\n, the control process \n275\n, and/or the control data \n261\n-\n267\n generated by the coordinated control device \n204\n, for display to the wellsite operator \n195\n.', 'The display screens may be shown or displayed alternately on a single video output device or simultaneously on one or more video output devices.', 'When utilizing a single video output device, the display screen to be displayed may be selected by the wellsite operator \n195\n via the input means.', 'The display screen to be displayed on the video output device may also or instead be selected automatically by the monitoring process \n274\n based on operational events detected or planned at the well construction system \n100\n (e.g., a drilling process or event), such that information relevant to an event currently taking place is displayed.', 'Each display screen may also include operational controls in the form of virtual or software buttons, toggles, levers, slide bars, icons, and the like (e.g., on/off buttons, increase/decrease slide bars), such as may be utilized to select the display screen and/or control operation of the subsystem \n211\n-\n217\n associated with the display screen.', 'The plurality of display screens described herein may be collectively referred to hereinafter as an integrated display.', 'The display screens may also display video signals (e.g., one or more video feeds) generated by one or more of the video cameras \n198\n of the CCTV system \n215\n.', 'One or more video signals may be displayed on a dedicated video output device and/or one or more video signals may be displayed in a picture-in-picture (PIP) video window inset or embedded on a display screen showing other information.', 'Sourcing (i.e., selection) of the video camera \n198\n whose video signal is to be displayed on the display screen may be automated based on operational events (e.g., drilling events, drilling operation processes, etc.)', 'at the well construction system \n100\n, such that video signals relevant to an event currently taking place are displayed.', 'FIG.', '4\n is a schematic view of a portion of an example implementation of a wellsite operator control workstation \n300\n communicatively connected with the processing device \n192\n (e.g., the wellsite computing resource environment \n205\n) and/or other portions of the well construction system \n100\n according to one or more aspects of the present disclosure.', 'The operator workstation \n300\n comprises an operator chair \n302\n and an HMI system comprising a plurality of input and output devices disposed in association with and/or integrated with the operator chair \n302\n to permit the wellsite operator \n195\n to enter commands or other information to the processing device \n192\n and receive information from the processing device \n192\n and other portions of the well construction system \n100\n.', 'The operator chair \n302\n may include a seat \n304\n, a left armrest \n306\n, and a right armrest \n308\n.', 'The input devices of the operator workstation \n300\n may include a left joystick \n310\n, a right joystick \n312\n, and a plurality of buttons, knobs, dials, switches, or other physical controls \n314\n, \n315\n, \n316\n, \n318\n, \n320\n.', 'One or more of the joysticks \n310\n, \n312\n and/or the physical controls \n314\n, \n315\n, \n316\n may be integrated into the corresponding armrests \n306\n, \n308\n of the operator chair \n302\n to permit the wellsite operator \n195\n to operate these input devices from the operator chair \n304\n.', 'Furthermore, one or more of the physical controls \n318\n, \n320\n may be integrated into the corresponding joysticks \n310\n, \n312\n to permit the wellsite operator \n195\n to operate these physical controls \n318\n, \n320\n while operating the joysticks \n310\n, \n312\n.', 'The physical controls \n315\n may be emergency stop (E-stop) buttons, which may be electrically connected to E-stop relays of one or more pieces of wellsite equipment (e.g., the iron roughneck \n151\n, the PHM \n163\n, the drawworks \n119\n, the top drive \n116\n, etc.), such that the wellsite operator \n195\n can shut down the wellsite equipment during emergencies and other situations.', 'The output devices of the operator workstation \n300\n may include one or more video output devices \n322\n, \n324\n, \n326\n (e.g., video monitors) disposed in association with the operator chair \n304\n and operable to display to the wellsite operator \n195\n information from the processing device \n192\n and other portions of the well construction system \n100\n.', 'The video output devices may be implemented as one or more LCD displays, LED displays, plasma displays, cathode ray tube (CRT) displays, and/or other types of displays.', 'The video output devices \n322\n, \n324\n may be or comprise touch screens operable to display information to the wellsite operator \n195\n and receive commands or information from the wellsite operator \n195\n via a plurality of software buttons, switches, knobs, dials, icons, and/or other software controls \n328\n, \n330\n displayed on the video output devices \n322\n, \n324\n.', 'The software controls \n328\n, \n330\n may be operated (e.g., selected) via finger contact by the wellsite operator \n195\n.', 'The video output devices \n322\n, \n324\n may be disposed on or integrated into the arm rests \n306\n, \n308\n or other parts of the operator chair \n304\n to permit the wellsite operator \n195\n to operate the software controls \n328\n, \n330\n displayed on the video output devices \n322\n, \n324\n from the operator chair \n304\n.', 'The video output devices \n326\n may be disposed in front of or otherwise adjacent the operator chair \n302\n.', 'The video output devices \n326\n may include a plurality of video output devices \n332\n, \n334\n, \n336\n, each dedicated to displaying predetermined information in a predetermined (e.g., programmed) manner.', 'Although the video output devices \n326\n are shown comprising three video output devices \n332\n, \n334\n, \n336\n, the video output devices \n326\n may be or comprise one, two, four, or more video output devices.', 'When one or two video output devices are utilized, different portions of screens displayed on the two video output devices may each be dedicated to displaying predetermined information in a predetermined manner.', 'One or more of the video output devices \n326\n may be operated as both input and output devices.', 'For example, the video output devices \n334\n, \n336\n may display information related to the control and monitoring of the various subsystems \n211\n-\n217\n of the well construction system \n100\n.', 'The video output devices \n334\n, \n336\n may further display sensor signals or information \n340\n generated by the various sensors \n221\n-\n227\n of the well construction system \n100\n to permit the wellsite operator \n195\n to monitor operational status of the subsystems \n211\n-\n217\n.', 'The video output devices \n334\n, \n336\n may also display a plurality of software buttons, icons, switches, knobs, slide bars, dials, or other software controls \n342\n displayed on the video output devices \n334\n, \n336\n to permit the wellsite operator \n195\n to control the various actuators \n231\n-\n237\n or other portions of the subsystems \n211\n-\n217\n.', 'The software controls \n342\n may be operated by the physical controls \n314\n, \n316\n, the joysticks \n310\n, \n312\n, the touchscreens \n322\n, \n324\n, or other input devices of the operator workstation \n300\n.', 'One or more portions of the operator workstation \n300\n may comprise or form a portion of the CCTV system \n215\n described above and shown in \nFIGS.', '1-3\n.', 'For example, one or more of the video output devices \n326\n may be configured to display the video signals generated by one or more of the video cameras \n198\n.', 'The video output device \n332\n may operate purely as an output device dedicated for displaying the video signals generated by one or more of the video cameras \n198\n.', 'When displaying the video signals from multiple video cameras \n198\n, the display screen of the video output device \n326\n may be divided into or comprise multiple video windows, each displaying a corresponding video signal.', 'One or more of the video output devices \n334\n, \n336\n may display an integrated display screen displaying the sensor information \n340\n, the software controls \n342\n, and the video signals from one or more of the video cameras \n198\n.', 'For example, one or both of the display screens of the video output devices \n334\n, \n336\n may include one or more PIP video windows \n344\n, each displaying a video signal from a corresponding one of the video cameras \n198\n.', 'The PIP video windows \n344\n may be embedded or inset on the corresponding display screens along or adjacent the sensor information \n340\n and the software controls \n342\n.', 'FIGS.', '5 and 6\n are views of example implementations of display screens \n402\n, \n404\n generated by the processing device \n192\n (e.g., the wellsite computing resource environment \n205\n) and displayed on one or more of the video output devices \n326\n according to one or more aspects of the present disclosure.', 'The example display screen \n402\n displays various sensor information and software controls related to the control and monitoring of the WC system \n217\n and other related drilling or equipment information.', 'The example display screen \n404\n displays various sensor information and software controls related to the control and monitoring of the CPC system \n216\n and other related drilling or equipment information.', 'The display screens, including the display screens \n402\n, \n404\n, may comprise a wellsite subsystem selector/indicator window or area \n406\n, which may be utilized to switch between or select which one or more of the display screens are being displayed on the video output device.', 'The selector/indicator area \n406\n may be continuously displayed regardless of which display screen is being shown on the video output device.', 'The area \n406\n may comprise a subsystem selection menu \n408\n, such as a plurality of indicator bars, tabs, or buttons, each listing a subsystem \n211\n-\n217\n of the well construction system \n100\n.', 'The wellsite operator \n195\n may operate (e.g., click on, touch, highlight, and/or otherwise select) one of the buttons to select and view the display screen and the associated subsystem information.', 'The button associated with the selected subsystem \n211\n-\n217\n may light up, change color, and/or otherwise indicate which display screen and, thus, subsystem \n211\n-\n217\n, is being shown.', 'The selector/indicator area \n406\n may also include a SAFETY button, which may be selected to show the display screen with status of various safety equipment of the well construction system \n100\n, including gas detectors \n174\n, \n178\n and fire detectors.', 'Although the subsystem selection menu \n408\n is shown as a list that is permanently maintained on the display screens \n402\n, \n404\n, the subsystem selection menu \n408\n may be implemented as a dropdown or pop-up menu, displaying a list of subsystems \n211\n-\n217\n when clicked on or otherwise operated.', 'The selector/indicator area \n406\n may also include a plurality of alarms or event indicators \n410\n (e.g., lights), each associated with a corresponding subsystem selection button.', 'The monitoring process \n274\n may activate (e.g., light up, change color, etc.)', 'one or more of the event indicators \n410\n to show or alarm the wellsite operator \n195\n of an operational event at or associated with a corresponding subsystem \n211\n-\n217\n that may be associated with a predetermined corrective action or another action by the wellsite operator \n195\n.', 'Responsive to the event indicator \n410\n being activated, the wellsite operator \n195\n may switch to a display screen corresponding to the activated event indicator to assess the event and/or implement appropriate counteractive measures or actions.', 'Instead of manually changing between the display screens, the processing device \n192\n may automatically change the display screen to show the display screen corresponding to a subsystem \n211\n-\n217\n experiencing the event.', 'The display screens, including the display screens \n402\n, \n404\n, may further comprise a driller information window or area \n412\n displaying selected sensor data \n251\n-\n257\n or information related to status of drilling operations.', 'For example, the area \n412\n may include selected sensor data \n251\n from the RC system \n211\n, selected sensor data \n252\n from the FC system \n212\n, and/or selected sensor data from the WC system \n217\n.', 'The area \n412\n may display information such as hook load, traveling block position, drill bit depth, wellbore depth, number of stands or tubulars in the wellbore, standpipe pressure, top drive dolly location, inside BOP position, top drive pipe connection status, elevator status, stickup connection status, and slips status.', 'The area \n412\n may be continuously displayed regardless of which display screen is being shown on the video output device.', 'Each display screen, including the display screens \n402\n, \n404\n, may further comprise a corresponding subsystem information window or area \n414\n, \n418\n, respectively, displaying selected sensor data \n251\n-\n257\n or information related to a subsystem \n211\n-\n217\n being shown on the display screen.', 'The information displayed in the area \n414\n may switch when the wellsite operator \n195\n or the processing device \n192\n switches between the display screens of the integrated display.', 'The subsystem information area \n414\n of the display screen \n402\n may comprise a schematic view \n415\n of the BOP stack \n130\n and a plurality of status bars \n416\n indicative of status of corresponding portions of the BOP stack \n130\n.', 'The status bars \n416\n may display sensor data \n257\n showing operational parameters of the WC system \n217\n such as flow, pressure, temperature, and preventer position.', 'The area \n414\n may further show the sensor data \n257\n of the WC system \n217\n in table or list form.', 'One or more operational parameters (e.g., preventer position) of the WC system \n217\n may be changed, for example, by entering in the status bars \n416\n or on the list \n257\n the intended values of the one or more operational parameters, causing the coordinated control device \n204\n to transmit corresponding control data \n267\n to the controller \n247\n of the WC system \n217\n to change the operational parameters as intended.', 'The subsystem information area \n418\n of the display screen \n404\n may comprise a schematic view \n419\n of the choke manifold \n162\n and a plurality of status bars \n420\n indicative of status of corresponding portions of the choke manifold \n162\n.', 'The status bars \n420\n may display sensor data \n256\n showing operational parameters of the CPC system \n216\n, such as flow, pressure, temperature, and position.', 'The area \n418\n may further show the sensor data \n256\n of the CPC system \n216\n in table or list form.', 'One or more operational parameters of the CPC system \n216\n may be changed, for example, by entering in the status bars \n420\n or on the list \n256\n the intended values of the one or more operational parameters, causing the coordinated control device \n204\n to transmit corresponding control data \n266\n to the controller \n246\n of the CPC system \n216\n to change the operational parameters as intended.', 'Each display screen, including the display screens \n402\n, \n404\n, may further include a one or more PIP video windows \n422\n, each displaying in real-time a video signal from a predetermined video camera \n198\n to display a predetermined portion of the well construction system \n100\n, a predetermined one of the subsystems \n211\n-\n217\n, and/or predetermined wellsite equipment.', 'The PIP video windows \n422\n may be embedded or inset on the corresponding display screens \n402\n, \n404\n along or adjacent the sensor information and the software controls displayed on the display screens \n402\n, \n404\n.', 'The view shown in the PIP video window \n422\n may be switched between different video cameras \n198\n.', 'For example, the PIP video window \n422\n of the display screen \n402\n may show a real-time view of the BOP stack \n130\n and the PIP video window \n422\n of the display screen \n404\n may show a real-time view of the choke manifold \n162\n.', 'Each display screen, including the display screens \n402\n, \n404\n, may also comprise an event description window or area \n424\n listing and/or describing one or more operational events taking place at the well construction system \n100\n.', 'The event description area \n424\n may also list and/or describe one or more counteractive measures (e.g., corrective actions, operational sequences) related to the event that may be performed or otherwise implemented in response to the event.', 'Depending on the event and/or mode (e.g., advice, interlock, automated) in which the coordinated control device \n204\n is operating, the processing device \n192\n may just describe the corrective action within the event description area \n424\n, and the wellsite operator \n195\n may implement such corrective action.', 'However, the processing device \n192\n may automatically implement the corrective action, or cause the corrective action to be automatically implemented, such as by transmitting predetermined control data \n261\n-\n267\n to the controller \n241\n-\n247\n of the corresponding subsystem \n211\n-\n217\n.', 'The information displayed in the area \n424\n may just display events and/or corrective actions related to the display screen and the subsystem \n211\n-\n217\n being viewed and, thus, change when switching between the display screens of the integrated display.', 'However, the information displayed in the area \n424\n may not change when switching between the display screens, and may list events and/or corrective actions related to each subsystem \n211\n-\n217\n, such as in chronological order or in the order of importance.', 'As described above, the coordinated control device \n204\n or another portion of the processing device \n192\n may automatically change the display screen to show the subsystem \n211\n-\n217\n experiencing the event and the corresponding description and/or corrective action related to the event.', 'Each display screen, including the display screens \n402\n, \n404\n, may be adjusted or otherwise configured by the wellsite operator \n195\n to display one or more of the various information windows or areas in a preferred or otherwise intended position on each display screen.', 'For example, the selector/indicator area \n406\n may be displayed at the bottom of the display screens \n402\n, \n404\n, the event description area \n424\n may be displayed at the top of the display screens \n402\n, \n404\n, and the driller information area \n412\n may be displayed on the left side of the display screens \n402\n, \n404\n.', 'Furthermore, the location and/or size (i.e., dimensions) of the PIP video windows \n422\n displayed on each display screen, including the display screens \n402\n, \n404\n, may also be adjusted or otherwise selected.', 'The placement of the various information windows or areas and the PIP video windows \n422\n on the display screens may be moved or selected, for example, via one or more of the physical controls physical controls \n314\n, \n316\n, \n318\n, \n320\n, such as by entering an intended location of the information areas and PIP video windows \n422\n or by dragging the information areas and PIP video windows \n422\n to an intended location on the display screens.', 'One or more portions of the operator workstation \n300\n, such as the input and output devices, may also be utilized by the wellsite operator \n195\n to set, configure, or otherwise control operation of the CCTV system \n215\n.', 'For example, one or more of the input devices of the operator workstation \n300\n may be utilized to enter into the processing device \n192\n various video display settings to cause the CCTV system \n215\n to operate based on such video display settings.', 'The input devices may be utilized to configure the number of video signals displayed on each of the video output devices \n326\n, and to configure the size and position of the PIP video windows \n344\n, \n422\n.', 'The input devices of the operator workstation \n300\n may be further utilized to associate a video camera \n198\n with a video output device \n326\n and/or PIP video window \n344\n, \n422\n to select what portions of the well construction system \n100\n are shown on which video output device \n326\n and/or PIP video window \n344\n, \n422\n, and when such portions of the well construction system \n100\n are shown during the well construction operation.', 'Thus, based on such associations, the processing device \n192\n may be operable to cause the CCTV system \n215\n to automatically display predetermined objects and/or areas of the well construction system \n100\n during corresponding successive stages of the well construction operation.', 'The displayed objects and/or areas may be those that the wellsite operator \n195\n may utilize to confirm predetermined parameters, configurations, statuses, and the like, before the automatic sequence of the well construction operation continues.', 'Such aspects may reduce and/or eliminate manual operator input, which may save time during automatic sequences.', 'The video display settings that may be entered into the processing device \n192\n to configure the CCTV system \n215\n may thus comprise associations between each successive operational stage of a well construction operation during which the well construction system \n100\n forms the wellbore \n102\n, and the one or more of the video cameras \n198\n capturing one or more portions of the well construction system \n100\n performing such operational stage of the well construction operation.', 'After such associations are entered into the processing device \n192\n, the processing device \n192\n may automatically display on one or more of the video output devices \n326\n one or more of the video signals from the one or more of the video cameras \n198\n associated with each successive operational stage of the well construction operation, such as to automatically show one or more portions of the well construction system \n100\n performing each successive operational stage of the well construction operation.', 'The video display settings that may be entered into the processing device \n192\n to configure the CCTV system \n215\n may further comprise associations between each operational event and one of the video cameras \n198\n capturing a portion of the well construction system \n100\n experiencing that operational event.', 'After such associations are entered into the processing device, and upon detecting one of the operational events, the processing device \n192\n may automatically display on one or more of the video output devices \n326\n the video signal from the video camera \n198\n associated with the detected operational event, such as to automatically show the well construction system \n100\n portion experiencing the detected operational event.', 'The video display settings may be entered into the processing device \n192\n via one or more CCTV configuration display screens displayed on one or more of the video output devices \n322\n, \n324\n, \n326\n.', 'Each CCTV configuration screen may display information related to status of various portions of the CCTV system \n215\n and the software controls \n328\n, \n330\n, \n342\n, which may be operated to enter the video display settings into the processing device \n192\n to configure the CCTV system \n215\n.', 'In an example implementation, the CCTV configuration display screens may be displayed on one or both of the video output devices \n322\n, \n324\n (i.e., touchscreens) permitting the wellsite operator \n195\n to enter the video display settings from the operator chair \n304\n via finger contact with the corresponding software controls \n328\n, \n330\n.', 'FIGS.', '7-11\n are example implementations of CCTV configuration display screens \n500\n, \n502\n, \n504\n, \n506\n, respectively, generated by the processing device \n192\n and displayed on one or more of the video output devices \n322\n, \n324\n, \n326\n for configuring or otherwise controlling the CCTV system \n215\n by the wellsite operator \n195\n according to one or more aspects of the present disclosure.', 'The CCTV configuration display screens \n500\n, \n502\n, \n504\n, \n506\n may be displayed on one or both of the video output devices \n322\n, \n324\n (i.e., touchscreens), permitting the wellsite operator \n195\n to enter the video display settings from the operator chair \n304\n via finger contact with the corresponding software controls \n328\n, \n330\n.', 'Each of the CCTV configuration display screens \n500\n, \n502\n, \n504\n, \n506\n displays different sets of software controls \n328\n, \n330\n and, thus, may be utilized to configure different features or aspects of the CCTV system \n215\n.', 'Each of the screens \n500\n, \n502\n, \n504\n, \n506\n may be displayed by selecting a corresponding tab \n510\n, \n512\n, \n514\n, \n516\n displayed on each of the screens \n500\n, \n502\n, \n504\n, \n506\n, although additional and/or different tabs are also within the scope of the present disclosure.', 'For example, a video camera control tab \n510\n may be selected (e.g., operated via finger contact) to display the screen \n500\n, a camera selection tab \n512\n may be selected to display the screen \n502\n, an advanced display configuration tab \n514\n may be selected to display the screen \n504\n, and an automatic video display configuration tab \n516\n may be selected to display the screen \n506\n.', 'The selected tab may be highlighted, differently colored, or otherwise distinguished from the non-selected tabs, such as depicted in \nFIG.', '7\n by the selected tab \n510\n.', 'The configuration screen \n500\n includes video signal source indicator buttons \n520\n, \n522\n, \n524\n, each corresponding to one of the video output devices \n332\n, \n334\n, \n336\n and operable to visually indicate which video camera video signals are displayed on each of the video output devices \n332\n, \n334\n, \n336\n.', 'In the example implementation of the screen \n500\n shown in \nFIG.', '7\n, the indicator button \n520\n indicates that the video output device \n332\n displays the video signal from a video camera \n198\n capturing real-time video of (i.e., pointed toward) the top of the mast portion of the well construction system \n100\n.', "The indicator button \n522\n indicates that the video output device \n334\n displays the video signal from a video camera \n198\n capturing real-time video of the off-driller's side (ODS) top connection (i.e., top drive connection handover for triple stand drill pipe between a tubular delivery arm (TDA) \n167\n and the top drive \n116\n).", 'The displayed video may be used to verify that the elevator \n129\n on the top drive \n116\n is closed and that the fingerboard latches \n169\n are open or closed.', 'The indicator button \n524\n indicates that the video output device \n336\n displays the video signal from a video camera \n198\n capturing real-time video of the lower connection (i.e., top drive connection with a single drill pipe).', 'The displayed video may provide the wellsite operator \n195\n with a visual feedback when making up single connections.', 'As described above, the video signals shown on the video output devices \n334\n, \n336\n may be shown within one or more corresponding PIP video windows \n334\n, \n422\n.', 'The indicator buttons \n520\n, \n522\n, \n524\n for actively displayed ones of the selected video camera video signals may be highlighted, differently colored, or otherwise distinguished from the non-displayed ones of the selected video camera video signals.', 'For example, in \nFIG.', '7\n, the video signal from the video camera \n198\n capturing real-time video of the top of the mast is currently being displayed on the video output device \n332\n, and the video signals from the video cameras \n198\n capturing real-time video of the ODS top connection and the lower connection are not currently being displayed on the video output devices \n334\n, \n336\n.', 'The display/non-display status may be toggled by operating (e.g., touching, clicking on, etc.)', 'the corresponding indicator buttons \n520\n, \n522\n, \n524\n.', 'Highlighting of the indicator buttons \n520\n, \n522\n, \n524\n may also or instead inform the wellsite operator \n195\n what video camera \n198\n is active, whereby operating one or more of the other buttons on the display screen \n500\n will then apply to the active video camera \n198\n.', 'For example, when the indicator button \n520\n is highlighted, the video camera \n198\n associated with the indicator button \n520\n is active on the video output device \n332\n and the other buttons on the display screen \n500\n will apply to such video camera \n198\n.', 'If the wellsite operator \n195\n clicks on or otherwise operates the indicator button \n522\n, the video camera \n198\n associated with the indicator button \n522\n will become active and the other buttons on the display screen \n500\n will apply to such video camera \n198\n.', 'The CCTV system \n215\n may be configured to display on the video output device \n332\n either a single video signal in full screen, as shown in the display \n332\n depicted in \nFIG.', '4\n, or multiple video signals from multiple corresponding video cameras \n198\n, simultaneously.', 'For example, the CCTV system \n215\n may be configured to display two video signals from two corresponding video cameras \n198\n (i.e., a bi-view video signal feed) with each video signal filling a corresponding half of the display screen of the video output device \n332\n.', 'The CCTV system \n215\n may instead be configured to display four video signals from four corresponding video cameras \n198\n (i.e., a quad-view video signal feed) with each video signal filling a corresponding quarter of the display screen of the video output device \n332\n.', 'For example, the CCTV configuration screen \n500\n shown in \nFIG.', '8\n depicts a quad-view video signal feed, such that the indicator button \n520\n is divided in four sections each indicating the video camera \n198\n providing the video feed displayed in the corresponding quarter.', 'The indicator button \n520\n shows that the video output device \n332\n is configured to display four video signals from four corresponding video cameras \n198\n capturing real-time video of the top of the mast, the stickup, the crown, and the tool joint assist.', 'The CCTV configuration screen \n500\n may also be utilized to set position or direction (e.g., pan, tilt) of each video camera \n198\n of the CCTV system.', 'For example, the screen \n500\n may include a video camera select button \n526\n for selecting the video cameras \n198\n to be repositioned.', 'When the button \n526\n is operated, a list or a selection menu (not shown) may drop down or otherwise appear, permitting the wellsite operator \n195\n to select the video camera \n198\n to be configured.', 'However, instead of the list or selection menu appearing, when the button \n526\n is operated, another screen may appear (e.g., screen \n502\n described below), permitting the wellsite operator \n195\n to select the video camera \n198\n to be configured.', 'After the wellsite operator \n195\n selects a video camera \n198\n, the video camera \n198\n may be panned left via button \n530\n, panned right via button \n532\n, tilted up via button \n534\n, tilted down via button \n536\n, zoomed in via button \n538\n, and zoomed out via button \n540\n.', 'Additional buttons \n542\n, \n544\n may be operated to wipe and wash, respectively, the selected video camera \n198\n.', 'Several positions for each video camera \n198\n may be stored or recalled by touching, clicking, or otherwise selecting a corresponding one of camera preset position buttons \n546\n.', 'For example, when the position of a selected video camera \n198\n is configured, one of the buttons \n546\n may be operated to save the current video camera settings.', 'The same video camera \n198\n may be repositioned and the configuration saved by pressing another one of the buttons \n546\n.', 'Each preset position may be recalled by pressing one of the buttons \n546\n associated with the preset position.', 'The wellsite operator \n195\n may also control the CCTV video cameras \n198\n using one or both of the joysticks \n310\n, \n312\n.', 'One or more of the CCTV configuration display screens \n500\n, \n502\n, \n504\n, \n506\n may also be utilized by the wellsite operator \n195\n to manually select which of the video camera video signals are to be displayed on one or more of the video output devices \n326\n.', 'For example, the wellsite operator \n195\n may select the tab \n512\n to switch to the screen \n502\n, shown in \nFIG.', '9\n.', 'The screen \n502\n displays video camera selection buttons \n550\n that may be operated to select one or more of the video cameras \n198\n whose video signals are to be displayed.', 'Each button \n550\n may be labeled with the location of the corresponding video camera \n198\n or with the name of the wellsite equipment or portion of the well construction system \n100\n captured by the corresponding video camera \n198\n.', 'The buttons \n550\n may also or instead be labeled with other identifiers, such as equipment identification numbers.', 'After being selected, one or more of the video output devices \n326\n may display the video signals from the one or more of the selected video cameras \n198\n.', 'Manual video camera selection may override the programmed associations described herein to display the video signals from the video cameras \n198\n manually selected.', 'Instead of the screen \n502\n containing the buttons \n550\n, the screen \n502\n may contain a list, a selection menu, or other means for manually selecting the video camera video signals to be displayed.', 'One or more of the CCTV configuration display screens \n500\n, \n502\n, \n504\n, \n506\n may also be utilized by the wellsite operator \n195\n to select how many of the video camera video signals are to be displayed on each of the video output devices \n326\n.', 'For example, the wellsite operator \n195\n may select the tab \n514\n to switch to the screen \n504\n, shown in \nFIG.', '10\n.', 'The screen \n504\n displays selection buttons \n552\n, \n554\n, \n556\n that may be operated to select the number of video camera video signals to be displayed on each of the video output devices \n326\n.', 'The button \n552\n may be operated to select the number of video camera video signals to be displayed on the video output device \n332\n.', 'The button \n554\n may be operated to select the number of video camera video signals to be displayed within corresponding PIP video windows \n344\n, \n422\n on the video output device \n334\n.', 'The button \n556\n may be operated to select the number of video camera video signals to be displayed within corresponding PIP video windows \n344\n, \n422\n on the video output device \n336\n.', 'The selected ones of the buttons \n552\n, \n554\n, \n556\n may be highlighted, differently colored, or otherwise distinguished from the non-selected ones of the buttons \n552\n, \n554\n, \n556\n.', 'The screen \n504\n shows that the video output device \n332\n is set to display one video camera video signal, resulting in one video camera video signal displayed on the video output device \n332\n, as shown in \nFIG.', '4\n.', 'The screen \n504\n further shows that the video output device \n334\n is set to display two video camera video signals, resulting in two video camera video signals displayed within corresponding PIP video windows \n344\n, \n422\n on the video output device \n334\n, as shown in \nFIG.', '4\n.', 'The screen \n504\n also shows that the video output device \n336\n is set to display one video camera video signal, resulting in one video camera video signal displayed within a corresponding PIP video window \n344\n, \n422\n on the video output device \n336\n, as shown in \nFIG.', '4\n.', 'The screen \n504\n may also include manual focus adjustment control buttons \n558\n, \n560\n operable to adjust optical focus of each selected video camera \n198\n and manual iris (i.e., aperture) adjustment control buttons \n562\n, \n564\n operable to adjust iris size of each selected video camera \n198\n to match changing light conditions at the wellsite.', 'The screen \n504\n may also include a video camera lock button \n566\n operable to lock video camera settings and/or controls, such as to prevent other wellsite operators \n195\n from configuring or otherwise controlling the locked video cameras \n198\n.', 'One or more of the CCTV configuration display screens \n500\n, \n502\n, \n504\n, \n506\n may also be utilized by the wellsite operator \n195\n to enter the above-described associations into the processing device \n192\n.', 'These may cause the CCTV system \n215\n to automatically display predetermined wellsite equipment and/or portions of the well construction system \n100\n during corresponding stages of the well construction operation and/or operational events detected during the well construction operation.', 'To enter such associations, the wellsite operator \n195\n may select the tab \n516\n to switch to the CCTV configuration screen \n506\n, shown in \nFIG.', '11\n.', 'The screen \n506\n displays software controls \n328\n, \n330\n (e.g., buttons) that may be operated to select and, thus, associate the video cameras \n198\n, the video output devices \n326\n, and the various operational stages and/or events taking place during the well constriction operation.', 'A video camera selection button \n570\n may be operated by the wellsite operator \n195\n to select one of the video cameras \n198\n from which the video signal is to be displayed on one of the video output devices \n326\n.', 'When the button \n570\n is operated, a list or a selection menu (not shown) containing names or other identifiers of the video cameras \n198\n may drop down or otherwise appear, permitting the wellsite operator \n195\n to select a video camera \n198\n.', 'Thereafter, a drill stage selection button \n572\n may be operated by the wellsite operator \n195\n to select the operational stage of the well construction operation during which the video signal from the selected one of the video cameras \n198\n is to be displayed on one of the video output devices \n326\n.', 'When the button \n572\n is operated, a list or a selection menu (not shown) containing names or other identifiers of the operational stages may drop down or otherwise appear, permitting the wellsite operator \n195\n to select and, thus, associate the operational stage with the previously selected video camera \n198\n.', 'Instead of or in addition to selecting the operational stage, a drill event selection button \n574\n may be operated by the wellsite operator \n195\n to select the operational event during which the video signal from the selected one of the video cameras \n198\n is to be displayed on one of the video output devices \n326\n.', 'When the button \n574\n is operated, a list or a selection menu (not shown) containing names or other identifiers of the operational events may drop down or otherwise appear, permitting the wellsite operator \n195\n to select and, thus, associate the operational event with the previously selected video camera \n198\n.', 'A video position selection button \n576\n may also be operated by the wellsite operator \n195\n to select which of the video output devices \n326\n will display the selected video signal and the position (i.e., location) on the selected video output device \n326\n that the selected video signal will be displayed.', 'When the button \n576\n is operated, a list or a selection menu \n578\n containing names or other identifiers of the video output devices \n326\n and available positions (e.g., quadrant of the video output device \n332\n, PIP windows \n344\n, \n422\n of the video output devices \n334\n, \n336\n, etc.)', 'for the video signal from the selected video camera \n198\n to be displayed may drop down or otherwise appear, permitting the wellsite operator \n195\n to select and, thus, associate the video signal with one of the video output devices \n326\n and the display position on such video output device \n326\n.', 'After the associations between the video cameras \n198\n, the video output devices \n326\n, and the operational stages and/or events are selected, the associations may be saved to the processing device \n192\n by operating a save button \n580\n displayed on the screen \n506\n.', 'In addition to displaying the CCTV configuration display screens \n500\n, \n502\n, \n504\n, \n506\n, the processing device \n192\n may be further operable to provide other software tools operable to display configuration display screens on one or more of the video output devices \n322\n, \n324\n, \n326\n, such as for configuring other systems or portions of the well construction system \n100\n.', 'For example, the touchscreens \n322\n, \n324\n may display a tool selection bar \n582\n displaying icons, buttons, or other software controls permitting the wellsite operator \n195\n to select and use other software tools from the operator chair \n304\n via finger contact with the touchscreens \n322\n, \n324\n.', 'The tool selection bar \n582\n may be permanently displayed on one or both of the touchscreens \n322\n, \n324\n, such as may permit the wellsite operator \n195\n to quickly switch between different software tools.', 'The software tools may each have multiple, independently selectable configuration screens (i.e., pages), each corresponding to an activity, operation, and/or types/categories thereof.', 'As shown on the example configurations screens \n500\n, \n502\n, \n504\n, \n506\n depicted in \nFIGS.', '7-11\n, the tool selection bar \n582\n may include a calculator tool icon \n584\n for displaying a calculator, a keyboard tool icon \n586\n for displaying a keyboard, and a display configuration tool icon \n588\n for displaying a software control display preference screen.', 'The tool selection bar \n582\n may further include a cabin windows control tool icon \n590\n for displaying a cabin window control screen, a cabin climate control tool icon \n592\n for displaying a cabin climate control screen, a control cabin lighting control tool icon \n594\n for displaying a cabin lighting control screen, and a PA/phone tool icon \n598\n for displaying an internet-based phone control screen.', 'The tool selection bar \n582\n may also include a CCTV configuration tool icon \n596\n operable to display the CCTV configuration screens \n500\n, \n502\n, \n504\n, \n506\n described above.', 'As shown in \nFIG.', '11\n, the selected icon may be highlighted, differently colored, or otherwise distinguished from the non-selected icons, such as to inform the wellsite operator \n195\n which software tool is currently being displayed.', 'Each configuration screen generated on the touchscreens \n322\n, \n324\n may also include a power button \n599\n operable to turn off the corresponding touchscreen \n322\n, \n324\n when selected.', 'The software tools and corresponding icons described above are merely examples, and additional and/or different software tools and corresponding icons are also within the scope of the present disclosure.', 'FIG.', '12\n is a schematic view of at least a portion of an example implementation of a processing device \n600\n according to one or more aspects of the present disclosure.', 'Implementations of the processing device \n600\n may form at least a portion of one or more electronic devices utilized at the well construction system \n100\n.', 'For example, an implementation of the processing device \n600\n may be or form at least a portion of the processing devices \n188\n, \n192\n.', 'Implementations of the processing device \n600\n may form at least a portion of the control system \n200\n, including the wellsite computing resource environment \n205\n, the coordinated control device \n204\n, the supervisory control system \n207\n, the local controllers \n241\n-\n247\n, the onsite user devices \n219\n, and the offsite user devices \n220\n.', 'The wellsite computing resource environment \n205\n, the coordinated control device \n204\n, the supervisory control system \n207\n, one or more of the local controllers \n241\n-\n247\n, one or more of the onsite user devices \n219\n, and/or one or more of the offsite user devices \n220\n may also be or comprise an implementation of the processing device \n600\n.', 'When implemented as part of the wellsite computing resource environment \n205\n, the processing device \n600\n may be in communication with various sensors, actuators, controllers, and other devices of the subsystems \n211\n-\n217\n of the well construction system \n100\n.', 'The processing device \n600\n may be operable to receive coded instructions \n632\n from the wellsite operators \n195\n and the sensor data \n251\n-\n257\n generated by the sensors \n221\n-\n227\n, process the coded instructions \n632\n and the sensor data \n251\n-\n257\n, and communicate the control data \n261\n-\n267\n to the local controllers \n241\n-\n247\n and/or the actuators \n231\n-\n237\n to execute the coded instructions \n632\n to implement at least a portion of one or more example methods and/or operations described herein, and/or to implement at least a portion of one or more of the example systems described herein.', 'The processing device \n600\n may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, internet appliances, and/or other types of computing devices.', 'The processing device \n600\n may comprise a processor \n612\n, such as a general-purpose programmable processor.', 'The processor \n612\n may comprise a local memory \n614\n, and may execute coded instructions \n632\n present in the local memory \n614\n and/or another memory device.', 'The processor \n612\n may execute, among other things, the machine-readable coded instructions \n632\n and/or other instructions and/or programs to implement the example methods and/or operations described herein.', 'The programs stored in the local memory \n614\n may include program instructions or computer program code that, when executed by the processor \n612\n of the processing device \n600\n, may cause the subsystems \n211\n-\n217\n of the well construction system \n100\n to perform the example methods and/or operations described herein.', 'The processor \n612\n may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples.', 'Other processors from other families may also be utilized.', 'The processor \n612\n may be in communication with a main memory \n617\n, such as may include a volatile memory \n618\n and a non-volatile memory \n620\n, perhaps via a bus \n622\n and/or other communication means.', 'The volatile memory \n618\n may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices.', 'The non-volatile memory \n620\n may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n618\n and/or non-volatile memory \n620\n.', 'The processing device \n600\n may also comprise an interface circuit \n624\n.', 'The interface circuit \n624\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others.', 'The interface circuit \n624\n may also comprise a graphics driver card.', 'The interface circuit \n624\n may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.).', 'One or more of the local controllers \n241\n-\n247\n, the sensors \n221\n-\n227\n, and the actuators \n231\n-\n237\n may be connected with the processing device \n600\n via the interface circuit \n624\n, such as may facilitate communication between the processing device \n600\n and the local controllers \n241\n-\n247\n, the sensors \n221\n-\n227\n, and/or the actuators \n231\n-\n237\n.', 'One or more input devices \n626\n may also be connected to the interface circuit \n624\n.', 'The input devices \n626\n may permit the wellsite operators \n195\n to enter the coded instructions \n632\n, such as control commands, processing routines, operational set-points, and/or video display settings, including associations between the video cameras \n198\n, the video output devices \n326\n, and the various operational stages and/or events taking place during the well constriction operation.', 'The input devices \n626\n may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples.', 'One or more output devices \n628\n may also be connected to the interface circuit \n624\n.', 'The output devices \n628\n may be, comprise, or be implemented by video output devices (e.g., an LCD, an LED display, a CRT display, and/or a touchscreen), printers, and/or speakers, among other examples.', 'The processing device \n600\n may also communicate with one or more mass storage devices \n630\n and/or a removable storage medium \n634\n, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.', 'The coded instructions \n632\n may be stored in the mass storage device \n630\n, the main memory \n617\n, the local memory \n614\n, and/or the removable storage medium \n634\n.', 'Thus, the processing device \n600\n may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor \n612\n.', 'In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor \n612\n.', 'The coded instructions \n632\n may include program instructions or computer program code that, when executed by the processor \n612\n, may cause the various subsystems \n211\n-\n217\n of the well construction system \n100\n to perform intended methods, processes, and/or operations disclosed herein.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising: (A) a closed-circuit television (CCTV) system for use at a well construction system operable to form a well at an oil/gas wellsite, wherein the CCTV system comprises: (1) a plurality of video cameras at different locations within the well construction system, wherein each video camera is operable to generate a corresponding video signal; and (2) a video output device; and (B) a control system communicatively connected with each of the video cameras and the video output device, wherein the control system comprises a processor and a memory operable to store computer programs, wherein the computer programs utilize video display settings, and wherein the control system is operable to: (1) receive the video display settings from a human wellsite operator; (2) receive the video signals from each of the video cameras; and (3) automatically display on the video output device one or more of the received video signals based on the video display settings.', 'The video display settings may comprise associations between: each successive operational stage of a well construction operation during which the well construction system forms the wellbore; and one or more of the video cameras capturing one or more portions of the well construction system performing such operational stage of the well construction operation.', 'In such implementations, among others within the scope of the present disclosure, the control system may be operable (during the well construction operation) to automatically display on the video output device one or more of the video signals from the one or more of the video cameras associated with each successive operational stage of the well construction operation, thereby automatically showing one or more portions of the well construction system performing each successive operational stage of the well construction operation.', 'The control system may be operable to: receive sensor information from a sensor of the well construction system; detect an operational event occurring in the well construction system based on the received sensor information, wherein the video display settings may comprise an association between the operational event and one of the video cameras capturing a portion of the well construction system experiencing that operational event; and, upon detecting the operational event, automatically display on the video output device the video signal from the associated video camera, thereby automatically showing the well construction system portion experiencing the detected operational event.', 'The control system may be operable to: (A) receive sensor information from a plurality of sensors of the well construction system; (B) detect operational events occurring in the well construction system based on the received sensor information, wherein the video display settings may comprise associations between: (1) each operational event; and (2) one of the video cameras capturing a portion of the well construction system experiencing that operational event; and (C) upon detecting one of the operational events, automatically display on the video output device the video signal from the video camera associated with the detected operational event, thereby automatically showing the well construction system portion experiencing the detected operational event.', 'The video display settings may comprise one or more of video camera zoom, video camera pan, and video camera tilt.', 'The control system may be operable to: receive sensor information from a plurality of sensors of the well construction system; and display on the video output device the received sensor information, wherein the one or more of the received video signals may be automatically displayed in a picture-in-picture video window on the video output device based on the received video display settings.', 'The video output device may be a first video output device, the CCTV system may comprise a second video output device adjacent the first video output device, a first one of the video signals may be automatically displayed on the first video output device based on the received video display settings, and the control system may be operable to: receive sensor information from a plurality of sensors of the well construction system; display the received sensor information on the second video output device; and automatically display a second one of the video signals in a picture-in-picture video window on the second video output device based on the received video display settings.', 'The video output device may be a first video output device, and the apparatus may comprise a second video output device communicatively connected with the control system and operable to display a screen comprising a plurality of software controls operable by the human wellsite operator to enter the video display settings to the control system.', 'The second video output device may be a touch screen permitting the human wellsite operator to operate the software controls via finger contact with the touch screen.', 'The apparatus may comprise an operator control workstation having a seat from which the wellsite human operator controls the well construction system, and the operator control workstation may comprise the second video output device disposed in association with the seat, thereby permitting the wellsite human operator to operate the software controls via finger contact from the seat.', 'The software controls may comprise: a video camera selection button operable to select each of the video cameras to be configured for operation; and one or more of a video camera zoom button, a video camera pan button, and a video camera tilt button.', 'The video camera selection button may be one of a plurality of video camera selection buttons each associated with a different one of the video cameras, and each of the video camera selection buttons may be labeled with a location of the associated one of the video cameras or with names of wellsite equipment of the well construction system captured by the associated one of the video cameras.', 'The first video output device may be a first one of a plurality of first video output devices, and one or more of the software controls may be operable to associate one or more of the video cameras with one or more of the first video output devices such that the one or more of the first video output devices display one or more of the video signals from the associated one or more of the video cameras.', 'One of the software controls may be operable to associate each first video output device with one of the video cameras such that each first video output device displays the video signal from the associated video camera.', 'The software controls may comprise a video camera selection button operable to override the received video display settings to select a different one of the video cameras whose video signal is to be displayed on the/each first video output device.', 'The present disclosure also introduces an apparatus comprising a well construction system comprising: (A) a plurality of components collectively operable to construct a well at an oil/gas wellsite via a plurality of operations; (B) a plurality of video cameras each positioned at a different location in the well construction system and operable to generate a corresponding video signal; (C) a video output device; and (D) a control system comprising a processor and a memory storing an executable code, wherein the control system is operable to: (1) receive the video signals from the video cameras; (2) receive video display settings comprising associations between the operations and the video cameras; and (3) during each operation, automatically display on the video output device one or more of the video signals received from the one or more video cameras associated with that operation.', 'During each operation, the automatic display of the one or more of the video signals received from the one or more video cameras associated with that operation may automatically show one or more portions of the well construction system performing that operation, and/or one or more of the components associated with that operation.', 'The control system may be operable to: receive sensor information from a sensor of the well construction system; detect an operational event occurring in the well construction system based on the received sensor information, wherein the video display settings may comprise an association between the operational event and one of the video cameras capturing a portion of the well construction system experiencing that operational event; and, upon detecting the operational event, automatically display on the video output device the video signal from the associated video camera, thereby automatically showing the well construction system portion experiencing the detected operational event.', 'The control system may be operable to: (A) receive sensor information from a plurality of sensors of the well construction system; (B) detect operational events occurring in the well construction system based on the received sensor information, wherein the video display settings may comprise associations between: (1) each operational event; and (2) one of the video cameras capturing a portion of the well construction system experiencing that operational event; and (C) upon detecting one of the operational events, automatically display on the video output device the video signal from the video camera associated with the detected operational event, thereby automatically showing the well construction system portion experiencing the detected operational event.', 'The video display settings may comprise one or more of video camera zoom, video camera pan, and video camera tilt.', 'The control system may be operable to: receive sensor information from a plurality of sensors of the well construction system; and display on the video output device the received sensor information, wherein the one or more of the received video signals is automatically displayed in a picture-in-picture video window on the video output device based on the received video display settings.', 'The video output device may be a first video output device, the well construction system may comprise a second video output device adjacent the first video output device, a first one of the video signals may be automatically displayed on the first video output device based on the received video display settings, and the control system may be operable to: receive sensor information from a plurality of sensors of the well construction system; display the received sensor information on the second video output device; and automatically display a second one of the video signals in a picture-in-picture video window on the second video output device based on the received video display settings.', 'The video output device may be a first video output device, and the apparatus may comprise a second video output device communicatively connected with the control system and operable to display a screen comprising a plurality of software controls operable by a human wellsite operator to enter the video display settings to the control system.', 'The second video output device may be a touch screen permitting the human wellsite operator to operate the software controls via finger contact with the touch screen.', 'The apparatus may comprise an operator control workstation having a seat from which the wellsite human operator controls the well construction system, and the operator control workstation may comprise the second video output device disposed in association with the seat to permit the wellsite human operator to operate the software controls via finger contact from the seat.', 'The software controls may comprise: a video camera selection button operable to select each of the video cameras to be configured for operation; and one or more of a video camera zoom button, a video camera pan button, and a video camera tilt button.', 'The video camera selection button may be one of a plurality of video camera selection buttons each associated with a different one of the video cameras, and each of the video camera selection buttons may be labeled with a location of the associated one of the video cameras or with names of wellsite equipment of the well construction system captured by the associated one of the video cameras.', 'The first video output device may be a first one of a plurality of first video output devices, and one or more of the software controls are operable to associate one or more of the video cameras with one or more of the first video output devices such that the one or more of the first video output devices display one or more of the video signals from the associated one or more of the video cameras.', 'One of the software controls may be operable to associate each first video output device with one of the video cameras such that each first video output device displays the video signal from the associated video camera.', 'The software controls may comprise a video camera selection button operable to override the received video display settings to select a different one of the video cameras whose video signal is to be displayed on the/each first video output device.', 'The present disclosure also introduces a method comprising constructing a well at an oil/gas wellsite by: (A) operating a well construction system to perform a plurality of operations; and (B) operating a control system comprising a processor and a memory storing an executable code, wherein operating the control system comprises: (1) receiving video signals from video cameras each positioned at a different location in the well construction system; and (2) receiving video display settings comprising associations between the operations and the video cameras such that, during each operation, a video output device automatically displays one or more of the video signals received from the one or more video cameras associated with that operation.', 'During each operation, the automatic display of the one or more of the video signals received from the one or more video cameras associated with that operation may automatically show one or more portions of the well construction system performing that operation.', 'Operating the well construction system to perform the operations may comprise operating the control system to operate a plurality of components of the well construction system to perform the operations.', 'During each operation, the automatic display of the one or more of the video signals received from the one or more video cameras associated with that operation may automatically show one or more of the components associated with that operation.', 'The video display settings may comprise associations between operational events and the video cameras, and operating the control system may comprise: receiving sensor information generated by a plurality of sensors of the well construction system; detecting occurrence of one of the operational events based on the sensor information; and upon detecting the operational event, automatically displaying on the video output device one or more video signals from one or more of the video cameras associated with the detected operational event.', 'Automatically displaying the one or more video signals from the one or more video cameras associated with the detected operational event may automatically show one or more portions of the well construction system experiencing the detected operational event.', 'The video display settings may comprise one or more of video camera zoom, video camera pan, and video camera tilt.', 'The video output device may be a first video output device, the apparatus may comprise a second video output device, and operating the control system may comprise: displaying on the second video output device a screen comprising a plurality of software buttons; and operating the software buttons by a human wellsite operator to enter the video display settings into the control system.', 'Operating the software buttons by the human wellsite operator may comprise operating the software buttons to: select one or more of the video cameras to be configured for operation; and adjust one or more of a video camera zoom, video camera pan, and a video camera tilt of the selected one or more of the video cameras.', 'Operating the control system may comprise: receiving sensor information from a plurality of sensors of the well construction system; and displaying the received sensor information on the video output device, wherein the one or more of the received video signals may be automatically displayed in a picture-in-picture video window on the video output device based on the received video display settings.', 'The video output device may be a first video output device, a first one of the video signals may be automatically displayed on the first video output device based on the received video display settings, and operating the control system may comprise: receiving sensor information from a plurality of sensors of the well construction system; displaying the received sensor information on a second video output device; and automatically displaying a second one of the video signals on the second video output device based on the received video display settings in a picture-in-picture video window.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'A method comprising:\nconstructing a well at an oil/gas wellsite by: operating a well construction system to perform a plurality of operations; and operating a control system comprising a processor and a memory storing an executable code, wherein operating the control system comprises: receiving video signals from video cameras each positioned at a different location in the well construction system; receiving video display settings comprising associations between: each successive operational stage of a well construction operation during which the well construction system forms a wellbore of the well; and one or more of the video cameras capturing one or more portions of the well construction system performing such operational stage of the well construction operation; and automatically displaying, during the well construction operation, on a video output device one or more of the video signals from the one or more of the video cameras associated with each successive operational stage of the well construction operation to automatically show one or more portions of the well construction system performing each successive operational stage of the well construction operation.', '2.', 'The method of claim 1, wherein the video display settings comprise one or more of video camera zoom, video camera pan, and video camera tilt.', '3.', 'A method comprising:\nconstructing a well at an oil/gas wellsite by: operating a well construction system to perform a plurality of operations; and operating a control system comprising a processor and a memory storing an executable code, wherein operating the control system comprises: receiving video signals from video cameras each positioned at a different location in the well construction system; receiving video display settings from a human operator at the oil/gas wellsite; receiving sensor information from a sensor of the well construction system; detecting an operational event occurring in the well construction system based on the received sensor information, wherein the video display settings comprise an association between the operational event and one of the video cameras capturing a portion of the well construction system experiencing that operational event; and upon detecting the operational event, automatically displaying on a video output device the video signal from the associated video camera to automatically show the well construction system portion experiencing the detected operational event.', '4.', 'The method of claim 3, wherein the video display settings comprise one or more of video camera zoom, video camera pan, and video camera tilt.', '5.', 'A method comprising:\nconstructing a well at an oil/gas wellsite by: operating a well construction system to perform a plurality of operations; and operating a control system comprising a processor and a memory storing an executable code, wherein operating the control system comprises: receiving video signals from video cameras each positioned at a different location in the well construction system; receiving video display settings from a human operator at the oil/gas wellsite; automatically displaying on a first video output device one or more of the received video signals based on the video display settings; communicatively coupling a second video output device with the control system; displaying on the second video output device a plurality of software controls operable by the human operator at the oil/gas wellsite to enter the video display settings to the control system, wherein the second video output device is a touch screen permitting the human operator at the oil/gas wellsite to operate the software controls via finger contact with the touch screen.', '6.', 'The method of claim 5, wherein the video display settings comprise one or more of video camera zoom, video camera pan, and video camera tilt.', '7.', 'The method of claim 5, wherein the second video output device is included in an operator control workstation having a seat from which the human operator at the oil/gas wellsite controls the well construction system, the second video output device being positioned in relation to the seat to permit the human operator at the oil/gas wellsite to operate the software controls via finger contact from the seat.', '8.', 'The method of claim 5, wherein the software controls comprise:\na video camera selection button operable to select each of the video cameras to be configured for operation; and\none or more of a video camera zoom button, a video camera pan button, and a video camera tilt button.\n\n\n\n\n\n\n9.', 'The method of claim 8, wherein the video camera selection button is further operable to override the received video display settings to select a different one of the video cameras whose video signal is to be displayed on the first video output device.', '10.', 'The method of claim 5, wherein operating the control system further comprises:\nreceiving sensor information from a plurality of sensors of the well construction system;\ndisplaying the received sensor information on the second video output device; and\nautomatically display a second one of the video signals in a picture-in-picture video window on the second video output device based on the received video display settings.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '4 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '5 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG.', '6 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG. 7 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG. 8 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '9 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '10 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG.', '11 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '12 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG. 1 is a schematic view of at least a portion of an example implementation of a well construction system 100 according to one or more aspects of the present disclosure.', 'The well construction system 100 represents an example environment in which one or more aspects described below may be implemented.', 'Although the well construction system 100 is depicted as an onshore implementation, the aspects described below are also applicable to offshore and inshore implementations.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of a control system 200 for the well construction system 100 according to one or more aspects of the present disclosure.', 'The following description refers to FIGS.', '1 and 2 collectively.;', 'FIG. 3 is a schematic view of an example implementation of the control system 200 shown in FIG.', '2 according to one or more aspects of the present disclosure.', 'The following description refers to FIGS.', '1-3 collectively.;', 'FIG. 3 also depicts the above-described subsystems 211-217 of the well construction system 100, such as the RC system 211, the FC system 212, the MPDC system 213, the GM system 214, the CCTV system 215, the CPC system 216, and the WC system 217.', 'An example implementation of the well construction system 100 may include one or more onsite user devices 219, such as may be communicatively connected or otherwise interact with an information technology (IT) system 218 of the wellsite computing resource environment 205.', 'The onsite user devices 219 may be or comprise stationary and/or portable user devices stationed at the well construction system 100.', 'For example, the onsite user devices 219 may include a desktop computer, a laptop computer, a smartphone or other portable smart device, a personal digital assistant (PDA), a tablet/touchscreen computer, a wearable computer, and/or other devices.', 'The onsite user devices 219 may be or comprise the operator workstation 197 shown in FIG.', '1 and described above.', 'The onsite user devices 219 may be operable to communicate with the wellsite computing resource environment 205, such as via the IT system 218, and/or the remote computing resource environment 206, such as via a network 208.', 'The IT system 218 may include communication conduits, software, computers, and other IT equipment facilitating communication between one or more portions of the wellsite computing resource environment 205, and/or between the wellsite computing resource environment 205 and another portion of the well construction system 100, such as the remote computing resource environment 206.; FIG.', '4 is a schematic view of a portion of an example implementation of a wellsite operator control workstation 300 communicatively connected with the processing device 192 (e.g., the wellsite computing resource environment 205) and/or other portions of the well construction system 100 according to one or more aspects of the present disclosure.', 'The operator workstation 300 comprises an operator chair 302 and an HMI system comprising a plurality of input and output devices disposed in association with and/or integrated with the operator chair 302 to permit the wellsite operator 195 to enter commands or other information to the processing device 192 and receive information from the processing device 192 and other portions of the well construction system 100.', 'The operator chair 302 may include a seat 304, a left armrest 306, and a right armrest 308.; FIGS.', '5 and 6 are views of example implementations of display screens 402, 404 generated by the processing device 192 (e.g., the wellsite computing resource environment 205) and displayed on one or more of the video output devices 326 according to one or more aspects of the present disclosure.', 'The example display screen 402 displays various sensor information and software controls related to the control and monitoring of the WC system 217 and other related drilling or equipment information.', 'The example display screen 404 displays various sensor information and software controls related to the control and monitoring of the CPC system 216 and other related drilling or equipment information.', '; FIGS.', '7-11 are example implementations of CCTV configuration display screens 500, 502, 504, 506, respectively, generated by the processing device 192 and displayed on one or more of the video output devices 322, 324, 326 for configuring or otherwise controlling the CCTV system 215 by the wellsite operator 195 according to one or more aspects of the present disclosure.', 'The CCTV configuration display screens 500, 502, 504, 506 may be displayed on one or both of the video output devices 322, 324 (i.e., touchscreens), permitting the wellsite operator 195 to enter the video display settings from the operator chair 304 via finger contact with the corresponding software controls 328, 330.; FIG.', '12 is a schematic view of at least a portion of an example implementation of a processing device 600 according to one or more aspects of the present disclosure.', 'Implementations of the processing device 600 may form at least a portion of one or more electronic devices utilized at the well construction system 100.', 'For example, an implementation of the processing device 600 may be or form at least a portion of the processing devices 188, 192.', 'Implementations of the processing device 600 may form at least a portion of the control system 200, including the wellsite computing resource environment 205, the coordinated control device 204, the supervisory control system 207, the local controllers 241-247, the onsite user devices 219, and the offsite user devices 220.', 'The wellsite computing resource environment 205, the coordinated control device 204, the supervisory control system 207, one or more of the local controllers 241-247, one or more of the onsite user devices 219, and/or one or more of the offsite user devices 220 may also be or comprise an implementation of the processing device 600.'] |
|
USNot Available | INTEGRATED LITHIUM EXTRACTION | Feb 3, 2021 | Ankur D. Jariwala, Gary W. Sams | No Companies Listed | NPL References not found. | US Citations not found. | Foreign Citations not found. | No images available | ['Methods and apparatus for integrated alkali metal extraction are disclosed.', 'Various exchange media are used to separate a chosen alkali metal, usually lithium, from a source stream and render the alkali metal into a product.', 'In some cases, absorption/desorption processes, using solid and/or liquid absorption media, are used to purify a brine stream into a concentrate stream having elevated concentration of the desired alkali metal.', 'Various processes, which may include use of liquid absorbents, electrochemical processing, centrifugation, evaporation, electrical mixing and separation, or combinations thereof, are used to separate the chosen metal from the source, and aqueous streams are recycled among the processes to facilitate the various separations.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application claims the benefit of U.S. Provisional Application No. 62/970,781, filed Feb. 6, 2020, which is incorporated by reference it its entirety.', 'FIELD', 'This patent application describes methods and apparatus for lithium recovery from aqueous sources.', 'Specifically, integrated lithium extraction processes are described herein.', 'BACKGROUND\n \nLithium is a key element in energy storage.', 'Electrical storage devices, such as batteries, supercapacitors, and other devices commonly use lithium to mediate the storage and release of chemical potential energy as electrical current.', 'As demand for renewable, but non-transportable, energy sources such as solar and wind energy grows, demand for technologies to store energy generated using such sources also grows.', 'Global lithium reserves are, according to one estimate, about 82.8 MMT (million metric tons)', 'LCE (lithium carbonate equivalents), with China, Argentina, and Chile accounting for some 80% of known global reserves.', 'Current global demand is estimated at 212 kMT, a rate that current global reserves can supply for about 390 years.', 'While global demand has approximately tripled over the last decade, demand for lithium is expected to increase approximately five-fold over the coming decade, with annual increases exceeding 20%.', 'Extraction capacity is currently approximately in balance with demand, and planned investments are estimated to grow extraction capacity to 735 kMT LCE by 2022.', 'With more money being deployed in lithium extraction, new cost-effective technologies are needed to drive growth in use of renewable energy.', 'The mining industry has numerous techniques for the extraction of lithium from mineral or saline waters.', 'Hard rock mining with acid digestion is common, but labor intensive.', 'Methods currently used for salar lakes involve evaporation ponds with chemical additives to selectively precipitate the lithium.', 'This process requires months to complete yielding a material containing roughly 50-60% lithium.', 'In recent years, companies are investigating improved methods to recover lithium directly from salar lakes that avoid evaporation, are faster with high lithium yield.', 'Many techniques use a solid adsorbent that selectively recovers lithium, followed by a wash step that liberates the lithium for further processing.', 'These techniques require a large quantity of vessels and associated piping to leverage the economy of scale.', 'Other techniques use a liquid absorbent that selectively recovers the lithium followed by a wash step.', 'The adsorbent efficacy can be increased through pre-conditioning of the input salar waters and post-processing on the lithium product.', 'The absorbent is contacted with a lithium-bearing brine in a pulse column.', 'The absorbent and brine counter-flow through the column, and hydraulic pulses are applied to shear the fluids into small domains that intimately contact to extract lithium from the aqueous phase into the absorbent.', 'Lithium is then separated from the absorbent using acid to form an aqueous lithium salt solution or slurry, which can then be processed to yield lithium in a desired form.', 'Pre-conditioning steps generally include the removal of divalent ions, specifically calcium and magnesium, which will be co-absorbed by either a solid or liquid extraction step, generally referred to as “softening.”', 'This softening step can be accomplished using one of two techniques.', 'One softening method involves adding basic materials such as sodium carbonate and sodium hydroxide to the water to crystallize and precipitate calcium carbonate and magnesium hydroxide to “soften” the water.', 'The methods above are generally difficult to scale, are expensive to operate, and are generally not efficient and environmentally benign in use of water.', 'New apparatus and methods of lithium extraction are needed.', 'SUMMARY\n \nEmbodiments described herein provide a method of recovering alkali metals from an aqueous source, comprising removing divalent ions from the aqueous source by exposing the aqueous source to an intercalated resin that absorbs alkali metals; flushing the intercalated resin using a clean water stream to produce an aqueous divalent depleted stream; extracting alkali metals from the aqueous divalent depleted stream to produce a concentrated monovalent stream and a monovalent depleted stream; and routing the monovalent depleted stream to a purification process to produce the clean water stream.', 'Other embodiments described herein provide a method of recovering lithium from an aqueous source, comprising using a solid adsorbent selective for lithium in a first process to form an aqueous divalent depleted stream from the aqueous source; using a liquid absorbent in a second process to form an aqueous lithium rich stream from the aqueous divalent depleted stream; and recovering lithium from the aqueous lithium rich stream in a third process.', 'Other embodiments described herein provide a lithium extraction apparatus, comprising a first absorption/desorption unit comprising a solid absorbent, a first aqueous recycle inlet, and an outlet; a second absorption/desorption unit comprising a liquid absorbent and having an inlet coupled to the outlet of the first absorption/desorption unit, an intermediate product outlet, and a first aqueous recycle outlet fluidly coupled to the first aqueous recycle inlet of the first absorption/desorption unit, and a second aqueous recycle inlet; and a recovery unit with an inlet coupled to the outlet of the second absorption/desorption unit and a second aqueous recycle outlet fluidly coupled to the second aqueous recycle inlet.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1A\n is a process diagram summarizing a lithium recovery process according to one embodiment.\n \nFIG.', '1B\n is a schematic process diagram of a lithium recovery process according to another embodiment.\n \nFIG.', '2A\n is a process diagram of a separation process for a lithium extraction process, according to one embodiment.\n \nFIG.', '2B\n is a process diagram of a separation process according to another embodiment.\n \nFIG.', '2C\n is a process diagram of a first process according to another embodiment.\n \nFIG.', '3A\n is a process diagram of a lithium extraction process according to one embodiment.\n \nFIG.', '3B\n is a process diagram of a lithium extraction process according to another embodiment.\n \nFIG.', '3C\n is a process diagram of a lithium extraction process according to another embodiment.\n \nFIG.', '3D\n is a schematic cross-sectional view of a lithium extraction vessel according to one embodiment.\n \nFIG.', '4\n is a process diagram of a lithium extraction process according to another embodiment.', 'DETAILED DESCRIPTION\n \nFIG.', '1A\n is a process diagram summarizing a lithium recovery process \n100\n according to one embodiment.', 'The process \n100\n generally has three stages or sub-processes, a first process \n102\n that can be a preparation stage, a second process \n103\n that can be an extraction stage, and a third process \n104\n that can be a finishing stage.', 'Each process generally has a feed stream and an effluent stream, and aqueous streams, which might be just water, generally recycle among the processes.', 'In the first process \n102\n, a brine stream \n106\n bearing lithium is subjected to one or more treatments to reduce impurity concentration and, optionally to increase lithium concentration.', 'Divalent ions and non-lithium monovalent ions are separated from lithium to yield a first effluent \n108\n with very low, or even undetectable amounts of non-lithium monovalent and divalent ions.', 'Returnable water \n110\n is rejected in the first process \n102\n and can be returned to the environment, either to the source, for example the salar lake source, mine source, or seawater source, or to a rapid infiltration basin, or other reinjection facility, for subterranean reinsertion.', 'The returnable water \n110\n generally contains the divalent and non-lithium materials from the source brine that were separated from lithium in the first process.', 'Returnable water can also be returned to the source in a way that promotes extraction.', 'For example, where the source is a salar lake, water can be returned at a location in the lake that energizes gradual flow of lithium bearing water toward the feed location for the process \n100\n.', 'Likewise, for subterranean sources, a reinjection location can be selected that has a similar effect of flowing lithium-bearing water toward the process feed location.', 'The first process effluent \n108\n is routed to the second process \n103\n by a conduit fluidly coupled to an outlet of the first process and to an inlet of the second process.', 'In the second process \n103\n, the first process effluent \n108\n is subjected to physical and/or chemical treatment to extract or concentrate lithium to form a lithium concentrate stream \n112\n as effluent from the second process \n103\n.', 'Water, or an aqueous stream, is generally recovered in the second process \n103\n and recycled to the first process \n102\n as an aqueous recycle \n114\n.', 'The recycle \n114\n is generally useable, potentially blended with fresh water or subjected to a purification process, in the absorption/desorption processes of the first process \n102\n to form the first process effluent \n108\n.', 'Some processes that can be used in the second process \n103\n use one or more processing aids \n116\n as input to the second process \n103\n.', 'The processing aids \n116\n generally facilitate the physical and/or chemical treatments of the second process \n103\n.', 'The lithium concentrate stream \n112\n may be an ionic solution of lithium or an aqueous slurry of one or more lithium salts.', 'The third process \n104\n generally recovers the lithium into a transportable or saleable lithium product stream \n120\n, usually a concentrated lithium hydroxide aqueous solution or slurry or a concentrated lithium chloride, carbonate, or sulfate aqueous solution or slurry.', 'Extraction aids and/or water streams may be recycled from the third process \n104\n in one or more recycle streams \n118\n.', 'In some cases the one or more recycle streams \n118\n includes an aqueous recycle stream that is a lithium salt solution to aid in separation of lithium streams in the second process \n103\n.', 'In some cases, one (or more) of the recycle streams \n118\n can be an acid stream, which may contain lithium.', 'Multiple recycle streams \n118\n, for example an acid stream and a salt stream, may be routed from the third process \n104\n to different parts of the second process \n103\n.', 'The lithium extraction process \n100\n efficiently removes lithium from a brine stream and returns the lithium-depleted brine stream to the environment harmlessly.', 'Brine streams can be obtained from salar lakes, mining operations, geothermal sources, surface brines, seawater, petro-lithium brine, and other aqueous lithium sources.', 'Lithium minerals can also be dispersed in water for processing in the lithium extraction process \n100\n.', 'The product lithium stream \n120\n is suitable for crystallization and evaporation processes to recover solid lithium compounds from the concentrated lithium-containing product stream \n120\n.', 'FIG.', '1B\n is a schematic process diagram of a lithium recovery process \n121\n according to another embodiment.', 'The process \n121\n uses a stagewise exchange process supported by circulating aqueous, or water, loops.', 'The first process \n102\n accomplishes an exchange between a source stream \n106\n and a first aqueous loop \n124\n.', 'A first exchange medium \n126\n is used in the first process \n102\n to accomplish the exchange.', 'Here, since the process \n121\n is a lithium recovery process, lithium is exchanged between the source stream \n106\n and the first aqueous loop \n124\n.', 'In one case, the first exchange medium \n126\n selectively absorbs lithium from the source stream \n106\n and lithium is released from the first exchange medium \n126\n by the aqueous loop \n124\n.', 'In this case, first exchange medium \n126\n is sequentially exposed to the source stream \n106\n and the aqueous loop \n124\n, and the first exchange medium \n126\n may contain multiple units to allow continuous flow of the source stream \n106\n and the first aqueous loop \n124\n.', 'The first exchange medium \n126\n generally separates lithium from other materials, such as divalent materials and non-lithium monovalent materials, in the source stream \n106\n.', 'The separated materials exit in a rejected aqueous stream \n128\n.', 'A portion of the first aqueous loop \n124\n carries lithium from the first process \n102\n to the second process \n103\n.', 'A volume of the first aqueous loop \n124\n is selected to provide a target concentration of lithium to the second process \n103\n, which may be higher or lower than a concentration of lithium in the source stream \n106\n.', 'In one category of embodiments, the target concentration of lithium delivered to the second process \n103\n is higher than the concentration of lithium in the source stream \n106\n.', 'The first aqueous loop \n124\n may be passed through a filter process \n130\n before flowing to the second process \n103\n.', 'The filter process \n130\n may further purify the aqueous stream flowing in the first aqueous loop \n124\n from the first process \n102\n to the second process \n103\n, removing solids and/or impurities, for example scavenging any residual non-lithium divalent or monovalent species in the first aqueous loop \n124\n.', 'The second process \n103\n may be a process for providing lithium in an arbitrary form at an arbitrary concentration.', 'Generally, after separation of lithium from the source stream \n106\n, the second process \n103\n prepares lithium for finishing into a salable form in the third process \n104\n.', 'A second exchange medium \n132\n is used to exchange lithium from the first aqueous loop \n124\n to a second aqueous loop \n134\n.', 'As in the process \n102\n, the exchange medium \n132\n selectively absorbs lithium from the first aqueous loop \n124\n, and lithium is released from the second exchange medium \n132\n by contact with the second aqueous loop \n134\n.', 'As in the process \n102\n, the second exchange medium \n132\n is sequentially contacted with the first and second aqueous loops \n124\n and \n134\n.', 'It should be noted that the first and second exchange media \n126\n and \n132\n may each be solid or liquid.', 'The first exchange medium \n126\n need only be selective for lithium, and may be solid or liquid.', 'Likewise, the second exchange medium \n132\n need only be selective for lithium, and may be solid or liquid.', 'Solid lithium-selective exchange media are noted above.', 'Where the exchange medium is a solid, multiple units can be used to allow continuous operation, where one or more units are in absorption mode while one or more other units are in desorption mode.', 'Where the exchange medium is a liquid, the liquid exchange medium can be continuously circulated between loading phases and unloading phases.', 'After releasing lithium, the first aqueous loop \n124\n returns to the first process \n102\n.', 'The first aqueous loop \n124\n may be subjected to a purification process \n135\n, such as a reverse osmosis process, other membrane filtration process, or other filtration process to remove any residual impurities, such as divalent species or non-lithium monovalent species.', 'In this way, the first aqueous loop \n124\n circulates between the first and second processes \n102\n and \n103\n, acting as a carrier for lithium.', 'If necessary, the first aqueous loop \n124\n may be water balanced by adding or removing water as necessary.', 'A tank with level control and water makeup (not shown) can be provided in the first aqueous loop \n124\n for this purpose.', 'The second aqueous loop \n134\n carries lithium from the second process \n103\n to the third process \n104\n where lithium is removed from the second aqueous loop \n134\n and converted to a salable product \n160\n.', 'The third process \n104\n can be an electrolysis process, an evaporation process, an electrochemical process, or any suitable process for converting lithium to a salable form.', 'The second aqueous loop \n134\n allows lithium to be provided to the third process \n104\n at a concentration that allows optimum processing in the third process \n104\n.', 'For example, many processes for converting lithium to a salable form benefit from a feed stream having an arbitrarily high concentration of lithium.', 'Using the second aqueous loop \n134\n allows lithium concentration in the feed to the third process \n104\n to be optimized by selecting a circulation volume of the second aqueous loop \n134\n.', 'As with the first aqueous loop \n124\n, the second aqueous loop \n134\n may be subjected to a filtration process \n140\n before the third process \n104\n, and after releasing lithium in the third process \n104\n, the second aqueous loop \n134\n returns to the second process \n103\n.', 'As with the first aqueous loop \n124\n, the second aqueous loop \n134\n may be subjected to a purification process \n150\n, which as above may be a reverse osmosis process, another membrane process, or another filtration process, to remove any impurities.', 'In a typical implementation of the process \n121\n, the source stream \n106\n may be a brine with 200 ppm lithium, and the first process \n102\n can be operated to provide a lithium concentration in the first aqueous loop \n124\n exiting the first process \n102\n of 1500 ppm by setting a flow volume of the first aqueous loop at about 10-15%, for example 13%, of the flow volume of the source stream \n122\n.', 'The second process \n103\n can be operated to provide a lithium concentration in the second aqueous loop \n124\n exiting the second process \n103\n of 3000 ppm by setting a flow volume of the second aqueous loop at about 50% of the flow volume of the first aqueous loop \n124\n.', 'Operation of the first and second processes \n102\n and \n103\n for exchanging lithium may benefit from recycling a low concentration of lithium in the first and second aqueous loops \n124\n and \n134\n.', 'For example, a concentration of lithium around 100 ppm in each stream may be helpful in releasing lithium from the first and second exchange medium \n126\n and \n132\n, in some cases.', 'Thus, either of the first or the second aqueous loops \n124\n and \n134\n may be operated with a residual amount of lithium being recycled to aid lithium extraction.', 'FIG.', '2A\n is a process diagram of a separation process \n200\n for a lithium extraction process, according to one embodiment.', 'The separation process \n200\n can be used as the first process \n102\n of the lithium extraction process \n100\n of \nFIG.', '1\n.', 'The separation process \n200\n includes an absorption/desorption resin unit \n202\n configured to contact a lithium-bearing brine stream with an absorption resin selective to lithium, examples of which include DOWEX AG® 50W-X12, an ion exchange resin available from Dow Chemical Co. of Midland, Mich., and AMBERSEP™ G26 H resin available from Dupont de Nemours, Inc., of Wilmington,', 'Del. Other aluminum hydroxide based resins can also be used.', 'The separation process \n200\n separates lithium from other non-lithium species, at least in part, to facilitate lithium recovery from a lithium source.', 'The non-lithium species separated from lithium in the separation process \n200\n include divalent species, such as calcium and magnesium, and monovalent non-lithium species, such as sodium.', 'The absorption/desorption resin unit \n202\n comprises a vessel \n204\n, in which one or more resin beds \n206\n is disposed.', 'The resin beds \n206\n may comprise a resin support material, such as polystyrene or polypropylene, and an absorption material, potentially with solid diluent to control flow velocity through the resin bed.', 'Brine is charged to a resin bed \n206\n through feed line \n208\n.', 'The brine stream passes through the resin bed \n206\n and lithium ions from the brine stream adhere to the resin in the resin bed \n206\n.', 'Lithium adsorbs onto the surface of resin fibers or particles in the resin bed \n206\n, so the resin is an adsorption resin.', 'The resin bed \n206\n thus absorbs lithium from the brine, so the resin is also an absorption material.', 'In this case, the feed line \n208\n is divided into branches to feed the two resin beds \n206\n.', 'Control valves \n209\n may be used to control flow of brine to one resin bed \n206\n or the other.', 'Lithium-depleted brine exits the resin beds \n206\n through a return effluent line \n210\n, shown here branched for the two resin beds \n206\n.', 'When the resin bed \n206\n reaches an endpoint, for example a saturation point of lithium ions in the resin bed \n206\n, flow of the brine stream through the resin bed \n206\n is discontinued, and in this case switched to the other resin bed \n206\n.', 'The resin bed \n206\n that has reached its end point is flushed with water to remove the lithium from the resin.', 'Flush water enters the resin bed lithium-free, or with a low concentration of lithium, through a flush water line \n212\n, branched here for the two resin beds \n206\n.', 'Lithium is released from the resin bed into the fresh water, which exits the resin bed through a lithium-bearing effluent line \n214\n.', 'The flush water is typically flowed through the resin bed \n206\n in a direction opposite to a flow direction of the brine stream through the resin bed \n206\n.', 'Concentration of lithium ions in the lithium-bearing effluent can be maximized by minimizing flow of water through the resin bed \n206\n.', 'Time and concentration can be optimized for a given resin bed, but the optimal flow of water generally depends on size and porosity of the resin bed \n206\n, and on loading of the resin bed \n206\n.', 'Lower flow rate results in higher lithium concentration.', 'In general, concentration of lithium ions in an optimized flush water flow will be from about 2 ppm to about 200 ppm.', 'In one example, using a resin bed with a volume of about 400-500 ft\n3\n, a flow of about 15 gpm of fresh water for about 100 minutes removes most lithium from the resin bed, resulting in an effluent lithium concentration of about 1,800 ppm.', 'Prior to entering the resin bed \n206\n for lithium removal, a brine stream may be subjected to a pretreatment in a preparation unit \n216\n.', 'The preparation unit \n216\n may be, or include, a filtration unit to remove any solids that might reduce effectiveness of the resin bed, or beds, at removing lithium.', 'The preparation unit \n216\n may be, or include, a pH adjustment unit that lowers pH of the brine stream \n106\n to passivate silica in the brine stream \n106\n.', 'A pH of 4-7 is found to be helpful in reducing, or eliminating, the effect of silica on absorption/desorption processes.', 'The brine stream \n106\n is treated in the preparation unit \n216\n to yield the brine feed routed to the absorption/desorption unit \n202\n through the brine feed line \n208\n.', 'Sand, and other solids, can be removed in the preparation unit \n216\n using a suitable filtration method, such as microfiltration, ultrafiltration, or another filtration method.', 'Filtration processing aids \n218\n, such as ferric chloride or other processing aids such as pH adjustment aids (for example hydrochloric acid), may be added to the preparation unit \n216\n.', 'Typically, for processing in resin beds, it is helpful to remove all solid particles of size 10 μm and above.', 'Multiple stages of filtration can be used, if desired, so that flow rate can be optimized.', 'For example, a first stage of rough filtration can remove large particles and a second stage of fine filtration can remove smaller particles, and the capacity of both stages can be adjusted to optimize throughput.', 'Lithium-depleted brine from the absorption/desorption resin beds is removed through return effluent line \n210\n, and can be processed for return to the environment.', 'A lithium-depleted effluent line \n211\n carries lithium-depleted effluent from each resin bed \n206\n to the return effluent line \n210\n.', 'Any impurities that might recycle from further downstream in the process can be removed using suitable chemical treatments.', 'Alternately, and/or additionally, the brine can be routed to a rapid infiltration bed for leaching back into the ground.', 'Flush water for flushing the resin beds \n206\n can be obtained from any convenient source.', 'Here, the flush water is reclaimed from other parts of the process using a reverse osmosis unit \n220\n, which returns purified water through the flush water line \n212\n to the absorption/desorption resin unit \n202\n.', 'The reverse osmosis unit \n220\n can be an advanced reverse osmosis unit with sweep.', 'Water can be reclaimed from the return effluent line \n210\n or by recycling water from downstream processes, such as the second and third processes \n103\n and \n104\n (\nFIG.', '1\n), in a recycle water stream \n222\n.', 'Both water sources can be routed to the remote osmosis unit \n220\n according to process conditions.', 'The reverse osmosis unit \n220\n returns a concentrated return brine stream \n224\n to the environment, for example to a rapid infiltration bed.', 'As noted above in connection with \nFIG.', '1B\n, to the extent water flow in return brine stream \n224\n, or other reject streams, is more than water input from the source \n106\n, make-up water can be provided at any convenient location of the process.', 'For example, the flush water \n212\n can be stored in a tank with level control operationally coupled to a make-up water stream.', 'The lithium-bearing water effluent from the resin bed or beds may contain residual monovalent and divalent ion impurities.', 'Removing, or reducing, these impurities can be helpful to some downstream lithium extraction operations.', 'The impurities may include other alkali metals such as sodium and potassium and alkaline earths such as magnesium and calcium.', 'In \nFIG.', '2A\n, a softener \n230\n is used to treat these impurities.', 'The lithium-bearing effluent line \n214\n carries lithium-bearing effluent to the softener \n230\n where softening reagents are added in a reagent stream \n232\n.', 'The softener \n230\n typically uses a vessel and may include mixing.', 'Alternately, the softener \n230\n may be an ion exchange resin unit with resins, such as chloralkali ion exchange resins available from Dow Chemical Co. of Midland, Mich., that are selective to divalent ions.', 'A softener effluent \n234\n is withdrawn from the softener \n230\n and sent to further processing such as lithium extraction.', 'The separation process \n200\n is generally operated to concentrate lithium and reduce the concentration of impurities such as monovalent and divalent ions other than lithium because reducing the volume of water to be handled reduced the size of equipment needed to further process the lithium.', 'Lithium sensors can be used at various places in the process \n200\n to monitor operation, and operating conditions of the absorption/desorption resin unit \n202\n can be adjusted to affect lithium concentration in the effluent.', 'For example, a lithium sensor \n236\n, such as a lithium-selective electrode, can be coupled to the lithium-depleted effluent lines \n211\n of the individual resin beds \n206\n to detect lithium increase in the lithium-depleted effluent as a sign of approaching endpoint of the resin bed \n206\n.', 'Lithium sensors can also be coupled to the lithium bearing effluent line \n214\n and/or the brine feed line \n208\n to provide lithium concentration information for use in process control.', 'The lithium sensor \n236\n may be an online analytical sensor, such as a capillary electrophoresis sensor, to sense multiple ions.', 'Such lithium detectors can also be used prior to approach of the endpoint to optimize brine throughput through the resin bed \n206\n.', 'For example, brine flowrate through a resin bed \n206\n can be increased until a rise in lithium concentration in the lithium-depleted effluent line \n211\n is detected.', 'A tolerance threshold can be applied to define a maximum flowrate through the resin bed \n206\n.', 'FIG.', '2B\n is a process diagram of a separation process \n250\n according to another embodiment.', 'In this embodiment, a second stage of absorption/desorption takes the place of the softener \n230\n.', 'Here, the absorption/desorption resin unit \n202\n is a first absorption/desorption resin unit, and the separation process \n250\n includes a second absorption/desorption resin unit \n252\n.', 'The lithium-bearing effluent line \n214\n is routed to the second absorption/desorption resin unit \n252\n for a second process of lithium concentration and purification similar to that performed in the first absorption/desorption resin unit \n202\n.', 'Here the lithium-bearing stream charged to the second resin unit \n252\n can have any lithium concentration.', 'For example, the lithium-bearing effluent of the first resin unit \n202\n has an elevated lithium concentration compared to the initial brine stream charged to the first resin unit \n202\n through the feed line \n208\n.', 'In one case, the lithium-bearing effluent of the first resin unit \n202\n may be operated at maximum lithium concentration by minimizing flush water to the resin beds \n206\n to a practical minimum.', 'Alternately, the lithium-bearing effluent of the first resin unit \n202\n may be operated at a lithium concentration somewhat reduced from the practical maximum, for example by 20-40%, to provide a process operating window.', 'In general, higher TDS (total dissolved solids) in the brine feed to the resin bed \n206\n enhances adsorption by the resin bed \n206\n, leading to better separation.', 'The second absorption/desorption resin unit \n252\n may use different exchange materials, different resins, or different morphologies than the first absorption/desorption resin unit \n202\n.', 'The second resin unit \n252\n has, in this case, two resin beds \n256\n, each of which contains an exchange material selective to lithium.', 'As noted elsewhere, more than two resin beds \n256\n can be used to optimize bed use for continuous operation.', 'Because the lithium-bearing stream charged to the second resin unit \n252\n may have different composition from the brine fed to the first resin unit \n202\n through the feed line \n208\n, the resin in the beds \n256\n may have a different configuration from the resin in the beds \n206\n and/or a different loading of exchange material.', 'If, for example, the stream fed to the second resin unit \n252\n has higher lithium concentration, lower impurity concentration, and lower flow rate than the stream fed to the first resin unit \n252\n, the resin beds \n256\n may be larger than the resin beds \n206\n to accommodate adsorbing more lithium, or may include more exchange material and/or have higher surface area to adsorb more lithium.', 'The second absorption/desorption resin unit \n252\n is operated in a manner similar to the first absorption/desorption resin unit \n202\n, with lithium-bearing feed from the lithium-bearing effluent line \n214\n routed to one of the resin beds \n256\n of the second resin unit \n252\n.', 'The fluid from the lithium-bearing effluent line \n214\n flows through the resin bed \n256\n depositing lithium in the exchange resin of the resin bed \n256\n.', 'Upon reaching an endpoint, which may be at saturation of the resin bed \n256\n with lithium, flow of the lithium-bearing stream through the resin bed \n256\n is discontinued and flush water is flowed through the resin bed \n256\n to remove the lithium from the resin bed \n256\n.', 'Flow rate of flush water can be selected to increase lithium concentration further, if desired.', 'Flush water for the second absorption/desorption resin unit \n252\n can be obtained from any source.', 'Here, the flush water is obtained from the reverse osmosis unit \n220\n, as for the first absorption/desorption resin unit \n202\n.', 'It should be noted that other forms of purification can be used instead of reverse osmosis, such as other membrane purification processes and/or other filtration processes.', 'The reverse osmosis unit \n220\n is, in this case, sized to provide sufficient flush water for operation of the two resin units \n202\n and \n252\n.', 'Flush water flow can be split between the two units \n202\n and \n252\n using appropriate valving, which is omitted from \nFIG.', '2B\n for simplicity.', 'Lithium-depleted water from the second resin unit \n252\n can also be routed to the reverse osmosis unit \n220\n for water recovery and recycle, and/or mixed with the brine feed \n208\n.', 'In the process \n250\n of \nFIG.', '2B\n, the second absorption/desorption resin unit \n252\n produces a lithium-bearing effluent \n258\n that is typically higher in lithium concentration than the lithium-bearing effluent stream from the first resin unit \n202\n.', 'In one example, the feed stream \n208\n has 500 ppm lithium, the lithium-bearing effluent stream in the lithium-bearing effluent line \n214\n has 1,500 ppm lithium, and the lithium-bearing effluent stream in the second lithium-bearing effluent line \n258\n has 3,000 ppm lithium.', 'In some cases, the concentration of lithium in the second lithium-bearing effluent line \n258\n may be sufficient so that further concentration and extraction is unnecessary.', 'In such cases, the second resin unit \n252\n may function in the role of the second process \n103\n of the general process \n100\n of \nFIG.', '1\n.', 'In such cases, the lithium-bearing effluent line \n258\n may route lithium-bearing water directly to the third process \n104\n, or to other uses as an intermediate or finished product.', 'FIG.', '2C\n is a process diagram of a first process \n280\n according to another embodiment.', 'Here, an exchange section \n282\n is used to initialize a purified lithium-bearing stream \n284\n from the brine feed \n106\n, using single, double, or multi-stage absorption/desorption processing.', 'The lithium-bearing stream \n284\n is optionally routed to a softener \n286\n, where an intermediate lithium-bearing stream \n288\n emerges.', 'Either the lithium-bearing stream \n284\n or the intermediate lithium-bearing stream \n288\n is routed to an evaporator \n290\n to increase lithium concentration.', 'Much of the water in the feed to the evaporator \n290\n can be removed and returned to the exchange section \n282\n as the recycle water stream \n222\n.', 'A lithium concentrate stream \n292\n emerges from the evaporator having lithium concentration up to the solubility limit of the lithium salts from the original brine feed \n106\n.', 'For lithium chloride, the concentration in the lithium concentrate stream \n292\n may be up to 84 wt %.', 'Any suitable evaporator can be used for the evaporator \n290\n, including steam evaporators, furnace evaporators, solar-powered or direct solar evaporators, and the like.', 'In one embodiment, a multi-effect compression evaporator is used in which the lithium-bearing feed stream is exposed to a heat source at elevated pressure to increase temperature, and then the heated stream is reduced in pressure to effect evaporation and separation of vapor from residual liquid, which becomes the lithium concentrate stream \n292\n.', 'FIG.', '3A\n is a process diagram of a lithium extraction process \n3000\n according to one embodiment.', 'The lithium extraction process \n3000\n may be used as the second process \n103\n of the lithium extraction process \n100\n of \nFIG.', '1\n.', 'The lithium extraction process \n3000\n may also, or alternately, be used at the first process \n102\n of the lithium extraction process \n100\n of \nFIG.', '1\n.', 'The lithium extraction process \n3000\n removes lithium from an aqueous source, and produces an environmentally benign aqueous return stream.', 'Here, the aqueous source is a process such as the first process \n102\n of the lithium extraction process \n100\n of \nFIG.', '1\n.', 'The lithium extraction process \n3000\n is a liquid absorption process.', 'A lithium-bearing stream \n3002\n is contacted with a liquid absorbent that is not miscible with water to extract lithium from the water.', 'The lithium-bearing stream \n3002\n may be the high-concentration lithium-bearing streams of the lithium-bearing effluent line \n214\n of \nFIG.', '2A\n, the softener effluent \n234\n, the lithium-bearing stream of the second lithium-bearing effluent line \n258\n, or the lithium concentrate stream \n292\n, among others.', 'Use of high-concentration lithium streams generally allows for reduction in size of equipment.', 'The liquid absorbent most commonly used is CYANEX 936®, available from Solvay S.A. of Brussels, Belgium.', 'The absorption process is performed in a contacting section \n3004\n, where intimate contact of the lithium-bearing stream \n3002\n with the absorbent is performed.', 'A contactor \n3006\n provides the intimate, high surface area contact that is most useful for solvent extraction of lithium from aqueous media.', 'The lithium-bearing stream \n3002\n is provided to a first end \n3010\n of the contactor \n3006\n while a liquid absorbent stream \n3012\n containing the lithium absorbent is provided to a second end \n3014\n of the contactor \n3006\n, thus performing a counter-current liquid-liquid extraction.', 'A loaded absorbent stream \n3016\n is removed at the first end \n3010\n of the contactor \n3006\n while a lithium-depleted aqueous stream \n3018\n is removed at the second end \n3014\n of the contactor \n3006\n.', 'The loaded absorbent stream \n3016\n is mainly the liquid absorbent complexed with lithium ions, and potentially other monovalent and divalent impurities.', 'The contactor \n3006\n is a high shear vessel that shears the absorbent phase into very small domains that intimately contact the aqueous phase to provide high surface area for interfacial transport of lithium from the aqueous phase to the absorbent.', 'Alternately, the high shear vessel can shear the aqueous phase into small domains dispersed in the absorbent phase.', 'In one embodiment, the contactor \n3006\n is a pulse column that comprises a plurality of parallel trays disposed throughout the column at regular intervals.', 'A hydraulic or mechanical impulse source is fluidly coupled to the column interior to provide an impulse to the fluid flowing through the column.', 'Alternately, the trays can be moved abruptly to establish shear.', 'Differences in density of the aqueous and non-aqueous phases result in different effect of the hydraulic pulse on the two phases, giving rise to very high instantaneous shear rates as the pulse propagates through the fluid column.', 'The shear maintains very small domains of the absorbent phase in the aqueous phase.', 'The pulse column is a technology available from Tenova S.p.A. of Gerenzano, Italy, and other providers.', 'Caustic can be injected at one or more locations of the contactor \n3006\n, or into the lithium-bearing stream \n3002\n, to manage pH in the contactor \n3006\n as metal transfers from the aqueous to the organic phase.', 'The caustic species may be selected to have low affinity for the organic adsorbent to avoid adding substantial impurities to the metal absorbed by the organic absorbent.', 'Rate of caustic addition may be adjusted to maintain a desired pH at any selected location of the contactor \n3006\n, at which point a pH sensor may be coupled to the contactor \n3006\n.', 'Lithium is extracted from the loaded absorbent stream \n3016\n in an extraction section \n3022\n.', 'The loaded absorbent stream \n3016\n is contacted with an aqueous decoupling agent in an extractor \n3024\n.', 'The aqueous decoupling agent breaks the lithium-absorbent complex and produces an aqueous lithium salt solution or slurry.', 'The aqueous decoupling agent is typically a strong acid solution such as sulfuric acid.', 'In this case, the extractor \n3024\n is a stripping column in which the loaded absorbent stream \n3016\n is provided to a first end \n3026\n of the column and sulfuric acid is provided as an aqueous decoupling agent \n3028\n to a second end \n3030\n of the column opposite from the first end \n3026\n.', 'The sulfuric acid and loaded absorbent flow in counter-current through the column, and where the aqueous and organic phases contact, sulfuric acid reacts with the lithium-absorbent complex to produce lithium sulfate in the aqueous phase flowing from the second end \n3030\n to the first end \n3026\n as a solution and/or slurry.', 'An aqueous lithium salt stream \n3032\n, which is a stream resulting from decoupling lithium from a lithium containing absorbent stream using an aqueous decoupling agent, is withdrawn from the first end \n3026\n of the extractor \n3024\n.', 'In this case, the aqueous lithium salt stream is a lithium sulfate stream because sulfuric acid is used as decoupling agent.', 'An unloaded absorbent stream \n3034\n is withdrawn at the second end \n3030\n of the extractor \n3024\n.', 'The unloaded absorbent stream \n3034\n can be recycled to the contactor \n3006\n as the absorbent stream \n3012\n after appropriate purification.', 'The extractor \n3024\n, in this case, is a column, but other types of contacting apparatus, such as various types of mixed vessels and electrical settlers such as dual frequency A/C or D/C settlers, can be used also.', 'Separation processes can optionally be used in the contacting stage and the extraction stage to mitigate any carryover or carryunder material which would otherwise result in loss of lithium or loss of absorbent.', 'For example, the lithium-depleted aqueous stream \n3018\n can be routed to a first separator \n3036\n to recover any trace absorbent eluted from the contactor \n3006\n.', 'The separator may be any convenient physical or chemical separator including settlers, which may be electrically, chemically, or buoyantly enhanced (buoyant enhancement can be performed by flowing gas through a settling fluid to enhance separation velocity), rotational separators, strippers, scrubbers, or combinations thereof.', 'The separator \n3036\n can also be the reverse osmosis unit \n220\n of \nFIGS.', '2A and 2B\n or another reverse osmosis unit.', 'The separator \n3036\n yields a recovered absorbent in a recovered absorbent line \n3038\n connected with the liquid absorbent stream \n3012\n.', 'The separator \n3036\n also yields a recovered aqueous stream \n3040\n that can be routed to the reverse osmosis unit \n220\n, or if the separator \n3036\n achieves sufficient purification, the recovered aqueous stream \n3040\n can be returned to the flush water line \n212\n for use in the absorption/desorption resin units \n202\n and \n252\n.', 'The aqueous lithium salt stream \n3032\n can also optionally be routed to a second separator \n3042\n, which may be any of the kinds of separators described above for the first separator \n3036\n.', 'The optional second separator \n3042\n yields a clean lithium salt stream \n3044\n and a recovered absorbent stream, which may be routed through a recovered absorbent line \n3046\n to the liquid absorbent stream \n3012\n and/or the unloaded absorbent stream \n3034\n.', 'A processing aid source \n3048\n may be used with the separator \n3042\n to aid in separation of the aqueous stream from the organic stream, thus reducing the amount impurities in each of the clean lithium salt stream and the recovered absorbent stream.', 'The processing aid source \n3048\n is, or includes, an alkali metal salt in an aqueous stream such as a solution or slurry.', 'The alkali metal is usually lithium, but others such as sodium can be used.', 'When an alkali metal other than the alkali metal being recovered and purified is used in the processing aid source, further separation, such as differential solubility separation, electrochemical separation, and the like, is used to separate the process aid alkali metal from the desired alkali metal.', 'The processing aid source \n3048\n also contains an anion that is typically the same as the anion being used to extract the alkali metal in the extraction section \n3022\n.', 'Where sulfuric acid is used as the decoupling agent \n3028\n, the processing aid source \n3048\n contains sulfate ions.', 'Where hydrochloric acid is used, the processing aid source \n3048\n includes chloride ions.', 'In the case where lithium is being extracted using sulfate ions, the processing aid source \n3048\n is an aqueous lithium sulfate source.', 'The processing aid source \n3048\n may also include decoupling agent, such as sulfuric acid.', 'Total dissolved solids of the processing aid \n3048\n may be 0.25 wt % to 0.75 wt %.', 'The dissolved salts improve separation in the presence of electric fields in the separator \n3042\n.', 'The processing aid source \n3048\n may be obtained from any convenient source, one of which is by recycling an aqueous stream from downstream operations such as the third process \n104\n.', 'In embodiments where sulfuric acid is used to extract lithium from the absorbent as lithium sulfate, and where the lithium sulfate is converted to lithium hydroxide in the third process \n104\n, the third process \n104\n yields a lithium-bearing sulfuric acid stream that can be recycled to the extraction section \n3022\n as, or with, the decoupling agent \n3028\n, or alternately as, or with, the processing aid source \n3048\n.', 'An optional scrubbing section \n3050\n can be used to remove unwanted metals if removal is not performed elsewhere, or is otherwise insufficient.', 'The scrubbing section \n3050\n can be beneficial where uptake of impurities by the absorbent in the contactor \n3006\n might result in significant impurities in recovered lithium for downstream processes.', 'Typically, scrubbing will be performed prior to extraction for part, or all of the loaded absorbent.', 'All, or a portion, of the loaded absorbent stream \n3016\n can thus be routed to a scrubber \n3052\n (appropriate valving can be used to split flow, if desired, between the scrubber \n3052\n and other dispositions described below for the loaded absorbent stream \n3016\n).', 'The scrubber \n3052\n is a contactor/separator unit that contacts loaded absorbent with a decoupling agent to release unwanted impurities from the loaded absorbent.', 'Typically, for simplicity, the same decoupling agent is used for the scrubber \n3052\n and for the extractor \n3024\n.', 'The scrubber \n3052\n is a settler, with a mixer \n3054\n coupled to an inlet of the settler.', 'Decoupling agent \n3028\n is routed to the mixer \n3054\n along with loaded absorbent, where the two streams are intimately mixed.', 'Because the absorbent is selective to a desired metal, such as lithium, impurities are more weakly bound to the absorbent, so less intense decoupling can be used to separate mainly impurities while separating only a small amount of the desired metal.', 'For example, where sodium is to be separated from lithium in the scrubbing section \n3050\n, a 10% molar excess of decoupling agent to sodium can be used.', 'Thus, if sodium loading is 10% of lithium loading in the loaded absorbent, for example, the amount of decoupling agent used for scrubbing can be 10-15% of the amount needed to fully unload metals from the absorbent.', 'Alternately, the decoupling agent can be diluted for use in the scrubbing section \n3050\n.', 'The great majority of sodium will thus be removed, while only a small amount of lithium is removed.', 'The mixer \n3054\n is configured to provide mixing time and intensity sufficient to unload impurities from the loaded absorbent.', 'The separation effect of the mixer \n3054\n can be optimized by adjusting mixing time, shear rate, and decoupling agent concentration or amount.', 'The settler used as the scrubber \n3052\n can be any type of settler.', 'In one case, an electrical settler is used to maximize throughput.', 'Aqueous and organic streams separate into two phases in the settler.', 'The scrubber organic phase \n3058\n, which is loaded absorbent, is returned to the loaded absorbent line \n3016\n, or otherwise routed to the extraction section \n3022\n.', 'The scrubber aqueous phase \n3056\n, which is decoupling agent along with metals, can be recycled to the contacting section \n3004\n, for example to the lithium-bearing feed stream \n3002\n, to recover desired metals such as lithium.', 'FIG.', '3B\n is a process diagram of a lithium extraction process \n3100\n according to another embodiment.', 'Here, a high-concentration lithium-bearing aqueous stream \n3102\n is contacted with a liquid absorbent in a multi-chamber mixer/settler \n3104\n.', 'The liquid absorbent stream \n3012\n is provided to a mixing chamber \n3106\n of the mixer/settler \n3104\n along with the stream \n3102\n.', 'Here, the high-concentration lithium-bearing aqueous stream can be any of the streams identified as feed streams for the process of \nFIG.', '3A\n.', 'Mixing is performed in the mixing chamber \n3106\n by any suitable means, such as powered agitation, pumparound mixing, static and/or dynamic mixers, and the like.', 'High-shear mixing matched to reaction kinetics obtains the best results, but any mixing can be used with sufficient residence time.', 'Residence time in the mixing chamber \n3106\n is selected to allow time for transportation of lithium from the aqueous phase to the absorbent phase, and mixing is performed to reduce diffusion lengths, and therefore times, in the aqueous phase.', 'The mixed fluid flows from the mixing chamber \n3106\n to a settling chamber \n3108\n of the mixer/settler \n3104\n.', 'The two chambers may be separated by an impermeable barrier, a perforated barrier, or a porous barrier, and flow between the chambers may be accomplished merely by transport through the barrier or by flow through a conduit connecting the two chambers or over a weir separating the two chambers.', 'In-line mixing may be disposed in the conduit to provide additional mixing prior to the settling chamber \n3108\n.', 'In the settling chamber, the aqueous phase and the absorbent phase are allowed to separate into two bulk phases.', 'The separation may be enhanced using any suitable method, such as chemical separation aids and/or energy (heat, electricity).', 'Buoyancy can also be used to speed separation by bubbling gas through the settling chamber \n3108\n.', 'Combinations of settling aids can also be used.', 'Loaded absorbent \n3116\n exits the settling chamber \n3108\n through loaded absorbent line, which is coupled to an extractor \n3122\n.', 'Lithium-depleted aqueous stream \n3118\n exits the settling chamber \n3108\n, and may be recycled to the first process \n102\n, as described above.', 'The extractor \n3122\n, in this case, is another mixer/settler with an extractor mixing chamber \n3182\n and an extractor settling chamber \n3184\n, much like the mixer/settler \n3104\n.', 'The loaded absorbent is charged to the extractor mixing chamber \n3182\n, along with aqueous decoupling agent \n3028\n.', 'The fluid is mixed as described above and flowed to the extractor settling chamber \n3184\n, where the fluid is separated by any of the methods described above for the settling chamber \n3108\n.', 'An aqueous lithium stream, which may be a solution or a slurry depending on the quantity and composition of decoupling agent used relative to the amount of lithium carried by the loaded absorbent \n3116\n, exits the extractor settling chamber \n3184\n through extractor effluent line \n3188\n coupled between the extractor effluent and the third process \n104\n.', 'The aqueous lithium stream is processed in the third process \n104\n to yield a lithium product, for example lithium chloride or lithium hydroxide.', 'Unloaded absorbent exits the extractor settling chamber \n3184\n through absorbent recycle line \n3190\n, which is coupled between the extractor \n3122\n and the liquid absorbent stream \n3012\n provided to the mixer/settler \n3104\n.', 'A processing aid source \n3192\n may be used in the extractor \n3122\n to aid in separating the organic and aqueous phases in the extractor settling chamber \n3182\n.', 'The processing aid may be, or may include, an alkali metal salt solution.', 'The alkali metal may be lithium.', 'The anion for the salt solution is usually the same anion being used to separate the lithium from the absorbent in the extractor \n3122\n.', 'Where sulfuric acid is used as the decoupling agent \n3028\n, the processing aid source \n3192\n is typically a lithium sulfate solution or slurry.', 'If hydrochloric acid is used, then a lithium chloride solution or slurry may be used.', 'If another alkali metal is used in the processing aid source \n3192\n, further separation is used between the extractor \n3122\n and the third process \n104\n, or in the finishing stage, to purify the desired alkali metal, in this case lithium.', 'It has been found that the alkali metal processing aid source \n3192\n aids in separating an alkali metal aqueous stream, such as the aqueous lithium stream exiting in the effluent line \n3188\n, from an organic stream, such as the unloaded absorbent exiting in the absorbent recycle line \n3190\n.', 'The processing aid source \n3192\n may be a recycled lithium-containing stream from the third process \n104\n.', 'For example, in one embodiment, the finishing stage converts lithium in a lithium sulfate slurry or solution into lithium hydroxide, yielding a sulfuric acid stream that is recycled in a decoupling agent recycle line \n3194\n.', 'The decoupling agent recycle line \n3194\n is coupled to the extractor mixing chamber \n3182\n to deliver recycled decoupling agent to the extractor \n3122\n.', 'Here, the decoupling agent recycle line \n3194\n is coupled between the third process \n104\n and the processing aid source \n3192\n, but the decoupling agent recycle line \n3194\n could be coupled to the decoupling agent stream \n3028\n, or to the loaded absorbent \n3116\n, or to another location of the extractor mixing chamber \n3182\n.', 'The sulfuric acid stream recycled to the extractor \n3122\n in the decoupling agent recycle line \n3194\n can be configured, by operation of the third process \n104\n, to contain a desired quantity of lithium salt as processing aid.', 'In such cases, the recycled decoupling agent may be the processing aid source \n3192\n.', 'It should be noted, in reference to the process \n3100\n of \nFIG.', '3B\n, that the extractor \n3122\n could be replaced by the extraction section \n3022\n of the \nFIG.', '3A\n process \n3000\n.', 'Likewise, the extraction section \n3022\n of the \nFIG.', '3A\n process \n3000\n could be replaced by the extractor \n3122\n of the \nFIG.', '3B\n process \n3100\n.', 'That is to say, the processes \n3000\n and \n3100\n each have a contacting stage where a lithium-bearing aqueous stream is contacted with a liquid absorbent.', 'The two contacting operations in the processes \n3000\n and \n3100\n are the contacting section \n3004\n and the mixer/settler \n3104\n.', 'The processes \n3000\n and \n3100\n also have extraction stages where a lithium-bearing organic absorbent is contacted with an aqueous decoupling agent to remove lithium from the organic absorbent.', 'The two extraction stages in the processes \n3000\n and \n3100\n are the extraction section \n3022\n and the extractor \n3122\n.', 'Each of the contacting section \n3004\n and the mixer/settler \n3104\n can be paired with either the extraction section \n3022\n or the extractor \n3122\n.', 'Likewise, each of the extraction section \n3022\n and the extractor \n3122\n can be paired with either the contacting section \n3004\n or the mixer/settler \n3104\n.', 'The process \n3100\n may include a scrubber \n3150\n.', 'In this case, the scrubber \n3150\n is another mixer/settler similar to the mixer/settlers \n3104\n and \n3122\n.', 'As in the process \n3000\n, the scrubber \n3150\n contacts all or part of the loaded absorbent \n3116\n with a small amount of the decoupling agent \n3192\n or \n3194\n to release weakly bound impurities from the loaded absorbent.', 'A mixer \n3152\n of the scrubber \n3150\n intimately mixes the loaded absorbent with the small amount of decoupling agent, dispersing the decoupling agent within the loaded absorbent.', 'As noted above, because the concentration of impurities absorbed by the loaded absorbent is low relative to the desired metal, and because the absorbent is selective to the desired metal, a lower amount of decoupling agent is used to release the impurities.', 'The mixture moves to a settler \n3154\n of the scrubber \n3150\n where two bulk phases separate.', 'The scrubber aqueous phase \n3156\n, containing decoupled metals and decoupling agent, is recycled to the lithium-bearing stream \n3102\n.', 'The scrubber organic phase \n3158\n, which is loaded absorbent depleted of impurities, is returned to the loaded absorbent stream \n3116\n or otherwise routed to the extractor \n3122\n.', 'It should also be noted that decoupling agent can be recycled in the process \n3000\n of \nFIG.', '3A\n in a manner similar to that shown in the process \n3100\n of \nFIG.', '3B\n.', 'As described above, the decoupling agent recycle line \n3194\n can be coupled between the third process \n104\n and one or more of the separator \n3042\n, the processing aid source \n3048\n, and the aqueous lithium salt stream \n3032\n.', 'FIG.', '3C\n is a process diagram of a lithium extraction process \n3200\n according to another embodiment.', 'The process \n3200\n of \nFIG.', '3C\n is similar to the process \n3100\n of \nFIG.', '3B\n, except that a different method is used to contact the various materials to perform extraction and recovery.', 'As in the processes \n3000\n and \n3100\n of \nFIGS.', '3A and 3B\n, there are two stages to the process \n3200\n of \nFIG.', '3C\n, a contacting stage \n3204\n and an extraction stage \n3221\n.', 'In each stage, a centrifugal mixer/separator is used to contact an aqueous medium with an organic medium, accomplish material transfer between the two media, and then separate the media.', 'Here, the contacting, transfer, and separation are primarily performed in a single centrifugal mixer/separator.', 'The contacting stage \n3204\n has a contactor \n3206\n that is a liquid centrifuge.', 'The contactor \n3206\n comprises a vessel \n3208\n with a rotatable barrel \n3210\n disposed within the vessel \n3208\n.', 'A rotor \n3212\n is attached to the barrel \n3210\n and extends through a wall \n3213\n of the vessel \n3208\n along a central axis thereof.', 'The rotor \n3212\n is sealed at the wall \n3213\n by conventional means, and is operable to rotate the barrel \n3210\n within the vessel \n3208\n.', 'The vessel \n3208\n is operated as a liquid-full vessel, so the rotating barrel \n3210\n imparts angular momentum to the fluid within the vessel \n3208\n, energizing a density-driven and affinity-driven separation of bulk phases within the vessel \n3208\n.', 'The barrel \n3210\n has a contacting structure \n3214\n attached to a first end plate \n3215\n and a second end plate \n3218\n opposite from the first end plate \n3215\n.', 'The barrel \n3210\n may be supported at the distal end by a bearing \n3219\n attached to an inner end wall of the vessel \n3208\n.', 'The contacting structure \n3214\n has a cylindrical structure with a hollow interior to provide a mixing zone for fluids within the barrel \n3210\n moving radially inward and outward according to their respective densities.', 'As the fluids flow radially, they encounter the contacting structure \n3214\n and are forced into intimate contact by small flow cross-sections and/or shear.', 'The contacting structure \n3214\n generally rotates with the barrel \n3210\n to enhance mixing.', 'The contacting structure \n3214\n may be a shear structure that applies angular momentum to the liquid within the vessel \n3208\n to promote mixing of fluid phases within the shear structure.', 'For example, a plurality of nested cylindrical vanes with openings for radial fluid flow may be provided as a shear structure.', 'Such openings may have uniform or diverse size and shape and may be uniformly or non-uniformly spaced.', 'Alternately, the contacting structure \n3214\n may be a surface area structure, such as a packing, that provides high surface area and very long flow paths in a generally radial direction to promote fluid mixing within the surface area structure.', 'Packing materials that can be used in include various rings, mesh, or other commonly used packing materials.', 'A rotating surface area structure may also provide some shear to the fluids within the contacting structure \n3214\n.', 'A high-concentration lithium-bearing aqueous stream \n3202\n is charged to a heavy phase inlet \n3222\n of the contactor \n3206\n at a location of the vessel \n3208\n that is radially and axially peripheral.', 'A liquid absorbent \n3012\n is charged to a light phase feed \n3224\n of the contactor \n3206\n at a location of the vessel \n3208\n that is radially central and axially peripheral.', 'In this case, the heavy phase inlet \n3222\n and light phase feed \n3224\n are located at the same end of the vessel \n3208\n, but they could be located at opposite ends of the vessel \n3208\n in some cases.', 'The feed locations are selected to promote mixing and residence time of the fluids within the vessel \n3208\n.', 'The fluids charged to the contactor \n3206\n mix within the vessel \n3208\n as the barrel \n3210\n is rotated.', 'Angular momentum of the heavy fluid charged to the heavy phase inlet \n3222\n creates outward radial pressure to cause flow of the heavy fluid outward from the central axis of the vessel \n3208\n toward the radial periphery of the vessel \n3208\n.', 'Flow of the heavy phase outward displaces the light phase inward toward the central axis of the vessel \n3208\n.', 'As the fluids flow through the contacting structure \n3214\n, the fluids mix intimately and may undergo shear, resulting in lithium transfer from the aqueous phase to the organic phase.', 'The two fluids collect and coalesce into two bulk phases within the vessel \n3208\n, the heavier phase along the periphery of the vessel \n3208\n and the lighter phase near the central axis of the vessel \n3208\n.', 'The heavier phase, in this case, is the aqueous phase depleted of lithium ions while the lighter phase is the organic absorbent carrying lithium.', 'A loaded absorbent line \n3226\n is coupled to the vessel \n3208\n at a central radial location near the central axis thereof to withdraw the loaded absorbent from the vessel \n3208\n.', 'A depleted aqueous line \n3228\n is coupled to the vessel \n3208\n at a radial periphery thereof to withdraw the depleted aqueous phase from the vessel \n3208\n.', 'The effluent streams from the contactor \n3206\n may be routed to one or more separators in the event residual impurity is present.', 'Here, each stream is shown routed to one separator.', 'Loaded absorbent is routed to a first separator \n3230\n to remove any residual aqueous material.', 'The first separator \n3230\n may be any suitable separator, such as a gravity separator, a rotational separator, an electrical separator, a thermodynamic separator such as a distillation or flash unit, or a diffusion separator, or a separator combining multiple separation methods.', 'Depleted aqueous material is routed to a second separator \n3232\n to recover any residual organic material therein.', 'The second separator \n3232\n can also be any suitable separator.', 'Separated aqueous material from the first and second separators \n3230\n and \n3232\n is combined into a depleted aqueous stream \n3234\n that is routed to disposal.', 'As noted above, the depleted aqueous stream \n3234\n can be routed to exchange units in the first process \n102\n, optionally by way of the reverse osmosis unit \n220\n.', 'As also noted above, instead of one single separator, each effluent stream from the contactor \n3206\n can be processed in a separation train that may include multiple separators of the same type or different types, with feed and effluent streams arranged to accomplish the desired degree of purification of the loaded absorbent and depleted aqueous streams.', 'Loaded absorbent is recovered and combined into a loaded absorbent line \n3216\n, which is routed to the extraction stage \n3221\n.', 'The extraction stage \n3221\n is similar to the contacting stage \n3204\n.', 'An extractor \n3250\n, which is a second liquid centrifuge, contacts the loaded absorbent with an aqueous decoupling agent to transfer lithium from the absorbent to the aqueous decoupling agent while concurrently energizing an affinity-driven and density-driven separation of the two materials into two bulk phases.', 'In this case, the extractor \n3250\n is identical in important respects with the contactor \n3206\n.', 'The loaded absorbent is charged to the light phase inlet \n3252\n of the extractor, and the decoupling agent, for example sulfuric acid or another acid, is charged to the heavy phase inlet \n3254\n.', 'As before, the heavy phase inlet \n3254\n is near the central axis of the extractor \n3250\n at an axial periphery thereof, while the light phase inlet \n3252\n is axially and radially peripheral.', 'The contacting structure \n3214\n enhances mixing and rotation of the barrel drives radial separation of the fluids into two bulk phases.', 'An unloaded absorbent is withdrawn from an unloaded absorbent line \n3256\n coupled between the vessel \n3208\n and a third separator \n3258\n, while an aqueous lithium salt stream is withdrawn from an aqueous line \n3260\n coupled between the vessel \n3208\n and a fourth separator \n3262\n.', 'Absorbent is withdrawn from the separators \n3258\n and \n3262\n, combined into a recycle absorbent line \n3264\n, and routed to the contacting stage \n3204\n, to the absorbent stream \n3012\n, the heavy phase inlet \n3222\n of the contactor \n3206\n, or to another suitable location on the vessel \n3208\n.', 'Aqueous lithium salt solution or slurry is withdrawn from each separator and combined into a clean lithium salt stream \n3266\n, which can then be routed to further processing or sale, for example to the third process \n104\n of \nFIG.', '1\n.', 'As before, in \nFIG.', '3C\n, the contacting and extraction stages use the same types of contacting and separation equipment, but such equipment could be used in combination with the other types of contacting and separation equipment described above.', 'For example, the centrifugal-type apparatus of the process \n3200\n could be combined with the tower-type apparatus of the process \n3000\n or with the mixer/settler-type apparatus of the process \n3100\n.', 'Thus, a centrifugal-type contactor could be combined with a tower-type extractor or with a mixer/settler type extractor, and a centrifugal-type extractor could be combined with a tower-type or mixer/settler-type contactor.', 'Such choices depend on the nature of the streams being processed and the geography and infrastructure available to support the overall process.', 'FIG.', '3D\n is a schematic cross-sectional view of a lithium extraction vessel \n3300\n, according to one embodiment.', 'The lithium extraction vessel \n3300\n has three chambers, a contacting chamber \n3312\n, a scrubbing chamber \n3314\n, and an extraction chamber \n3316\n.', 'The lithium extraction vessel \n3300\n is operated in continuous-flow mode with a lithium-bearing concentrate stream, a make-up organic absorbent, and a decoupling agent as feed streams and an aqueous lithium salt stream, an organic absorbent purge, and a depleted aqueous stream as effluents.', 'The organic absorbent is recycled within the vessel \n3300\n from the scrubbing chamber \n3314\n and the extraction chamber \n3316\n to the contacting chamber \n3312\n.', 'The three chambers are separated by three partitions, a first partition \n3313\n separating the contacting chamber \n3312\n from the scrubbing chamber \n3314\n and a second partition \n3315\n separating the scrubbing chamber \n3314\n from the extraction chamber \n3316\n.', 'The vessel \n3300\n accomplishes three contact/separation steps between an organic phase and an aqueous phase.', 'The organic phase is lithium absorbent and the aqueous phase is the lithium-carrying medium for each step.', 'In each chamber, the organic phase is introduced in a lower portion of the chamber and the aqueous phase is introduced in an upper portion of the chamber.', 'Due to the density difference of the phases, the organic phase will flow upward and the aqueous phase will flow downward to afford contact and interaction between the phases.', 'In each chamber, the two phases are introduced using distributors to provide surface area for mixing and material transport between the two phases.', 'The chambers of the vessel \n3300\n are operated liquid-full, and each chamber is provided with an electrode assembly to generate an electric field in the chamber to enhance mixing and/or separation between the phases.', 'Each of the contacting chamber \n3312\n, the scrubbing chamber \n3314\n, and the extraction chamber \n3316\n thus has an aqueous distributor \n3320\n at an upper part of the respective chamber and an organic distributor \n3322\n at a lower part of the chamber.', 'Organic and aqueous phases may be transported from one chamber to the other through organic conduits that generally move organic phase from the top portion of one chamber to the organic distributor \n3322\n at the bottom of another chamber and aqueous conduits that generally move aqueous phase from the bottom portion of one chamber to the aqueous distributor \n3320\n at the top of another chamber.', 'Pumps are disposed within the vessel \n3300\n to facilitate flows between chambers.', 'Aqueous and organic streams are recycled within the vessel \n3300\n using conduits disposed within the vessel \n3300\n.', 'Pumps are used to facilitate the recycle flows.', 'A high-concentration lithium-bearing aqueous stream \n3302\n is charged to the aqueous distributor \n3320\n of the contacting chamber \n3312\n.', 'The absorbent stream \n3012\n is charged to the organic distributor \n3322\n of the contacting chamber.', 'In this case, the absorbent stream \n3012\n is a make-up stream.', 'Additional absorbent is recycled within the vessel \n3300\n through an absorbent recycle \n3330\n, which may be routed along any convenient pathway within or outside the vessel \n3300\n.', 'In this case, the absorbent recycle \n3330\n is shown schematically as an arrow.', 'The absorbent recycle \n3330\n generally withdraws unloaded absorbent from an top portion of the extraction chamber \n3316\n and routes the unloaded absorbent to the organic distributor \n3322\n of the contacting chamber \n3312\n.', 'A pump may be used to flow the unloaded absorbent through the conduit \n3330\n.', 'The aqueous and organic streams are contacted within the contacting chamber \n3312\n.', 'Alternately, the absorbent stream \n3012\n may be pre-mixed with the lithium-bearing stream \n3302\n, using for example one or more in-line static or dynamic mixers, and provided to the contacting chamber \n3312\n through either the aqueous distributor \n3320\n or the organic distributor \n3322\n of the contacting chamber \n3312\n.', 'Lithium migrates from the aqueous phase to the organic phase in the contacting chamber \n3312\n.', 'A first electric field unit \n3340\n applies an electric field to the fluid inside the contacting chamber \n3312\n.', 'The first electric field unit \n3340\n comprises a first electrode assembly \n3342\n electrically coupled to a first power unit assembly \n3344\n.', 'The first power unit assembly \n3344\n applies electric power to the one or more electrodes of the first electrode assembly \n3342\n to create an electric field between electrodes of the first electrode assembly \n3342\n and/or between an electrode of the first electrode assembly \n3342\n and a wall of the contacting chamber \n3312\n.', 'The applied electric field influences behavior of the aqueous phase, higher voltage encouraging smaller aqueous droplets and lower voltage encouraging larger aqueous droplets.', 'It should be noted that the first power unit assembly \n3344\n may include multiple power units, with multiple electrodes of the first electrode assembly \n3342\n electrically coupled to the multiple power units of the first power unit assembly \n3344\n to provide different electric field conditions at different locations in the contacting chamber \n3312\n.', 'Thus, for example, mixing can be encouraged in a central area of the contacting chamber \n3312\n and separation can be encouraged in the top and bottom areas of the contacting chamber \n3312\n by applying different electric field conditions using different power circuits.', 'Aqueous material, depleted of lithium ions by contact with the absorbent, collects and coalesces in the lower portion of the contacting chamber \n3312\n while absorbent loaded with lithium that has migrated from the aqueous phase to the organic phase collects and coalesces in the upper portion of the contacting chamber \n3312\n.', 'A lithium-depleted aqueous stream \n3318\n is withdrawn from the contacting chamber \n3312\n from the lower portion of the contacting chamber \n3312\n where the aqueous material coalesces and settles in a bulk aqueous phase.', 'The organic phase in the contacting chamber \n3312\n, which is a loaded absorbent, is routed into the scrubbing chamber \n3314\n through a conduit \n3332\n that collects loaded absorbent at the upper portion of the contacting chamber \n3312\n and deliver the loaded absorbent to the organic distributor \n3322\n at the lower portion of the scrubbing chamber \n3314\n, transiting through the first partition \n3313\n.', 'The conduit \n3332\n is shown schematically as an arrow in \nFIG.', '3D\n.', 'A pump may be used to facilitate flow of loaded absorbent through the conduit \n3332\n.', 'In the scrubbing chamber \n3314\n, the loaded absorbent is contacted with a first decoupling agent stream \n3304\n to perform a low-intensity decoupling of impurity species from the loaded absorbent.', 'The first decoupling agent stream \n3304\n is provided to the scrubbing chamber \n3314\n using the aqueous distributor \n3320\n of the scrubbing chamber \n3314\n.', 'The decoupling agent of the first decoupling agent stream \n3304\n is the same decoupling agent used in the extraction chamber \n3316\n, which is provided to the aqueous distributor \n3320\n of the extraction chamber \n3316\n as a second decoupling agent stream \n3306\n.', 'The decoupling process performed in the scrubbing chamber \n3314\n is a low-intensity decoupling process to decouple species weakly bound to the absorbent.', 'Because the absorbent is selective, the absorbent absorbs the selective species more strongly than other impurity species.', 'A low-intensity decoupling process thus preferentially removes the impurity species from the absorbent.', 'The low-intensity decoupling process is performed by using a small volume of the decoupling agent or by using a dilute decoupling agent.', 'The first decoupling agent stream \n3304\n is thus either smaller in volume than the second decoupling agent stream \n3306\n, or is diluted to have lower strength than the second decoupling agent stream \n3306\n.', 'Mixing and separation is performed in the scrubbing chamber \n3314\n in a manner similar to the contacting chamber \n3312\n.', 'A second electric field unit \n3350\n has a second electrode assembly \n3352\n electrically coupled to a second power unit assembly \n3354\n.', 'The second electrode assembly \n3352\n and the second power unit assembly \n3354\n may be configured the same as the first electrode assembly \n3342\n and the first power unit assembly \n3344\n, respectively, or may be different, depending on the conditions and volumes selected for operating the scrubbing chamber \n3314\n.', 'Mixing and separation are performed in the scrubbing chamber \n3314\n, with a bulk organic phase collecting at an upper portion of the scrubbing chamber \n3314\n and a bulk aqueous phase collecting at a lower portion of the scrubbing chamber \n3314\n.', 'An aqueous impurity stream \n3326\n is withdrawn from the lower portion of the scrubbing chamber \n3314\n.', 'The aqueous impurity stream \n3326\n will be a weak acid stream with impurity species, such as divalent and non-lithium monovalent species, and potentially a low concentration of lithium.', 'All, or a portion, of the aqueous impurity stream \n3326\n can be recycled to the aqueous distributor \n3320\n of the contacting chamber \n3312\n to recover any lithium therein and/or to facilitate mixing and separation in the contacting chamber \n3312\n.', 'The recycled aqueous impurity stream may be delivered directly to the aqueous distributor \n3320\n of the contacting chamber \n3312\n or may be mixed with the high-concentration lithium-bearing aqueous stream \n3302\n before delivery to the contacting chamber \n3312\n.', 'The organic phase of the scrubbing chamber \n3314\n is a clean loaded absorbent.', 'The clean loaded absorbent is withdrawn from the upper portion of the scrubbing chamber \n3314\n into a conduit \n3334\n that transits the second partition \n3315\n and delivers the clean loaded absorbent to the organic distributor \n3322\n of the extraction chamber \n3316\n.', 'The second decoupling agent stream \n3306\n is delivered to the aqueous distributor \n3320\n of the extraction chamber \n3316\n.', 'In the extraction chamber \n3316\n, the organic and aqueous phases mix and contact to unload lithium from the clean loaded absorbent into the aqueous phase to form a clean lithium salt stream \n3350\n, which is withdrawn from a lower portion of the extraction chamber \n3316\n.', 'As for the contacting and scrubbing chambers \n3312\n and \n3314\n, a third electric field unit \n3360\n is provided for the extraction chamber \n3316\n.', 'The third electric field unit \n3360\n has a third electrode assembly \n3362\n disposed with in the extraction chamber \n3316\n and a third power unit assembly \n3364\n electrically coupled to the third electrode assembly \n3362\n to provide an electric field within the extraction chamber \n3316\n.', 'The third electric field unit \n3360\n may also be configured with multiple electrodes and power units to provide tailored electric field conditions within the extraction chamber \n3316\n to promote mixing and settling in different areas of the extraction chamber \n3316\n.', 'An absorbent purge stream \n3356\n may be withdrawn from an upper portion of the extraction chamber \n3316\n.', 'As described above, at least a portion of the unloaded absorbent that collects at the upper portion of the extraction chamber \n3316\n is recycled to the contacting chamber \n3312\n through the absorbent recycle \n3330\n.', 'The vessel \n3300\n illustrates a lithium processing embodiment provided in a single vessel for compact processing.', 'The vessel \n3300\n may include a controller \n3380\n operatively coupled to flow control devices for the various feed, product, and recycle streams, and to the power units to control operation of the vessel \n3300\n.', 'Various sensors, temperature, pressure, composition, and electrical sensors, may be provided at selected locations to monitor the process, and the controller \n3380\n may employ advanced process control measures, such as machine learning or other artificial intelligence approaches, to optimize or target the processes of the vessel \n3300\n.', 'FIG.', '4\n is a process diagram of a lithium extraction process \n400\n according to another embodiment.', 'The lithium extraction process \n400\n includes the separation process \n200\n of \nFIG.', '2A\n and an electrochemical unit \n402\n as a second process \n103\n.', 'No third process \n104\n is used in the process \n400\n since the electrochemical unit \n402\n produces a salable lithium product.', 'The electrochemical unit \n402\n includes a vessel \n404\n with an electrode \n406\n electrically coupled to a power circuit \n408\n.', 'In one embodiment, the electrochemical unit \n402\n operates by intercalating lithium into a lithium-selective electrode, for example a manganese-containing electrode, until an endpoint is reached.', 'The electrode is powered with a voltage selective for lithium uptake.', 'The vessel \n404\n is then flushed and filled with fresh water or a dilute lithium salt solution.', 'Finally the potential is reversed on the electrode \n406\n to release the lithium from the electrode into the solution.', 'The electrochemical unit \n402\n can be operated as a concentrator/purifier by providing a variable volume interior for the vessel \n404\n.', 'The vessel \n404\n has an interior \n410\n that may contain a separator material.', 'The electrode \n406\n may be disposed on a movable plate \n412\n that can be positioned to provide a variable volume interior for the vessel \n404\n.', 'During lithium uptake, the movable plate \n412\n can be positioned at the full volume position to maximize exposure of brine to electrochemical processing in the vessel \n404\n.', 'After the endpoint is reached and the vessel \n404\n is flushed, the movable plate \n412\n can be positioned at a reduced volume position.', 'When the reduced volume interior is filled with dilute brine to perform the release process, the lithium will be released into a smaller volume of water so that resulting solution will be concentrated.', 'The electrochemical unit \n402\n has two or more of the vessels \n404\n to provide continuous operation.', 'As an endpoint is reached in one of the vessels \n404\n, concentrate from the separation process \n200\n can be diverted to another of the vessels \n404\n, while the first vessel \n404\n is unloaded and prepared for lithium extraction.', 'As before with other embodiments described above, monovalent depleted brine from the electrochemical unit \n402\n can be routed to the separation process \n200\n for use as a flush medium, optional through a reverse osmosis or other purification unit.', 'During lithium uptake operation, a monovalent depleted stream \n414\n is withdrawn from the vessel, or vessels, \n410\n and can be routed back to the separation process \n200\n for use as flush water, optionally through a reverse osmosis unit as described above.', 'During lithium release operation, clean water is provided to the vessel, or vessels \n410\n, through clean water line \n416\n, which may be obtained from a reverse osmosis unit as described above.', 'Lithium is unloaded from the electrode \n406\n into the clean water to form a lithium product stream that is withdrawn through lithium product line \n420\n.', 'Note that flow control devices are omitted for simplicity.', 'Each of the vessels \n404\n can be operated in continuous flow mode until an endpoint is reached, or in semi-batch mode.', 'In continuous flow mode, an aqueous lithium-bearing stream such as the lithium-bearing effluent \n214\n of the resin unit \n202\n can be charged to one of the vessels \n404\n continuously while powering the electrode \n406\n.', 'As the lithium-bearing stream flows through the vessel \n404\n, the electrode \n406\n continuously absorbs lithium from the lithium-bearing stream.', 'Absorption rate is influenced by flow rate of fluid through the vessel \n404\n and electrical current flowing through the electrode \n406\n.', 'Endpoint can be detected by monitoring current flow through the electrode \n406\n.', 'A drop in current flow at steady voltage indicates approach of an endpoint where the electrochemical extraction effectiveness of the electrode is being impeded by lithium ion saturation.', 'To operate the vessels \n404\n in semi-batch mode, an aliquot of the lithium-bearing stream is loaded into one vessel \n404\n and the electrode \n406\n is powered at the lithium-selective voltage until current drops, indicating either lithium saturation of the electrode or lithium depletion of the aqueous medium in the vessel \n404\n.', 'At that time, the lithium depleted aqueous medium can be flush and new lithium-bearing material loaded into the vessel \n404\n.', 'An endpoint is reached when an initial current using new lithium-bearing brine is significantly below previous initial currents.', 'At that time, the vessel \n404\n can be flushed and unloaded.', 'In semi-batch mode, two or more vessels \n404\n can provide quasi-continuous operation by alternating loading and unloading operations.', 'For semi-batch operation, four vessels \n404\n provides more continuous operation because one pair of vessels can be operated in lithium uptake while the other pair of vessels is operated in lithium unloading.\n \nProcesses that can be used for the third process \n104\n include electrolysis and crystallization processes.', 'An electrolysis process can be used to convert a lithium salt solution or slurry into lithium hydroxide, yielding an acid stream in the process that can be recycled to the second process \n103\n as a decoupling agent or processing aid for separation.', 'A crystallization process uses evaporation and/or filtering to isolate lithium salt crystals.', 'The liquid eluent can also be recycled to upstream processes, such as the reverse osmosis unit \n220\n (\nFIG.', '2A\n).', 'Presented herein are embodiments of an integrated lithium recovery process that subjects a lithium-containing brine to anionic ion exchange to concentrate and purify the lithium and to an extraction process to bring the lithium to a form that can be sold directly or finished into a saleable product.', 'The processes described herein have the ability to optimize use of water and organic process aids, and to minimize impact on the environment from returned water.', 'Some processes described herein provide lithium recovery in a compact footprint while maximizing use of process water and processing aids.'] | ['1.', 'A method of recovering alkali metals from an aqueous source, comprising:\nremoving divalent ions from the aqueous source by exposing the aqueous source to an intercalated resin that absorbs alkali metals;\nflushing the intercalated resin using a clean water stream to produce an aqueous divalent depleted stream;\nextracting alkali metals from the aqueous divalent depleted stream to produce a concentrated monovalent stream and a monovalent depleted stream; and\nrouting the monovalent depleted stream to a purification process to produce the clean water stream.', '2.', 'The method of claim 1, wherein the extracting the alkali metals from the aqueous divalent depleted stream comprises performing a liquid absorption process on the aqueous divalent depleted stream.', '3.', 'The method of claim 1, further comprising recovering alkali metals from the concentrated monovalent stream.', '4.', 'The method of claim 1, wherein the extracting alkali metals from the aqueous divalent depleted stream comprises using a processing aid comprising an alkali metal.', '5.', 'The method of claim 1, wherein the extracting alkali metals from the aqueous divalent depleted stream comprises contacting the aqueous divalent depleted stream with a liquid absorbent to form a loaded absorbent and the monovalent depleted stream.', '6.', 'The method of claim 5, wherein the extracting the alkali metals from the aqueous divalent depleted stream further comprises performing a liquid desorption process on the loaded absorbent to form the concentrated monovalent stream.', '7.', 'The method of claim 5, wherein contacting the aqueous divalent depleted stream with the liquid absorbent comprises intimately mixing the aqueous divalent depleted stream with the liquid absorbent to form a multi-phase mixture and separating the multi-phase mixture into the loaded absorbent and the monovalent depleted stream using an electrical separator.', '8.', 'The method of claim 7, wherein the intimately mixing the aqueous divalent depleted stream with the liquid absorbent is performed in a mixing zone of the electrical separator.', '9.', 'The method of claim 1, wherein extracting alkali metals from the aqueous divalent depleted stream comprises performing an electrochemical reaction using selective electrochemical conditions to isolate a desired alkali metal and form the monovalent depleted stream, and hydrating the isolated alkali metal to form the concentrated monovalent stream.', '10.', 'A method of recovering lithium from an aqueous source, comprising:\nusing a solid adsorbent selective for lithium in a first process to form an aqueous divalent depleted stream from the aqueous source;\nusing a liquid absorbent in a second process to form an aqueous lithium rich stream from the aqueous divalent depleted stream; and\nrecovering lithium from the aqueous lithium rich stream in a third process.', '11.', 'The method of claim 10, further comprising recycling an aqueous stream from the second process to the first process.', '12.', 'The method of claim 10, further comprising recycling an aqueous stream from the third process to the second process.', '13.', 'The method of claim 12, wherein the second process comprises an electrical separation process, and the recycled aqueous stream is provided to the electrical separation process.', '14.', 'The method of claim 13, wherein the recycled aqueous stream is an acid stream.', '15.', 'The method of claim 14, wherein the acid stream contains lithium.', '16.', 'The method of claim 10, wherein the aqueous source has a first concentration of lithium, the aqueous divalent depleted stream has a second concentration of lithium, and the aqueous lithium rich stream has a third concentration of lithium; and where the third concentration is larger than the second concentration and the second concentration is larger than the first concentration.', '17.', 'The method of claim 16, further comprising recycling a first aqueous stream from the second process to the first process and recycling a second aqueous stream from the third process to the second process.', '18.', 'The method of claim 17, wherein the second process comprises an electrical separation process and the second aqueous stream is provided to the electrical separation process.', '19.', 'A lithium extraction apparatus, comprising:\na first absorption/desorption unit comprising a solid absorbent, a first aqueous recycle inlet, and an outlet;\na second absorption/desorption unit comprising a liquid absorbent and having an inlet coupled to the outlet of the first absorption/desorption unit, an intermediate product outlet, and a first aqueous recycle outlet fluidly coupled to the first aqueous recycle inlet of the first absorption/desorption unit, and a second aqueous recycle inlet; and\na recovery unit with an inlet coupled to the outlet of the second absorption/desorption unit and a second aqueous recycle outlet fluidly coupled to the second aqueous recycle inlet.\n\n\n\n\n\n\n20.', 'The lithium extraction apparatus of claim 19, wherein the second absorption/desorption unit comprises at least one apparatus selected from the group consisting of a pulse column, a mixer/settler, a centrifuge, an electrical contactor, and an electrochemical reactor.'] | ['FIG.', '1A is a process diagram summarizing a lithium recovery process according to one embodiment.;', 'FIG.', '1B is a schematic process diagram of a lithium recovery process according to another embodiment.', '; FIG.', '2A is a process diagram of a separation process for a lithium extraction process, according to one embodiment.;', 'FIG.', '2B is a process diagram of a separation process according to another embodiment.', '; FIG.', '2C is a process diagram of a first process according to another embodiment.', '; FIG.', '3A is a process diagram of a lithium extraction process according to one embodiment.; FIG.', '3B is a process diagram of a lithium extraction process according to another embodiment.', '; FIG.', '3C is a process diagram of a lithium extraction process according to another embodiment.;', 'FIG.', '3D is a schematic cross-sectional view of a lithium extraction vessel according to one embodiment.; FIG.', '4 is a process diagram of a lithium extraction process according to another embodiment.; FIG.', '1A is a process diagram summarizing a lithium recovery process 100 according to one embodiment.', 'The process 100 generally has three stages or sub-processes, a first process 102 that can be a preparation stage, a second process 103 that can be an extraction stage, and a third process 104 that can be a finishing stage.', 'Each process generally has a feed stream and an effluent stream, and aqueous streams, which might be just water, generally recycle among the processes.', ';', 'FIG.', '1B is a schematic process diagram of a lithium recovery process 121 according to another embodiment.', 'The process 121 uses a stagewise exchange process supported by circulating aqueous, or water, loops.', 'The first process 102 accomplishes an exchange between a source stream 106 and a first aqueous loop 124.', 'A first exchange medium 126 is used in the first process 102 to accomplish the exchange.', 'Here, since the process 121 is a lithium recovery process, lithium is exchanged between the source stream 106 and the first aqueous loop 124.', 'In one case, the first exchange medium 126 selectively absorbs lithium from the source stream 106 and lithium is released from the first exchange medium 126 by the aqueous loop 124.', 'In this case, first exchange medium 126 is sequentially exposed to the source stream 106 and the aqueous loop 124, and the first exchange medium 126 may contain multiple units to allow continuous flow of the source stream 106 and the first aqueous loop 124.', 'The first exchange medium 126 generally separates lithium from other materials, such as divalent materials and non-lithium monovalent materials, in the source stream 106.', 'The separated materials exit in a rejected aqueous stream 128.; FIG.', '2A is a process diagram of a separation process 200 for a lithium extraction process, according to one embodiment.', 'The separation process 200 can be used as the first process 102 of the lithium extraction process 100 of FIG.', '1.', 'The separation process 200 includes an absorption/desorption resin unit 202 configured to contact a lithium-bearing brine stream with an absorption resin selective to lithium, examples of which include DOWEX AG® 50W-X12, an ion exchange resin available from Dow Chemical Co. of Midland, Mich., and AMBERSEP™ G26 H resin available from Dupont de Nemours, Inc., of Wilmington,', 'Del. Other aluminum hydroxide based resins can also be used.', 'The separation process 200 separates lithium from other non-lithium species, at least in part, to facilitate lithium recovery from a lithium source.', 'The non-lithium species separated from lithium in the separation process 200 include divalent species, such as calcium and magnesium, and monovalent non-lithium species, such as sodium.;', 'FIG.', '2B is a process diagram of a separation process 250 according to another embodiment.', 'In this embodiment, a second stage of absorption/desorption takes the place of the softener 230.', 'Here, the absorption/desorption resin unit 202 is a first absorption/desorption resin unit, and the separation process 250 includes a second absorption/desorption resin unit 252.', 'The lithium-bearing effluent line 214 is routed to the second absorption/desorption resin unit 252 for a second process of lithium concentration and purification similar to that performed in the first absorption/desorption resin unit 202.; FIG.', '2C is a process diagram of a first process 280 according to another embodiment.', 'Here, an exchange section 282 is used to initialize a purified lithium-bearing stream 284 from the brine feed 106, using single, double, or multi-stage absorption/desorption processing.', 'The lithium-bearing stream 284 is optionally routed to a softener 286, where an intermediate lithium-bearing stream 288 emerges.', 'Either the lithium-bearing stream 284 or the intermediate lithium-bearing stream 288 is routed to an evaporator 290 to increase lithium concentration.', 'Much of the water in the feed to the evaporator 290 can be removed and returned to the exchange section 282 as the recycle water stream 222.', 'A lithium concentrate stream 292 emerges from the evaporator having lithium concentration up to the solubility limit of the lithium salts from the original brine feed 106.', 'For lithium chloride, the concentration in the lithium concentrate stream 292 may be up to 84 wt %.', 'Any suitable evaporator can be used for the evaporator 290, including steam evaporators, furnace evaporators, solar-powered or direct solar evaporators, and the like.', 'In one embodiment, a multi-effect compression evaporator is used in which the lithium-bearing feed stream is exposed to a heat source at elevated pressure to increase temperature, and then the heated stream is reduced in pressure to effect evaporation and separation of vapor from residual liquid, which becomes the lithium concentrate stream 292.; FIG.', '3A is a process diagram of a lithium extraction process 3000 according to one embodiment.', 'The lithium extraction process 3000 may be used as the second process 103 of the lithium extraction process 100 of FIG.', '1.', 'The lithium extraction process 3000 may also, or alternately, be used at the first process 102 of the lithium extraction process 100 of FIG.', '1.', 'The lithium extraction process 3000 removes lithium from an aqueous source, and produces an environmentally benign aqueous return stream.', 'Here, the aqueous source is a process such as the first process 102 of the lithium extraction process 100 of FIG.', '1.; FIG.', '3B is a process diagram of a lithium extraction process 3100 according to another embodiment.', 'Here, a high-concentration lithium-bearing aqueous stream 3102 is contacted with a liquid absorbent in a multi-chamber mixer/settler 3104.', 'The liquid absorbent stream 3012 is provided to a mixing chamber 3106 of the mixer/settler 3104 along with the stream 3102.', 'Here, the high-concentration lithium-bearing aqueous stream can be any of the streams identified as feed streams for the process of FIG.', '3A. Mixing is performed in the mixing chamber 3106 by any suitable means, such as powered agitation, pumparound mixing, static and/or dynamic mixers, and the like.', 'High-shear mixing matched to reaction kinetics obtains the best results, but any mixing can be used with sufficient residence time.', 'Residence time in the mixing chamber 3106 is selected to allow time for transportation of lithium from the aqueous phase to the absorbent phase, and mixing is performed to reduce diffusion lengths, and therefore times, in the aqueous phase.; FIG.', '3C is a process diagram of a lithium extraction process 3200 according to another embodiment.', 'The process 3200 of FIG.', '3C is similar to the process 3100 of FIG.', '3B, except that a different method is used to contact the various materials to perform extraction and recovery.', 'As in the processes 3000 and 3100 of FIGS. 3A and 3B, there are two stages to the process 3200 of FIG.', '3C, a contacting stage 3204 and an extraction stage 3221.', 'In each stage, a centrifugal mixer/separator is used to contact an aqueous medium with an organic medium, accomplish material transfer between the two media, and then separate the media.', 'Here, the contacting, transfer, and separation are primarily performed in a single centrifugal mixer/separator.;', 'FIG.', '3D is a schematic cross-sectional view of a lithium extraction vessel 3300, according to one embodiment.', 'The lithium extraction vessel 3300 has three chambers, a contacting chamber 3312, a scrubbing chamber 3314, and an extraction chamber 3316.', 'The lithium extraction vessel 3300 is operated in continuous-flow mode with a lithium-bearing concentrate stream, a make-up organic absorbent, and a decoupling agent as feed streams and an aqueous lithium salt stream, an organic absorbent purge, and a depleted aqueous stream as effluents.', 'The organic absorbent is recycled within the vessel 3300 from the scrubbing chamber 3314 and the extraction chamber 3316 to the contacting chamber 3312.', 'The three chambers are separated by three partitions, a first partition 3313 separating the contacting chamber 3312 from the scrubbing chamber 3314 and a second partition 3315 separating the scrubbing chamber 3314 from the extraction chamber 3316.; FIG.', '4 is a process diagram of a lithium extraction process 400 according to another embodiment.', 'The lithium extraction process 400 includes the separation process 200 of FIG.', '2A and an electrochemical unit 402 as a second process 103.', 'No third process 104 is used in the process 400 since the electrochemical unit 402 produces a salable lithium product.', 'The electrochemical unit 402 includes a vessel 404 with an electrode 406 electrically coupled to a power circuit 408.', 'In one embodiment, the electrochemical unit 402 operates by intercalating lithium into a lithium-selective electrode, for example a manganese-containing electrode, until an endpoint is reached.', 'The electrode is powered with a voltage selective for lithium uptake.', 'The vessel 404 is then flushed and filled with fresh water or a dilute lithium salt solution.', 'Finally the potential is reversed on the electrode 406 to release the lithium from the electrode into the solution.'] |
US11091994 | Method of refracturing in a horizontal well | Feb 8, 2017 | Sergey Dmitrievich Parkhonyuk, Evgeny Pavlovich Korelskiy, Kreso Kurt Butula, Andrey Sergeevich Konchenko, Valeriy Anatolievich Pavlov | Schlumberger Technology Corporation | International Preliminary Report on Patentability of International Patent Application No. PCT/RU2017/000060 dated Aug. 22, 2019; 8 page.; Butula et al., “Re-fracturing Considerations of Horizontal Well Multi Stage Fractured Completions in Mid Permeability Formations”, SPE-176720, Society of Petroleum Engineers, Oct. 26, 2015, 17 pages.; Jorgensen et al., “Using Flow Induced Stresses for Steering of Injection Fractures”, SPE/ISRM 78220, Society of Petroleum Engineers, Oct. 20-23, 2002, 9 pages.; International Search Report and Written Opinion issued in International Patent Appl. No. PCT/RU2017/00060 dated Sep. 14, 2017; 7 pages.; English Translation of International Search Report issued in International Patent Appl. No. PCT/RU2017/000060 dated Sep. 14, 2017; 1 page. | 7565929; July 28, 2009; Bustos et al.; 8210257; July 3, 2012; Dusterhoft et al.; 9366124; June 14, 2016; Brannon et al.; 20070079652; April 12, 2007; Craig; 20170114613; April 27, 2017; Lecerf; 20180355707; December 13, 2018; Rodriguez Herrera | 2462590; September 2012; RU; 2496001; October 2013; RU; 2018004370; January 2018; WO; 20218004369; January 2018; WO | ['A horizontal well may be refractured or reactivated by generating a geomechanical model to estimate the stress level in the formation; identifying zones with high, medium, and low stress levels in the formation; isolating existing fractures in the horizontal well; injecting a fracturing fluid into the well to create at least one new fracture in a zone with a low stress level and packing the created fracture with proppant to increase the stress level in the zone; isolating the at least one newly created fracture; initiating refracturing in the zone with the high and/or medium stress level; identifying a location of the refracturing crack in the zone with the high and/or medium stress level; and developing the refracturing crack and packing it with proppant.'] | ['Description\n\n\n\n\n\n\nThe present disclosure is directed to oil and gas industry and can be useful for stimulating subterranean formation using a hydraulic fracturing operation (frac), in particular, for refracturing of the formation.', 'BACKGROUND\n \nHydraulic fracturing of the formation (frac), also referred to as hydraulic fracturing, is the main means to increase well production due to generation or expanding cracks or channels leading from the wellbore to the pay formation.', 'Pumping beads of a propping agent (proppant) in the course of hydraulic fracturing of oil and gas bearing geological formations can increase the hydrocarbon production level of the formation.', 'The practice in oil and gas industry shows that a prolonged process of extraction of a formation fluid (oil and water), as well as pumping fluid into a formation can significantly change the stress pattern in the formation.', 'The standard geomechanical and hydrodynamical models of the formation can be used for calculating the pattern of pore pressure distribution and stress tensor distribution in the formation.', 'In practice, such calculations are performed at various stages of the formation lifetime, i.e. at the beginning of oil production, after well treatments, and at later s stages of production of the formation.', 'For the later stages of production of the formation that has earlier undergone stimulation by hydraulic fracturing or multiple fracturing (multizone frac) in an open-hole horizontal well, the geomechanical models can be used to find lean and weakly depleted zones around the well.', 'Zones, drainage of the formation fluid from which through the productive fractures was more intense, become the lean zones, and for them, the models predict a reduced level of minimal principal stress value (a component of the stress tensor), while virgin zones have the original high stress level in the productive formation.', 'For the formation with a horizontal (open-hole)', 'well, a situation occurs that refracturing will be performed in a zone with a low in-situ stress in the rock surrounding the well.', 'On the other hand, the regions with high in-situ stresses, according to the theory of hydraulic fracturing, will play the role of mechanical barriers that the fracture never enters.', 'In other words, the drained (lean) formation regions become the mechanically “preferable” sites for the next hydraulic fracturing, while the lean zones are “non-preferable” sites for the purpose of additional formation stimulation and enhancement of the fluid(s) production.', 'Therefore, the task of performing refracturing in a non-depleted zone having a potential for additional oil production requires “correcting” the stress field around the horizontal wellbore.\n \nHereinafter, the term “horizontal well” refers to a part of a drilled well with a horizontal or nearly level trajectory.', 'Note that this task of refracturing on a horizontal part of a well differs from the task of performing refracturing in a vertical well.', 'In the case of a vertical well, the hydrostatic pressure will be higher for deeper intervals, and an interval refracturing with sequential isolation of the lower intervals is feasible.', 'In the case of a horizontal well, the hydrostatic pressure will be even for all parts of the well, and refracturing will occur at the site with the minimum stress level.', 'Technologies for influencing the mechanical stress pattern in a subterranean formation are available in literature.', 'Publication SPE-78220-MS (Jorgensen, O. (2002 Jan. 1).', '“Using Flow Induced Stresses for Steering of Injection Fractures”.', 'Society of Petroleum Engineers.doi:10.2118/78220-MS) demonstrates that pumping aqueous fluid into the formation through an injection well affects the stress distribution in the formation, which can be used to control the hydraulic fracturing plane.', 'Calculations demonstrated that after three months of production/injection, the direction of the effective horizontal stress in the rock changes, and the values of stresses in the rock surrounding the production well and surrounding the injection well differ by nearly 10 MPa.', 'Publication SPE-176720-RU (Butula, K. K., Yudin, A., & Klyubin, A. (2015 Oct. 26).', '“Re-fracturing Considerations of Horizontal Well Multi Stage Fractured Completions in Mid Permeability Formations” (Russian).', 'Society of Petroleum Engineers.doi:10.2118/176720-RU) addresses the productivity of the horizontal wells completed with arrangements for multizonal hydraulic fracturing (multistage hydraulic fracturing, MSHF) drilled in the low and medium permeability formations.', 'Refracturing modeling using a geomechanical model (e.g., the FRACCADE® software) demonstrated that such operation increases the fracture-formation interface area.', 'Furthermore, it has also been shown that the azimuth of a refracturing crack changes relative to the existing “old” fractures.', 'This is caused by the changes in the natural stress field under the influence of the combined changes in the formation pressure around the production and injection wells.', 'The refracturing cracks are assumed to be normal to the existing hydraulic fracturing cracks.', 'This ensures an increased oil recovery factor (ORF).', 'The methods of refracturing in a horizontal well are known from the practice of the oil-producing industry.', 'U.S. Pat.', 'No. 9,366,124 (BAKER HUGHES INCORPORATED, 2016) discloses a method of refracturing using packers and coil tubing conveyed into the horizontal part of the well.', 'The horizontal (cased) well has several fracture clusters that need reactivation.', 'Using a packer and a slug of a diverting agent, the furthest fracture cluster is first hydraulically isolated.', 'Then, the isolated cluster is refractured at the existing (“old”) fracture, which increases the hydrocarbon fluid production from the formation.', 'The slug of the diverting agent (slurry of particles, which forms an isolating plug when delivered to the required site) is delivered via coil tubing to hydraulically isolate the cluster of the existing (“old”) fractures.', 'After completion of refracturing, the slug of the diverting agent is removed.', 'Usually, the use of the packer for reliable isolation of a part of the wellbore is possible for the cased horizontal wells.', 'U.S. Pat.', 'No. 8,210,257 (Halliburton Energy Services Inc, 2012) discloses a method of refracturing using the controlled injection units deployed in a horizontal well (e.g., controlled frac collar on a liner).', 'By creating new fractures, the mechanical stress level in the formation is changed.', 'Using control signals from the surface, the state of the injection units can be controlled (change of the “open-closed” state).', 'After the pattern of stresses in the formation around the wellbore has been changed, the fracturing fluid is pumped into one isolated interval to initiate the creation of a fracturing network.', 'The creation of the fracturing network on a larger part of the horizontal well instead of conventional (unbranched) fracture provides an additional volume of stimulated formation.', 'On the other hand, the method requires a specialized subsystem to control the injectors, which complicates the arrangement for multizonal injection in the horizontal well.', 'Therefore, there is a demand for performing the refracturing operations for horizontal wells, wherein the auxiliary fractures are used to change the stress level in various formation zones (intervals), with subsequent refracturing in the less depleted zones.', 'Furthermore, the refracturing operations are accompanied by the operations of isolating the existing (“old”) fractures to ensure refracturing in the new (virgin) parts of the well.', 'According to the provided method, refracturing can be performed without any additional wellbore equipment.', 'Also, when operating the injection horizontal wells, a situation may appear that the intake of the surrounding rock decreases over time.', 'This may be caused by the changes in stresses at different formation parts, the processes of scale (salts) deposition from the injected aqueous liquid or slick water in the rock, which generally decreases the efficiency of the formation waterflooding.', 'There is a demand for the methods of reactivation of an injection well by creating new fractures to stimulate the fluid injection in the formation for longer distances and in larger volumes.', 'SUMMARY\n \nThe present disclosure in its aspects provides the following.', 'One aspect of the present disclosure provides a method of refracturing in an open-hole horizontal well, wherein the productive fractures are present.', 'The method starts from generating a geomechanical model to estimate the stress level in the formation.', 'Based on the generated geomechanical model of the formation, zones with high, medium, and low stress levels in the rock surrounding the wellbore are identified.', 'Then, the existing (“old”) fractures in the horizontal well are isolated by injecting slugs of an isolating agent.', 'After that, in the selected interval with originally low stress level in the formation (i.e. in a lean zone), the stress level is increased by creating at least one auxiliary fracture and packing the created fracture with proppant: a small-sized auxiliary fracture is thus formed (“stress fracture”, i.e. a fracture to locally increase the stress level).', 'After closing this auxiliary fracture, the stress level in the selected zone increases from the original low value up to a medium or high value.', 'The new stress distribution near the horizontal well allows performing refracturing at a new site, where the originally high stress level now turns out to be lower than in the zone of the auxiliary fracture, and thus favourable conditions for the development of a new fracture have been created.', 'At least one propped fracture in the part with an originally low stress level in the formation is isolated (using an isolating agent).', 'The isolating agent (or the isolating pill) is a plug of the slurry of plugging particles and fibres that, upon injecting in an open crack, build up therein and reduce the fluid intake.', 'Refracturing is then initiated in the zone with an originally high or medium stress level (which have previously been identified on the basis of the geomechanical model).', 'While the refracturing crack is in an open state, the location identification of the refracturing crack relative to the zones of high, medium, and low stress levels in the formation around the well is performed.', 'If, based on the identification results, the open crack is located in the zones of originally high or medium stress level, the injection of the fracturing fluid is continued to develop further and pack the refracturing crack with proppant.', 'If required, several refracturing cracks are created.', 'According to another aspect of the present disclosure, a method is provided to reactivate an injection horizontal multizonal well, wherein the new refracturing cracks created in the zones with originally high or medium stress level are used to inject an aqueous liquid or slick water into the formation.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nFIG.', '1\n shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment and non-isolated existing (“old”) fractures (the starting configuration for refracturing).', 'FIG.', '2\n shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment with isolated existing (“old”) fractures and one small-sized auxiliary fracture.\n \nFIG.', '3\n shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment with isolated existing (“old”) fractures and one refracturing (new) crack.\n \nFIG.', '4\n shows a vertical cross-section of a drilled well in a productive formation: the results of a geomechanical modeling with the zones having various stress levels and refracturing cracks are indicated.', 'DETAILED DESCRIPTION', 'The present disclosure is based on the task of creating a refracturing method for a horizontally arranged well.', 'The first stage of the disclosed method comprises modeling the formation to determine the intervals of the horizontal well having various stress levels.', 'The geomechanical model (stress distribution and pore pressure distribution) is generated using various commercially available software with varying degrees of model details.', 'Thus, a 3D distribution of formation stress at different stages of well(s) lifetime can be obtained using, e.g., the PETREL® software (Schlumberger product).', 'Software packages Ru-FRAC or MANGROVE® and Visage (Schlumberger products) also have options for calculating new stress distribution after refracturing.', 'A 3D geomechanical model taking into account the temporal evolution of the formation can reveal the zones with different stress levels in the formation with the existing (“old”) fractures.', 'To generate a simplified geomechanical model, the simplified (2D and 1D) frac simulators are used, wherein, in addition to the standard input data on the formation (mechanical strength, porosity, permeability, formation breakdown pressure), additional semi-empirical data on the mechanical stress distribution around the wellbore are entered.', 'As used herein, the term “geomechanical model” refers to the results of numerical modeling of the formation of any level of complexity, which can be used to reliably identify zones (intervals) with different stress levels near the horizontal well.', 'The classification of a horizontal part of the well into the zones with high, medium, or low stress levels in the rock is performed relative to a certain “average” stress level around the horizontal well.', 'The suitable main parameters for consideration of the stressed state of the rock are either stress modulus (when modeling the isotropic stress), or components of the stress tensor (in the case of the anisotropic stress).', 'In one embodiment, the geomechanical model provides the major horizontal stress, which is the main parameter for predicting hydraulic fracturing on a horizontal part of the well.', 'The difference between the stress levels in different intervals (zones) identified on the basis of the geomechanical model amounts to more than 1 bar.', 'In this case, the fracture development in the formation will depend on the interval classification.', 'A lower difference in stress between intervals cannot change the prediction of the refracturing site.\n \nFIG.', '1\n shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment and productive fractures (regular fractures).', 'The fractures belong to the intervals with different mechanical properties (stress levels) and different rock drainage levels (lean and rich).', 'The method of refracturing in the horizontal well \n1\n is performed using a standard arrangement \n2\n for multizonal treatment (multistage hydraulic fracturing, MSHF) of the horizontal well.', 'The multizonal arrangement \n2\n for the horizontal part of the well includes a liner pipe, onto which the interval packers are deployed, frac collars (also referred to as the frac ports), through which the fracturing fluid (either a proppant slurry or a proppant-free fluid) is injected into the desired zone of the well.', 'The multizonal arrangement type FALCON or StageFRAC (Schlumberger product) can also be employed.', 'In another embodiment, the operation of injecting the fracturing fluid and injection of the isolating agent are performed in an open-hole horizontal well.', 'As will be readily apparent to those of ordinary skill in the art, other arrangements are also possible for this part.', 'At the first stage, a computer modeling of the stress levels using an available geomechanical model (in 2D or 3D approximation) is performed for the formation traversed with the horizontal well \n1\n with productive fractures.', 'Such geomechanical model (e.g., VISAGE and PETREL®) provides a complete 3D pattern of the stress tensor and pore pressure in the rock of the reservoir.', 'Using the geomechanical model, the zones of different types are identified along the well: zones with a low \n3\n, moderate (medium) \n5\n, and high \n7\n stress levels in the formation.', 'These zones \n3\n, \n5\n, \n7\n already have productive fractures.', 'Thus, a zone with a low stress level \n3\n has a fracture \n4\n, a zone with a medium stress level \n5\n has a fracture \n6\n, while a zone with a high stress level \n7\n has several fractures \n8\n.', 'These zones differ not only in the stress level, but also in the degree of depletion and other characteristics.', 'Such zoning (zones \n3\n-\n5\n-\n7\n) of the horizontal part of the well at later stages of production is usually related to the history of the formation fluid production from the reservoir, i.e. to the presence of the drained (lean) zones of the formation, which is shown as a decreased pore pressure (in the case of a linear-elastic geomechanical model, the pore pressure in the rock is directly associated with the stress).', 'Usually, the depleted interval \n3\n has the lowest stress level.', 'The virgin (having high pore pressure) zones (\n5\n and \n7\n in \nFIG.', '1\n) retain the originally high stress level.', 'As an exemplary embodiment, \nFIG.', '1\n shows three intervals (\n3\n, \n5\n, \n7\n), for which a diagram of the zone-average stress in the formation is given in the upper part of the drawing.', 'For example, zone \n3\n has the stress level of about 320 bar as compared to 355-365 bar for a weakly drained zone (zone \n7\n).', 'The stress level in the selected zones has been found using the PETREL® geomechanical model and corresponds to the regions with a high, medium (moderate), and low formation drainage.', 'At the next stage, the isolation (plugging, formation damage) of the existing fractures \n4\n, \n6\n, \n8\n is performed.', 'FIG.', '2\n shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment with the isolated fractures \n4\n, \n6\n, \n8\n. \nFIG.', '2\n shows that the isolating pills \n9\n (slugs of the isolating agent) close the entrance of the fractures (\n4\n, \n6\n, \n8\n).', 'The isolating pills \n9\n can be prepared of a downhole non-degradable or degradable material (in the latter option, a temporary fracture isolation for the duration of operation is achieved).', 'The technique for delivery and deployment of the isolating material (slugs in the form of particles and fibre slurry) in the open fractures is disclosed in U.S. Pat.', 'No. 7,565,929 (Schlumberger Technology Company).', 'After minimizing the ingress of the fracturing fluid into the isolated fractures, the stage of creating an auxiliary fracture \n10\n (or several auxiliary fractures) in the part of the horizontal well (for a local increase in the stress level in this zone \n3\n) is performed.', 'Since, according to the mechanics laws, a fracture arises and develops in the regions with a low major stress value, the auxiliary fracture \n10\n arises directly in zone \n3\n with the decreased stress level.', 'The development of the auxiliary fracture \n10\n (or several auxiliary fractures) in the zone with the low stress level in the formation locally increases the stress level (up to the level of 370 bar in \nFIG.', '2\n).', 'The stress level is stably increased if the auxiliary fracture \n10\n is packed with a high-strength proppant.', 'The propping agent (proppant) props the fracture walls, thereby preserving the increased stress in zone \n3\n (the stress increased up to the level of 370 bar in \nFIG.', '2\n), which is significantly higher than in the original situation.', 'Suitable proppants for the auxiliary fracture \n10\n include high-strength quartz sands or artificial ceramic sands, or mixtures thereof.', 'According to the disclosure, the operation of creating the auxiliary fracture \n10\n in the zone with an originally low stress level increases the stress level by at least 5 bar.', 'Such increase in the stress exceeds the difference in the stresses found for the zones (\n3\n, \n5\n, \n7\n) in the geomechanical model.', 'According to the modern techniques, a direct measurement of stress in the rock surrounding the well is complicated; therefore, the data of the numerical modeling is used.', 'There are two sources of the increased stress in zone \n3\n: the propped small-sized auxiliary fracture \n10\n (the purely mechanical load propagates through the formation around the fracture), and infiltration of the fracturing fluid itself into the formation (local injection of the pore fluid).', 'The modeling of the process of creating a planar fracture demonstrates that the increase in the stress level and the pore pressure over time becomes noticeable at the distances of the order of the fracture length.', 'A kind of stress “diffusion” over the formation takes place, i.e. the required increase in the stress occurs at the scale of the entire zone where the propped fracture \n10\n (“the stress fracture”) appeared.', 'Furthermore, the amount of the fracturing fluid (with proppant) required to create the fracture \n10\n is 5% to 50% of the amount of the fracturing fluid required for refracturing (see subsequent stages).', 'At the same time, the fracture \n10\n is auxiliary and small in size, since such fracture \n10\n is originally created not for production of the formation fluid (the fracture has a volume less than a “regular” fracturing crack), but rather to change the stress level in the formation in the treatment zone.', 'At the next stage (\nFIG.', '3\n), the propped fracture \n10\n is isolated with a slug of the isolating agent \n9\n.', 'Now, the formation surrounding the horizontal well \n1\n has been prepared for refracturing: all productive fractures (\n4\n, \n6\n, \n8\n) and the (new) auxiliary fracture \n10\n have been isolated; therefore, the fracturing fluid at a pressure exceeding the formation breakdown pressure will be injected in the initiated fracture.', 'After isolating the propped fracture \n10\n, refracturing is performed in the zones with the originally medium and high stress levels (such zones \n5\n and \n7\n have previously been identified on the basis of the geomechanical model).', 'Refracturing proceeds in zones \n5\n and \n7\n with a low drainage level (virgin zones of the formation).', 'At the next stage of the method, a refracturing crack \n12\n is initiated by increasing the fluid pressure in the horizontal well \n1\n beyond the level of the formation breakdown pressure (\nFIG.', '3\n).', 'The initiation is achieved by injecting the pad (proppant-free) fluid at a high pressure.', 'At this stage, the operator needs to know that the fracture \n12\n has been opened in the required zone (zone \n5\n or \n7\n, but not zone \n3\n).', 'To do this, the injection of fluid at a pressure exceeding the formation breakdown pressure is continued, and the location identification of the refracturing crack is performed.', 'The methods of identification of an open fracture rely on the fact that an open fracture is a hydrodynamic singularity in the well filled with fluid in contrast to the closed fractures \n4\n, \n6\n, \n8\n, \n10\n (\nFIG.', '2\n).', 'In an embodiment of the disclosure, the location identification of the refracturing crack is performed by pumping a “marker” fluid pulse in the wellbore and registering the resulting pressure response in the fluid filling the wellbore.', 'The method of determining the actual location of an open fracture using a marker pulse has been disclosed in patent application PCT/RU2016/000408 and is hereby incorporated by reference in its entirety.', 'In other embodiments of the disclosure, the location identification of the refracturing crack is performed by registering tube waves in the well.', 'Such method of the location identification of the wellbore objects (such as an open fracture) uses a special technique for processing signals with a high noise level in the well.', 'The method has been described in patent application PCT/RU2016/000407 and is hereby incorporated by reference in its entirety.', 'After the positive location identification of the initiated refracturing crack (the fracture develops in a zone with a medium or high stress), the injection of the proppant slurry for propping the refracturing crack \n12\n is continued.', 'FIG.', '3\n shows a schematic drawing of a part of a horizontal well with the arrangement for multizonal treatment after isolating (plugging) the fractures \n4\n, \n6\n, \n8\n and isolating the auxiliary fracture \n10\n.', 'A refracturing crack (re-frac) \n12\n has been created and propped in the zone with an originally medium stress level (zone \n5\n).', 'The creating of the refracturing crack \n12\n also (locally) increases the stress level in zone \n5\n (from the level of 345 bar to the level of 420 bar, cf. \nFIG.', '2\n and \nFIG.', '3\n).', 'The amount of the injected fracturing fluid for developing and propping the refracturing crack \n12\n is determined on the basis of an earlier prepared frac design using the commercially available frac simulators.', 'A temporary plugging of the refracturing crack \n12\n with a self-degradable plugging agent is also possible to continue stimulation of other formation zones, as described above.', 'According to the method, the subsequent refracturing cracks (not shown in \nFIG.', '3\n) may be created in the intervals \n5\n and \n7\n.', 'The process is repeated as described above with the purpose of locally increasing the stress level in the fracturing zone to perform subsequent refracturing in one of the zones.', 'Subsequent refracturing in zones \n5\n and \n7\n provides a multizonal treatment of the formation, thus allowing an increase in the volume of the stimulated formation and an improvement in the oil recovery factor (ORF).', 'This approach equips an engineer with a toolbox of auxiliary hydraulic fracturing, fracture isolation and refracturing techniques for treating all the zones on the horizontal part of the well.', 'The exact location of the new fracture (such as the refracturing crack \n12\n in zone \n5\n) depends on numerous geomechanical factors, since the stresses within each of the selected zones are not constant and may vary due to the “stress diffusion” in the rock.', 'When necessary, at the stages after propping and isolating the auxiliary fracture \n10\n and after propping and closing the refracturing crack \n12\n, additional modeling of the stress level is performed to predict the location of the next refracturing crack.', 'EXAMPLES\n \nBelow the results of refracturing of a formation are provided, wherein an intense production of the formation fluid (oil or oil-water-gas mixture) has been performed for 2-3 years through the horizontal well with multizonal hydraulic fracturing (several fractures), which resulted in the appearance of the lean and weakly-depleted zones around the horizontal well.', 'FIG.', '4\n shows the results of refracturing over the zones of the horizontal well and data of the geomechanical model on the stress level in the formation after refracturing.', 'Geomechanical Model of Formation\n \nThe processes occurring in the course of auxiliary hydraulic fracturing to locally change the stress level were modeled using the VISAGE® software (Schlumberger Technology Company, geomechanical simulator) and the ECLIPSE® software (Schlumberger Technology Company, hydrodynamical simulator), with modeling script prepared in the PETREL® environment.', 'As the input data, superimposed hydrodynamical and geomechanical models were used, as well as data on the pumping schedule, fluid volume, and type of the injected fracturing fluid.', 'When generating the model of the formation and fractures, the hydrodynamical and geomechanical models are superimposed.', 'The ECLIPSE® software takes into account the geometry of the auxiliary fracture \n10\n (height, length) that are found using the frac simulators (FracCADE or RU-FRAC).', 'The effect of creating and propping the fractures on the stress distribution over the zones is evaluated using the VISAGE software.', 'To obtain the desired effect, the minimum horizontal stresses in the stimulation zone must exceed the formation breakdown pressure for the next zone where the stimulation is scheduled.', 'Well and Formation', 'The considered well \n1\n had the length of a horizontal bore of about 800 m. The absolute depth of the formation was within the range of 2,730-2,800 m. A ball arrangement \n2\n for a six-stage hydraulic fracturing (multistage hydraulic fracturing, MSHF) with the distance between the frac ports of 100-120 m was hauled down into the well.', 'At the moment of refracturing, the balls and ball seats of the MSHF arrangement had been drilled, i.e. there were no barriers for the fracturing fluid transport.', 'The cubes of filtration and capacity parameters for the hydrodynamic modeling were generated using the current geological model, well data, and core examination; geostatistical methods were used for modeling in the inter-well space.', 'The considered well had porosity in the permeable intervals 11-18% and permeability 0.7-11 milliDarcy.', 'The thickness of the permeable intervals was 12-14 m. The hydrodynamic model builds upon the history of the formation fluid production (or fluid injection into the formation).', 'The geomechanical model of the formation was generated using the data of geophysical well logging and core examination.', 'The mechanical properties of the surrounding rock were modeled using the geostatistical methods, the stress-strained state was modeled with the VISAGE® software that uses the finite elements method.', 'Furthermore, the geomechanical model was checked using the data of mini-frac (mini-frac is a diagnostic method to perform limited-volume hydraulic fracturing for checking the actual breakdown pressure and estimating intake of the formation).', 'Young modulus around the horizontal well was 14-27 GPa for sandrock and 8-12 GPa for clays, Poisson ratios for sandrock and clays were 0.21-0.25 and 0.28-0.31, respectively.', 'At the moment of performing the work, the formation pressure was 160-190 bar, or 0.6-0.7 of the original pressure in the reservoir.', 'The minimum horizontal stress based on the results of modeling was found to be 350-370 bar.', 'As the modeling demonstrates, in one of the well intervals there is a low-stress and low pore pressure zone: this zone is the target for creating and propping the auxiliary fracture \n10\n.', 'Modeling of the stress level in the formation demonstrated that creation of a small-sized auxiliary fracture \n10\n in the interval with low stress level \n3\n locally increases the stress for the period of up to 48 hours, during which refracturing in other target zones was performed.', 'Into the auxiliary fracture \n10\n created in the zone with low stress level, the operator injected 85 m\n3 \nof fluid; proppant amount was 2 tons.', 'For the main work (for refracturing), 50 tons of proppant and 160-200 m\n3 \nof fluid were pumped at each stage.', 'Half-length of the auxiliary fracture \n10\n (based on the results of modeling in the frac simulator) was 15-20 m, with the modeled half-length of the refracturing crack being close to 120 m.', 'Thus, the dimensions and volume of the auxiliary fracture \n10\n are much lower than those for refracturing (main frac).', 'Temporary Fracture Isolation with Isolating Agent\n \nA step-wise isolation of all existing (“old”) fractures and the auxiliary fracture \n10\n was performed using the technologies of fracture isolation and fluid diversion to other zones for multizonal hydraulic fracturing, According to this technology, a mixture of plugging particles with a multimodal size distribution and degradable fibres was injected into the fractures for plugging.', 'The mixture was delivered as a slug of slurry in a slick water.', 'As a result of ingress of this slug into the fracture, a low permeability isolating plug was formed with rather low material consumption to form the isolating plug.', 'Today, self-degradable materials for isolation can be selected (such as, e.g., particles of fibres made of polylactic or polyglycol acid) that would provide a gradual plug degradation for the formation temperature within the range of 40° C. to 200° C.', 'The fractures can also be isolated with a non-degradable plugging agent (such as, for example, particles of calcium carbonate and polymer fibres).', 'FIG.', '4\n shows the performance of two refracturings \n12\n in the zones with the earlier isolated productive fractures \n8\n.', 'An increase in the stress level in zone \n3\n after creating the auxiliary fracture \n10\n is reflected with a darker tone on the 2D pattern of the stress distribution (see the corresponding legend in the left part of the pattern).', 'Modeling of the formation fluid (oil) influx in the horizontal well through the refracturing cracks \n12\n demonstrates a gain in oil production.', 'Although only several exemplary embodiments of the present disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that numerous modifications of the provided embodiments are possible without materially departing from this disclosure.', 'Accordingly, all such modifications should be included in the scope of the disclosure as defined in the claims below.'] | ['1.', 'A method of refracturing in a horizontal well, which comprises: (a) generating a geomechanical model to estimate the stress level in a formation; (b) identifying zones along the horizontal well with high, medium, and low stress levels in the formation around the well based on the generated geomechanical model of the formation, wherein the stress levels between different intervals differ by more than 1 bar; (c) isolating existing fractures in the horizontal well; (d) injecting a fracturing fluid into the well to create at least one new fracture in a zone with a low stress level and packing the newly created fracture with proppant to increase the stress level in the zone; (e) isolating at least one fracture created at stage (d); (f) initiating refracturing in the zone with a high and/or medium stress level identified at stage (b); (g) identifying a location of the refracturing crack in the zone with a high and/or medium stress level; (i) developing the refracturing crack and packing it with proppant.', '2.', 'The method of claim 1, wherein the isolation of the fractures at stages (c) and (e) is achieved by injecting slugs of a plugging agent.', '3.', 'The method of claim 1, wherein the development of the refracturing crack and its packing with proppant at stage (i) are performed in the zone with a high and/or medium stress level in the formation around the well identified at stage (b).', '4.', 'The method of claim 1, wherein the geomechanical model is generated on the basis of the temporal evolution of the 3D distribution of formation stress and pore pressure.', '5.', 'The method of claim 1, wherein the geomechanical model is generated on the basis of the temporal evolution of the 2D distribution of formation stress and pore pressure.', '6.', 'The method of claim 1, wherein the amount of the fracturing fluid with proppant for creating the fracture at stage (d) is within the range of 5% to 50% of the fracturing fluid amount with proppant for refracturing.', '7.', 'The method of claim 1, wherein the hydraulic fracturing operation at stage (d) in the zone with the low stress level increases the stress level by at least 5 bar.\n\n\n\n\n\n\n8.', 'The method of claim 1, wherein, after hydraulic fracturing at stage (d), the new stress level in the formation around the well is additionally determined using the geomechanical model.', '9.', 'The method of claim 1, wherein the location identification of the refracturing crack at stage (g) is performed by pumping a viscous marker pulse in the well and registering the resulting pressure response in the fluid.', '10.', 'The method of claim 1, wherein the location identification of the refracturing crack at stage (g) is performed by registering tube waves in the well.\n\n\n\n\n\n\n11.', 'The method of claim 1, wherein the hydraulic fracturing operation at stage (d) is performed by pumping a slurry of a high-strength ceramic sand and/or quartz sand.\n\n\n\n\n\n\n12.', 'The method of claim 1, wherein stage (i) is repeated in the zone with the high and/or medium stress level in the formation around the well identified at stage (b).', '13.', 'The method of claim 1, wherein the operation of injecting the fracturing fluid is performed using a multizonal arrangement comprising, e.g., a liner, packers, frac collars.', '14.', 'The method of claim 1, wherein the operation of injecting the fracturing fluid is performed in an open-hole horizontal well.', '15.', 'A method of reactivating an injection horizontal well, which comprises: (a) generating a geomechanical model to estimate the stress level in a formation; (b) identifying zones with high, medium, and low stress levels in the formation around the well based on the generated geomechanical model of the formation, wherein the stress levels between different intervals differ by more than 1 bar; (c) isolating existing fractures in the horizontal well; (d) injecting a fracturing fluid into the well to create at least one new fracture in a zone with a low stress level and packing the newly created fracture with proppant to increase the stress level in the zone; (e) isolating at least one fracture created at stage (d); (f) initiating refracturing in the zone with the high and/or medium stress level identified at stage (b); (g) identifying a location of the refracturing crack in the zone with a high and/or medium stress level; (i) developing the refracturing crack and packing it with proppant; (k) pumping the injecting fluid into the formation to increase the formation pressure or improve the oil recovery factor.'] | ['FIG.', '1 shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment and non-isolated existing (“old”) fractures (the starting configuration for refracturing).; FIG.', '2 shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment with isolated existing (“old”) fractures and one small-sized auxiliary fracture.; FIG.', '3 shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment with isolated existing (“old”) fractures and one refracturing (new) crack.; FIG.', '4 shows a vertical cross-section of a drilled well in a productive formation: the results of a geomechanical modeling with the zones having various stress levels and refracturing cracks are indicated.', '; FIG.', '1 shows a schematic drawing of a horizontal well with the arrangement for multi-interval treatment and productive fractures (regular fractures).', 'The fractures belong to the intervals with different mechanical properties (stress levels) and different rock drainage levels (lean and rich).', 'The method of refracturing in the horizontal well 1 is performed using a standard arrangement 2 for multizonal treatment (multistage hydraulic fracturing, MSHF) of the horizontal well.', 'The multizonal arrangement 2 for the horizontal part of the well includes a liner pipe, onto which the interval packers are deployed, frac collars (also referred to as the frac ports), through which the fracturing fluid (either a proppant slurry or a proppant-free fluid) is injected into the desired zone of the well.', 'The multizonal arrangement type FALCON or StageFRAC (Schlumberger product) can also be employed.', '; FIG.', '3 shows a schematic drawing of a part of a horizontal well with the arrangement for multizonal treatment after isolating (plugging) the fractures 4, 6, 8 and isolating the auxiliary fracture 10.', 'A refracturing crack (re-frac) 12 has been created and propped in the zone with an originally medium stress level (zone 5).', 'The creating of the refracturing crack 12 also (locally) increases the stress level in zone 5 (from the level of 345 bar to the level of 420 bar, cf. FIG.', '2 and FIG.', '3).', 'The amount of the injected fracturing fluid for developing and propping the refracturing crack 12 is determined on the basis of an earlier prepared frac design using the commercially available frac simulators.', 'A temporary plugging of the refracturing crack 12 with a self-degradable plugging agent is also possible to continue stimulation of other formation zones, as described above.', '; FIG.', '4 shows the results of refracturing over the zones of the horizontal well and data of the geomechanical model on the stress level in the formation after refracturing.;', 'FIG.', '4 shows the performance of two refracturings 12 in the zones with the earlier isolated productive fractures 8.', 'An increase in the stress level in zone 3 after creating the auxiliary fracture 10 is reflected with a darker tone on the 2D pattern of the stress distribution (see the corresponding legend in the left part of the pattern).', 'Modeling of the formation fluid (oil) influx in the horizontal well through the refracturing cracks 12 demonstrates a gain in oil production.'] |
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US11091960 | Placement of non-planar cutting elements | Jun 15, 2018 | Youhe Zhang, Xiaoge Gan, Huimin Song | SCHLUMBERGER TECHNOLOGY CORPORATION | First Office Action and Search Report issued in Chinese patent application 201680077569.5 dated Aug. 5, 2019, 24 pages.; Shunhui et al., Manufacture and Application of PDC Bit Enhanced by Special Diamond-Impregnated Segment, Petroleum Drilling Techniques, col. 42, No. 6, Nov. 2014, 4 pages.; International Search Report and Written Opinion issued in International Patent Application No. PCT/US2016/063711 dated Mar. 13, 2017, 16 pages.; International Search Report and Written Opinion issued in International Patent Application No. PCT/US2016/063710 dated Mar. 6, 2017, 15 pages.; International Preliminary Report on Patentability issued in International Patent Application No. PCT/US2016/063711 dated Jun. 19, 2018, 12 pages.; International Preliminary Report on Patentability issued in International Patent Application No. PCT/US2016/063710 dated Jun. 19, 2018, 11 pages.; Second Office Action and Search Report issued in Chinese patent application 201680077569.5 dated Jul. 3, 2020, 19 pages.; Third Office Action and Search Report issued in Chinese patent application 201680077569.5 dated Jan. 27, 2021.; Fourth Office Action issued in Chinese patent application 201680077569.5 dated May 8, 2021, 24 pages. | 5033560; July 23, 1991; Sawyer et al.; 5238075; August 24, 1993; Keith et al.; 8122980; February 28, 2012; Hall; 8887837; November 18, 2014; Azar; 10309156; June 4, 2019; Azar; 20060180356; August 17, 2006; Durairajan; 20070205023; September 6, 2007; Hoffmaster; 20080105466; May 8, 2008; Hoffmaster et al.; 20080179108; July 31, 2008; McClain et al.; 20080302575; December 11, 2008; Durairajan et al.; 20100155149; June 24, 2010; Keshavan et al.; 20100326742; December 30, 2010; Vempati et al.; 20120205163; August 16, 2012; Azar et al.; 20130168159; July 4, 2013; Eyre; 20140130418; May 15, 2014; Bao; 20140262544; September 18, 2014; Azar et al.; 20140262545; September 18, 2014; Azar; 20150259988; September 17, 2015; Chen et al. | 204782784; November 2015; CN | ['A downhole cutting tool includes a tool body having a tool axis, and a blade extending from the tool body.', 'The blade includes a cutting face, a trailing face, and a top face extending between the cutting face and the trailing face.', 'Cutting elements are attached to the bade along the cutting face, with each having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest.', 'In some cases, first cutting elements along the cutting face and second cutting elements along the top face and rearward from, and at the same radial position as, the first cutting elements have different size, orientation, geometry or material properties.', 'In additional aspects, at least two cutting elements on the blade have differing material properties, sizes, orientations, or working surface geometries along a blade profile of the blade.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED PATENT APPLICATIONS\n \nThis application is a continuation of International Patent Application No.', 'PCT/US2016/063710, filed Nov. 24, 2016, which claims the benefit of U.S. patent application Ser.', 'No. 62/269,769, filed Dec. 18, 2015.', 'This application is also a continuation of International Patent Application No. PCT/US2016/063711, filed Nov. 24, 2016, which claims the benefit of, and priority to, U.S. patent application Ser.', 'No. 62/269,780, filed Dec. 18, 2015.', 'Each of the foregoing is expressly incorporated herein by this reference in its entirety.', 'BACKGROUND\n \nThere are several types of downhole cutting tools, such as drill bits, including roller cone bits, hammer bits, and drag bits, reamers and milling tools.', 'Roller cone rock bits include a bit body adapted to be coupled to a rotatable drill string and include at least one “cone” that is rotatably mounted to a cantilevered shaft or journal.', 'Each roller cone in turn supports a plurality of cutting elements that cut and/or crush the wall or floor of the borehole and thus advance the bit.', 'The cutting elements, either inserts or milled teeth, contact with the formation during drilling.', 'Hammer bits generally include a one piece body having a crown.', 'The crown includes inserts pressed therein for being cyclically “hammered” and rotated against the earth formation being drilled.', 'Drag bits, often referred to as “fixed cutter drill bits,” include bits that have cutting elements attached to the bit body, which may be a steel bit body or a matrix bit body formed from a matrix material such as tungsten carbide surrounded by a binder material.', 'However, there are different types and methods of forming drag bits that are known in the art.', 'For example, drag bits having abrasive material, such as diamond, impregnated into the surface of the material which forms the bit body are commonly referred to as “impreg” bits.', 'Drag bits having cutting elements made of an ultra hard cutting surface layer or “table” (generally made of polycrystalline diamond material or polycrystalline boron nitride material) deposited onto or otherwise bonded to a substrate are known in the art as polycrystalline diamond compact (“PDC”) bits.', 'An example of a drag bit having a plurality of cutting elements with ultra hard working surfaces is shown in \nFIG.', '1\n.', 'The drill bit \n100\n includes a bit body \n110\n having a threaded upper pin end \n111\n and a cutting end \n115\n.', 'The cutting end \n115\n generally includes a plurality of ribs or blades \n120\n arranged about the rotational axis (also referred to as the longitudinal or central axis) of the drill bit and extending radially outward from the bit body \n110\n.', 'Cutting elements, or cutters, \n150\n are embedded in the blades \n120\n at predetermined angular orientations and radial locations relative to a working surface and with a desired back rake angle (i.e., a vertical orientation) and side rake angle (i.e., a lateral orientation) against a formation to be drilled.', 'FIG.', '2\n shows an example of a cutting element \n150\n, where the cutting element \n150\n has a cylindrical cemented carbide substrate \n152\n having an end face or upper surface referred to herein as a substrate interface surface \n154\n.', 'An ultrahard material layer \n156\n, also referred to as a cutting layer, has a top surface \n157\n, also referred to as a working surface, a cutting edge \n158\n formed around the top surface, and a bottom surface, referred to herein as an ultrahard material layer interface surface \n159\n.', 'The ultrahard material layer \n156\n may be a polycrystalline diamond or polycrystalline cubic boron nitride layer.', 'The ultrahard material layer interface surface \n159\n is bonded to the substrate interface surface \n154\n to form an interface between the substrate \n152\n and ultrahard material layer \n156\n.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'In one aspect, embodiments of the present disclosure relate to a downhole cutting tool that includes a tool body having a tool axis, at least one blade extending from the tool body including a cutting face, a trailing face, and a top face extending between the cutting face and the trailing face, a first cutting element attached to the at least one blade along the cutting face and a second cutting element attached to the at least one blade along the top face, rearward from and at the same radial position from the tool axis as the first cutting element.', 'A working surface of each of the first and the second cutting elements has a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest and the first cutting element has a different size, orientation, geometry, or material properties from the second cutting element.', 'In another aspect, embodiments of the present disclosure relate to a downhole cutting tool that includes a tool body having a tool axis, at least one blade extending from the tool body including a cutting face, a trailing face, and a top face extending between the cutting face and the trailing face, a first plurality of cutting elements attached to the at least one blade along the cutting face and a second plurality of cutting elements attached to the at least one blade along the top face, rearward from and radially between the first plurality of cutting elements.', 'A working surface of each of the first plurality of cutting elements and the second cutting element has a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest.', 'In yet another aspect, embodiments of the present disclosure relate to a downhole cutting tool that includes a tool body, at least one blade extending from the tool body including a cutting face, a trailing face, and a top face extending between the cutting face and the trailing face, a first plurality of cutting elements attached to the at least one blade along the cutting face and a second plurality of cutting elements attached to the at least one blade along the top face, rearward from the first plurality of cutting elements.', 'A working surface of each of the first and the second plurality of cutting elements has a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest, and at least one of the first plurality of cutting elements and at least one of the second plurality of cutting elements on the at least one blade have differing material properties, sizes, orientations, and/or working surface geometries.', 'In one aspect, embodiments of the present disclosure relate to a downhole cutting tool that includes a tool body, at least one blade extending from the tool body, the at least one blade having a cutting face, a trailing face and a top face extending between the cutting face and trailing face, a plurality of cutting elements attached to the at least one blade along the cutting face, a working surface of each of the plurality of cutting elements having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest.', 'At least two of the plurality of cutting elements on the at least one blade have differing material properties, sizes, orientations, and/or working surface geometries along a blade profile of the at least one blade.', 'In another aspect, embodiments of the present disclosure relate to a downhole cutting tool that includes a tool body having a tool axis, at least one blade extending from the tool body, the at least one blade having a cutting face, a trailing face and a top face extending between the cutting face and trailing face, a plurality of cutting elements attached to the at least one blade along the cutting face, a working surface of each of the plurality of cutting elements having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest.', 'A first of the plurality of cutting elements closer to the tool axis than a second of the plurality of cutting elements has a greater impact resistance than the second of the plurality of cutting elements.', 'In yet another aspect, embodiments of the present disclosure relate to a downhole cutting tool that includes a tool body having a tool axis, at least one blade extending from the tool body, the at least one blade having a cutting face, a trailing face and a top face extending between the cutting face and trailing face, a plurality of cutting elements attached to the at least one blade along the cutting face, a working surface of each of the plurality of cutting elements having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest, a first of the plurality of cutting elements further from the tool axis than a second of the plurality of cutting elements has a greater wear resistance than the second of the plurality of cutting elements.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nEmbodiments of the present disclosure are described with reference to the following figures.', 'Like numbers are used throughout the figures to reference like features and components.\n \nFIG.', '1\n shows a conventional drag bit.\n \nFIG.', '2\n shows a conventional cutting element.', 'FIGS.', '3 and 4\n show a cutting element having a non-planar top surface according to embodiments of the present disclosure.', 'FIG.', '5\n shows a perspective view of the cutting element shown in \nFIG.', '3\n.', 'FIGS.', '6 and 7\n show a cross-sectional view of a cutting element top surface according to embodiments of the present disclosure.', 'FIGS.', '8 and 9\n show a cutting element having a non-planar top surface according to embodiments of the present disclosure.\n \nFIG.', '10\n is a partial cross-sectional view of a bit with the cutting elements of the bit shown rotated into a single profile.', 'FIG.', '11\n shows a profile view of a drill bit according to embodiments of the present disclosure.\n \nFIG.', '12\n shows a cutting profile according to embodiments of the present disclosure.\n \nFIGS.', '13 and 14\n show rotation of cutting elements according to embodiments of the present disclosure.', 'FIGS.', '15, 16, and 17\n show a cutting profile according to embodiments of the present disclosure.\n \nFIG.', '18\n shows a geometry of a cutting element according to embodiments of the present disclosure.\n \nFIGS.', '19 and 20\n show a perspective view of a drill bit according to embodiments of the present disclosure.', 'FIGS.', '21-26\n show cutting profiles according to embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'In one aspect, embodiments of the present disclosure relate to cutting structure design using non-planar cutting elements.', 'Specifically, embodiments disclosed herein relate to improving the life and performance of a downhole cutting tool by positioning non-planar cutting elements in particular arrangements on the cutting tool.', 'An upper or top surface of the ultrahard layer (opposite the substrate on which the ultrahard layer is disposed), is non-planar.', 'Cutting elements of the present disclosure may be mounted to various types of downhole cutting tools, including but not limited to drill bits, such as drag bits, reamers, and other downhole milling tools.', 'Cutting elements of the present disclosure may optionally have a non-planar interface formed between a substrate and an ultrahard layer, where the top surface of the ultrahard layer is non-planar.', 'For example, according to embodiments of the present disclosure, a cutting element may include a substrate, an upper surface of the substrate including a cutting crest extending along at least a majority of a diameter of the substrate, the upper surface transitioning from the crest into a depressed region, and an ultrahard layer disposed on the substrate upper surface, thereby forming a non-planar interface between the ultrahard layer and the substrate.', 'Cutting elements having a non-planar top or working surface may include, for example, a substantially hyperbolic paraboloid (saddle) shape or a parabolic cylinder shape, where the crest or apex of the cutting element extends across substantially the entire diameter of the cutting element.', 'Further, interface surfaces may also include generally hyperbolic paraboloid shapes, as well as generally parabolic cylinder shapes.', 'For example, as it will be discussed later, cutting elements of the present disclosure may have a working surface that has a cutting crest \n312\n and \n512\n, as seen in \nFIGS.', '3, 4 and 8\n, at a peak height and a reduced height extending laterally away from the cutting crest.', 'In some embodiments, the cutting crest may not extend the entire diameter of the substrate.\n \nPlacement of Non-Planar Cutting Elements\n \nAccording to embodiments of the present disclosure, a cutting structure design consideration may include placement of a plurality of non-planar cutting elements on a downhole cutting tool.', 'The cutting tool includes a tool body having a tool axis and at least one blade extending from the tool body.', 'In particular, each blade extending from the tool body includes a cutting face, a trailing face, and a top face that extends between the cutting face and the trailing face.', 'In one or more embodiments, a plurality of cutting elements is attached along the cutting face and top face of at least one blade of the tool.', 'In various embodiments, other configurations may be used.', 'As it will be described later, at least two of the plurality of cutting elements mounted on at least one blade of the tool have different material properties, sizes, orientations, and/or working surface geometries, which may be along a blade profile in one or more embodiments, or between cutting elements mounted along the cutting face compared to the top face in one or more embodiments.', 'Referring now to \nFIG.', '10\n, a profile of bit \n10\n is shown as it would appear with the blades and the cutting elements rotated into a single rotated profile.', 'Bit \n10\n includes a central axis \n60\n about which bit \n10\n rotates in the cutting direction represented by arrow \n18\n.', 'In rotated profile, the plurality of blades of bit \n10\n (e.g., primary blades \n31\n-\n33\n and secondary blades \n34\n-\n36\n as shown in \nFIG.', '11\n) include blade profiles \n39\n.', 'Blade profiles \n39\n and bit face may be divided into three different regions labeled cone region \n24\n, shoulder region \n25\n, and gage region \n26\n.', 'Cone region \n24\n is concave in this embodiment and comprises the inner most region of bit \n10\n (e.g., cone region \n24\n is the central most region of bit \n10\n).', 'Adjacent cone region \n24\n is shoulder (or the upturned curve) region \n25\n.', 'In this embodiment, shoulder region \n25\n is generally convex.', 'The transition between cone region \n24\n and shoulder region \n25\n, typically referred to as the nose or nose region \n27\n, occurs at the axially outermost portion of composite blade profile \n39\n where a tangent line to the blade profile \n39\n has a slope of zero.', 'Moving radially outward, adjacent shoulder region \n25\n is gage region \n26\n, which extends substantially parallel to bit axis \n60\n at the radially outer periphery of composite blade profile \n39\n.', 'As shown in composite blade profile \n39\n, gage pads \n51\n define the outer radius \n23\n of bit \n10\n.', 'In this embodiment, outer radius \n23\n extends to and therefore defines the full gage diameter of bit \n10\n.', 'As used herein, the term “full gage diameter” refers to the outer diameter of the bit defined by the radially outermost reaches of the cutter elements and surfaces of the bit.', 'Referring still to \nFIG.', '10\n, cone region \n24\n is defined by a radial distance along the x-axis measured from central axis \n60\n.', 'It is to be understood that the x-axis is perpendicular to central axis \n60\n and extends radially outward from central axis \n60\n.', 'Cone region \n24\n may be defined by a percentage of outer radius \n23\n of bit \n10\n.', 'In some embodiments, cone region \n24\n extends from central axis \n60\n to no more than 50% of outer radius \n23\n.', 'In some embodiments, cone region \n24\n extends from central axis \n60\n to no more than 30% of outer radius \n23\n.', 'Cone region \n24\n may likewise be defined by the location of one or more secondary blades (e.g., secondary blades \n34\n-\n36\n as shown in \nFIG.', '11\n).', 'For example, cone region \n24\n extends from central axis \n60\n to a distance at which a secondary blade begins (e.g., distance “D” as illustrated in \nFIG.', '11\n).', 'In other words, the outer boundary of cone region \n24\n may coincide with the distance “D” at which one or more secondary blades begin.', 'The actual radius of cone region \n24\n, measured from central axis \n60\n, may vary from bit to bit depending on a variety of factors including without limitation, bit geometry, bit type, location of one or more secondary blades (e.g., secondary blades \n34\n-\n36\n), or combinations thereof.', 'For instance, in some cases bit \n10\n may have a relatively flat parabolic profile resulting in a cone region \n24\n that is relatively large (e.g., 50% of outer radius \n23\n).', 'However, in other cases, bit \n10\n may have a relatively long parabolic profile resulting in a relatively smaller cone region \n24\n (e.g., 30% of outer radius \n23\n).', 'Referring now to \nFIG.', '11\n, a schematic top view of bit \n10\n is illustrated.', 'Moving radially outward from bit axis \n60\n, the bit face includes cone region \n24\n, shoulder region \n25\n, and gage region \n26\n as previously described.', 'Nose region \n27\n generally represents the transition between cone region \n24\n and shoulder region \n25\n.', 'Specifically, cone region \n24\n extends radially from bit axis \n60\n to a cone radius, shoulder region \n25\n extends radially from cone radius to shoulder radius, and gage region \n26\n extends radially from shoulder radius to bit outer radius \n23\n.', 'Primary blades \n31\n-\n33\n extend radially along bit face from within cone region \n24\n proximal bit axis \n60\n toward gage region \n26\n and outer radius \n23\n.', 'Secondary blades \n34\n-\n36\n extend radially along bit face from proximal nose region \n27\n toward gage region \n26\n and outer radius \n23\n.', 'In this embodiment, each secondary blade \n34\n-\n36\n begins at a distance “D” that substantially coincides with the outer radius of cone region \n24\n (e.g., the intersection of cone region \n24\n and shoulder region \n25\n).', 'Thus, secondary blades \n34\n-\n36\n do not extend into cone region \n24\n.', 'In other embodiments, the secondary blades (e.g., secondary blades \n34\n-\n36\n) may extend to and/or slightly into the cone region (e.g., cone region \n24\n).', 'In this embodiment, each primary blade \n31\n-\n33\n and each secondary blade \n34\n-\n36\n extends substantially to gage region \n26\n and outer radius \n23\n.', 'However, in other embodiments, one or more primary and/or secondary blades may not extend completely to the gage region or outer radius of the bit.', 'Referring still to \nFIG.', '11\n, each primary blade \n31\n-\n33\n and each secondary blade \n34\n-\n36\n generally tapers (e.g., becomes thinner) in top view as it extends radially inwards towards central axis \n60\n.', 'Consequently, primary blades \n31\n-\n33\n are relatively thin proximal axis \n60\n where space is generally limited circumferentially, and widen towards gage region \n26\n.', 'Although primary blades \n31\n-\n33\n and secondary blades \n34\n-\n36\n extend linearly in the radial direction in top view, in other embodiments, one or more of the primary blades, one or more secondary blades, or combinations thereof may be arcuate or curve along their length in top view.', 'Primary blades \n31\n-\n33\n and secondary blades \n34\n-\n36\n provide cutting-supporting surfaces \n42\n and \n52\n, respectively, for mounting a plurality of cutting elements \n40\n.', 'The number of cutting elements on each primary blade (e.g., primary blades \n31\n-\n33\n) and each secondary blade (e.g., secondary blades \n34\n-\n36\n) may vary or may be equal.', 'The plurality of the cutting elements may be placed along the blade on a cone region, a nose region, a shoulder region and/or a gage region of at least one blade of the tool.', 'As mentioned above, in one or more embodiments, the cutting elements on a given blade may have differing material properties, sizes, orientations, and/or working surface geometries.', 'In one or more embodiments, the difference may be between cutting elements in different regions of the blade profile, such as between cutting elements in the cone, nose, shoulder, and gage regions of the blade.', 'Referring now to \nFIG.', '12\n, a cutting element layout for an example blade (now shown) is provided.', 'The cutting element layout includes a plurality of cutting elements \n279\n forming the primary row of cutting elements, and a plurality of cutting elements \n280\n forming the secondary or back-up row of cutting elements.', 'Additional discussion concerning the back-up row of cutting elements \n280\n is provided later.', 'The cutting elements \n279\n forming the primary row extend, in this embodiment, through a cone region \n24\n, nose region \n27\n, shoulder region \n25\n, and gage region \n26\n.', 'As shown, the cutting elements \n279\n forming the primary row may not have the same size.', 'For example, at least one of the plurality of cutting elements \n279\n placed on the cone \n24\n region of the blade may be larger in size than at least one of the plurality of cutting elements \n279\n placed on the nose \n27\n and/or shoulder \n25\n regions of the blade.', 'Similarly, as shown in \nFIG.', '12\n, at least one of the plurality of cutting elements placed on the gage region \n26\n of the blade may be larger than at least one of the plurality of cutting elements placed on the nose \n27\n and/or shoulder \n25\n regions of the blade.', 'In this embodiment, the cutting elements \n279\n placed in the cone \n24\n and gage \n26\n regions may have the same size and the cutting elements \n279\n placed on the nose and/or shoulder of the blade may have the same size.', 'However, different permutations of cutting element sizes may be used (for example, cone and/or gage cutting elements may be smaller than cutting elements in other regions), and that cutting elements within a given region of the blade profile may have different sizes (such as cutting elements within the nose region may also have two or more different sizes and cutting elements within the shoulder may also have two or more different sizes).', 'Further, the differences in size along the blade profile may be between cutting elements on any row.', 'Thus, the placement of cutting elements with different sizes within a given region of the blade profile may reduce or minimize harmful loads and stresses on the cutting elements during drilling.', 'For example, if high loads are expected in a given region of the profile, smaller cutting elements can be used, while larger, more efficient cutting elements can be used in other regions of the profile.', 'As noted above, cutting elements along the blade profile may have different orientations relative to one another.', 'Such orientations may refer, for example, to back rake, side rake, as well as rotational orientation within a cutter pocket.', 'Further, because the cutting elements of the present disclosure are non-planar cutting elements (and thus do not have a planar cutting face which is conventionally used to define rake angles), the conventional definitions for rake angle do not apply.', 'The orientational definitions may instead be described based, in part, on a particular feature of the non-planar working surface.', 'While greater description of the cutting element geometry may be found below, as noted above, the top or working surface of the ultrahard layer has at least one cutting crest that extends along a diameter from a cutting edge portion radially inward (such as from one edge to another).', 'The cutting crest may, for example, be used to define the orientation of a cutting element on a blade.', 'For example, while back rake is conventionally defined as the angle between the cutting face and a line normal to the formation being cut, for the cutting elements of the present disclosure, the effective back rake may be defined as the angle α formed between a line extending through the radial ends of the cutting crest \n312\n and a line normal to the formation \n380\n being cut (or substantially parallel to the tool axis), as shown in \nFIG.', '13\n.', 'In one or more embodiments, the back rake angle α may range from greater than 0 degrees to 45 degrees (or at least 5, 10, 15, 20, 25, 30, 35, or 40 degrees in various other embodiments).', 'Such back rake angles are negative in the context of the conventional PDC cutters because the angle extends clockwise from the normal line (in contrast to a positive back rake angle where the angle extends in a counter clockwise orientation relative to the normal line).', 'That is, a zero back rake angle for a conventional PDC cutter (and for the cutters of the present disclosure) is formed by the cutting face (or the line extending through the radial ends of the cutting crest) and a line that is parallel to or collinear with the line normal to the formation.', 'A negative angle is formed when the cutting element is tilted so that the cutting face (or cutting crest) angles in a clockwise direction relative to the normal line and a positive angle is formed when the cutting element is tilted so that a cutting face (or cutting crest) angles in a counter clockwise orientation relative to the normal line.', 'However, as shown in \nFIG.', '13\n, cutting elements \n40\n may be oriented substantially perpendicular to the blade top.', 'While this orientation is atypical for conventional PDC cutters, a perpendicular or 90° angle is formed by tilting the cutting element in a clockwise rotation by 90° relative to the normal line.', 'Because the orientation is still in the clockwise direction, this backrake angle is also considered to be negative.', 'However, in one or more embodiments, the cutting element \n40\n may also be oriented at a back rake angle α (formed between a line parallel to the tool axis and a line extending through the radial ends of the cutting crest) ranging from greater than 65 degrees to 115 degrees (or at least 65, 75, 80, 85, 90, 95, 100, 105, 110 degrees in various other embodiments).', 'While embodiments may generally use negative back rake angles, the cutting crest could be orientated a non-perpendicular angle with respect to the central axis of the cutting element, in which case a positive back rake (when an angle between the line extending through the radial ends of the cutting crest and a line normal to the formation extends in a counter clockwise direction) could be used.', 'When selecting different back rake angles for cutting elements placed in various regions of the blade profile, the selection may depend, for example, on where aggressive or passive cutting action is desired.', 'Thus, in some embodiments, the cutting elements of the present disclosure may be placed on the blade at various back rake angles, such as a positive, a neutral or a negative back rake angle.', 'However, all cutting elements may be placed on a blade at a negative back rake angle, and, for example, at least two cutting elements have differing negative back rake angles.', 'For example, such difference in back rake angle may be between at least two cutting elements along a blade profile, such as between cutting elements in different regions of the blade profile.', 'As seen in \nFIG.', '16\n, a plurality of cutting elements \n279\n form a first row and extend through a cone \n24\n, nose \n27\n, shoulder \n25\n, and gage \n26\n.', 'At least one of the plurality of cutting elements \n279\n placed on the nose \n27\n and/or the shoulder \n25\n may have smaller back rake angles than at least one of the plurality of cutting elements placed on the cone \n24\n and/or gage \n26\n regions.', 'Such a configuration may provide impact protection of the cutting tool.', 'However, other configurations are possible, depending on the applications of the cutting tool.', 'Further, in addition to differing back rake angles, the cutting elements \n279\n placed in the nose \n27\n and/or shoulder \n25\n may be smaller than those in the cone \n24\n and/or gage \n26\n.', 'In this embodiment, the cutting elements \n279\n placed in the cone \n24\n and gage \n26\n regions may have the same size and the cutting elements \n279\n placed on the nose and/or shoulder of the blade have the same size.', 'However, different permutations of cutting element back rake angles may be used (for example, cone and/or gage cutting elements may have smaller back rake angles than cutting elements in other regions), and that cutting elements within a given region of the blade profile may have different back rake angles (such as cutting elements within the nose region may also have two or more different back rake angles and cutting elements within the shoulder may also have two or more different back rake angles).', 'Further, the differences in back rake angles along the blade profile may be between cutting elements on any row.', 'Configurations with variable back rake angles and/or sizes of cutting elements placed in different regions of the blade profile may provide for increased aggressiveness of the cutting tool and/or increased longevity of the cutting tool.', 'In addition to different back rake angles, cutting elements \n40\n may also have different side rake angles along a blade profile.', 'Side rake may be defined as the angle β formed between a radial plane that is tangent to the peak of the cutting crest \n312\n and the radial plane of the tool (x-z plane).', 'When viewed along the z-axis, shown in \nFIG.', '14\n, a negative side rake β results from counterclockwise rotation of the cutting element, and a positive side rake β, from clockwise rotation.', 'In one or more embodiments, at least two cutting elements along a blade profile may have opposite side rake angle directions (positive versus negative) or a positive or neutral side rake angle on one cutting element and a neutral side rake angle on another.', 'In other embodiments, the angle itself may be varied.', 'The angles may range from −30 to 30 degrees, −20 to 20 degrees, or −10 to 10 degrees.', 'In addition to the back rake and side rake angles, the aggressiveness of cutting tools may be tailored by varying the rotational orientation of a cutting element within a cutter pocket (defined relative to a cutting profile curve formed from the cutting elements on a given row) along a blade profile.', 'Specifically, as shown in \nFIG.', '15\n, a cutting profile curve \n502\n may be the curve formed by extending tangent to each of the cutting elements \n40\n on a given row.', 'The rotational orientation w of a cutting element may be defined as the angle formed between a line normal to the cutting profile curve \n502\n and the line extending through the radial ends of the cutting crest \n312\n.', 'A clockwise rotation (shown on the cutting element on the right) may be a positive rotational orientation and a counter clockwise rotation (shown on the cutting element on the left) may be a negative rotational orientation.', 'In one or more embodiments, the rotational orientation may range from 0 to 90 degrees or up to 45, 40, 35, 30, 25, or 20 degrees in various embodiments.', 'Further, at least two rotational orientations may be used between at least two cutting elements having differential positions along the blade profile.', 'For example, such different rotational orientations may be between cutting elements within different regions or portions of the blade profile or the different orientations may be within a single region of the blade profile (such as cutting elements within the nose region may also have two or more different angles and cutting elements within the shoulder may also have two or more different angles).', 'In addition to the back rake and side rake angle affecting the aggressiveness of the non planar cutting element formation interaction, the cutting end geometry, specifically, the included angle of the working surface formed by the non-planar diamond table of the cutting elements, the radius of curvature at the crest, as well as the shape of the ridge (e.g., planar or radiused) may also affect the aggressiveness of which a non planar cutting element interacts with the formation.', 'As shown in \nFIG.', '4\n, the cutting crest \n312\n of a non-planar cutting element of the present disclosure has a convex cross-sectional shape (viewed along a plane perpendicular to cutting crest length across the diameter of the ultrahard layer), where the uppermost point of the crest has a radius of curvature \n313\n that transitions to opposite side surfaces at an angle \n311\n called the included angle of the working surface.', 'According to some of the present embodiments, the included angle of the working surface of at least one of the plurality of cutting elements mounted along at least one blade may range from about 100° degrees to less than about 180° or to about 175° in some embodiments, e.g., from 100° to 175°.', 'Further, in one or more embodiments, at least two cutting elements along a blade profile may have a different included angle from one another.', 'For example, the included angle of a first cutting element may be equal or larger than the included angle of a second cutting element.', 'In some embodiments, the included angle of the working surface of at least one of the plurality of cutting elements placed on the cone region \n24\n may be larger than an included angle of the working surface of at least one of the plurality of cutting elements placed on the nose \n27\n and/or shoulder \n25\n regions of the blade.', 'For example, in one or more embodiments, cutting elements in the cone region may have included angles between 130 (or 150) and 175 degrees, whereas cutting elements radially outside the cone region (in the nose, shoulder, and/or gage) may have included angles of less than 130 degrees.', 'In some embodiments, there may be a continuous decrease in the included angle moving radially outward, while other embodiments may have clusters of cutting elements at a particle angle.', 'By placing sharper cutting elements (i.e., having a smaller included angle) in the areas of the bit experiencing the greatest wear, for example the shoulder region \n27\n of the bit, the wear rate of the bit may be improved.', 'Referring now to \nFIG.', '17\n, \nFIG.', '17\n shows a cutting profile according to one embodiment.', 'As seen in \nFIG.', '17\n, cutting elements placed on the cone region \n24\n may have included angles bigger than cutting elements placed on the nose region \n27\n and shoulder region \n25\n.', 'Referring now to \nFIG.', '18\n, \nFIG.', '18\n shows a cross-sectional view of a cutting element of the present disclosure indicating the included angle \n1810\n of the working surface, the radius of curvature \n1820\n at the crest, as well as the diamond table thickness \n1830\n.', 'Cutting elements placed along the blade may have different radii of curvature at the crest.', 'For example, the radius of curvature at the crest may range from 0.02 in.', '(0.51 mm) to 0.300 in.', '(7.62 mm), or in another embodiment, from 0.06 in.', '(1.52 mm) to 0.18 in.', '(4.57 mm).', 'In one embodiment, the radius of curvature at the crest of at least a cutting element placed on the cone region of the tool body may be smaller than a radius of curvature at the crest of the another cutting element placed on the nose and/or the shoulder regions of the tool body.', 'Cutting elements with equal or different full radius top may be used.', 'The cutting elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond material.', 'In the typical fixed cutter bit, each cutting element or assembly comprises an elongated and generally cylindrical support member which is received and secured in a mating pocket formed in the surface of one of the several blades.', 'A cutting element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate), as well as mixtures or combinations of these materials.', 'The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide, often forming a polycrystalline diamond compact (PDC).', 'For convenience, as used herein, reference to “PDC bit” or “PDC cutting element” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.', 'According to the present disclosure, the plurality of the cutting elements have a diamond table that may be formed on the substrate, or may be separately formed and subsequently attached together.', 'Depending on the location of the cutting element on the tool and the properties of the cutting element (wear versus impact resistance), different grades of polycrystalline diamond may be used.', 'According to various embodiments, the diamond table may be formed from materials having different particle sizes but same binder content, same particle sizes but different binder content, or different particle sizes and different binder content.', 'For example, average diamond grain sizes may be within the range of about 1 micron to about 40 microns, where the lower limit can be any of 1 micron, 2 microns, or 3 microns and the upper limit can be any of 25 microns, 30 microns or 40 microns, where any lower limit can be used with any upper limit.', 'In such embodiment, the binder content may range from about 1% to about 15% by weight, where the lower limit can be any of 1%, 2%, or 5% and the upper limit can be any of 10%, 12% or 15%, where any lower limit can be used with any upper limit.', 'Multi-layers of diamond may be used.', 'When greater wear resistance is desired, a smaller particle size may be used (e.g., an average grain size of 1-2 microns as compared to 30-40 microns for another location), and when greater impact resistance is desired, a greater binder content (e.g., 10-15% by weight based on the total weight of at least a portion of the diamond layer as compared to a content of 1-2% by weight based on the total weight of at least a portion of the diamond layer in another location) may be used or a larger grain size (such as 30-40 microns as compared to a smaller size) may be used.', 'According to various embodiments, one of the plurality of cutting elements closer to the tool axis than a second of the plurality of cutting elements has a greater impact resistance (e.g., greater binder content) than the second of the plurality of cutting elements or vice versa.', 'In one or more embodiments, a first of the plurality of cutting elements further from the tool axis than a second of the plurality of cutting elements has a greater wear resistance (e.g., smaller particle size) than the second of the plurality of cutting elements or vice versa.', 'While the above embodiments describe use of non-planar cutting elements having differing material properties, sizes, orientations, and/or working surface geometries along a blade profile, the present disclosure is not so limited.', 'Rather, embodiments may also relate to multiple non-planar cutting elements positioned in a leading and trailing relationship on a given blade.', 'For example, according to various embodiments, a first plurality of cutting elements may be attached adjacent one another generally in a first row extending radially along at least one blade of the cutting tool, such as along the cutting face of at least one blade (specifically at the intersection of the cutting face (or front face) and the top face).', 'Further, a second plurality of cutting elements may be attached on the same blade, adjacent one another generally in a second row extending along the top face of the blade, rearward from the first plurality of cutting elements.', 'The first row (along the cutting face) may often be referred to as the leading or primary row of cutting elements, and the second row (along the top face, rearward from the first row) may be referred to as the secondary, back-up, or trailing row of cutting elements.', 'In one or more embodiments, the second plurality of cutting elements may be placed rearward from and at the same radial position from the tool axis as the cutting elements placed along the cutting face of the blade.', 'The second plurality of cutting elements may be placed rearward from and radially between the first plurality of cutting elements.', 'According to some of the present embodiments, the number of the first and second plurality of cutting elements placed along the blade may vary.', 'According to the present embodiments, at least one cutting element from the first row placed on the cutting face and at least one cutting element from the second row placed on the top face of at least one blade may have different material properties, sizes, orientations, and/or working surface geometries.', 'Referring now to \nFIGS.', '19 and 20\n, \nFIGS.', '19 and 20\n show partial views of a bit according to embodiments of the present disclosure.', 'The bit \n260\n generally includes a bit body \n261\n, a shank \n262\n and a threaded connection or pin for connecting bit \n260\n to a drill string, which is employed to rotate the bit in order to drill the borehole.', 'Bit face \n263\n supports a cutting structure \n264\n and is formed on the end of the bit \n260\n that is opposite to pin end.', 'Bit \n260\n further includes a central axis \n265\n about which bit \n260\n rotates in the cutting direction represented by arrow \n266\n.', 'As used herein, the terms “axial” and “axially” generally mean along or parallel to the bit axis (e.g., bit axis \n265\n), while the terms “radial” and “radially” generally mean perpendicular to the bit axis.', 'For instance, an axial distance refers to a distance measured along or parallel to the bit axis, and a radial distance refers to a distance measured perpendicularly from the bit axis.', 'Body \n261\n may be formed in a conventional manner using powdered metal tungsten carbide particles in a binder material to form a hard metal cast matrix.', 'The body can also be machined from a metal block, such as steel, rather than being formed from a matrix.', 'The cutting structure \n264\n is provided on face \n263\n of bit \n260\n.', 'Cutting structure \n264\n includes a plurality of blades which extend from bit face \n263\n.', 'In the embodiment illustrated in \nFIGS.', '19 and 20\n, cutting structure \n264\n includes three primary blades \n267\n-\n269\n circumferentially spaced-apart about bit axis \n265\n, and three secondary blades \n270\n-\n272\n circumferentially spaced-apart about bit axis \n265\n.', 'In this embodiment, the plurality of blades (e.g., primary blades \n267\n-\n269\n and secondary blades \n270\n-\n272\n) are uniformly angularly spaced on bit face \n263\n about bit axis \n265\n.', 'In particular, each blade \n267\n-\n272\n is generally being spaced about 60° from its adjacent blades \n267\n-\n272\n.', 'In other embodiments (not specifically illustrated), the blades may be spaced non-uniformly about the bit face.', 'Moreover, although bit \n260\n is shown as having three primary blades \n267\n-\n269\n and three secondary blades \n270\n-\n272\n, in general, bit \n260\n may comprise any suitable number of primary and secondary blades.', 'Still referring to \nFIGS.', '19 and 20\n, primary blades \n267\n-\n269\n and secondary blades \n270\n-\n272\n are integrally formed as part of, and extend from, bit body \n261\n and bit face \n263\n.', 'Primary blades \n267\n-\n269\n and secondary blades \n270\n-\n272\n extend radially across bit face \n263\n and longitudinally along a portion of the periphery of bit \n260\n.', 'Primary blades \n267\n-\n269\n extend radially from substantially proximal central axis \n265\n toward the periphery of bit \n260\n.', 'Thus, as used herein, the term “primary blade” refers to a blade that begins proximal the bit axis and extends generally radially outward along the bit face to the periphery of the bit.', 'However, secondary blades \n270\n-\n272\n do not extend from substantially proximal central axis \n265\n.', 'Rather, secondary blades \n270\n-\n272\n extend radially from a location that is away from central axis \n265\n toward the periphery of bit \n260\n.', 'Hence, primary blades \n267\n-\n269\n extend closer to central axis \n265\n than secondary blades \n270\n-\n272\n.', 'Thus, as used herein, the term “secondary blade” refers to a blade that begins at some distance from the bit axis and extends generally radially along the bit face to the periphery of the bit.', 'As shown in \nFIGS.', '19 and 20', ', each primary blade \n267\n-\n269\n has a cutting face \n273\n that faces in the direction of bit rotation, a trailing face \n274\n opposite the cutting face \n273\n, and a top face \n275\n, extending between the cutting face \n273\n and the trailing face \n274\n.', 'Similarly, each secondary blade \n270\n-\n272\n has a cutting face \n276\n, a trailing face \n278\n, and a top face \n277\n.', 'According to various embodiments, each primary and/or secondary blade includes a first and a second plurality of cutting elements mounted thereon.', 'For example, \nFIG.', '20\n shows the secondary blade \n271\n of bit \n260\n.', 'A first plurality (or first row) of non-planar cutting elements \n279\n is placed along the cutting face \n276\n of blade \n271\n.', 'The bit \n260\n further includes a second plurality (or second row) of non-planar cutting elements \n280\n disposed along the top face \n277\n of the blade \n271\n, rearward from the first plurality \n279\n.', 'In other words, the first plurality \n279\n of cutting elements may be disposed along the blade \n271\n at the cutting face \n276\n, while the second plurality \n280\n of cutting elements is disposed along the top face \n277\n of the blade \n271\n in a position that is distal from the cutting face \n276\n.', 'As exemplified in \nFIG.', '20\n, the second plurality \n280\n of cutting elements is placed rearward from and at the same radial position from the tool axis \n265\n as the first plurality \n279\n of cutting elements.', 'Still referring to \nFIG.', '20\n, the relative position of the first plurality of cutting elements \n279\n and the second plurality of cutting elements \n280\n along the blade \n271\n may be described in terms of leading-trailing perspective.', 'Specifically, as seen in \nFIG.', '20\n, the second plurality of cutting elements \n280\n is positioned rearward of the first plurality of cutting elements \n279\n, such that one or more cutting elements of the first plurality of cutting elements \n279\n shares a radial position with one or more cutting elements of the second plurality of cutting elements \n280\n.', 'Cutting elements sharing the same radial position on a blade are positioned at the same radial distance from the central or longitudinal axis \n265\n of the bit, such that as the bit rotates, the cutting elements cut along the same radial path.', 'A cutting element of the second plurality of cutting elements \n280\n and a cutting element of the first plurality of cutting elements \n279\n sharing a same radial position may be referred to as a back-up cutting element and a primary (or leading) cutting element, respectively.', 'In other words, as used herein, the term “back-up cutting element” is used to describe a cutting element that trails any other cutting element on the same blade when the bit is rotated in the cutting direction, and the term “primary (or leading) cutting element” is used to describe a cutting element provided on the leading edge of a blade.', 'Thus, when a bit is rotated about its central axis in the cutting direction, a “primary cutting element” does not trail any other cutting elements on the same blade.', 'Other cutting elements of the second plurality of cutting elements \n280\n may partially overlap the radial position of cutting elements of the first plurality of cutting elements \n279\n, or may be positioned in a radially adjacent position to cutting elements in the first row (i.e., where a cutting element in the second row is positioned rearward of a cutting element in the first row and do not share a radial position along the bit blade).', 'The placement of cutting elements in two different rows, such as, for example, \n279\n and \n280\n (as seen in \nFIG.', '20\n), may improve the lifetime of the cutting tool, as the cutting elements may be exposed to different loads and stresses.', 'Referring again to \nFIGS.', '19 and 20\n, leading cutting elements \n279\n are positioned adjacent one another generally in a first row extending radially along each blade \n267\n-\n272\n.', 'Further, back-up cutting elements \n280\n are positioned adjacent one another generally in a second row extending radially along each blade \n267\n-\n272\n.', 'Back-up cutting elements \n280\n are positioned behind the leading cutting elements \n279\n provided on the same blade (e.g., secondary blade \n271\n).', 'As seen in \nFIGS.', '19 and 20\n, when bit \n260\n rotates about central axis \n265\n in the cutting direction represented by arrow \n266\n, back-up cutting elements \n280\n trail the leading cutting elements \n279\n provided on the same blade \n271\n.', 'This is schematically shown in \nFIG.', '21\n.', 'However, as noted above, the back-up cutting elements \n280\n may be non-trailing when they are placed rearward from and radially between the leading cutting elements \n279\n, as shown in \nFIG.', '22\n.', 'In such an embodiment, greater cutting tip engagement may be expected if the back-up cutting elements are on profile.', 'This configuration may be beneficial to the overall rock breaking efficiency.', 'As used herein, the terms “leads,” “leading,” “trails,” and “trailing” are used to describe the relative positions of two structures (e.g., two cutting elements) on the same blade relative to the direction of bit rotation.', 'In particular, a first structure that is disposed ahead or in front of a second structure on the same blade relative to the direction of bit rotation “leads” the second structure (i.e., the first structure is in a “leading” position), whereas the second structure that is disposed behind the first structure on the same blade relative to the direction of bit rotation “trails” the first structure (i.e., the second structure is in a “trailing” position).', 'In general, primary (or leading) cutting elements \n279\n and back-up cutting elements \n280\n need not be positioned in rows, but may be mounted in other suitable arrangements provided each cutting element is either in a leading position (e.g., primary cutter element \n279\n) or trailing position (e.g., back-up cutter element \n280\n).', 'Examples of suitable arrangements may include without limitation, rows, arrays or organized patterns, randomly, sinusoidal pattern, or combinations thereof.', 'Further, in other embodiments, additional rows of cutter elements may be provided on a primary blade, secondary blade, or combinations thereof.', 'Referring again to \nFIGS.', '19 and 20\n, leading and back-up cutting elements \n279\n and \n280\n, respectively, may be disposed within the cone, shoulder, nose and/or gage regions of at least one blade of the cutting tool.', 'In various embodiments, primary cutting elements \n279\n may be placed along the entire length of at least a blade of a tool.', 'In yet another embodiment, the back-up cutting elements \n280\n may be placed on the same blade, rearward from the primary cutting elements \n279\n, within the nose and shoulder of at least one blade (e.g., blade \n271\n).', 'The general concept of “off and on profile” will be described using cutting elements \n2300\n and \n2320\n, as shown in the cross-sectional views of \nFIGS.', '23 and 24\n.', 'The cutting edge \n2310\n of cutting element \n2300\n lies on a primary cutting profile.', 'As used herein, the primary cutting profile refers to the curve or profile passing through the edge of each cutting crest of the cutting elements (such as cutting element \n2300\n) placed on a cutting face (e.g., cutting face \n273\n as shown in \nFIG.', '19\n) of a blade (e.g., blade \n267\n as shown in \nFIG.', '19\n).', 'A back-up cutting profile refers to the curve or profile passing through the edge of each cutting crest of the cutting elements forming the secondary or back-up row of cutting elements (such as cutting element \n282\n having an edge \n283\n) placed on a top face (e.g. top face \n275\n as shown in \nFIG.', '19\n) of a blade (e.g., blade \n267\n as shown in \nFIG.', '19\n).', 'Referring now to \nFIG.', '23\n, the cutting edge \n2330\n (and thus back-up profile) of the second cutting element \n2320\n may not extend to (i.e., is axially separated or offset from) the primary cutting profile defined by the cutting edge \n2310\n of the cutting element \n2300\n, and thus, may be described as being offset, “off profile” or “under profile” relative to the primary cutting profile.', 'As used herein, the phrase “off profile” refers to a cutting element extending from a cutting face (e.g., cutting face \n273\n as shown in \nFIG.', '19\n) of a blade (e.g., blade \n267\n as shown in \nFIG.', '19\n) that does not extend to the primary cutting profile in rotated profile view.', 'In such a case, the first plurality of cutting elements may be arranged in such a manner that they are over-exposed to the formation with respect to the second plurality of cutting elements.', 'Similarly, the phrase “on profile” refers to the structure that extends from the cutting face to the primary cutting profile in rotated profile view, when both pluralities of cutting elements engage the formation at the same point, or depth of cut, as shown in \nFIG.', '24\n.', 'The degree to which an off-profile cutting element is offset from the outermost cutting profile may be described in terms of a “cutting profile offset distance” or “exposure height,” h, equal to the minimum or shortest distance between the structure and the primary cutting profile in rotated profile view, as shown in \nFIG.', '23\n.', 'The selection of the exposure height difference may be based, for example, on the type of formation to be drilled.', 'Further, the exposure difference may allow for improving the efficiency of drilling in transition between different formation types.', 'If a leading cutting element has a greater exposure height (for drilling through a softer formation), it may dull when a different formation type is hit and the dulling of the cutting element may allow for engagement of the back-up cutting element.', 'In various embodiments, the cutting profile offset distance h ranges from 0.010 in.', '(0.254 mm) to 0.100 in.', '(2.54 mm), where the limits can be any of 0.015 in.', '(0.381 mm), 0.020 in.', '(0.508 mm), 0.070 in.', '(1.778 mm), 0.090 in.', '(2.286 mm), or 0.100 in.', '(2.54 mm), where any limit can be used in combination with any other limit.', 'Although the cutting profile of cutting element \n2320\n is off-profile in this embodiment, in other embodiments, one or more of the second cutting elements (e.g. cutting element \n2320\n) may be on-profile, as shown in \nFIG.', '24\n.', 'Referring again to \nFIG.', '20\n, each cutting element of the first plurality \n279\n of cutting elements and each cutting element of the second plurality of cutting elements \n280\n may have any suitable size and geometry.', 'According to various embodiments, the plurality of cutting elements placed along the cutting face \n276\n may have the same size.', 'However, as discussed above, two or more of the first plurality of cutting elements \n279\n placed along the cutting face (i.e., along a blade profile) may have different sizes.', 'Similarly, cutting elements of the second plurality of cutting elements \n280\n may have the same or different sizes along the blade profile.', 'Further, at least one of the first plurality of cutting elements \n279\n and at least one of the second plurality of cutting elements \n280\n may have different sizes, relative to one another.', 'In one or more embodiments, at least one of the first plurality of cutting elements \n279\n may be larger (i.e., have a larger diameter) than at least one of the second plurality of cutting elements \n280\n.', 'As compared to other cutting tools, such as for example conventional cutter elements, the present embodiments may offer the potential for controlled aggressiveness in different regions of the blade, depending on the regions with higher loads and stresses.', 'Thus, depending on the type of formation, the aggressiveness may be tailored by using different sizes and/or geometry of cutter elements in the regions with higher loads and stresses.', 'According to various embodiments, primary and back-up cutting elements may have a different size and/or geometry.', 'For example, according to the present embodiments, at least one primary cutting element and at least one back-up cutting element may have different sizes (e.g., diameters).', 'For example, at least one primary cutting element may have a larger size than at least one back-up cutting element.', 'Such combinations are shown in \nFIGS.', '12, 16, 21, and 22\n, for example.', 'Specifically, \nFIGS.', '12 and 16\n both show primary cutting elements (in the cone and gage regions) being larger than each of the back-up cutting elements (in the nose and shoulder regions).', 'FIGS.', '21 and 22\n show that the back-up cutting elements \n280\n may be smaller than the primary cutting elements \n279\n, when they are trailing or non-trailing.', 'Specifically, as seen in \nFIG.', '12\n, a first plurality of leading cutting elements \n279\n is placed along at least one blade (primary and/or secondary as shown in \nFIG.', '11\n) of a cutting tool, in the cone region \n24\n, nose region \n27\n, shoulder region \n25\n, and gage region \n26\n.', 'As seen in \nFIG.', '12\n, the cutting elements placed on the cone region \n24\n and on the gage region \n26\n have the same size.', 'However, these cutting elements are larger in size than the leading cutting elements placed on the nose region \n27\n and shoulder region \n25\n, improving the aggressiveness of the cutting tool.', 'As exemplified in \nFIG.', '12\n, a second plurality of back-up cutting elements \n280\n is placed on the same blade, rearward from and at the same radial position from the tool axis as the leading cutting elements \n279\n.', 'As seen in \nFIG.', '12\n, the back-up cutting elements \n280\n placed on the nose and shoulder regions have the same size as the corresponding leading cutting elements \n279\n.', 'Further, the back-up cutting elements \n280\n are smaller than the leading cutting elements \n279\n in the cone and gage regions.', 'Further, in such embodiments, in order to mitigate an expected lower side impact resistance of smaller non-planar cutting elements, a different included angle of the working surfaces, as well as different top radii of the cutting elements may be used.', 'For example, as shown in \nFIG.', '25\n, back-up cutting elements \n280\n having a smaller size than primary cutting elements \n279\n may also have a larger included angle of the working surface, as their impact resistance is expected to be lower.', 'In an embodiment, primary cutting elements \n279\n placed along at least a blade of the tool may have a diameter of 16 mm and an included angle of the working surface of 130°, while the back-up cutting elements \n280\n may have a 13 mm diameter and an included angle of the working surface of 150°.', 'In various embodiments, the cutting elements may be formed in sizes including, but not limited to, 9 mm, 13 mm, 16 mm, and 19 mm.', 'Selection of cutting element sizes may be based, for example, on the type of formation to be drilled.', 'For example, in softer formations, it may be desirable to use a larger cutting element, whereas in a harder formation, it may be desirable to use a smaller cutting element.', 'According to various embodiments, leading and back-up cutting elements may be made of materials with different properties.', 'For example, leading cutting elements may be made of materials that have more balanced properties, such as wear and impact resistance, while the back-up cutting elements may be made of materials that exhibit greater wear resistance than the leading cutting elements.', 'Therefore, the back-up cutting elements may perform more shearing when the leading cutting elements are worn down.', 'However, selection of the type of material that may be used depends on the location of a leading and/or back-up cutting elements in different regions of at least a blade.', 'For example, in one embodiment, at least one of the leading cutting elements placed on the cone region \n24\n of \nFIG.', '11\n is made of a material that exhibits more impact resistance (e.g., higher catalyst content), while at least one leading cutting element placed on the shoulder \n25\n of \nFIG.', '11\n is made of a material that exhibits more wear resistance (e.g., smaller diamond particle size).', 'Similarly, at least one of the leading cutting elements placed on the cone region \n24\n of \nFIG.', '11\n is made of a material that exhibits more wear resistance (e.g., smaller diamond particle size), while at least one leading cutting element placed on the shoulder \n25\n of \nFIG.', '11\n is made of a material that exhibits more impact resistance (e.g., higher catalyst content).', 'Further, when back-up cutting elements are used, it may be desirable for the back-up cutting elements to be more wear-resistant (e.g., smaller diamond particles), similar to the primary cutting elements in the nose and shoulder.', 'Thus, one or more back-up cutting elements may be more wear resistant than one or more primary cutting elements.', 'Specifically, for example, the back-up cutting elements may be more wear resistant than the primary cutting elements in the cone and/or gage region of the blade.', 'Further, in various embodiments, the back-up cutting elements may be of the same wear resistance as the primary cutting elements in the nose and/or shoulder region of the blade or in some embodiments may have more wear resistance.', 'In some embodiments, the back-up cutting elements may have less wear resistance than the primary cutting elements.', 'One or more leading cutting elements may have a higher impact resistance than one or more of back-up cutting elements, and in some embodiments, one or more leading cutting elements may have a lower impact resistance than one or more of the back-up cutting elements.', 'As previously noted, the aggressiveness of a cutting tool may be tailored considering also the geometry of the cutting elements.', 'Specifically, the included angle of the working surface of at least one cutting element, leading and/or back-up, may be varied, depending on the location of the cutting element on the blade.', 'For example, at least one leading cutting element (e.g., a cutting element of the first plurality of cutting elements \n279\n) may have an included angle of the working surface equal or larger than the included angle of the working surface of at least one back-up cutting element (e.g., a cutting element of the second plurality of cutting elements \n280\n).', 'In various embodiments, leading cutting elements may have a larger included angle, as they may be configured to withstand higher impact.', 'As shown in \nFIG.', '25\n, at least a leading cutting element \n279\n is sharper (having a relatively smaller included angle) than at least one back-up cutting element \n280\n, in order to be more aggressive.', 'As it will be described later, at least a portion of the peripheral edge of cutting elements of the present disclosure may be beveled or chamfered.', 'In one or more embodiments, leading and/or back-up cutting elements may be beveled or chamfered, as desired.', 'Such a chamfer or bevel offers the potential to reduce the aggressiveness of a cutting crest upon initial engagement with the formation.', 'In such embodiments, the cutting element bevel size may dictate the aggressiveness of a cutting tool.', 'For example, a smaller bevel may be more aggressive but less durable.', 'In such embodiment, the cutting elements with small bevel size may be placed in the regions of the blade that experience high stress, such as the cone region \n24\n, while cutting elements with higher bevel size may be placed on the nose region \n27\n and the shoulder region \n25\n.', 'Various combinations may be possible depending on the type of formation.', 'Referring back to \nFIG.', '16\n, another embodiment of the present disclosure is described.', 'As shown in \nFIG.', '16\n, similar to the embodiment presented in \nFIG.', '12\n, a first plurality of leading cutting elements \n279\n is placed along at least one blade (primary and/or secondary as shown in \nFIGS.', '11 and 19\n) of a cutting tool, in the cone region \n24\n, nose region \n27\n, shoulder region \n25\n and gage region \n26\n.', 'As shown, at least one of the leading cutting elements placed on the cone region \n24\n and at least one leading cutting element placed on the gage region \n26\n have the same size and the same back rake angle.', 'Similarly, at least one of the leading cutting elements placed on the nose region \n27\n and on the shoulder region \n25\n have the same size and the same back rake angle.', 'In order to improve the impact resistance of the leading cutting elements, at least one of leading cutting elements \n279\n placed on the cone and gage regions is larger in size and has a larger back rake angle than at least one of the leading cutting element placed on the nose region \n27\n and on the shoulder region \n25\n, respectively.', 'As exemplified in \nFIG.', '16\n, a second plurality of back-up cutting elements \n280\n are placed on the same blade, rearward from and at the same radial position from the tool axis as the leading cutting elements \n279\n.', 'The back-up cutting elements \n280\n are placed on the nose region \n27\n and shoulder region \n25\n, and have the same size as of the corresponding leading cutting elements \n279\n.', 'However, in order to improve the impact resistance of the back-up cutting elements, the back-up cutting elements placed on the nose region \n27\n and shoulder region \n25\n have a larger back rake angle than the corresponding leading cutting elements \n279\n.', 'In the present embodiment, the leading cutting elements \n279\n placed on the cone region \n24\n and on the gage region \n26\n, and the back-up cutting elements \n280\n placed on the nose region \n27\n and on the shoulder region \n25\n may have the same back rake angle.', 'However, other permutations of differences in back rake angle may be used between the leading cutting elements and the back-up cutting elements.', 'According to various embodiments, the directional control of a cutting tool may be tailored by using cutting elements with different side rake angles.', 'For example, as shown in \nFIG.', '26\n, the cutting elements \n279\n are larger than the size of the cutting elements \n280\n.', 'In addition, the back-up cutting elements \n280\n have a larger side rake angle than the leading cutting elements \n279\n.', 'As shown in \nFIG.', '26\n, the cutting direction is represented by \n281\n.', 'As a result, the back-up non-planar cutting elements of the present embodiment may act more similar to a shear cutter providing an improved impact resistance.', 'In one embodiment, a cutting element \n279\n may have a smaller side rake angle than a cutting element \n280\n.', 'Specifically, as illustrated, leading cutting elements \n279\n have a zero side rake, whereas the back-up cutting elements \n280\n have a non-zero side rake angle.', 'The back-up cutting elements \n280\n may have either a positive or negative side rake of up to 30 degrees.', 'While \nFIG.', '26\n shows back-up cutting elements having the same type and degree of side rake, two adjacent back-up cutting elements may have opposite types of side rake (including alternating positive and negative) and/or different values of side rake angles, similar to as described above along the blade profile.', 'By using leading and back-up cutting elements with different side rake angles, the bit properties may be tailored towards directional control.', 'Additionally, the back-up cutting elements may aid in breaking uncut ridges of formation formed between primary cutting elements, particularly when the larger side rake angles are on non-trailing back-up cutting elements.', 'In addition, by including back-up cutting elements with a side rake angle, the bit vibration through different rock applications may be minimized or reduced.', 'Substrates according to embodiments of the present disclosure may be formed of cemented carbides, such as tungsten carbide, titanium carbide, chromium carbide, niobium carbide, tantalum carbide, vanadium carbide, or combinations thereof cemented with iron, nickel, cobalt, or alloys thereof.', 'For example, a substrate may be formed of cobalt-cemented tungsten carbide.', 'Ultrahard layers according to embodiments of the present disclosure may be formed of, for example, polycrystalline diamond, such as formed of diamond crystals bonded together by a metal catalyst such as cobalt or other Group VIII metals under sufficiently high pressure and high temperatures (sintering under HPHT conditions), thermally stable polycrystalline diamond (polycrystalline diamond having at least some of the catalyst material removed), or cubic boron nitride.', 'Further, the ultrahard layer may be formed from one or more layers, which may have a gradient or stepped transition of diamond content therein.', 'In such embodiments, one or more transition layers (as well as the other layer) may include metal carbide particles therein.', 'Further, when such transition layers are used, the combined transition layers and outer layer may collectively be referred to as the ultrahard layer, as that term has been used in the present application.', 'That is, the interface surface on which the ultrahard layer (or plurality of layers including an ultrahard material) may be formed is that of the cemented carbide substrate.', 'Non-planar Cutting Elements\n \nCutting elements of the present disclosure may include a substrate, an ultrahard layer, and a non-planar interface formed between the substrate and the ultrahard layer.', 'The substrate may have an upper surface with a geometry defined by an x-y-z-coordinate system, where the height of the substrate, measured along a z-axis, varies along the x-axis and optionally y-axis.', 'A top surface of the ultrahard layer may also have a geometry defined by the x-y-z-coordinate system, where the height of the ultrahard layer varies along the x-axis and optionally y-axis.', 'As noted above, the cutting elements of the present disclosure are non-planar cutting elements, namely ridge cutters.', 'For example, a cutting element \n300\n of the present disclosure having a non-planar top surface \n305\n is shown in \nFIG.', '3\n.', 'Particularly, the cutting element \n300\n has an ultrahard layer \n310\n disposed on a substrate \n320\n at an interface \n330\n, where the non-planar top surface \n305\n geometry is formed on the ultrahard layer \n310\n.', 'The ultrahard layer \n310\n has a peripheral edge \n315\n surrounding (and defining the bounds of) the top surface \n305\n.', 'The top surface \n305\n has a cutting crest \n312\n extending a height \n314\n above the substrate \n320\n (at the cutting element circumference), and at least one recessed region extending laterally away from crest \n312\n.', 'As used herein, the crest refers to a portion of the non-planar cutting element that includes the peak(s) or greatest height(s) of the cutting element, which extends along a diameter of the cutting element (which may be, but is not limited to, being linear but could be curved or having a combination of linear and curved segments).', 'The presence of the crest \n312\n results in an undulating peripheral edge \n315\n having peaks and valleys.', 'The portion of the peripheral edge \n315\n which is proximate the crest \n312\n forms a cutting edge portion \n316\n.', 'As shown, the cutting crest \n312\n may also extend across the diameter of the ultrahard layer, such that two cutting edge portions \n316\n are formed at opposite sides of the ultrahard layer.', 'The top surface \n305\n further includes at least one recessed region \n318\n continuously decreasing in height in a direction away from the cutting crest \n312\n to another portion of the peripheral edge \n315\n that is the valley of the undulating peripheral edge \n315\n.', 'The cutting crest \n312\n and recessed regions \n318\n in the embodiment shown forms a top surface \n305\n having a parabolic cylinder shape, where the cutting crest \n312\n is shaped like a parabola that extends across the diameter of the ultrahard layer \n310\n and/or substrate \n320\n.', 'At least a portion of the peripheral edge (for example, the cutting edge portion and extending around the portion of the edge that will come into contact with the formation for an expected depth of cut) may be beveled or chamfered.', 'In other embodiments, the entire peripheral edge may be beveled.', 'In one or more embodiments, the cutting crest \n312\n may extend less than the diameter of the substrate \n320\n or even greater than the diameter of the substrate \n320\n.', 'For example, the ultrahard layer \n310\n may form a tapered sidewall at least proximate the cutting edge portion, for example, forming an angle with a line parallel to the axis of the cutting element that may range from −5 degrees (forming a larger diameter than the substrate \n320\n) to 20 degrees (forming a smaller diameter than the substrate \n320\n).', 'Depending on the size of the cutting element, the height \n314\n of the cutting crest \n312\n may range, for example, from about 0.1 inch (2.54 mm) to 0.3 inch (7.62 mm).', 'Further, unless otherwise specified, heights of the ultrahard layer (or cutting crests) are relative to the lowest point of the interface of the ultrahard layer and substrate.\n \nFIG.', '4\n shows a side view of the cutting element \n300\n.', 'As shown, the cutting crest \n312\n has a convex cross-sectional shape (viewed along a plane perpendicular to cutting crest length across the diameter of the ultrahard layer), where the uppermost point of the crest has a radius of curvature \n313\n that transitions to opposite side surfaces at an angle \n311\n.', 'According to embodiments of the present disclosure, a cutting element top surface may have a cutting crest with a radius of curvature ranging from 0.02 in.', '(0.51 mm) to 0.300 in.', '(7.62 mm), or in another embodiment, from 0.06 in.', '(1.52 mm) to 0.18 in.', '(4.57 mm).', 'Further, while the illustrated embodiment shows a cutting crest \n312\n having a curvature at its upper peak, it is also within the scope of the present disclosure that the cutting crest \n312\n may have a plateau or a substantially planar face along at least a portion of the diameter, axially above the recessed regions \n318\n laterally spaced from the cutting crest \n312\n.', 'Thus, in such an embodiment, the cutting crest may have a substantially infinite radius of curvature.', 'In such embodiments, the plateau may have radiused transitions into the sidewalls that extend to form recessed regions \n318\n.', 'Further, in some embodiments, along a cross-section of the cutting crest \n312\n extending laterally into depressed regions \n318\n, cutting crest \n312\n may have an included angle at the working surface \n311\n formed between the sidewalls extending to recessed regions \n318\n that may range from 100 degrees to 175 degrees.', 'Further, depending on the type of upper surface geometry, it is also intended that other crest angles, including down to 90 degrees may also be used.', 'The geometry of a cutting element top surface may also be described with respect to an x-y-z coordinate system.', 'For example, the cutting element shown in \nFIG.', '3\n is reproduced in \nFIG.', '5\n along an x-y-z coordinate system.', 'The cutting element \n300\n has an ultrahard layer \n310\n disposed on a substrate \n320\n at an interface \n330\n, and a longitudinal axis coinciding with the z-axis extending there through.', 'The non-planar top surface \n305\n formed on the ultrahard layer \n310\n has a geometry formed by varying heights (wherein the height is measured along the z-axis) along the x-axis and y-axis.', 'As shown, the greatest height (apex or peak) formed in the top surface (which may also be referred to as the cutting crest \n312\n in \nFIG.', '3\n) extends across the diameter of the cutting element along the y-axis, such that the crest height extends from a first portion of the peripheral edge \n315\n to a second portion of the peripheral edge \n315\n opposite from the first portion.', 'From the sake of convenience, the y-axis is defined based on the extension of the cutting element crest; however, one skilled in the art would appreciate that if defined differently, the remaining description based on the x-, y-, z-coordinate system would similarly vary.', 'A cross-sectional view of the cutting element \n300\n along the intersection of the y-axis and z-axis is shown in \nFIG.', '6\n.', 'The y-z cross-sectional view of the cutting element may be referred to as the crest profile view as the uniformity, extension, etc., of the crest may be observed from such a cross-sectional view.', 'As shown in the crest-profile view in \nFIG.', '6\n, the top surface \n305\n along the crest height (i.e., crest profile) is substantially linear.', 'While the cutting crest could be linear, as shown in this embodiment, it could also be curved or radiused.', 'A cross-sectional view of the cutting element \n300\n along the intersection of the x-axis and the z-axis is shown in \nFIG.', '7\n, and may be referred to as the crest geometry view, as the curvature, etc., of the crest may be observed from such a cross-sectional view.', 'As shown in the crest geometry view in \nFIG.', '7\n, the top surface \n305\n peaks at the z axis (at the crest height), and continuously decreases from the crest height, moving along the x-axis in either direction towards the peripheral edge \n315\n of the cutting element (which may also be referred to as the recessed regions \n318\n in \nFIG.', '3\n), such that the top surface \n305\n has a generally parabolic shape along the cross-section.', 'Depending on the curvature of the cross-section illustrated in \nFIG.', '7\n, the cross-section may also be described as the cross-section of a cone with a rounded apex, i.e., two angled sidewalls tangentially transitioning into the rounded apex (having the radius of curvature ranges described above).', 'However, sidewalls with curvature, either concave or convex, may also be used.', 'In this illustrated embodiment, the generally parabolic shape in the x-z cross-sectional view (or crest geometry view) extends along the y-axis, such that the three dimensional shape of the non-planar top surface \n305\n has parabolic cylinder shape.\n \nFIGS.', '8 and 9\n show another example of a cutting element \n500\n having a non-planar top surface \n505\n.', 'The cutting element \n500\n has an ultrahard layer \n510\n disposed on a substrate \n520\n at an interface \n530\n, wherein the non-planar top surface \n505\n is formed on the ultrahard layer \n510\n.', 'The ultrahard layer \n510\n has a peripheral edge \n515\n surrounding the top surface \n505\n.', 'The top surface \n505\n has a cutting crest \n512\n extending a height \n514\n above the substrate \n520\n, and at least one recessed region \n518\n extending laterally from crest \n512\n.', 'The crest \n512\n, proximate a portion of the peripheral edge \n515\n, forms a first cutting edge portion \n516\n.', 'As shown in \nFIG.', '9\n, the cutting crest \n512\n of a non-planar cutting element of the present disclosure has a radius of curvature \n513\n that transitions to opposite side surfaces at an angle \n511\n called included angle of the working surface.', 'The peripheral edge \n515\n may be undulating from a peak at the cutting edge portion \n516\n, and a valley proximate at least one recessed region \n518\n, which continuously decreases in height in a direction away from the crest \n512\n.', 'As shown in \nFIG.', '9\n, the recessed regions \n518\n extends a height above the substrate/ultrahard layer interface (along the circumference), but may have a height differential \n517\n (from the cutting edge portion \n516\n), which is also equal to the total variation in height of the top surface \n505\n.', 'According to some embodiments, a non-planar top surface of a cutting element may have a height differential \n517\n ranging between 0.04 in (1.02 mm) and 0.2 in (5.08 mm) depending on the overall size of the cutting element.', 'For example, the height differential \n517\n relative to the cutting element diameter may range from 0.1 to 0.5, or from 0.15 to 0.4 in other embodiments.', 'Additionally, in one or more embodiments, the height of the diamond at the peripheral edge adjacent recessed region \n518\n (i.e., at the side of the cutting element having the lowest diamond height) may be at least 0.04 in.', '(1.02 mm).', 'Advantageously, embodiments disclosed herein may provide for at least one of the following.', 'The various geometries and placement of the non-planar cutting elements may provide for optimized use of the non-planar cutting elements during use, specifically, to reduce or minimize harmful loads and stresses on the cutting elements during drilling.', 'By placing non-planar cutting elements with different material properties, sizes, orientations, and/or working surface geometries in areas of a cutting tool experiencing increased wear, the wear rate of the bit may be improved.', 'In addition, non-planar cutting elements having side rake angles may provide better impact resistance to the cutting element.', 'Furthermore, by using leading and back-up cutting elements with different side rake angles, the cutting tool properties may be tailored towards directional control.', 'In addition, the bit vibration through different rock applications may be minimized.', 'Cutting tools according to the present embodiments may offer the potential for controlled aggressiveness along the entire blade profile, and therefore may exhibit higher cutting efficiency and longer life time than conventionally cutting tools.', 'While embodiments of this disclosure have been described in detail with particular references to embodiments thereof, the embodiments described herein are not intended to be exhaustive or to limit the scope of the disclosure to the exact forms disclosed.', 'Persons skilled in the art and technology to which this invention pertains will appreciate that alterations and changes in the described structures and methods of assembly and operation can be practiced without meaningfully departing from the principles, spirit, and scope of this disclosure.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein.', 'Additionally, as used herein, the term “substantially” and similar terms are used as terms of approximation and not as terms of degree, and are intended to account for the inherent deviations in measured or calculated values that would be recognized by those of ordinary skill in the art.', 'Furthermore, as used herein, when a component is referred to as being “on” or “coupled to” another component, it can be directly on or attached to the other component or intervening components may be present therebetween.', 'It should be understood that any directions or reference frames in the preceding description are merely relative directions or movements.', 'For example, any references to “up” and “down” or “above” and “below” are merely descriptive of the relative position or movement of the related elements.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not just structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke means-plus-function for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A downhole cutting tool, comprising:\na tool body;\nat least one blade extending from the tool body, the at least one blade having a cutting face, a trailing face, and a top face extending between the cutting face and trailing face; and\na plurality of cutting elements attached to the at least one blade along the cutting face, wherein each cutting element of the plurality of cutting elements comprises a diamond table and a substrate, a working surface of each of the plurality of cutting elements having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest, the working surface being opposite the substrate,\nat least two of the plurality of cutting elements on the at least one blade having differing material properties along a blade profile of the at least one blade, wherein the differing material properties consist of the diamond tables having an average diamond grain size between 1 to 40 microns, a binder content by weight between 1% to 15%, or any combination thereof, and a first cutting element of the at least two comprises a diamond table having an average diamond grain size of 3 microns or less and a binder content by weight of 2% or less.', '2.', 'The downhole cutting tool of claim 1, wherein the plurality of the cutting elements is placed on a cone region, a nose region, a shoulder region, or a gage region of the at least one blade.', '3.', 'The downhole cutting tool of claim 2, wherein a size of at least one of the plurality of cutting elements placed on the cone and the gage regions is larger than a size of at least one of the plurality of cutting elements placed on the nose and shoulder regions of the tool body.', '4.', 'The downhole cutting tool of claim 2, wherein an included angle of the working surface of at least one of the plurality of cutting elements placed on the cone region is larger than an included angle of the working surface of at least one of the plurality of cutting elements placed on the nose or shoulder regions of the tool body.', '5.', 'The downhole cutting tool of claim 2, wherein at least one of the plurality of cutting elements in the cone region has a greater back rake angle than at least one of the plurality of cutting elements in the nose or shoulder region.', '6.', 'The downhole cutting tool of claim 2, wherein the cutting element in the cone region is larger than the cutting element in the nose or shoulder region.', '7.', 'The downhole cutting tool of claim 2, wherein the cutting element in the gage region is larger than the cutting element in the nose and/or shoulder region.', '8.', 'The downhole cutting tool of claim 2, wherein a radius of curvature at the crest of at least one of the plurality of cutting elements placed on the cone region of the tool body is larger than a radius of curvature at the crest of at least one of the plurality of cutting elements placed on the nose or shoulder regions of the tool body.', '9.', 'The downhole cutting tool of claim 1, wherein the at least two of the plurality of cutting elements have different back rake angles or different side rake angles.', '10.', 'The downhole cutting tool of claim 9, wherein the plurality of the cutting elements is placed on a cone region, a nose region, a shoulder region, or a gage region of the at least one blade, and wherein a cutting element in the gage region has a larger back rake angle than a cutting element in the nose or shoulder region.', '11.', 'The downhole cutting tool of claim 1, wherein the at least two cutting elements have a different angle formed between a line extending through the crest and a cutting profile curve that is tangent to the plurality of cutting elements.\n\n\n\n\n\n\n12.', 'The downhole cutting tool of claim 1, wherein a second cutting element of the plurality of cutting elements comprises a second diamond table having an average diamond grain size between 30 to 40 microns and binder content by weight between 10% to 15%.\n\n\n\n\n\n\n13.', 'The downhole cutting tool of claim 12, wherein the first cutting element is further from a tool axis of the tool body on the at least one blade than the second cutting element.', '14.', 'A downhole cutting tool, comprising:\na tool body having a tool axis;\nat least one blade extending from the tool body, the at least one blade having a cutting face, a trailing face, and a top face extending between the cutting face and trailing face; and\na plurality of cutting elements attached to the at least one blade along the cutting face, wherein each cutting element of the plurality of cutting elements comprises a diamond table and a substrate, a working surface of each of the plurality of cutting elements having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest, the working surface being opposite the substrate,\na first of the plurality of cutting elements closer to the tool axis than a second of the plurality of cutting elements having a greater impact resistance than the second of the plurality of cutting elements, wherein the first plurality of cutting elements comprises the diamond tables having an average grain size between 30 to 40 microns inclusive, the second plurality of cutting elements comprises the diamond tables having an average grain size less than 3 microns and a binder content by weight of 2% or less.\n\n\n\n\n\n\n15.', 'The downhole cutting tool of claim 14, wherein the plurality of the cutting elements is placed on a cone region, a nose region, a shoulder region, or a gage region of the at least one blade.', '16.', 'The downhole cutting tool of claim 15, wherein the size of at least one of the plurality of cutting elements placed on the cone or the gage region is larger than the size of at least one of the plurality of cutting elements placed on the nose and/or shoulder regions of the tool body.', '17.', 'The downhole cutting tool of claim 15, wherein an included angle of the working surface of at least one of the plurality of cutting elements placed on the cone region is larger than an included angle of the working surface of at least one of the plurality of cutting elements placed on the nose and/or shoulder regions of the tool body.', '18.', 'The downhole cutting tool of claim 14, wherein the at least two of the plurality of cutting elements have different back rake angles or different side rake angles.', '19.', 'The downhole cutting tool of claim 14, wherein a radius of curvature at the crest of at least one of the plurality of cutting elements placed on the cone region of the tool body is larger than a radius of curvature at the crest of at least one of the plurality of cutting elements placed on the nose or shoulder regions of the tool body.', '20.', 'A downhole cutting tool, comprising:\na tool body having a tool axis;\nat least one blade extending from the tool body, the at least one blade having a cutting face, a trailing face, and a top face extending between the cutting face and trailing face; and\na plurality of cutting elements attached to the at least one blade along the cutting face, wherein each cutting element of the plurality of cutting elements comprises a diamond table and a substrate, a working surface of each of the plurality of cutting elements having a cutting crest at a peak height and a reduced height extending laterally away from the cutting crest, the working surface being opposite the substrate,\na first of the plurality of cutting elements further from the tool axis than a second of the plurality of cutting elements having a greater wear resistance than the second of the plurality of cutting elements, wherein the first of the plurality of cutting elements comprises the diamond tables having a binder content by weight of less than or equal to 2%, a first cutting element of the plurality of cutting elements comprises a first diamond table having an average diamond grain size of less than or equal to 3 microns, and the second of the plurality of cutting elements comprises the diamond tables having a binder content by weight between 10 to 15% inclusive.'] | ['FIG.', '2 shows an example of a cutting element 150, where the cutting element 150 has a cylindrical cemented carbide substrate 152 having an end face or upper surface referred to herein as a substrate interface surface 154.', 'An ultrahard material layer 156, also referred to as a cutting layer, has a top surface 157, also referred to as a working surface, a cutting edge 158 formed around the top surface, and a bottom surface, referred to herein as an ultrahard material layer interface surface 159.', 'The ultrahard material layer 156 may be a polycrystalline diamond or polycrystalline cubic boron nitride layer.', 'The ultrahard material layer interface surface 159 is bonded to the substrate interface surface 154 to form an interface between the substrate 152 and ultrahard material layer 156.', '; FIG.', '1 shows a conventional drag bit.; FIG.', '2 shows a conventional cutting element.; FIGS.', '3 and 4 show a cutting element having a non-planar top surface according to embodiments of the present disclosure.', '; FIG.', '5 shows a perspective view of the cutting element shown in FIG.', '3.; FIGS.', '6 and 7 show a cross-sectional view of a cutting element top surface according to embodiments of the present disclosure.; FIGS. 8 and 9 show a cutting element having a non-planar top surface according to embodiments of the present disclosure.', '; FIG.', '10 is a partial cross-sectional view of a bit with the cutting elements of the bit shown rotated into a single profile.; FIG.', '11 shows a profile view of a drill bit according to embodiments of the present disclosure.;', 'FIG.', '12 shows a cutting profile according to embodiments of the present disclosure.; FIGS. 13 and 14 show rotation of cutting elements according to embodiments of the present disclosure.; FIGS.', '15, 16, and 17 show a cutting profile according to embodiments of the present disclosure.', '; FIG.', '18 shows a geometry of a cutting element according to embodiments of the present disclosure.; FIGS.', '19 and 20 show a perspective view of a drill bit according to embodiments of the present disclosure.; FIGS.', '21-26 show cutting profiles according to embodiments of the present disclosure.', '; FIG.', '4 shows a side view of the cutting element 300.', 'As shown, the cutting crest 312 has a convex cross-sectional shape (viewed along a plane perpendicular to cutting crest length across the diameter of the ultrahard layer), where the uppermost point of the crest has a radius of curvature 313 that transitions to opposite side surfaces at an angle 311.', 'According to embodiments of the present disclosure, a cutting element top surface may have a cutting crest with a radius of curvature ranging from 0.02 in.', '(0.51 mm) to 0.300 in.', '(7.62 mm), or in another embodiment, from 0.06 in.', '(1.52 mm) to 0.18 in.', '(4.57 mm).', 'Further, while the illustrated embodiment shows a cutting crest 312 having a curvature at its upper peak, it is also within the scope of the present disclosure that the cutting crest 312 may have a plateau or a substantially planar face along at least a portion of the diameter, axially above the recessed regions 318 laterally spaced from the cutting crest 312.', 'Thus, in such an embodiment, the cutting crest may have a substantially infinite radius of curvature.', 'In such embodiments, the plateau may have radiused transitions into the sidewalls that extend to form recessed regions 318.', 'Further, in some embodiments, along a cross-section of the cutting crest 312 extending laterally into depressed regions 318, cutting crest 312 may have an included angle at the working surface 311 formed between the sidewalls extending to recessed regions 318 that may range from 100 degrees to 175 degrees.', 'Further, depending on the type of upper surface geometry, it is also intended that other crest angles, including down to 90 degrees may also be used.; FIGS. 8 and 9 show another example of a cutting element 500 having a non-planar top surface 505.', 'The cutting element 500 has an ultrahard layer 510 disposed on a substrate 520 at an interface 530, wherein the non-planar top surface 505 is formed on the ultrahard layer 510.', 'The ultrahard layer 510 has a peripheral edge 515 surrounding the top surface 505.', 'The top surface 505 has a cutting crest 512 extending a height 514 above the substrate 520, and at least one recessed region 518 extending laterally from crest 512.', 'The crest 512, proximate a portion of the peripheral edge 515, forms a first cutting edge portion 516.', 'As shown in FIG. 9, the cutting crest 512 of a non-planar cutting element of the present disclosure has a radius of curvature 513 that transitions to opposite side surfaces at an angle 511 called included angle of the working surface.', 'The peripheral edge 515 may be undulating from a peak at the cutting edge portion 516, and a valley proximate at least one recessed region 518, which continuously decreases in height in a direction away from the crest 512.', 'As shown in FIG. 9, the recessed regions 518 extends a height above the substrate/ultrahard layer interface (along the circumference), but may have a height differential 517 (from the cutting edge portion 516), which is also equal to the total variation in height of the top surface 505.', 'According to some embodiments, a non-planar top surface of a cutting element may have a height differential 517 ranging between 0.04 in (1.02 mm) and 0.2 in (5.08 mm) depending on the overall size of the cutting element.', 'For example, the height differential 517 relative to the cutting element diameter may range from 0.1 to 0.5, or from 0.15 to 0.4 in other embodiments.', 'Additionally, in one or more embodiments, the height of the diamond at the peripheral edge adjacent recessed region 518 (i.e., at the side of the cutting element having the lowest diamond height) may be at least 0.04 in.', '(1.02 mm).'] |
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US11092005 | EM-telemetry remote sensing wireless network and methods of using the same | Jul 23, 2019 | Luis Eduardo DePavia, Gaelle Jannin, Jiuping Chen | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in International Patent application PCT/US2016/034523, dated Sep. 20, 2016. 13 pages.; International Perliminary Report on Patentability issued in International Patent appliction PCT/US2016/034523 dated Dec. 5, 2017, 11 pages.; Evans et al., The Price of Poor Power Quality, American Association of Drilling Engineers. AADE-11-NTCE-7. National Technical Conference and Exhibition, Houston, Texas, Apr. 12-14, 2011. 17 pages.; Marsala et al., First Borehole to Surface Electromagnetic Survey in KSA: Reservoir Mapping and Monitoring at a New Scale, Saudi Aramco Journal of Technology, Winter 2011. pp. 36-78.; Colombo et al., Sensitivity Analysis of 3D Surface-Borehole CSEM for a Saudi Arabian Carbonate Reservoir, SEG Las Vegas 2012 Annual Meeting. 5 pages.; Strack et al., Full Field Array Electromagnetics: Advanced EM from the Surface the Borehole, Exploration to Reservoir Monitoring, 9th Biennial International Conference & Exposition on Petroleum Geophysics, Hyderabad, India. 2012.; Zhdanov et al., Electromagnetic Monitoring of CO2 Sequestration in Deep Reservoirs, First Break, vol. 31, pp. 71-78, Feb. 2013. | 3079550; February 1963; Huddleston, Jr.; 4739325; April 19, 1988; MacLeod; 4980682; December 25, 1990; Klein et al.; 5091725; February 25, 1992; Gard; 6167156; December 26, 2000; Antoniades et al.; 6657597; 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May 2017; WO | ["A surface system for an electromagnetic telemetry remote sensing wireless system includes a surface acquisition system configured to receive wireless signals and a plurality of nodes deployed at Earth's surface in a drilling area.", 'Each of the nodes includes a distinct pair of first and second spaced apart electrodes and is configured to digitize voltage differences between the corresponding first and second electrodes and to wirelessly transmit the digitized voltage differences to the surface acquisition system.', 'The voltage differences include an electromagnetic signal transmitted by a downhole tool deployed in a wellbore in the drilling area.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThe present application is a Continuation of U.S. application Ser.', 'No. 15/574,509, filed Nov. 16, 2017, which is a National Stage Entry of PCT/US16/34523, filed May 27, 2016, which claims the benefit of, and priority to, U.S. Provisional Patent Application No. 62/168,430, filed May 29, 2015, each of which are hereby incorporated by reference in their entirety.', 'BACKGROUND\n \nA current limitation of electromagnetic telemetry remote sensing systems is that signal amplitude received at surface can be small with respect to electrical noise picked up by the stakes or other equipment that serve as electrodes.', 'Hence, under high noise conditions, the signal received is often corrupted, and consequently the demodulation and decoding result in erroneous or missing information.', 'A second limitation is the fact that the field crew must nail down a set of electrode rods deep in the ground for every rig and several hundred feet of wire must be run from these stakes to a data acquisition system, typically located in a shack near the rig.', 'Worse yet, the setup frequently involves routing wires through roads, local rig vehicle traffic, fences etc. . . .', 'and is time consuming, requiring testing for proper ground connection each time and complicated logistics, provides an increased safety risk exposure and can lead to cable damage and unexpected failures.', 'A need exists, therefore, for reliable sensing of EM signals in environments where the EM signal may be small and the noise level high, and the burden of hard wiring and complicated installation logistics are omitted.', 'SUMMARY\n \nAn electromagnetic telemetry remote sensing wireless system and methods for using the system are disclosed.', "A surface system includes a surface acquisition system configured to receive wireless signals and a plurality of nodes deployed at Earth's surface in a drilling area.", 'Each of the nodes includes a distinct pair of first and second spaced apart electrodes and is configured to digitize voltage differences between the corresponding first and second electrodes and to wirelessly transmit the digitized voltage differences to the surface acquisition system.', 'The voltage differences include an electromagnetic signal transmitted by a downhole tool deployed in a wellbore in the drilling area.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThe above and further advantages of this invention may be better understood by referring to the following description in conjunction with the accompanying drawings, in which like numerals indicate like structural elements and/or features in various figures.', 'The drawings are not necessarily to scale, emphasis instead being placed upon illustrating the principles of the invention.\n \nFIG.', '1\n illustrates how the cable and the stakes can be placed around a rig infrastructure during job setup where stake placement is limited to a few hundred feet around rig and cable is connected to the measurement-while-drilling shack (“MWD”).', 'FIG.', '2\n shows noise propagation as a function of depth and radial distance from the noise source.\n \nFIG.', '3\n shows the EM-telemetry signal decay of a downhole tool as a function of radial distance from the rig and tool depth.', 'The EM-telemetry signal amplitude from the downhole tool is attenuated as the distance increases radially from the rig and as the tool is positioned at a greater depth.', 'The black contour lines show that as the tool moves deeper in the well, the attenuation rate is lower as the signal is measured away from the rig.\n \nFIG.', '4\n illustrates downhole signal amplitude and rig noise amplitude at radial distance from the rig (plot for gap placed at depth approximately 3000 feet).', 'FIG.', '5\n shows the signal to noise ratio computed at a range of radial distance points from the well and EM-tool at different gap depths.\n \nFIG.', '6\n illustrates one embodiment of the EM-telemetry remote wireless remote sensing network described herein.', 'Electrodes are placed in pairs and significantly away from the rig site.', 'An array is installed in the area and data streamed to an acquisition system.', 'FIG.', '7\n illustrates nodes streaming electromagnetic (“EM”) sensed data to a number of rigs in the area.\n \nFIG.', '8\n illustrates an example well site in which embodiments of an array noise reduction manager can be employed.\n \nFIG.', '9\n illustrates an example global uplink chain that can be used with implementations of the array noise reduction manager.\n \nFIG.', '10\n illustrates an example observation model in accordance with implementations of the array noise reduction manager.\n \nFIG.', '11\n shows an example of what might be expected in a Quadrature Phase-Shift Keying (“QPSK”) modulation.\n \nFIG.', '12\n illustrates an example method associated with the array noise reduction manager.\n \nFIG.', '13\n illustrates an example method associated with the array noise reduction manager.\n \nFIG.', '14\n illustrates an example method associated with the array noise reduction manager.\n \nFIG.', '15\n shows signal to noise ratio (“SNR”) computed from each of two orthogonal channels, labeled Sensor 1 (blue) and Sensor 2 (green).', 'FIG.', '16\n is similar to \nFIG.', '15\n except that Sensor 2 (green) now refers to a synthesized signal, which corresponds to a direction 30 degrees away from the original Sensor 2.', 'A noticeable improvement in SNR is evident.', 'FIG.', '17\n shows a remote set-up of Example 1 that was placed at approximately 2800 feet away from the well site.\n \nFIG.', '18A\n represents the well site recording at channel 1 of Example I.\n \nFIG.', '18B\n represents the well site recording at channel 2 of Example I.\n \nFIG.', '19A\n represents the remote location recording of channel 1 of Example I.\n \nFIG.', '19B\n represents the remote location recording of channel 2 of Example I.\n \nFIG.', '20\n shows a test site described in Example II where the array of electrodes was deployed in the vicinity of the drilling rig and 1500 feet away from the right.\n \nFIG.', '21A\n & \nFIG.', '21B\n show the spectrograms for station 6 channel 1 (top) and channel 2 (bottom), close to the drilling well described in Example II.\n \nFIGS.', '22A & 22B\n show the spectrograms for station 5 channel 1 (top) and channel 2 (bottom), 1500 feet away from the rig described in Example II.', "DETAILED DESCRIPTION\n \nElectromagnetic telemetry (also “EM-Telemetry” or “EM Telemetry”) transmits information and data from a downhole tool (also referred to herein as a “tool” or “EM-tool” or “EM tool”) placed in a borehole to an acquisition system located at the earth's surface and also sends commands from the earth to the downhole tools.", 'Information and data transmitted to the surface can contain tool position, orientation in the borehole as well as a variety of formation evaluation measurements which are used in some applications to guide the drilling direction and optimize the well placement in the pay zone.', 'A modulated current can be injected by the tool into the formation through the metal in the drilling string and the bottom hole assembly (“BHA”) that is in contact with the rock in the borehole.', 'A section of the BHA can act as one electrode and the upper section of the BHA and drill string can act as the other electrode.', 'The separation between sections consists of an insulating gap.', "Signal is received at the earth's surface by measuring the voltage between two points, typically between the well head and a second electrode connected to the ground a few hundred feet away.", 'The voltage signal is acquired, demodulated and decoded, providing the information to the user to make drilling and steering decisions and/or adjustment of drilling parameters including, but not limited to, drilling depth, drilling rate, drilling rotation, rotation speed, torque, thrust pressure, rotating pressure, injection fluid flow rate and pressure, x and y inclination, reflected vibration, drilling fluid composition, fluid density, viscosity, fluid loss and the like.', 'Also, data and information including, but not limited to these drilling parameters, can be wirelessly streamed to the data acquisition system.', 'As noted above, a limitation of prior art EM-telemetry systems is that the signal amplitude received at surface can be very small respect to the electrical noise picked up by the electrodes.', 'Under high noise conditions, the received signal can be corrupted, consequently demodulation and decoding result in erroneous or missing information.', 'As also noted above, a second limitation of prior art EM-Telemetry systems is that the field crew must nail a set of electrode rods, also referred to as “stakes,” deep in the ground for every rig and lay down several hundred feet of wire from the stakes into the acquisition system which is typically located in a measurement-while-drilling shack near the rig.', 'This frequently involves routing wires through roads, local rig vehicle traffic, fences etc.', 'The setup is time consuming, requires testing for proper ground connection each time, complicated logistics, increased safety risk exposure and leads to cable damage and unexpected failures during the job.', 'As described herein, the electrodes can be either deployed at surface, downhole or in ocean or other large body of water.', 'As used herein, the term “electrode” includes, but is not limited to, a surface electrode, a downhole electrode and an ocean electrode.', 'The surface electrode can be, for example, an observation well well-head, a capacitive electrode or a magnetometer and the like.', 'The downhole electrode can be a metallic ball, an electric insulating gap or a magnetometer and the like.', 'The metallic ball can be in contact with casing or insulted form the casing.', 'The ocean electrode is a metallic rod or magnetometer and the like.', 'The EM-Telemetry signals can be measured using any combination of two electrodes.', 'As further described herein, to obtain a significant or maximum amount of information, two pairs of electrodes should be deployed, and they should be installed substantially perpendicular to each other.', 'Hence, the present disclosure provides methodologies to enable EM-Telemetry decoding in electromagnetic (“EM”) unfriendly environments, particularly instances where the downhole signal can be small and the noise can be high relative to the signal.', 'In contrast to prior art methods, the methods described herein eliminate the need to deploy stakes (also referred to sometimes as “electrodes”) and hard wire cables at each rig location.', 'A main source of electrical noise which impedes EM-telemetry is often generated by the electrical equipment around the rig.', 'One source of noise is produced by current loops in the ground between different pieces of equipment or as referred to herein as “rig noise.”', 'When the voltage is measured between a pair of stakes, separated for example at 500 feet from each other, the voltage contains both the signal of interest received from the downhole tool and rig noise.', 'Rig noise amplitude is large near the rig area (where the ground loop currents circulate) and is attenuated as it is measured at a distance away from the rig.', 'When a measurement is made at a significantly large distance from the rig (several hundred to thousands of feet) the rig noise becomes insignificant.', 'FIG.', '1\n illustrates how the cable \n144\n hundreds of feet long and the stakes (referred to herein also as “electrodes”) \n6\n can be placed around a rig \n14\n infrastructure during job setup where stake placement is limited to a few hundred feet around rig and cable is connected to the measurement-while-drilling shack (“MWD”) \n142\n because of fencing \n146\n, a road \n218\n and the like.', 'As shown in \nFIG.', '2\n, rig noise decay is a function of radial distance from the rig and is independent of the BHA depth position.', "At the same time, low frequency electromagnetic signals are transmitted by the downhole tool and travel through earth formations to the earth's surface, producing signal that can be measured between a pair of stakes placed at the surface.", 'As the BHA drills deeper, signal from the downhole tool is attenuated as it travels to the surface and the voltage measured between two stakes diminishes.', 'The rate of signal attenuation versus depth follows a different profile as the voltage measurements are made going away from the well.', 'When measurements are made away from the rig, the signal decay rate is smaller.', 'FIG.', '3\n shows tool signal decay as a function of radial distance from the rig and tool depth.', 'The black contour lines show the attenuation rate is lower as the signal is measured away from the rig.', 'As such, there is an optimal location at a significantly far distance from the well where rig noise is minimized and the downhole signal (while greatly reduced) is measureable.', 'In that configuration, the signal to noise ratio (also referred to herein as “SNR”) is large, enabling the decoding of EM-telemetry data which otherwise would not be possible.\n \nFIG.', '4\n illustrates, at one depth, the expected received signal at surface from the downhole tool and its decaying attenuation as it is measured away from the rig.', 'It also shows the rig noise amplitude and the noise attenuation as the distance from the rig increases.', 'In the near proximity of the well (few hundred feet), the noise and signal have both been observed to have high amplitude of similar order.', 'At relatively far distance (i.e., 3000 feet), the rig noise has decayed significantly while the downhole signal has been reduced only slightly.', 'Diversity receivers and numerical methods of signal processing are described.', 'Diversity receivers and numerical methods of signal processing have been described.', 'For example, in U.S. Pat. Nos. 6,657,597 and 7,268,696, Rodney et al. teach EM telemetry systems that are in use while a well is being drilled where an adaptive filter is used to remove noise from the received EM signal.', 'See, U.S. Pat.', 'No. 6,657,597, Col. 4, line 58 through Col. 7.', 'Line 17, and FIGS.', '1, 2 and 3, incorporated herein as reference.', 'In U.S. Pat. No. 7,151,466, Gabelmann et al., teach a data-fusion receiver where an ultra-low frequency electromagnetic telemetry receiver which fuses multiple input receive sources to synthesize a decodable message packet from a noise corrupted telemetry message string.', 'Gabelmann et al. explain ultra-low frequency electromagnetic waves (ULF EM) waves and identifies a variety of receivers employed as the telemetry receiver.', 'See, U.S. Pat.', 'No. 7,151,466 generally and particularly U.S. Pat.', 'No. 7,151,466 at Col. 1, line 29 through Col. 3, line 40 incorporated herein by reference.', 'Likewise, in U.S. Pat. No. 7,243,028, Young et al. teach methods and apparatus for reducing noise in a detected electromagnetic wave used to telemeter data during a wellbore operation.', 'In one embodiment, two surface antennae are placed on opposite sides of the wellbore and at the same distance from the wellbore.', 'The signals from the two antennae are summed to reduce the noise in the electromagnetic signal transmitted from the electromagnetic downhole tool.', 'U.S. Pat.', 'No. 7,243,028, Col. 4, 1. 51 through Col. 7, 1. 55 incorporated by reference.', 'Finally, in U.S. Pat. No. 7,268,696 Rodney et al. teach directional signal and noise sensors for borehole EM telemetry systems.\n \nFIG.', '5\n shows the signal to noise ratio computed at selected radial distance points from the well and different gap depths.', 'While the tool is at shallow depths, the SNR is high for radial distance away from the well even in instances where electrode pair is placed within 2000 feet from the well.', 'However, when the tool is at a much greater depth (beyond 7000 feet for example), the SNR drops for stake locations near the well since the rig noise is high and tool signal is small.', 'However, the SNR is larger at farther locations where the stakes are 6000 feet, 8000 feet, etc. . . .', 'away from the well.', 'This example is a vertical well and the SNR and signal amplitude are for illustration purposes.', 'Actual values vary on a case by case basis depending on the formation resistivity, and rig noise amplitude and source.', 'As to limitations presented when laying stakes \n6\n at each rig \n14\n and running wires and cable \n144\n as described in the background section, here, logistics are further complicated if there is a need to place the electrodes \n6\n significantly away (in the order of thousands of feet) from the rig in an effort to reduce the rig noise.', 'As such, the methodology described herein includes installing an array of electrode pairs which is located a significant distance from the rig \n14\n.', 'Each set of electrodes forms a node \n12\n (or cell) that digitizes voltage and wirelessly streams the data/information to an acquisition system.', 'This methodology eliminates the time, cost, and risks in routing extra-long cables and permits placing the electrodes \n6\n far away from the rig to improve the signal to noise ratio.', 'Permanent or semi-permanent installations of the nodes \n12\na\n, \n12\nb\n, \n12\nc\n, \n12\ne\n, \n12\nf \ncan be set up in a drilling area of 500 feet to 2 to 5 square miles.', 'Numerous sensing nodes, each having an electrode pair (pair of stakes) can be deployed and wirelessly stream data, enabling noise cancellation algorithms and further improve SNR.', 'Data from multiple tools running in different pads can be received simultaneously and EM downlinks can be transmitted from a single location to multiple tools downhole.', 'The EM downlink can refer to a communication signal, such as telecommunication signal, and/or information that the signal conveys.', 'Each tool (not shown) can be assigned a frequency channel and an identifier and synchronized, if desired or required.', 'Further, as the downhole tool drills a lateral well (typically several thousand fee long), the EM signal amplitude will be reduced as the tool moves radially from the node.', 'At the same time, the signal will increase as the tool approaches another node located in the direction that the tool is drilling.', 'In the array deployed in the drilling area, certain nodes receive stronger signal than other nodes at different time as the downhole tool drills through the well.', 'Therefore, signal is likely to increase in one or more nodes.\n \nFIG.', '6\n illustrates one embodiment of an EM-telemetry remote sensing wireless network \n2\n, also referred to herein sometimes as an EM-telemetry remote sensing wireless system.', 'FIG.', '7\n illustrates three nodes \n12\na\n, \n12\nb\n, \n12\nc \nstreaming EM sensed data to one or more rigs \n14\n (rigs \n14\na\n, \n14\nb\n, \n14\nc\n, \n14\nd\n, \n14\ne\n, \n14\nf\n, \n14\ng\n, and \n14\nh \nin \nFIG.', '7\n) in the drilling area (sometimes referred to as “the area.”).', 'As described below, electrodes \n6\na\n, \n6\nb\n, \n6\nc\n, \n6\nd\n, \n6\ne\n, and \n6\nf \nare placed significantly away from the rigs \n14\n to minimize rig noise pick-up.', 'Data can be streamed into a central data acquisition system \n150\n or to a number of acquisition system where data is processed and can be utilized.', 'The Noise Reduction Manager\n \nIn electromagnetic telemetry, the presence of noise from unwanted electromagnetic sources can threaten the reliability of a telemetry uplink.', 'Such noise can be generated by a wide variety of devices associated with electromagnetic energy including electric power generators, electronic power controllers and converters, mud motors, wellhead equipment, AC units, vehicles, welding equipment, consumer electronics.', 'Noise can also be generated by surrounding the environment such power transmission systems, buildings or nearby construction of the same.', 'As described in U.S. patent application Ser.', 'No. 14/517,197, an array noise reduction manager (also referred to sometimes as the “noise reduction manager”) can be used in the EM-telemetry remote sensing wireless network system and can be configured to receive measurements from several sensors on one or more tools or nodes.', 'As described herein, the noise reduction manager applies a selected de-mixing vector to filter the noise sources from the measurements and improves the signal to noise ratio of a telemetry signal in the measurements.', 'The noise reduction manager can improve a signal to noise ratio of a signal through use of an interface to receive the signal, which includes information associated with an operating condition from two or more sensors on one more tools.', 'The noise reduction manager also includes a noise reduction module to simultaneously remove noise associated with several noise sources from the received signal through use of a de-mixing vector.', 'The noise reduction manager is capable of directing a processor to receive signals from two or more sensors and apply a selected de-mixing vector to filter one or more noise sources from the signals.', 'The term “noise reduction” as used herein includes a range of signal noise reduction, from decreasing some of the noise in a signal to cancellation of noise in a signal.', 'U.S. patent application Ser.', 'No. 14/517,197, unpublished, ¶¶', '[0001] to [0042] incorporated herein by reference.', 'Array noise reduction can be accomplished through the use of multiple sensors on one or more tools and in conjunction with the array noise reduction manager utilizing a de-mixing vector.', 'In one possible aspect, a certain number of sensors (“N”) are used to process N−1 noise sources from a desired signal.', 'In another possible aspect, different noise sources can be jointly removed rather than sequentially removed from the desired signal.', 'Id. ¶ [0020].', 'Array noise reduction as described herein is useful in electromagnetic (“EMAG” or “EM”) telemetry, including scenarios where EM telemetry is employed in conjunction with Measuring While Drilling (“MWD”) or Logging', 'While Drilling (“LWD”) operations and MWD tools, LWD tools and in underbalanced drilling conditions and/or when gas is used instead of mud as drilling fluid.', 'Array noise reduction reduces environmental noise (or noise due to the environment) in EM telemetry and improves the reliability of associated uplink telemetry, even when power constraints result in a signal power is measured at a well surface and smaller than environmental noise present at a well site.', 'Id. at ¶¶', '[0021] & [0022].\n \nFIG.', '8\n illustrates a well site \n100\n in which embodiments of the noise reduction manager can be employed.', 'Well site \n100\n can be onshore or offshore.', 'In this example system, a borehole \n102\n is formed in a subsurface formation by rotary drilling; however, the noise reduction manager can be employed in well sites where directional drilling is being conducted.', 'A drill string \n104\n is suspended within the borehole \n102\n and has a bottom hole assembly (“BHA”) \n106\n having a drill bit \n108\n at its lower end.', 'The surface system can have platform and derrick assembly \n110\n (also referred to herein as a “rig”) positioned over the borehole \n102\n.', 'The assembly \n110\n can include a rotary table \n112\n, kelly \n114\n, hook \n116\n and rotary swivel \n118\n.', 'The drill string \n104\n is rotated by the rotary table \n112\n, energized by means not shown, which engages the kelly \n114\n at an upper end of the drill string \n104\n.', 'The drill string \n104\n is suspended from the hook \n116\n, attached to a traveling block (not shown), through the kelly \n114\n and a rotary swivel \n118\n which permits rotation of the drill string \n104\n relative to the hook \n116\n.', 'A top drive system can also be used.', 'Id. at ¶¶ [0023] & [0024].', 'The surface system can includes drilling fluid or mud \n120\n stored in a pit \n122\n formed at the well site \n100\n.', 'A pump \n124\n delivers the drilling fluid \n120\n to the interior of the drill string \n104\n via a port in the swivel \n118\n, causing the drilling fluid \n120\n to flow downwardly through the drill string \n103\n as indicated by the directional arrow \n126\n.', 'The drilling fluid \n120\n exits the drill string \n103\n via ports in the drill bit \n108\n, and the circulates upwardly through the annulus region between the outside of the drill string \n104\n and the wall of the borehole \n102\n, as indicated by the directional arrows \n128\n.', 'The drilling fluid \n120\n lubricates the drill bit \n108\n and carries formation cuttings up to the surface as the drilling fluid \n120\n is returned to the pit \n122\n for recirculation.', 'The BHA \n106\n includes a drill bit \n108\n and a variety of equipment \n130\n such as a logging-while-drilling (LWD) module \n132\n, a measuring-while-drilling (MWD) module \n134\n, a roto-steerable system and motor (not shown), and/or various other tools.', 'Id. at ¶¶', '[0025] & [0026].', 'In one possible implementation, the LWD module \n132\n is housed in a special type of drill collar, as is known in the art, and can include one or more of a plurality of logging tools including but not limited to a nuclear magnetic resonance (NMR) tool, a directional resistivity tool, and/or a sonic logging tool.', 'It will also be understood that more than one LWD and/or MWD tool can be employed.', 'The LWD module \n132\n can include capabilities of measuring, processing, and storing information, as well as for communicating with the surface equipment.', 'Id. at ¶ [0027].', 'The MWD module \n134\n can also be housed in a special type of drill collar, as is known in the art, and include one or more devices for measuring characteristics of the well environment, such as characteristics of the drill string and drill bit.', 'The MWD tool can further include an apparatus (not shown) for generating electrical power to the downhole system.', 'This may include a mud turbine generator powered by the flow of the drilling fluid \n120\n, it being understood that other power and/or battery systems may be employed.', 'The MWD module \n134\n can include one or more of a variety of measuring devices known in the art including, for example, a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.', 'Id. at ¶ [0028].', 'Data and information can be received by one or more sensors \n140\n.', 'The sensors \n140\n can be located on, above, or below the surface \n138\n in a variety of locations.', 'In one possible implementation, placement of sensors \n140\n can be independent of precise geometrical considerations.', 'Sensors \n140\n can be chosen from any sensing technology known in the art, including those capable of measuring electric or magnetic fields, including electrodes (such as stakes), magnetometers, coils, etc. Id. at ¶ [0029].', 'In one possible implementation, the sensors \n140\n receive information including LWD data and/or MWD data, which can be utilized to steer the drill bit \n108\n and any tools associated herewith.', 'In one implementation the information received by the sensors \n140\n can be filtered to decrease and/or cancel noise at a logging and control system \n142\n.', 'Logging and control system \n142\n can be used with a wide variety of oilfield applications, including a logging-while-drilling, artificial lift, measuring-while-drilling, etc. . . . .', 'Also, logging and control system \n142\n can be located at surface \n138\n, below surface \n138\n, proximate to borehole \n102\n, remote from borehole \n102\n, or any combination thereof.', 'Id. at ¶ [0030].', 'Alternatively, or additionally, the information received by the sensors \n140\n can be filtered to decrease and/or cancel noise at one or more other locations, including any configuration known in the art, such as in one or more handheld devices proximate and/or remote from the well site \n100\n, at a computer located at a remote command center, in the logging and control system \n142\n itself, etc. Id. at ¶ [0031].\n \nFIG.', '9\n illustrates an example global uplink chain \n200\n that can be used in conjunction with implementations of sensor noise reduction.', 'In one possible implementation, information \n202\n is collected or produced by equipment, such as equipment \n130\n.', 'In one possible aspect, information \n202\n can be represented as binary information.', 'Id. at ¶ [0032] incorporated herein by reference.', 'Information \n202\n can be modulated at a modulator \n204\n and transmitted to a demodulator \n206\n.', 'In one possible embodiment, modulator \n204\n produces a signal \n208\n, such as an electromagnetic signal that includes information/data \n202\n that is transmitted using any method and equipment known in the art.', 'Signal \n208\n can be susceptible to one or more noise sources \n210\n during transmission.', 'Noise sources \n210\n can include a wide variety of devices associated with electromagnetic energy such as, for example, mud motors, well heads, AC units, vehicles, welding operations, consumer electronics, electric perturbations from external sources for which no direct mitigation can be achieved and/or be caused by other environmental causes.', 'Id. at ¶ [0032] & [0033].', 'In one possible implementation, signal \n208\n with accompanying noise is received by sensors, such as sensors \n140\n.', 'The sensors provide measurements \n212\n corresponding to signal \n208\n with accompanying noise, to demodulator \n206\n.', 'Signal \n208\n with accompanying noise from noise sources \n210\n, is demodulated at demodulator \n206\n.', 'In one possible aspect, a noise reduction manager \n214\n can be employed to apply the concepts of array noise reduction to remove or reduce noise from demodulated signal \n208\n to produce a denoised signal.', 'Information (also referred to herein as “data”) \n202\n can be decoded from the denoised signal by a symbol estimator \n216\n using any symbol estimation techniques known in the art.', 'Id. at ¶ [0034].\n \nFIG.', '10\n illustrates an example observation model \n300\n in accordance with implementations of noise reduction.', 'As shown, four electromagnetic sources \n302\n, \n304\n, \n306\n, and \n308\n are present, though it will be understood that more or fewer electromagnetic sources can also be used.', 'Electromagnetic sources \n302\n-\n308\n can be represented by “so\n1 \n(t)”, “so\n2\n(t)”, “so\n3\n(t)” and “so\n4\n(t)”, respectively, where t is the time.', 'In one possible implementation, source \n302\n can be a telemetry source producing a signal to be extracted while sources \n304\n-\n308\n can be noise sources.', 'Measurement of the signal from source \n302\n can be achieved using sensors \n140\n, such as metal rods, coils, magnetometers, or any measurement device sensitive to an electric or magnetic field, located on the surface or in the well, for instance an electrode sensing the potential deep into the ground inside the casing.', 'In one possible implementation, the measurements can be obtained by amplification of the difference of electric potential measured between a “ref” sensor \n310\n (denotable as ref(t)) and other sensors \n312\n, \n314\n, \n316\n, \n318\n (which can be denoted respectively as “se\n1\n(t)”, “se\n2\n(t)”, “se\n3\n(t)”, “se\n4\n(t)” such that a voltage v\ni\n(t) measured at surface \n138\n can be proportional to a difference of potential v\ni \n(t)=G. (se\ni\n(t)−ref(t)), where G is a measurement gain.', 'Id. at ¶¶', '[0035] & [0036].\n \nIn one possible implementation, any signal obtained at surface \n138\n which is proportional to the electric or magnetic field on a surface location or proportional to the difference of the electric field or magnetic field between two surface locations can be denoted as v\ni\n(t).', 'In one possible aspect, according to the superposition principle, the relationship between the signals measured and the sources can be written as the following linear relationship:', '[\n \n \n \n \n \n \nv\n \n1\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \nv\n \ni\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n]\n \n \n=\n \n \n \n[\n \n \n \n \n \nm\n \n11\n \n \n \n \n…\n \n \n \n \nm\n \n \n1\n \n\u2062\n \nj\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \nm\n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n \n…\n \n \n \n \nm\n \nij\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \n \nso\n \n1\n \n \n\u2061\n \n \n(\n \nt\n \n)', '⋮\n \n \n \n \n \n \n \nso\n \nj\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n]\n \n \n \n \n \n \n \nIf the mixing matrix', '[m\nij\n] is invertible, the sources can be recovered using the inverse matrix (or pseudoinverse in the case i>j) as follows:', '[\n \n \n \n \n \n \nso\n \n1\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \nso\n \nj\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n]\n \n \n=\n \n \n \n \n \n[\n \n \n \n \n \nm\n \n11\n \n \n \n \n…\n \n \n \n \nm\n \n \n1\n \n\u2062\n \nj\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \nm\n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n \n…\n \n \n \n \nm\n \nij\n \n \n \n \n \n]\n \n \n+\n \n \n\u2061\n \n \n[\n \n \n \n \n \n \nv\n \n1\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \nv\n \ni\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n]\n \n \n \n=\n \n \n \n[\n \n \n \n \n \nd\n \n11\n \n \n \n \n…\n \n \n \n \nd\n \n \n1\n \n\u2062\n \ni\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \nd\n \n \nj\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n \n…\n \n \n \n \nd\n \nji\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \n \nv\n \n1\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n \n⋮\n \n \n \n \n \n \n \nv\n \ni\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n \n \n \n]', 'In one possible embodiment, the symbol “+” can denote either the inverse matrix (if i=j) or the pseudoinverse matrix (if i>j).', 'In one possible implementation, the matrix [d\nij\n] can be called the demixing matrix.', 'In one possible embodiment, the electromagnetic source so\n1 \n(t) can be recovered using following equation:\n \n \n \n \n \n \n \nso\n \n1\n \n \n\u2061\n \n \n(\n \nt\n \n)\n \n \n \n=\n \n \n \n∑\n \n \nk\n \n=\n \n1\n \n \ni\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nd\n \n \n1\n \n\u2062\n \nk\n \n \n \n·\n \n \n \nv\n \nk\n \n \n\u2061\n \n \n(\n \nt\n \n)', 'The vector [d\n1i\n] can be referred to as the “demixing vector”.', 'In one possible implementation, at surface \n138\n one or more measurements v\ni\n(t) from sensors \n140\n can be converted to a constellation space using demodulation (such as low pass filtering and/or down sampling) at the rate of one sample per symbol.', 'The samples obtained from the measurement v\ni\n(t) at the end of this procedure can be denoted z\ni \n[n] where n is the symbol index.', 'For example, in the constellation domain, the samples of the telemetry signal may be concentrated around the constellation centers of the modulation.', 'Id. at ¶¶', '[0038] & [0043].\n \nFIG.', '11\n shows example constellation centers \n400\n which might be expected in one implementation of the array noise reduction for a Quadrature Phase-Shift Keying (QPSK) modulation.', 'In \nFIG.', '11\n, four constellation centers \n400\n are shown, however it will be understood that more or less constellation centers can also be used.', 'Id. at ¶ [0045] Noise reduction in EM telemetry can be formulated as a reduction and/or minimization exercise under constraint.', 'See U.S. application Ser.', 'No. 14/517,197, unpublished, filed Oct. 17, 2014 at ¶¶', '[0050] to [0062], incorporated herein by reference.\n \nFIG.', '12\n illustrates an example data learning method \n1000\n that can be used with embodiments of sensor array noise reduction.', 'As shown an observation matrix z can be formed from samples \n1002\n of signals z\ni\n[n] \n1004\n such as signals \n208\n.', 'Signals \n1004\n can include, for example, information received by sensors \n140\n and can have already been demodulated, such as by demodulator \n206\n.', 'In an embodiment, a sliding window can be employed to access samples \n1002\n for use in estimating denoising parameters.', 'In one aspect, the samples \n1002\n correspond in time (i.e., the samples are associated with measurements made by sensors \n140\n during the same time frame).', 'In one implementation, a dispersion metric can be estimated for one or more demixing vectors in a demixing vector database \n1008\n.', 'FIG.', '13\n illustrate an example method \n1100\n for selecting and using a demixing vector.', 'FIG.', '14\n illustrates another example method \n1200\n with sensor array noise reduction.', 'FIGS.', '12-14\n illustrate example methods for implementing aspects of the noise reduction manager.', 'The methods are illustrated as a collection of blocks and other elements in a logical flow graph representing a sequence of operations that can be implemented in hardware, software, firmware, logic or any combination thereof.', 'The order in which the methods are described is not intended to be construed as a limitation, and any number of the described method blocks can be combined in any order to implement the methods, or alternate methods.', 'Additionally, individual blocks and/or elements may be deleted from the methods without departing from the spirit and scope of the subject matter described therein.', 'In the context of software, the blocks and other elements can represent computer instructions that, when executed by one or more processors, perform the recited operations.', 'Further, it is understood that computations in array noise reduction, including those discussed in \nFIGS.', "12-14\n, can be done in baseband and/or at the rate of carrier's frequency.", 'Further, it will be understood that a variety of frame structures and error correcting codes can be used.', 'Also, the nature of modulation may also be accounted for, i.e. a probability density function of the modulation can be utilized to provide information to discriminate a desired signal from noise in sensor array noise reduction.', 'Moreover, a linear combination of all measurements made, such as measurements made by sensors \n140\n, may be used in the array noise reduction manager to generate a de-noised signal.', 'See U.S. application Ser.', 'No. 14/517,197, filed Oct. 17, 2014, unpublished, ¶¶', '[0065] to [0080], incorporated herein by reference.', 'An example computing device for hosting the array noise reduction manager \n10\n can contain a processor and memory can be configured to implement various embodiments of array noise reduction, including hosting one or more databases, and one or more volatile data storage media.', 'See U.S. application Ser.', 'No. 14/517,197, filed Oct. 17, 2014, unpublished, ¶¶', '[0081] to [0092], incorporated herein by reference.', 'Stake Placement Optimization & Noise Mapping\n \nU.S. Patent Application No. 62/255,012 filed on Nov. 13, 2015 describes methodologies for placement of electrodes that can determine the spatial distribution of a signal caused by generating an electromagnetic field in an instrument disposed in a drill string.', 'In these methods, the electromagnetic field includes encoded measurements from at least one sensor associated with the instrument.', 'Voltages induced by noise are measured across at least one pair of spaced apart electrodes placed at a plurality of position at a surface location.', 'A spatial distribution of noise is estimated using the measured voltages.', 'Positions for placement of at least two electrodes are selected using the spatial distribution of signal and the spatial distribution of noise.', 'U.S. Pat.', 'Application No. 62/255,012 filed Nov. 13, 2015 ¶ [0008], [0031], and [0032] incorporated herein by reference.', 'More specifically, an electrode is placed radially away from another electrode placed at the wellhead.', 'Voltages are modeled as a function of EM signal transmitter depth from 3,000 feet to 12,000 feet deep.', 'Id. at ¶ [0033] incorporated by reference.', 'The voltage decreases as the transmitter depth increases.', 'Another radial configuration places two electrodes further away from the well head but aligned with the well.', 'Id. at ¶ [0034] incorporated by reference.', 'In this configuration, the radial position of the well is defined as zero distance.', 'In order to maximize the EM signal (sometimes referred to herein as “signal”) detected at the surface, the electrode pair should be along a line extending radially outward form the well head.', 'The strongest signal is found closest to the well head.', 'The most suitable distance, however, depends on the maximum intended depth of the wellbore and the electrical properties of the geological layers between the surface and the transmitter.', 'This distance may be computed prior to drilling using one or any number of finite element analysis.', 'Id. at ¶ [0035] incorporated by reference.', 'In short, voltage detected between the well head and an electrode is larger than the voltage detected between a pair of electrodes that are both spaced away from the well head.', 'However, the well head is the place of the largest noise amplitude.', 'Id.\n \nTherefore, mapping of noise at the surface is recommended to identify noise source through various methods (including the 4-parameter method) and to determine areas of smaller noise that may be suitable for placement of the electrodes.', 'Id. at ¶¶', '[0036] through [0039] incorporated by reference.', 'Furthermore, combining the results from the signal map and the noise map can enable the generation of a SNR map.', 'Id. at ¶ [0043] incorporated by reference.', 'The SNR can be generated by dividing the signal potential map by the noise potential map, that is, the signal amplitude value by the noise amplitude value, or by dividing a component of the electric field corresponding to the signal by a component of the electric field corresponding to the noise.', 'Id.\n \nDiversified Receivers for EM Telemetry\n \nIn a system containing a signal and coherent noise, it is desirable to eliminate the coherent noise from the received waveform.', 'In the case of EM telemetry, the signal consists of an electric field which is measured as the potential difference between two electrodes or stakes embedded in the ground.', 'This measured potential difference may also contain various coherent noise components, typically emanating from electrical equipment associated with the drilling rig.', 'Also, waveforms can be assumed to be contained within a relatively narrow bandwidth close to the nominal signal frequency, and filtering is applied to the measured data in order to exclude unwanted frequencies.', 'If the signal is an electric field Es in direction us and there is a noise component En in direction un, the field measured between points positioned in receiver direction ur is: \n \nE\nm\n=(\nu\ns\n·u\nr\n)·\nE\ns\n+(\nu\nn\n·u\nr\n)·\nE\nn \n \n \nIn this situation, the receiver electrodes can be positioned in such a manner so to maximize the signal to noise ratio (“SNR”).', 'Provided that us and un are non-parallel, this can be accomplished by positioning the receiver electrodes (also referred to herein as stakes) along a line orthogonal to the noise, so that (un·ur)·En=0 and the SNR is infinite.', 'However, in practical situations this cannot be accomplished, because there are normally multiple noise sources with a variety of orientations.', 'For example, with two noise sources the following equation applies: \n \nE\nm\n=(\nu\ns\n·u\nr\n)·\nE\ns\n+(\nu\nn1\n·u\nr\n)·\nE\nn1\n+(\nu\nn2\n·u\nr\n)·\nE\nn2', 'If the two noise components are uncorrelated, the problem is equivalent to finding the optimal receiver direction ur such that \n |(\nu\ns\n·u\nr\n)·', 'E\ns\n|\n2\n/[|(\nu\nn1\n·u\nr\n)·\nE\nn1\n|\n2\n+|(\nu\nn2\n·u\nr\n)·\nE\nn2\n|\n2\n]=maximum \n \nThis is not generally a practical approach, as the amplitudes and directions of coherent noise sources, and even the number of such noise sources, may be unknown and variable.', 'In addition, some random noise will be present, uncorrelated between the sources, which gives an additional advantage to maximizing signal strength.', 'It is therefore useful to provide a way by which the effective receiver direction or can be synthesized and adjusted in real time without physically moving the electrodes.', 'This adjustment can be performed by using a search algorithm to maximize the SNR at any particular time.', 'Also, the SNR can be estimated and displayed by the decoding algorithm.', "Synthetic Stake Rotation\n \nFor EM telemetry, in most instances, the receiver is a measurement between electrodes close to the earth's surface, which for practical reasons limits the receiver direction ur to the horizontal plane.", 'If two pairs of electrodes are arranged as approximately orthogonal pairs, and the potentials across both pairs are measured, then the electric field can be derived in any horizontal direction.', 'Furthermore, three stakes can achieve the desired electrode layout, if they are arranged in a L pattern.', 'Assuming that one electrode pair is separated by a distance Dx in direction x, and the other pair is separated by a distance Dy in direction y, then the electric field Ew in direction w may be found by linear superposition: \n \nEw=Vx/Dx\n·(\nw·x\n)+\nVy/Dy\n·(\nw·y\n)', 'The optimum direction w is found by passing the synthesized signal Ew to a decoder in which SNR is computed, and using a search algorithm for find the direction w which produces maximum SNR.', 'By applying this technique to real field data, as shown in \nFIGS.', '15 & 16\n, it has been demonstrated that improvements in SNR are possible.', 'FIG.', '15\n shows SNR computed from each of two orthogonal channels, labeled Sensor 1 (blue) and Sensor 2 (green).', 'FIG.', '16\n is similar, except that Sensor 2 (green) now refers to a synthesized signal, which corresponds to a direction 30 degrees away from the original Sensor 2.', 'A noticeable improvement in SNR is evident.', 'Vertical Magnetometer\n \nUsing a vertical magnetometer, the signal and noise components of the received waveform are separated.', 'When receiving a plurality of signals, there is variation in the relationship between signal and coherent noise.', 'However, it is possible to process a combination of channels together and thereby obtain a signal to noise ratio (“SNR”) better than that of either individual channel.', 'A characteristic of an EM telemetry signal is that current is carried along the drill string and casing, and tends to flow radially through the ground to and from the wellhead.', 'The associated magnetic field signal has a strong component circumferentially around the well at the surface, and relatively weak components in other directions.', 'In particular, the vertical component of the magnetic field signal measured at a point on the surface near the wellhead is small.', 'On the other hand, coherent noise normally emanates from electrical machinery associated with the drilling rig.', 'Noise may be radiating from cables or it may be caused by ground loops.', 'Because rig machinery and cables are laid out on the surface of the earth, such electrical noise tends to flow through the earth in a direction close to horizontal.', 'There is therefore an associated magnetic noise component in the vertical direction.', 'Therefore, a measurement of the vertical component Bz of the magnetic field at a surface location will have a relatively large contribution from coherent noise and a relatively small contribution from EM telemetry signal.', 'In contrast, the electrical EM signal will have a major horizontal component Er in a direction close to radial with respect to the wellhead.', 'Hence, the two signals may be regarded as combinations of signal and noise, such as: \n \nEr=a·S+b·N \n \n \nBz′=c·S+d·N \n \n where S and N are amplitudes of electrical signal and noise respectively, the prime (′) indicates a time derivative, and a/b≠c/d.', 'In this situation the noise can be eliminated by: \n \nS\n=(\nd·Er−b·Bz\n)/', '(\na·d−b·c\n)', 'The time derivative Bz′ may be implemented by a time shift of a quarter period for a narrow-band signal, or by a more complex technique such as Hilbert transform over a broader bandwidth.', 'Alternatively, the time derivative may be obtained by numerical finite-difference methods such as taking the difference between adjacent samples.', 'It will be observed that the calculated signal component S is a weighted sum of Er and Bz′. EM telemetry generally employs encoding schemes in which signal decoding is independent of amplitude, therefore a useful parameter proportional to S can be found with only one variable; the relative weighting factor k: \n \nS\nest\n=Er+k·Bz′\n \n \nThe optimum value for k may be found by providing an initial value, computing Sest in this way, and passing it to a decoder where SNR is computed.', 'A search algorithm may then be used to obtain the value of k which results in maximum SNR.', 'Example I\n \nRemote Location Test\n \nAs shown in \nFIG.', '17\n, a remote location \n402\n was placed at about 2,800 feet away from well site \n404\n.', 'The electromagnetic signal sent by the tool at 7,600 feet deep in the formation was simultaneously recorded at the well site and at the remote location.', 'Two channels were recorded at each location.', 'A first channel (channel 1) was oriented toward the rig and a second channel (channel 2) was deployed orthogonally to the first channel.', 'The tool sent a 6 Hz low-frequency signal into the formation.', 'FIGS.', '18A and 18B\n are spectrograms recorded at the well site.', 'The spectrograms show that high noise levels are measured at well site.', 'The background noise can be estimated to be about −120 dB and large noises were measured at specific frequencies such as 34 Hz, 25 Hz, 8 Hz and 5.6 Hz, for example.', 'The EM telemetry signal was identified at 6 Hz and its corresponding harmonics around it.', 'The signal to noise ratio (SNR) was measured at about 25 dB enabling a good decoding of the 6 Hz telemetry signal.', 'But the noise present at multiple frequencies prevented us from increasing the telemetry frequency.', 'Indeed, large noises recorded in the same frequency band as the EM signal would decrease the SNR and prevented the surface system from decoding without errors.', 'FIGS.', '19A and 19B\n are spectrograms recorded at the remote location and show the background noise at a remote location is lower than that at a well site and estimated at about −140 dB. Noises measured at specific frequencies at well site were not recorded by the remote set-up at the remote location indicating that the right noise has been attenuated.', 'However, the EM telemetry signal was identified at 6 Hz.', 'The amplitude of EM signal was measured at 14 microV on channel 1 and 4 microV on channel 2.', 'The SNR was measured at 17 dB for channel 1 and 13 dB for channel 2.', 'This test showed that EM-telemetry signals can be decoded at remote location and the large noises (noise components) measured at specific frequencies at a well site are not propagated to the remote location.', 'Hence, any frequency can be used to communicate with the EM tool.', 'Example II\n \nEM-Telemetry Field Test\n \nFIG.', '20\n shows an array of electrodes deployed in the vicinity of a drilling rig (not shown) and compared with an array of electrodes situated at approximately 1,500 feet away from the drilling well at Station 5.', 'Channel 2 (CH2) on station 6 is deployed at approximately 500 feet away from the drilling rig.', 'FIGS.', '21A and 21\n B show spectrograms for station 6 channel 1 (CH1) (top) and channel 2 (CH2) (bottom), close to the drilling well. \nFIGS.', '22A & 22B\n show spectrograms for station 5 channel 1 (CH1) (top) and channel 2 (CH2) (bottom), 1500 feet away from the rig.', 'In this test, the background noise levels were shown to be much lower on the channels of station 5 (below −100 dB) while the background noise levels at station 6 are approximately −90 dB. SNR measured at station 5 channel 1 were in the order of approximately 15 dB. SNR measured by the conventional channel connected between the well-head and the stakes were smaller than 10 dB. Moreover, during some time intervals, signal was measured by the conventional channel connected to the well-head and was completely buried in noise, preventing reliable EM-communication between the downhole tool and surface (encircled in red, station 6 channel 1).', 'Additional Uses for Electromagnetic-Telemetry Remote Sensing Wireless System', 'In addition to enabling EM-telemetry, the EM remote sensing wireless system described herein can also be used as an electrical resistivity tomography array or with an electrical resistivity tomography (“ERT”) technique in order to monitor hydrocarbon depletion over long time intervals.', 'Because the pair of electrodes (also referred to herein sometimes as “stakes”) are each placed at fixed location separated by a distance, that can be several hundred feet apart, the electrodes are sensitive to small voltage variations.', 'If a known current source injects a current into the ground at known amplitude, then the voltage sensed at each one of the nodes is a function of the resistivity between the electrodes.', 'The measured resistivity is representative not only of the top soil layer but of the formation deep into the ground.', 'For oil fields where Enhanced Oil Recovery (“EOR”) is used, typically water is injected, displacing the oil and creating a change in resistivity.', 'Monitoring the resistivity between a number of nodes that are distributed throughout an area that can be up to several square miles, and detecting where resistivity is dropping off over a long time interval provides an indication of hydrocarbon depletion.', 'Another use of the EM wireless array can be to detect and triangulate the exact location of fracking originated earthquakes.', 'For this purpose, a geophone can be placed into each one of the nodes where the output is digitized, streamed, and synchronized to absolute time by means of a GPS or similar system.', 'The exact distance from the epicenter to each station can then be computed by measuring the arrival time of the P and S waves to each station.', 'Standard seismic triangulation can be employed to determine the location of the origin.', 'The exact epicenter location is useful to understand the long term changes that are taking place in the hydrocarbon bearing formation and to correlate it to production rates or injection strategy.', 'This information also provides the ability to optimize the injection and help understand under what conditions earth quakes are generated in order to reduce its incidence, a matter of general public concern and detrimental to the oil-field industry.', 'Another application includes prognostic health monitoring of electrical equipment in the area.', 'With numerous pumps in the neighboring area where the EM monitoring stations are deployed, each node can monitor (indirectly) the health status of the pump motors.', 'This is done by analyzing the electrical noise acquired by the nodes.', 'An increase of harmonics or significant changes in the electric noise sensed by the nodes (also referred to sometimes herein as “EM remote nodes”) will indicate a possible malfunction or a safety hazard that requires attention.', 'See e.g., Evans, I. C. et al., The Price of Poor Power Quality, AADE-11-NTCE-7, AADE (2011), particularly at pages 15 to 16 incorporated herein by reference.', 'Additional uses for the systems and methods disclosed herein include borehole to surface EM-telemetry in order to map hydrocarbons.', 'See e.g., Marsala, A. F. et al., First Borehole to Surface Electromagnetic Survey in KSA: Reservoir Mapping and Monitoring at a New Scale, Saudi Aramco Journal of Technology, Winter 2011.', 'Specifically, Marsala et al. teach that “[i]n this pilot field test, the BSEM technology showed the potential to map waterfront movements in an area 4 km from the single well surveyed, evaluate the in sweep efficiency, identify bypassed/lagged oil zones and eventually monitor the fluid displacements if surveys are repeated over time.', 'The data quality of the recorded signals is highly satisfactory.', "Fluid distribution maps obtained with BSEM surveys are coherent with production data measured at the wells' locations, filling the knowledge gap of the inter-well area.", 'Id. at 36, ¶4 See also, Colombo, D. et al., Sensitivity Analysis of 3D Surface-Borehole CSEM for a Saudi Arabian Carbonate Reservoir, SEG Las Vegas 2012 Annual Meeting; Strack, K. et al., Full Field Array Electromagnetics: Advanced EM from the Surface the Borehole, Exploration to Reservoir Monitoring, 9th Biennial International Conference & Exposition on Petroleum Geophysics, Hyderabad 2012; Zhdanov, M. S., et al., Electromagnetic Monitoring of CO2 Sequestration in Deep Reservoirs, First Break, Vol. 31, 71-78, February 2013 (teaching electromagnetic monitoring of CO2 sequestration in deep reservoirs).', 'Zhdanov et al. teach “geophysical monitoring of carbon dioxide (CO injections in a deep reservoir has become an important component of carbon capture and storage.', 'Until recently, the seismic method was the dominant technique used for reservoir monitoring.”', 'Id. at 71, incorporated herein by reference.', 'They present “a feasibility study of permanent electromagnetic (EM) monitoring of CO2 sequestration in deep reservoir” Id.\n \nIn short, EM-telemetry, borehole-to-surface technology and cross-well EM technology, each endeavor to bring signal to the surface as efficiently and effectively as possible.', 'As such, each of these technologies can be used in the EM-telemetry remote sensing wireless system and methods described herein.', 'Furthermore, additional applications for the methods and systems described herein can include: waterfront movement; bypassed/lagged oil zones; fluid displacement; CO2 flooding; and hydraulic fracking monitoring.'] | ['1.', "An electromagnetic telemetry remote sensing wireless system, the system comprising:\na downhole tool deployed in a wellbore in a subterranean formation in a drilling area, the downhole tool configured to transmit a modulated electrical current into the formation and thereby generate an electromagnetic signal at Earth's surface; and\na surface system configured to receive, at the Earth's surface, the electromagnetic signal generated by the downhole tool, digitize the received signal, and wirelessly stream the digitized signal to an acquisition system at the Earth's surface,\nwherein each of a plurality of nodes of the surface system includes a distinct pair of first and second spaced apart electrodes, each of the plurality of nodes configured to (i) receive the electromagnetic signal transmitted from the tool as a voltage difference between the first and second spaced apart electrodes, (ii) digitize the voltage differences as digital information, and (iii) wirelessly stream the digital information from the digitized voltage differences to the acquisition system at the Earth's surface.", '2.', 'The system of claim 1, comprising a plurality of downhole tools deployed in a plurality of corresponding wellbores drilled in the drilling area, wherein each of the plurality of downhole tools transmits a modulated current into the formation thereby generating corresponding electromagnetic signals.', '3.', 'The system of claim 2, wherein each of the plurality of downhole tools operates in a corresponding pad.\n\n\n\n\n\n\n4.', 'The system of claim 1, wherein the acquisition system is located at a rig site.', '5.', 'The system of claim 1, wherein the acquisition system is configured to demodulate and decode the voltage differences to extract information encoded in the electromagnetic signal.', '6.', 'The system of claim 1, comprising at least first, second, and third of said nodes.\n\n\n\n\n\n\n7.', 'The system of claim 1, further comprising a noise reduction manager having a de-mixing vector, the de-mixing vector filtering a noise component of the signal and increasing a signal to noise ratio.', '8.', "A surface system for an electromagnetic telemetry remote sensing wireless system, the surface system comprising:\na surface acquisition system configured to receive wireless signals; and\na plurality of nodes deployed at Earth's surface in a drilling area remote from noise generating equipment at a rig and remote from a downhole tool transmitting the wireless signals, each of the plurality of nodes including a distinct pair of first and second spaced apart electrodes, each of the plurality of nodes being configured to: (i) receive the electromagnetic signal transmitted from the downhole tool as a voltage difference between the first and second spaced apart electrodes; (ii) digitize the voltage difference as digital information; and\n(iii) wirelessly stream the digital information from the digitized voltage differences to the surface acquisition system.", '9.', 'The system of claim 8, wherein the voltage difference includes a plurality of electromagnetic signals transmitted by a corresponding plurality of downhole tools deployed in corresponding wellbores drilled in the drilling area.', '10.', 'The system of claim 8, wherein the acquisition system is located at a rig site.', '11.', 'The system of claim 8, wherein the acquisition system is configured to demodulate and decode the voltage differences to extract information encoded in the electromagnetic signal.', '12.', 'The system of claim 8, comprising at least first, second, and third of said nodes.\n\n\n\n\n\n\n13.', 'The system of claim 8, further comprising a noise reduction manager having a de-mixing vector, the de-mixing vector filtering a noise component of the signal and increasing a signal to noise ratio.', '14.', "A method of EM-telemetry remote wireless sensing comprising the steps of:\ninstalling a plurality of nodes in a drilling area at Earth's surface, each of the nodes including a distinct pair of first and second spaced apart electrodes that are remote from noise-generating equipment at a rig site of the drilling area and which digitize voltage differences between the first and second spaced apart electrodes as voltage differences;\ntransmitting a signal from a downhole tool in a wellbore, the downhole tool being remote from the plurality of nodes;\nreceiving the signal transmitted from the downhole tool at the plurality of nodes and digitizing the voltage difference between the corresponding first and second electrodes as a digital signal;\nwirelessly streaming the digital signal to a data acquisition system deployed in the drilling area; and\ndemodulating and decoding the digitized voltage differences and thereby extracting information encoded in the transmitted signal.", '15.', 'The method of claim 14, further comprising\ndeploying the downhole tool in the wellbore, the wellbore drilled in a subterranean formation in the drilling area; and\ncausing the downhole tool to inject a modulated electrical current into the formation to transmit the signal.', '16.', 'The method of claim 15, further comprising\nsteering the downhole tool and/or adjusting other drilling process parameters based on the extracted information.\n\n\n\n\n\n\n17.', 'The method of claim 15, wherein\ndeploying the downhole tool comprises deploying a plurality of downhole tools in a corresponding plurality of wellbores drilled in the drilling area; and\ncausing the downhole tool to inject comprises causing each of the downhole tools to inject a corresponding modulated electrical current into the formation to transmit corresponding signals.', '18.', 'The system of claim 4, wherein the rig site is in the drilling area and the plurality of nodes are in the drilling area and remote from the rig site.', '19.', 'The system of claim 18, wherein one or more noise-generating devices are located at the rig site and are remote from the plurality of nodes.'] | ['FIG. 1 illustrates how the cable and the stakes can be placed around a rig infrastructure during job setup where stake placement is limited to a few hundred feet around rig and cable is connected to the measurement-while-drilling shack (“MWD”).; FIG.', '2 shows noise propagation as a function of depth and radial distance from the noise source.; FIG.', '3 shows the EM-telemetry signal decay of a downhole tool as a function of radial distance from the rig and tool depth.', 'The EM-telemetry signal amplitude from the downhole tool is attenuated as the distance increases radially from the rig and as the tool is positioned at a greater depth.', 'The black contour lines show that as the tool moves deeper in the well, the attenuation rate is lower as the signal is measured away from the rig.; FIG.', '4 illustrates downhole signal amplitude and rig noise amplitude at radial distance from the rig (plot for gap placed at depth approximately 3000 feet).; FIG.', '5 shows the signal to noise ratio computed at a range of radial distance points from the well and EM-tool at different gap depths.; FIG.', '6 illustrates one embodiment of the EM-telemetry remote wireless remote sensing network described herein.', 'Electrodes are placed in pairs and significantly away from the rig site.', 'An array is installed in the area and data streamed to an acquisition system.; FIG.', '7 illustrates nodes streaming electromagnetic (“EM”) sensed data to a number of rigs in the area.', '; FIG.', '8 illustrates an example well site in which embodiments of an array noise reduction manager can be employed.', '; FIG.', '9 illustrates an example global uplink chain that can be used with implementations of the array noise reduction manager.; FIG.', '10 illustrates an example observation model in accordance with implementations of the array noise reduction manager.; FIG.', '11 shows an example of what might be expected in a Quadrature Phase-Shift Keying (“QPSK”) modulation.;', 'FIG. 12 illustrates an example method associated with the array noise reduction manager.; FIG.', '13 illustrates an example method associated with the array noise reduction manager.; FIG.', '14 illustrates an example method associated with the array noise reduction manager.; FIG.', '15 shows signal to noise ratio (“SNR”) computed from each of two orthogonal channels, labeled Sensor 1 (blue) and Sensor 2 (green).; FIG.', '16 is similar to FIG.', '15 except that Sensor 2 (green) now refers to a synthesized signal, which corresponds to a direction 30 degrees away from the original Sensor 2.', 'A noticeable improvement in SNR is evident.', '; FIG.', '17 shows a remote set-up of Example 1 that was placed at approximately 2800 feet away from the well site.;', 'FIG.', '18A represents the well site recording at channel 1 of Example I.; FIG.', '18B represents the well site recording at channel 2 of Example I.; FIG.', '19A represents the remote location recording of channel 1 of Example I.; FIG.', '19B represents the remote location recording of channel 2 of Example I.; FIG.', '20 shows a test site described in Example II where the array of electrodes was deployed in the vicinity of the drilling rig and 1500 feet away from the right.; FIG.', '21A & FIG.', '21B show the spectrograms for station 6 channel 1 (top) and channel 2 (bottom), close to the drilling well described in Example II.; FIGS.', '22A & 22B show the spectrograms for station 5 channel 1 (top) and channel 2 (bottom), 1500 feet away from the rig described in Example II.; FIG.', '1 illustrates how the cable 144 hundreds of feet long and the stakes (referred to herein also as “electrodes”) 6 can be placed around a rig 14 infrastructure during job setup where stake placement is limited to a few hundred feet around rig and cable is connected to the measurement-while-drilling shack (“MWD”) 142 because of fencing 146, a road 218 and the like.;', 'FIG.', '4 illustrates, at one depth, the expected received signal at surface from the downhole tool and its decaying attenuation as it is measured away from the rig.', 'It also shows the rig noise amplitude and the noise attenuation as the distance from the rig increases.', 'In the near proximity of the well (few hundred feet), the noise and signal have both been observed to have high amplitude of similar order.', 'At relatively far distance (i.e., 3000 feet), the rig noise has decayed significantly while the downhole signal has been reduced only slightly.; FIG.', '5 shows the signal to noise ratio computed at selected radial distance points from the well and different gap depths.', 'While the tool is at shallow depths, the SNR is high for radial distance away from the well even in instances where electrode pair is placed within 2000 feet from the well.', 'However, when the tool is at a much greater depth (beyond 7000 feet for example), the SNR drops for stake locations near the well since the rig noise is high and tool signal is small.', 'However, the SNR is larger at farther locations where the stakes are 6000 feet, 8000 feet, etc. . . .', 'away from the well.', 'This example is a vertical well and the SNR and signal amplitude are for illustration purposes.', 'Actual values vary on a case by case basis depending on the formation resistivity, and rig noise amplitude and source.; FIG.', '6 illustrates one embodiment of an EM-telemetry remote sensing wireless network 2, also referred to herein sometimes as an EM-telemetry remote sensing wireless system.', 'FIG.', '7 illustrates three nodes 12a, 12b, 12c streaming EM sensed data to one or more rigs 14 (rigs 14a, 14b, 14c, 14d, 14e, 14f, 14g, and 14h in FIG.', '7) in the drilling area (sometimes referred to as “the area.”).', 'As described below, electrodes 6a, 6b, 6c, 6d, 6e, and 6f are placed significantly away from the rigs 14 to minimize rig noise pick-up.', 'Data can be streamed into a central data acquisition system 150 or to a number of acquisition system where data is processed and can be utilized.; FIG.', '8 illustrates a well site 100 in which embodiments of the noise reduction manager can be employed.', 'Well site 100 can be onshore or offshore.', 'In this example system, a borehole 102 is formed in a subsurface formation by rotary drilling; however, the noise reduction manager can be employed in well sites where directional drilling is being conducted.', 'A drill string 104 is suspended within the borehole 102 and has a bottom hole assembly (“BHA”) 106 having a drill bit 108 at its lower end.', 'The surface system can have platform and derrick assembly 110 (also referred to herein as a “rig”) positioned over the borehole 102.', 'The assembly 110 can include a rotary table 112, kelly 114, hook 116 and rotary swivel', '118.', 'The drill string 104 is rotated by the rotary table 112, energized by means not shown, which engages the kelly 114 at an upper end of the drill string 104.', 'The drill string 104 is suspended from the hook 116, attached to a traveling block (not shown), through the kelly 114 and a rotary swivel 118 which permits rotation of the drill string 104 relative to the hook 116.', 'A top drive system can also be used.', 'Id. at ¶¶ [0023] & [0024].; FIG. 9 illustrates an example global uplink chain 200 that can be used in conjunction with implementations of sensor noise reduction.', 'In one possible implementation, information 202 is collected or produced by equipment, such as equipment 130.', 'In one possible aspect, information 202 can be represented as binary information.', 'Id. at ¶ [0032] incorporated herein by reference.', 'Information 202 can be modulated at a modulator 204 and transmitted to a demodulator 206.', 'In one possible embodiment, modulator 204 produces a signal 208, such as an electromagnetic signal that includes information/data 202 that is transmitted using any method and equipment known in the art.', 'Signal 208 can be susceptible to one or more noise sources 210 during transmission.', 'Noise sources 210 can include a wide variety of devices associated with electromagnetic energy such as, for example, mud motors, well heads, AC units, vehicles, welding operations, consumer electronics, electric perturbations from external sources for which no direct mitigation can be achieved and/or be caused by other environmental causes.', 'Id. at ¶ [0032] & [0033].; FIG.', '10 illustrates an example observation model 300 in accordance with implementations of noise reduction.', 'As shown, four electromagnetic sources 302, 304, 306, and 308 are present, though it will be understood that more or fewer electromagnetic sources can also be used.', 'Electromagnetic sources 302-308 can be represented by “so1 (t)”, “so2(t)”, “so3(t)” and “so4(t)”, respectively, where t is the time.', 'In one possible implementation, source 302 can be a telemetry source producing a signal to be extracted while sources 304-308 can be noise sources.', 'Measurement of the signal from source 302 can be achieved using sensors 140, such as metal rods, coils, magnetometers, or any measurement device sensitive to an electric or magnetic field, located on the surface or in the well, for instance an electrode sensing the potential deep into the ground inside the casing.', 'In one possible implementation, the measurements can be obtained by amplification of the difference of electric potential measured between a “ref” sensor 310 (denotable as ref(t)) and other sensors 312, 314, 316, 318 (which can be denoted respectively as “se1(t)”, “se2(t)”, “se3(t)”, “se4(t)”', 'such that a voltage vi(t) measured at surface 138 can be proportional to a difference of potential vi (t)=G. (sei(t)−ref(t)), where G is a measurement gain.', 'Id. at ¶¶', '[0035] & [0036].; FIG.', '11 shows example constellation centers 400 which might be expected in one implementation of the array noise reduction for a Quadrature Phase-Shift Keying (QPSK) modulation.', 'In FIG.', '11, four constellation centers 400 are shown, however it will be understood that more or less constellation centers can also be used.', 'Id. at ¶ [0045] Noise reduction in EM telemetry can be formulated as a reduction and/or minimization exercise under constraint.', 'See U.S. application Ser.', 'No. 14/517,197, unpublished, filed Oct. 17, 2014 at ¶¶', '[0050] to [0062], incorporated herein by reference.', '; FIG.', '12 illustrates an example data learning method 1000 that can be used with embodiments of sensor array noise reduction.', 'As shown an observation matrix z can be formed from samples 1002 of signals zi[n] 1004 such as signals 208.', 'Signals 1004 can include, for example, information received by sensors 140 and can have already been demodulated, such as by demodulator 206.', 'In an embodiment, a sliding window can be employed to access samples 1002 for use in estimating denoising parameters.', 'In one aspect, the samples 1002 correspond in time (i.e., the samples are associated with measurements made by sensors 140 during the same time frame).', 'In one implementation, a dispersion metric can be estimated for one or more demixing vectors in a demixing vector database 1008.', '; FIG.', '13 illustrate an example method 1100 for selecting and using a demixing vector.', 'FIG.', '14 illustrates another example method 1200 with sensor array noise reduction.; FIGS.', '12-14 illustrate example methods for implementing aspects of the noise reduction manager.', 'The methods are illustrated as a collection of blocks and other elements in a logical flow graph representing a sequence of operations that can be implemented in hardware, software, firmware, logic or any combination thereof.', 'The order in which the methods are described is not intended to be construed as a limitation, and any number of the described method blocks can be combined in any order to implement the methods, or alternate methods.', 'Additionally, individual blocks and/or elements may be deleted from the methods without departing from the spirit and scope of the subject matter described therein.', 'In the context of software, the blocks and other elements can represent computer instructions that, when executed by one or more processors, perform the recited operations.; FIGS.', '19A and 19B are spectrograms recorded at the remote location and show the background noise at a remote location is lower than that at a well site and estimated at about −140 dB. Noises measured at specific frequencies at well site were not recorded by the remote set-up at the remote location indicating that the right noise has been attenuated.', 'However, the EM telemetry signal was identified at 6 Hz.', 'The amplitude of EM signal was measured at 14 microV on channel 1 and 4 microV on channel 2.', 'The SNR was measured at 17 dB for channel 1 and 13 dB for channel 2.', 'This test showed that EM-telemetry signals can be decoded at remote location and the large noises (noise components) measured at specific frequencies at a well site are not propagated to the remote location.', 'Hence, any frequency can be used to communicate with the EM tool.; FIG.', '20 shows an array of electrodes deployed in the vicinity of a drilling rig (not shown) and compared with an array of electrodes situated at approximately 1,500 feet away from the drilling well at Station 5.', 'Channel 2 (CH2) on station 6 is deployed at approximately 500 feet away from the drilling rig.; FIGS.', '21A and 21 B show spectrograms for station 6 channel 1 (CH1) (top) and channel 2 (CH2) (bottom), close to the drilling well.', 'FIGS.', '22A & 22B show spectrograms for station 5 channel 1 (CH1) (top) and channel 2 (CH2) (bottom), 1500 feet away from the rig.', 'In this test, the background noise levels were shown to be much lower on the channels of station 5 (below −100 dB) while the background noise levels at station 6 are approximately −90 dB. SNR measured at station 5 channel 1 were in the order of approximately 15 dB. SNR measured by the conventional channel connected between the well-head and the stakes were smaller than 10 dB. Moreover, during some time intervals, signal was measured by the conventional channel connected to the well-head and was completely buried in noise, preventing reliable EM-communication between the downhole tool and surface (encircled in red, station 6 channel 1).'] |
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US11085265 | Downhole sealing tool | Sep 25, 2015 | Oscar Rivas Diaz | Schlumberger Technology Corporation | International Search Report and Written Opinion issued in International Patent Appl. No. PCT/US2015/052167 dated Jan. 4, 2016; 23 pages. | 5279787; January 18, 1994; Oltrogge; 8151895; April 10, 2012; Kunz; 20020056553; May 16, 2002; Duhon; 20020158064; October 31, 2002; Spencer; 20040149418; August 5, 2004; Bosma; 20060037750; February 23, 2006; Wardlaw; 20120298359; November 29, 2012; Eden; 20130087335; April 11, 2013; Carragher; 20130199786; August 8, 2013; McConaghy; 20150064591; March 5, 2015; Haltiner, Jr. | 2011151271; December 2011; WO | ['A sealing tool for conveyance within a tubular member within a wellbore extending into a subterranean formation.', 'The sealing tool includes a mandrel and a eutectic sealing material disposed about the mandrel.', 'The eutectic sealing material has a eutectic temperature at which the eutectic sealing material melts.', 'The sealing tool also includes means for heating the eutectic sealing material to at least the eutectic temperature.', 'The eutectic sealing material is transferred onto an inner surface of the tubular member by activating the heating means to heat the eutectic sealing material to at least the eutectic temperature to melt the eutectic sealing material.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThis application claims priority to and the benefit of the following, the entire disclosures of which are hereby incorporated herein by reference: U.S. Provisional Application No. 62/055,166, titled “DOWNHOLE EUTECTIC MATERIAL PATCH,” filed Sep. 25, 2014; U.S. Provisional Application No. 62/055,149, titled “DOWNHOLE EUTECTIC MATERIAL HEATING ASSEMBLY AND METHOD,” filed Sep. 25, 2014; and U.S. Provisional Application No. 62/055,180, titled “DOWNHOLE EUTECTIC MATERIAL PATCH WITH ANCHOR,” filed Sep. 25, 2014.\n \nBACKGROUND OF THE DISCLOSURE', 'The present disclosure is related in general to wellsite equipment, such as oilfield surface equipment, downhole assemblies, coiled tubing (CT) assemblies, slickline assemblies, and the like.', 'The present disclosure is also related to the use of downhole sealing materials.', "Coiled tubing is a technology that has been expanding its range of application since its introduction to the oil industry in the 1960's.", 'Its ability to pass through completion tubulars and the wide array of tools and technologies that may be used in conjunction with it make coiled tubing a versatile technology.', 'Typical coiled tubing apparatus include surface pumping facilities, a coiled tubing string mounted on a reel, a method to convey the coiled tubing into and out of the wellbore (such as an injector head or the like), and surface control apparatus at the wellhead.', 'Coiled tubing has been utilized for performing well treatment and/or well intervention operations in existing wellbores, such as, but not limited to, hydraulic fracturing, matrix acidizing, milling, perforating, coiled tubing drilling, and the like.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus that includes a sealing tool for conveyance within a tubular member within a wellbore extending into a subterranean formation.', 'The sealing tool includes a mandrel and a eutectic sealing material disposed about the mandrel.', 'The eutectic sealing material has a eutectic temperature at which the eutectic sealing material melts.', 'The sealing tool also includes means for heating the eutectic sealing material to at least the eutectic temperature.', 'The present disclosure also introduces a method that includes conveying a sealing tool within a tubular member within a wellbore extending into a subterranean formation.', 'The sealing tool includes a mandrel, a eutectic sealing material disposed about the mandrel, and means for heating the eutectic sealing material.', 'The eutectic sealing material is transferred onto an inner surface of the tubular member by activating the heating means to heat the eutectic sealing material to at least the eutectic temperature to melt the eutectic sealing material.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is best understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIGS.', '2 and 3\n are schematic sectional views of a portion of an example implementation of the apparatus shown in \nFIG.', '1\n at different stages of operation.', 'FIGS.', '4 and 5\n are schematic sectional views of a portion of another example implementation of the apparatus shown in \nFIGS.', '1 and 2\n at different stages of operation.', 'FIG.', '6\n is a schematic axial view of a portion of another example implementation of the apparatus shown in \nFIGS.', '1 and 2\n according to one or more aspects of the present disclosure.', 'FIG.', '7\n is a schematic side view of the apparatus shown in \nFIG.', '6\n according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.\n \nFIG.', '1\n is a schematic view of at least a portion of an example wellsite system \n100\n according to one or more aspects of the present disclosure, representing an example coiled tubing environment in which one or more apparatus described herein may be implemented, including to perform one or more methods and/or processes also described herein.', 'However, it is to be understood that aspects of the present disclosure are also applicable to implementations in which wireline, slickline, and/or other conveyance means are utilized instead of or in addition to coiled tubing.', 'FIG.', '1\n depicts a wellsite surface \n105\n upon which various wellsite equipment is disposed proximate a wellbore \n120\n. \nFIG.', '1\n also depicts a sectional view of the Earth below the wellsite surface \n105\n containing the wellbore \n120\n, as well as a tool string \n110\n positioned within the wellbore \n120\n.', 'The wellbore \n120\n extends from the wellsite surface \n105\n into one or more subterranean formations \n130\n.', 'When utilized in cased-hole implementations, a cement sheath \n124\n may secure a casing \n122\n within the wellbore \n120\n.', 'However, one or more aspects of the present disclosure are also applicable to open-hole implementations, in which the cement sheath \n124\n and the casing \n122\n have not yet been installed in the wellbore \n120\n.', 'At the wellsite surface \n105\n, the wellsite system \n100\n may comprise a control center \n180\n comprising processing and communication equipment operable to send, receive, and process electrical and/or optical signals.', 'The control center \n180\n is operable to control at least some aspects of operations of the wellsite system \n100\n.', 'The control center \n180\n may comprise an electrical power source operable to supply electrical power to components of the wellsite system \n100\n, including the tool string \n110\n.', 'The electrical signals, the optical signals, and the electrical power may be transmitted between the control center \n180\n and the tool string \n110\n via conduits \n184\n, \n186\n extending between the control center \n180\n and the tool string \n110\n.', 'The conduits \n184\n, \n186\n may each comprise one or more electrical conductors, such as electrical wires, lines, or cables, which may transmit electrical power and/or electrical control signals from the control center \n180\n to the tool string \n110\n, as well as electrical sensor, feedback, and/or other data signals from the tool string \n110\n to the control center \n180\n.', 'The conduits \n184\n, \n186\n may each further comprise one or more optical conductors, such as fiber optic cables, which may transmit light pulses and/or other optical signals (hereafter collectively referred to as optical signals) between the control center \n180\n and the tool string \n110\n.', 'The conduits \n184\n, \n186\n may collectively comprise a plurality of conduits or conduit portions interconnected in series and/or in parallel and extending between the control center \n180\n and the tool string \n110\n.', 'For example, as depicted in the example implementation of \nFIG.', '1\n, the conduit \n184\n extends between the control center \n180\n and a reel \n160\n of coiled tubing \n162\n, such that the conduit \n184\n may remain substantially stationary with respect to the wellsite surface \n105\n.', 'The conduit \n186\n extends between the reel \n160\n and the tool string \n110\n via the coiled tubing \n162\n, including the coiled tubing \n162\n spooled on the reel \n160\n.', 'Thus, the conduit \n186\n may rotate and otherwise move with respect to the wellsite surface \n105\n.', 'The reel \n160\n may be rotatably supported on the wellsite surface \n105\n by a stationary base \n164\n, such that the reel \n160\n may be rotated to advance and retract the coiled tubing \n162\n within the wellbore \n120\n.', 'The conduit \n186\n may be contained within an internal passage of the coiled tubing \n162\n, secured externally to the coiled tubing \n162\n, or embedded within the structure of the coiled tubing \n162\n.', 'A rotary joint \n150\n, such as may be known in the art as a collector, provides an interface between the stationary conduit \n184\n and the moving conduit \n186\n.', 'The wellsite system \n100\n may further comprise a fluid source \n140\n from which fluid may be conveyed by a fluid conduit \n142\n to the reel \n160\n of coiled tubing \n162\n.', 'The fluid conduit \n142\n may be fluidly connected to the coiled tubing \n162\n by a swivel or other rotating coupling (obstructed from view in \nFIG.', '1\n).', 'The coiled tubing \n162\n may be utilized to convey the fluid received from the fluid source \n140\n to the tool string \n110\n coupled at the downhole end of the coiled tubing \n162\n within the wellbore \n120\n.', 'The wellsite system \n100\n may further comprise a support structure \n170\n, such as may include or otherwise support a coiled tubing injector \n171\n and/or other apparatus operable to facilitate movement of the coiled tubing \n162\n in the wellbore \n120\n.', 'Other support structures may be also included, such as a derrick, a crane, a mast, a tripod, and/or other structures.', 'A diverter \n172\n, a blow-out preventer (BOP) \n173\n, and/or a fluid handling system \n174\n may also be included as part of the wellsite system \n100\n.', 'For example, during deployment, the coiled tubing \n162\n may be passed from the injector \n171\n, through the diverter \n172\n and the BOP \n173\n, and into the wellbore \n120\n.', 'The tool string \n110\n may be conveyed along the wellbore \n120\n via the coiled tubing \n162\n in conjunction with the coiled tubing injector \n171\n, such as may be operable to apply an adjustable uphole and downhole force to the coiled tubing \n162\n to advance and retract the tool string \n110\n within the wellbore \n120\n.', 'During some downhole operations, fluid may be conveyed through the coiled tubing \n162\n and may exit into the wellbore \n120\n adjacent to the tool string \n110\n.', 'For example, the fluid may be directed into an annular area between the sidewall of the wellbore \n120\n and the tool string \n110\n through one or more ports (not shown) in the coiled tubing \n162\n and/or the tool string \n110\n.', 'Thereafter, the fluid may flow in the uphole direction and out of the wellbore \n120\n.', 'The diverter \n172\n may direct the returning fluid to the fluid handling system \n174\n through one or more conduits \n176\n.', 'The fluid handling system \n174\n may be operable to clean the fluid and/or prevent the fluid from escaping into the environment.', 'The fluid may then be returned to the fluid source \n140\n or otherwise contained for later use, treatment, and/or disposal.', 'The tool string \n110\n may be a single or multiple modules, sensors, and/or tools \n112\n, hereafter collectively referred to as the tools \n112\n.', 'For example, the tool string \n110\n and/or one or more of the tools \n112\n may be or comprise at least a portion of a monitoring tool, an acoustic tool, a density tool, a drilling tool, an electromagnetic (EM) tool, a formation testing tool, a fluid sampling tool, a formation logging tool, a formation measurement tool, a gravity tool, a magnetic resonance tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a surveying tool, and/or a tough logging condition (TLC) tool, among other examples within the scope of the present disclosure.', 'One or more of the tools \n112\n may be or comprise a casing collar locator (CCL) operable to detect ends of casing collars by sensing a magnetic irregularity caused by the relatively high mass of an end of a collar of the casing \n122\n.', 'One or more of the tools \n112\n may also or instead be or comprise a gamma ray (GR) tool that may be utilized for depth correlation.', 'The CCL and/or GR tools may transmit signals in real-time to wellsite surface equipment, such as the control center \n180\n, via the conduits \n184\n, \n186\n.', 'The CCL and/or GR tool signals may be utilized to determine the position of the tool string \n110\n, such as with respect to known casing collar numbers and/or positions within the wellbore \n120\n.', 'Therefore, the CCL and/or GR tools may be utilized to detect and/or log the location of the tool string \n110\n within the wellbore \n120\n, such as during intervention operations as described below.', 'One or more of the tools \n112\n may also comprise one or more sensors \n113\n.', 'The sensors \n113\n may include inclination and/or other orientation sensors, such as accelerometers, magnetometers, gyroscopic sensors, and/or other sensors for utilization in determining the orientation of the tool string \n110\n relative to the wellbore \n120\n.', 'The sensors \n113\n may also or instead include sensors for utilization in determining petrophysical and/or geophysical parameters of a portion of the formation \n130\n along the wellbore \n120\n, such as for measuring and/or detecting one or more of pressure, temperature, strain, composition, and/or electrical resistivity, among other examples within the scope of the present disclosure.', 'The sensors \n113\n may also or instead include fluid sensors for utilization in detecting the presence of fluid, a certain fluid, or a type of fluid within the tool string \n110\n or the wellbore \n120\n.', 'The sensors \n113\n may also or instead include fluid sensors for utilization in measuring properties and/or determining composition of fluid sampled from the wellbore \n120\n and/or the formation \n130\n, such as spectrometers, fluorescence sensors, optical fluid analyzers, density sensors, viscosity sensors, pressure sensors, and/or temperature sensors, among other examples within the scope of the present disclosure.', 'One or more of the tools \n112\n may also be or comprise perforating guns and/or other perforating tools.', 'For example, such a perforating tool may be positioned in the tool string \n110\n uphole of the sealing tool \n200\n described below, such as in implementations in which the sealing tool \n200\n may be utilized to plug and abandon a lower zone of the wellbore \n120\n, the sealing tool \n200\n may be then be disconnected from the tool string \n110\n, and then the perforating tool may be utilized to perforate a new zone above the abandoned zone, and such sequence of operations could be performed without removing the tool string \n110\n from the wellbore \n120\n.', 'The wellsite system \n100\n may also include a telemetry system comprising one or more downhole telemetry tools \n115\n (such as may be implemented as one or more of the tools \n112\n) and/or a portion of the control center \n180\n to facilitate communication between the tool string \n110\n and the control center \n180\n.', 'The telemetry system may be a wired electrical telemetry system and/or an optical telemetry system, among other examples.', 'One of the tools \n112\n, designated in \nFIG.', '1\n by reference number \n200\n, is a sealing tool operable to seal and/or repair a tubular member downhole, such as the casing \n122\n and/or a portion of completion/production tubular member \n114\n.', 'For example, the sealing tool \n200\n may be operable to smooth out, patch, plug, or otherwise repair holes, perforations, scrapes, deformations, and other damaged portions of the tubular member.', 'FIGS.', '2 and 3\n are schematic sectional views of at least a portion of an example implementation of the sealing tool \n200\n shown in \nFIG.', '1\n.', 'The following description refers to \nFIGS.', '1-3\n, collectively.', 'The sealing tool \n200\n comprises a mandrel \n202\n directly or indirectly coupled to another portion of the tool string \n110\n, such as an adjacent other one of the tools \n112\n of the tool string \n110\n.', 'The sealing tool \n200\n also carries or otherwise comprises a eutectic sealing material \n204\n disposed about the mandrel \n202\n.', 'The eutectic sealing material \n204\n is disposed about the mandrel \n202\n in a manner permitting the eutectic sealing material \n204\n to remain about the mandrel \n202\n during downhole conveyance operations.', 'For example, the eutectic sealing material \n204\n may be provided in the form of one or more rings (not shown) that are stacked or otherwise disposed about the mandrel \n202\n, although other arrangements are also within the scope of the present disclosure.', 'The eutectic sealing material \n204\n may be selected based on, for example, anticipated wellbore conditions and a well intervention operation to be performed with the sealing tool \n200\n.', 'The eutectic sealing material \n204\n is an alloy or other combination of elements, compounds, and/or other constituents formulated such that the melting point of the eutectic sealing material \n204\n is lower than the melting points of each of the individual constituents.', 'The melting temperature of the eutectic sealing material \n204\n is known as the eutectic temperature.', 'On a phase diagram (not shown), the intersection of the eutectic temperature and the eutectic composition gives the eutectic point.', 'The eutectic temperature depends on the amounts and perhaps relative orientations of its constituents.', 'The eutectic sealing material \n204\n may comprise a bismuth-based alloy, such as may substantially comprise 58% bismuth and 42% tin, by weight.', 'However, other eutectic alloys are also within the scope of the present disclosure.', 'After positioning the sealing tool \n200\n relative to the casing \n122\n, the completion/production tubular member \n114\n, and/or other tubular member that is the subject of the intervention operation, which is generally designated in \nFIGS.', '2 and 3\n by reference numeral \n224\n, the eutectic sealing material \n204\n is transformed into a eutectic state by heating via electrical, chemical, and/or other heating means \n206\n.', 'The eutectic sealing material \n204\n then melts, transforming from a solid state to a liquid or melted state.', 'When in the melted state, the eutectic sealing material \n204\n may be molded or otherwise formed to perform the well intervention operation.', 'The heating means \n206\n may comprise one or more electrical heating coils or other elements (not shown) disposed within the mandrel \n202\n substantially along the length of the eutectic sealing material \n204\n.', 'Electric power may be provided to the heating means \n206\n via one or more electrical conductors of the conduits \n184\n, \n186\n.', 'The tool string \n100\n may also comprise an internal alternator or generator (not shown) for generating heat or electrical energy to heat the eutectic sealing material \n204\n.', 'The heating means \n206\n may also or instead comprise one or more thermites and/or other heat-generating chemical elements, such as may be disposed in solid or powder form substantially along the length of the eutectic sealing material \n204\n, whether within the mandrel \n202\n or between the mandrel \n202\n and the eutectic sealing material \n204\n.', 'The heat-generating chemical elements may be activated to generate heat via chemical reaction, thus melting the eutectic sealing material \n204\n about the mandrel \n202\n.', 'A downhole portion \n208\n of the mandrel \n202\n at or near the downhole end of the mandrel \n202\n has a larger outer diameter \n216\n relative to the diameter \n217\n of the rest of the mandrel \n202\n.', 'The transition between the diameters \n216\n, \n217\n defines a spreader \n210\n that urges the melted eutectic sealing material \n204\n radially outward toward the tubular member \n224\n, such as to provide a path for a subsequent downhole tool or fluid placement within the wellbore \n20\n.', 'The spreader \n210\n extends circumferentially around the mandrel \n202\n, and tapers diagonally with respect to a longitudinal axis \n214\n of the sealing tool \n200\n, such as to form a substantially frustoconical surface.', 'For example, as depicted in \nFIG.', '3\n, after the heating means \n206\n is activated, the melted eutectic sealing material \n204\n may flow in a downhole direction and be urged onto the inner surface \n225\n of the tubular member \n225\n.', 'The mandrel \n202\n may also be pulled in the uphole direction with respect to the tubular member \n224\n by the coiled tubing \n162\n and/or other conveyance means, such that the spreader \n210\n may further urge the melted eutectic sealing material \n204\n onto the inner surface \n225\n of the tubular member \n224\n.', 'As the melted eutectic sealing material \n204\n is squeezed between the downhole portion \n208\n of the mandrel \n202\n and the tubular member \n224\n, the downhole portion \n208\n contacts and absorbs heat from the melted eutectic sealing material \n204\n.', 'Consequently, the eutectic sealing material \n204\n cools and solidifies, thus conformingly adhering to the inner surface \n225\n of the tubular member \n224\n without further flowing along the tubular member \n224\n or otherwise deforming from the shape formed by the spreader \n210\n.', 'Accordingly, a layer \n205\n of eutectic sealing material \n204\n is formed along the inner surface \n225\n of the tubular member \n224\n.', 'The layer \n205\n may form a patch for a damaged portion of the tubular member \n224\n, and/or may provide a new or repaired inner surface of the tubular member \n224\n, such as may permit subsequent downhole tool or fluid placement within the tubular member \n224\n.', 'The mandrel \n102\n may be moved in the uphole direction at a speed that permits the melted eutectic sealing material \n204\n to cool to a temperature at which the viscosity and/or other properties of the eutectic sealing material \n204\n reach an intended level of solidity.', 'The properties of the eutectic sealing material \n104\n may be selected such that the eutectic sealing material \n204\n chemically and/or otherwise bonds with the inner surface \n225\n of the tubular member \n224\n and/or otherwise permits the eutectic sealing material \n204\n to be molded and/or otherwise shaped by the spreader \n210\n.', 'The diameter \n216\n of the downhole portion \n208\n of the mandrel \n202\n may be slightly smaller than the inner diameter \n232\n of the tubular member \n224\n.', 'For example, the outer diameter \n216\n may be selected based on the inner diameter \n232\n and an intended thickness of the layer \n205\n of eutectic sealing material \n204\n to be applied to the inner surface \n225\n of the tubular member \n224\n.', 'The spreader \n210\n may also comprise one or more a flexible scoopers, bristles, and/or other filaments (not shown) operable to distribute the melted eutectic sealing material \n204\n around the inner surface \n225\n of the tubular member \n224\n.', 'Although shown as being integral to the downhole portion \n208\n of the mandrel \n202\n, the spreader \n210\n may be a separate and distinct portion of the sealing tool \n200\n connected to the mandrel \n202\n.', 'The downhole portion \n208\n of the mandrel \n202\n may be substantially solid or, as shown in \nFIGS.', '2 and 3\n, may comprise recesses, holes, fins, and/or other heat-dissipating features \n209\n extending into or from the outer surface \n212\n of the downhole portion \n208\n and/or a cavity \n211\n extending into the downhole end of the mandrel \n202\n.', 'Such features \n209\n may aid in absorbing heat from the melted eutectic sealing material \n204\n and/or in transferring heat from the melted eutectic sealing material \n204\n to the surrounding environment, which may include water and/or other fluids within the tubular member \n224\n.', 'The thickness \n218\n of the layer \n205\n of eutectic sealing material formed on the inner surface \n225\n of the tubular member \n224\n may range between about 5 millimeters (mm) and about 25 mm.', 'However, the thickness \n218\n may have other values within the scope of the present disclosure.', 'FIGS.', '4 and 5\n are schematic sectional views of another example implementation of the sealing tool \n200\n shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure, and designated in \nFIGS.', '4 and 5\n by reference number \n300\n.', 'Unless described otherwise, the sealing tool \n300\n is substantially similar to the sealing tool \n200\n shown in \nFIGS.', '2 and 3\n, including where indicated by like reference numbers.', 'The following description refers to \nFIGS.', '1, 4, and 5\n, collectively.', 'The sealing tool \n300\n is depicted in \nFIGS.', '4 and 5\n as being disposed within a portion of the wellbore \n120\n that does not include completion/production tubing \n114\n,', 'but that does include a damaged portion \n334\n extending into the casing \n122\n and perhaps the cement sheath \n124\n and/or the formation \n130\n.', 'The sealing tool \n300\n comprises a plug, packer, anchor, and/or other sealing member \n302\n that fixedly engages with the casing \n122\n and slidably engages with the mandrel \n202\n to form a fluid seal between the casing \n122\n and the mandrel \n202\n.', 'The sealing member \n302\n may function to constrain the melted eutectic sealing material \n204\n from flowing in the uphole direction beyond the sealing member \n302\n.', 'In \nFIG.', '4\n, the sealing tool \n300\n is depicted during a sealing operation stage in which the heating means \n206\n has melted a portion of the eutectic sealing material \n204\n and the mandrel \n202\n has been moved in the uphole direction with respect to the casing \n122\n, thereby forming a layer \n205\n of eutectic sealing material on the inner surface \n123\n of the casing \n122\n, as described above with respect to the layer \n205\n formed on the inner surface \n225\n of the tubular member \n224\n shown in \nFIG.', '3\n.', 'The remaining eutectic sealing material \n204\n is constrained within an annular region \n336\n generally defined in an axial direction by the sealing member \n302\n and the spreader \n210\n and in a radial direction by the mandrel \n202\n and the inner surface \n123\n of the casing \n122\n.', 'Consequently, the mandrel \n202\n moves in the uphole direction, the volume of the annular region \n336\n decreases.', 'Accordingly, upon melting, the constrained portion of the eutectic sealing material \n204\n within the annular region \n336\n is pressurized.', 'Such pressurization urges the melted eutectic sealing material \n204\n into the damaged portion \n334\n.', 'Thus, as shown in \nFIG.', '5\n, as the mandrel \n202\n moves past the damaged portion \n334\n, the damaged portion \n334\n may be sealed with the melted eutectic sealing material \n204\n, including implementations in which the melted eutectic sealing material \n204\n flows into the damaged portion \n334\n, and perhaps filling cracks, cavities, and/or perforations extending into the casing \n122\n, the cement sheath \n124\n, and/or the formation \n130\n.', 'The sealing member \n302\n and/or another portion of the sealing tool \n300\n may also comprise one or more releasing features (not shown), such as collapsing dogs, shear pins, or the like.', 'Such releasing features may be utilized for disengaging the sealing member \n302\n from the casing \n122\n to permit the tool string \n110\n to be retrieved to the surface.', 'The sealing tools \n200\n, \n300\n described above may also or instead be operable to perform well abandonment operations.', 'For example, the sealing tools \n200\n, \n300\n may be deployed within the wellbore \n120\n and subsequently operated to fill the wellbore \n120\n in order to plug and abandon the wellbore \n120\n.', 'The sealing tools \n200\n, \n300\n may also be operated as described above but allowing melted eutectic sealing material \n204\n to solidify around the downhole portion \n208\n of the mandrel \n202\n without removing the downhole portion \n208\n before such solidification, such that the downhole portion \n208\n and the solidified eutectic sealing material \n204\n collectively form a solid plug preventing communication of wellbore fluids between portions of the wellbore \n120\n above and below the plug.', 'The downhole portion \n208\n of the mandrel \n202\n may then be severed from the mandrel \n202\n, or the sealing tool \n200\n, \n300\n may be disengaged from the rest of the tool string \n110\n and left in the wellbore \n120\n.', 'FIG.', '6\n is a schematic top end view of another example implementation of the sealing tool \n200\n shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure, and designated in \nFIG.', '6\n by reference number \n400\n.', 'Unless described otherwise, the sealing tool \n400\n is substantially similar to the sealing tool \n200\n shown in \nFIGS.', '2 and 3\n, including where indicated by like reference numbers.', 'The sealing tool \n400\n includes a brittle material \n402\n interposing the mandrel \n202\n and the eutectic sealing material \n204\n, and a plurality of heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n disposed at least partially within the eutectic sealing material \n204\n and/or between the eutectic sealing material \n204\n and the brittle material \n402\n. \nFIG.', '7\n is a side view of the sealing tool \n400\n with the eutectic sealing material \n204\n, one of the heating element probes \n406\n, one of the heating element probes \n408\n, and one of the heating element probes \n410\n removed to show an example implementation of the heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n.', 'Although removed from view in \nFIG.', '6\n for the sake of clarity, \nFIG.', '7\n also depicts a housing \n470\n of the sealing tool \n400\n.', 'When the eutectic sealing material \n204\n is in its original, pre-melted form, the eutectic sealing material \n204\n is free from an interior portion of the housing \n470\n, but the housing \n470\n axially retains the eutectic sealing material \n204\n around the mandrel \n202\n.', 'However, other means for retaining the eutectic sealing material \n204\n around the mandrel \n202\n are also within the scope of the present disclosure.', '(It is also noted that the sealing tools \n200\n, \n300\n described above may comprise a similar housing and/or other means for retaining the pre-melted eutectic sealing material \n204\n around the mandrel \n202\n).', 'The following description refers to \nFIGS.', '1, 6, and 7\n, respectively.', 'The sealing tool \n400\n may be utilized in a horizontal portion of the tubular member \n224\n.', 'Thus, \nFIGS.', '6 and 7\n include reference number \n440\n indicating the bottom (relative to the direction of gravity \n401\n) of the inner surface \n225\n of the tubular member \n224\n, and reference number \n442\n indicating the top of the inner surface \n225\n of the tubular member \n224\n.', 'Reference number \n444\n indicates the uphole end of the sealing tool \n400\n, and reference number \n446\n indicates the downhole end of the sealing tool \n400\n.', 'It is noted, however, that the sealing tool \n400\n may also be utilized in vertical and other portions of the tubular member \n224\n.', 'The brittle material \n402\n includes one or more portions collectively disposed between the mandrel \n202\n and the eutectic sealing material \n204\n.', 'For example, the brittle material \n402\n may be a layer formed substantially continuously around the mandrel \n202\n along a longitudinal length similar to the longitudinal length of the eutectic sealing material \n204\n.', 'The brittle material \n402\n may be or comprise a lattice or honeycombed steel material or the like, by which the eutectic sealing material \n204\n may separate from the mandrel \n202\n during sealing operations.', 'The heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n may be utilized instead of or in addition to the heating means \n206\n shown in \nFIG.', '2\n.', 'The heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n may be or comprise electrical heating coils and/or other elements operable to generate heat to melt the eutectic sealing material \n204\n.', 'The heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n may be electrically energized as described above with respect to the electrical heating element implementation of the heating means \n206\n shown in \nFIG.', '2\n, including via electrical conductors \n401\n (schematically depicted in \nFIG.', '6\n as dotted lines) electrically connected with one or more electrical conductors (not shown) internal to the mandrel \n202\n.', 'Each heating element probe \n404\n, \n406\n, \n408\n, \n410\n, \n412\n may be individually activated to heat and melt the eutectic sealing material \n204\n that is in contact with that heating element probe \n404\n, \n406\n, \n408\n, \n410\n, \n412\n.', 'As shown in \nFIG.', '7\n, the heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n substantially extend along the longitudinal length of the eutectic sealing material \n204\n.', 'The heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n may extend diagonally and/or helically with respect to the longitudinal axis \n214\n of the sealing tool \n400\n, as depicted in \nFIG.', '7\n.', 'However, other arrangements are also within the scope of the present disclosure, such as implementations in which the heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n extend substantially parallel or otherwise with respect to the longitudinal axis \n214\n of the sealing tool \n400\n.', 'The eutectic sealing material \n204\n may be circumferentially partitioned into portions \n454\n, \n456\n, \n458\n, \n460\n, \n462\n, such as by radially extending barriers \n416\n.', 'Three of the barriers \n416\n are schematically depicted in \nFIG.', '7\n by dashed lines, but the remaining barriers \n416\n are not shown (although solely for the sake of clarity).', 'The barriers \n416\n, and thus the portions \n454\n, \n456\n, \n458\n, \n460\n, \n462\n of the eutectic sealing material \n204\n, extend diagonally, helically, parallel, or otherwise with respect to the longitudinal axis \n214\n of the sealing tool \n400\n in the same orientation as the heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n, such that each heating element probe \n404\n, \n406\n, \n408\n, \n410\n, \n412\n generally extends within a central region of the corresponding portion \n454\n, \n456\n, \n458\n, \n460\n, \n462\n of the eutectic sealing material \n204\n.', 'The barriers \n416\n may comprise the brittle material described above or another brittle material operable to withstand high temperatures generated by the heating probes \n304\n, \n306\n, \n308\n, \n310\n, \n312\n.', 'The barriers \n316\n may also comprise thin sheets of a metallic material operable to withstand the high temperatures generated by the heating probes \n304\n, \n306\n, \n308\n, \n310\n, \n312\n and be deformed by the spreader \n210\n and/or otherwise during sealing operations.', 'The barriers \n316\n may also simply be gaps between the portions \n454\n, \n456\n, \n458\n, \n460\n, \n462\n of the eutectic sealing material \n204\n.', 'When a sealing tool \n200\n, \n300\n, \n400\n within the scope of the present disclosure is utilized in a horizontal or otherwise non-vertical portion of a wellbore/tubular member, gravity may urge the melted eutectic sealing material \n204\n to flow in a radial or otherwise unintended direction.', 'Accordingly, the eutectic sealing material \n204\n may be activated in stages and directed by the downwardly sloping barriers \n416\n to intended regions within the tubular member \n224\n, such as to progressively build up or maintain the deposited eutectic sealing material \n205\n prior to moving the sealing tool \n400\n in the uphole direction.', 'Different portions \n454\n, \n456\n, \n458\n, \n460\n, \n462\n of the eutectic sealing material \n204\n may be heated and cooled in varying series, such as to form portions of the deposited eutectic sealing material \n205\n on which subsequent portions \n454\n, \n456\n, \n458\n, \n460\n, \n462\n of the eutectic sealing material \n204\n may be heated and cooled, thus building an intended sealing structure portion by portion.', 'For example, the heating element probe \n404\n closest to the bottom \n440\n of the tubular member \n224\n may be activated first to melt the corresponding portion \n454\n of the eutectic sealing material \n204\n.', 'After that portion \n454\n of the eutectic sealing material \n204\n at least partially cools and sets (after deactivating the heating element probe \n404\n), the heating element probes \n406\n that are next closest to the bottom \n440\n of the tubular member \n224\n (immediately above the previously utilized heating element probe \n304\n) may be activated to melt the corresponding portions \n456\n of the eutectic sealing material \n204\n.', 'After the portions \n456\n at least partially set, the heating element probes \n408\n that are next closest to the bottom \n440\n of the tubular member \n224\n may be activated to melt the corresponding portions \n458\n of the eutectic sealing material \n204\n.', 'After the portions \n458\n at least partially set, the next closest heating element probes \n410\n may be activated to melt the corresponding portions \n460\n of the eutectic sealing material \n204\n.', 'After the portions \n458\n at least partially set, the uppermost heating element probe \n412\n may be activated to melt the corresponding portion \n462\n of the eutectic sealing material \n204\n.', 'Thus, the heating element probes \n404\n, \n406\n, \n408\n, \n410\n, \n412\n may be sequentially utilized such that the melted portions \n454\n, \n456\n, \n458\n, \n460\n, \n462\n of the eutectic sealing material \n204\n may each, in series, flow along the corresponding barriers \n416\n and onto the inner surface \n225\n of the tubular member \n224\n.', 'The sealing tool \n400\n may also include the spreader \n210\n shown in \nFIG.', '2\n and/or the sealing element \n302\n shown in \nFIG.', '4\n, such as to aid in directing the sequentially melted portions \n454\n, \n456\n, \n458\n, \n460\n, \n462\n of the eutectic sealing material \n204\n onto progressively higher regions of the inner surface \n225\n of the tubular member \n224\n, perhaps including while moving the sealing tool \n400\n uphole within the tubular member \n224\n, thus progressively filling the region between about the spreader \n210\n and/or the downhole portion \n208\n of the mandrel.', 'As successive portions of the deposited eutectic sealing material \n204\n cools and at least partially sets along the inner surface \n225\n of the tubular member, such portions block the subsequently melted other portions of the eutectic sealing material \n204\n from flowing in the downhole direction, thus encouraging flow up around the inner surface \n225\n of the tubular member \n224\n.', 'After the intended portions \n454\n, \n456\n, \n468\n, \n460\n, \n462\n of the eutectic sealing material \n204\n have been melted and perhaps permitted to partially set on the inner surface \n225\n of the tubular member \n224\n, whether in the serial manner described above or otherwise, the sealing tool \n400\n may be moved (e.g., pulled) in the uphole direction.', 'Consequently, the spreader \n210\n may urge the melted or partially set eutectic sealing material \n204\n against the against the inner surface \n225\n of the tubular member \n224\n to shape and/or mold the eutectic sealing material \n204\n and, thus, patch and/or repair the tubular member \n224\n, as described above.', 'Such movement of the sealing tool \n400\n may also intentionally fracture or break the brittle material \n402\n and/or barriers \n416\n to aid in freeing the sealing tool \n400\n from the partially or fully set eutectic sealing material, such that the sealing tool \n400\n may be retrieved to the wellsite surface \n105\n.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art should readily recognize that the present disclosure introduces an apparatus comprising: a sealing tool for conveyance within a tubular member within a wellbore extending into a subterranean formation, wherein the sealing tool comprises: a mandrel; a eutectic sealing material disposed about the mandrel, wherein the eutectic sealing material has a eutectic temperature at which the eutectic sealing material melts; and means for heating the eutectic sealing material to at least the eutectic temperature.', 'The tubular member may be a casing member secured within the wellbore and/or a portion of completion/production tubing installed within the wellbore.', 'The eutectic sealing material may comprise an alloy of two or more different metals each having an individual melting temperature that is greater than the eutectic temperature.', 'The eutectic sealing material may substantially comprise a bismuth-based alloy.', 'The bismuth-based alloy may substantially comprise 58% bismuth and 42% tin, by weight.', 'The mandrel may comprise a downhole portion having a first outer diameter that may be substantially larger than a second outer diameter of the rest of the mandrel, and a surface transitioning between the first and second outer diameters may define a spreader that urges the eutectic sealing material melted by the heating means radially outward toward an inner surface of the tubular member.', 'The spreader may be a substantially frustoconical surface extending axially tapered between the first and second outer diameters and circumferentially extending substantially continuously around the mandrel.', 'The downhole portion of the mandrel may comprise a plurality of heat-dissipating features each extending into an outer surface of the downhole portion and/or a plurality of heat-dissipating features each extending into a cavity that extends into a downhole end of the mandrel.', 'The sealing tool may further comprise a sealing member operable to fixedly engage with the tubular member, slidably engage with the mandrel, and form a fluid seal between the tubular member and the mandrel.', 'The heating means may comprise an electrical heating coil disposed within the mandrel and/or means for activating a heat-generating chemical reaction.', 'The heating means may comprise a plurality of heating element probes each contacting the eutectic sealing material.', 'The sealing tool may further comprise a brittle material securing the eutectic sealing material around the mandrel.', 'The heating element probes may each extend along a longitudinal length of the eutectic sealing material.', 'The heating element probes may each extend diagonally and/or helically with respect to a longitudinal axis of the sealing tool.', 'The eutectic sealing material may be circumferentially partitioned into a plurality of portions by a corresponding plurality of barriers each extending radially and longitudinally between neighboring ones of the portions of the eutectic sealing material.', 'The heating element probes, the portions of the eutectic sealing material, and the barriers may each extend diagonally and/or helically with respect to a longitudinal axis of the sealing tool, and each heating element probe may extend within a central region of a corresponding portion of the eutectic sealing material between neighboring ones of the barriers.', 'The sealing tool may be operable for conveyance within the tubular member via coiled tubing.', 'The present disclosure also introduces a method comprising: conveying a sealing tool within a tubular member within a wellbore extending into a subterranean formation, wherein the sealing tool comprises: a mandrel; a eutectic sealing material disposed about the mandrel, wherein the eutectic sealing material has a eutectic temperature at which the eutectic sealing material melts; and means for heating the eutectic sealing material to at least the eutectic temperature; and transferring the eutectic sealing material onto an inner surface of the tubular member by activating the heating means to heat the eutectic sealing material to at least the eutectic temperature to melt the eutectic sealing material.', 'Conveying the sealing tool within the tubular member may comprise conveying the sealing tool via coiled tubing.', 'Conveying the sealing tool within the tubular member may comprise conveying the sealing tool to a damaged portion of the tubular member, and transferring the eutectic sealing material onto the inner surface of the tubular member may comprise covering the damaged portion of the tubular member with the transferred eutectic sealing material.', 'Transferring the eutectic sealing material onto the inner surface of the tubular member may comprise plugging the tubular member by substantially filling a longitudinal portion of the tubular member.', 'Substantially filling the longitudinal portion of the tubular member may comprise substantially filling the longitudinal portion with the transferred eutectic sealing material.', 'Transferring the eutectic sealing material onto the inner surface of the tubular member may comprise axially moving the sealing tool within the tubular member after activating the heating means but before the melted eutectic sealing material transferred onto the inner surface of the tubular member is permitted to completely solidify, such that a feature of the sealing tool may spread the melted eutectic sealing material around the inner surface of the tubular member as the sealing tool moves axially past the melted eutectic sealing material.', 'The transferred eutectic sealing material spread around the inner surface of the tubular member may have a thickness ranging between about 5 millimeters and about 25 millimeters.', 'The heating means may comprise an electrical coil, and activating the heating means may comprise electrically energizing the electrical coil.', 'The method may further comprise, after conveying the sealing tool within the tubular member and before transferring the eutectic sealing material onto the inner surface of the tubular member, engaging a sealing member of the sealing tool with the inner surface of the tubular member to form a fluid seal between the inner surface of the tubular member and the mandrel.', 'Transferring the eutectic sealing material onto the inner surface of the tubular member may comprise pressurizing the melted eutectic sealing material between the mandrel and the sealing member by sliding the mandrel axially through the sealing member.', 'Pressurizing the melted eutectic sealing material may urge the melted eutectic sealing material into a damaged portion of the tubular member.', 'The eutectic sealing material may be circumferentially partitioned into a plurality of portions by a corresponding plurality of barriers each extending radially and longitudinally between neighboring ones of the portions of the eutectic sealing material, and the heating means may comprise a plurality of heating element probes each extending within a central region of a corresponding portion of the eutectic sealing material between neighboring ones of the barriers.', 'Activating the heating means may comprise activating one or more of the heating element probes independently of other ones of the heating element probes.', 'The partitioned portions of the eutectic sealing material may comprise a first partitioned portion, a second partitioned portion, and a third partitioned portion, and the plurality of heating element probes may comprise: a first heating element probe contacting the first partitioned portion but not the second and third partitioned portions; a second heating element probe contacting the second partitioned portion but not the first and third partitioned portions; and a third heating element probe contacting the third partitioned portion but not the first and second partitioned portions.', 'Conveying the sealing tool within the tubular member may comprise conveying the sealing tool to a substantially horizontal portion of the tubular member within a substantially horizontal portion of the wellbore such that the first heating element probe is closest to a bottom side of the tubular member relative to the second and third heating element probes, and such that the third heating element probe is closest to a top side of the tubular member relative to the first and second heating element probes.', 'Transferring the eutectic sealing material onto the inner surface of the tubular member may comprise: activating the first heating element probe, but not the second and third heating element probes, to melt the first partitioned portion, but not the second and third partitioned portions, onto the inner surface of the tubular member; then permitting the melted first partitioned portion to at least partially solidify on the inner surface of the tubular member; then activating the second heating element probe, but not the first and third heating element probes, to melt the second partitioned portion, but not the third partitioned portion, onto the at least partially solidified first partitioned portion on the inner surface of the tubular member; then permitting the melted second partitioned portion to at least partially solidify; then activating the third heating element probe, but not the first and third heating element probes, to melt the third partitioned portion onto the at least partially solidified second partitioned portion overlying the at least partially solidified first partitioned portion on the inner surface of the tubular member.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'An apparatus, comprising:\na sealing tool for conveyance within a tubular member within a wellbore extending into a subterranean formation, wherein the sealing tool comprises: a mandrel; a eutectic sealing material disposed about the mandrel, wherein the eutectic sealing material has a eutectic temperature at which the eutectic sealing material melts, and wherein the eutectic sealing material is circumferentially partitioned into a plurality of portions by a corresponding plurality of barriers each extending radially and longitudinally between neighboring ones of the portions of the eutectic sealing material; and heating means for heating the eutectic sealing material to at least the eutectic temperature to melt the eutectic sealing material such that the eutectic sealing material flows onto an inner surface of the tubular member, wherein the heating means comprises a plurality of heating element probes each extending within a central region of a corresponding portion of the eutectic sealing material between neighboring ones of the barriers, and wherein the plurality of heating element probes are configured to be individually activated independently of other ones of the heating element probes.', '2.', 'The apparatus of claim 1 wherein the tubular member is a casing member secured within the wellbore.', '3.', 'The apparatus of claim 1 wherein the tubular member is a portion of completion/production tubing installed within the wellbore.', '4.', 'The apparatus of claim 1 wherein the eutectic sealing material comprises an alloy of two or more different metals each having an individual melting temperature that is greater than the eutectic temperature.', '5.', 'The apparatus of claim 1 wherein the eutectic sealing material comprises a bismuth-based alloy.', '6.', 'The apparatus of claim 5 wherein the bismuth-based alloy comprises a eutectic mixture of bismuth and tin.\n\n\n\n\n\n\n7.', 'The apparatus of claim 1 wherein the mandrel comprises a downhole portion having a first outer diameter that is substantially larger than a second outer diameter of the rest of the mandrel, and wherein a surface transitioning between the first and second outer diameters defines a spreader that urges the eutectic sealing material melted by the heating means radially outward toward the inner surface of the tubular member.', '8.', 'The apparatus of claim 7 wherein the spreader is a substantially frustoconical surface extending axially tapered between the first and second outer diameters and circumferentially extending continuously around the mandrel.', '9.', 'The apparatus of claim 7 wherein the downhole portion of the mandrel comprises a plurality of heat-dissipating features each extending into an outer surface of the downhole portion.', '10.', 'The apparatus of claim 7 wherein the downhole portion of the mandrel comprises a plurality of heat-dissipating features each extending into a cavity that extends into a downhole end of the mandrel.', '11.', 'The apparatus of claim 1 wherein the sealing tool further comprises a sealing member operable to fixedly engage with the tubular member, slidably engage with the mandrel, and form a fluid seal between the tubular member and the mandrel.', '12.', 'The apparatus of claim 1 wherein the sealing tool further comprises a brittle material securing the eutectic sealing material around the mandrel.', '13.', 'The apparatus of claim 1 wherein the heating element probes each extend along a longitudinal length of the eutectic sealing material.', '14.', 'The apparatus of claim 13 wherein the heating element probes each extend diagonally and/or helically with respect to a longitudinal axis of the sealing tool.', '15.', 'The apparatus of claim 1 wherein the sealing tool is operable for conveyance within the tubular member via coiled tubing.', '16.', 'The apparatus of claim 1 wherein the plurality of barriers extend radially outward further than the plurality of heating element probes.', '17.', 'A method, comprising:\nconveying a sealing tool within a tubular member within a wellbore extending into a subterranean formation, wherein the sealing tool comprises:\na mandrel;\na eutectic sealing material disposed about the mandrel, wherein the eutectic sealing material has a eutectic temperature at which the eutectic sealing material melts, and wherein the eutectic sealing material is circumferentially partitioned into a plurality of portions by a corresponding plurality of barriers each extending radially and longitudinally between neighboring ones of the portions of the eutectic sealing material; and\nheating means for heating the eutectic sealing material to at least the eutectic temperature, wherein the heating means comprises a plurality of heating element probes each extending within a central region of a corresponding portion of the eutectic sealing material between neighboring ones of the barriers; and\ntransferring the eutectic sealing material onto an inner surface of the tubular member by activating the heating means to heat the eutectic sealing material to at least the eutectic temperature to melt the eutectic sealing material, wherein activating the heating means comprises individually activating the plurality of heating element probes independently of other ones of the heating element probes to melt a corresponding portion of the eutectic sealing material, and permitting the corresponding portion of the eutectic sealing material to at least partially solidify on the inner surface of the tubular member.', '18.', 'The method of claim 17 wherein conveying the sealing tool within the tubular member comprises conveying the sealing tool via coiled tubing.', '19.', 'The method of claim 17 wherein conveying the sealing tool within the tubular member comprises conveying the sealing tool to a damaged portion of the tubular member, and wherein transferring the eutectic sealing material onto the inner surface of the tubular member comprises covering the damaged portion of the tubular member with the transferred eutectic sealing material.', '20.', 'The method of claim 17 wherein transferring the eutectic sealing material onto the inner surface of the tubular member comprises plugging the tubular member by substantially filling a longitudinal portion of the tubular member.', '21.', 'The method of claim 20 wherein substantially filling the longitudinal portion of the tubular member comprises substantially filling the longitudinal portion with the transferred eutectic sealing material.', '22.', 'The method of claim 17 wherein transferring the eutectic sealing material onto the inner surface of the tubular member comprises axially moving the sealing tool within the tubular member after activating the heating means but before the melted eutectic sealing material transferred onto the inner surface of the tubular member is permitted to completely solidify, such that a feature of the sealing tool spreads the melted eutectic sealing material around the inner surface of the tubular member as the sealing tool moves axially past the melted eutectic sealing material.', '23.', 'The method of claim 22 wherein the transferred eutectic sealing material spread around the inner surface of the tubular member has a thickness ranging between 5 millimeters and 25 millimeters.', '24.', 'The method of claim 17 further comprising, after conveying the sealing tool within the tubular member and before transferring the eutectic sealing material onto the inner surface of the tubular member, engaging a sealing member of the sealing tool with the inner surface of the tubular member to form a fluid seal between the inner surface of the tubular member and the mandrel.', '25.', 'The method of claim 24 wherein transferring the eutectic sealing material onto the inner surface of the tubular member comprises pressurizing the melted eutectic sealing material between the mandrel and the sealing member by sliding the mandrel axially through the sealing member.', '26.', 'The method of claim 25 wherein pressurizing the melted eutectic sealing material urges the melted eutectic sealing material into a damaged portion of the tubular member.', '27.', 'The method of claim 17 wherein:\nthe partitioned plurality of portions of the eutectic sealing material comprise a first partitioned portion, a second partitioned portion, and a third partitioned portion; and\nthe plurality of heating element probes comprises: a first heating element probe contacting the first partitioned portion but not the second and third partitioned portions; a second heating element probe contacting the second partitioned portion but not the first and third partitioned portions; and a third heating element probe contacting the third partitioned portion but not the first and second partitioned portions.', '28.', 'The method of claim 27 wherein:\nconveying the sealing tool within the tubular member comprises conveying the sealing tool to a substantially horizontal portion of the tubular member within a substantially horizontal portion of the wellbore such that: the first heating element probe is closest to a bottom side of the tubular member relative to the second and third heating element probes; and the third heating element probe is closest to a top side of the tubular member relative to the first and second heating element probes; and\ntransferring the eutectic sealing material onto the inner surface of the tubular member comprises:\nactivating the first heating element probe, but not the second and third heating element probes, to melt the first partitioned portion, but not the second and third partitioned portions, onto the inner surface of the tubular member; then\npermitting the melted first partitioned portion to at least partially solidify on the inner surface of the tubular member; then\nactivating the second heating element probe, but not the first and third heating element probes, to melt the second partitioned portion, but not the third partitioned portion, onto the at least partially solidified first partitioned portion on the inner surface of the tubular member; then\npermitting the melted second partitioned portion to at least partially solidify; and then\nactivating the third heating element probe, but not the first and third heating element probes, to melt the third partitioned portion onto the at least partially solidified second partitioned portion overlying the at least partially solidified first partitioned portion on the inner surface of the tubular member.', '29.', 'The method of claim 17 wherein the plurality of barriers extend radially outward further than the plurality of heating element probes.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIGS.', '2', 'and', '3 are schematic sectional views of a portion of an example implementation of the apparatus shown in FIG.', '1 at different stages of operation.', '; FIGS. 4 and 5 are schematic sectional views of a portion of another example implementation of the apparatus shown in FIGS.', '1 and 2 at different stages of operation.', '; FIG.', '6 is a schematic axial view of a portion of another example implementation of the apparatus shown in FIGS.', '1 and 2 according to one or more aspects of the present disclosure.', '; FIG. 7 is a schematic side view of the apparatus shown in FIG.', '6 according to one or more aspects of the present disclosure.', '; FIG. 1 is a schematic view of at least a portion of an example wellsite system 100 according to one or more aspects of the present disclosure, representing an example coiled tubing environment in which one or more apparatus described herein may be implemented, including to perform one or more methods and/or processes also described herein.', 'However, it is to be understood that aspects of the present disclosure are also applicable to implementations in which wireline, slickline, and/or other conveyance means are utilized instead of or in addition to coiled tubing.; FIG.', '1 depicts a wellsite surface 105 upon which various wellsite equipment is disposed proximate a wellbore 120. FIG.', '1 also depicts a sectional view of the Earth below the wellsite surface 105 containing the wellbore 120, as well as a tool string 110 positioned within the wellbore 120.', 'The wellbore 120 extends from the wellsite surface 105 into one or more subterranean formations 130.', 'When utilized in cased-hole implementations, a cement sheath 124 may secure a casing 122 within the wellbore 120.', 'However, one or more aspects of the present disclosure are also applicable to open-hole implementations, in which the cement sheath 124 and the casing 122 have not yet been installed in the wellbore 120.; FIGS. 2 and 3 are schematic sectional views of at least a portion of an example implementation of the sealing tool 200 shown in FIG.', '1.', 'The following description refers to FIGS.', '1-3, collectively.; FIGS. 4 and 5 are schematic sectional views of another example implementation of the sealing tool 200 shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure, and designated in FIGS.', '4 and 5 by reference number 300.', 'Unless described otherwise, the sealing tool 300 is substantially similar to the sealing tool 200 shown in FIGS.', '2 and 3, including where indicated by like reference numbers.', 'The following description refers to FIGS.', '1, 4, and 5, collectively.;', 'FIG. 6 is a schematic top end view of another example implementation of the sealing tool 200 shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure, and designated in FIG.', '6 by reference number 400.', 'Unless described otherwise, the sealing tool 400 is substantially similar to the sealing tool 200 shown in FIGS.', '2 and 3, including where indicated by like reference numbers.', 'The sealing tool 400 includes a brittle material 402 interposing the mandrel 202 and the eutectic sealing material 204, and a plurality of heating element probes 404, 406, 408, 410, 412 disposed at least partially within the eutectic sealing material 204 and/or between the eutectic sealing material 204 and the brittle material 402. FIG.', '7 is a side view of the sealing tool 400 with the eutectic sealing material 204, one of the heating element probes 406, one of the heating element probes 408, and one of the heating element probes 410 removed to show an example implementation of the heating element probes 404, 406, 408, 410, 412.', 'Although removed from view in FIG.', '6 for the sake of clarity, FIG.', '7 also depicts a housing 470 of the sealing tool 400.', 'When the eutectic sealing material 204 is in its original, pre-melted form, the eutectic sealing material 204 is free from an interior portion of the housing 470, but the housing 470 axially retains the eutectic sealing material 204 around the mandrel 202.', 'However, other means for retaining the eutectic sealing material 204 around the mandrel 202 are also within the scope of the present disclosure.', '(It is also noted that the sealing tools 200, 300 described above may comprise a similar housing and/or other means for retaining the pre-melted eutectic sealing material 204 around the mandrel 202).', 'The following description refers to FIGS.', '1, 6, and 7, respectively.'] |
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US11091968 | Automated choke control apparatus and methods | Mar 12, 2018 | Luis Astudillo, Tiago Albrecht de Freitas, Henrique Duarte Moser, Wasim Azem | SCHLUMBERGER TECHNOLOGY CORPORATION | Extended Search Report issued in the EP Application 18764140.2, dated Nov. 4, 2020 (7 pages).; International Preliminary Report on Patentability issued in the related PCT Application PCT/US2018/021913, dated Sep. 19, 2019 (14 pages).; International Search Report and Written Opinion issued in the related PCT Application PCT/US2018/021913, dated Jun. 26, 2018 (15 pages). | 4630675; December 23, 1986; Neipling et al.; 6595294; July 22, 2003; Dalsmo; 20040144565; July 29, 2004; Koederitz; 20040216884; November 4, 2004; Bodine et al.; 20050092523; May 5, 2005; McCaskill et al.; 20050222772; October 6, 2005; Koederitz et al.; 20080154510; June 26, 2008; Scott; 20100307598; December 9, 2010; Cao; 20120215364; August 23, 2012; Rossi; 20120255776; October 11, 2012; Knudsen; 20140090888; April 3, 2014; Smith et al.; 20150083494; March 26, 2015; Noske; 20150292291; October 15, 2015; Donald; 20150337218; November 26, 2015; Ricotta; 20160298401; October 13, 2016; Cotten et al.; 20170175731; June 22, 2017; Abrol; 20180135365; May 17, 2018; Knudsen; 20180274347; September 27, 2018; Ricotta | 2014007797; January 2014; WO | ['Automated choke control apparatus and methods are disclosed herein.', 'An apparatus for automatically controlling a choke valve comprises a controller.', 'The controller is to control a choke position of the choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected.', 'The controller is further to control a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected, the wellhead being operatively coupled to the choke valve.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates generally to choke control and, more specifically, to automated choke control apparatus and methods.', 'DESCRIPTION OF THE RELATED ART\n \nChoke valves are commonly implemented in connection with drilling operations (e.g., underbalanced drilling, overbalanced drilling, etc.) to control the wellhead pressure (e.g., the surface pressure) of a wellhead operatively coupled to a production well.', 'Conventional choke control systems include control panels having a wellhead pressure indicator and a choke position indicator that respectively provide a human drilling operator with corresponding visual indications of the wellhead pressure of the wellhead and the choke position of the choke valve.', 'As used herein, the term “choke position” means an extent to which a flow control member (e.g., a plug) of a choke valve is open and/or closed relative to a fully-open and/or fully-closed position of the flow control member.', 'The choke position of a choke valve may be expressed as a percentage of a maximum stroke distance traveled by the flow control member of the choke valve and/or by a maximum stroke distance traveled by a stem rigidly coupled (e.g., directly or indirectly) to the flow control member of the choke valve.', 'The control panels of the conventional choke control systems described above further include a manually-operable control lever that is movable and/or positionable by the drilling operator.', 'In response to noticing an undesirable wellhead pressure via the wellhead pressure indicator, and/or in response to noticing an undesirable choke position via the choke position indicator, the drilling operator may move and/or adjust a position of the manually-operable control lever to reduce the extent to which the wellhead pressure of the wellhead and/or the choke position of the choke valve deviate from desired value(s).', 'The drilling operator may need to adjust the manually-operable control lever frequently to maintain the wellhead pressure and/or the choke position of the choke valve at desired value(s).', 'SUMMARY\n \nAutomated choke control apparatus and methods are disclosed herein.', 'In some examples, an apparatus for automatically controlling a choke valve is disclosed.', 'In some examples, the apparatus includes a controller.', 'In some examples, the controller is to control a choke position of the choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected.', 'In some examples, the controller is to control a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected, the wellhead being operatively coupled to the choke valve.', 'In some examples, a method for automatically controlling a choke valve is disclosed.', 'In some examples, the method includes controlling a choke position of the choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected.', 'In some examples, the method includes controlling a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected, the wellhead being operatively coupled to the choke valve.', 'In some examples, a tangible machine readable storage medium including instructions is disclosed.', 'In some examples, the instructions, when executed, cause a controller to control a choke position of a choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected.', 'In some examples, the instructions, when executed, cause the controller to control a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected, the wellhead being operatively coupled to the choke valve.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a block diagram of a known choke control system.\n \nFIG.', '2\n is a block diagram of an example automated choke control apparatus that may be implemented in accordance with the teachings of this disclosure.', 'FIGS.', '3A and 3B\n are a flowchart representative of an example method that may be executed at the example automated choke control apparatus of \nFIG.', '2\n to selectively control a choke position of a choke valve or a pressure of a wellhead.\n \nFIG.', '4\n is an example processor platform capable of executing instructions to implement the method of \nFIGS.', '3A and 3B\n and the example automated choke control apparatus of \nFIG.', '2\n.', 'Certain examples are shown in the above-identified figures and described in detail below.', 'In describing these examples, like or identical reference numbers are used to identify the same or similar elements.', 'The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale or in schematic for clarity and/or conciseness.', 'DETAILED DESCRIPTION', 'Well pressure control is critical to successfully performing drilling operations (e.g., underbalanced drilling, overbalanced drilling, etc.).', 'Conventional choke control systems and/or the control panels thereof require that a human drilling operator make regular (e.g., frequent) adjustments to a manually-operated control lever to maintain a wellhead pressure of a wellhead and/or a choke position of a choke valve at desirable value(s).', 'Unlike such conventional choke control systems and/or control panels, the automated choke control apparatus and methods disclosed herein selectively control the wellhead pressure of the wellhead via a wellhead pressure control loop, or the choke position of the choke valve via a choke position control loop.', 'Implementation of the disclosed automated choke control apparatus and methods advantageously reduces the extent of human intervention needed to maintain a wellhead pressure of a wellhead and/or a choke position of a choke valve at desirable value(s).', 'Reducing the extent of human intervention reduces the possibility of human exposure to a well scenario (e.g., a blowout) and also reduces operational risks associated with human errors.', 'Before describing the details of example automated choke control apparatus and methods, a description of a known choke control system is provided in connection with \nFIG.', '1\n.', 'FIG.', '1\n is a block diagram of a known choke control system \n100\n.', 'The choke control system \n100\n includes a control panel \n102\n, a wellhead \n104\n, a hydraulic power unit \n106\n, an actuator \n108\n and a choke valve \n110\n.', 'The choke control system \n100\n manages and/or controls the wellhead pressure (e.g. surface pressure) of a wellhead (e.g., the wellhead \n104\n) operatively coupled to a well (not shown).', 'By managing and/or controlling the wellhead pressure, the choke control system \n100\n also manages and/or controls the production rate from the well.', 'Management and/or control of the wellhead pressure via the choke control system \n100\n may prevent kicks and/or blowouts of the well from occurring.', 'The control panel \n102\n of \nFIG.', '1\n is operatively coupled to the hydraulic power unit \n106\n to enable a distribution of hydraulic fluid supplied by the hydraulic power unit \n106\n to be controlled.', 'As described in greater detail herein, the hydraulic power unit \n106\n is operatively coupled to the actuator \n108\n of \nFIG.', '1\n, the actuator \n108\n is operatively coupled to the choke valve \n110\n of \nFIG.', '1\n, and the choke valve \n110\n is operatively coupled to the wellhead \n104\n of \nFIG.', '1\n.', 'Thus, by enabling the distribution of hydraulic fluid supplied by the hydraulic power unit \n106\n to be controlled, the control panel \n102\n further enables the choke position of the choke valve \n110\n and/or the wellhead pressure of the wellhead \n104\n to be controlled.', 'The control panel \n102\n of \nFIG.', '1\n is manually monitored and/or manually operated by a human drilling operator.', 'The control panel \n102\n includes a pressure indicator \n112\n, a position indicator \n114\n and a hydraulic distribution lever \n116\n.', 'The pressure indicator \n112\n provides the drilling operator with a visual indication (e.g., via a gauge or other display device) of the wellhead pressure of the wellhead \n104\n of \nFIG.', '1\n.', 'The position indicator \n114\n provides the drilling operator with a visual indication (e.g., via a gauge or other display device) of the choke position (e.g., fifty percent closed) of the choke valve \n110\n of \nFIG.', '1\n.', 'The hydraulic distribution lever \n116\n is movable (e.g., turnable, slidable, etc.)', 'and/or positionable by the drilling operator to adjust the distribution of the hydraulic fluid supplied by the hydraulic power unit \n106\n of \nFIG.', '1\n to the actuator \n108\n of \nFIG.', '1\n.', 'For example, in response to noticing an undesirable wellhead pressure of the wellhead \n104\n via the pressure indicator \n112\n, and/or in response to noticing an undesirable choke position of the choke valve \n110\n via the position indicator \n114\n, the drilling operator may move and/or adjust a position of the hydraulic distribution lever \n116\n in a direction that results in a corresponding movement and/or adjustment to the choke position of the choke valve \n110\n and/or the wellhead pressure of the wellhead \n104\n.', 'As a result of the drilling operator moving and/or adjusting the position of the hydraulic distribution lever \n116\n, the extent to which the wellhead pressure of the wellhead \n104\n and/or the choke position of the choke valve \n110\n deviate from desired value(s) may be reduced for a duration of time (e.g., until the drilling operator notices another undesirable condition of the wellhead pressure of the wellhead \n104\n and/or the choke position of the choke valve \n110\n requiring additional manual intervention via the hydraulic distribution lever \n116\n of the control panel \n102\n).', 'The wellhead \n104\n of \nFIG.', '1\n provides a structural and pressure-containing interface for drilling and production equipment associated with a well.', 'The wellhead \n104\n includes a pressure sensor \n118\n.', 'The pressure sensor \n118\n senses, measures and/or detects a wellhead pressure of the wellhead \n104\n.', 'The pressure sensor \n118\n of the wellhead \n104\n is operatively coupled (e.g., via wired and/or wireless communication) to the pressure indicator \n112\n of the control panel \n102\n such that the visual indication of the wellhead pressure provided via the pressure indicator \n112\n corresponds to the wellhead pressure sensed, measured and/or detected via the pressure sensor \n118\n.', 'The wellhead pressure of the wellhead \n104\n sensed, measured and/or detected via the pressure sensor \n118\n may increase and/or decrease as a result of a change in a choke position of the choke valve \n110\n.', 'The hydraulic power unit \n106\n of \nFIG.', '1\n supplies hydraulic fluid to the actuator \n108\n of \nFIG.', '1\n based on the position of the hydraulic distribution lever \n116\n of the control panel \n102\n of \nFIG.', '1\n.', 'For example, in response to a movement and/or adjustment of the hydraulic distribution lever \n116\n by the drilling operator, the hydraulic power unit \n106\n adjusts a distribution of the hydraulic fluid being supplied to the actuator \n108\n via a first hydraulic fluid supply line \n120\n and/or a second hydraulic fluid supply line \n122\n.', 'The actuator \n108\n of \nFIG.', '1\n is a double-acting actuator including a piston \n124\n, a first port \n126\n, a second port \n128\n, and a manual override \n130\n.', 'The first port \n126\n of the actuator \n108\n is in fluid communication with the hydraulic power unit \n106\n via the first hydraulic fluid supply line \n120\n.', 'The second port \n128\n of the actuator \n108\n is in fluid communication with the hydraulic power unit \n106\n via the second hydraulic fluid supply line \n122\n.', 'The piston \n124\n of the actuator \n108\n is movable and/or positionable based on the distribution of the hydraulic fluid received via the first port \n126\n and/or the second port \n128\n of the actuator \n108\n.', 'For example, the piston \n124\n may move in a first direction in response to an increase of the hydraulic fluid received via the first port \n126\n relative to the hydraulic fluid received via the second port \n128\n, and may move in a second direction opposite the first direction in response to an increase of the hydraulic fluid received via the second port \n128\n relative to the hydraulic fluid received via the first port \n126\n.', 'The manual override \n130\n of the actuator \n108\n is a manually-operable wheel and/or lever that may be used by a drilling operator to move and/or position the piston \n124\n of the actuator \n108\n.', 'For example, a drilling operator may need to operate the manual override \n130\n of the actuator \n108\n in the absence of hydraulic fluid being adjustably supplied to the actuator \n108\n via the hydraulic power unit \n106\n.', 'The choke valve \n110\n of \nFIG.', '1\n controls production flow from the well to which the wellhead \n104\n of \nFIG.', '1\n is operatively coupled.', 'The choke valve \n110\n includes a stem \n132\n, a plug \n134\n, and a position sensor \n136\n.', 'The stem \n132\n of the choke valve \n110\n is rigidly coupled (e.g., directly or indirectly) to the piston \n124\n of the actuator \n108\n such that movement of the piston \n124\n of the actuator \n108\n produces a corresponding movement of the stem \n132\n of the choke valve \n110\n.', 'Similarly, the plug \n134\n of the choke valve \n110\n is rigidly coupled (e.g., directly or indirectly) to the stem \n132\n of the choke valve \n110\n such that movement of the stem \n132\n of the choke valve \n110\n produces a corresponding movement of the plug \n134\n of the choke valve \n110\n.', 'The position sensor \n136\n of the choke valve \n110\n is operatively coupled to the stem \n132\n of the choke valve \n110\n.', 'The position sensor \n136\n senses, measures and/or detects a position (e.g., a linear displacement) of the stem \n132\n of the choke valve \n110\n, and/or a choke position (e.g., an extent to which a flow control member of the choke valve is open and/or closed) of the choke valve \n110\n.', 'For example, the position sensor \n136\n may sense, measure and/or detect that the stem \n132\n of the choke valve \n110\n is in a position corresponding to the choke position of the choke valve \n110\n being fifty percent closed.', 'The position sensor \n136\n of the choke valve \n110\n is operatively coupled (e.g., via wired and/or wireless communication) to the position indicator \n114\n of the control panel \n102\n such that the visual indication of the choke position provided via the position indicator \n114\n corresponds to the position of the stem \n132\n and/or the choke position of the choke valve \n110\n sensed, measured and/or detected via the position sensor \n136\n.', 'The choke position of the choke valve \n110\n sensed, measured and/or detected via the position sensor \n136\n may increase and/or decrease as a result of a change in the position of the stem \n132\n and/or the plug \n134\n of the choke valve \n110\n.', 'Changes to the choke position of the choke valve \n110\n may produce corresponding increases and/or decreases to the wellhead pressure of the wellhead \n104\n.', 'In contrast to the known choke control system \n100\n of \nFIG.', '1\n, the example automated choke control apparatus and methods described herein selectively control the wellhead pressure of the wellhead via a wellhead pressure control loop, or the choke position of the choke valve via a choke position control loop.\n \nFIG.', '2\n is a block diagram of an example automated choke control apparatus \n200\n that may be implemented in accordance with the teachings of this disclosure.', 'As described in greater detail herein, the automated choke control apparatus \n200\n of \nFIG.', '2\n is operatively coupled to one or more structure(s) and/or component(s) of a choke control system (e.g., the known choke control system \n100\n of \nFIG.', '1\n).', 'In the illustrated example of \nFIG.', '2\n, the automated choke control apparatus \n200\n includes an example position sensor \n202\n, an example pressure sensor \n204\n, an example user interface \n206\n, an example mode detector \n208\n, an example controller \n210\n, and an example memory \n212\n.', 'However, other example implementations of the automated choke control apparatus \n200\n may include fewer or additional structures in accordance with the teachings of this disclosure.', 'The example position sensor \n202\n of \nFIG.', '2\n is operatively coupled to a stem of a choke valve (e.g., the stem \n132\n of the choke valve \n110\n of \nFIG.', '1\n).', 'The position sensor \n202\n of \nFIG.', '2\n senses, measures and/or detects a position (e.g., a linear displacement) of the stem of the choke valve, and/or a choke position of the choke valve (e.g., an extent to which a flow control member of the choke valve is open and/or closed).', 'For example, the position sensor \n202\n may sense, measure and/or detect that the stem of the choke valve is in a position corresponding to the choke valve being fifty percent closed.', 'In the illustrated example of \nFIG.', '2\n, the position of the stem of the choke valve and/or the choke position of the choke valve sensed, measured and/or detected by the position sensor \n202\n is provided to and/or made accessible to the controller \n210\n of \nFIG.', '2\n.', 'Position data sensed, measured and/or detected by the position sensor \n202\n may be of any type, form and/or format, and may be stored in a computer-readable storage medium such as the example memory \n212\n described below.', 'The example pressure sensor \n204\n of \nFIG.', '2\n is operatively coupled to a wellhead (e.g., the wellhead \n104\n of \nFIG.', '1\n).', 'The pressure sensor \n204\n of \nFIG.', '2\n senses, measures and/or detects a wellhead pressure of the wellhead.', 'In the illustrated example of \nFIG.', '2\n, the wellhead pressure sensed, measured and/or detected by the pressure sensor \n204\n is provided to and/or made accessible to the controller \n210\n of \nFIG.', '2\n.', 'Pressure data sensed, measured and/or detected by the pressure sensor \n204\n may be of any type, form and/or format, and may be stored in a computer-readable storage medium such as the example memory \n212\n described below.', 'The example user interface \n206\n of \nFIG.', '2\n facilitates interactions and/or communications between an end user and the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'The user interface \n206\n includes one or more input device(s) \n214\n via which the user may input information and/or data to the controller \n210\n of the automated choke control apparatus \n200\n.', 'For example, the input device(s) \n214\n may be implemented as one or more of a button, a switch, a dial, a keyboard, a mouse, and/or a touchscreen that enable(s) the user to convey data and/or commands to the controller \n210\n of the automated choke control apparatus \n200\n.', 'In some examples, the data and/or command(s) conveyed via the input device(s) \n214\n of the user interface \n206\n identify and/or indicate a choke position setpoint and/or a desired choke position of a choke valve (e.g., a desired choke position of the choke valve \n110\n of \nFIG.', '1\n).', 'In some examples, the data and/or command(s) conveyed via the input device(s) \n214\n of the user interface \n206\n identify and/or indicate a wellhead pressure setpoint and/or a desired wellhead pressure of a wellhead (e.g., a desired wellhead pressure of the wellhead \n104\n of \nFIG.', '1\n).', 'In some examples, the data and/or information conveyed via the input device(s) \n214\n of the user interface \n206\n identify and/or indicate a selected control mode (e.g., a choke position control mode, a wellhead pressure control mode, a manual override mode, etc.) of the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'Data and/or information that is received and/or conveyed via the user input device(s) \n214\n of the user interface \n206\n may be of any type, form and/or format, and may be stored in a computer-readable storage medium such as the example memory \n212\n described below.', 'The user interface \n206\n of \nFIG.', '2\n also includes one or more output device(s) \n216\n via which the controller \n210\n of the automated choke control apparatus \n200\n presents information and/or data in visual and/or audible form to the user.', 'For example, the output device(s) \n216\n may be implemented as one or more of a light emitting diode, a touchscreen, and/or a liquid crystal display for presenting visual information, and/or a speaker for presenting audible information.', 'In some examples, the data and/or information presented via the output device(s) \n216\n of the user interface \n206\n identify and/or indicate a measured and/or current choke position of a choke valve (e.g., a current choke position of the choke valve \n110\n of \nFIG.', '1\n).', 'In some examples, the data and/or information presented via the output device(s) \n216\n of the user interface \n206\n identify and/or indicate a measured and/or current wellhead pressure of a wellhead (e.g., a current wellhead pressure of the wellhead \n104\n of \nFIG.', '1\n).', 'In some examples, the data and/or command(s) presented via the output device(s) \n216\n of the user interface \n206\n identify and/or indicate a choke position setpoint and/or a desired choke position of a choke valve (e.g., a desired choke position of the choke valve \n110\n of \nFIG.', '1\n).', 'In some examples, the data and/or command(s) presented via the output device(s) \n216\n of the user interface \n206\n identify and/or indicate a wellhead pressure setpoint and/or a desired wellhead pressure of a wellhead (e.g., a desired wellhead pressure of the wellhead \n104\n of \nFIG.', '1\n).', 'In some examples, the data and/or information presented via the output device(s) \n216\n of the user interface \n206\n identify and/or indicate a selected control mode (e.g., a choke position control mode, a wellhead pressure control mode, a manual override mode, etc.) of the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'Data and/or information that is presented and/or to be presented via the output device(s) \n216\n of the user interface \n206\n may be of any type, form and/or format, and may be stored in a computer-readable storage medium such as the example memory \n212\n described below.', 'The example mode detector \n208\n of \nFIG.', '2\n determines, identifies and/or detects an operation mode of the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'For example, the mode detector \n208\n may identify and/or detect selection of one of a plurality of available operation modes of the automated choke control apparatus \n200\n including, for example, a choke position control mode, a wellhead pressure control mode, or a manual override mode.', 'In some examples, the mode detector \n208\n determines and/or detects selection of the choke position control mode, the wellhead pressure control mode, or the manual override mode based on data and/or information (e.g., a mode selection bit, a choke position setpoint, a desired choke position, a wellhead pressure setpoint, a desired wellhead pressure, a manual override code, etc.) included within and/or indicated by an input control signal received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n.', 'Mode identification data determined, identified and/or detected by the pressure sensor \n204\n may be of any type, form and/or format, and may be stored in a computer-readable storage medium such as the example memory \n212\n described below.', 'The example controller \n210\n of \nFIG.', '2\n may be implemented by a semiconductor device such as a processor, microprocessor, or microcontroller.', 'The controller \n210\n manages and/or controls the operation of the automated choke control apparatus \n200\n of \nFIG.', '2\n, a hydraulic power unit (e.g., the hydraulic power unit \n106\n of \nFIG.', '1\n) operatively coupled to the automated choke control apparatus \n200\n, an actuator (e.g., the actuator \n108\n of \nFIG.', '1\n) operatively coupled to the hydraulic power unit, and/or a choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) operatively coupled to the actuator.', 'The controller \n210\n manages and/or controls the automated choke control apparatus \n200\n, the hydraulic power unit, the actuator and/or the choke valve based on data, information and/or one or more signal(s) obtained and/or accessed by the controller \n210\n from one or more of the position sensor \n202\n, the pressure sensor \n204\n, the user interface \n206\n, the mode detector \n208\n and/or the memory \n212\n, and/or based on data, information and/or one or more signal(s) provided by the controller \n210\n to one or more of the user interface \n206\n, the mode detector \n208\n, the memory \n212\n and/or the hydraulic power unit.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines whether an input control signal has been received.', 'For example, the controller \n210\n may determine that an input control signal has been received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n operates and/or controls a choke position control loop in response to the mode detector \n208\n of \nFIG.', '2\n determining that a received input control signal indicates selection of a choke position control mode of the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n continues to operate and/or control the choke position control loop until the controller \n210\n determines that an updated input control signal has been received indicating selection of a different operation mode (e.g., a wellhead pressure control mode, a manual override mode, etc.) of the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n operates and/or controls a wellhead pressure control loop in response to the mode detector \n208\n of \nFIG.', '2\n determining that a received input control signal indicates selection of a wellhead pressure control mode of the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n continues to operate and/or control the wellhead pressure control loop until the controller \n210\n determines that an updated input control signal has been received indicating selection of a different operation mode (e.g., a choke position control mode, a manual override mode, etc.) of the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines a desired choke position of a choke valve.', 'For example the controller \n210\n may determine a desired choke position of a choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) based on an identified choke position setpoint.', 'In some examples, data and/or information identifying and/or indicating the desired choke position (e.g., the choke position setpoint) may be included in an input control signal received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n.', 'In other examples, data and/or information identifying and/or indicating the desired choke position may be received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n separately from (e.g., prior to or subsequent to) the received input control signal.', 'In some examples, the controller \n210\n may determine a desired choke position of a choke valve by accessing, obtaining, and/or otherwise identifying desired choke position data (e.g., the choke position setpoint) stored in the example memory \n212\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines a current choke position of a choke valve.', 'For example, the controller \n210\n may determine a current choke position of a choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) by accessing, obtaining, and/or otherwise identifying stem position data sensed, measured and/or detected by the example position sensor \n202\n of \nFIG.', '2\n, and/or choke position data derived therefrom.', 'In some examples, the controller \n210\n may determine a current choke position of the choke valve based on choke position correlation data stored in the example memory \n212\n of \nFIG.', '2\n.', 'In some such examples, the choke position correlation data enables the controller \n210\n to associate (e.g., correlate) a position of the stem of the choke valve (e.g., a position of the stem \n132\n of the choke valve \n110\n of \nFIG.', '1\n) with a corresponding choke position (e.g., fifty percent closed) of the choke valve.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines a difference between a current choke position of a choke valve and a desired choke position of the choke valve.', 'For example, the controller \n210\n may determine a difference between a current choke position of a choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) and the desired choke position of the choke valve by comparing position data corresponding to the current choke position to position data corresponding to the desired choke position.', 'In some examples, the controller \n210\n determines whether the difference between the current choke position of the choke valve and the desired choke position exceeds a choke position error threshold.', 'For example, the controller \n210\n may determine that the difference between the current choke position of the choke valve and the desired choke position exceeds a choke position error threshold, thus indicating that the current choke position needs to be adjusted via one or more control signal(s) to match the desired choke position within an acceptable margin of error.', 'In some examples, the controller \n210\n of \nFIG.', '2\n generates one or more control signal(s) to adjust the current choke position of the choke valve to match the desired choke position.', 'For example, the controller \n210\n may generate one or more control signal(s) that cause(s) a hydraulic power unit (e.g., the hydraulic power unit \n106\n of \nFIGS.', '1 and 2\n)', 'to distribute hydraulic control fluid to an actuator (e.g., the actuator \n108\n of \nFIG.', '1\n) operatively coupled to the choke valve such that the actuator causes a stem and/or a plug of the choke valve (e.g., the stem \n132\n and/or the plug \n134\n of the choke valve \n110\n of \nFIG.', '1\n) to move from a current position corresponding to the current choke position of the choke valve to a desired position corresponding to the desired choke position.', 'In some examples, the one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit correspond to a difference between the current choke position of the choke valve and the desired choke position.', 'The one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit cause the stem and/or the plug of the choke valve to move in a direction that results in the current choke position of the choke valve being adjusted toward the desired choke position.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines a desired wellhead pressure of a wellhead.', 'For example the controller \n210\n may determine a desired wellhead pressure of a wellhead (e.g., the wellhead \n104\n of \nFIG.', '1\n) based on an identified wellhead pressure setpoint.', 'In some examples, data and/or information identifying and/or indicating the desired wellhead pressure (e.g., the wellhead pressure setpoint) may be included in an input control signal received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n.', 'In other examples, data and/or information identifying and/or indicating the desired wellhead pressure may be received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n separately from (e.g., prior to or subsequent to) the received input control signal.', 'In some examples, the controller \n210\n may determine a desired wellhead pressure of a wellhead by accessing, obtaining, and/or otherwise identifying desired wellhead pressure data (e.g., the wellhead pressure setpoint) stored in the example memory \n212\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines a current wellhead pressure of a wellhead.', 'For example, the controller \n210\n may determine a current wellhead pressure of a wellhead (e.g., the wellhead \n104\n of \nFIG.', '1\n) by accessing, obtaining, and/or otherwise identifying wellhead pressure data sensed, measured and/or detected by the example pressure sensor \n204\n of \nFIG.', '2\n.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines a difference between a current wellhead pressure of a wellhead and a desired wellhead pressure of the wellhead.', 'For example, the controller \n210\n may determine a difference between a current wellhead pressure of a wellhead (e.g., the wellhead \n104\n of \nFIG.', '1\n) and a desired wellhead pressure of the wellhead by comparing wellhead pressure data corresponding to the current wellhead pressure to wellhead pressure data corresponding to the desired wellhead pressure.', 'In some examples, the controller \n210\n of \nFIG.', '2\n determines whether the difference between the current wellhead pressure of the wellhead and the desired wellhead pressure exceeds a wellhead pressure error threshold.', 'For example, the controller \n210\n may determine that the difference between the current wellhead pressure of the wellhead and the desired wellhead pressure exceeds a wellhead pressure error threshold, thus indicating that the current wellhead pressure needs to be adjusted via one or more control signal(s) to match the desired wellhead pressure within an acceptable margin of error.', 'In some examples, the controller \n210\n of \nFIG.', '2\n generates one or more control signal(s) to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure.', 'For example, the controller \n210\n may generate one or more control signal(s) that cause(s) a hydraulic power unit (e.g., the hydraulic power unit \n106\n of \nFIGS.', '1 and 2\n)', 'to distribute hydraulic control fluid to an actuator (e.g., the actuator \n108\n of \nFIG.', '1\n) operatively coupled to a choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) such that the actuator causes a stem and/or a plug of the choke valve (e.g., the stem \n132\n and/or the plug \n134\n of the choke valve \n110\n of \nFIG.', '1\n) to move from a current position corresponding to the current wellhead pressure of the wellhead to a desired position corresponding to the desired wellhead pressure.', 'In some examples, the controller \n210\n accesses wellhead pressure correlation data stored in the memory \n212\n of \nFIG.', '2\n to associate (e.g. correlate) a position of a stem of a choke valve (e.g., a position of the stem \n132\n of the choke valve \n110\n of \nFIG.', '1\n) to a corresponding wellhead pressure of a wellhead (e.g., a wellhead pressure of the wellhead \n104\n of \nFIG.', '1\n).', 'In some examples, the one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit correspond to a difference between the current wellhead pressure and the desired wellhead pressure, and/or to a difference between a current position of the stem corresponding to the current wellhead pressure and a desired position of the stem corresponding to the desired wellhead pressure.', 'The one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit cause the stem and/or the plug of the choke valve to move in a direction that results in the current wellhead pressure of the wellhead being adjusted toward the desired wellhead pressure.', 'The example memory \n212\n of \nFIG.', '2\n may be implemented by any type(s) and/or any number(s) of storage device(s) such as a storage drive, a flash memory, a read-only memory (ROM), a random-access memory (RAM), a cache and/or any other storage medium in which information is stored for any duration (e.g., for extended time periods, permanently, brief instances, for temporarily buffering, and/or for caching of the information).', 'The information stored in the memory \n212\n may be stored in any file and/or data structure format, organization scheme, and/or arrangement.', 'The memory \n212\n is accessible to the position sensor \n202\n, the pressure sensor \n204\n, the user interface \n206\n, the mode detector \n208\n and the controller \n210\n of \nFIG.', '2\n, and/or, more generally, to the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'In some examples, the memory \n212\n of \nFIG.', '2\n stores desired choke position data (e.g., a choke position setpoint) derived from one or more signals, messages and/or commands received via the user interface \n206\n of \nFIG.', '2\n.', 'In some examples, the memory \n212\n stores current choke position data (e.g., a measured choke position) sensed, measured and/or detected by the position sensor \n202\n of \nFIG.', '2\n.', 'In some examples, the memory \n212\n stores choke position correlation data that may be accessed to associate (e.g. correlate) a position of a stem of a choke valve (e.g., a position of the stem \n132\n of the choke valve \n110\n of \nFIG.', '1\n) to a corresponding choke position (e.g., fifty percent closed) of the choke valve.', 'In some examples, the memory \n212\n stores a choke position error threshold.', 'In some examples, the memory \n212\n of \nFIG.', '2\n stores desired wellhead pressure data (e.g., a wellhead pressure setpoint) derived from one or more signals, messages and/or commands received via the user interface \n206\n of \nFIG.', '2\n.', 'In some examples, the memory \n212\n stores current wellhead pressure data (e.g., a measured wellhead pressure) sensed, measured and/or detected by the pressure sensor \n204\n of \nFIG.', '2\n.', 'In some examples, the memory \n212\n stores wellhead pressure correlation data that may be accessed to associate (e.g. correlate) a position of a stem of a choke valve (e.g., a position of the stem \n132\n of the choke valve \n110\n of \nFIG.', '1\n) to a corresponding wellhead pressure of a wellhead (e.g., a wellhead pressure of the wellhead \n104\n of \nFIG.', '1\n).', 'In some examples, the memory \n212\n stores a wellhead pressure error threshold.', 'In some examples, the automated choke control apparatus \n200\n of \nFIG.', '2\n implements and/or is operatively coupled to (e.g., in electrical communication with) a supervisor module that monitors (e.g., senses, measures, and/or detects) bottom hole and surface conditions of the well to ensure that the limitations of the drilling equipment are not exceeded.', 'In some such examples, data obtained via the supervisor module may be obtained and analyzed by the automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'The automated choke control apparatus \n200\n of \nFIG.', '2\n may control the hydraulic power unit \n106\n based in part on the data obtained from the supervisor module, thereby ensuring equipment safety while simultaneously providing for automated control of choke position and wellhead pressure.', 'While an example manner of implementing the example automated choke control apparatus \n200\n is illustrated in \nFIG.', '2\n, one or more of the elements, processes and/or devices illustrated in \nFIG.', '2\n may be combined, divided, re-arranged, omitted, eliminated and/or implemented in any other way.', 'Further, the example position sensor \n202\n, the example pressure sensor \n204\n, the example user interface \n906\n, the example mode detector \n208\n, the example controller \n210\n and/or the example memory \n214\n of \nFIG.', '2\n may be implemented by hardware, software, firmware and/or any combination of hardware, software and/or firmware.', 'Thus, for example, any of the example position sensor \n202\n, the example pressure sensor \n204\n, the example user interface \n906\n, the example mode detector \n208\n, the example controller \n210\n and/or the example memory \n214\n of \nFIG.', '2\n could be implemented by one or more analog or digital circuit(s), logic circuits, programmable processor(s), application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)) and/or field programmable logic device(s) (FPLD(s)).', 'When reading any of the apparatus or system claims of this patent to cover a purely software and/or firmware implementation, at least one of the example position sensor \n202\n, the example pressure sensor \n204\n, the example user interface \n906\n, the example mode detector \n208\n, the example controller \n210\n and/or the example memory \n214\n of \nFIG.', '2\n is/are hereby expressly defined to include a tangible computer readable storage device or storage disk such as a memory, a digital versatile disk (DVD), a compact disk (CD), a Blu-ray disk, etc. storing the software and/or firmware.', 'Further still, the example automated choke control apparatus \n200\n of \nFIG.', '2\n may include one or more elements, processes and/or devices in addition to, or instead of, those illustrated in \nFIG.', '2\n, and/or may include more than one of any or all of the illustrated elements, processes and devices.', 'A flowchart representative of an example method that may be executed at the example automated choke control apparatus \n200\n of \nFIG.', '2\n to selectively control a choke position of a choke valve or a wellhead pressure of a wellhead is shown in \nFIGS.', '3A and 3B\n.', 'In this example, the method may be implemented using machine-readable instructions that comprise one or more program(s) for execution by a processor such as the example processor \n402\n shown in the example processor platform \n400\n discussed below in connection with \nFIG.', '4\n.', 'The one or more program(s) may be embodied in software stored on a tangible computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor \n402\n, but the entire program(s) and/or parts thereof could alternatively be executed by a device other than the processor \n402\n, and/or embodied in firmware or dedicated hardware.', 'Further, although the example program(s) is/are described with reference to the flowchart illustrated in \nFIGS.', '3A and 3B\n, many other automated methods for selectively controlling a choke position of a choke valve or a wellhead pressure of a wellhead may be used.', 'For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated, or combined.', 'As mentioned above, the example method of \nFIGS.', '3A and 3B\n may be implemented using coded instructions (e.g., computer and/or machine-readable instructions) stored on a tangible computer readable storage medium such as a hard disk drive, a flash memory, a read-only memory (ROM), a compact disk (CD), a digital versatile disk (DVD), a cache, a random-access memory (RAM) and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information).', 'As used herein, the term “tangible computer readable storage medium” is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media.', 'As used herein, “tangible computer readable storage medium” and “tangible machine readable storage medium” are used interchangeably.', 'Additionally or alternatively, the example method of \nFIGS.', '3A and 3B\n may be implemented using coded instructions (e.g., computer and/or machine-readable instructions) stored on a non-transitory computer and/or machine-readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information).', 'As used herein, the term “non-transitory computer readable medium” is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media.', 'As used herein, when the phrase “at least” is used as the transition term in a preamble of a claim, it is open-ended in the same manner as the term “comprising” is open ended.', 'FIGS.', '3A and 3B\n are a flowchart representative of an example method \n300\n that may be executed at the example automated choke control apparatus \n200\n of \nFIG.', '2\n to selectively control a choke position of a choke valve or a wellhead pressure of a wellhead.', 'The example method \n300\n begins when the example controller \n210\n of \nFIG.', '2\n determines whether an input control signal has been received (block \n302\n).', 'For example, the controller \n210\n may determine that an input control signal has been received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n.', 'If the controller \n210\n determines at block \n302\n that an input control signal has not been received, control of the example method \n300\n remains at block \n302\n.', 'If the controller \n210\n instead determines at block \n302\n that an input control signal has been received, control of the example method \n300\n proceeds to block \n304\n.', 'At block \n304\n, the example mode detector \n208\n of \nFIG.', '2\n determines whether the input control signal indicates selection of a choke position control mode (block \n304\n).', 'For example, the mode detector \n208\n may determine that the input control signal detected at block \n302\n of the method \n300\n indicates selection of a choke position control mode based on data and/or information (e.g., a mode selection bit, a choke position setpoint, a desired choke position, etc.) included within and/or indicated by the input control signal.', 'If the mode detector \n208\n determines at block \n304\n that the input control signal indicates selection of a choke position control mode, control of the example method \n300\n proceeds to block \n306\n.', 'If the mode detector \n208\n instead determines at block \n304\n that the input control signal does not indicate selection of a choke position control mode, control of the example method \n300\n proceeds to block \n320\n.', 'At block \n306\n, the example controller \n210\n of \nFIG.', '2\n determines a desired choke position of a choke valve (block \n306\n).', 'For example the controller \n210\n may determine a desired choke position of a choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) based on an identified choke position setpoint.', 'In some examples, data and/or information identifying and/or indicating the desired choke position (e.g., the choke position setpoint) may be included in the input control signal detected at block \n302\n of the method \n300\n.', 'In other examples, data and/or information identifying and/or indicating the desired choke position may be received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n separately from (e.g., prior to or subsequent to) the input control signal detected at block \n302\n of the method \n300\n.', 'In some examples, the controller \n210\n determines a desired choke position of a choke valve by accessing, obtaining, and/or otherwise identifying desired choke position data (e.g., the choke position setpoint) stored in the example memory \n212\n of \nFIG.', '2\n.', 'Following block \n306\n, control of the example method \n300\n proceeds to block \n308\n.', 'At block \n308\n, the example controller \n210\n of \nFIG.', '2\n determines a current choke position of the choke valve (block \n308\n).', 'For example, the controller \n210\n may determine a current choke position of the choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) by accessing, obtaining, and/or otherwise identifying stem position data sensed, measured and/or detected by the example position sensor \n202\n of \nFIG.', '2\n, and/or choke position data derived therefrom.', 'In some examples, the controller \n210\n may determine a current choke position of the choke valve based on choke position correlation data stored in the example memory \n212\n of \nFIG.', '2\n.', 'In some such examples, the choke position correlation data enables the controller \n210\n to associate (e.g., correlate) a position of the stem of the choke valve (e.g., a position of the stem \n132\n of the choke valve \n110\n of \nFIG.', '1\n) with a corresponding choke position (e.g., fifty percent closed) of the choke valve.', 'Following block \n308\n, control of the example method \n300\n proceeds to block \n310\n.', 'At block \n310\n, the example controller \n210\n of \nFIG.', '2\n determines a difference between the current choke position and the desired choke position (block \n310\n).', 'For example, the controller \n210\n may determine a difference between the current choke position and the desired choke position by comparing position data corresponding to the current choke position to position data corresponding to the desired choke position.', 'Following block \n310\n, control of the example method \n300\n proceeds to block \n312\n.', 'At block \n312\n, the example controller \n210\n of \nFIG.', '2\n determines whether the difference between the current choke position and the desired choke position exceeds a choke position error threshold (block \n312\n).', 'For example, the controller \n210\n may determine that the difference between the current choke position and the desired choke position exceeds a choke position error threshold, thus indicating that the current choke position needs to be adjusted via one or more control signal(s) to match the desired choke position within an acceptable margin of error.', 'If the controller \n210\n determines at block \n312\n that the difference between the current choke position and the desired choke position does not exceed the choke position error threshold, control of the example method \n300\n returns to block \n308\n.', 'If the controller \n210\n instead determines at block \n312\n that the difference between the current choke position and the desired choke position exceeds the choke position error threshold, control of the example method \n300\n proceeds to block \n314\n.', 'At block \n314\n, the example controller \n210\n of \nFIG.', '2\n generates one or more control signal(s) to adjust the current choke position of the choke valve to match the desired choke position (block \n314\n).', 'For example, the controller \n210\n may generate one or more control signal(s) that cause(s) a hydraulic power unit (e.g., the hydraulic power unit \n106\n of \nFIGS.', '1 and 2\n)', 'to distribute hydraulic control fluid to an actuator (e.g., the actuator \n108\n of \nFIG.', '1\n) operatively coupled to the choke valve such that the actuator causes a stem and/or a plug of the choke valve (e.g., the stem \n132\n and/or the plug \n134\n of the choke valve \n110\n of \nFIG.', '1\n) to move from a current position corresponding to the current choke position of the choke valve to a desired position corresponding to the desired choke position.', 'In some examples, the one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit correspond to a difference between the current choke position and the desired choke position, and/or to a difference between a current position of the stem corresponding to the current choke position and a desired position of the stem corresponding to the desired choke position.', 'The one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit cause the stem and/or the plug of the choke valve to move in a direction that results in the current choke position of the choke valve being adjusted toward the desired choke position.', 'Following block \n314\n, control of the example method \n300\n proceeds to block \n316\n.', 'At block \n316\n, the example controller \n210\n of \nFIG.', '2\n determines whether an updated input control signal has been received (block \n316\n).', 'For example, the controller \n210\n may determine that an updated input control signal (e.g., a more recent input control signal relative to the input control signal detected at block \n302\n of the method \n300\n) has been received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n.', 'If the controller \n210\n determines at block \n316\n that an updated input control signal has not been received, control of the example method \n300\n returns to block \n308\n.', 'If the controller \n210\n instead determines at block \n316\n that an updated input control signal has been received, control of the example method \n300\n proceeds to block \n318\n.', 'At block \n318\n, the example mode detector \n208\n of \nFIG.', '2\n determines whether the updated input control signal indicates selection of a manual override mode (block \n318\n).', 'For example, the mode detector \n208\n may determine that the updated input control signal detected at block \n316\n of the method \n300\n indicates selection of a manual override mode based on data and/or information (e.g., a mode selection bit, a manual override code, etc.) included within and/or indicated by the updated input control signal.', 'If the mode detector \n208\n determines at block \n318\n that the updated input control signal does not indicate selection of a manual override mode, control of the example method \n300\n returns to block \n304\n.', 'If the mode detector \n208\n instead determines at block \n318\n that the updated input control signal indicates selection of a manual override mode, the example method \n300\n ends.', 'At block \n320\n, the example mode detector \n208\n of \nFIG.', '2\n determines whether the input control signal indicates selection of a wellhead pressure control mode (block \n320\n).', 'For example, the mode detector \n208\n may determine that the input control signal (e.g., the input control signal detected at block \n302\n, the updated input control signal detected at block \n316\n, etc.) indicates selection of a wellhead pressure control mode based on data and/or information (e.g., a mode selection bit, a wellhead pressure setpoint, a desired wellhead pressure, etc.) included within and/or indicated by the input control signal.', 'If the mode detector \n208\n determines at block \n320\n that the input control signal indicates selection of a wellhead pressure control mode, control of the example method \n300\n proceeds to block \n322\n.', 'If the mode detector \n208\n instead determines at block \n320\n that the input control signal does not indicate selection of a wellhead pressure control mode, the example method \n300\n ends.', 'At block \n322\n, the example controller \n210\n of \nFIG.', '2\n determines a desired wellhead pressure of a wellhead (block \n322\n).', 'For example the controller \n210\n may determine a desired wellhead pressure of a wellhead (e.g., the wellhead \n104\n of \nFIG.', '1\n) based on an identified wellhead pressure setpoint.', 'In some examples, data and/or information identifying and/or indicating the desired wellhead pressure (e.g., the wellhead pressure setpoint) may be included in the input control signal detected at block \n302\n of the method \n300\n.', 'In other examples, data and/or information identifying and/or indicating the desired wellhead pressure may be received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n separately from (e.g., prior to or subsequent to) the input control signal detected at block \n302\n of the method \n300\n.', 'In some examples, the controller \n210\n determines a desired wellhead pressure of a wellhead by accessing, obtaining, and/or otherwise identifying desired wellhead pressure data (e.g., the wellhead pressure setpoint) stored in the example memory \n212\n of \nFIG.', '2\n.', 'Following block \n322\n, control of the example method \n300\n proceeds to block \n324\n.', 'At block \n324\n, the example controller \n210\n of \nFIG.', '2\n determines a current wellhead pressure of the wellhead (block \n324\n).', 'For example, the controller \n210\n may determine a current wellhead pressure of the wellhead (e.g., the wellhead \n104\n of \nFIG.', '1\n) by accessing, obtaining, and/or otherwise identifying wellhead pressure data sensed, measured and/or detected by the example pressure sensor \n204\n of \nFIG.', '2\n.', 'Following block \n324\n, control of the example method \n300\n proceeds to block \n326\n.', 'At block \n326\n, the example controller \n210\n of \nFIG.', '2\n determines a difference between the current wellhead pressure and the desired wellhead pressure (block \n326\n).', 'For example, the controller \n210\n may determine a difference between the current wellhead pressure and the desired wellhead pressure by comparing wellhead pressure data corresponding to the current wellhead pressure to wellhead pressure data corresponding to the desired wellhead pressure.', 'Following block \n326\n, control of the example method \n300\n proceeds to block \n328\n.', 'At block \n328\n, the example controller \n210\n of \nFIG.', '2\n determines whether the difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold (block \n328\n).', 'For example, the controller \n210\n may determine that the difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold, thus indicating that the current wellhead pressure needs to be adjusted via one or more control signal(s) to match the desired wellhead pressure within an acceptable margin of error.', 'If the controller \n210\n determines at block \n328\n that the difference between the current wellhead pressure and the desired wellhead pressure does not exceed the wellhead pressure error threshold, control of the example method \n300\n returns to block \n324\n.', 'If the controller \n210\n instead determines at block \n328\n that the difference between the current wellhead pressure and the desired wellhead pressure exceeds the wellhead pressure error threshold, control of the example method \n300\n proceeds to block \n330\n.', 'At block \n330\n, the example controller \n210\n of \nFIG.', '2\n generates one or more control signal(s) to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure (block \n330\n).', 'For example, the controller \n210\n may generate one or more control signal(s) that cause(s) a hydraulic power unit (e.g., the hydraulic power unit \n106\n of \nFIGS.', '1 and 2\n)', 'to distribute hydraulic control fluid to an actuator (e.g., the actuator \n108\n of \nFIG.', '1\n) operatively coupled to a choke valve (e.g., the choke valve \n110\n of \nFIG.', '1\n) such that the actuator causes a stem and/or a plug of the choke valve (e.g., the stem \n132\n and/or the plug \n134\n of the choke valve \n110\n of \nFIG.', '1\n) to move from a current position corresponding to the current wellhead pressure of the wellhead to a desired position corresponding to the desired wellhead pressure.', 'In some examples, the controller \n210\n accesses wellhead pressure correlation data stored in the memory \n212\n of \nFIG.', '2\n to associate (e.g. correlate) a position of a stem of a choke valve (e.g., a position of the stem \n132\n of the choke valve \n110\n of \nFIG.', '1\n) to a corresponding wellhead pressure of a wellhead (e.g., a wellhead pressure of the wellhead \n104\n of \nFIG.', '1\n).', 'In some examples, the one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit correspond to a difference between the current wellhead pressure and the desired wellhead pressure, and/or to a difference between a current position of the stem corresponding to the current wellhead pressure and a desired position of the stem corresponding to the desired wellhead pressure.', 'The one or more control signal(s) generated by the controller \n210\n and supplied to the hydraulic power unit cause the stem and/or the plug of the choke valve to move in a direction that results in the current wellhead pressure of the wellhead being adjusted toward the desired wellhead pressure.', 'Following block \n330\n, control of the example method \n300\n proceeds to block \n332\n.', 'At block \n332\n, the example controller \n210\n of \nFIG.', '2\n determines whether an updated input control signal has been received (block \n332\n).', 'For example, the controller \n210\n may determine that an updated input control signal (e.g., a more recent input control signal relative to the input control signal detected at block \n302\n of the method \n300\n) has been received via one or more of the input device(s) \n214\n of the user interface \n206\n of \nFIG.', '2\n.', 'If the controller \n210\n determines at block \n332\n that an updated input control signal has not been received, control of the example method \n300\n returns to block \n324\n.', 'If the controller \n210\n instead determines at block \n332\n that an updated input control signal has been received, control of the example method \n300\n proceeds to block \n334\n.', 'At block \n334\n, the example mode detector \n208\n of \nFIG.', '2\n determines whether the updated input control signal indicates selection of a manual override mode (block \n334\n).', 'For example, the mode detector \n208\n may determine that the updated input control signal detected at block \n332\n of the method \n300\n indicates selection of a manual override mode based on data and/or information (e.g., a mode selection bit) included within and/or indicated by the updated input control signal.', 'If the mode detector \n208\n determines at block \n334\n that the updated input control signal does not indicate selection of a manual override mode, control of the example method \n300\n returns to block \n304\n.', 'If the mode detector \n208\n instead determines at block \n334\n that the updated input control signal indicates selection of a manual override mode, the example method \n300\n ends.', 'FIG.', '4\n is an example processor platform \n400\n capable of executing instructions to implement the example method \n300\n of \nFIGS.', '3A and 3B\n and the example automated choke control apparatus \n200\n of \nFIG.', '2\n.', 'The processor platform \n400\n of the illustrated example includes a processor \n402\n.', 'The processor \n402\n of the illustrated example is hardware.', 'For example, the processor \n402\n can be implemented by one or more integrated circuit(s), logic circuit(s), microprocessor(s) or controller(s) from any desired family or manufacturer.', 'The processor \n402\n of the illustrated example includes a local memory \n404\n (e.g., a cache).', 'The processor \n402\n also includes the example mode detector \n208\n and the example controller \n210\n of \nFIG.', '2\n.', 'The processor \n402\n of the illustrated example is in communication with one or more example sensors \n406\n via a bus \n408\n.', 'The example sensors \n406\n include the example position sensor \n202\n and the example pressure sensor \n204\n of \nFIG.', '2\n.', 'The processor \n402\n of the illustrated example is also in communication with a main memory including a volatile memory \n410\n and a non-volatile memory \n412\n via the bus \n408\n.', 'The volatile memory \n410\n may be implemented by Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS Dynamic Random Access Memory (RDRAM) and/or any other type of random access memory device.', 'The non-volatile memory \n412\n may be implemented by flash memory and/or any other desired type of memory device.', 'Access to the volatile memory \n410\n and the non-volatile memory \n412\n is controlled by a memory controller.', 'The processor \n402\n of the illustrated example is also in communication with one or more mass storage devices \n414\n for storing software and/or data.', 'Examples of such mass storage devices \n414\n include floppy disk drives, hard drive disks, compact disk drives, Blu-ray disk drives, RAID systems, and digital versatile disk (DVD) drives.', 'In the illustrated example, the mass storage device \n414\n includes the example memory \n212\n of \nFIG.', '2\n.', 'The processor platform \n400\n of the illustrated example also includes a user interface circuit \n416\n.', 'The user interface circuit \n416\n may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), and/or a PCI express interface.', 'In the illustrated example, one or more input device(s) \n214\n are connected to the user interface circuit \n416\n.', 'The input device(s) \n214\n permit(s) a user to enter data and commands into the processor \n402\n.', 'The input device(s) \n214\n can be implemented by, for example, a button, a switch, a dial, a keyboard, a mouse, a touchscreen, an audio sensor, a camera (still or video), a track-pad, a trackball, isopoint, a voice recognition system, a microphone, and/or a liquid crystal display.', 'One or more output device(s) \n216\n are also connected to the user interface circuit \n416\n of the illustrated example.', 'The output device(s) \n216\n can be implemented, for example, by a light emitting diode, an organic light emitting diode, a liquid crystal display, a touchscreen and/or a speaker.', 'The user interface circuit \n416\n of the illustrated example may, thus, include a graphics driver such as a graphics driver chip and/or processor.', 'In the illustrated example, the input device(s) \n214\n, the output device(s) \n216\n and the user interface circuit \n416\n collectively form the example user interface \n206\n of \nFIG.', '2\n.', 'The processor platform \n400\n of the illustrated example also includes a network interface circuit \n418\n.', 'The network interface circuit \n418\n may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), and/or a PCI express interface.', 'In the illustrated example, the network interface circuit \n418\n facilitates the exchange of data and/or signals with external machines via a network \n420\n.', 'In some examples, the network \n420\n may be facilitated via 4-20 mA wiring and/or via one or more communication protocol(s) including, for example, Foundation Fieldbus, Highway Addressable Remote Transducer (HART), Transmission Control Protocol/Internet Protocol (TCP/IP), Profinet, Modbus and/or Ethernet.', 'Coded instructions \n422\n for implementing the method \n300\n of \nFIGS.', '3A and 3B\n may be stored in the local memory \n404\n, in the volatile memory \n410\n, in the non-volatile memory \n412\n, in the mass storage device \n414\n, and/or on a removable tangible computer readable storage medium such as a CD or DVD.', 'From the foregoing, it will be appreciated that the disclosed automated choke control apparatus and methods provide numerous advantages over conventional choke control systems.', 'For example, implementation of the disclosed automated choke control apparatus and methods provide for selective control of the wellhead pressure of the wellhead via a wellhead pressure control loop, or the choke position of the choke valve via a choke position control loop.', 'Accordingly, implementation of the disclosed automated choke control apparatus and methods advantageously reduces the extent of human intervention needed to maintain a wellhead pressure of a wellhead and/or a choke position of a choke valve at desirable value(s).', 'Reducing the extent of human intervention reduces the possibility of human exposure to a well scenario (e.g., a blowout) and also reduces operational risks associated with human errors.', 'The aforementioned advantages and/or benefits are achieved via the disclosed automated choke control apparatus and methods.', 'In some examples, an apparatus for automatically controlling a choke valve is disclosed.', 'In some disclosed examples, the apparatus comprises a controller.', 'In some disclosed examples, the controller is to control a choke position of the choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected.', 'In some disclosed examples, the controller is to control a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected.', 'In some disclosed examples, the wellhead is operatively coupled to the choke valve.', 'In some disclosed examples of the apparatus, the controller, while controlling the choke position of the choke valve via the first control loop, is to determine a desired choke position of the choke valve and to determine a current choke position of the choke valve.', 'In some disclosed examples of the apparatus, the controller, while controlling the choke position of the choke valve via the first control loop, is further to generate a control signal in response to determining that a difference between the current choke position and the desired choke position exceeds a choke position error threshold.', 'In some disclosed examples, the generated control signal is to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current choke position of the choke valve to match the desired choke position.', 'In some disclosed examples of the apparatus, the controller, while controlling the wellhead pressure of the wellhead via the second control loop, is to determine a desired wellhead pressure of the wellhead and to determine a current wellhead pressure of the wellhead.', 'In some disclosed examples of the apparatus, the controller, while controlling the wellhead pressure of the wellhead via the second control loop, is further to generate a control signal in response to determining that a difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold.', 'In some disclosed examples, the generated control signal is to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure by adjusting a current choke position of the choke valve.', 'In some disclosed examples of the apparatus, the controller is further to control the choke position of the choke valve via the first control loop until selection of the second one of the plurality of operation modes or selection of a third one of the plurality of operation modes is detected.', 'In some disclosed examples of the apparatus, the controller is further to control the wellhead pressure of the wellhead via the second control loop until selection of the first one of the plurality of operation modes or selection of the third one of the plurality of operation modes is detected.', 'In some disclosed examples, the third one of the plurality of operation modes is a manual override mode.', 'In some disclosed examples, the apparatus further comprises a user interface to receive input control signals associated with automatically controlling the choke valve.', 'In some disclosed examples, the apparatus further comprises a mode detector to detect selection of respective ones of the first one, the second one, and the third one of the plurality of operation modes based on mode identification data included in corresponding ones of the input control signals received via the user interface.', 'In some disclosed examples, the mode identification data includes at least one of a mode selection bit, a choke position setpoint, a wellhead pressure setpoint, or a manual override code.', 'In some examples, a method for automatically controlling a choke valve is disclosed.', 'In some disclosed examples, the method comprises controlling a choke position of the choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected.', 'In some disclosed examples, the method comprises controlling a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected.', 'In some disclosed examples, the wellhead is operatively coupled to the choke valve.', 'In some disclosed examples of the method, controlling the choke position of the choke valve via the first control loop comprises determining a desired choke position of the choke valve and determining a current choke position of the choke valve.', 'In some disclosed examples of the method, controlling the choke position of the choke valve via the first control loop further comprises generating a control signal in response to determining that a difference between the current choke position and the desired choke position exceeds a choke position error threshold.', 'In some disclosed examples, the generated control signal is to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current choke position of the choke valve to match the desired choke position.', 'In some disclosed examples of the method, controlling the wellhead pressure of the wellhead via the second control loop comprises determining a desired wellhead pressure of the wellhead and determining a current wellhead pressure of the wellhead.', 'In some disclosed examples of the method, controlling the wellhead pressure of the wellhead via the second control loop comprises generating a control signal in response to determining that a difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold.', 'In some disclosed examples, the generated control signal is to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure by adjusting a current choke position of the choke valve.', 'In some disclosed examples, the method further comprises controlling the choke position of the choke valve via the first control loop until selection of the second one of the plurality of operation modes or selection of a third one of the plurality of operation modes is detected.', 'In some disclosed examples, the method further comprises controlling the wellhead pressure of the wellhead via the second control loop until selection of the first one of the plurality of operation modes or selection of the third one of the plurality of operation modes is detected.', 'In some disclosed examples, the third one of the plurality of operation modes is a manual override mode.', 'In some disclosed examples, the method further comprises receiving, via a user interface, input control signals associated with automatically controlling the choke valve.', 'In some disclosed examples, the method further comprises detecting selection of respective ones of the first one, the second one, and the third one of the plurality of operation modes based on mode identification data included in corresponding ones of the input control signals received via the user interface.', 'In some disclosed examples, the mode identification data includes at least one of a mode selection bit, a choke position setpoint, a wellhead pressure setpoint, or a manual override code.', 'In some examples, a tangible machine readable storage medium comprising instructions is disclosed.', 'In some disclosed examples, the instructions, when executed, cause a controller to control a choke position of a choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected.', 'In some disclosed examples, the instructions, when executed, cause the controller to control a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected.', 'In some disclosed examples, the wellhead is operatively coupled to the choke valve.', 'In some disclosed examples of the tangible machine readable storage medium, the instructions, when executed, cause the controller controlling the choke position of the choke valve via the first control loop to determine a desired choke position of the choke valve and determining a current choke position of the choke valve.', 'In some disclosed examples of the tangible machine readable storage medium, the instructions, when executed, cause the controller controlling the choke position of the choke valve via the first control loop to generate a control signal in response to determining that a difference between the current choke position and the desired choke position exceeds a choke position error threshold.', 'In some disclosed examples, the generated control signal is to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current choke position of the choke valve to match the desired choke position.', 'In some disclosed examples of the tangible machine readable storage medium, the instructions, when executed, cause the controller controlling the wellhead pressure of the wellhead via the second control loop to determine a desired wellhead pressure of the wellhead and determining a current wellhead pressure of the wellhead.', 'In some disclosed examples of the tangible machine readable storage medium, the instructions, when executed, cause the controller controlling the wellhead pressure of the wellhead via the second control loop to generate a control signal in response to determining that a difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold.', 'In some disclosed examples, the generated control signal is to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure by adjusting a current choke position of the choke valve.', 'In some disclosed examples of the tangible machine readable storage medium, the instructions, when executed, cause the controller to control the choke position of the choke valve via the first control loop until selection of the second one of the plurality of operation modes or selection of a third one of the plurality of operation modes is detected.', 'In some disclosed examples of the tangible machine readable storage medium, the instructions, when executed, cause the controller to control the wellhead pressure of the wellhead via the second control loop until selection of the first one of the plurality of operation modes or selection of the third one of the plurality of operation modes is detected.', 'In some disclosed examples, the third one of the plurality of operation modes is a manual override mode.', 'In some disclosed examples of the tangible machine readable storage medium, the instructions, when executed, cause the controller to detect selection of respective ones of the first one, the second one, and the third one of the plurality of operation modes based on mode identification data included in corresponding ones of input control signals received via a user interface.', 'In some disclosed examples, the corresponding ones of the input control signals are associated with automatically controlling the choke valve.', 'In some disclosed examples, the mode identification data includes at least one of a mode selection bit, a choke position setpoint, a wellhead pressure setpoint, or a manual override code.', 'In some disclosed examples, the choke may be used as a drilling choke by linking it to wellhead sensors at the same time as a testing choke for use during a well testing operation.', 'The choke provides an accurate choke size with various methods to measure the size of the choke.', 'Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.'] | ['1.', 'An apparatus for automatically controlling a choke valve, the apparatus comprising:\na controller to: control a choke position of the choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected; and control a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected, the wellhead operatively coupled to the choke valve.', '2.', 'The apparatus of claim 1, wherein the controller, while controlling the choke position of the choke valve via the first control loop, is to:\ndetermine a desired choke position of the choke valve;\ndetermine a current choke position of the choke valve; and\ngenerate a control signal in response to determining that a difference between the current choke position and the desired choke position exceeds a choke position error threshold, the control signal to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current choke position of the choke valve to match the desired choke position.', '3.', 'The apparatus of claim 1, wherein the controller, while controlling the wellhead pressure of the wellhead via the second control loop, is to:\ndetermine a desired wellhead pressure of the wellhead;\ndetermine a current wellhead pressure of the wellhead; and\ngenerate a control signal in response to determining that a difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold, the control signal to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure by adjusting a current choke position of the choke valve.', '4.', 'The apparatus of claim 1, wherein the controller is further to:\ncontrol the choke position of the choke valve via the first control loop until selection of the second one of the plurality of operation modes or selection of a third one of the plurality of operation modes is detected; and\ncontrol the wellhead pressure of the wellhead via the second control loop until selection of the first one of the plurality of operation modes or selection of the third one of the plurality of operation modes is detected.', '5.', 'The apparatus of claim 4, wherein the third one of the plurality of operation modes is a manual override mode.', '6.', 'The apparatus of claim 4, further comprising:\na user interface to receive input control signals associated with automatically controlling the choke valve; and\na mode detector to detect selection of respective ones of the first one, the second one, and the third one of the plurality of operation modes based on mode identification data included in corresponding ones of the input control signals received via the user interface.', '7.', 'The apparatus of claim 6, wherein the mode identification data includes at least one of a mode selection bit, a choke position setpoint, a wellhead pressure setpoint, or a manual override code.', '8.', 'A method for automatically controlling a choke valve, the method comprising:\ncontrolling a choke position of the choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected; and\ncontrolling a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected, the wellhead operatively coupled to the choke valve.\n\n\n\n\n\n\n9.', 'The method of claim 8, wherein controlling the choke position of the choke valve via the first control loop comprises:\ndetermining a desired choke position of the choke valve;\ndetermining a current choke position of the choke valve; and\ngenerating a control signal in response to determining that a difference between the current choke position and the desired choke position exceeds a choke position error threshold, the control signal to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current choke position of the choke valve to match the desired choke position.', '10.', 'The method of claim 8, wherein controlling the wellhead pressure of the wellhead via the second control loop comprises:\ndetermining a desired wellhead pressure of the wellhead;\ndetermining a current wellhead pressure of the wellhead; and\ngenerating a control signal in response to determining that a difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold, the control signal to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure by adjusting a current choke position of the choke valve.', '11.', 'The method of claim 8, further comprising:\ncontrolling the choke position of the choke valve via the first control loop until selection of the second one of the plurality of operation modes or selection of a third one of the plurality of operation modes is detected; and\ncontrolling the wellhead pressure of the wellhead via the second control loop until selection of the first one of the plurality of operation modes or selection of the third one of the plurality of operation modes is detected.\n\n\n\n\n\n\n12.', 'The method of claim 11, wherein the third one of the plurality of operation modes is a manual override mode.', '13.', 'The method of claim 11, further comprising:\nreceiving, via a user interface, input control signals associated with automatically controlling the choke valve; and\ndetecting selection of respective ones of the first one, the second one, and the third one of the plurality of operation modes based on mode identification data included in corresponding ones of the input control signals received via the user interface.', '14.', 'The method of claim 13, wherein the mode identification data includes at least one of a mode selection bit, a choke position setpoint, a wellhead pressure setpoint, or a manual override code.', '15.', 'A tangible machine readable storage medium comprising instructions that, when executed, cause a controller to at least:\ncontrol a choke position of a choke valve via a first control loop in response to selection of a first one of a plurality of operation modes being detected; and\ncontrol a wellhead pressure of a wellhead via a second control loop in response to selection of a second one of the plurality of operation modes being detected, the wellhead operatively coupled to the choke valve.', '16.', 'The tangible machine readable storage medium of claim 15, wherein the instructions, when executed, are further to cause the controller controlling the choke position of the choke valve via the first control loop to:\ndetermine a desired choke position of the choke valve;\ndetermine a current choke position of the choke valve; and\ngenerate a control signal in response to determining that a difference between the current choke position and the desired choke position exceeds a choke position error threshold, the control signal to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current choke position of the choke valve to match the desired choke position.\n\n\n\n\n\n\n17.', 'The tangible machine readable storage medium of claim 15, wherein the instructions, when executed, are further to cause the controller controlling the wellhead pressure of the wellhead via the second control loop to:\ndetermine a desired wellhead pressure of the wellhead;\ndetermine a current wellhead pressure of the wellhead; and\ngenerate a control signal in response to determining that a difference between the current wellhead pressure and the desired wellhead pressure exceeds a wellhead pressure error threshold, the control signal to cause a hydraulic power unit and an actuator operatively coupled to the choke valve to adjust the current wellhead pressure of the wellhead to match the desired wellhead pressure by adjusting a current choke position of the choke valve.\n\n\n\n\n\n\n18.', 'The tangible machine readable storage medium of claim 15, wherein the instructions, when executed, are further to cause the controller to:\ncontrol the choke position of the choke valve via the first control loop until selection of the second one of the plurality of operation modes or selection of a third one of the plurality of operation modes is detected; and\ncontrol the wellhead pressure of the wellhead via the second control loop until selection of the first one of the plurality of operation modes or selection of the third one of the plurality of operation modes is detected, the third one of the plurality of operation modes being a manual override mode.', '19.', 'The tangible machine readable storage medium of claim 18, wherein the instructions, when executed, are further to cause the controller to:\ndetect selection of respective ones of the first one, the second one, and the third one of the plurality of operation modes based on mode identification data included in corresponding ones of input control signals received via a user interface, the corresponding ones of the input control signals being associated with automatically controlling the choke valve.', '20.', 'The tangible machine readable storage medium of claim 19, wherein the mode identification data includes at least one of a mode selection bit, a choke position setpoint, a wellhead pressure setpoint, or a manual override code.'] | ['FIG.', '1 is a block diagram of a known choke control system.; FIG.', '2 is a block diagram of an example automated choke control apparatus that may be implemented in accordance with the teachings of this disclosure.;', 'FIGS.', '3A and 3B are a flowchart representative of an example method that may be executed at the example automated choke control apparatus of FIG.', '2 to selectively control a choke position of a choke valve or a pressure of a wellhead.; FIG.', '4 is an example processor platform capable of executing instructions to implement the method of FIGS.', '3A and 3B and the example automated choke control apparatus of FIG.', '2.; FIG.', '1 is a block diagram of a known choke control system 100.', 'The choke control system 100 includes a control panel 102, a wellhead 104, a hydraulic power unit 106, an actuator 108 and a choke valve 110.', 'The choke control system 100 manages and/or controls the wellhead pressure (e.g. surface pressure) of a wellhead (e.g., the wellhead 104) operatively coupled to a well (not shown).', 'By managing and/or controlling the wellhead pressure, the choke control system 100 also manages and/or controls the production rate from the well.', 'Management and/or control of the wellhead pressure via the choke control system 100 may prevent kicks and/or blowouts of the well from occurring.; FIG.', '2 is a block diagram of an example automated choke control apparatus 200 that may be implemented in accordance with the teachings of this disclosure.', 'As described in greater detail herein, the automated choke control apparatus 200 of FIG.', '2 is operatively coupled to one or more structure(s) and/or component(s) of a choke control system (e.g., the known choke control system 100 of FIG. 1).', 'In the illustrated example of FIG.', '2, the automated choke control apparatus 200 includes an example position sensor 202, an example pressure sensor 204, an example user interface 206, an example mode detector 208, an example controller 210, and an example memory 212.', 'However, other example implementations of the automated choke control apparatus 200 may include fewer or additional structures in accordance with the teachings of this disclosure.', '; FIGS.', '3A and 3B are a flowchart representative of an example method 300 that may be executed at the example automated choke control apparatus 200 of FIG.', '2 to selectively control a choke position of a choke valve or a wellhead pressure of a wellhead.', 'The example method 300 begins when the example controller 210 of FIG.', '2 determines whether an input control signal has been received (block 302).', 'For example, the controller 210 may determine that an input control signal has been received via one or more of the input device(s) 214 of the user interface 206 of FIG.', '2.', 'If the controller 210 determines at block 302 that an input control signal has not been received, control of the example method 300 remains at block 302.', 'If the controller 210 instead determines at block 302 that an input control signal has been received, control of the example method 300 proceeds to block 304.; FIG.', '4 is an example processor platform 400 capable of executing instructions to implement the example method 300 of FIGS.', '3A and 3B and the example automated choke control apparatus 200 of FIG.', '2.', 'The processor platform 400 of the illustrated example includes a processor 402.', 'The processor 402 of the illustrated example is hardware.', 'For example, the processor 402 can be implemented by one or more integrated circuit(s), logic circuit(s), microprocessor(s) or controller(s) from any desired family or manufacturer.', 'The processor 402 of the illustrated example includes a local memory 404 (e.g., a cache).', 'The processor 402 also includes the example mode detector 208 and the example controller 210 of FIG.', '2.'] |
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US11092713 | Compensated azimuthally invariant electromagnetic logging measurements | Oct 14, 2016 | Peter T. Wu, Mark T. Frey | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in International Patent application PCT/US2016/056940, dated Jan. 24, 2017. 16 pages.; International Search Report and Written Opinion issued in International Patent application PCT/US2016/056945, dated Oct. 16, 2014. 14 pages.; First Office Action and Search Report issued in Chinese Patent Application 201680066656.0 dated Jul. 25, 2019, 17 pages.; Office Action issued in U.S. Appl. No. 15/773,638 dated Aug. 19, 2019, 12 pages.; Second Office Action and Search Report issued in Chinese Patent Application 201680066656.0 dated Jun. 8, 2020, 9 pages.; Gooneratne et al., Downhole Applications of Magnetic Sensors, Sensors 2017 (Oct. 19, 2017), 17, 2384; doi:10.3390/s17102384 (32 pages).; First Office Action and Search Report issued in Chinese Patent Application 201680069118.7 dated Mar. 15, 2021, 21 pages with English translation. | 5682099; October 28, 1997; Thompson et al.; 5811973; September 22, 1998; Meyer, Jr.; 6957572; October 25, 2005; Wu; 7863901; January 4, 2011; Seleznev et al.; 7991555; August 2, 2011; Yang et al.; 8433518; April 30, 2013; Omeragic et al.; 8466683; June 18, 2013; Legendre et al.; 8736271; May 27, 2014; Dion et al.; 9448324; September 20, 2016; Frey; 9541666; January 10, 2017; Frey; 9581721; February 28, 2017; Frey; 9618647; April 11, 2017; Frey; 9784880; October 10, 2017; Frey; 9804292; October 31, 2017; Bertrand et al.; 9933541; April 3, 2018; Yang; 10302805; May 28, 2019; Frey; 10371781; August 6, 2019; Homan et al.; 20050012036; January 20, 2005; Tubel et al.; 20100127708; May 27, 2010; Bittar; 20100305862; December 2, 2010; Li; 20110074427; March 31, 2011; Wang et al.; 20110166842; July 7, 2011; Banning-Geertsma et al.; 20110238312; September 29, 2011; Seydoux et al.; 20110291855; December 1, 2011; Homan et al.; 20110309833; December 22, 2011; Yang; 20130073206; March 21, 2013; Hou; 20150276967; October 1, 2015; Frey; 20150276968; October 1, 2015; Frey; 20150276973; October 1, 2015; Frey; 20170075024; March 16, 2017; Wu et al.; 20180321414; November 8, 2018; Wu et al. | 103352696; October 2013; CN; 204163719; February 2015; CN; WO2008137987; November 2008; WO; 2010134845; November 2010; WO; WO2014011190; January 2014; WO; WO2015027002; February 2015; WO; WO2015027010; February 2015; WO | ['A method for making downhole electromagnetic logging measurements of a subterranean formation is disclosed.', 'An electromagnetic logging tool is rotated in a subterranean wellbore.', 'The tool includes a transmitter axially spaced apart from a receiver.', 'The transmitter may include an axial transmitting antenna and at least one transverse transmitting antenna and the receiver may include an axial receiving antenna and at least one transverse receiving antenna.', 'The transmitting antennas transmit corresponding electromagnetic waves into the subterranean wellbore.', 'The receiving antennas receive corresponding voltage measurements which are processed to compute harmonic voltage coefficients.', 'Ratios of the selected harmonic voltage coefficients are processed to compute gain compensated, azimuthally invariant measurement quantities.'] | ['Description\n\n\n\n\n\n\nCROSS REFERENCE TO RELATED APPLICATIONS', 'The present application is the U.S. national phase of International Patent Application No. PCT/US2016/056940, filed Oct. 14, 2016, and entitled “Compensated Azimuthally Invariant Electromagnetic Logging Measurements,” which claims priority to U.S. Provisional Application 62/250,651 filed Nov. 4, 2015, the entirety of which is incorporated by reference.', 'FIELD OF THE INVENTION\n \nDisclosed embodiments relate generally to downhole electromagnetic logging methods and more particularly to a logging tool and methods for obtaining fully gain compensated azimuthally invariant electromagnetic logging measurements.', 'BACKGROUND INFORMATION', 'The use of electromagnetic measurements in prior art downhole applications, such as logging while drilling (LWD) and wireline logging applications is well known.', 'Such techniques may be utilized to determine a subterranean formation resistivity, which, along with formation porosity measurements, is often used to indicate the presence of hydrocarbons in the formation.', 'While the use of azimuthally sensitive directional resistivity measurements may provide valuable information upon which steering decisions may be made (e.g., in a pay-zone steering operation), obtaining accurate formation properties can be challenging owing to the azimuthal dependence of the measurements.', 'This problem can be further compounded by transmitter and receiver gains and gain mismatch which vary with downhole pressure and temperature and can influenced by the mechanical shocks and vibration inherent in the drilling environment.', 'There are currently no known methods for providing fully gain compensated, azimuthally invariant, tri-axial propagation measurements.', 'SUMMARY\n \nA method for making downhole electromagnetic logging measurements of a subterranean formation is disclosed.', 'An electromagnetic logging tool is rotated in a subterranean wellbore.', 'The tool includes a transmitter axially spaced apart from a receiver.', 'The transmitter may include an axial transmitting antenna and at least one transverse transmitting antenna and the receiver may include an axial receiving antenna and at least one transverse receiving antenna.', 'The transmitting antennas transmit corresponding electromagnetic waves into the subterranean wellbore.', 'The receiving antennas receive corresponding voltage measurements which are processed to compute harmonic voltage coefficients.', 'Ratios of the selected harmonic voltage coefficients are processed to compute gain compensated, azimuthally invariant measurement quantities.', 'In an alternative embodiment an eccentered (off centered) electromagnetic logging tool is rotated in the subterranean wellbore.', 'The transmitting and receiving antennas are used to transmit electromagnetic wave and receive corresponding voltages as described in the preceding paragraph.', 'Combinations of the received voltage measurements are processed to compute combined measurement quantities, ratios of which are in turn further processed to compute the gain compensated, azimuthally invariant measurement quantities.', 'The disclosed embodiments may provide various technical advantages.', 'For example, the disclosed methodology may be used to provide gain compensated azimuthally invariant measurement quantities.', 'The properties of such compensated measurements generally depend only on other formation properties, such as horizontal and vertical conductivities (resistivities) and the relative dip angle.', 'For the purpose of inverting for the formation properties, using azimuthal invariant measurements may greatly enhance the robustness of the inversion process.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFor a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:\n \nFIG.', '1\n depicts one example of a drilling rig on which the disclosed electromagnetic logging methods may be utilized.', 'FIG.', '2A\n depicts one example of the electromagnetic logging tool shown on \nFIG.', '1\n.', 'FIG.', '2B\n schematically depicts the antenna moments in an electromagnetic logging tool including triaxial transmitters and receivers.\n \nFIG.', '2C\n schematically depicts the antenna moments in an alternative electromagnetic logging tool including triaxial transmitters and receivers.\n \nFIG.', '3\n depicts a flow chart of one disclosed method embodiment for computing gain compensated, azimuthally invariant measurement quantities.\n \nFIG.', '4\n depicts a flow chart of another disclosed method embodiment for computing gain compensated, azimuthally invariant measurement quantities.\n \nFIG.', '5\n depicts a flow chart of a method embodiment for obtaining a warning flag indicative of the validity of the computed quantity.', 'FIGS.', '6A and 6B\n (collectively \nFIG.', '6\n) depict a schematic illustration of an eccentered tool in a wellbore that penetrates an anisotropic formation at a relative dip angle.\n \nFIGS.', '7 and 8\n depict plots of compensated real (\nFIG.', '7\n) and imaginary (\nFIG.', '8\n) modeled measurements versus formation dip azimuth (AZF) for each of the 3×3 tensor components acquired from a centered tool.', 'FIGS.', '9A and 9B\n depict plots of TBT(real(xxpyy\nij\n)) and TBT(imag(xxpyy\nij\n))', 'versus AZF acquired from a centered tool.\n \nFIGS.', '10A and 10B\n depict plots of TBT(real(xxmyy\nij\n)) and TBT(imag(xxmyy\nij\n))', 'versus AZF acquired from a centered tool.\n \nFIG.', '11A\n depicts a plot of TBT(real(XZ\nij\n+ZX\nij\n)) and TBT(imag(XZ\nij\n+ZX\nij\n)) versus AZF at various tool eccentering azimuth values.\n \nFIG.', '11B\n depicts a plot of TBT(real(XZ\nij\n+ZX\nij\n)) and TBT(imag(XZ\nij\n+ZX\nij\n)) versus AZT at various formation dip azimuth values.\n \nFIGS.', '12A and 12B\n depict plots of TBT(real(XX\nij\n+YY\nij\n))', 'and TBT(imag(XX\nij\n+YY\nij\n))', 'versus AZF (\nFIG.', '12A\n) and AZT (\nFIG.', '12B\n).', 'FIGS.', '13A and 13B\n depict plots of TBT(real(XX\nij\n))', '+TBT(real(YY\nij\n)) and TBT(imag(XX\nij\n))', '+TBT(imag(YY\nij\n)) versus AZF (\nFIG.', '13A\n) and AZT (\nFIG.', '13B\n).', 'FIGS.', '14A and 14B\n depict plots of TBT(real(XY\nij \nYX\nij\n)) and TBT(imag(XY\nij \nYX\nij\n))', 'versus AZF (\nFIG.', '14A\n) and AZT (\nFIG.', '14B\n).', 'FIGS.', '15A and 15B\n depict plots of TBT(real(Z\nzz\n)) and TBT(imagl(Z\nzz\n))', 'versus AZF (\nFIG.', '15A\n) and AZT (\nFIG.', '15B\n).', 'DETAILED DESCRIPTION\n \nFIG.', '1\n depicts an example drilling rig \n10\n suitable for employing various method embodiments disclosed herein.', 'A semisubmersible drilling platform \n12\n is positioned over an oil or gas formation (not shown) disposed below the sea floor \n16\n.', 'A subsea conduit \n18\n extends from deck \n20\n of platform \n12\n to a wellhead installation \n22\n.', 'The platform may include a derrick and a hoisting apparatus for raising and lowering a drill string \n30\n, which, as shown, extends into borehole \n40\n and includes a drill bit \n32\n deployed at the lower end of a bottom hole assembly (BHA) that further includes an electromagnetic measurement tool \n50\n configured to make directional electromagnetic logging measurements.', 'As described in more detail below the electromagnetic measurement tool \n50\n may include multi-axial antennas deployed on a logging while drilling tool body.', 'It will be understood that the deployment illustrated on \nFIG.', '1\n is merely an example.', 'Drill string \n30\n may include substantially any suitable downhole tool components, for example, including a steering tool such as a rotary steerable tool, a downhole telemetry system, and one or more MWD or LWD tools including various sensors for sensing downhole characteristics of the borehole and the surrounding formation.', 'The disclosed embodiments are by no means limited to any particular drill string configuration.', 'It will be further understood that the disclosed embodiments are not limited to use with a semisubmersible platform \n12\n as illustrated on \nFIG.', '1\n.', 'The disclosed embodiments are equally well suited for use with either onshore or offshore subterranean operations.', 'FIG.', '2A\n depicts one example of an electromagnetic measurement tool \n50\n.', 'In the depicted embodiment measurement tool \n50\n includes first and second axially spaced transmitters \n52\n and \n54\n and first and second axially spaced receivers \n56\n and \n58\n deployed on a logging while drilling tool body \n51\n, with the receivers \n56\n and \n58\n being deployed axially between the transmitters \n52\n and \n54\n.', 'As described in more detail below, each of the transmitters \n52\n and \n54\n and receivers \n56\n and \n58\n includes at least one transverse antenna and may further include an axial antenna.', 'For example, the transmitters and receivers may include a bi-axial antenna arrangement including an axial antenna and a transverse (cross-axial) antenna.', 'In another embodiment, the transmitters and receivers may include a tri-axial antenna arrangement including an axial antenna and first and second transverse antennas that are orthogonal to one another.', 'As is known to those of ordinary skill in the art, an axial antenna is one whose moment is substantially parallel with the longitudinal axis of the tool.', 'Axial antennas are commonly wound about the circumference of the logging tool such that the plane of the antenna is substantially orthogonal to the tool axis.', 'A transverse antenna is one whose moment is substantially perpendicular to the longitudinal axis of the tool.', 'A transverse antenna may include, for example, a saddle coil (e.g., as disclosed in U.S. Patent Publications 2011/0074427 and 2011/0238312 each of which is incorporated by reference herein).', 'FIG.', '2B\n depicts the moments (magnetic dipoles) of one embodiment of measurement tool \n50\n in which the transmitters \n52\n, \n54\n and receivers \n56\n, \n58\n each include a tri-axial antenna arrangement.', 'Each of the transmitters \n52\n, \n54\n includes an axial transmitting antenna T\n1\nz \nand T\n2\nz \nand first and second transverse transmitting antennas T\n1\nx\n, T\n1\ny \nand T\n2\nx\n, T\n2\ny\n.', 'Likewise, each of the receivers \n56\n, \n58\n includes an axial receiving antenna R\n1\nz \nand R\n2\nz \nand first and second transverse receiving antennas R\n1\nx\n, R\n1\ny \nand R\n2\nx\n, R\n2\ny\n.', 'It will be understood that the disclosed embodiments are not limited to a tri-axial antenna configuration such as that depicted on \nFIG.', '2B\n.', 'FIG.', '2C\n depicts an alternative electromagnetic measurement tool embodiment \n50\n′ in which the first and second transmitters are deployed on corresponding first and second subs \n61\n and \n62\n that are free to rotate with respect to one another (e.g., in an embodiment in which a drilling motor \n65\n is deployed therebetween).', 'As in tool embodiment \n50\n, each of the transmitters T\n1\n and T\n2\n and receivers R\n1\n and R\n1\n may include a tri-axial antenna arrangement.', 'In the example embodiment depicted the moment of R\n1\nz \nis aligned with the moment of T\n1\nz \n(and the z-axis) while the moments of R\n1\nx \nand R\n1\ny \nare rotationally offset from the moments of T\n1\nx \nand T\n1\ny \nby an offset angle α (e.g., 45 degrees in the depicted embodiment).', 'The moment of R\n2\nz \nis aligned with the moment of T\n2\nz \nwhile the moments of R\n2\nx \nand R\n2\ny \nare rotationally offset from the moments of T\n2\nx \nand T\n2\ny \nby α (e.g., 45 degrees).', 'The disclosed embodiments are, of course, not limited in these regards.', 'As stated above, the first and second subs \n61\n and \n62\n may rotate with respect to one another such that the moments of the x- and y-axis transmitting and receiving antennas are misaligned and rotate with respect to one another (i.e., the misalignment angle between the subs varies with time).', 'Using the notation shown on \nFIG.', '2C\n, at any instant in time, the orientation angle of the x-axis on sub \n61\n (the T\n1\nx \ndirection) is θ\n1 \nwith respect to an arbitrary ‘global’ (or wellbore) x-direction.', 'Likewise, at the same instant in time, the orientation angle of the x-axis on sub \n62\n (the T\n2\nx \ndirection) is θ\n2 \nwith respect to the global x-direction.', 'It will thus be understood that the moments of the x- and y-transmitting and receiving antennas T\n1\n and T\n2\n and R\n1\n and R\n2\n are misaligned by a misalignment angle γ=θ\n1 \nθ\n2\n.', 'It will be understood that θ\n1 \nand θ\n2 \nmay be referred to as toolface angles of the first and second subs in that they define the rotational orientation of the subs with respect to a global reference direction.', 'Since θ\n1 \nand θ\n2 \nare variable with time (owing to the rotation of the subs) and since the subs rotate at different rates the misalignment angle γ also varies with time.\n \nFIG.', '3\n depicts a flow chart of one disclosed method embodiment \n100\n for computing gain compensated azimuthally invariant measurement quantities.', 'An electromagnetic measurement tool (e.g., one of the measurement tools depicted on \nFIGS.', '2B and 2C\n) is deployed in and rotated in a subterranean wellbore at \n102\n (e.g., while drilling the wellbore).', 'Electromagnetic measurements are acquired at \n104\n (e.g., via firing the transmitters and receiving the corresponding electromagnetic waves at the receiving antennas) while the tool is rotating and processed to obtain harmonic voltage coefficients.', 'Ratios of selected harmonic voltage coefficients may then be processed to obtain the gain compensated, azimuthally invariant measurement quantities at \n106\n.', 'The harmonic voltage coefficients are selected such that (i) the transmitter and receiver gains are canceled in the computed ratio (i.e., such that the coefficients in the numerator have the same gains as the coefficients in the denominator) and such that (ii) the measurement quantity is azimuthally invariant (i.e., such that the azimuthal response of the quantities in the denominator is the same, and thus cancels, the azimuthal response of the quantities in the numerator).', 'For example, if the numerator includes a first harmonic cosine function then the denominator may be selected such that it also includes a first harmonic cosine function.', 'With continued reference to \nFIG.', '3\n, and as is known to those of ordinary skill in the art, a time varying electric current (an alternating current) in a transmitting antenna produces a corresponding time varying magnetic field in the local environment (e.g., the tool collar and the formation).', 'The magnetic field in turn induces electrical currents (eddy currents) in the conductive formation.', 'These eddy currents further produce secondary magnetic fields which may produce a voltage response in a receiving antenna.', 'The measured voltage in the receiving antennae may be processed, as is known to those of ordinary skill in the art, to obtain one or more properties of the formation.', 'In general, earth formations are anisotropic such that their electrical properties may be expressed as a 3×3 tensor that contains information on formation resistivity anisotropy, dip, bed boundaries and other aspects of formation geometry.', 'It will be understood by those of ordinary skill in the art that the mutual couplings between the tri-axial transmitter antennas and the tri-axial receiver antennas depicted on \nFIGS.', '2B and/or 2C\n form a 3×3 matrix and thus may have sensitivity to a full 3×3 formation impedance tensor.', 'For example, a 3×3 matrix of measured voltages V\nij \nmay be expressed as follows:\n \n \n \n \n \n \n \n \n \nV\n \nij\n \n \n=\n \n \n \n[\n \n \n \n \n \nV\n \nijxx\n \n \n \n \n \nV\n \nijxy\n \n \n \n \n \nV\n \nijxz\n \n \n \n \n \n \n \nV\n \nijyx\n \n \n \n \n \nV\n \nijyy\n \n \n \n \n \nV\n \nijyz\n \n \n \n \n \n \n \nV\n \nijzx\n \n \n \n \n \nV\n \nijzy\n \n \n \n \n \nV\n \nijzz\n \n \n \n \n \n]\n \n \n=\n \n \n \n \nI\n \ni\n \n \n\u2062\n \n \nZ\n \nij\n \n \n \n=\n \n \n \n[\n \n \n \n \n \nI\n \nix\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0', 'I\n \niy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \nI\n \niz\n \n \n \n \n \n]\n \n \n\u2061\n \n \n[\n \n \n \n \n \nZ\n \nijxx\n \n \n \n \n \nZ\n \nijxy\n \n \n \n \n \nZ\n \nijxz\n \n \n \n \n \n \n \nZ\n \nijyx\n \n \n \n \n \nZ\n \nijyy\n \n \n \n \n \nZ\n \nijyz\n \n \n \n \n \n \n \nZ\n \nijzx\n \n \n \n \n \nZ\n \nijzy\n \n \n \n \n \nZ\n \nijzz\n \n \n \n \n \n]\n \n \n \n \n \n \n \n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n \nwhere V\nij \nrepresent the 3×3 matrix of measured voltages with i indicating the corresponding transmitter triad (e.g., T\n1\n or T\n2\n) and j indicating the corresponding receiver triad (e.g., R\n1\n or R\n2\n), I\ni \nrepresent the transmitter currents, and Z\nij \nrepresent the transfer impedances which depend on the electrical and magnetic properties of the environment surrounding the antenna pair in addition to the frequency, geometry, and spacing of the antennas.', 'The third and fourth subscripts indicate the axial orientation of the transmitter and receiver antennas.', 'For example, V\n12xy \nrepresents a voltage measurement on the y-axis antenna of receiver R\n2\n from a firing of the x-axis antenna of transmitter T\n1\n.', 'When bending of the measurement tool is negligible (e.g., less than about 10 degrees), the measured voltages may be modeled mathematically, for example, as follows: \n \nV\nij\n=G\nTi\nm\nTi\nt\n(\nR\nθt\nt\nZ\nij\nR\nθr\n)\nm\nRj\nG\nRj \n\u2003\u2003(2) \n \nwhere Z\nij \nare matrices representing the triaxial tensor couplings (impedances) between the locations of transmitter i and receiver j, G\nTi \nand G\nRj \nare diagonal matrices representing the transmitter and receiver gains, R\nθt \nand R\nθr \nrepresent the rotation matrices for rotating the transmitter and receiver about the z-axis through angles θ\nt \nand θ\nr\n, m\nTi \nand m', 'Rj \nrepresent the matrices of the direction cosines for the transmitter and receiver moments at θ=0, and the superscript t represents the transpose of the corresponding matrix.', 'The matrices in Equation 2 may be given, for example, as follows:\n \n \n \n \n \n \n \n \n \nZ\n \nij\n \n \n=\n \n \n[\n \n \n \n \n \nZ\n \nijxx\n \n \n \n \n \nZ\n \nijxy\n \n \n \n \n \nZ\n \nijxz\n \n \n \n \n \n \n \nZ\n \nijyx\n \n \n \n \n \nZ\n \nijyy\n \n \n \n \n \nZ\n \nijyz\n \n \n \n \n \n \n \nZ\n \nijzx\n \n \n \n \n \nZ\n \nijzy\n \n \n \n \n \nZ\n \nijzz\n \n \n \n \n \n]\n \n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n \nG\n \nTi\n \n \n=\n \n \n[\n \n \n \n \n \ng\n \nTix\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nTiy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nTiz\n \n \n \n \n \n]\n \n \n \n \n \n \n(\n \n4\n \n)\n \n \n \n \n \n \n \n \nG\n \nRj\n \n \n=\n \n \n[\n \n \n \n \n \ng\n \nRix\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ng\n \nRiy\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \ng\n \nRiz\n \n \n \n \n \n]\n \n \n \n \n \n \n(\n \n5\n \n)\n \n \n \n \n \n \n \n \nR\n \n \nθ\n \n\u2062\n \n \n \n \n\u2062\n \nt\n \n \n \n=\n \n \n[\n \n \n \n \n \ncos\n \n\u2061\n \n \n(\n \n \nθ\n \nt\n \n \n)\n \n \n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \nt\n \n \n)\n \n \n \n \n \n0\n \n \n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \nt\n \n \n)\n \n \n \n \n \n \ncos\n \n\u2061\n \n \n(\n \n \nθ\n \nt\n \n \n)\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n \n \n(\n \n6\n \n)\n \n \n \n \n \n \n \n \nR\n \n \nθ\n \n\u2062\n \n \n \n \n\u2062\n \nr\n \n \n \n=\n \n \n[\n \n \n \n \n \ncos\n \n\u2061\n \n \n(\n \n \nθ\n \nr\n \n \n)\n \n \n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \nr\n \n \n)\n \n \n \n \n \n0\n \n \n \n \n \n \nsin\n \n\u2061\n \n \n(\n \n \nθ\n \nr\n \n \n)', 'cos\n \n\u2061\n \n \n(\n \n \nθ\n \nr\n \n \n)\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n \n \n(\n \n7\n \n)\n \n \n \n \n \n \n \n \nUsing the T\n1\nx \nantenna direction as a reference direction for the first sub and the T\n2\nx \nantenna direction as a reference direction for the second sub, the matrices of the direction cosines of the transmitter and receiver moments may be given, for example, as follows: \n m\nT1\n=I \n m\nR1\n=R\nα\n \n m\nR2\n=R\nα\n \n m\nT2\n=I \n \nwhere I represents the identity matrix and R\nα\n represents the rotation matrix about the z-axis through the angle α.', 'It will be understood that Equations 2-8 are written for a general embodiment (such as shown on \nFIG.', '2C\n) in which the subs \n61\n and \n62\n are free to rotate with respect to one another.', 'In an embodiment in which the transmitters and receivers are deployed on a common tool body (such that there is no misalignment as in \nFIG.', '2B\n)', 'it will be understood that θ\nt\n=θ\nr \nsuch that V\nij\n=G\nTi\n(R\nθ\nt\nZ\nij\nR\nθ\n)G\nRj\n.', 'It will be understood that the disclosed embodiments are not limited in regard to the relative rotation of the transmitters and receivers.', 'Gain compensated quantities may be computed with or without relative rotation between the transmitters and receivers.', 'For example, commonly assigned U.S. patent application Ser.', 'No. 14/549,396 (which is fully incorporated by reference herein) discloses methods for obtaining gain compensated measurements with differential rotation of the first transmitter and receiver with respect to the second transmitter and receiver (e.g., in an embodiment similar to that depicted on \nFIG.', '2C\n).', 'Commonly assigned U.S. patent application Ser.', 'No. 14/325,797 (which is also fully incorporated by reference herein) discloses methods for obtaining compensated measurements in which the transmitters and receivers are rotationally fixed relative to one another (e.g., in an embodiment similar to that depicted on \nFIG.', '2B\n).', 'In embodiments in which the transmitters and receivers are rotationally fixed, the rotated couplings may be expressed mathematically in harmonic form, for example, as follows: \n \nR\nθ\nt\nZ\nij\nR\nθ\n=Z\nDC_ij\n+Z\nFHC_ij \ncos(θ)+\nZ\nFHS_ij \nsin(θ)+\nZ\nSHC_ij \ncos(2θ)+\nZ\nSHS_ij \nsin(2θ) \u2003\u2003(9) \n \nwhere Z\nDC_ij \nrepresents a DC (average) coupling coefficient, Z\nFHC_ij \nand Z\nFHS_ij \nrepresent first order harmonic cosine and first order harmonic sine coefficients, and Z\nSHC_ij \nand Z\nSHS_ij \nrepresent second order harmonic cosine and second order harmonic sine coefficients of the ij transmitter receiver couplings.', 'These coefficients are shown below:\n \n \n \n \n \n \n \n \n \n \nZ\n \n \n \nDC\n \n—\n \n \n\u2062\n \nij\n \n \n \n=\n \n \n \n \n \n \n \nZ\n \nijxx\n \n \n+\n \n \nZ\n \nijyy\n \n \n \n2\n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n0\n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \nZ\n \nijxx\n \n \n+\n \n \nZ\n \nijyy\n \n \n \n2\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nijzz\n \n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \n \n \nFHC\n \n—\n \n \n\u2062\n \nij\n \n \n \n=\n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nijxz\n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nijyz\n \n \n \n \n \n \n \nZ\n \nijzx\n \n \n \n \n \nZ\n \nijzy\n \n \n \n \n0\n \n \n \n \n]', '\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \n \n \nFHS\n \n—\n \n \n\u2062\n \nij\n \n \n \n=\n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nijyz\n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \nZ\n \nijxz\n \n \n \n \n \n \n \nZ\n \nijzy\n \n \n \n \n \nZ\n \nijzx\n \n \n \n \n0\n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \n \n \nSHC\n \n—\n \n \n\u2062\n \nij\n \n \n \n=\n \n \n \n \n \n \n \nZ\n \nijxx\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nZ\n \nijyy\n \n \n \n2\n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n+\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n0\n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n+\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxx\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nZ\n \nijyy\n \n \n \n)\n \n \n2\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nZ\n \n \n \nSHS\n \n—\n \n \n\u2062\n \nij\n \n \n \n=\n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n+\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxx\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nZ\n \nijyy\n \n \n \n)\n \n \n2\n \n \n \n \n0\n \n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxx\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nZ\n \nijyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n+\n \n \nZ\n \nijyx\n \n \n \n)', '2\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n \n \n \n \n(\n \n10\n \n)', 'In general, the receiving antenna voltages are measured while the tool rotates in the borehole.', 'Following the form of Equation 9, the measured voltages may be expressed mathematically in terms of their harmonic voltage coefficients, for example, as follows thereby enabling the harmonic voltage coefficients to be obtained: \n \nV\nij\n=V\nDC_ij\n+V\nFHC_ij \ncos(θ)+\nV\nFHS_ij \nsin(θ)+\nV\nSHC_ij \ncos(2θ)+\nV\nSHS_ij \nsin(2θ) \u2003\u2003 (11) \n \nwherein where V\nDC_ij \nrepresents a DC voltage coefficient, V\nFHC_ij \nand V\nFHS_ij \nrepresent first order harmonic cosine and first order harmonic sine voltage coefficients (also referred to herein as first harmonic cosine and first harmonic sine voltage coefficients), and V\nSHC_ij \nand V\nSHS_ij \nrepresent second order harmonic cosine and second order harmonic sine voltage coefficients (also referred to herein as second harmonic cosine and second harmonic sine voltage coefficients) of the ij transmitter receiver couplings.', 'It will be understood that collocated tri-axial transmitter and receiver embodiments (e.g., as depicted on \nFIGS.', '2B and 2C\n) are not required to gain compensate certain of the 3×3 matrix components.', 'For example, the axial cross terms (i.e., the xz, zx, yz, and zy terms) may be gain compensated using any tool embodiment that includes an axial transmitter antenna, a transverse (cross-axial) transmitter antenna, an axial receiver antenna, and a transverse receiver antenna deployed on the tool body.', 'These transmitter and receiver antennas may be distributed along the tool body with substantially any suitable spacing and order.', 'Moreover, the transmitter antennas and/or the receiver antennas may be collocated (or not).', 'The disclosed embodiments are not limited to any particular transmitter and receiver antenna configuration so long as the tool includes at least one axial transmitter antenna, at least one transverse transmitter antenna, at least one axial receiver antenna, and at least one transverse receiver antenna.', 'Taking ratios between the DC xx and yy voltage measurements or the second harmonic xx', 'and yy voltage measurements given in Equation 10 allows a gain ratio gT\ni \nof the x to y transmitter and gain ratio gR\nj \nof the x to y receiver to be obtained, for example, as follows:\n \n \n \n \n \n \n \n \n \n \ngR\n \nj\n \n \n=\n \n \n \n \n \n \nV\n \n \nDC\n \nijxx\n \n \n \n \nV\n \n \nDC\n \nijyy\n \n \n \n \n\u2062\n \n \n \nV\n \n \nDC\n \nijyx\n \n \n \n \nV\n \n \nDC\n \nijxy\n \n \n \n \n \n \n=\n \n \n \n \n \n \nV\n \n \nSHC\n \nijxx\n \n \n \n \nV\n \n \nSHC\n \nijyy\n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHC\n \nijyx\n \n \n \n \nV\n \n \nSHC\n \nijxy\n \n \n \n \n \n \n=\n \n \n \n \n \n \nV\n \n \nSHS\n \nijxx\n \n \n \n \nV\n \n \nSHS\n \nijyy\n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHS\n \nijyx\n \n \n \n \nV\n \n \nSHS\n \nijxy\n \n \n \n \n \n \n=\n \n \n \ng\n \nRjx\n \n \n \ng\n \nRjy\n \n \n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \ngT\n \ni\n \n \n=\n \n \n \n \n \n \nV\n \n \nDC\n \nijxx\n \n \n \n \nV\n \n \nDC\n \nijyy\n \n \n \n \n\u2062\n \n \n \nV\n \n \nDC\n \nijxy\n \n \n \n \nV\n \n \nDC\n \nijyx\n \n \n \n \n \n \n=\n \n \n \n \n \n \nV\n \n \nSHC\n \nijxx\n \n \n \n \nV\n \n \nSHC\n \nijyy\n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHC\n \nijxy\n \n \n \n \nV\n \n \nSHC\n \nijyx\n \n \n \n \n \n \n=\n \n \n \n \n \n \nV\n \n \nSHS\n \nijxx\n \n \n \n \nV\n \n \nSHS\n \nijyy\n \n \n \n \n\u2062\n \n \n \nV\n \n \nSHS\n \nijxy\n \n \n \n \nV\n \n \nSHS\n \nijyx\n \n \n \n \n \n \n=\n \n \n \ng\n \nTix\n \n \n \ng\n \nTiy\n \n \n \n \n \n \n \n \n \n \n \n(\n \n12\n \n)', 'Since the gain ratio formulas in Equation 12 involve taking a square root, there may be a 180 degree phase ambiguity (i.e., a sign ambiguity).', 'As such, the gain ratios may not be arbitrary, but should be controlled such that they are less than 180 degrees.', 'For un-tuned receiving antennas, the electronic and antenna gain/phase mismatch (assuming the antenna wires are not flipped from one receiver to another) may generally be controlled to within about 30 degrees (particularly at the lower frequencies used for deep measurements).', 'This is well within 180 degrees (even at elevated temperatures where the mismatch may be at its greatest).', 'For tuned transmitting antennas, however, the phase may change signs (i.e., jump by 180 degrees) if the drift in the antenna tuning moves across the tuning resonance.', 'Such transmitter phase ratio ambiguity (sign ambiguity) may be resolved, for example, using Equation 12 and the knowledge that the receiver gain/phase ratio is not arbitrary, but limited to about 30 degrees (i.e. to enable the determination of whether the transmitter phase difference is closer to 0 or 180 degrees).', 'The x and y gain ratios defined in Equation 12 enable the following gain ratio matrices to be defined:\n \n \n \n \n \n \n \n \n \n \nG\n \n \n \nRj\n \n—\n \n \n\u2062\n \nratio\n \n \n \n=\n \n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ngR\n \nj\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n=\n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ng\n \nRjx\n \n \n \ng\n \nRjy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nG\n \n \n \nTi\n \n—\n \n \n\u2062\n \nratio\n \n \n \n=\n \n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \ngT\n \ni\n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n=\n \n \n[\n \n \n \n \n1\n \n \n \n0\n \n \n \n0\n \n \n \n \n \n0\n \n \n \n \n \ng\n \nTix\n \n \n \ng\n \nTiy\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n1\n \n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \n13\n \n)\n \n \n \n \n \n \n \n \nwhere G\nRj_ratio \nrepresents the gain ratio matrix for receiver Rj and G\nTi_ratio \nrepresents the gain ratio matrix for transmitter Ti.\n \nApplying these gain ratios to the measured voltages (shown in Equation 11) enables the y transmitter and y receiver gains to be replaced by x transmitter and x receiver gains.', 'The voltage measurements may then be rotated mathematically to simulate rotation of the x and y antennas in the R\n1\n and R\n2\n receivers and the T\n2\n transmitter such that they are rotationally aligned with the x and y antennas in the T\n1\n transmitter.', 'Such rotation removes the effect of the offset angle α and misalignment angle γ on the measurements and results in the following back-rotated Fourier coefficients:\n \n \n \n \n \n \n \n \n \nVR\n \nDCij\n \n \n=\n \n \n \n \nR\n \n \nβ\n \nTi\n \n \nt\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nG\n \n \n \nTi\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nDCij\n \n \n\u2062\n \n \nG\n \n \n \nRj\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nβ\n \nRj\n \n \n \n \n=\n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n \nZ\n \nijxx\n \n \n+\n \n \nZ\n \nijyy\n \n \n \n2\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n-\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n-\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n \nZ\n \nijxx\n \n \n+\n \n \nZ\n \nijyy\n \n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTiz\n \n \n\u2062\n \n \ng\n \nRjz\n \n \n\u2062\n \n \nZ\n \nijzz\n \n \n \n \n \n \n \n \n \n \n \n(\n \n14\n \n)\n \n \n \n \n \n \n \n \nVR\n \nFHCij\n \n \n=\n \n \n \n \nR\n \n \nβ\n \nTi\n \n \nt\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nG\n \n \n \nTi\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nFHCij\n \n \n\u2062\n \n \nG\n \n \n \nRj\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nβ\n \nRj\n \n \n \n \n=\n \n \n\u2003\n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \nZ\n \nijxz\n \n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjz\n \n \n\u2062\n \n \nZ\n \nijyz\n \n \n \n \n \n \n \n \n \ng\n \nTiz\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \nZ\n \nijzx\n \n \n \n \n \n \n \ng\n \nTiz\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \nZ\n \nijzy\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \n15\n \n)\n \n \n \n \n \n \n \n \nVR\n \nFHSij\n \n \n=\n \n \n \n \nR\n \n \nβ\n \nTi\n \n \nt\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nG\n \n \n \nti\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nFHSij\n \n \n\u2062\n \n \nG\n \n \n \nRj\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nβ\n \nRj\n \n \n \n \n=\n \n \n\u2003\n \n \n[\n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \nZ\n \nijyz\n \n \n \n \n \n \n \n0\n \n \n \n0\n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjz\n \n \n\u2062\n \n \nZ\n \nijxz\n \n \n \n \n \n \n \n \n \ng\n \nTiz\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \nZ\n \nijzy\n \n \n \n \n \n \n \ng\n \nTiz\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \nZ\n \nijzx\n \n \n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \n16\n \n)\n \n \n \n \n \n \n \n \nVR\n \nSHCij\n \n \n=\n \n \n \n \nR\n \n \nβ\n \nTi\n \n \nt\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nG\n \n \n \nTi\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nSHCij\n \n \n\u2062\n \n \nG\n \n \n \nRj\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nβ\n \nRj\n \n \n \n \n=\n \n \n\u2003\n \n \n[\n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n \nZ\n \nijxx\n \n \n-\n \n \nZ\n \nijyy\n \n \n \n2\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n+\n \n \nz\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nijxy\n \n \n+\n \n \nZ\n \nijyx\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n \nZ\n \nijxx\n \n \n-\n \n \nZ\n \nijyy\n \n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \n17\n \n)\n \n \n \n \n \n \n \n \nVR\n \nSHSij\n \n \n=\n \n \n \n \nR\n \n \nβ\n \nTi\n \n \nt\n \n \n\u2062\n \n \n \n \n\u2062\n \n \nG\n \n \n \nTi\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nV\n \nSHSij\n \n \n\u2062\n \n \nG\n \n \n \nRj\n \n—\n \n \n\u2062\n \nratio\n \n \n \n\u2062\n \n \nR\n \n \nβ\n \nRj\n \n \n \n \n=\n \n \n\u2003\n \n \n[\n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n \nZ\n \nijxy\n \n \n+\n \n \nZ\n \nijyx\n \n \n \n2\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nijxx\n \n \n-\n \n \nz\n \nijyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n(\n \n \n \nZ\n \nijxx\n \n \n-\n \n \nZ\n \nijyy\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \ng\n \nTix\n \n \n\u2062\n \n \ng\n \nRjx\n \n \n\u2062\n \n \n \n \nZ\n \nijxy\n \n \n+\n \n \nZ\n \nijyx\n \n \n \n2\n \n \n \n \n \n0\n \n \n \n \n \n0\n \n \n \n0\n \n \n \n0\n \n \n \n \n]\n \n \n \n \n \n \n \n \n(\n \n18\n \n)\n \n \n \n \n \n \n \n \nwhere VR represent the rotated coefficients, β\nT1\n=0, β\nR1\n=α, β\nT2\n=γ, and β\nR2\n=(α+γ).', 'The following terms may be obtained from the back rotated coefficients given in Equations 14-18: \n \nxxpyy\nij\n=VR\nDCijxx\n+VR\nDCijyy\n=g\nTix\ng\nRjx\n(\nZ\nijxx\n+\nZ\nijyy\n) \u2003\u2003(19) \n \nxxmyy\nij\n=0.5×(\nVR\nSHCijxx \nVR\nSHCijxy \nVR\nSHSijyx \nVR\nSHSijxy\n)=\ng\nTix\ng\nRjx\n(\nZ\nijxx \nZ\nijyy\n) \u2003\u2003(20) \n \nxymyx\nij\n=VR\nDCijxy \nVR\nDCijxy\n=g\nTix\ng\nRjx\n(\nZ\nijxy \nZ\nijyx\n) \u2003\u2003(21) \n \nxypyx\nij\n=0.5×(\nVR\nSHC\nijxy\n+VR\nSHC\nijyx\n+VR\nSHSijxx \nVR\nSHSijyy\n)=\ng\nTix\ng\nRjx\n(\nZ\nijxy\n+\nZ\nijyx\n)', '(22) \n \nwhere the overhead bar in \nZ\nijxx\n, \nZ\nijyy\n, \nZ\nijxy\n, and \nZ\nijyx \nindicates that the value is obtained from the Fourier coefficients which is an average.', 'The common gain factor in these terms is g\nTix\ng\nRjx\n.', 'The following additional terms representative of the nine tensor components in 3×3 matrix may be obtained, for example, as follows: \n \nVR\nZ\nijxx\n=0.5×(\nxxpyy\nij\n+xxmyy\nij\n)=\ng\nTix\ng\nRjx\nZ\nijxx \n\u2003\u2003(23) \n \nVR\nZ\nijyy\n=0.5×(\nxxpyy\nij \nxxmyy\nij\n)=\ng\nTix\ng\nRjx\nZ\nijyy \n\u2003\u2003(24) \n \nVR\nZ\nijxy\n=0.5×(\nxypyx\nij\n+xymyx\nij\n)=\ng\nTix\ng\nRjx\nZ\nijxy \n\u2003\u2003(25) \n \nVR\nZ\nijyx\n=0.5×(\nxypyx\nij \nxymyx\nij\n)', '=\ng\nTix\ng\nRjx\nZ\nijyx \n\u2003\u2003(26) \n \nVR\nZ\nijxz\n=0.5×(\nVR\nFHCijxz \nVR\nFHSijyz\n)=\ng\nTix\ng\nRjz\nZ\nijxz \n\u2003\u2003(27) \n \nVR\nZ\nijzx\n=0.5×(\nVR\nFHCijzx \nVR\nFHSijzy\n)=\ng\nTix\ng\nRjx\nZ\nijzx \n\u2003\u2003(28) \n \nVR\nZ\nijyz\n=0.5×(\nVR\nFHCijyz\n+VR\nFHSijxz\n)=\ng\nTix\ng\nRjz\nZ\nijyz \n\u2003\u2003(29) \n \nVR\nZ\nijzy\n=0.5×(\nVR\nFHCijzy\n+VR\nFHSijzx\n)=\ng\nTix\ng\nRjx\nZ\nijzy \n\u2003\u2003(30) \n VR\nZ\nijzz\n=VR\nDCijzz\n=g\nTiz\ng\nRjz\nZ\nijzz\n\u2003\u2003(31)', 'These may be written in 3×3 matrix form, for example, as follows:\n \n \n \n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nij\n \n \n \n=\n \n \n[\n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijxx\n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijxy\n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijxz\n \n \n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijyx\n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijyy\n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijyz\n \n \n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijzx\n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijzy\n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijzz\n \n \n \n \n \n \n]\n \n \n \n \n \n \n(\n \n32\n \n)', 'The quantities in Equations 23-32 contain transmitter and receiver gains.', 'In order to use these measured quantities to accurately invert for formation properties, accurate and stable transmitter and receiver calibrations are required.', 'However, performing accurate and stable calibrations that are valid over all tool operating conditions is extremely difficult and problematic (not to mention expensive).', 'Thus, with reference again to \nFIG.', '3\n, ratios of selected measurements may be computed to cancel out all the transmitter and receiver gains.', 'These ratios may be thought of as having two components; the numerator and the denominator.', 'In the discussion that follows the numerators and denominators are selected such that (i) the transmitter and receiver gains are canceled in the computed ratio (i.e., such that the coefficients in the numerator have the same gains as the coefficients in the denominator) and such that (ii) the measurement quantity is azimuthally invariant (i.e., such that the azimuthal response of the quantities in the denominator is the same, and thus cancels, the azimuthal response of the quantities in the numerator).', 'Gain Compensation\n \nThe following term by term (TBT) compensation operators may be defined for any measurement X\nij \nobtained between transmitter i and receiver j, for example, as follows:\n \n \n \n \n \n \nTBT\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \n \n(\n \n \nX\n \nij\n \n \n)\n \n \n \n=\n \n \n \n \nX\n \n12\n \n \n \nX\n \n11\n \n \n \n×\n \n \n \nX\n \n21\n \n \n \nX\n \n22\n \n \n \n \n \n \n \n \n \n \n \nTBT\n \n\u2061\n \n \n(\n \n \nX\n \nij\n \n \n)\n \n \n \n=\n \n \n \n \n \nX\n \n12\n \n \n \nX\n \n11\n \n \n \n×\n \n \n \nX\n \n21\n \n \n \nX\n \n22', 'These operators are fully gain compensated in that numerator gain terms are canceled by the denominator gain terms.', 'It will be understood that the above operators contain the same information about the formation parameters and that either may be used either in subsequent inversion processes.', 'It will further be understood that there are two possible solutions for the square root in TBT(X\nij\n) and that extra care should be taken to make sure that the same branch of solution is chosen in comparing measured data and model data.', 'Gain compensated measurements may be obtained from a k-direction transmitter and an 1-direction receiver from triaxial stations 1 and 2 (in which k and l take on x, y, and z directions), for example, as follows:\n \n \n \n \n \n \nTBT\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \n \n(\n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijkl\n \n \n \n)\n \n \n \n=\n \n \n \nCZ\n \nkl\n \n2\n \n \n=\n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \n \n12\n \n\u2062\n \nkl\n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \n \n11\n \n\u2062\n \nkl\n \n \n \n \n \n·\n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_', '21\n \n\u2062\n \nkl\n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \n \n22\n \n\u2062\n \nkl\n \n \n \n \n \n \n=\n \n \n \n \n \nZ\n \n_\n \n \n \n12\n \n\u2062\n \nkl\n \n \n \n \n \nZ\n \n_\n \n \n \n11\n \n\u2062\n \nkl\n \n \n \n \n·\n \n \n \n \nZ\n \n_\n \n \n \n21\n \n\u2062\n \nkl\n \n \n \n \n \nZ\n \n_\n \n \n \n22\n \n\u2062\n \nkl\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nTBT\n \n\u2061\n \n \n(\n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijkl\n \n \n \n)\n \n \n \n=\n \n \n \nCZ\n \nkl\n \n \n=\n \n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \n \n12\n \n\u2062\n \nkl\n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \n \n11\n \n\u2062\n \nkl\n \n \n \n \n \n·\n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \n \n21\n \n\u2062\n \nkl\n \n \n \n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \n \n22\n \n\u2062\n \nkl\n \n \n \n \n \n \n \n=\n \n \n \n \n \n \nZ\n \n_\n \n \n \n12\n \n\u2062\n \nkl\n \n \n \n \n \nZ\n \n_\n \n \n \n11\n \n\u2062\n \nkl\n \n \n \n \n·\n \n \n \n \nZ\n \n_\n \n \n \n21\n \n\u2062\n \nkl\n \n \n \n \n \nZ\n \n_\n \n \n \n22\n \n\u2062\n \nkl\n \n \n \n \n \n \n \n \n \n \n \n \nA full 3×3 matrix may then be expressed, for example, as follows:\n \n \n \n \n \n \n \n \n \nTBT\n \n\u2061\n \n \n(\n \n \nVR\n \n\u2062\n \n \n \nZ\n \n_\n \n \nijkl\n \n \n \n)\n \n \n \n=\n \n \n[\n \n \n \n \n \nCZ\n \nxx\n \n \n \n \n \nCZ\n \nxy\n \n \n \n \n \nCZ\n \nxz\n \n \n \n \n \n \n \nCZ\n \nyx\n \n \n \n \n \nCZ\n \nyy\n \n \n \n \n \nCZ\n \nyz\n \n \n \n \n \n \n \nCZ\n \nzx\n \n \n \n \n \nCZ\n \nzy\n \n \n \n \n \nCZ\n \nzz\n \n \n \n \n \n]\n \n \n \n \n \n \n(\n \n33\n \n)\n \n \n \n \n \n \n \n \nIt will be understood that TBT(VR\nZ\nijkl\n) represent fully gain compensated measurements in that the numerator gain terms are canceled by the denominator gain terms.', 'Gain compensated, azimuthally invariant measurements may be obtained by adhering to both criteria defined above.', 'Centered Tool\n \nFor a centered electromagnetic logging tool, the off-diagonal terms of TBT(VR\nZ\nijkl\n), i.e., CZ\nxy\n, CZ\nyx\n, CZ\nxz\n, CZ\nzx\n, CZ\nyz\n, and CZ\nzy\n, are azimuthally invariant.', 'For example, the numerator of CZ\nxz \nincludes \nZ\n12xz \nand \nZ\n21zx\n, each of which is a first harmonic function of θ.', 'The denominator of CZ\nxz \nincludes of \nZ\n11xz \nand \nZ\n22zx \neach of which is also a first harmonic function of θ.', 'The first harmonic function of θ in the denominator therefore cancels the first harmonic function of θ in the numerator such that the resultant CZ\nxz \nis both gain compensated and azimuthally invariant.', 'Similarly CZ\nzx\n, CZ\nyz\n, and CZ\nzy \neach include a first harmonic function of θ in both the numerator and denominator such that they are azimuthally invariant.', 'The off-diagonal terms CZ\nxy \nand CZ\nyx \neach include a second harmonic function of θ in both the numerator and denominator such that they are azimuthally invariant.', 'Of the diagonal terms, CZ\nzz \nonly includes DC components and is therefore also azimuthally invariant.', 'The remaining diagonal terms, CZ\nxx \nand CZ\nyy\n, each include a DC term and a second harmonic function of θ such that they are not azimuthally invariant.', 'The following compensated, azimuthally invariant quantities may be computed (contain the same information as CZ\nxx \nand CZ\nyy \nbut are azimuthally invariant):\n \n \n \n \n \n \n \n \n \nCRXXPYY\n \n=\n \n \n \nTBT\n \n\u2061\n \n \n(\n \n \nreal\n \n\u2061\n \n \n(\n \n \nxxpyy\n \nij\n \n \n)\n \n \n \n)\n \n \n \n=\n \n \n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n12\n \n \n)\n \n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n11\n \n \n)\n \n \n \n \n×\n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n21\n \n \n)\n \n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n22\n \n \n)', '\u2062\n \n \n \n \n \n\u2062\n \n \nCIXXPYY\n \n=\n \n \n \nTBT\n \n\u2061\n \n \n(\n \n \nimag\n \n\u2061\n \n \n(\n \n \nxxpyy\n \nij\n \n \n)\n \n \n \n)\n \n \n \n=\n \n \n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n12\n \n \n)\n \n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n11\n \n \n)\n \n \n \n \n×\n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n21\n \n \n)\n \n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXPYY\n \n22\n \n \n)\n \n \n \n \n \n \n \n \n \n \n \n \n(\n \n34\n \n)\n \n \n \n \n \n \n \n \nCRXXMYY\n \n=\n \n \n \nTBT\n \n\u2061\n \n \n(\n \n \nreal\n \n\u2061\n \n \n(\n \n \nxxmyy\n \nij\n \n \n)\n \n \n \n)\n \n \n \n=\n \n \n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n12\n \n \n)\n \n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n11\n \n \n)\n \n \n \n \n×\n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n21\n \n \n)\n \n \n \n \nreal\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n22\n \n \n)\n \n \n \n \n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \nCRXXMYY\n \n=\n \n \n \nTBT\n \n\u2061\n \n \n(\n \n \nimag\n \n\u2061\n \n \n(\n \n \nxxmyy\n \nij\n \n \n)\n \n \n \n)\n \n \n \n=\n \n \n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n12\n \n \n)\n \n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n11\n \n \n)\n \n \n \n \n×\n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n21\n \n \n)\n \n \n \n \nimag\n \n\u2061\n \n \n(\n \n \nXXMYY\n \n22\n \n \n)\n \n \n \n \n \n \n \n \n \n \n \n \n(\n \n35\n \n)\n \n \n \n \n \n \n \n \nwhere CRXXPYY and CIXXPYY represent real and imaginary quantities that are related to an xx plus yy coupling component and CRXXMYY and CIXXMYY represent real and imaginary quantities that are related to an xx minus yy coupling component.', 'Eccentered Tool\n \nFor an eccentered (off centered) electromagnetic logging tool, the off-diagonal terms of TBT(VR\nZ\nijkl\n), i.e., CZ\nxy\n, CZ\nyx\n, CZ\nxz\n, CZ\nzx\n, CZ\nyz\n, and CZ\nzy\n, are generally no longer azimuthally invariant since the numerators include additional harmonic terms related to the eccentering azimuth φ.', 'Alternative measurements are defined in order to obtain gain compensated azimuthally invariant measurements for an eccentered logging tool.', 'FIG.', '4\n depicts a flow chart of an alternative methodology \n120\n for computing gain compensated azimuthally invariant measurement quantities.', 'An electromagnetic measurement tool (e.g., one of the measurement tools depicted on \nFIGS.', '2B and 2C\n) is deployed in and rotated in a subterranean wellbore at \n122\n (e.g., while drilling the wellbore).', 'The measurement tool is generally (but not necessarily) eccentered (off-centered) in the wellbore while rotating in \n122\n.', 'A plurality of electromagnetic measurements is acquired at \n124\n.', 'These measurements may be acquired, for example, via sequentially firing a plurality of the transmitters and receiving the corresponding electromagnetic waves (voltages) at a corresponding plurality of the receiving antennas while the tool is rotating in \n122\n.', 'Certain ones of the electromagnetic measurements are combined (e.g., added or subtracted) to obtain combined measurement quantities at \n126\n.', 'In certain embodiments, the combined measurement quantities may be azimuthally invariant with respect to one or both of the formation dip azimuth and the eccentering azimuth.', 'Ratios of selected ones of the combined measurement quantities may then be processed to compute the gain compensated, azimuthally invariant measurement quantities at \n128\n.', 'Eccentered Tool—Axial Cross Coupling Components\n \nBased on modeled data from an eccentered tool in a borehole, the Z\nxz \nand Z\nzx \ncross coupling impedances may be expressed in the following functional form: \n \nXZ\nij\n=A\nxzij\nFHF\n(θ)+\nB\nxzij\nFHF\n(φ)+\nC\nxzij\nSHF\n(2θ)+\nD\nxzij\nSHF\n(2φ) \u2003\u2003(36) \n \nZX\nij\n=A\nzxij\nFHF\n(θ)+\nB\nzxij\nFHF\n(φ)+\nC\nzxij\nSHF\n(2θ)+\nD\nzxij\nSHF\n(2φ) \u2003\u2003(37) \n \nwhere A, B, C, and D represent coefficient values, and FHF and SHF represent first and second harmonic functions (e.g., sin and cos functions).', 'The coefficients for the cross coupling impedances Z\nxz \nand Z\nzx \nare related to one another as follows: \n \n \n \nA\nxzij\n=A\nzxij\n; B\nxzij\n=B\nzxij\n; C\nxzij\n=C\nzxij\n; D\nxzij\n=D\nzxij\n; and A\nxzij\n˜B\nxzij\n>>C\nxzij\n˜D\nxzij \n \n \n \n \n \nsuch that Equations 36 and 37 may be combined, for example, as follows: \n \nXZ\nij\n+ZX\nij\n=2(\nA\nxzij\nFHF\n(θ)+\nD\nxzij\nSHF\n(2φ))', '(38) \n \nXZ\nij \nZX\nij\n=2(\nB\nxzij\nFHF\n(φ)+\nC\nxzij\nSHF\n(2θ))', '(39) \n \nThe magnitude of A\nxzij \nand B\nxzij \nare generally similar to one another, but significantly larger than those of C\nxzij \nand D\nxzij\n.', 'For separate (different) transmitter and receiver stations (i, j=1, 2), the ratio of the magnitude of the real and imaginary components of A\nxzij \nto the real and imaginary components of D\nxzij \nvary as do the similar ratios of B\nxzij \nto C\nxzij\nModel data suggests that imag(XZ\nij\n+XZ\nij\n) has the highest ratio such that the following approximations hold: \n Imag(\nXZ\nij\n+ZX\nij\n)=2·imag(\nA\nxzij\nFHF\n(θ)+\nD\nxzij\nSHF\n(2φ))', '2·imag(\nA\nxzij\nFHF\n(θ)) \u2003\u2003(40)', 'The following gain compensated quantity related to the xz and zx cross coupling components is therefore essentially azimuthally invariant (since A\nxzij\n>>D\nxzij\n):', 'CIXZPZX=TBT\n(imag(\nXZ\nij\n+ZX\nij\n))', '(41) \n \nLikewise, the following gain compensated quantity related to a sum of the yz and zy cross coupling components is also essentially azimuthally invariant.', 'CIYZPZY=TBT\n(imag(\nYZ\nij\n+ZY\nij\n))', '(42) \n Eccentered Tool—Transverse Coupling Components \n \nModeled data from an eccentered tool in a borehole show that the Z\nxx \nand Z\nyy \ncoupling impedances may be expressed in the following functional form: \n \nXX\nij\n=A\nxxij', '+B\nxxij\nSHF\n(2θ)+\nC\nxxij\nSHF\n(2φ) \u2003\u2003(43)', 'YY\nij\n=A\nyyij\n+B\nyyij\nSHF\n(2θ)+\nC\nyyij\nSHF\n(2φ) \u2003\u2003(44) \n \nsuch that the compensated quantities CZ\nxx \nand C Z\nyy \nare not azimuthally invariant.', 'Equations 43 and 44 may be combined, for example, as follows: \n \nXX\nij\n+YY\nij\n=(', 'A\nxxij', '+A\nyyij\n)', '+(\nB\nxxij\n+B\nyyij\n)\nSHF\n(2θ)+(\nC\nxxij', '+C\nyyij\n)\nSHF\n(2φ)', '(45) \n \nXX\nij \nYY\nij\n=(\nA\nxxij \nA\nyyij\n)', '+(\nB\nxxij \nB\nyyij\n)\nSHF\n(2θ)+(\nC\nxxij \nC\nyyij\n)\nSHF\n(2φ) \u2003\u2003(46) \n \nwhere the magnitude of both the real and imaginary parts of (A\nxxij', '+A\nyyij\n) is about 3 orders of magnitude greater than (B\nxxij\n+B\nyyij\n) and (C\nxxij\n+C\nyyij\n) such that: \n (\nA\nxxij', '+A\nyyij\n)>>(\nB\nxxij', '+B\nyyij\n) and (\nC\nxxij\n+C\nyyij\n) \n and \n XX\nij\n+YY\nij \n(A\nxxij', '+A\nyyij\n) \u2003\u2003(47)', 'The following gain compensated, azimuthally invariant quantities related to a sum of the xx and yy coupling components may therefore be computed.', 'CRXXPYY=TBT\n(real(\nXX\nij\n+YY\nij\n))', 'CIXXPYY=TBT\n(imag(\nXX\nij\n+YY\nij\n))', '(48) \n \nThe functional form of XX\nij \nYY\nij \nsuggests that TBT(XX\nij \nYY\nij\n) is not azimuthally invariant when the tool is eccentered (since (A\nxxij \nA\nyyij\n)˜(B\nxxij \nB\nyyij\n)˜(C\nxxij \nC\nyyij\n)).', 'Eccentered Tool—Transverse Cross Coupling Components\n \nModeled data from an eccentered tool in a borehole show that the Z\nxy \nand Z\nyx \ncross coupling impedances may be expressed in the following functional form: \n \nXY\nij\n=A\nxyij', 'FHF\n(θ)+\nB\nxyij\nSHF\n(2θ)+\nC\nxyij\nFHF\n(φ)+\nD\nxyij\nSHF\n(2φ) \u2003\u2003(49) \n \nYX\nij\n=A\nyxij\nFHF\n(θ)+\nB\nyxij\nSHF\n(2θ)+\nC\nyxij\nFHF\n(φ)+\nD\nyxij\nSHF\n(2φ) \u2003\u2003(50) \n where: \n A\nxyij\n=A\nyxij\n=C\nxyij\n=C\nyxij\n; B\nxyij\n=B\nyxij\n; and D\nxyij\n=D\nyxij \n \n \nEquations 49 and 50 may therefore be combined, for example, as follows: \n \nXY\nij\n+YX\nij\n=2\nB\nxyij\nSHF\n(2θ)+2\nD\nxyij\nSHF\n(2φ) \u2003\u2003(51) \n \nXY\nij \nYX\nij\n=2\nA\nxyij\n(\nFHF\n(θ)+\nFHF\n(φ))', '(52)', 'The following gain compensated, azimuthally invariant quantities related to a difference between the xy and yx cross coupling components may therefore be computed.', 'CRXYMYX=TBT\n(real(\nXY\nij \nYX\nij\n))', 'CRXYMYX=TBT\n(imag(\nXY\nij \nYX\nij\n))', '(53) \n \nThe functional form of XY\nij\n+YX\nij \nsuggests that TBT(XY\nij\n+YX\nij\n) is not azimuthally invariant.', 'Eccentered Tool—Axial Coupling Component\n \nThe Z\nzz \ncoupling impedance may be expressed in the following functional form: \n \nZZ\nij\n=A\nzzij\n+B\nzzij\n(\nSHF\n(2)+\nSHF\n(2φ))', '(54) \n \nwhere real(A\nzzij\n)>>real(B\nzzij\n).', 'Since the magnitude of the real part of A\nzzij \nis about 3 order of magnitude greater than that of B\nzzij\n, TBT(real(Z\nzz\n)) is essentially azimuthally invariant.', 'It will be understood that in isotropic formations or anisotropic formations having zero dip, the off-diagonal components of VR\nZ\nij \n(equation 32) are equal to zero.', 'Moreover, in anisotropic formations having non-zero dip, the off-diagonal components of VR\nZ\nij \ngenerally exhibit zero-crossing points.', 'The axial (z-related) non-diagonal terms have two zero-crossing points while the non-axial (non z-related) off-diagonal terms have 4 zero-crossing points as the formation dip azimuth varies.', 'It will be readily apparent that when the measurement of VR\nZ\nij \nhas zero response (a zero value), the quantities in equation 33 are undefined (owing to a division by zero).', 'In practice it may thus be necessary to trap and/or flag such conditions.', 'For example, a noise floor may be evaluated for any particular measurement.', 'Measurement values less than some factor (e.g., five) of the noise floor may thus be flagged.', 'FIG.', '5\n depicts a flow chart of a method \n150\n for computing one of the gain compensated, azimuthally invariant quantities disclosed herein TBT(X\nij\n) and a warning flag F\nx \nto indicate the validity of the computed quantity.', 'The method is initialized at \n152\n by setting the warning flag to zero and selecting a value for multiplication factor n. Electromagnetic measurements X are received at \n154\n, for example, including substantially any suitable measurements described above with respect to equations 32-54.', 'For example, the measurements X may include the xz, zx, yz, zy, xy, yx, xx, yy, and/or zz tensor components and/or compound measurements such as xx+yy, xx−yy, xz+zx, xz−zx, yz+zy, yz−zy, xy+yx, and/or xy−yx, and/or real and imaginary components of any one or more of such measurements.', 'Input N\nijx \nrepresents the noise level of input measurement \nZ\nijx\n.', 'With continued reference to \nFIG.', '5\n, the compensated measurements may be computed at \n156\n (e.g., using one or more of the above described equations) and output at \n160\n.', 'A zero response in the denominator of the compensated quantity is evaluated at \n158\n.', 'A threshold value is obtained by multiplying factor n by the noise level (n·N\nijx\n).', 'Values above the threshold are considered to be non-zero while those below the threshold are taken to be equal to zero.', 'The flag F\nx \nis set to the value 1 when one of the denominator terms is below the threshold.', 'It will be understood that any suitable multiplication factor may be used (e.g., n=5).', 'Higher values tend to disqualify more data points with the accepted data points having a higher confidence level.', 'Lower values tend to accept more data points but have corresponding a lower a confidence level.', 'The disclosed embodiments are in no way limited to any multiplication factor values.', 'Model Data Validation\n \nThe disclosed embodiments are now described in further detail by way of the following non-limiting computational examples.', 'FIG.', '6\n depicts a schematic illustration of an eccentered electromagnetic logging tool \n50\n deployed in a wellbore \n40\n that penetrates an anisotropic formation at a relative dip angle is shown.', 'A wellbore reference frame may be defined by x-, y-, and z-axes (which are fixed relative to the wellbore).', 'A tool reference frame may be defined by x′-, y′-, and z′-axes which are fixed relative to the logging tool.', 'Rotation of the tool in the wellbore causes the x′- and y′-tool axes rotate about the z- and z′-axes with respect to the x- and y-axes of the wellbore.', 'The relative angle φ between the reference frames (e.g., between the x- and x′-axes in the plane orthogonal to the z-axis) is commonly referred to in the art as the toolface angle.', 'The tool \n50\n is shown to be eccentered in the wellbore \n40\n (having a wellbore diameter d) by an eccentering distance decc at an eccentering azimuthal angle ψ (in the wellbore reference frame).', 'An apparent eccentering azimuth (also referred to as the apparent tool eccentering angle AZT) may be defined as the direction of tool eccentering in the tool reference frame (e.g., with respect to the x′-axis).', 'The formation is depicted to be anisotropic, having vertical and horizontal conductivities σv and σh at a relative dip angle ϕ\ndip \nwith respect to the x-axis (i.e., with respect to the wellbore reference frame).', "An apparent dip azimuth angle is indicated by Φ and represents the relative angle between an orientation marker on the tool (e.g., the x′-axis on the tool which is aligned with the magnetic dipole on the x-axis transmitter) and the direction of the formation's normal vector on the plane orthogonal to the tool's z′-axis.", 'The apparent dip azimuth angle is also referred to herein as the apparent formation azimuth', 'AZF.', 'The conductivity of the drilling fluid is also indicated by σmud.', 'A finite element code was used to model the responses of the example triaxial tool depicted on \nFIG.', '2B\n deployed in a wellbore traversing a dipping anisotropic formation such as that illustrated in \nFIGS.', '6A and 6B\n.', 'The transmitter-to-receiver spacing (between T\n1\n and R\n1\n and between T\n2\n and R\n2\n) was 34 inches.', 'The spacing between R\n1\n and R\n2\n was 18 inches.', 'The outer diameter of the tool was 8.5 inches and the borehole diameter was 14 inches.', 'The horizontal resistivity and the vertical resistivity of the anisotropic formation were Rh=1 ohm·m and Rv=5 ohm·m (it will be understood to those of ordinary skill in the art that conductivity and resistivity are reciprocally related and can be derived from one another).', 'The wellbore was filled with an oil-based drilling fluid having a resistivity of 1000 ohm·m.', 'The formation dip was 30 degrees and the apparent dip azimuth was incremented from 0 to 330 degrees in 30 degree steps for a total of 12 formation iterations.', 'For each formation iteration, the tool was deployed at an eccentering distance decc off center in the borehole with the apparent tool eccentering azimuth varying from 0 to 330 degrees in 30 degree increments for a total of 12 tool eccentering azimuth iterations.', 'Thus for a given tool eccentering distance, a set of 144 iterations were generated (12 dip azimuth iterations times 12 eccentering azimuth iterations).', 'Multiple sets of iterations were computed for corresponding tool eccentering distances ranging from 0 to 2 inches.', 'The plots depicted on \nFIGS.', '7-10B\n were computed for a centered tool.', 'The plots on \nFIGS.', '11A-15B\n were computed for an eccentered tool having an eccentering distance of 2 inches and various eccentering azimuth angles.', 'FIGS.', '7 and 8\n depict plots of modeled compensated real (\nFIG.', '7\n) and imaginary (\nFIG.', '8\n) measurements versus formation dip azimuth (AZF) for each of the 3×3 tensor components acquired from a centered tool.', 'The gain compensated quantities were computed using the term by term (TBT) algorithm described above (e.g., in Equation 33).', 'Note that the compensated response for each of the off-diagonal responses (i.e., the xy, yx, xz, zx, yz, and zy components) is essentially azimuthally invariant (essentially independent of the formation dip azimuth) for both the real and imaginary measurements.', 'The gain compensated zz response (the axial coupling) is also observed to be azimuthally invariant.', 'As described previously, the gain compensated xx', 'and yy responses (the transverse couplings) vary with AZF as an approximate second harmonic function.', 'FIGS.', '7 and 8\n also demonstrate the utility of the zero-crossing flagging algorithm described above with respect to \nFIG.', '4\n.', 'The xy and yx components have four zero crossings (at AZF values of 0, 90, 180, and 270 degrees).', 'These values have been flagged and removed from the plots.', 'The xz, zx, yz, and zy components have two zero crossings (at AZF values of 90 and 270 degrees for the xz and zx components and values of 0 and 180 degrees for the yz and zy components).', 'These values have also been flagged and removed from the corresponding plots.', 'FIGS.', '9A and 9B\n depict plots of TBT(real(xxpyy\nij\n)) and TBT(imag(xxpyy\nij\n))', 'versus AZF acquired from a centered tool and computed using Equation 34.', 'Note that these gain compensated quantities are substantially azimuthally invariant (in this example varying less than 0.1% over 360 degrees of AZF).', 'FIGS.', '10A and 10B\n depict plots of TBT(real(xxmyy\nij\n)) and TBT(imag(xxmyy\nij\n))', 'versus AZF acquired from a centered tool and computed using Equation 35.', 'Note that these gain compensated quantities are substantially azimuthally invariant (in this example varying less than 0.5% over 360 degrees of AZF).', 'FIG.', '11A\n depicts a plot of TBT(real(XZ\nij\n+ZX\nij\n)) and TBT(imag(XZ\nij\n+ZX\nij\n)) versus AZF at various tool eccentering azimuth values.', 'As depicted, TBT(imag(XZ\nij\n+ZX\nij\n)) is azimuthally invariant with respect to both the formation dip azimuth (AZF) and the tool eccentering azimuth', '(AZT).', 'TBT(real(XZ\nij\n+ZX\nij\n)) is shown to vary with AZF and AZT.', 'Zero crossings at 90 and 270 degrees have been flagged and removed from the plot.', 'FIG.', '11B\n depicts a plot of TBT(real(XZ\nij\n+ZX\nij\n)) and TBT(imag(XZ\nij\n+ZX\nij\n)) versus AZT at various formation dip azimuth values.', 'As depicted, TBT(imag(XZ\nij\n+ZX\nij\n)) is azimuthally invariant with respect to both the formation dip azimuth (AZF) and the tool eccentering azimuth', '(AZT).', 'TBT(real(XZ\nij\n+ZX\nij\n)) is shown to vary with AZF and AZT.', 'With continued reference to \nFIGS.', '11A and 11B\n, it will be understood that TBT(real(YZ\nij\n+ZY\nij\n)) and TBT(imag(YZ\nij\n+ZY\nij\n))', 'are similar to TBT(real(XZ\nij\n+ZX\nij\n))', 'and TBT(imag(XZ\nij\n+ZX\nij\n)), but shifted by 90 degrees with respect to AZF and AZT.', 'For example, the zero crossings are at 0 and 180 degrees when plotted with respect to AZF (analogously to \nFIG.', '9A\n).', 'FIGS.', '12A and 12B\n depict plots of TBT(real(XX\nij\n+YY\nij\n))', 'and TBT(imag(XX\nij\n+YY\nij\n))', 'versus AZF (\nFIG.', '12A\n) and AZT (\nFIG.', '12B\n) as computed using Equation 48.', 'These measurement quantities are depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth.', 'FIGS.', '13A and 13B\n depict plots of TBT(real(XX\nij\n))', '+TBT(real(YY\nij\n)) and TBT(imag(XX\nij\n))', '+TBT(imag (YY\nij\n)) versus AZF (\nFIG.', '13A\n) and AZT (\nFIG.', '13B\n).', 'The imaginary measurement quantities are depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth while the real measurement quantities show some variation with respect to both the formation dip azimuth and the tool eccentering azimuth.', 'FIGS.', '14A and 14B\n depict plots of TBT(real(XY\nij \nYX\nij\n)) and TBT(imag(XY\nij \nYX\nij\n))', 'versus AZF (\nFIG.', '14A\n) and AZT (\nFIG.', '14B\n) as computed using Equation 53.', 'These measurement quantities are depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth.', 'FIGS.', '15A and 15B\n depict plots of TBT(real(Z\nzz\n)) and TBT(imagl(Z\nzz\n))', 'versus AZF (\nFIG.', '15A\n) and AZT (\nFIG.', '15B\n).', 'TBT(real(Z\nzz\n)) is shown to vary with azimuth while TBT(imagl(Z\nzz\n)) is depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth.', 'It will be understood that the various methods disclosed herein for computing gain compensated azimuthally invariant measurement quantities may be implemented on a on a downhole processor.', 'By downhole processor it is meant an electronic processor (e.g., a microprocessor or digital controller) deployed in the drill string (e.g., in the electromagnetic logging tool or elsewhere in the BHA).', 'In such embodiments, the computed quantities may be stored in downhole memory and/or transmitted to the surface while drilling via known telemetry techniques (e.g., mud pulse telemetry or wired drill pipe).', 'Alternatively, the harmonic fitting coefficients or the compensated quantities may transmitted to the surface and the apparent formation azimuth, the apparent tool eccentering azimuth, and/or the tool eccentering distance may be computed at the surface using a surface processor.', 'Whether transmitted to the surface or computed at the surface, the quantities may then be utilized in an inversion process (along with a formation model) to obtain various formation parameters as described above.', 'Although methods for making gain compensated, azimuthally invariant electromagnetic logging measurements have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.'] | ['1.', 'A method comprising:\n(a) operating an eccentered electromagnetic logging tool in a wellbore in a subterranean formation, the electromagnetic logging tool including a transmitter axially spaced apart from a receiver, the transmitter including an axial transmitting antenna and at least one transverse transmitting antenna, the receiver including an axial receiving antenna and at least one transverse receiving antenna;\n(b) causing the axial transmitting antenna and the at least one transverse transmitting antenna to sequentially transmit corresponding electromagnetic waves into the wellbore;\n(c) using the axial receiving antenna and the at least one transverse receiving antenna to receive voltage measurements corresponding to the electromagnetic waves transmitted in (b), wherein the voltage measurements comprise different coupling voltages;\n(d) processing combinations of the different coupling voltages at least in part by matching of formation dip azimuth and tool eccentering azimuth harmonic functions to compute a gain compensated, azimuthally invariant measurement quantity; and\n(e) performing an inversion using at least the gain compensated, azimuthally invariant measurement quantity to compute at least one conductivity value of the subterranean formation.', '2.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity computed in (d) is azimuthally invariant with respect to at least one of the formation dip azimuth and the tool eccentering azimuth of the electromagnetic logging tool in the wellbore.', '3.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is related to an xz and a zx coupling or to a yz and a zy coupling.', '4.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is related to an imaginary component of an xz+zx coupling or an imaginary component of a yz+zy coupling.', '5.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is computed according to at least one of the following mathematical equations:\nCIXZPZX=TBT(imag(XZij+ZXij))', 'CIYZPZY=TBT(imag(YZij+ZYij))\nwherein CIXZPZX and CIYZPZY represent the gain compensated, azimuthally invariant measurement quantity, XZij, ZXij, YZij, and ZYij represent the voltage measurements expressed as formation dip azimuth and tool eccentering azimuth harmonic functions, XZij+ZXij and YZij+ZYij comprise matched formation dip azimuth and tool eccentering azimuth harmonic functions, imag(·) represents an imaginary component of the matched formation dip azimuth and tool eccentering azimuth harmonic functions, and TBT(·) represents a computed ratio.', '6.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is related to an xx and a yy coupling.', '7.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is related to a real or an imaginary component of an xx+yy coupling.', '8.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is computed according to at least one of the following mathematical equations:\nCRXXPYY=TBT(real(XXij+YYij))', 'CIXXPYY=TBT(imag(XXij+YYij))\nwherein CRXXPYY and CIXXPYY represent the gain compensated, azimuthally invariant measurement quantity, XXij and YYij represent the voltage measurements expressed as formation dip azimuth and tool eccentering azimuth harmonic functions, XXij+YYij comprises matched formation dip azimuth and tool eccentering azimuth harmonic functions, real(·) represents a real component of the matched formation dip azimuth and tool eccentering azimuth harmonic functions, imag(·) represents an imaginary component of the matched formation dip azimuth and tool eccentering azimuth harmonic functions, and TBT(·) represents a computed ratio.', '9.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is related to an xy and a yx coupling.', '10.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is related to a real or an imaginary component of an xy+yx coupling.', '11.', 'The method of claim 1, wherein the gain compensated, azimuthally invariant measurement quantity is computed according to at least one of the following mathematical equations:\nCRXYMYX=TBT(real(XYij−YXij))', 'CRXYMYX=TBT(imag(XYij−YXij))\nwherein CRXYMYX and CRXYMYX represent the gain compensated, azimuthally invariant measurement quantity, XYij and YXij represent the voltage measurements expressed as formation dip azimuth and tool eccentering azimuth harmonic functions, XYij −YXij represents comprises matched formation dip azimuth and tool eccentering azimuth harmonic functions, real(·) represents a real component of the matched formation dip azimuth and tool eccentering azimuth harmonic functions, imag(·) represents an imaginary component of the matched formation dip azimuth and tool eccentering azimuth harmonic functions, and TBT(·) represents a computed ratio.\n\n\n\n\n\n\n12.', 'A method comprising:\n(a) operating an electromagnetic logging tool in a wellbore in a subterranean formation, the electromagnetic logging tool including a transmitter axially spaced apart from a receiver, the transmitter including an axial transmitting antenna and at least one transverse transmitting antenna, the receiver including an axial receiving antenna and at least one transverse receiving antenna;\n(b) causing the axial transmitting antenna and the at least one transverse transmitting antenna to transmit corresponding electromagnetic waves into the subterranean formation;\n(c) using the axial receiving antenna and the at least one transverse receiving antenna to receive voltage measurements corresponding to the electromagnetic waves transmitted in (b), wherein the voltage measurements comprise different coupling voltages;\n(d) processing combinations of the different coupling voltages at least in part by matching of formation dip azimuth harmonic functions to compute a gain compensated, azimuthally invariant measurement quantity; and\n(e) performing an inversion using at least the gain compensated, azimuthally invariant measurement quantity to compute at least one conductivity value of the subterranean formation.', '13.', 'A logging while drilling tool comprising:\na logging while drilling tool body;\nat least one transmitter axially spaced apart from at least one receiver on the tool body, the transmitter including an axial transmitting antenna and at least one transverse transmitting antenna, the receiver including an axial receiving antenna and at least one transverse receiving antenna; and\na controller configured to (i) cause the axial transmitting antenna and the at least one transverse transmitting antenna to sequentially transmit corresponding electromagnetic waves; (ii) cause the axial receiving antenna and at least one transverse receiving antenna to receive voltage measurements corresponding to the electromagnetic waves transmitted in (i), wherein the voltage measurements comprise different coupling voltages, and (iii) process combinations of the different coupling voltages at least in part by matching at least one of formation dip azimuth harmonic functions and formation dip azimuth and tool eccentering azimuth harmonic functions to compute at least one gain compensated, azimuthally invariant measurement quantity for inversion to compute at least one conductivity value of a subterranean formation.', '14.', 'The logging while drilling tool of claim 13, wherein the at least one gain compensated, azimuthally invariant measurement quantity is azimuthally invariant with respect to at least one of a formation dip azimuth and a tool eccentering azimuth of the logging while drilling tool in a wellbore in the subterranean formation.', '15.', 'The logging while drilling tool of claim 13, wherein the at least one gain compensated, azimuthally invariant measurement quantity is azimuthally invariant with respect to both a formation dip azimuth and a tool eccentering azimuth of the logging while drilling tool in a wellbore in the subterranean formation.', '16.', 'The logging while drilling tool of claim 13, wherein the at least one gain compensated, azimuthally invariant measurement quantity is related to an xz and a zx coupling or to a yz and a zy coupling.'] | ['FIG.', '1 depicts one example of a drilling rig on which the disclosed electromagnetic logging methods may be utilized.;', 'FIG.', '2A depicts one example of the electromagnetic logging tool shown on FIG.', '1.; FIG.', '2B schematically depicts the antenna moments in an electromagnetic logging tool including triaxial transmitters and receivers.;', 'FIG.', '2C schematically depicts the antenna moments in an alternative electromagnetic logging tool including triaxial transmitters and receivers.; FIG.', '3 depicts a flow chart of one disclosed method embodiment for computing gain compensated, azimuthally invariant measurement quantities.; FIG.', '4 depicts a flow chart of another disclosed method embodiment for computing gain compensated, azimuthally invariant measurement quantities.; FIG.', '5 depicts a flow chart of a method embodiment for obtaining a warning flag indicative of the validity of the computed quantity.; FIGS.', '6A and 6B (collectively FIG. 6) depict a schematic illustration of an eccentered tool in a wellbore that penetrates an anisotropic formation at a relative dip angle.; FIGS. 7 and 8 depict plots of compensated real (FIG. 7) and imaginary (FIG.', '8) modeled measurements versus formation dip azimuth (AZF) for each of the 3×3 tensor components acquired from a centered tool.; FIGS.', '9A and 9B depict plots of TBT(real(xxpyyij)) and TBT(imag(xxpyyij))', 'versus AZF acquired from a centered tool.; FIGS.', '10A and 10B depict plots of TBT(real(xxmyyij)) and TBT(imag(xxmyyij))', 'versus AZF acquired from a centered tool.; FIG.', '11A depicts a plot of TBT(real(XZij+ZXij)) and TBT(imag(XZij+ZXij))', 'versus AZF at various tool eccentering azimuth values.; FIG.', '11B depicts a plot of TBT(real(XZij+ZXij)) and TBT(imag(XZij+ZXij))', 'versus AZT at various formation dip azimuth values.; FIGS.', '12A and 12B depict plots of TBT(real(XXij+YYij)) and TBT(imag(XXij+YYij))', 'versus AZF (FIG. 12A) and AZT (FIG. 12B).; FIGS.', '13A and 13B depict plots of TBT(real(XXij))+TBT(real(YYij)) and TBT(imag(XXij))+TBT(imag(YYij))', 'versus AZF (FIG.', '13A) and AZT (FIG. 13B).;', 'FIGS.', '14A and 14B depict plots of TBT(real(XYij YXij)) and TBT(imag(XYij YXij)) versus AZF (FIG. 14A) and AZT (FIG.', '14B).', '; FIGS.', '15A and 15B depict plots of TBT(real(Zzz)) and TBT(imagl(Zzz))', 'versus AZF (FIG. 15A) and AZT (FIG. 15B).; FIG. 1 depicts an example drilling rig 10 suitable for employing various method embodiments disclosed herein.', 'A semisubmersible drilling platform 12 is positioned over an oil or gas formation (not shown) disposed below the sea floor 16.', 'A subsea conduit 18 extends from deck 20 of platform 12 to a wellhead installation 22.', 'The platform may include a derrick and a hoisting apparatus for raising and lowering a drill string 30, which, as shown, extends into borehole 40 and includes a drill bit 32 deployed at the lower end of a bottom hole assembly (BHA) that further includes an electromagnetic measurement tool 50 configured to make directional electromagnetic logging measurements.', 'As described in more detail below the electromagnetic measurement tool 50 may include multi-axial antennas deployed on a logging while drilling tool body.', '; FIG.', '2A depicts one example of an electromagnetic measurement tool 50.', 'In the depicted embodiment measurement tool 50 includes first and second axially spaced transmitters 52 and 54 and first and second axially spaced receivers 56 and 58 deployed on a logging while drilling tool body 51, with the receivers 56 and 58 being deployed axially between the transmitters 52 and 54.', 'As described in more detail below, each of the transmitters 52 and 54 and receivers 56 and 58 includes at least one transverse antenna and may further include an axial antenna.', 'For example, the transmitters and receivers may include a bi-axial antenna arrangement including an axial antenna and a transverse (cross-axial) antenna.', 'In another embodiment, the transmitters and receivers may include a tri-axial antenna arrangement including an axial antenna and first and second transverse antennas that are orthogonal to one another.', 'As is known to those of ordinary skill in the art, an axial antenna is one whose moment is substantially parallel with the longitudinal axis of the tool.', 'Axial antennas are commonly wound about the circumference of the logging tool such that the plane of the antenna is substantially orthogonal to the tool axis.', 'A transverse antenna is one whose moment is substantially perpendicular to the longitudinal axis of the tool.', 'A transverse antenna may include, for example, a saddle coil (e.g., as disclosed in U.S. Patent Publications 2011/0074427 and 2011/0238312 each of which is incorporated by reference herein).', '; FIG.', '2B depicts the moments (magnetic dipoles) of one embodiment of measurement tool 50 in which the transmitters 52, 54 and receivers 56, 58 each include a tri-axial antenna arrangement.', 'Each of the transmitters 52, 54 includes an axial transmitting antenna T1z and T2z and first and second transverse transmitting antennas T1x, T1y and T2x, T2y.', 'Likewise, each of the receivers 56, 58 includes an axial receiving antenna R1z and R2z and first and second transverse receiving antennas R1x, R1y and R2x, R2y.', 'It will be understood that the disclosed embodiments are not limited to a tri-axial antenna configuration such as that depicted on FIG.', '2B.; FIG.', '2C depicts an alternative electromagnetic measurement tool embodiment 50′ in which the first and second transmitters are deployed on corresponding first and second subs 61 and 62 that are free to rotate with respect to one another (e.g., in an embodiment in which a drilling motor 65 is deployed therebetween).', 'As in tool embodiment 50, each of the transmitters T1 and T2 and receivers R1 and R1 may include a tri-axial antenna arrangement.', 'In the example embodiment depicted the moment of R1z is aligned with the moment of T1z (and the z-axis) while the moments of R1x and R1y are rotationally offset from the moments of T1x and T1y by an offset angle α (e.g., 45 degrees in the depicted embodiment).', 'The moment of R2z is aligned with the moment of T2z while the moments of R2x and R2y are rotationally offset from the moments of T2x and T2y by α (e.g., 45 degrees).', 'The disclosed embodiments are, of course, not limited in these regards.; FIG.', '3 depicts a flow chart of one disclosed method embodiment 100 for computing gain compensated azimuthally invariant measurement quantities.', 'An electromagnetic measurement tool (e.g., one of the measurement tools depicted on FIGS.', '2B and 2C) is deployed in and rotated in a subterranean wellbore at 102 (e.g., while drilling the wellbore).', 'Electromagnetic measurements are acquired at 104 (e.g., via firing the transmitters and receiving the corresponding electromagnetic waves at the receiving antennas) while the tool is rotating and processed to obtain harmonic voltage coefficients.', 'Ratios of selected harmonic voltage coefficients may then be processed to obtain the gain compensated, azimuthally invariant measurement quantities at 106.', 'The harmonic voltage coefficients are selected such that (i) the transmitter and receiver gains are canceled in the computed ratio (i.e., such that the coefficients in the numerator have the same gains as the coefficients in the denominator) and such that (ii) the measurement quantity is azimuthally invariant (i.e., such that the azimuthal response of the quantities in the denominator is the same, and thus cancels, the azimuthal response of the quantities in the numerator).', 'For example, if the numerator includes a first harmonic cosine function then the denominator may be selected such that it also includes a first harmonic cosine function.; FIG.', '4 depicts a flow chart of an alternative methodology 120 for computing gain compensated azimuthally invariant measurement quantities.', 'An electromagnetic measurement tool (e.g., one of the measurement tools depicted on FIGS.', '2B and 2C) is deployed in and rotated in a subterranean wellbore at 122 (e.g., while drilling the wellbore).', 'The measurement tool is generally (but not necessarily) eccentered (off-centered) in the wellbore while rotating in 122.', 'A plurality of electromagnetic measurements is acquired at 124.', 'These measurements may be acquired, for example, via sequentially firing a plurality of the transmitters and receiving the corresponding electromagnetic waves (voltages) at a corresponding plurality of the receiving antennas while the tool is rotating in 122.', 'Certain ones of the electromagnetic measurements are combined (e.g., added or subtracted) to obtain combined measurement quantities at 126.', 'In certain embodiments, the combined measurement quantities may be azimuthally invariant with respect to one or both of the formation dip azimuth and the eccentering azimuth.', 'Ratios of selected ones of the combined measurement quantities may then be processed to compute the gain compensated, azimuthally invariant measurement quantities at 128.; FIG.', '5 depicts a flow chart of a method 150 for computing one of the gain compensated, azimuthally invariant quantities disclosed herein TBT(Xij) and a warning flag Fx to indicate the validity of the computed quantity.', 'The method is initialized at 152 by setting the warning flag to zero and selecting a value for multiplication factor n. Electromagnetic measurements X are received at 154, for example, including substantially any suitable measurements described above with respect to equations 32-54.', 'For example, the measurements X may include the xz, zx, yz, zy, xy, yx, xx, yy, and/or zz tensor components and/or compound measurements such as xx+yy, xx−yy, xz+zx, xz−zx, yz+zy, yz−zy, xy+yx, and/or xy−yx, and/or real and imaginary components of any one or more of such measurements.', 'Input Nijx represents the noise level of input measurement Zijx.; FIGS. 7 and 8 depict plots of modeled compensated real (FIG. 7) and imaginary (FIG.', '8) measurements versus formation dip azimuth (AZF) for each of the 3×3 tensor components acquired from a centered tool.', 'The gain compensated quantities were computed using the term by term (TBT) algorithm described above (e.g., in Equation 33).', 'Note that the compensated response for each of the off-diagonal responses (i.e., the xy, yx, xz, zx, yz, and zy components) is essentially azimuthally invariant (essentially independent of the formation dip azimuth) for both the real and imaginary measurements.', 'The gain compensated zz response (the axial coupling) is also observed to be azimuthally invariant.', 'As described previously, the gain compensated xx', 'and yy responses (the transverse couplings) vary with AZF as an approximate second harmonic function.; FIGS. 7 and 8 also demonstrate the utility of the zero-crossing flagging algorithm described above with respect to FIG.', '4.', 'The xy and yx components have four zero crossings (at AZF values of 0, 90, 180, and 270 degrees).', 'These values have been flagged and removed from the plots.', 'The xz, zx, yz, and zy components have two zero crossings (at AZF values of 90 and 270 degrees for the xz and zx components and values of 0 and 180 degrees for the yz and zy components).', 'These values have also been flagged and removed from the corresponding plots.; FIGS.', '9A and 9B depict plots of TBT(real(xxpyyij)) and TBT(imag(xxpyyij))', 'versus AZF acquired from a centered tool and computed using Equation 34.', 'Note that these gain compensated quantities are substantially azimuthally invariant (in this example varying less than 0.1% over 360 degrees of AZF).; FIGS.', '10A and 10B depict plots of TBT(real(xxmyyij)) and TBT(imag(xxmyyij))', 'versus AZF acquired from a centered tool and computed using Equation 35.', 'Note that these gain compensated quantities are substantially azimuthally invariant (in this example varying less than 0.5% over 360 degrees of AZF).', '; FIG.', '11A depicts a plot of TBT(real(XZij+ZXij)) and TBT(imag(XZij+ZXij))', 'versus AZF at various tool eccentering azimuth values.', 'As depicted, TBT(imag(XZij+ZXij)) is azimuthally invariant with respect to both the formation dip azimuth (AZF) and the tool eccentering azimuth', '(AZT).', 'TBT(real(XZij+ZXij)) is shown to vary with AZF and AZT.', 'Zero crossings at 90 and 270 degrees have been flagged and removed from the plot.; FIG.', '11B depicts a plot of TBT(real(XZij+ZXij)) and TBT(imag(XZij+ZXij))', 'versus AZT at various formation dip azimuth values.', 'As depicted, TBT(imag(XZij+ZXij)) is azimuthally invariant with respect to both the formation dip azimuth (AZF) and the tool eccentering azimuth', '(AZT).', 'TBT(real(XZij+ZXij)) is shown to vary with AZF and AZT.; FIGS.', '12A and 12B depict plots of TBT(real(XXij+YYij)) and TBT(imag(XXij+YYij))', 'versus AZF (FIG. 12A) and AZT (FIG. 12B) as computed using Equation 48.', 'These measurement quantities are depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth.; FIGS.', '13A and 13B depict plots of TBT(real(XXij))+TBT(real(YYij)) and TBT(imag(XXij))+TBT(imag (YYij))', 'versus AZF (FIG.', '13A) and AZT (FIG. 13B).', 'The imaginary measurement quantities are depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth while the real measurement quantities show some variation with respect to both the formation dip azimuth and the tool eccentering azimuth.; FIGS.', '14A and 14B depict plots of TBT(real(XYij YXij)) and TBT(imag(XYij YXij)) versus AZF (FIG. 14A) and AZT (FIG.', '14B) as computed using Equation 53.', 'These measurement quantities are depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth.; FIGS.', '15A and 15B depict plots of TBT(real(Zzz)) and TBT(imagl(Zzz))', 'versus AZF (FIG. 15A) and AZT (FIG. 15B).', 'TBT(real(Zzz)) is shown to vary with azimuth while TBT(imagl(Zzz)) is depicted to be invariant with respect to both the formation dip azimuth and the tool eccentering azimuth.'] |
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with fluid in the fluid flow line of a borehole tool.', 'The crystals are chosen to have different refractive indices and/or different angles of incidence, but to provide total internal reflection for light that is directed through the crystals to the crystal/fluid interface.', 'The measured attenuations for each crystal are used in conjunction with the known refractive indices and angles of incidence of said crystals to determine the refractive index of the fluid.'] | ['Description\n\n\n\n\n\n\nRELATED ART', 'The present application is related to co-owned U.S. Pat.', 'No. 9,500,583 to Jiang et al., which is hereby incorporated by reference herein in its entirety.', 'TECHNICAL FIELD', 'The subject disclosure relates to the downhole monitoring of fluids in a formation.', 'More particularly, the subject disclosure relates to apparatus and methods for measuring the refractive index of a formation fluid which may be useful during production of hydrocarbons from a formation, although the disclosure is not limited thereto.', 'BACKGROUND', 'In developing an oilfield, and during both injection and production, reservoir fluids are monitored.', 'In enhanced oil recovery (EOR) processes, compositional measurements within fluids are useful for quantitative evaluation of displacement induced migration.', 'Specifically, data on fluids characterization in different producing zones may be used to infer reservoir structure.', 'One commonly used approach in measuring fluid composition is to withdraw fluid samples from a reservoir in a formation using a formation testing probe (downhole tool) or packed-off intervals.', 'Light beams and light sensors of the downhole tool are used to measure light transmission at infra-red (IR) wavelengths of the fluid sample which is pulled into a flowline.', 'The spectral characteristics of the transmitted beam are indicative of various components within the fluid, each chemical component having its own absorption signature.', 'In addition, transport properties of the fluid such as the density and viscosity may be obtained.', 'As disclosed in previously-incorporated U.S. Pat.', 'No. 9,500,583 to Jiang et al., attenuated total reflection (ATR) measurements at mid-IR frequencies can be used to measure a dissolved component, e.g. CO\n2 \nin a liquid.', "Methods utilizing ATR measurements rely on the attenuation of a reflected wave due to a small penetration (usually to a depth of a fraction of a wavelength) of the incident beam's evanescent wave.", 'The penetration depth is dependent on the refractive indices of the fluid and the material with which the fluid is in contact.', 'In the absence of any information, a particular refractive index for the fluid is assumed.', 'However, since the refractive index of the fluid may vary with the concentration of the dissolved components, as well as temperature and pressure, the assumption that the refractive index of fluids flowing through a flowline remains constant can result in certain inaccuracies in analyzing the fluid components, especially in EOR processes.', 'While the refractive index of formation fluids such as crude oil has been measured uphole using conventional refractometers, it is logistically difficult and expensive to routinely bring reconstituted representative samples to the laboratory for analysis.', 'Moreover, the reservoir fluids being brought uphole may be contaminated by drilling-mud filtrate, and contaminants may be introduced or removed during the fluid transfer process from downhole to the lab, thereby introducing significant bias in the estimates of the refractive index of the downhole fluid.', 'Another challenge arises due to the variability of the refractive index with temperature, fluid composition, and pressure.', 'Yet a further challenge to measuring the refractive index of the formation fluid is posed by the dissolution of gases such as CO\n2 \nin the fluid hydrocarbon, the very concentration of which is often the interest in EOR monitoring.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'Illustrative embodiments of the present disclosure include a borehole tool employing a flow line, a light source, two non-alike crystals interfacing with the flow line, light detectors, and a processor, where the light source, crystals, and flow line are arranged for light to be transmitted through the crystals and to undergo attenuated total reflection, and the detected intensities (or absorbances) detected by the light detectors are used by the processor in determining the refractive index of the fluid flowing in the flow line.', 'In one embodiment, the non-alike crystals are not alike in that they have different refractive indices, e.g., they are different materials.', 'In one embodiment, the non-alike crystals are of the same material but are not alike in that they have different geometries.', 'In one embodiment, the non-alike crystals differ in both their materials and their geometries.', 'Additional aspects, embodiments, objects and advantages of the disclosed apparatus and methods may be understood with reference to the following detailed description taken in conjunction with the provided drawings.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a schematic diagram of an apparatus for downhole determination of the refractive index of a formation fluid.', 'FIG.', '2\n is a partial block, partial schematic diagram of elements of the apparatus of \nFIG.', '1\n.', 'FIGS.', '3\na \nand 3\nb \nare schematic diagrams showing crystals arranged relative to a flow line.\n \nFIG.', '4\n is a plot of a double normalized function for the effective path length for diamond and sapphire.\n \nFIG.', '5\n is a flow chart of a method of determining a refractive index of a formation fluid.', 'DETAILED DESCRIPTION', 'The particulars shown herein are by way of example and for purposes of illustrative discussion of the examples of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure.', 'In this regard, no attempt is made to show details in more detail than is necessary, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice.', 'Furthermore, like reference numbers and designations in the various drawings indicate like elements.', 'Before discussing embodiments, it is useful to understand some of the underlying physics, and to provide certain definitions.', 'The refractive index, η, is the reciprocal of the ratio of the phase velocity ν in the medium of interest to the speed of light in a vacuum (c) i.e.,\n \n \n \n \n \n \n \n \nη\n \n=\n \n \n \nc\n \nv\n \n \n.', '(\n \n1\n \n)\n \n \n \n \n \n \n \n Light travels slower in a non-vacuum medium than it travels in vacuum because of electromagnetic field interactions with the charged particles of the medium.', 'The speed of light in a particular medium and its refractive index are dependent both on temperature and pressure.', 'Various relationships have been proposed to capture the dependence between refractive index and mass density.', 'For example, in miscible systems, the Gladstone-Dale equation is \n \n \n \n \n \n \n \n \n \n \n \nη\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \nϱ\n \n \n=\n \n \n \n∑\n \n1\n \nN\n \n \n\u2062\n \n \n \n \n\u2062\n \n \n \nw\n \ni\n \n \n\u2062\n \n \nη\n \nMi\n \n \n \n \n \n,\n \n \n \n \n \n(\n \n2\n \n)\n \n \n \n \n \n \n \n where is the mass density of the medium, η\nMi \nis the molar refractivity of the i\nth \ncomponent, w\ni \nis the mass fraction of the component i, and the summation is over all the N components.', "Another well-known relationship is the Lorentz-Lorenz equation \n \n \n \n \n \n \n \n \n \n \n \n \nη\n \n2\n \n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \nη\n \n2\n \n \n+\n \n2\n \n \n \n=\n \n \n \n(\n \n \n \n \nN\n \nA\n \n \n\u2062\n \nα\n \n \n \n3\n \n\u2062\n \nM\n \n \n \n)\n \n \n\u2062\n \nϱ\n \n \n \n,\n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n where α denotes the molecular polarizability of the medium, N\nA \nis the Avogadro's number, and M is the molecular weight of the medium.", 'The polarizability is the coefficient of proportionality between the dipole moment and the electric field.', 'Measurements of refractive index can be combined with one or more of the aforementioned formulae to obtain physical properties of interest, including mass density, composition of crude oil, viscosity etc.', 'within a restricted series of materials.', 'These estimates are useful for reservoir modeling and in many other contexts.', 'ATR technology is based on measuring the change in the intensity of a totally internally reflected (infrared) beam when it passes through the interface of the sensor (crystal) and the sample.', 'The change of intensity may be described in terms of the attenuation of the reflected beam intensity when compared to the incident beam.', 'In implementing technology utilizing attenuated total reflection, two necessary conditions for total internal reflection should be satisfied including that the refractive index of the crystal is greater than that of the sample, and that the incident angle of the beam is greater than the critical angle at the crystal-sample interface.', 'As previously suggested, the amplitude of the internally reflected wave at the crystal-sample interface is affected because the evanescent wave formed while undergoing total internal reflection penetrates the sample adjacent to the interface, and exponentially decays with the distance from the crystal-sample interface.', 'The penetration depth d\np \nis the distance from the crystal-sample interface where the intensity of the evanescent wave decays to 1/e of its original value and is given by\n \n \n \n \n \n \n \n \n \n \nd\n \np\n \n \n=\n \n \nλ\n \n \n2\n \n\u2062\n \n \n \n \n\u2062\n \n \nΠη\n \nc\n \n \n\u2062\n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \nΘ\n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n/\n \n \nη\n \nc\n \n \n \n)\n \n \n \n2\n \n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n4\n \n)\n \n \n \n \n \n \n \n where λ is the wavelength of infrared radiation, n\nf \nis the refractive index of the fluid, η\nc \nis the refractive index of the ATR crystal, and Θ is the angle of incidence.', 'In a strongly absorbing medium, the interaction between the probing light beam and the medium should be sufficiently small to ensure that measurements are not entirely attenuated.', 'In this context, the extent of interaction is quantified by the depth of penetration.', 'Since the penetration depth of the evanescent wave may be measured in the range of microns to a few millimeters, as set forth in previously incorporated U.S. Pat.', 'No. 9,500,583 to Jiang et al., ATR can be a powerful technique for obtaining indications of CO\n2 \ndissolved in brine and crude oil downhole.', 'It is also noted that if the ATR sensing apparatus is configured to have multiple reflections N\nR\n, the cumulative depth of penetration N\nR\nd\np \nmay be used to compute the effective optical path length of the sensor, l. \n \nIn one aspect, it may be assumed that the effective path length of mid-IR waves in a ATR crystal is proportional to d\np \nas may be calculated from equation (4).', 'In reality, the interactions are more complicated, as parallel and perpendicular polarized waves undergo differing attenuations, a complexity that is circumvented by the perturbation expansions considered hereinafter.', 'Thus, as a starting point, the effective path length may be calculated according to \n \nl=KN\nR\nd\np\n,\u2003\u2003(5) \n where N\nR \nis the number of reflections that is determined by the design of the crystal-fluid interface, and K is an oft-ignored proportionality variable that is likely to vary with η\nf\n, η\nc \nand Θ. \n \nOne purpose of making an ATR measurement is for a determination of the concentration C of a dissolved species that attenuates the incident IR-signal at one or more chosen wavelengths.', 'The measurement is conducted by measuring the attenuation ratio, and assuming that η\nf \nis known, l is calculated, and from which, the attenuation coefficient at the wavelength of interest is inferred.', 'Since the attenuation coefficient is directly related to C at the sensitive wavelength λ, the concentration may be estimated.', "The issue is that the procedure assumes that either η\nf \nis known, or that η\nf \nis independent of C and that the solvent's η\nf \nis known as a function of pressure and temperature.", 'The latter dependence is sufficiently weak and may be accounted for through calibration.', 'Also, traditionally the technique has worked well for dilute solutions.', "However, when the solution is not dilute in the solute, η\nf \nvaries with C, resulting in an error in estimated C.\n \nThe Beer-Lambert's law relates the absorbance A(λ), concentration C of a component in the downhole fluid that induces absorption at λ, and the optical path length l.", 'At any wavelength \n \nA\n(λ)=ε(λ)\nCl\n=ε(λ)\nCKN\nR\nd\np\n,\u2003\u2003(6) \n where ε(λ) is the absorption coefficient of the component at wavelength λ.', 'Knowing the intensity of the incident beam (e.g., by using a reference wavelength where no attenuation is expected to occur), and the intensity of the reflected beam, A(λ) is obtained from \n \n \n \n \n \n \n \n \n \nA\n \n\u2061\n \n \n(\n \nλ\n \n)\n \n \n \n=\n \n \n \nln\n \n\u2061\n \n \n(\n \n \n \nI\n \n\u2061\n \n \n(\n \nλ\n \n)\n \n \n \n \n \nI\n \n0\n \n \n\u2061\n \n \n(\n \nλ\n \n)\n \n \n \n \n)\n \n \n \n.', '(\n \n7\n \n)\n \n \n \n \n \n \n \n where I\n0\n(λ) and I(λ) are the magnitudes of the incident intensity and reflected intensity respectively at wavelength λ.', 'Thus, the measurements allow a determination of A(λ).', 'Knowing A(λ) provides a determination of C (equation (6)) if d\np \nis known (for a constant K).', 'This in turn assumes that η\nf \nof the fluid is known.', 'However, in the oil-field, the solvent is unknown.', 'Properties of the hydrocarbon vary from well to well or from zone to zone in a given well.', 'In addition, for a given solvent, η\nf \nmay vary with C.', 'It will be appreciated by those of skill in the art that the intensity I\n0\n(λ) is an unknown unless a reference wavelength at which no attenuation takes place is available.', 'Since the ratio of the intensities of the source beam is known at the two wavelengths (this drift is assumed to be negligible), the reference and the absorption values, I\n0\n(λ) is obtained from the reference response.', 'The ratio of the incident intensity may be a function of temperature, but this is known a priori.', 'With the previously described underlying physics in mind, according to one aspect, the refractive index of a fluid is measured downhole as hereinafter described by using information obtained from two different attenuated total reflectance (ATR) sensors.', 'Knowing the refractive index permits a calculation of the concentration of the species that attenuates the signal at the wavelength of interest.', 'The present description focuses on the mid-infrared (m-IR) range; however, the technique is also extensible to a different range of wavelengths.', 'Turning now to \nFIG.', '1\n, an apparatus \n10\n for determining downhole the refractive index of a formation fluid is seen.', 'The apparatus or tool \n10\n is seen suspended in a borehole \n12\n traversing a formation \n14\n by a cable \n15\n that is spooled in a usual fashion on a suitable winch (not shown) on the formation surface.', 'On the surface, the cable \n15\n may be electrically coupled to an electrical control system \n18\n.', 'The tool \n10\n includes an elongated body \n19\n which encloses the downhole portion of the tool control system \n16\n.', 'The elongated body \n19\n also carries a selectively extendable fluid admitting assembly \n20\n and a selectively extendable tool anchoring member \n21\n which are respectively arranged on opposite sides of the body.', 'The fluid admitting assembly \n20\n is equipped for selectively sealing off or isolating selected portions of the wall of the borehole \n12\n such that pressure or fluid communication with the adjacent earth formation is established.', 'Also included with tool \n10\n are a fluid analysis module \n25\n with a flow line \n30\n through which the obtained fluid flows.', 'The fluid may thereafter be expelled through a port (not shown) or it may be sent to one or more fluid collecting chambers \n22\n and \n23\n which may receive and retain the fluids obtained from the formation.', 'Control of the fluid admitting assembly, the fluid analysis section, and the flow path to the collecting chambers is maintained by the electrical control systems \n16\n and \n18\n.', 'In at least one aspect, at least two testing chambers are placed in communication with the flow line \n30\n in a manner described hereinafter with respect to \nFIGS.', '3\na \nand 3\nb\n.', 'Each test chamber may assume a configuration substantially as shown in \nFIG.', '2\n.', 'In particular, each sample chamber \n114\n may be bounded by a cover \n116\n and an exterior surface \n118\n of an optically dense crystal \n120\n.', 'The flow line provides for supply of the fluid sample \n122\n into the sample chamber \n114\n such that liquid fluid (the sample) is in direct contact with the exterior surface \n118\n of the crystal \n120\n.', 'An infrared light source \n124\n generates a beam of infrared radiation \n126\n that is directed into the crystal \n120\n such that it is incident on the interface of the crystal \n120\n and the liquid fluid of the sample \n122\n at an angle larger than the critical angle Θ\nc\n.', 'The critical angle is a function of the refractive indices of both the sample and the crystal and is given by Θ\nc\n=sin\n−1\n(η\nf\n/η\nc\n) where η\nc \nis the refractive index of the crystal \n120\n and η\nf \nis the refractive index of the sample \n122\n.', 'The internal reflection of the beam \n126\n can occur multiple times along the interface of the crystal \n120\n and the sample \n122\n.', 'The crystal \n120\n may be realized from a high refractive index material such as sapphire or diamond in order to minimize the critical angle.', 'In the regions of the infrared spectrum where the sample absorbs energy, the evanescent wave will be attenuated.', 'The crystal \n120\n directs the reflected beam \n130\n (including the attenuated energy from each evanescent wave) for supply to an IR detector \n132\n.', 'Signal processing circuitry \n134\n (e.g. amplifier and filter circuitry, and A/D conversion circuitry) processes the output of the IR detector \n132\n to measure and process the output of the IR detector \n132\n, thereby measuring the intensity of the detected light within the predetermined IR measurement bands as a function of time and generating digital data corresponding to such measurements.', 'In one embodiment, one or more predetermined IR measurement bands include a predetermined absorption band centered around 4.27 microns (e.g., 4.27 microns ±75 nanometers), a predetermined reference band centered around 4 microns (e.g., 4 microns ±75 nanometers), and a reference band centered around 3 microns (e.g., 3 microns ±75 nanometers).', 'In one embodiment, the reflected beam (including the attenuated evanescent waves) is guided by a lens \n136\n through an optical filter \n138\n to the IR detector \n132\n.', 'The optical filter \n138\n provides bandpass optical filtering for the predetermined infrared measurement (and reference) bands.', 'The IR detector \n132\n may include an array of IR detector elements corresponding to the predetermined infrared measurement bands.', 'Alternatively, a single IR detector element can be used.', 'In one embodiment, additional supporting electronics can be supplied in conjunction with the IR light sources \n124\n and IR detectors \n132\n.', 'The supporting electronics may be provided for each light source and each detector or may be shared by the light sources and by the detectors.', 'As seen in \nFIG.', '2\n such supporting electronics may include a data communication interface \n140\n, IR source driver circuitry \n142\n, control circuity \n144\n, and power circuitry \n146\n.', 'The data communications interface \n140\n may be electrically coupled to the signal processing circuitry \n134\n and may operate to communicate the digital data generated by the signal processing circuitry \n134\n (which represents the intensity of the detected light within the predetermined IR measurement band(s) as a function of time) to an external data processor \n160\n.', 'The data processor \n160\n processes the digital data as described in more detail below in order to determine the refractive index of the formation fluid sample.', 'The IR source driver circuitry \n142\n may generate electrical signals for supply to the IR light source \n124\n in order to operate the IR light source \n124\n as desired.', 'The control circuitry \n144\n may control operation of the electrical, optoelectrical and/or optical elements of the apparatus in accordance with commands communicated from the external data processor \n160\n to the control circuitry \n144\n via the communications interface \n140\n.', 'For example, the control circuitry \n144\n may interface to the IR source driver circuitry \n142\n to activate and control the operational mode of the IR light source \n124\n via commands issued by the external data processor \n160\n and communicated thereto via communications interface \n140\n.', 'The control circuitry \n144\n can carry out other control operations as desired.', 'The power circuitry \n146\n may receive power supply signals from an external power supply \n162\n and transform and/or condition these signals into a form suitable for supply to the electrical and opto-electrical elements of the apparatus.', 'The operation of the power circuitry \n146\n can include AC-DC conversion functions, DC-DC conversion functions, voltage regulation functions, current limiting functions, and other power conditioning functions well known in the arts.', 'In one aspect, the sensing crystal will be exposed to a high-pressure fluid, whereas the infrared source, detectors, and electronics may be isolated from the fluid.', 'Arrangements for accomplishing the same are described in co-owned U.S. Pat.', 'No. 9,500,583 which was previously incorporated by reference herein.', 'Turning now to \nFIG.', '3\na\n, one embodiment having two unalike crystals \n220\na\n, \n220\nb \nis seen.', 'The crystals \n220\na \nand \n220\nb \nare seen to be adjacent each other and along a flow line \n30\n.', 'In \nFIG.', '3\na\n, crystals \n220\na \nand \n220\nb \nhave different geometries.', 'By way of example only, crystal \n220\na \nis a sapphire ATR crystal having faces (exterior surfaces) that angle at 75° from the horizontal, whereas crystal \n220\nb \nis a sapphire ATR crystal having faces that angle at 65° from the horizontal.', 'When the crystals are in contact with formation fluids, both crystals are expected to have total internal reflection, with three reflections shown.', 'In the arrangement of \nFIG.', '3\na\n, the crystals are arranged such that fluid flowing through the flow line \n30\n (direction indicated by the arrow) will be first in contact with crystal \n220\na \nand then in contact with crystal \n220\nb\n.', 'Assuming that the fluid is generally homogeneous, measurements can be made simultaneously.', 'On the other hand, if it is assumed that the fluid is not homogeneous, the measurements can be made sequentially when it is expected that the same fluid is adjacent to the respective crystals.', 'In \nFIG.', '3\nb\n, another embodiment having two unalike crystals \n320\na\n, \n320\nb \nis seen.', 'Crystals \n320\na\n, \n320\nb \nare seen to face each other on opposite sides of fluid line \n30\n.', 'As seen in \nFIG.', '3\nb\n, crystals \n320\na \nand \n320\nb \nhave different geometries.', 'By way of example only, crystal \n320\na \nis a sapphire ATR crystal having faces (exterior surfaces) that angle at 75° from the horizontal, whereas crystal \n320\nb \nis a sapphire ATR crystal having faces that angle at 65° from the horizontal.', 'Because the crystals are arranged opposite each other with the fluid from the fluid line \n30\n passing therebetween, measurements involving the crystals can be made simultaneously.', 'In other embodiments, the unalike crystals may have identical geometries (angles of incidence), but may be made from different materials; i.e., the crystals have different refractive indices.', 'By way of example only, one crystal may be a sapphire crystal and the other crystal may be a diamond material.', 'In yet other embodiments, both the materials and the angles of incidence (geometry) of the unalike crystals may be different.', 'The geometry of each material may be optimized in order to maximize sensitivity to η\nf\n.', 'Within an expected range of η\nf\n, the configuration may be tailored so that the difference in the attenuation between the two crystals is maximized for the same wavelength λ and number of reflections N\nR\n.', 'With the unalike crystals, equation (4) can be rewritten with an index j which is used to refer to either\n \n \n \n \n \n \n \n \n \n \nd\n \npj\n \n \n=\n \n \nλ\n \n \n2\n \n\u2062\n \n \n \n \n\u2062\n \n \nΠη\n \ncj\n \n \n\u2062\n \n \n \n \n(\n \n \n \nsin\n \n2\n \n \n\u2062\n \n \nΘ\n \nj\n \n \n \n)\n \n \n\u2062\n \n \n \n(\n \n \nη\n \n/\n \n \nη\n \ncj\n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n8\n \n)\n \n \n \n \n \n \n \n where η\ncj \ndenotes the refractive index of crystal j, j=1, 2, . . .', 'and Θ\nj \nis the angle of incidence designed for each j.', 'With two crystals, using equation (8), a ratio of penetration depths can be expressed as \n \n \n \n \n \n \n \n \n \n \nd\n \n \np\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \nd\n \n \np\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n=\n \n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n\u2062\n \n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \nΘ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n)\n \n \n \n2\n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \nΘ\n \n2\n \n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n)\n \n \n \n2\n \n \n \n \n \n.', '(\n \n9\n \n)\n \n \n \n \n \n \n \n Using equations (5) and (6), and replacing d\np \nyields \n \n \n \n \n \n \n \n \n \n \n \nA\n \n2\n \n \n \nA\n \n1\n \n \n \n=\n \n \n \n \n \nK\n \n2\n \n \n\u2062\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n \n \nK\n \n1\n \n \n\u2062\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n \n\u2062\n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \nΘ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n)\n \n \n \n2\n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \nΘ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n)\n \n \n \n2\n \n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n10\n \n)\n \n \n \n \n \n \n \n (since N\nR \nis expected to be the same for both crystals), where A\n1 \nand A\n2 \nare attenuations for j=1, 2.', 'As a first approximation, it is assumed that K\n1\n=K\n2\n.', 'With that assumption, equation (10) may be used to find the index of refraction for the fluid η\nf\n, as the indices of refraction of the crystals η\nc1 \nand η\nc2 \nare known, the angles of incidence Θ\n1 \nand Θ\n2 \nare known, and the attenuations A\n1 \nand A\n2 \nare measured.', 'However, in certain embodiments, and as described in more detail hereinafter, the index of refraction for the fluid may be determined without the K\n1\n=K\n2 \napproximation.', 'For K\n1\n≠K\n2\n, the ratio of K\n2 \nto K\n1 \nmay be represented as\n \n \n \n \n \n \n \n \n \n \nK\n \n2\n \n \n \nK\n \n1\n \n \n \n=\n \n \n \nR\n \n\u2061\n \n \n(\n \n \n \n \nη\n \nf\n \n \n;\n \nΘ\n \n \n,\n \n \nη\n \nc\n \n \n \n)\n \n \n \n.', '(\n \n11\n \n)', "In order to construct the dependence of the function R on its arguments, it may be supposed that the true penetration depth is given by the average of the perpendicular and parallel polarized waves' effective path length (d\ne\n).", 'Explicit relationships for these are known and the mean value is used for unpolarized light.', 'Therefore d\ne\n/d\np \nmay be computed for various η\nf\n, η\nc\n, and Θ as long as conditions of ATR are met, i.e., a total reflection occurs assuming unpolarized light is used.', 'Otherwise, for polarized light, the components of parallel and perpendicular fields may be considered so as to compute the effective path length appropriately.', 'Now the ratio of the effective path length and the penetration depth is denoted D, with D=d\ne\n/d\np\n, and a refractive index range restricted between 1.325 to 1.475 is assumed, with the minimum η\nm\n=1.325 and the maximum η\nM\n=1.475.', 'This range by no means is restrictive, but is chosen based on commonly encountered values of aqueous fluids and oils.', 'It is easily extended to encompass a larger range.', 'An interesting computational result is that if one denotes as D\n0 \nfor D at a η\nf \nof 1.325, the ratio D\nn\n=D/D\n0 \nis nearly independent of Θ for diamond and sapphire, commonly used in ATR measurements.', 'This is true for 65°≤Θ≤75°.', 'Based on this normalization,\n \n \n \n \n \n \n \n \n \n \nD\n \nn\n \n \n=\n \n \n \nD\n \n \nD\n \n0\n \n \n \n=\n \n \n \n \nf\n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n;\n \n \nη\n \nc\n \n \n \n)', '\u2062\n \n \n \n \n\u2062\n \n65\n \n\u2062\n \n°\n \n \n≤\n \nΘ\n \n≤\n \n \n75\n \n\u2062\n \n°\n \n \n \n \n \n,\n \n \n \n \n \n(\n \n12\n \n)\n \n \n \n \n \n \n \n or f is independent of Θ for the angles of interest.', 'In one aspect, the dependence of the ratio on the refractive index of the crystal may also be removed through another normalization.', 'More particularly, a double normalized ratio is defined according to\n \n \n \n \n \n \n \n \n \nD\n \nnn\n \n \n=\n \n \n \n \nD\n \nn\n \n \n\u2061\n \n \n[\n \n \n1\n \n+\n \n \n \n(\n \n \n \n \nη\n \nc\n \n \n \nη\n \ns\n \n \n \n\u2062\n \n1\n \n \n)\n \n \n\u2062\n \n \n \n(\n \n \n \n \nη\n \nf\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n \nη\n \nM\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n)\n \n \n \n3\n \n/\n \n2\n \n \n \n \n \n]\n \n \n \n=\n \n \n \ng\n \n\u2061\n \n \n(\n \n \nη\n \nf\n \n \n)\n \n \n \n.', '(\n \n13\n \n)\n \n \n \n \n \n \n \n where η\ns \nis the refractive index of sapphire and η\nc \nis the refractive index of the crystal (diamond or sapphire) through which the measurement is made.', 'Equation (13) is consistent with the earlier statement that for sapphire, D\nn \nis nearly independent of Θ. Equation (13) may be considered important because g is a function of η\nf \nalone and shows little dependence on η\nc\n.', 'FIG.', '4\n demonstrates this inference.', 'Thus, given the known function g(η\nf\n) through calibration, or less accurately through \nFIG.', '4\n,\n \n \n \n \n \n \n \n \nD\n \n=\n \n \n \n \nD\n \nn\n \n \n\u2062\n \n \nD\n \n0\n \n \n \n=\n \n \n \nD\n \n0\n \n \n\u2062\n \n \n \n \ng\n \n\u2061\n \n \n(\n \n \nη\n \nf\n \n \n)', '[\n \n \n1\n \n+\n \n \n \n(\n \n \n \n \nη\n \nc\n \n \n \nη\n \ns\n \n \n \n\u2062\n \n1\n \n \n)\n \n \n\u2062\n \n \n \n(\n \n \n \n \nη\n \nf\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n \nη\n \nM\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n)\n \n \n \n3\n \n/\n \n2\n \n \n \n \n \n]\n \n \n \n.\n \n \n \n \n \n \n \n \n(\n \n14\n \n)\n \n \n \n \n \n \n \n Now, D\n0 \nis the depth of penetration at η\nf\n=1.325, a value that is known for a given η\nc \nand Θ, or D\n0 \nmay be written according to D\n0\n=h(η\nc\n,Θ).', 'Thus, D is now known from Equation (14) as a function η\nf\n.', 'The measurement of the refractive index of a formation fluid supposes that there are two crystals placed along the tubing or a pipe of a a borehole tool through which a fluid flows.', 'The purpose of the instrumentation is to find the refractive index of the fluid from which other determinations may be made (e.g., inferring a dissolved component concentration), but the component could alter the refractive index determination by its very presence.', 'As previously suggested, two different ATR crystals (either different Θ, or η\nc \nor both) are utilized, and an attenuation measurement is made on the same fluid so that A\n2\n/A\n1 \nis measured.', 'On the right hand side of Equation (10) the unknowns are η\nf \nand K\n2\n/K\n1\n.', 'In one embodiment, a premise is that D=d\ne\n/d\np\n≈l/d\np\n=K. Thus (see Eq. 9 and 10) the ratio of the D values are the same as that of K. Therefore,\n \n \n \n \n \n \n \n \n \n \n \nA\n \n1\n \n \n \nA\n \n2\n \n \n \n=\n \n \n \n \n \nK\n \n1\n \n \n\u2062\n \n \nd\n \n \np\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n \n \nK\n \n2\n \n \n\u2062\n \n \nd\n \n \np\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n \n=\n \n \n \n \n \nh\n \n\u2061\n \n \n(\n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n,\n \n \nΘ\n \n1\n \n \n \n)\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n+\n \n \n \n(\n \n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \nη\n \ns\n \n \n \n\u2062\n \n1\n \n \n)\n \n \n\u2062\n \n \n \n(\n \n \n \n \nη\n \nf\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n \nη\n \nM\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n)\n \n \n \n3\n \n/\n \n2\n \n \n \n \n \n]\n \n \n \n \n \nh\n \n\u2061\n \n \n(\n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n,\n \n \nΘ\n \n2\n \n \n \n)\n \n \n \n\u2061\n \n \n[\n \n \n1\n \n+\n \n \n \n(\n \n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \nη\n \ns\n \n \n \n\u2062\n \n1\n \n \n)\n \n \n\u2062\n \n \n \n(\n \n \n \n \nη\n \nf\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n \nη\n \nM\n \n \n\u2062\n \n \nη\n \nm\n \n \n \n \n)\n \n \n \n3\n \n/\n \n2\n \n \n \n \n \n]\n \n \n \n \n\u2062\n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n\u2062\n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \nΘ\n \n2\n \n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n)\n \n \n \n2\n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \n \n \nΘ\n \n1\n \n \n\u2061\n \n \n(\n \n \n \nη\n \nf\n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n \n)\n \n \n \n2\n \n \n \n \n \n \n \n \n,\n \n \n \n \n \n(\n \n15\n \n)\n \n \n \n \n \n \n \n where η\ns \nis the known refractive index of sapphire, and the right hand side is a function of η\nf \nfor given geometries of the crystal and its material.', 'Therefore, from the ratio of A\n1 \nto A\n2\n, η\nf \nis obtained by inverting Equation (15), since η\nc \nand Θ are known for the crystals.', 'Note that g(η\nf\n) does not appear in the ratio.', 'Though the inferences are based on the assumption of l being approximately the same as d\ne\n, this is by no means restrictive.', 'It is possible to take several different solvents whose refractive indices are known and are within the range of interest, dissolve the component whose concentration is desired to a small value, and measure attenuation.', 'This in turn allows knowledge of the path length or K.', 'It is then a matter of constructing a suitable function h(η\nc\n, Θ) and g(η\nf\n) from the measured data.', 'The purpose of knowing g(η\nf\n) is to confirm that such a function is possible, although it is not used in the ratio evaluation.', 'Note that for the case of K being a constant, D\nn\n=1 and D\nnn\n=1.', 'The depth of penetration from an attenuation point of view is simply proportional to d\np\n.', 'Regardless, the calibration allows a determination of the characteristics of K.\n \nEmbodiments of methods utilizing the disclosed apparatus are understood with reference to \nFIG.', '5\n.', 'More particularly, at \n500\n, a borehole tool having a fluid admitting assembly, a flow line, two unalike crystals in contact with the flow line, at least one light source, and light detectors and associated signal processing circuitry is placed downhole in a formation.', 'At \n510\n, the fluid admitting assembly of the borehole tool is moved into contact with the formation at a location of interest.', 'At \n520\n, the borehole tool is activated to cause formation fluid to flow into the flow line of the borehole tool (e.g., by dropping the pressure in the flow line below the formation pressure).', 'At \n530\n, light (e.g., IR rays) from the light source(s) is directed simultaneously or sequentially into the unalike crystals and detected by the detectors.', 'At \n540\n, the detected light at each detector is compared to an unattenuated light value for the light source associated with that detector in order to obtain attenuation values (e.g., A\n1 \nand A\n2\n).', 'At \n550\n, a ratio of the attenuation values is used to determine the refractive index of the fluid flowing through the flow line.', 'The refractive index of the fluid may be determined using an equation such as equation (10) or equation (15).', 'In either case, known or measurable values such as the refractive indices of the crystals and the angles of incidence of the crystals are utilized, it being understood and appreciated that the crystals are provided with either different refractive indices and/or with different angles of incidence.', 'In the case of equation (15), additional known values provided including minimum and maximum values for crystal refractive indices.', 'At \n560\n, the determined refractive index of the formation fluid is optionally used in conjunction with other information to provide additional determinations regarding the fluid and/or formation.', 'For example, having obtained a measure of dissolved carbon dioxide for a fluid with a known refractive index, equation (15) may now be modified and utilized to convert a measured attenuation to the attenuation that would have been obtained for the refractive index for which the calibration has been carried out.', 'More particularly, and according to one aspect, a dissolved component concentration of a gas such as CO\n2 \nmay be measured as follows.', 'First, a calibration for dissolved CO\n2 \nis made with a solvent-solute mixture for which the refractive index is η\nf1\n.', 'Using the methodology already described, the fluid refractive index η\n2 \nfor which the dissolved concentration is desired is obtained.', 'The attenuation A\n2 \nis known, but in order to infer the concentration of the dissolved component, the calibration curve known for a fluid refractive index η\nf1 \nis used.', 'Then, the attenuation obtained with η\nf2 \nis shifted to an attenuation that would have been obtained had the fluid been one of refractive index Rewriting Eq. 15 with a crystal of η\nc2 \nand Θ\n2\n, but for fluids of refractive index and η\nf2\n, the following is obtained:\n \n \n \n \n \n \n \n \n \n \nA\n \n1\n \n \n \nA\n \n2\n \n \n \n=\n \n \n \n \ng\n \n\u2061\n \n \n(\n \n \nη\n \n \nf\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n)\n \n \n \n \ng\n \n\u2061\n \n \n(\n \n \nη\n \n \nf\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n)\n \n \n \n \n\u2062\n \n \n \n[\n \n \n1\n \n+\n \n \n \n(\n \n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \nη\n \ns\n \n \n \n-\n \n1\n \n \n)\n \n \n\u2062\n \n \n \n(\n \n \n \n \nη\n \n \nf\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n-\n \n \nη\n \nm\n \n \n \n \n \nη\n \nM\n \n \n-\n \n \nη\n \nm\n \n \n \n \n)\n \n \n \n3\n \n/\n \n2\n \n \n \n \n \n]\n \n \n \n[\n \n \n1\n \n+\n \n \n \n(\n \n \n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \nη\n \ns\n \n \n \n-\n \n1\n \n \n)\n \n \n\u2062\n \n \n \n(\n \n \n \n \nη\n \n \nf\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n-\n \n \nη\n \nm\n \n \n \n \n \nη\n \nM\n \n \n-\n \n \nη\n \nm\n \n \n \n \n)\n \n \n \n3\n \n/\n \n2\n \n \n \n \n \n]\n \n \n \n\u2062\n \n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \nθ\n \n2\n \n \n \n-\n \n \n \n(\n \n \n \nη\n \n \nf\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n)\n \n \n2\n \n \n \n \n \n \nsin\n \n2\n \n \n\u2062\n \n \nθ\n \n2\n \n \n \n-\n \n \n \n(\n \n \n \nη\n \n \nf\n \n\u2062\n \n \n \n \n\u2062\n \n1\n \n \n \n/\n \n \nη\n \n \nc\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n \n \n \n)\n \n \n2\n \n \n \n \n \n \n \n \n \n \n(\n \n16\n \n)', 'Knowing A\n1 \nfrom the above equation from a measured A\n2 \nthus allows the use of the calibration curve corresponding to a fluid of calibration of η\nf2\n.', 'In one aspect, some of the methods and processes described above, such as calculating the attenuation values and calculating the refractive index of the formation fluid are performed by a processor.', 'The term “processor” should not be construed to limit the embodiments disclosed herein to any particular device type or system.', 'The processor may include a computer system.', 'The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing any of the methods and processes described above.', 'The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.', 'Some of the methods and processes described above, can be implemented as computer program logic for use with the computer processor.', 'The computer program logic may be embodied in various forms, including a source code form or a computer executable form.', 'Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as FORTRAN, C, C++, Python, or JAVA).', 'Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor.', 'The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).', 'Alternatively or additionally, the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)).', 'Any of the methods and processes described above can be implemented using such logic devices.', 'Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples without materially departing from this subject disclosure.', 'Thus, by way of example only, and not by way of limitation, while various embodiments describe the use of two unalike crystals, more than two unalike crystals may be utilized.', 'Also, while sapphire and diamond were described for use as crystals, it will be appreciated that other materials could be used.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A borehole apparatus for determining the refractive index of a fluid, comprising:', 'A 1 A 2 = K 1 \u2062 d p \u2062 \u2062', '1', 'K 2 \u2062 d', 'p \u2062 \u2062 2', '= h \u2061 ( η c \u2062 \u2062 1, Θ 1 )', '\u2061 [ 1 + ( η c \u2062 \u2062 2 η s \u2062 1 )', '\u2062 ( η f \u2062 η m η M \u2062 η m )', '3 / 2 ] h \u2061', '( η c \u2062 \u2062 2, Θ 2 )', '\u2061 [ 1 + ( η c \u2062 \u2062 1 η s \u2062 1 )', '\u2062 ( η f \u2062 η m η M \u2062 η m )', '3 / 2 ] \u2062', 'η c \u2062 \u2062', '2', 'η c \u2062 \u2062', '1', '\u2062 sin 2 \u2062 Θ 2 \u2061 ( η f / η', 'c \u2062 \u2062 2 ) 2 sin 2 \u2062 Θ 1 \u2061 ( η f / η', 'c \u2062 \u2062 1 ) 2, wherein A1 is the attenuation of said first crystal and A2 is the attenuation of said second crystal, respectively, ηf is said refractive index of the fluid,', 'ηc1 is the refractive index of said first crystal, ηc2 is the refractive index of said second crystal, Θ1 is the angle of incidence of said first crystal, Θ2 is the angle of incidence of said second crystal, ηM is a maximum refractive index value for said first and second crystals and is equal to 1.475 and ηm is a minimum refractive index value for said first and second crystals and is equal to 1.325, and ηs is a refractive index of a reference crystal material.', 'an elongate body having a fluid admitting assembly and a fluid flow line configured to receive the fluid;\na first crystal and a second crystal each having a face configured to be in contact with the fluid in the fluid flow line, wherein said first and second crystals have different refractive indices, different angles of incidence, or different refractive indices and different angles of incidence with respect to one another;\nat least one light source coupled to said first and second crystals and configured to direct light into said first and second crystals, said light having at least one wavelength, and said wavelength, said refractive indices and said angles of incidence being chosen such that said light undergoes total internal reflection at interfaces between said first and second crystals and the fluid;\nat least one light detector coupled to said first and second crystals configured to measure the reflected light exiting said crystals; and\na processor coupled to said at least one light detector, said processor configured to determine attenuations of said light entering said crystals and configured to determine said refractive index of the fluid utilizing said attenuations, said refractive indices, and said angles of incidence of said crystals, wherein said refractive index is determined according to:\n\n\n\n\n\n\n2.', 'The borehole apparatus of claim 1, wherein the reference crystal material is sapphire.', '3.', 'The borehole apparatus of claim 1, wherein one of said first crystal and said second crystal is a sapphire crystal, and the other of said first crystal and said second crystal is a diamond crystal.', '4.', 'The borehole apparatus of claim 1, wherein said first crystal and said second crystal have different angles of incidence, and both said first crystal and said second crystal have an angle of incidence between 65° and 75°.', '5.', 'The borehole apparatus of claim 1, wherein said first and second crystals are adjacent each other on one side of said fluid flow line.', '6.', 'The borehole apparatus of claim 1, wherein said first and second crystals face each other on opposite sides of said fluid flow line.', '7.', 'A method for determining the refractive index of a fluid, comprising: A 1 A 2 = K 1 \u2062 d p \u2062 \u2062 1', 'K 2 \u2062 d', 'p \u2062 \u2062 2', '= h \u2061 ( η c \u2062 \u2062 1, Θ 1 )', '\u2061 [ 1 + ( η c \u2062 \u2062 2 η s \u2062 1 )', '\u2062 ( η f \u2062 η m η M \u2062 η m )', '3 / 2 ] h \u2061', '( η c \u2062 \u2062 2, Θ 2 )', '\u2061 [ 1 + ( η c \u2062 \u2062 1 η s \u2062 1 )', '\u2062 ( η f \u2062 η m η M \u2062 η m )', '3 / 2 ] \u2062', 'η c \u2062 \u2062', '2', 'η c \u2062 \u2062', '1', '\u2062 sin 2 \u2062 Θ 2 \u2061 ( η f / η', 'c \u2062 \u2062 2 ) 2 sin 2 \u2062 Θ 1 \u2061 ( η f / η', 'c \u2062 \u2062 1 ) 2, wherein A1 is the attenuation value of said first crystal and A2 is the attenuation value of said second crystal, ηf is said refractive index of the fluid,', 'ηc1 is the refractive index of said first crystal, ηc2 is the refractive index of the second crystal, Θ1 is the angle of incidence of said first crystal, and Θ2 is the angle of incidence of said second crystal, ηM is a maximum refractive index value for said first and second crystals and equal to 1.475 and ηm is a minimum refractive index value for said first and second crystals and is equal to 1.325, and ηs is a refractive index of a reference crystal material.', 'placing into a borehole traversing a formation a borehole tool having a fluid admitting assembly, a flow line, a first crystal and a second crystal each in contact with the fluid in the flow line, at least one light source, at least one light detector having signal processing circuitry associated therewith, and a processor, wherein said first and second crystals have different refractive indices, different angles of incidence, or different refractive indices and different angles of incidence with respect to one another;\nmoving the fluid admitting assembly of the borehole tool into contact with the formation at a location of interest in the formation;\ncausing formation fluid to flow into the flow line of the borehole tool and into contact with said first and second crystals;\ndirecting light from the at least one light source into said first and second crystals, and\ndetecting with the at least one light detector the light exiting the crystals, said crystals and said light source having been chosen such that said light will undergo total internal reflection at interfaces between said crystals and said fluid;\nusing the signal processing circuitry associated with the at least one light detector to compare the exiting light to an unattenuated light value for the light source associated with the at least one detector in order to obtain attenuation values; and\ndetermining with the processor the refractive index of the fluid flowing through the flow line using the attenuation values, the refractive indices, and the angles of incidence of said crystals, wherein the refractive index is determined according to:\n\n\n\n\n\n\n8.', 'The method of claim 7, wherein the reference crystal material is sapphire.', '9.', 'The method of claim 7, wherein one of said first crystal and said second crystal is a sapphire crystal, and the other of said first crystal and said second crystal is a diamond crystal.', '10.', 'The method of claim 7, wherein said first crystal and said second crystal have different angles of incidence, and both said first crystal and said second crystal have an angle of incidence between 65° and 75°.', '11.', 'The method of claim 7, wherein said first and second crystals are adjacent each other on one side of said fluid flow line.', '12.', 'The method of claim 7, wherein said first and second crystals face each other on opposite sides of said fluid flow line.'] | ['FIG.', '1 is a schematic diagram of an apparatus for downhole determination of the refractive index of a formation fluid.;', 'FIG. 2 is a partial block, partial schematic diagram of elements of the apparatus of FIG.', '1.; FIGS.', '3a and 3b are schematic diagrams showing crystals arranged relative to a flow line.; FIG.', '4 is a plot of a double normalized function for the effective path length for diamond and sapphire.; FIG.', '5 is a flow chart of a method of determining a refractive index of a formation fluid.'] |
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US11086282 | Interface for automation client | Mar 6, 2020 | Clinton D. Chapman, Han Yu, Mbaga Louis Ahorukomeye | Schlumberger Technology Corporation | NPL References not found. | 3893525; July 1975; Dower et al.; 4814968; March 21, 1989; Fukumoto; 5522459; June 4, 1996; Padgett et al.; 20030129052; July 10, 2003; Johnson; 20040128000; July 1, 2004; Phillips et al.; 20070276545; November 29, 2007; Smirnov; 20080059038; March 6, 2008; Yoshida et al.; 20100305718; December 2, 2010; Clark et al.; 20110071960; March 24, 2011; Singh; 20110303462; December 15, 2011; Lovorn et al.; 20130282150; October 24, 2013; Panther et al. | 1898077; March 2008; EP; 9410613; May 1994; WO | ['Automation agents are utilized to modify operating characteristics of a client, such as a piece of equipment.', 'An operating characteristic of equipment can be selectively adjusted by modification of a set point value, which is associated with the operating characteristic of the equipment.', 'The equipment can adjust the operating characteristic based upon the set point value.', 'A remote control indication can be provided to indicate when a set point value is available for modification.', 'The remote control indication is adjustable by an execution module associated with the equipment.', 'A set point latch can be provided for indicating when the set point value is modifiable by an automation agent.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThis application claims priority to U.S. Provisional Patent Application Ser.', 'No. 61/805,890 filed Mar. 27, 2013 and PCT Application PCT/US204/031641 filed Mar. 25, 2014 and claims priority to and is a continuation of U.S. patent application Ser.', 'No. 14/763,518, titled “INTERFACE FOR AUTOMATION CLIENT,” filed Jul. 26, 2015.', 'The entire disclosures of all three applications are hereby incorporated herein by reference.', 'BACKGROUND\n \nIndustrial and process control systems include various types of control equipment used in industrial production, such as Supervisory Control and Data Acquisition (SCADA) systems, Distributed Control Systems (DCS), and other control equipment using, for example, Programmable Logic Controllers (PLC).', 'These control systems can be used in industries including electrical, water, oil, gas, and data.', 'Using information collected from remote stations in the field, automated and/or operator-driven supervisory commands can be transmitted to field control devices.', 'These field devices control local operations, such as opening and closing valves and breakers, collecting data from sensor systems, and monitoring a local environment for alarm conditions.', 'For example, in the oil and gas industry, oil wells are created by drilling a hole into the earth utilizing a drilling rig that rotates a drill string (e.g., drill pipe) having a drill bit attached thereto.', 'The drill bit, aided by the weight of pipes (e.g., drill collars) cuts into rock within the earth.', 'Drilling fluid (e.g., mud) is pumped into the drill pipe and exits at the drill bit.', 'The drilling fluid may be utilized to cool the bit and lift rock cuttings to the surface.', 'During such drilling operations, a drilling apparatus can be controlled manually, automatically, and various combinations thereof to provide effective operations.', 'For example, some operations are controlled manually and other operations are controlled automatically.', 'SUMMARY\n \nAspects of the disclosure can relate to a method for facilitating automation of equipment, such as industrial equipment.', 'The method may include selectively adjusting an operating characteristic of equipment by an exposed set point value, which is associated with the operating characteristic of the equipment.', 'The method may also include providing a remote control indication for indicating when a set point value is available for modification.', 'The remote control indication can be adjusted by an execution module associated with the equipment.', 'The method also includes providing a set point latch that represents a value for indicating when the set point value is modifiable by an automation agent.', 'The automation agent can automatically adjust the operating characteristic by modification of the set point value when the set point latch is latched.', 'Other aspects of the disclosure can relate to a computing device for facilitating automation of equipment.', 'The computing device may selectively adjust an operating characteristic of the equipment by modification of a set point value, which is associated with the operating characteristic of the equipment.', 'The computing device can provide a remote control indication for indicating when a set point value is available for modification and provide a set point latch for indicating when the set point value is modifiable by an automation agent.', 'The automation agent can automatically adjust the operating characteristic by modification of the set point value when the set point latch is latched.', 'Also, aspects of the disclosure can relate to a system for facilitating automation of equipment.', 'The system includes equipment having a memory for storing a set point value associated with an operating characteristic of the equipment.', 'The equipment is operable to adjust the operating characteristic based upon the set point value.', 'The system also includes an automation agent for automatically adjust the operating characteristic by modification of the set point value.', 'The set point latch indicates when the set point value is to be modified by the automation agent.', 'The system also includes an execution module connected with the equipment to selectively adjusting the operating characteristic by the modification of the set point value.', 'The equipment may apply the set point value when the set point latch is latched and the set point value is available for remote control as indicated by a remote control indication.', 'This Summary is provided to introduce a selection of concepts in a simplified form that are further described below in the Detailed Description.', 'This Summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE FIGURES', 'The Detailed Description is described with reference to the accompanying figures.', 'The use of the same reference numbers in different instances in the description and the figures may indicate similar or identical items.\n \nFIG.', '1\n is a diagrammatic illustration of a block diagram of a computing device for facilitating automation of equipment (e.g., a client) in accordance with an example embodiment of the present disclosure, where the computing device includes a control module that is communicatively connected to the equipment.\n \nFIG.', '2\n is a block diagram illustrating a communication interface between the computing device and the equipment in accordance with an example embodiment of the present disclosure.', 'FIG.', '3\n is a state diagram illustrating logic for facilitating transfer of control between a control module and an automation agent deployed on the equipment in accordance with an example embodiment of the present disclosure.', 'FIGS.', '4 and 5\n illustrate flow charts for furnishing control from a control module to a deployable automation agent in accordance with an example embodiment of the present disclosure.', 'FIGS.', '6 and 7\n illustrate flow charts furnishing a manual control indication to force an automation agent to transition control from the deployable automation agent to the control module in accordance with an example embodiment of the present disclosure.', 'FIGS.', '8 and 9\n illustrate flow charts for releasing control from a deployable automation agent to the control module in accordance with an example embodiment of the present disclosure.', 'FIGS.', '10 and 11\n illustrate flow charts for controlling a current value that has been already latched by a deployable automation agent in accordance with an example embodiment of the present disclosure.', 'FIGS.', '12 and 13\n illustrate flow charts for using a recommended fail-safe set point in the event that a communication failure occurs.', 'DETAILED DESCRIPTION\n \nReferring generally to \nFIGS.', '1 through 13\n, a system for facilitating automation of equipment, such as industrial equipment, is described.', 'The system includes equipment (e.g., one or more clients) and a control module configured to control (e.g., remotely control) the equipment.', 'For example, the system comprises an industrial or process control system that can automate an oil and gas process, or a portion of an oil and gas process.', 'In embodiments of the disclosure, an oil and gas process can be considered to be an industrial process related to the oil and gas industry and at least partially performing physical activities using one or more process components.', 'Process components can be considered to be controllable hardware and/or software entities that implement a physical oil and gas process (e.g., drilling rig equipment, machines and devices, and any hardware/software controllers).', 'Other processes associated with the oil and gas industry, including other processes associated with drilling production or related activities, can also utilize the techniques described herein.', 'However, the oil and gas industry is provided by way of example only and is not meant to limit the present disclosure.', 'The techniques described herein can be used in other industrial and automation process control system settings, including, but not necessarily limited to: manufacturing, production, power generation, fabrication, refining, water and wastewater, electrical power transmission and distribution, wind farms, large communication systems, chemical, pharmaceutical, food and beverage, pulp and paper, mining, metals, and so forth.', 'In addition, in embodiments of the disclosure, an automation system can be considered to be a software and/or hardware environment that hosts one or more state machines and provides an interface to permit agents, the state machine or the automation system to receive data from external sensors and data acquisition hardware/software associated with a process, and to send commands or otherwise control process components to perform a process according to a control algorithm.', 'An agent, in embodiments of the disclosure, can be considered to be a software process that runs independently with some degree of autonomy, and that interacts with process components, controllers and/or an intermediate service, such as an automation system, that provides access to the process components and/or the controllers.', 'As disclosed herein, the agents may comprise deployable agents that facilitate a communication interface utilized to provide set point values and possibly corresponding fail-safe set point values to furnish functionality to control a particular piece of equipment.', 'For example, a Boolean flag for a mud pump may be transitioned from a false Boolean value to a true Boolean value to indicate that remote automation control is possible to a deployable agent associated with the mud pump.', 'Once the automation agent receives the indication that remote control is possible, the automation agent may adjust one or more operating characteristics (e.g., a mud flow rate) of the mud pump by modifying one or more set point values and a possibly corresponding fail-safe set point and then set a corresponding set point latch to indicate to the equipment controller that it should use the specified set point exposed by the equipment controller.', 'This can allow other, non-specified, set points that are not used by the automation agents to still be controllable by an operator.', 'For instance, the mud flow rate of the mud pump may be controlled by the automation agent while the set point latch is set to a true Boolean value, and the operator may control one or more other operating characteristics of the mud pump such as transmission gear.', 'The operating characteristic may comprise any controllable value associated with an equipment control module \n112\n, \n116\n.', 'For example, the operating characteristic may comprise, but is not limited to, a revolution per minute value, a throttle position, a maximum torque, direction, and/or an automation routine whose functionality is associated with the equipment control module \n112\n, \n116\n.', 'Further, in some embodiments, the operator can also control other operating characteristics that are not currently under control by an external agent.', 'The equipment controlled by an equipment control module \n112\n, \n116\n may comprise, but is not limited to, a mud pump, a hoist, a rotary device, a choke, a valve, an alarm device, a blowout preventer (BOP), an auto-driller or the like.', 'Recommended fail-safe set point values can be utilized as set point values such that in an operating state causing a fail-safe condition (e.g., a communication loss), the equipment can transition to a predetermined safe state which can vary depending upon the operation being executed by the deployable agent.', 'For the purposes of the present disclosure, the term “fail-safe state” is used to refer to a state that is more stable than a previous state the equipment was operating at before implementing the “fail-safe state.”', 'For instance, during a communication loss, the deployable agent may automatically adjust an operating characteristic such as a number of revolutions per minute (RPM) based upon a corresponding fail safe set point value.', 'In this example, the deployable agent can reduce the number of RPMs.\n \nFIG.', '1\n illustrates example apparatus \n100\n, such as a drilling rig, or the like, that includes a computing device \n101\n in which a control system can be implemented.', 'The computing device \n101\n is illustrated as including one or more computers having a central processing unit \n108\n including at least one hardware-based microprocessor coupled to a memory \n107\n, which can represent the random access memory (RAM) devices that includes the main storage of computing device \n101\n, as well as any supplemental levels of memory, e.g., cache memories, non-volatile or backup memories (e.g., programmable or flash memories), read-only memories, etc.', 'In addition, the memory \n107\n can be considered to include memory storage physically located elsewhere in computing device \n101\n, e.g., any cache memory in a microprocessor, as well as any storage capacity used as a virtual memory, e.g., as stored on a mass storage device \n106\n or on another computer coupled to computing device \n101\n.', 'Computing device \n101\n may receive a number of inputs and outputs for communicating information externally and stores information internally within the memory \n107\n.', 'For interfacing with a user or operator, computing device \n101\n may include a user interface \n102\n incorporating one or more user input devices (e.g., a keyboard, a pointing device, a display, a printer, etc.).', 'Otherwise, user input can be received via another computer or terminal (e.g., over a network interface \n103\n, \n104\n coupled to a network, such as networks \n105\n, \n106\n).', 'Computing device \n101\n also can be in communication with one or more mass storage devices \n106\n, which can be, for example, internal hard disk storage devices, external hard disk storage devices, storage area network devices, etc.', 'In this embodiment, computing device \n101\n additionally serves as a secure bridge between a deterministic network \n105\n and a non-deterministic network \n106\n.', 'Deterministic network can have coupled thereto one or more clients \n109\n, real time data stores \n110\n, sensors \n111\n-\n1\n, actuator \n111\n-\n2\n and equipment control module \n112\n.', 'Likewise, non-deterministic network can have coupled thereto one or more clients \n113\n, real time data stores \n114\n, sensors \n115\n-\n1\n, actuator \n115\n-\n2\n, and equipment control module \n116\n.', 'Clients \n109\n, \n113\n in this regard can be considered to be clients of the computing device \n101\n (e.g., drilling equipment, etc.), while real time data stores \n110\n, \n114\n can be considered to be any data store in which data related to a particular oil and gas process is collected and made accessible to the automation system.', 'For example, the clients \n109\n, \n113\n may comprise equipment, such as drilling equipment, that is communicatively connected to the computing device \n101\n through a respective network \n105\n, \n106\n.', 'The sensors \n111\n-\n1\n, \n115\n-\n1\n can be considered to include any sensors used to collect (e.g., measure) data related to a particular oil and gas process, while equipment controller modules \n112\n, \n116\n can be considered to include any controller, such as a programmable logic controller (PLC) or supervisory control and data acquisition (SCADA) system utilized to perform the control of one or more pieces of equipment (e.g., for a drilling automation system, controllers that provide control over equipment related to managed pressure drilling service, an autodriller, downlink system, a controller to control an operation characteristic of the drilling equipment, etc.).', 'The deterministic network \n105\n can be implemented, for example, as a computer connected to a communication interface (e.g., a Profibus communication interface), and additionally can be coupled to one or more process components for which it is desirable to control in an oil and gas process, e.g., one or more equipment control modules \n112\n (e.g., various programmable logic controllers (PLCs) and supervisory control and data acquisition (SCADA)-connected hardware systems).', 'Computing device \n101\n may operate under the control of an operating system \n117\n and executes or otherwise relies upon various computer software applications, components, programs, objects, modules, data structures, etc., (e.g., an automation server, also referred to herein as an execution module \n118\n).', 'The execution module \n118\n provides a communication interface for remote control \n119\n to the deterministic network \n105\n from the non-deterministic network \n106\n (e.g., a transmission control protocol/internet protocol network), and thus restricts access to deterministic network \n105\n, and to the rig control, to authorized entities and systems.', 'In addition, in some embodiments, equipment control modules \n112\n, \n116\n can also be considered to function as process components for the purpose of controlling an oil and gas process.', 'Further, in some embodiments another device coupled to a non-deterministic network \n106\n can be used as a gateway between computing device \n101\n and deterministic network \n105\n.', 'The execution module \n118\n implements the communication interface for remote control \n119\n using technologies such as Object Linking and Embedding (OLE) for Process Control (OPC).', 'An agent \n120\n, \n121\n communicates to the communication interface for remote control \n119\n using a compatible protocol that can be implemented for various operating systems, programming language, software platforms and/or hardware platforms, thereby enabling agents to be implemented in any suitable software and/or hardware environment.', 'For example, an agent can be resident on a laptop computer or a mobile device such that, when the computer or mobile device connects to a common network with the execution module \n118\n, the agent \n120\n, \n121\n is automatically connected to the execution module \n118\n.', 'As shown in \nFIG.', '1\n, the execution module \n118\n can include a number of software components, including, for example, a connection manager \n123\n and a logger \n124\n.', 'The connection manager \n123\n handles the connection and communication with the agents \n120\n, \n121\n.', 'The logger \n124\n creates, saves, and provides access to a log of transactions within or with the execution module \n118\n.', 'FIG.', '2\n illustrates an example communication interface for remote control \n119\n between a computing device \n101\n and an agent \n120\n, \n121\n.', 'A control state machine adapter \n201\n can be utilized within an agent (agent \n120\n, \n121\n) to allow a greater resolution of the remote control state for the particular equipment desired to be controlled via the communication interface for remote control \n119\n.', 'In an embodiment of the present disclosure, the system \n100\n establishes a communication interface with one or more of the agents \n120\n, \n121\n.', 'The agents \n120\n, \n121\n have memory associated therewith to store a set point value corresponding to an operating characteristic of the agent \n120\n, \n121\n.', 'For example, the set point value may represent a torque value that causes a respective equipment control module \n112\n, \n116\n to operate the drilling equipment at least at approximately a torque value.', 'In another example, the set point value may represent a mud flow rate of a mud pump that causes the equipment control module \n112\n, \n116\n to operate the mud pump at least at approximately a mud flow rate.', 'The communication interface for remote control \n119\n provides an interface for allowing an agent \n120\n, \n121\n to determine a sub-set of operating characteristics are available for remote control.', 'An example of this interface is provided in \nFIG.', '2\n as RC_READY, which comprises a Boolean value.', 'For a particular operating characteristic of equipment, the communication interface for remote control \n119\n provides an interface that allows an agent \n120\n, \n121\n the ability to provide a set point; to provide a recommended set point to use in the event communication is lost, herein referred to as a fail-safe set point; an associated latch value that allows a particular set point and recommend fail-safe set point to be used remote control; and the current set point value used by the system.', 'An example of these four values (or points) in \nFIG.', '2\n are, respectively, RPM_SP, RPM_SP_FS, RPM_SP_LATCH, and RPM_SP_CV.', 'The set point latch can be represented by a Boolean value, which is set to ‘true’ by the agent \n120\n, \n121\n when the agent is allowed remote control (RC_READY in \nFIG.', '2\n example) to indicate to the execution module \n118\n that the current and future values for set point are to be used for the operating characteristic set point until the set point latch is set to ‘false’, or a fail-safe event occurs (e.g., communication is lost).', 'In one or more embodiments, the computing device \n101\n may provide a user interface \n102\n that provides the operator the ability to allow for remote control.', 'If an operator indicates that a sub-set of operating characteristics are available for remote control, then an associated indication can be provided to agent \n120\n, \n121\n.', 'In one or more embodiments, the computing device \n101\n includes a control availability module \n125\n.', 'The control availability module \n125\n represents functionality to determine when it is appropriate to receive remote commands.', 'If the control availability module \n125\n detects that a sub-set of operating characteristics are available for remote control, then an associated indication can be provided to agent \n120\n, \n121\n.', 'In one or more embodiments, the adapter \n201\n, and respective agent \n120\n, \n121\n may include state machine logic.', 'The change in state within the state machine of the adapter \n201\n allows the agent \n120\n, \n121\n to determine the current condition of the remote control readiness of the equipment controlled through computing device \n101\n and exposed by the communication interface for communication interface for remote control \n119\n.\n \nFIG.', '3\n generally illustrates a state machine representing logic for facilitating transfer of control to an agent \n120\n, \n121\n, where set point latches are used to transition between local control of the industrial system to remote control by agent.\n \nFIGS.', '4 and 5\n illustrate an example flow chart \n400\n for furnishing (e.g., providing) control from the control module to a respective agent.', 'In one or more embodiments, the computing device \n101\n may present a user interface (e.g., user interface \n102\n) to an operator of a drill rig to indicate that remote control is allowed.', 'The operator of a drill rig can allow remote control for each operating characteristic or a sub-set of operating characteristics for the rig via the user interface, such as user interface \n102\n (Block \n402\n).', 'As shown in \nFIG.', '4\n, a remote control indication is received (Block \n404\n) by an agent.', 'For example, the agents \n120\n, \n121\n receive a remote control indication.', 'The respective agent \n120\n, \n121\n indicates to the adapter \n201\n, which has implemented the state machine logic shown in \nFIG.', '3\n, to go to starting by setting CONTROL_SP to ‘true’.', 'The state machine logic in \nFIG.', '3\n transitions from ‘0—OFF’ to ‘2—Starting’ when both CONTROL_SP is ‘true’ and RC_READY is ‘true’.', 'As shown in \nFIG.', '4\n, the adapter may perform a set of checks (Block \n410\n) to determine whether an agent has provided appropriate set point and fail-safe set point values and whether the drill rig is in the proper state by examining values exposed in the communication interface for remote control \n119\n.', 'For example, the adapter \n201\n may determine whether an agent \n120\n, \n121\n has provided appropriate set point and fail-safe set point values and whether the apparatus \n100\n is in a proper state by examining values exposed via the communication interface for remote control \n119\n.', 'The adapter \n201\n may also utilize contextual, historical, and/or real-time data values in determining the agent \n120\n, \n121\n has provided the appropriate set point and fail-safe set point values (and whether the apparatus \n100\n is in the proper state).', 'When the set of checks pass, the adapter latches (sets to ‘true’) associated set point latches, and the execution module, such as the execution module \n118\n, utilizes set points and any future values of the set points from the agent (Block \n412\n).', 'At this point, the adapter \n201\n advances the state machine to ‘1—ON’ as shown in \nFIG.', '3\n.', 'This state condition may continue until CONTROL_SP=false (e.g., transitioning the state machine logic to ‘3—Stopping’) or a fail-safe event is detected (e.g., communication is lost).', 'If a fail-safe event is detected the state machine logic is transitioned to ‘−2—Exception’ and the fail-safe set point value is utilized.', 'In some embodiments, a forced manual control may be implemented, which transitions the state machine logic to ‘−1—Forced Manual’.', 'If the set of checks failed, the adapter \n201\n transitions the state machine shown in \nFIG.', '3\n to ‘−2—Exception’.', 'If the state machine is in the states ‘2—Starting’, ‘1—ON’, or ‘3—Stopping’ and remote control is revoked, the state machine transitions to ‘−1—Forced Manual’, indicating to agent \n120\n, \n121\n that remote control has been revoked.', 'The remote control operability may be revoked by the operator or by a forced unlatch of a respective latch utilized by the agent \n120\n, \n121\n.', 'If the state machine is in the states ‘2—Starting’, ‘1—ON’, or ‘3—Stopping’ and there is a communication loss between the communication interface for remote control \n119\n and the agent \n120\n, \n121\n, the state machine logic advances to ‘−2—Exception’.', 'The execution module \n118\n can use the recommended fail-safe set points if another set point value has not been preset.', 'In embodiments, a remote control ready having a true Boolean value can indicate to an automation agent \n120\n, \n121\n that one or more set point values are available for remote control.', 'As shown in \nFIG.', '5\n, RC_READY comprises a false Boolean value at the start when the execution module \n118\n is controlling.', 'When the execution module \n118\n is signaled by, for example, a user via the user interface \n102\n, the RC_READY changes to a true Boolean value.', 'The state machine, shown in \nFIG.', '3\n, comprises a state of ‘−1—Forced Manual’, ‘−2—Exception’, or ‘0—OFF’.', 'If the state machine controlled by the adapter \n201\n is in the state ‘−1—Forced Manual’ or ‘−2—Exception’ when the adapter \n201\n receives the signal that RC_READY is a true Boolean value, then the state changes to ‘0—OFF’ as provided by the CONTROL_SP_CV of the adapter \n201\n.', 'Once an agent \n120\n, \n121\n receives indication that the RC_READY is a true Boolean value from the execution module \n118\n, the agent \n120\n, \n121\n sets respective set point values and recommended fail-safe set points the agent \n120\n, \n121\n is to control.', 'In \nFIG.', '5\n, the agent \n120\n, \n121\n sets set points VALUE\n1\n_SP to V\n1\n and VALUE\n2\n_', 'SP to V\n2\n, as well as, sets the associated fail-safe set points VALUE\n1\n_SP_FS to V\n1\n_FS and VALUE\n2\n_SP_FS to V\n2\n_FS.', 'These values are sent and stored by the execution module \n118\n.', 'The respective agent \n120\n, \n121\n then indicates to the adapter \n201\n that the agent \n120\n, \n121\n can assume remote control by setting CONTROL_SP of the adapter \n201\n to a true Boolean value.', 'Since RC_READY is a true Boolean value, CONTROL_SP is a true Boolean value, and CONTROL_SP_CV is ‘0—Off’, the state machine hosted within adapter \n201\n advances to ‘2—Starting’.', 'The adapter \n201\n can perform checks to determine whether conditions are appropriate for remote control of the client \n109\n, \n113\n while the state machine hosted within adapter \n201\n is in a ‘2—Starting’ state.', 'If conditions are not appropriate, the adapter \n201\n can set the CONTROL_SP_CV to ‘−2—Exception’ to terminate the process.', 'If conditions are appropriate, the adapter \n201\n latches the appropriate set points latches by setting VALUE\n1\n_SP_LATCH and VALUE\n2\n_SP_LATCH to a true Boolean value.', 'The adapter \n201\n then sets CONTROL_SP_CS to ‘1—ON’.', 'When a value within the communication interface for remote control \n119\n changes, the execution module \n118\n evaluates the change and takes appropriate action.', 'If RC_READY is a true Boolean value and VALUE\n1\n_SP_LATCH is a true Boolean value and VALUE\n1\n_SP_CV does not equal VALUE\n1\n_SP, then the execution module \n118\n applies the requested set point value to the appropriate equipment control module \n112\n, \n116\n, and, if accepted by the equipment control module \n112\n, \n116\n, the execution module \n118\n sets VALUE\n1\n_SP_CV to VALUE\n1\n_SP.\n \nFIGS.', '6 and 7\n illustrate a method \n600\n for releasing control from the automation agent to the execution module \n118\n (e.g., rig control system).', 'For example, in \nFIG.', '7\n, an initial state is shown for the agent \n120\n, \n121\n having control of set points VALUE\n1\n_SP and VALUE\n2\n_SP is shown.', 'These values are indicated by RC_READY being a true Boolean value, VALUE\n1\n_SP_LATCH', 'being a true Boolean value, and VALUE\n2\n_SP_LATCH being a true Boolean value.', 'The agent \n120\n, \n121\n is indicated control by CONTROL_SP_CV being ‘1—ON’.', 'As shown in \nFIG.', '6\n, an indication to release control is received (Block \n602\n).', 'This indication, for example, could be from an operator stopping remote control capability of one or more set points via the user interface \n102\n on the execution module \n118\n, which sets RC_READY to a false Boolean value.', 'As shown in \nFIGS.', '6 and 7\n, the remote control set point is set to a false Boolean value, and, once the release indication is received, the control set point current value is transitioned to ‘−1—Forced Manual’ (Block \n606\n).', 'Referring to \nFIG.', '6\n, the adapter unlatches set points by setting VALUE\n1\n_SP_LATCH and VALUE\n2\n_SP_LATCH to a false Boolean value (Block \n608\n).', 'In one or more embodiments the VALUE\n1\n_SP_LATCH and VALUE\n2\n_SP_LATCH are set to false by the execution module \n118\n.', 'In another embodiment, the VALUE\n1\n_SP_LATCH and VALUE\n2\n_SP_LATCH are not changed and remote control functionality may not be engaged due to the logic described in Block \n502\n of \nFIG.', '5\n.', 'FIGS.', '8 and 9\n illustrate a method \n800\n of an agent releasing remote control.', 'As an example, in \nFIG.', '9\n, an initial state is shown for the agent \n120\n, \n121\n having control of set points VALUE\n1\n_SP and VALUE\n2\n_SP.', 'This is indicated by RC_READY being a true Boolean value, VALUE\n1\n_SP_LATCH', 'being a true Boolean value, and VALUE\n2\n_SP_LATCH being a true Boolean value.', 'As described herein and shown in \nFIG.', '9\n, the agent \n120\n, \n121\n is indicated as being in control through CONTROL_SP_CV being ‘1—ON’.', 'As shown in \nFIG.', '8\n, an indication to release control is received (Block \n802\n) by setting CONTROL_SP to a false Boolean value, and the control state is set to ‘3—Stopping’ (Block \n804\n).', 'For example, the adapter \n201\n sets CONTROL_SP_CV to ‘3—Stopping’.', 'As shown in \nFIGS.', '8 and 9\n, the associated set points are unlatched (Block \n806\n).', 'For example, the adapter \n201\n then unlatches the set points by setting VALUE\n1\n_SP_LATCH and VALUE\n2\n_SP_LATCH to a false Boolean value.', 'The control state is transitioned to ‘0—Off’ (Block \n808\n) as shown in \nFIGS.', '8 and 9\n.', 'For example, the adapter \n201\n then sets the control state as shown in \nFIG.', '3\n to ‘0—Off’ by setting CONTROL_SP_CV.', 'In response, the execution module \n118\n does not communication the VALUE\n1\n_SP and VALUE\n2\n_SP to respective equipment control modules \n112\n, \n116\n due to the logic described in Block \n502\n of \nFIG.', '5\n.', 'FIGS.', '10 and 11\n illustrate a method \n1000\n of a user forcing manual control.', 'For example, in \nFIG.', '11\n, an initial state is shown for the agent \n120\n, \n121\n having control of set points VALUE\n1\n_SP and VALUE\n2\n_SP.', 'This is indicated by RC_READY being a true Boolean value, VALUE\n1\n_SP_LATCH', 'being a true Boolean value, and VALUE\n2\n_SP_LATCH being a true Boolean value.', 'The agent \n120\n, \n121\n is indicated control by CONTROL_SP_CV being ‘1—ON’.', 'The user interface \n102\n allows the operator the ability to modify a set point that is being remote controlled.', 'As shown in \nFIG.', '10\n, a set point latch is unlatched.', 'For example, upon the user requesting a change to the set point value, VALUE\n1\n_SP_CV, the execution module \n118\n unlatches the set point by setting VALUE\n1\n_SP_LATCH to a false Boolean value and the logic in Block \n502\n of \nFIG.', '5\n may prevent further set point values for this set point from being received from the agent \n120\n, \n121\n.', 'The control state is transitioned to ‘−1—Forced Manual’ (Block \n1004\n) and then the associated set points are unlatched.', 'After receiving the signal that VALUE\n1\n_SP_LATCH has changed to a false Boolean value, the adapter \n201\n sets the control state as shown in \nFIG.', '3\n to ‘−1—Forced Manual’ and unlatches respective set points.', 'In this example, the adapter \n201\n sets VALUE\n2\n_SP_LATCH to a false Boolean value, and the execution module \n118\n does not communicate the VALUE\n1\n_SP and VALUE\n2\n_SP to the respective equipment control modules \n112\n, \n116\n due to the logic described in Block \n502\n of \nFIG.', '5\n.', 'FIGS.', '12 and 13\n illustrate an embodiment when communication between the execution module \n118\n and the agent \n120\n, \n121\n is interrupted.', 'For example, in \nFIG.', '13\n, an initial state is shown for the agent \n120\n, \n121\n having control of set points VALUE\n1\n_SP and VALUE\n2\n_SP.', 'This is indicated by RC_READY being a true Boolean value, VALUE\n1\n_SP_LATCH', 'being a true Boolean value, and VALUE\n2\n_SP_LATCH being a true Boolean value.', 'The agent \n120\n, \n121\n is indicated control by CONTROL_SP_CV being ‘1—ON’.', 'The execution module \n118\n has been provided with recommend fail-safe values V\n1\n_FS and V\n2\n_FS for VALUE\n1\n_SP_FS and VALUE\n2\n_SP_FS, respectively.', 'As shown, a communication loss occurs between the execution module and a respective agent (Block \n1202\n).', 'In this example, a loss of communication occurs between agent \n120\n, \n121\n and the execution module \n118\n.', 'This can be sensed by one or more methods, such as loss of a watch dog signal or a heartbeat.', 'Once the loss of communication has been detected, a remote control indication is set to not ready (Block \n1204\n).', 'For example, the execution module \n118\n indicates that remote control is not ready by setting RC_READY to a false Boolean value.', 'As shown in \nFIG.', '12\n, the recommended fail-safe set point values of any latched set point are set (Block \n1206\n), and the set points are unlatched (Block \n1208\n).', 'For example, the execution module \n118\n examines each associated set point latch to determine whether the latch is set to a true Boolean value.', 'The execution module \n118\n then applies the recommend fail-safe set point to one or more latched set points, as shown in Block \n1301\n of \nFIG.', '13\n.', 'The execution module \n118\n then unsets the set point latches by setting VALUE\n1\n_SP_LATCH and VALUE\n2\n_SP_LATCH to a false Boolean value.', 'In some embodiments, as shown in \nFIG.', '12\n, the control state is transitioned to ‘−2—Exception’ (Block \n1210\n).', 'For example, the adapter \n201\n can transition the control state logic to ‘−2—Exception’ when a communication loss is detected.', 'In general, the routines executed to implement the embodiments disclosed herein, whether implemented as part of an operating system or a specific application, component, program, object, module or sequence of instructions, or even a subset thereof, will be referred to herein as “computer program code” or simply “program code.”', 'Program code typically comprises one or more instructions that are resident at various times in various memory and storage devices in a computer, and that, when read and executed by one or more processors in a computer, cause that computer to perform functions.', 'Moreover, while embodiments have and hereinafter will be described in the context of fully functioning computers and computer systems, those skilled in the art will appreciate that the various embodiments are capable of being distributed as a program product in a variety of forms.', 'Such computer readable media can include computer readable storage media and communication media.', 'Computer readable storage media is non-transitory in nature, and can include volatile and non-volatile, and removable and non-removable media implemented in any method or technology for storage of information, such as computer-readable instructions, data structures, program modules or other data.', 'Computer readable storage media can further include random-access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other solid state memory technology, CD-ROM, digital versatile disks (DVD), or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium that can be used to store the desired information and which can be accessed by computing device \n101\n.', 'Communication media can embody computer readable instructions, data structures or other program modules.', 'By way of example, and not limitation, communication media can include wired media such as a wired network or direct-wired connection, and wireless media such as acoustic, RF, infrared and other wireless media.', 'Combinations of any of the above can also be included within the scope of computer readable media.', 'It will be appreciated that agents, as well as the software components in computing device \n101\n implementing an automation server can be distributed among multiple computers, e.g., within clusters or even within distributed systems where computers are geographically distant from one another.', 'A distributed system can be implemented on heterogeneous computer systems such that agents resident on different hardware and/or software environments.', 'It will also be appreciated that security features can be implemented to ensure that authorized agents are permitted to interact with other agents and underlying hardware in an automation system.', 'Furthermore, it will be appreciated that an automation server or an execution module can be resident in a single, central computer, or can be distributed among multiple computers (e.g., as a distributed service, a cluster, a cloud service, etc.).', 'Although a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from “Interface For Automation Client.”', 'Accordingly, one or more of the modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'An automation system comprising:\nan execution module implemented by a computing device, wherein the computing device comprises a central processing unit (“CPU”) and a network interface coupled to the CPU, and wherein the execution module comprises a communication interface for remote control (“CIRC”); and\na network connected to the CPU via the network interface and comprising: a plurality of clients comprising controllable equipment of a drilling rig, wherein a plurality of operating characteristics each characterize current operation of a corresponding one or more of the clients in response to a current value of a corresponding one of a plurality of set points collectively being used to control the clients, wherein the plurality of operating characteristics comprises at least one of drill revolutions per minute, mud pump flow rate, torque, and throttle position; and a plurality of agents each associated with a corresponding one of the set points, wherein each agent: receives from the CIRC a remote control indication of whether the corresponding set point is available for remote control by the agent; receives from the CIRC a current value for the corresponding set point; receives from the CIRC a latch indication of whether that agent is latched to the CIRC and, thereby, remotely controlling the corresponding set point; provides to the CIRC a remote controlled value to be used for the corresponding set point absent loss of communication between the CIRC and that agent; and provides to the CIRC a fail-safe value to be used for the corresponding set point upon loss of communication between the CIRC and that agent.', '2.', 'The automation system of claim 1 wherein the network further comprises an equipment control module operable to control ones of the set points not being controlled by any of the agents.', '3.', 'The automation system of claim 1 wherein the CPU is coupled to a memory and comprises a hardware-based microprocessor.', '4.', 'The automation system of claim 1 wherein the controllable equipment comprises a plurality of hardware controllers each associated with a corresponding one or more components of the drilling rig equipment.', '5.', 'The automation system of claim 4 wherein the controllable equipment further comprises a plurality of software controllers each associated with a corresponding one or more components of the drilling rig equipment.', '6.', 'The automation system of claim 1 wherein the network further comprises a plurality of sensors for collecting data related to an oil and gas process performed by the drilling rig via control of the controllable equipment.', '7.', 'The automation system of claim 6 wherein the network further comprises a real time data store storing the collected data.', '8.', 'The automation system of claim 1 wherein the execution module implements the CIRC using Object Linking and Embedding (OLE) for Process Control (OPC).', '9.', 'The automation system of claim 1 wherein the execution module comprises a connection manager controlling connection and communication with the agents.', '10.', 'The automation system of claim 1 wherein the execution module comprises a logger that creates, saves, and provides access to a log of transactions within and with the execution module.', '11.', 'The automation system of claim 1 wherein each agent automatically connects to the CIRC in response to connection of that agent to the network.', '12.', 'The automation system of claim 1 wherein the computing device comprises a user interface permitting a human operator to select which of the set points are made available for remote control.', '13.', 'The automation system of claim 12 wherein the user interface permits the human operator to manually interrupt remote control being performed by one of the agents.', '14.', 'The automation system of claim 1 wherein the plurality of operating characteristics comprises:\ndrill revolutions per minute;\nmud pump flow rate;\ntorque; and\nthrottle position.', '15.', 'The automation system of claim 1 wherein the controllable equipment comprises:\na mud pump;\na hoist;\na rotary device;\na choke;\na valve; and\na blowout preventer.', '16.', 'The automation system of claim 1 wherein:\nthe network interface is a first network interface;\nthe computing device comprises a second network interface coupled to the CPU;\nthe network is a first network connected to the CPU via the first network interface;\nthe clients are first clients comprising controllable first equipment of the drilling rig;\nthe operating characteristics are first operating characteristics;\nthe set points are first set points collectively being used to control the first clients;\nthe automation system further comprises a second network connected to the CPU via the second network interface and comprising a plurality of second clients comprising second controllable equipment of the drilling rig;\na plurality of second operating characteristics each characterize current operation of a corresponding one or more of the second clients in response to a current value of a corresponding one of a plurality of second set points collectively being used to control the second clients;\nthe agents are each associated with a corresponding one of the first or second set points; and\neach agent: receives from the CIRC a remote control indication of whether the corresponding first or second set point is available for remote control by the agent; receives from the CIRC a current value for the corresponding first or second set point; receives from the CIRC a latch indication of whether that agent is latched to the CIRC and, thereby, remotely controlling the corresponding first or second set point; provides to the CIRC a remote controlled value to be used for the corresponding first or second set point absent loss of communication between the CIRC and that agent; and provides to the CIRC a fail-safe value to be used for the corresponding first or second set point upon loss of communication between the CIRC and that agent.', '17.', 'The automation system of claim 16 wherein the first network is a non-deterministic network and the second network is a deterministic network.', '18.', 'The automation system of claim 16 wherein the first network further comprises an equipment control module operable to control ones of the first and second set points not being controlled by any of the agents.', '19.', 'The automation system of claim 16 wherein the second network further comprises an equipment control module operable to control the second set points in the absence of the execution module.', '20.', 'The automation system of claim 16 wherein:\nthe first network further comprises a first equipment control module operable to control ones of the first and second set points not being controlled by any of the agents; and\nthe second network further comprises a second equipment control module operable to control the second set points in the absence of the execution module.'] | ['FIG.', '1 is a diagrammatic illustration of a block diagram of a computing device for facilitating automation of equipment (e.g., a client) in accordance with an example embodiment of the present disclosure, where the computing device includes a control module that is communicatively connected to the equipment.; FIG.', '2 is a block diagram illustrating a communication interface between the computing device and the equipment in accordance with an example embodiment of the present disclosure.', '; FIG.', '3 is a state diagram illustrating logic for facilitating transfer of control between a control module and an automation agent deployed on the equipment in accordance with an example embodiment of the present disclosure.; FIGS. 4 and 5 illustrate flow charts for furnishing control from a control module to a deployable automation agent in accordance with an example embodiment of the present disclosure.; FIGS.', '6 and 7 illustrate flow charts furnishing a manual control indication to force an automation agent to transition control from the deployable automation agent to the control module in accordance with an example embodiment of the present disclosure.; FIGS.', '8 and 9 illustrate flow charts for releasing control from a deployable automation agent to the control module in accordance with an example embodiment of the present disclosure.; FIGS.', '10 and 11 illustrate flow charts for controlling a current value that has been already latched by a deployable automation agent in accordance with an example embodiment of the present disclosure.; FIGS.', '12 and 13 illustrate flow charts for using a recommended fail-safe set point in the event that a communication failure occurs.;', 'FIG. 1 illustrates example apparatus 100, such as a drilling rig, or the like, that includes a computing device 101 in which a control system can be implemented.', 'The computing device 101 is illustrated as including one or more computers having a central processing unit 108 including at least one hardware-based microprocessor coupled to a memory 107, which can represent the random access memory (RAM) devices that includes the main storage of computing device 101, as well as any supplemental levels of memory, e.g., cache memories, non-volatile or backup memories (e.g., programmable or flash memories), read-only memories, etc.', 'In addition, the memory 107 can be considered to include memory storage physically located elsewhere in computing device 101, e.g., any cache memory in a microprocessor, as well as any storage capacity used as a virtual memory, e.g., as stored on a mass storage device 106 or on another computer coupled to computing device 101.; FIG.', '2 illustrates an example communication interface for remote control 119 between a computing device 101 and an agent 120, 121.', 'A control state machine adapter 201 can be utilized within an agent (agent 120, 121) to allow a greater resolution of the remote control state for the particular equipment desired to be controlled via the communication interface for remote control 119.; FIG.', '3 generally illustrates a state machine representing logic for facilitating transfer of control to an agent 120, 121, where set point latches are used to transition between local control of the industrial system to remote control by agent.; FIGS. 4 and 5 illustrate an example flow chart 400 for furnishing (e.g., providing) control from the control module to a respective agent.', 'In one or more embodiments, the computing device 101 may present a user interface (e.g., user interface 102) to an operator of a drill rig to indicate that remote control is allowed.', 'The operator of a drill rig can allow remote control for each operating characteristic or a sub-set of operating characteristics for the rig via the user interface, such as user interface 102 (Block 402).', 'As shown in FIG. 4, a remote control indication is received (Block 404) by an agent.', 'For example, the agents 120, 121 receive a remote control indication.', 'The respective agent 120, 121 indicates to the adapter 201, which has implemented the state machine logic shown in FIG.', '3, to go to starting by setting CONTROL_SP to ‘true’.', 'The state machine logic in FIG.', '3 transitions from ‘0—OFF’ to ‘2—Starting’ when both CONTROL_SP is ‘true’ and RC_READY is ‘true’.; FIGS. 6 and 7 illustrate a method 600 for releasing control from the automation agent to the execution module 118 (e.g., rig control system).', 'For example, in FIG. 7, an initial state is shown for the agent 120, 121 having control of set points VALUE1_SP and VALUE2_SP is shown.', 'These values are indicated by RC_READY being a true Boolean value, VALUE1_SP_LATCH being a true Boolean value, and VALUE2_SP_LATCH being a true Boolean value.', 'The agent 120, 121 is indicated control by CONTROL_SP_CV being ‘1—ON’.', 'As shown in FIG.', '6, an indication to release control is received (Block 602).', 'This indication, for example, could be from an operator stopping remote control capability of one or more set points via the user interface 102 on the execution module 118, which sets RC_READY to a false Boolean value.', 'As shown in FIGS.', '6 and 7, the remote control set point is set to a false Boolean value, and, once the release indication is received, the control set point current value is transitioned to ‘−1—Forced Manual’ (Block 606).', 'Referring to FIG.', '6', ', the adapter unlatches set points by setting VALUE1_SP_LATCH and VALUE2_SP_LATCH to a false Boolean value (Block 608).', 'In one or more embodiments the VALUE1_SP_LATCH and VALUE2_SP_LATCH are set to false by the execution module 118.', 'In another embodiment, the VALUE1_SP_LATCH and VALUE2_SP_LATCH are not changed and remote control functionality may not be engaged due to the logic described in Block 502 of FIG.', '5.; FIGS. 8 and 9 illustrate a method 800 of an agent releasing remote control.', 'As an example, in FIG. 9, an initial state is shown for the agent 120, 121 having control of set points VALUE1_SP and VALUE2_SP.', 'This is indicated by RC_READY being a true Boolean value, VALUE1_SP_LATCH being a true Boolean value, and VALUE2_SP_LATCH being a true Boolean value.', 'As described herein and shown in FIG.', '9, the agent 120, 121 is indicated as being in control through CONTROL_SP_CV being ‘1—ON’.', 'As shown in FIG. 8, an indication to release control is received (Block 802) by setting CONTROL_SP to a false Boolean value, and the control state is set to ‘3—Stopping’ (Block 804).', 'For example, the adapter 201 sets CONTROL_SP_CV to ‘3—Stopping’.', 'As shown in FIGS.', '8 and 9, the associated set points are unlatched (Block 806).', 'For example, the adapter 201 then unlatches the set points by setting VALUE1_SP_LATCH and VALUE2_SP_LATCH to a false Boolean value.', 'The control state is transitioned to ‘0—Off’ (Block 808) as shown in FIGS. 8 and 9.', 'For example, the adapter 201 then sets the control state as shown in FIG.', '3 to ‘0—Off’ by setting CONTROL_SP_CV.', 'In response, the execution module 118 does not communication the VALUE1_SP and VALUE2_SP to respective equipment control modules 112, 116 due to the logic described in Block 502 of FIG.', '5.; FIGS.', '10 and 11 illustrate a method 1000 of a user forcing manual control.', 'For example, in FIG.', '11, an initial state is shown for the agent 120, 121 having control of set points VALUE1_SP and VALUE2_SP.', 'This is indicated by RC_READY being a true Boolean value, VALUE1_SP_LATCH being a true Boolean value, and VALUE2_SP_LATCH being a true Boolean value.', 'The agent 120, 121 is indicated control by CONTROL_SP_CV being ‘1—ON’.', 'The user interface 102 allows the operator the ability to modify a set point that is being remote controlled.', 'As shown in FIG.', '10, a set point latch is unlatched.', 'For example, upon the user requesting a change to the set point value, VALUE1_SP_CV, the execution module 118 unlatches the set point by setting VALUE1_SP_LATCH to a false Boolean value and the logic in Block 502 of FIG.', '5 may prevent further set point values for this set point from being received from the agent 120, 121.', 'The control state is transitioned to ‘−1—Forced Manual’ (Block 1004) and then the associated set points are unlatched.', 'After receiving the signal that VALUE1_SP_LATCH has changed to a false Boolean value, the adapter 201 sets the control state as shown in FIG.', '3 to ‘−1—Forced Manual’ and unlatches respective set points.', 'In this example, the adapter 201 sets VALUE2_SP_LATCH to a false Boolean value, and the execution module 118 does not communicate the VALUE1_SP and VALUE2_SP to the respective equipment control modules 112, 116 due to the logic described in Block 502 of FIG.', '5.; FIGS.', '12 and 13 illustrate an embodiment when communication between the execution module 118 and the agent 120, 121 is interrupted.', 'For example, in FIG. 13, an initial state is shown for the agent 120, 121 having control of set points VALUE1_SP and VALUE2_SP.', 'This is indicated by RC_READY being a true Boolean value, VALUE1_SP_LATCH being a true Boolean value, and VALUE2_SP_LATCH being a true Boolean value.', 'The agent 120, 121 is indicated control by CONTROL_SP_CV being ‘1—ON’.', 'The execution module 118 has been provided with recommend fail-safe values V1_FS and V2_FS for VALUE1_SP_FS and VALUE2_SP_FS, respectively.', 'As shown, a communication loss occurs between the execution module and a respective agent (Block 1202).', 'In this example, a loss of communication occurs between agent 120, 121 and the execution module 118.', 'This can be sensed by one or more methods, such as loss of a watch dog signal or a heartbeat.', 'Once the loss of communication has been detected, a remote control indication is set to not ready (Block 1204).', 'For example, the execution module 118 indicates that remote control is not ready by setting RC_READY to a false Boolean value.', 'As shown in FIG.', '12, the recommended fail-safe set point values of any latched set point are set (Block 1206), and the set points are unlatched (Block 1208).', 'For example, the execution module 118 examines each associated set point latch to determine whether the latch is set to a true Boolean value.', 'The execution module 118 then applies the recommend fail-safe set point to one or more latched set points, as shown in Block 1301 of FIG.', '13.', 'The execution module 118 then unsets the set point latches by setting VALUE1_SP_LATCH and VALUE2_SP_LATCH to a false Boolean value.', 'In some embodiments, as shown in FIG. 12, the control state is transitioned to ‘−2—Exception’ (Block 1210).', 'For example, the adapter 201 can transition the control state logic to ‘−2—Exception’ when a communication loss is detected.'] |
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US11078402 | Use of particulate or fibrous materials in gravel pack applications | Mar 26, 2015 | Matthew Offenbacher, Balkrishna Gadiyar | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion regarding corresponding application No. PCT/US2015/022766; 11 pages; dated Jul. 7, 2015. | 4470915; September 11, 1984; Conway; 20010036905; November 1, 2001; Parlar et al.; 20040055747; March 25, 2004; Lee; 20080139416; June 12, 2008; Rimassa; 20090258798; October 15, 2009; Munoz et al.; 20120132421; May 31, 2012; Loiseau; 20130213638; August 22, 2013; Keller; 20130228335; September 5, 2013; Dobson | Foreign Citations not found. | No images available | ['Methods include drilling at least one interval of a wellbore with a water-based wellbore fluid producing a filtercake in the at least one interval of the wellbore.', 'The methods also include gravel packing an interval of a wellbore traversing a subterranean formation with a gravel pack that comprises polyhydroxycarboxylic acid, and hydrolyzing the polyhydroxycarboxylic acid to degrade at least a portion of the filtercake.'] | ['Description\n\n\n\n\n\n\nThis application is a National Stage application of International Application No.', 'PCT/US2015/022766 filed Mar. 26, 2015, which claims the benefit of U.S. Provisional Application No. 61/970,610 filed on Mar. 26, 2014, incorporated by reference herein in its entirety.', 'BACKGROUND\n \nTo produce oil and gas from a hydrocarbon reservoir, a wellbore is first drilled through geological formations.', 'During drilling operations, specially designed reservoir drilling fluids may have various additives, including biologically-derived polymers and bridging solids that lubricate the drill bit and remediate fluid loss into the formation.', 'Drilling fluid additives are often formulated such that formation damage caused by the accumulated drilling fluids may be reversible, because the additives are soluble or breakable upon contact with a suitable breaker fluid, which may include acids, oxidizers, or enzymes, for example.', 'Once the wellbore is generated in the hydrocarbon reservoir, production tubing and/or screens may be emplaced within the wellbore and placed within an interval of the formation prior to hydrocarbon production.', 'During production, sand control methods and/or devices are used to prevent sand particles in the formation from entering and plugging the production screens and tubes in order extend the life of the well.', 'Sand control methods may include gravel packing in which the annular space between the wellbore and the production screens is filled with specially sized gravel packing sand.', 'Following drilling operations and prior to introduction of the sand or gravel for the gravel pack, the hydrocarbon-bearing formation may contain a substantially impermeable filtercake created by the reservoir drilling fluid.', 'This thin and impermeable filtercake may prevent the gravel pack fluid from entering the formation, and may result in gravel pack failure.', 'Moreover, after gravel pack emplacement, the filtercake existing between the gravel pack sand and the formation may require removal before the flow of hydrocarbon may be initiated.', 'Without the removal of the filtercake, plugging of the production screen by the filtercake could occur, impairing production.', 'Various chemicals, breakers, and mechanical devices have been developed to remove filtercakes during gravel packing operations.', 'For example, acids may be delivered to soak the gravel pack sand and filtercake.', 'Here, the goal is to dissolve the acid-soluble and acid-breakable components in the filtercake and remediate the damaged formation.', 'Other breakers, such as oxidizers and enzymes, may also be delivered to destroy oxidizer- and enzyme-breakable organic components.', 'They may not be as effective in destroying acid-soluble and acid-breakable inorganic components in the filtercake, such as calcium carbonate.', 'As a result, acid-soluble and breakable components may remain behind the gravel pack sand and cause impairment during the production of the well.', 'Secondly, many oxidizing breakers have compatibility issues with certain brines and may react with the brine and create undesirable by-products, such as Cl\n2 \nand Br\n2 \ngases.', 'This reaction can occur even before the breakers are pumped down to attack the filtercake.', 'Third, in addition to brine compatibility issues, enzyme breakers may also have reduced activity outside of the optimal temperature range for the given enzyme.', 'For example, enzyme breakers may lose reactivity in highly concentrated divalent brines or at temperatures above 93° C. (200° F.).', 'The above filtercake breakers are often pumped separately after the gravel pack sand has been set.', 'They are not pumped during the gravel pack operation because they can create precarious conditions for the operation.', 'For instance, the acid-based breakers can destroy the filtercake during gravel pack operations, which may result in high fluid loss and premature failure in the gravel pack operation.', 'Similarly, pumping oxidizers and enzyme breakers with gravel pack sand may cause inconsistent application of oxidizers and enzyme breakers to the filtercakes.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'In one aspect, methods described herein are directed to drilling at least one interval of a wellbore with a water-based wellbore fluid to produce a filtercake in the at least one interval of the wellbore.', 'The method may also include gravel packing an interval of a wellbore traversing a subterranean formation with a gravel pack that includes polyhydroxycarboxylic acid, and hydrolyzing the polyhydroxycarboxylic acid to degrade at least a portion of the filtercake.', 'In another aspect, methods described here are directed to running a sand control screen assembly to a selected depth within the uncased section of the wellbore to facilitate a gravel packing operation and introducing a gravel pack slurry that includes polyhydroxycarboxylic acid into the wellbore to facilitate gravel packing operations.', 'Other aspects and advantages of the disclosure will be apparent from the following description and the appended claims.', 'DETAILED DESCRIPTION', 'In one aspect, embodiments disclosed herein relate to wellbore treatments containing filtercake breakers that may be used during operations to clean the wellbore prior to the production of hydrocarbons from a subterranean formation.', 'Filtercake breakers may be applied to filtercakes to aid in their removal, particularly during completions operations such as gravel packing prior to initiation of hydrocarbon production.', 'Wellbores drilled in certain subterranean formations are sometimes completed as open holes, i.e., without a casing or liner installed therein.', 'Special drilling fluids referred to in the art as “drill-in fluids” may be used to drill such wellbores, among other reasons, to minimize the damage to the permeability of the producing zones or formations.', 'The drill-in fluid may form a filtercake on the walls of the wellbore, which may prevent or reduce fluid loss during drilling, and upon completion of the drilling, may stabilize the wellbore during subsequent completion operations such as placing a gravel pack in the wellbore.', 'After completion operations in the wellbore have been concluded, filtercake remaining on the walls of the wellbore must be removed.', 'This may be accomplished by contacting the filtercake with an aqueous acid solution.', 'However, the use of an aqueous acid solution may be hazardous to personnel or may cause corrosion on surfaces and/or equipment in the wellbore.', 'In addition, acid solutions may react rapidly at the initial point of contact with the wellbore, which can lead to the creation of fluid loss zones into which acid and other wellbore fluids may be lost.', 'Prematurely spent acid solutions may also leave much of the wellbore untreated and remaining filtercake in place, which can lead to downstream issues and reduced production rates.', 'In embodiments in accordance with the instant disclosure, a filtercake breaker composition may be employed for in place of aqueous acid solutions.', 'In particular embodiments, filtercake breaker compositions may produce acid over time and, in effect, may be less hazardous to personnel.', 'Moreover, because of this time-dependent release of acid, these compounds may be able to flow further into the wellbore before reacting to reduce pH, allowing specific placement of the compositions into a given interval of interest.', 'Thus, where targeting of a particular interval of the wellbore is desired, filtercake breaker materials of the instant disclosure may allow for more complete removal of filtercakes and reduce formation damage that may result in the creation of fluid loss zones.', 'In one or more embodiments, filtercake breaker compositions in accordance with the present disclosure may include wellbore fluids containing a degradable polymeric breaker that releases acid upon exposure to a number of stimuli that may include changes in temperature and pH or exposure to various solvents.', 'For example, in some embodiments, a degradable polyhydroxycarboxylic acid present as a powder, particulate, or fiber may be used as a delayed filtercake breaker that slowly hydrolyzes and releases acidic byproducts that dissolve or degrade acid-soluble components in the filtercake.', 'After a sufficient amount of time, the released acids may degrade filtercake to such an extent that the filtercake may be removed by pumping or washing the degraded filtercake residue from the well.', 'Filtercake breaker compositions in accordance with the present disclosure may also be used in conjunction with sand control methods such as gravel packing that involve the use of sand screens and other hardware.', 'For example, a sand control screen assembly may be emplaced within a selected depth within an uncased section of the wellbore to facilitate a gravel packing operation.', 'Gravel packing may then involve mixing gravel with a carrier fluid, and pumping the slurry down the tubing and through a cross-over and into an annulus created between an emplaced screen and an uncased interval of the wellbore.', 'The carrier fluid in the slurry may then leak off into the formation and/or through the screen.', 'The screen may prevent the gravel and other materials in the slurry from entering the production tubing, causing gravel and other additives to deposit in the annulus around the screen and forming the gravel pack.', 'The gravel pack then serves to prevent sand and other formation fines from flowing into the wellbore.', 'In particular embodiments, the polyhydroxycarboxylic acid may be added to a gravel pack fluid in place of gravel and pumped downhole to fill the annular space between the production screen and formation.', 'In yet other embodiments, polymeric hydroxycarboxylic acid may be combined with a gravel packing material such as bauxite, ceramic materials, glass materials, sand, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates, nut shell pieces, seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, carbons, metal oxides, and the like.', 'Embodiments directed to gravel packing methods may encompass both open-hole and cased-hole operations.', 'For instance, in an open-hole completion, a gravel pack in accordance with the present disclosure may be positioned between the wall of the wellbore and a sand screen that surrounds a perforated base pipe.', 'In a cased-hole completion, a gravel pack in accordance with the present disclosure may be positioned between a perforated casing string and a sand screen that surrounds a perforated base pipe.', 'Polyhydroxycarboxylic Acids\n \nFiltercake breaking agents in accordance with the present disclosure may be polyesters produced from the polymerization of hydroxycarboxylic acids.', 'Polyhydroxycarboxylic acids are unique in that, upon exposure to an appropriate stimulus, the polyacid hydrolyzes and releases acidic monomers that decrease the pH of the surrounding medium, which may find particular use in the removal of filtercakes prior to the initiation of production.', 'The hydroxycarboxylic acid breakers in accordance with the present disclosure may be produced through condensation polymerization methods known in the art.', 'In one embodiment, self-polymerization can be initiated by heating a monomer to a temperature above the melting point of the polymeric form, which promotes a condensation reaction that produces water as the polymer forms.', 'The hydroxycarboxylic acid may be added to the gravel pack during the process of gravel packing.', 'Thus, the hydroxycarboxylic acid may be emplaced into the wellbore in combination with the gravel pack.', 'During use, polyhydroxycarboxylic acids may then slowly hydrolyze and release an acidic byproduct once dispersed in a wellbore fluid or solvent containing water.', 'Polymer hydrolysis may depend on a number of factors that include temperature, solubility of the polymer and released monomer, molecular weight of the polymer, the presence of water, and the ionic strength of the wellbore fluid or brine.', 'Under downhole conditions, the polymeric hydroxycarboxylic acid generates acidic by-products that may react with the acid-soluble and acid-breakable components in the filtercake.', 'The slow release rate of the acidic by-product may require that the well be shut in for a given period of time to complete the dissolution and break-down reaction.', 'In particular embodiments, the rate of hydrolysis of the polymer and the corresponding conversion to free acid may be delayed sufficiently to enable targeted emplacement of the polyhydroxycarboxylic acid in selected intervals without premature and undesirable filtercake removal.', 'In one or more embodiments, wellbore fluids compositions may contain at least one polyhydroxycarboxylic acid may hydrolyze at temperature of 120° F. (49° C.) or greater.', 'In other embodiments, the polyhydroxycarboxylic acid may hydrolyze at temperatures of 150° F. (66° C.) or greater.', 'In a non-limiting example, polylactic acid converts to the free acid at temperatures within the range of about 150° F. (66° C.) to about 170° F. (77° C.).', 'Polyhydroxycarboxylic acids in accordance with the present disclosure may be formed from a number of possible monomers that including, but not limited to lactic acid, malic acid, gluconic acid, glycolic acid, citric acid, mandelic acid, saccharic acid, mucic acid, tartaric acid, 3-hydroxybutyric acid, 4-hydroxybutyric acid, 4-hydroxyvaleric acid, 5-hydroxyvaleric acid and 6-hydroxycaproic acid.', 'The monomeric repeating unit may also be derived from a cyclic monomer or cyclic dimer of the respective aliphatic hydroxycarboxylic acid.', 'Examples of these include lactide, glycolide, β-propiolactone, β-butyrolactone, γ-butyrolactone, γ-valerolactone, δ-valerolactone, ε-caprolactone and the like.', 'It is also within the scope of this disclosure that any of the above monomers may be co-polymerized to produce copolymers, block copolymers, or higher order polymers such as terpolymers or quaternary polymers.', 'In one or more embodiments, the molecular weight of the polyhydroxycarboxylic acid may affect the hydrolysis rates and formation of acid downhole, possibly affecting the rate and effectiveness of the polymer in breaking the filtercake.', 'In some embodiments the weight average molecular weight of the hydroxycarboxylic acid polymer may range from 500 to 10,000,000 Daltons.', 'In other embodiments, the weight average molecular weight may range from 1,000 to 500,000 Daltons; and from 2,000 to 200,000 Daltons in yet other embodiments.', 'In some embodiments, the molecular weight distribution (M\nw\n/M\nn\n) of the hydroxycarboxylic acid polymer may range from 1.2 to 5.0.', 'In other embodiments, the molecular weight distribution may range from 2.0 to 4.0; and from 2.3 to 3.5 in yet other embodiments.', 'In one or more embodiments, a wellbore fluid containing a polymeric hydroxycarboxylic acid may be emplaced within an interval of a wellbore containing a degradable filtercake in order to remove the filtercake.', 'The polymeric hydroxycarboxylic acids disclosed herein may be used to break monovalent salt-based systems, such as FLOPRO® NT, divalent salt-based systems, such as DIPRO™, and reversible oil-based systems such as FAZEPRO™, all of which are commercially available from M-I, L.L.C. (Houston, Tex.).', 'The wellbore fluid may also include water and brines containing various electrolytes and their blends, such as, but not limited to NaCl, KCl, CaCl\n2\n, CaBr\n2\n, ZnBr\n2\n, etc.', 'In one or more embodiments, wellbore fluids in accordance with this disclosure may contain at least one polyhydroxycarboxylic acid formulated in a wellbore fluid at a percent by weight (wt %) concentration having a lower limit equal or greater than 0.05 wt %, 0.1 wt %, 0.5 wt %, 1 wt %, and 5 wt %, to an upper limit of 0.5 wt %, 1 wt %, 5 wt %, 7 wt %, and 10 wt %, where the wt % concentration of the polyhydroxycarboxylic acid may range from any lower limit to any upper limit.', 'In other embodiments, the polyhydroxycarboxylic acid breaker may be present in a wellbore fluid at a percent by weight of at least 10 wt %.', 'A polyhydroxycarboxylic acid may be formulated in a wellbore fluid in an amount that ranges from 0.5 ppb to 20 ppb in some embodiments.', 'In some embodiments, the polyhydroxycarboxylic acid breaker may be added in an amount that is at least 15 ppb or at least 18 ppb in other embodiments.', 'In some embodiments, polyhydroxycarboxylic acid may be added to the defluidizing pill in a range of 5 ppb to 20 ppb.', 'In one or more embodiment, at least one polyhydroxycarboxylic acid hydrolyzes and decreases the pH to a value within the range of less than pH 1 to pH 5.', 'In other embodiments, the pH may range from pH 1 to pH 3.', 'The three dimensional shape of the polyhydroxycarboxylic acid additive may also be varied to control a number of the rate of dissolution.', 'In some embodiments, the polyhydroxycarboxylic acid may be provided as a particulate or fiber.', 'As used herein, a particulate is a spherical, substantially spherical, or oblate solid prepared from the polymerization of at least one hydroxycarboxylic acid.', 'For example, polyhydroxycarboxylic acid particulates may be a preparation of homogenous polymer solids that are uniform in size or added as a mixture of sizes in other embodiments.', 'Further, polyhydroxycarboxylic acid particulates may be formed from amorphous or crystalline polymer.', 'The average size of the particulate may range from about 1 nm to about 1 mm, or from about 100 nm to about 100 μm in other embodiments.', 'In one or more embodiments, the polyhydroxycarboxylic acid may be added in the form of a polymeric fiber.', 'Polyhydroxycarboxylic acid fibers in accordance with the instant disclosure may have lengths within the range of 100 μm to 20 mm.', 'In other embodiments the polyhydroxycarboxylic acid fibers may have lengths within the range of 500 μm to 15 mm.', 'The diameter of the polyhydroxycarboxylic acid fiber may be used to control the extent and rate of dissolution of the fiber, particularly upon exposure to elevated temperature.', 'In embodiments of the instant disclosure, the diameter of the polyhydroxycarboxylic acid fibers may fall within the range of about 0.1 μm to about 60 μm.', 'In yet another embodiment, the diameter of the polyhydroxycarboxylic acid fibers may be within the range of 0.5 μm to 50 μm.', 'It is further contemplated that polyhydroxycarboxylic acid may be added in various other forms such as, for example, in granular form, a flake material, or the like.', 'The present disclosure also extends to the simultaneous placement of gravel and polyhydroxycarboxylic acid in either granular form or as a flake material.', 'In one or more embodiments, polyhydroxycarboxylic acid may be mixed with a gravel packing additive at a ratio of percent by weight of polyhydroxycarboxylic acid to gravel additive that may range from about 5:1 to about 1:5.', 'In other embodiments, the ratio of polyhydroxycarboxylic acid to gravel additive that may range from about 3:1 to about 1:1.', 'It is also envisioned that, in some embodiments, that gravel packing operations may be performed using particulate polyhydroxycarboxylic acid and exclude gravel additives.', 'In other embodiments, the polyhydroxycarboxylic acid may hydrolyze at a temperature of 120° F. (49° C.) or greater.', 'It is further contemplated that gravel packing operations disclosed herein may include an initial gravel pack emplaced for the purposes of sand control with a possible secondary gravel pack emplaced for remedial purposes.', 'The polyhydroxycarboxylic acid, when emplaced with the gravel pack, may dissolve in the wellbore.', 'Thus, a consolidated gravel pack may be maintained since the dissolved polyhydroxycarboxylic acid particles (e.g., fibers, particulates, flakes, etc.) do not create void spaces.', 'Rather, the polyhydroxycarboxylic acid particles are packed within pores in the gravel and when dissolved, degrade the filtercake.', 'EXAMPLES', 'The following examples are included to demonstrate embodiments of the present disclosure.', 'It should be appreciated by those of skill in the art that the techniques and compositions disclosed in the examples which follow represent techniques discovered to function well in the practice of the disclosure, and thus can be considered to constitute preferred modes for its practice.', 'However, those of skill in the art should, in light of the present disclosure, appreciate that many changes can be made in the specific embodiments which are disclosed and still obtain a like or similar result without departing from the spirit and scope of the disclosure.', 'The data below discusses methods of using a polylactic acid (PLA) additive to filtercakes generated by water-based drilling fluids.', 'In the following demonstration of the viability of this approach, a polyhydroxycarboxylic acid breaker formulation degrades filtercakes produced using water-based drilling fluids FLOPRO NT and DIPRO systems.', 'Example 1.1\n \nThe 9.5 ppg FLOPRO NT system was formulated as shown in Table 1.', 'FLOPRO NT is a conventional polymer carbonate reservoir drill-in system consisting of primarily acid-soluble components, where FLO-VIS PLUS is a clarified xanthan gum viscosifier, FLOTROL is a derivatized starch fluid loss additive, SAFE-CARB is a sized ground calcium carbonate, D-STROYER is an internal filtercake breaker, and SAFE-SCAV NA is an oxygen scavenger, all of which are commercially available from MI-SWACO L.L.C. (Houston, Tex.).', 'X-CIDE 102 is a glutaraldehyde additive commercially available from Baker Hughes (Houston, Tex.).', "TABLE 1\n \n \n \n \n \n \n \n \nWellbore fluid formulations for Example 1\n \n \n \n \n \n \n \n \n \n \n \n \nConcentration\n \n \n \n \nProducts\n \n(lb/bbl)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nWater\n \n311.49\n \n \n \n \nKCl\n \n28.85\n \n \n \n \nFLO-VIS PLUS\n \n1.00\n \n \n \n \nSoda Ash\n \n0.15\n \n \n \n \nFLOTROL\n \n8.00\n \n \n \n \nX-CIDE 102\n \n0.20\n \n \n \n \nSAFE-CARB 2\n \n5.00\n \n \n \n \nSAFE-CARB 10\n \n5.00\n \n \n \n \nSAFE-CARB 20\n \n5.00\n \n \n \n \nSAFE-CARB 40\n \n23.00\n \n \n \n \nSAFE-CARB 250\n \n7.00\n \n \n \n \nD-STROYER\n \n1.00\n \n \n \n \nSAFE-SCAV NA\n \n0.15\n \n \n \n \n \n \n \n \n \n \n \nAfter formulation, the wellbore fluid's rheology at 120° F. was studied and the sample was hot rolled to measure the stability of the fluid over time.", 'Following hot rolling, the rheology of the fluid was again measured.', 'Results are shown in Table 2.\n \n \n \n \n \n \n \n \nTABLE 2\n \n \n \n \n \n \n \n \nRheological measurements for the wellbore fluid of\n \n \n \nExample 1 at 120° F.\n \n \n \n \n \n \n \n \n \n \nFann Dial Reading\n \nBefore Hot Roll\n \nAfter Hot Roll\n \n \n \n \n \n \n \n \n \n \n \n \n \n600 rev/min\n \n57\n \n53\n \n \n \n300 rev/min\n \n42\n \n38\n \n \n \n200 rev/min\n \n36\n \n32\n \n \n \n100 rev/min\n \n29\n \n25\n \n \n \n\u20036 rev/min\n \n14\n \n11\n \n \n \n\u20033 rev/min\n \n12\n \n9\n \n \n \nGels 10″/10′\n \n13/15\n \n10/13\n \n \n \n \n \n \n \n \nBrookfield Reading (cP)\n \n \n \n \n \n \n \n \n \n \nLSRV 1 minute\n \n—\n \n22,895\n \n \n \nLSRV 2 minute\n \n—\n \n23,095\n \n \n \nLSRV 3 minute\n \n—\n \n22,795\n \n \n \n \n \n \n \n \n \n \nTo evaluate the effects of the polylactic acid (PLA) fibers on filtercake clean up, the test procedure below was used.', 'The test equipment and materials used are considered typical for those who are skilled in the art.', 'A filtercake was built on a water-saturated ceramic disk having an average 5-micron pore opening size in a double-ended high temperature high pressure fluid loss cell by pressing the reservoir drilling fluid against the ceramic disk with about 300 psi nitrogen differential pressure at about 60-82° C. 140° F.-180° F.) for approximately 16 hours.', 'Samples were then transferred to a cell and a filtercake was built.', 'Spurt loss of the fluid was then measured.', 'Results are show in Table 3.\n \n \n \n \n \n \n \n \nTABLE 3\n \n \n \n \n \n \nSpurt loss for fluid compositions assayed\n \n \n \nin Example 1\n \n \n \nModified HTHP (FAO-10 Disc) @ 150° F.\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nSpurt\n \n5.8 mL\n \n \n \n \n\u20021 minute\n \n6.0 mL\n \n \n \n \n\u20022 minute\n \n6.4 mL\n \n \n \n \n\u20024 minute\n \n6.8 mL\n \n \n \n \n\u20029 minute\n \n7.6 mL\n \n \n \n \n16 minute\n \n8.4 mL\n \n \n \n \n25 minute\n \n9.2 mL\n \n \n \n \n30 minute\n \n9.6 mL\n \n \n \n \n36 minute\n \n9.8 mL\n \n \n \n \n \n \n \n \n \n \n \nNext', ', the PLA additive was prepared as a slurry in brine at 3 lb/bbl in 8 oz. jars.', 'The filtercake prepared above was then transferred to the jar by placing the filtercake-covered aloxite disk into the jar for observation.', 'Gravel was mixed with the PLA additive and placed upon the filtercake.', 'The filtercake was then placed in an oven at 170° F. (77° C.) and observed at regular intervals to qualitatively measure filtercake degradation and/or removal.', 'After 72 hours, the FLOPRO filtercake was significantly degraded and nearly completely dissolved.', 'Example 1.2\n \nThe 14.0 ppg DIPRO system was formulated as shown in Table 4.', 'DIPRO is a biopolymer free system including a complex starch and calcium carbonate.', 'TABLE 4\n \n \n \n \n \n \n \n \nWellbore fluid formulations for Example 1.2.', 'Products\n \nConcentration (lb/bbl)\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nDI-TROL\n \n8.00\n \n \n \n \nDI-BALANCE\n \n1.00\n \n \n \n \n14.2 lb/gal Calcium Bromide \n \n498.47\n \n \n \n \nBrine Water\n \n35.96\n \n \n \n \nSAFE-CARB 2\n \n5.00\n \n \n \n \nSAFE-CARB 10\n \n5.00\n \n \n \n \nSAFE-CARB 20\n \n5.00\n \n \n \n \nSAFE-CARB 40\n \n23.00\n \n \n \n \nSAFE-CARB 250\n \n7.00', "After formulation, the wellbore fluid's rheology was studied and the sample was hot rolled to measure the stability of the fluid over time.", 'Following the hot rolling, the rheology of the fluid was again measured.', 'Results are shown in Table 5.\n \n \n \n \n \n \n \n \nTABLE 5\n \n \n \n \n \n \n \n \nRheological measurements for the \n \n \n \nwellbore fluid of Example 2\n \n \n \n \n \n \n \n \n \n \nFann Dial Reading\n \nBefore Hot Roll\n \nAfter Hot Roll\n \n \n \n \n \n \n \n \n \n \n \n \n \n600 rev/min\n \n73\n \n75\n \n \n \n300 rev/min\n \n48\n \n49\n \n \n \n200 rev/min\n \n38\n \n39\n \n \n \n100 rev/min\n \n27\n \n28\n \n \n \n\u20036 rev/min\n \n10\n \n8\n \n \n \n\u20033 rev/min\n \n8\n \n7\n \n \n \nGels 10″/10′\n \n6/8\n \n5/6\n \n \n \n \n \n \n \n \nBrookfield Reading (cP)\n \n \n \n \n \n \n \n \n \n \nLSRV 1 minute\n \n—\n \n14,997\n \n \n \nLSRV 2 minute\n \n—\n \n16,496\n \n \n \nLSRV 3 minute\n \n—\n \n17,196\n \n \n \n \n \n \n \n \n \n \nSamples were then transferred to a cell and a filtercake was created.', 'Spurt loss of the fluid was then recorded as shown below in Table 6.\n \n \n \n \n \n \n \n \nTABLE 6\n \n \n \n \n \n \nSpurt loss for fluid compositions\n \n \n \nassayed in Example 1\n \n \n \nModified HTHP (FAO-10 Disc) @ 150° F.\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nSpurt\n \n3.4 mL\n \n \n \n \n\u20021 minute\n \n3.6 mL\n \n \n \n \n\u20022 minute\n \n3.8 mL\n \n \n \n \n\u20024 minute\n \n4.0 mL\n \n \n \n \n\u20029 minute\n \n4.3 mL\n \n \n \n \n16 minute\n \n4.6 mL\n \n \n \n \n25 minute\n \n5.0 mL\n \n \n \n \n30 minute\n \n5.2 mL\n \n \n \n \n36 minute\n \n5.4 mL\n \n \n \n \n \n \n \n \n \n \n \nNext, the PLA additive was prepared as a slurry in brine at 3 lb/bbl in 8 oz. jars.', 'The filtercake prepared above was then transferred to the jar by placing the filtercake-covered aloxite disk into the jar for observation.', 'The filtercake was then placed in an oven at 170° F. (77° C.) and observed at regular intervals to qualitatively measure filtercake degradation and/or removal.', 'The DIPRO filtercake appeared to completely dissolve, which was expected because it did not contain the biopolymer viscosifier.', 'In both samples 1.1 and 1.2, a portion of the fibrous polymeric breaker appeared to float at the top of the solution.', 'However, it is clear from the observed dissolution of the filtercakes that this did not substantially affect the overall efficiency of the PLA additive.', 'Both of the above described systems are water-based, but a reversible invert emulsion system such as FAZEPRO, for example, may also be compatible.', 'Example 2\n \nIn the following example, two filtercakes were prepared as described above for Example 1.1.', 'The first sample was soaked in 11 ppg calcium chloride and the second in 14 ppg calcium bromide.', 'A second pair of filtercakes was prepared as described above for Example 1.2, one in 9 ppg potassium and the second in 12 ppg sodium bromide.', 'The filtercakes were placed face down in a slurry of gravel and polylactic acid fibers.', 'The samples were then incubated at 170° F. (77° C.) and monitored.', 'Observations were made at 48 hours and then after 192 hours (7 days).', 'All samples showed sufficient degradation.', 'The calcium bromide samples appeared to react the most quickly and since no filtercake was evident after 48 hours both samples were removed from the soak observations at that point.', 'While some of the PLA additive floated to the top in the samples, portions were retained within the gravel itself.', 'After 7 days, the remaining calcium chloride samples were removed from solution and it was observed that the filtercake had completely dissolved.', 'At the proper temperature range, polyhydroxycarboxylic acids demonstrate the potential to function as a breaker additive to aid in filtercake dispersion or total dissolution and may be added as part of a breaker fluid composition or in combination with gravel during gravel packing operations.', 'While the disclosure has presented a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the disclosure as presented herein.', 'Moreover, embodiments described herein may be practiced in the absence of any element that is not specifically disclosed herein.', 'Accordingly, the scope of the disclosure should be limited only by the attached claims.'] | ['1.', 'A method comprising:\ndrilling at least one interval of a wellbore with a water-based wellbore fluid, wherein the water-based wellbore fluid produces a filtercake in the at least one interval of the wellbore;\ngravel packing an interval of a wellbore traversing a subterranean formation with a gravel pack comprising polyhydroxycarboxylic acid, wherein the polyhydroxycarboxylic acid is a polymer formed from one or more monomers selected from a group consisting of malic acid, lactic acid, gluconic acid, citric acid, mandelic acid, saccharic acid, mucic acid, and tartaric acid, wherein the polyhydroxycarboxylic acid hydrolyzes at a temperature ranging from about 150° F. to about 170° F.;\nhydrolyzing the polyhydroxycarboxylic acid; and\ndegrading at least a portion of the filtercake.', '2.', 'The method of claim 1, wherein the ratio of the polyhydroxycarboxylic acid to gravel in the gravel pack ranges from about 5:1 to 1:5 by total weight.', '3.', 'The method of claim 1, wherein the polyhydroxycarboxylic acid hydrolyzes and decreases the pH of the gravel pack to a value within a range of pH 1 to pH 5.\n\n\n\n\n\n\n4.', 'The method of claim 1, wherein the polyhydroxycarboxylic acid is emplaced in the wellbore in combination with the gravel pack.', '5.', 'The method of claim 1, wherein the polyhydroxycarboxylic acid is present as a polyhydroxycarboxylic acid fiber.', '6.', 'The method of claim 5, wherein the polyhydroxycarboxylic acid fiber has a length within the range of 100 μm to 20 mm.\n\n\n\n\n\n\n7.', 'The method of claim 1, wherein the polyhydroxycarboxylic acid is added at a concentration that ranges from about 0.5 ppb to 15 ppb.', '8.', 'A method comprising:\nrunning a sand control screen assembly to a selected depth within the uncased section of the wellbore to facilitate a gravel packing operation; and\nintroducing a gravel pack slurry comprising polyhydroxycarboxylic acid into the wellbore to facilitate gravel packing operations, wherein the polyhydroxycarboxylic acid is a polymer formed from one or more monomers selected from a group consisting of malic acid, lactic acid, gluconic acid, citric acid, mandelic acid, saccharic acid, mucic acid, and tartaric acid, wherein the polyhydroxycarboxylic acid hydrolyzes at a temperature ranging from about 150° F. to about 170° F.\n\n\n\n\n\n\n9.', 'The method of claim 8, wherein the polyhydroxycarboxylic acid is emplaced in the wellbore in combination with the gravel pack slurry.', '10.', 'The method of claim 8, wherein the ratio of the polyhydroxycarboxylic acid to gravel additive ranges from about 5:1 to 1:5 by total weight.', '11.', 'The method of claim 8, wherein the polyhydroxycarboxylic acid is added at a concentration that ranges from about 0.5 ppb to 15 ppb.\n\n\n\n\n\n\n12.', 'The method of claim 8, wherein the polyhydroxycarboxylic acid is present as a polyhydroxycarboxylic acid fiber.', '13.', 'The method of claim 12, wherein the polyhydroxycarboxylic acid fiber has a length within the range of 100 μm to 20 mm.\n\n\n\n\n\n\n14.', 'The method of claim 8, wherein the polyhydroxycarboxylic acid is present as a polyhydroxycarboxylic acid particulate.'] | ['No Captions Available'] |
US11078743 | System and methodology for providing bypass through a swellable packer | May 16, 2019 | Saikumar Mani, Nabil Batita, Nikhil Nair, Joao Mendonca, Oloruntoba Ogunsanwo | Schlumberger Technology Corporation | NPL References not found. | 5875852; March 2, 1999; Floyd; 6325144; December 4, 2001; Turley; 6481496; November 19, 2002; Jackson; 7836960; November 23, 2010; Patel et al.; 8082990; December 27, 2011; Lovell et al.; 8235108; August 7, 2012; Lemme et al.; 8322415; December 4, 2012; Loretz et al.; 8794310; August 5, 2014; Allen et al.; 9243473; January 26, 2016; Yang et al.; 20020074116; June 20, 2002; Millar; 20030079878; May 1, 2003; Pramann, II; 20050257928; November 24, 2005; Arizmendi; 20110056706; March 10, 2011; Brooks; 20150354315; December 10, 2015; Windegaard; 20170037710; February 9, 2017; Richards | Foreign Citations not found. | ['A swellable packer comprises an elastomeric element and a mandrel extending through the elastomeric element.', 'The elastomeric element is formed of an elastomer which undergoes swelling following contact with certain types of well fluids.', 'The elastomeric element is sealed with respect to the mandrel and may be located along an undercut region of the mandrel.', 'Additionally, the mandrel has an interior passage extending longitudinally through the mandrel and offset with respect to an external geometry of the mandrel.', 'Accordingly, the mandrel is effectively constructed with relatively thicker and thinner wall sections.', 'The thicker wall section or sections accommodates at least one bypass conduit which extends longitudinally through the mandrel.'] | ['Description\n\n\n\n\n\n\nBACKGROUND', 'In many well applications, a well string is deployed downhole into a wellbore.', 'For some downhole applications, swellable packers may be deployed along the well string to enable isolation of a section or sections of the wellbore.', 'Swellable packers utilize an elastomeric packer element disposed about a base pipe.', 'The elastomeric packer element may be formed with a polymer which swells in the presence of well fluids to form a seal with the surrounding wellbore surface.', 'Swellable packers may be used in various well applications ranging from well construction to well completion in both open hole and cased hole wells.', 'Depending on the type of equipment employed in the well string, control lines may be run downhole.', 'To bypass a swellable packer, slits are formed in the elastomeric packer element and the control lines are inserted through the slits.', 'As the elastomeric packer element swells it closes the slit around each control line to form a seal with the control line.', 'However, the presence of these bypass slits substantially reduces the pressure holding capacity of the swellable packer.', 'SUMMARY', 'In general, a system and methodology are provided to facilitate sealing along a well string.', 'According to an embodiment, a swellable packer comprises an elastomeric element and a mandrel extending through the elastomeric element.', 'The elastomeric element is formed of an elastomer which undergoes swelling following contact with certain types of well fluids.', 'The elastomeric element is sealed with respect to the mandrel and may be located along an undercut region of the mandrel.', 'Additionally, the mandrel has an interior passage extending longitudinally through the mandrel and offset with respect to an external geometry of the mandrel.', 'Accordingly, the mandrel is effectively constructed with relatively thicker and thinner wall sections.', 'The thicker wall section or sections accommodates a plurality of bypass conduits which extend longitudinally through the mandrel.', 'However, many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nCertain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements.', 'It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:\n \nFIG.', '1\n is an illustration of a well string deployed in a borehole, the well string comprising at least one swellable packer, according to an embodiment of the disclosure;\n \nFIG.', '2\n is an orthogonal view of an example of a swellable packer, according to an embodiment of the disclosure;\n \nFIG.', '3\n is a cross-sectional view of an example of a swellable packer taken generally along a longitudinal axis of the swellable packer, according to an embodiment of the disclosure;\n \nFIG.', '4\n is a cross-sectional view showing a portion of the swellable packer illustrated in \nFIG.', '3\n, according to an embodiment of the disclosure;\n \nFIG.', '5\n is another cross-sectional illustration showing a portion of an example of a swellable packer, according to an embodiment of the disclosure;\n \nFIG.', '6\n is an end view of an example of a mandrel which may be used in a swellable packer, according to an embodiment of the disclosure; and\n \nFIG.', '7\n is a side view of a portion of the mandrel illustrated in \nFIG.', '6\n, according to an embodiment of the disclosure.', 'DETAILED DESCRIPTION', 'In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure.', 'However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.', 'The disclosure herein generally involves a system and methodology which facilitate sealing along a borehole while accommodating one or more control lines or other structures such as shunt tubes.', 'According to an embodiment, a swellable packer comprises a swellable elastomeric element and a mandrel, e.g. a base pipe, extending through the elastomeric element.', 'The swellable packer may be positioned along a well string to facilitate sealing between the well string and a surrounding borehole wall, e.g. a cased or open hole wellbore wall.', 'The elastomeric element is formed of an elastomer which undergoes swelling following contact with certain types of well fluids, e.g. hydrocarbon-based fluids.', 'Additionally, the elastomeric element is sealed with respect to the mandrel and may be located along an undercut region of the mandrel.', 'For example, the elastomeric element may be adhered to the mandrel or otherwise sealed to the mandrel.', 'The undercut region may extend along an exterior of the mandrel for a substantial length of the elastomeric element, e.g. at least half the length of the elastomeric element.', 'The undercut enables increased volume of the elastomer and increased radial distance between the exterior of the mandrel and the exterior of the elastomeric element.', 'In some embodiments, the undercut region extends to the longitudinal ends of the elastomeric element.', 'Additionally, the mandrel has an interior passage extending longitudinally through the mandrel and offset with respect to an external geometry of the mandrel.', 'Accordingly, the mandrel is effectively constructed with relatively thicker and thinner wall sections.', 'The thicker wall section or sections accommodates at least one bypass conduit.', 'In various embodiments, the thicker wall section or sections accommodates a plurality of bypass conduits which extend longitudinally through the mandrel.', 'The mandrel may be formed of a metal material such that the bypass conduits extend through the metal material of the mandrel internally of the elastomeric element.', 'The number of bypass conduits which may be located within the mandrel wall may be governed by the eccentricity and size of the internal geometry of the mandrel along with the geometry, radial spacing, and angular spacing of the bypass conduits.', 'Referring generally to \nFIG.', '1\n, an example of a well system \n30\n is illustrated.', 'The well system \n30\n may comprise a well string \n32\n, e.g. a well completion string, deployed in a wellbore \n34\n or other type of borehole.', 'The wellbore \n34\n may be a vertical wellbore, a deviated wellbore, e.g. horizontal wellbore, or other suitably oriented wellbore formed in a geologic formation \n36\n.', 'By way of example, the geologic formation \n36\n may comprise hydrocarbon fluids such as oil and natural gas.', 'The illustrated well system \n30\n also comprises a swellable packer \n38\n which may be transitioned between a radially contracted position and a radially expanded position following sufficient exposure to specific types of well fluids, e.g. hydrocarbon-based fluids.', 'In \nFIG.', '1\n, the swellable packer \n38\n is illustrated in the radially expanded position in sealing engagement with a surrounding borehole wall \n40\n.', 'The well string \n32\n may comprise various numbers of swellable packers \n38\n and various other types of equipment, e.g. completion equipment.', 'Referring generally to \nFIG.', '2\n, an example of swellable packer \n38\n is illustrated.', 'In this embodiment, the swellable packer \n38\n comprises a mandrel \n42\n and an elastomeric element \n44\n.', 'The mandrel \n42\n extends through the elastomeric element \n44\n which is sealed, e.g. adhered or otherwise bonded, to the mandrel \n42\n.', 'The elastomeric element \n44\n is formed from a material, e.g. a complex polymer, which swells in the presence of certain types of fluid, e.g. well fluids, as with traditional swellable packers.', 'At least one communication line \n46\n is routed longitudinally through the material forming the mandrel \n42\n as explained in greater detail below.', 'By way of example, the communication line or lines \n46\n may comprise electrical lines, hydraulic control lines, shunt tubes, and/or other types of communication lines for communicating signals and/or fluid through the swellable packer \n38\n.', 'With additional reference to \nFIG.', '3\n, a cross-sectional illustration of the swellable packer \n38\n is provided.', 'As illustrated, the mandrel \n42\n has a mandrel wall \n48\n which forms an internal geometry \n50\n in the form of a longitudinal passage \n52\n extending longitudinally through the mandrel \n42\n.', 'By way of example, the internal geometry \n50\n and longitudinal passage \n52\n may have a circular cross-section which maintains a consistent diameter through the mandrel \n42\n.', 'In some embodiments, however, the internal geometry \n50\n and longitudinal passage \n52\n may have varying diameters and/or non-circular cross-sections.', 'The mandrel \n42\n also provides an external geometry \n54\n having a cross-sectional center offset from a cross-sectional center of the internal geometry \n50\n.', 'The internal geometry \n50\n/longitudinal passage \n52\n effectively becomes eccentrically located with respect to the external geometry \n54\n.', 'The eccentricity of the mandrel \n42\n establishes a thicker wall portion \n56\n of mandrel wall \n48\n relative to a thinner wall portion \n58\n, as further illustrated in \nFIG.', '4\n.', 'The thicker wall portion \n56\n provides room for a bypass conduit \n60\n, e.g. a plurality of bypass conduits \n60\n, formed within the mandrel wall \n48\n radially inward of elastomeric element \n44\n.', 'In other words, the bypass conduits \n60\n may be contained within the material, e.g. metal material, of which mandrel \n42\n is formed.', 'The bypass conduit or conduits \n60\n may be constructed to accommodate various types of communication lines \n46\n.', 'For example, individual bypass conduits \n60\n may be constructed to enable passage therethrough of an electrical control line or hydraulic control line.', 'In some embodiments, individual bypass conduits \n60\n may be constructed to provide a portion of the communication line \n46\n itself.', 'For example, a section of hydraulic line or shunt tube can be coupled to each end of a given bypass conduit \n60\n and the bypass conduit \n60\n can simply route fluid through the mandrel \n42\n of swellable packer \n38\n.', 'Depending on the parameters of a given application, various types of fittings \n62\n, e.g. connectors, may be used at the ends of each bypass conduit \n60\n to form a seal between the material of mandrel \n42\n and the corresponding communication line \n46\n.', 'In some embodiments, the fittings \n62\n may be in the form of wet connects or other types of connectors into which sections of communication line \n46\n may be coupled.', 'The number and arrangement of bypass conduits \n60\n and corresponding communication lines \n46\n may vary according to the parameters of an intended operation.', 'By way of example, the mandrel \n42\n and thicker wall portion (or portions) \n56\n may be constructed to accommodate 2 bypass conduits, 3 bypass conduits, 4 bypass conduits, or 5 or more bypass conduits \n60\n.', 'In some embodiments, end caps \n64\n may be secured to the exterior of mandrel \n42\n at longitudinal ends of elastomeric element \n44\n to protect and/or limit axial expansion of the elastomeric element \n44\n during swelling.', 'The end caps \n64\n may be secured to the mandrel \n42\n by an attachment mechanism \n66\n which may be in the form of setscrews \n68\n.', 'According to some embodiments, a protective shielding \n70\n also may be positioned at the longitudinal ends of elastomeric element \n44\n.', 'The protective shielding \n70\n may be used with end caps \n64\n or without end caps \n64\n, as illustrated in \nFIG.', '5\n.', 'Referring again to \nFIGS.', '4 and 5\n, the mandrel \n42\n also may comprise an undercut \n72\n formed along the exterior of mandrel \n42\n.', 'The undercut \n72\n provides a region of reduced outside diameter along a portion of the mandrel \n42\n so as to enable construction of elastomeric element \n44\n with a greater thickness and a greater volume of a swellable material \n74\n.', 'The undercut \n72\n may be a region which extends along an exterior of the mandrel \n42\n for a substantial length of the elastomeric element \n44\n.', 'Additionally, the undercut \n72\n may extend around the entire circumference of the mandrel \n42\n, although some embodiments may employ an undercut \n72\n which extends along a portion of the circumference.', 'Depending on various factors such as swellable packer size and pressure rating, the undercut \n72\n may extend at least 50% of the length of the elastomeric element \n44\n, at least 75% of the length of elastomeric element \n44\n, or at least 90% of the length of elastomeric element \n44\n.', 'In some embodiments, the undercut \n72\n provides a region of decreased mandrel diameter which extends to the longitudinal ends of the elastomeric element \n44\n, as illustrated in \nFIGS. 4 and 5\n.', 'It should be noted various types of couplers \n75\n, e.g. threaded ends or separate threaded couplers, may be used to connect swellable packer \n38\n into well string \n32\n.', 'Referring generally to \nFIGS.', '6 and 7\n, an embodiment of mandrel \n42\n illustrates the internal geometry \n50\n as offset with respect to the external geometry \n54\n.', 'In this example, the external geometry \n54\n of mandrel \n42\n has a cross-sectional center \n76\n offset from a cross-sectional center \n78\n of the internal geometry \n50\n to achieve a desired eccentricity.', 'The internal geometry \n50\n/longitudinal passage \n52\n effectively becomes eccentrically located in mandrel \n42\n with respect to the external geometry \n54\n.', 'A suitable offset distance or length \n80\n between cross-sectional centers \n76\n and \n78\n may be selected to establish desired packer parameters, such as wall thicknesses to accommodate a desired number of bypass conduits \n60\n.', 'As illustrated in \nFIG.', '6\n, the eccentric geometries may establish a sufficiently thicker wall portion \n56\n to accommodate a plurality of the bypass conduits \n60\n.', 'The bypass conduits \n60\n are sized and arranged according to the desired types of communication lines \n46\n.', 'It should be noted the cross-sectional configuration of the internal geometry \n50\n and the external geometry \n54\n may vary in size and shape.', 'In some embodiments, however, the external geometry \n54\n may be generally circular in cross-section and the internal geometry \n50\n may similarly be generally circular in cross-section.', 'In such an embodiment, the cross-sectional centers \n76\n, \n78\n are centers of the respective circulars and offset from each other the desired distance \n80\n.', 'Depending on the well application, one or more of the swellable packers \n38\n may be positioned along the well string \n32\n which may include various forms of downhole completions.', 'The bypass conduits \n60\n and corresponding communication lines \n46\n may be used for conducting electrical signals, for transmitting pressure signals, for enabling pumping of sand or gravel slurry, and/or for communicating other types of signals and/or materials past the swellable packer \n38\n.', 'The communication lines \n46\n may be routed through a plurality of the swellable packers \n38\n to traverse, for example, different production zones.', 'Because the bypass conduits \n60\n are formed through the metal material (or other suitable material) of mandrel \n42\n, the pressure holding capacity of the swellable packer is substantially greater than with traditional swellable packers.', 'The greater volume of material forming the elastomeric element \n44\n due to undercut \n72\n also enhances the effectiveness and pressure holding capability of the swellable packer \n38\n.', 'By maintaining the bypass conduit \n60\n outside of the internal geometry \n50\n/longitudinal passage \n52\n, communication lines \n46\n may be routed past the swellable packer \n38\n without affecting through-tubing intervention procedures.', 'Depending on the environmental parameters and other parameters concerning a given downhole operation, various numbers of swellable packers \n38\n may be employed along well string \n32\n.', 'Additionally, the size, configuration, and materials forming each elastomeric element \n44\n may be adjusted to achieve the desired swelling and pressure holding capability in a given environment and with given well fluids.', 'Similarly, the size, configuration, and materials used to construct each mandrel \n42\n may be selected according to the parameters of a given operation and environment.', 'The techniques for routing communication lines \n46\n through the corresponding bypass conduits \n60\n or for coupling communication lines \n46\n with the bypass conduits \n60\n may vary from one application and environment to another.', 'Similarly, the types and arrangements of communication lines \n46\n and corresponding bypass conduits \n60\n can be adjusted to accommodate a given operation.', 'Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.'] | ['1.', 'A system for use in a well, comprising:\na swellable packer having a mandrel and an elastomeric element bonded to the mandrel, the elastomeric element undergoing swelling and radial expansion following contact with certain types of fluid in a borehole;\nthe mandrel having a mandrel wall with an internal geometry in the form of a longitudinal passage of circular cross-section, the mandrel wall being thicker along a portion of a circumference of the mandrel to provide an external geometry having a cross-sectional center offset from an internal geometry cross-sectional center, the mandrel wall having a plurality of bypass conduits extending longitudinally through the portion, the mandrel further comprising an undercut region along an exterior of the mandrel wall to enable increased radial thickness of the elastomeric element, wherein the elastomeric element abuts a transition of the exterior of the mandrel wall to the undercut region.', '2.', 'The system as recited in claim 1, wherein the undercut region extends around the entire circumference of the mandrel.', '3.', 'The system as recited in claim 1, wherein the swellable packer is mounted along a well string deployed in the borehole.', '4.', 'The system as recited in claim 1, further comprising an electrical line extending through at least one bypass conduit of the plurality of bypass conduits.', '5.', 'The system as recited in claim 1, further comprising a hydraulic control line extending through at least one bypass conduit of the plurality of bypass conduits.', '6.', 'The system as recited in claim 1, further comprising a shunt tube extending through at least one bypass conduit of the plurality of bypass conduits.', '7.', 'The system as recited in claim 1, wherein the plurality of bypass conduits comprises two bypass conduits.', '8.', 'The system as recited in claim 1, wherein the plurality of bypass conduits comprises three bypass conduits.', '9.', 'The system as recited in claim 1, wherein the plurality of bypass conduits comprises four bypass conduits.', '10.', 'The system as recited in claim 1, wherein the plurality of bypass conduits comprises at least five bypass conduits.', '11.', 'The system as recited in claim 1, wherein the undercut region does not extend around the entire circumference of the mandrel.', '12.', 'A system for use in a well, comprising:\na swellable packer having:\nan elastomeric element formed of an elastomer which undergoes swelling following contact with certain types of well fluid; and\na mandrel extending through the elastomeric element and sealed with respect to the elastomeric element, the mandrel having an interior passage which is offset with respect to an external geometry of the mandrel such that the mandrel has a thicker wall section on one side of the mandrel relative to the other side of the mandrel, the thicker wall section containing a plurality of bypass conduits extending longitudinally through the mandrel, wherein the mandrel comprises an undercut region along an exterior of the mandrel and located between longitudinal ends of the elastomeric element, and wherein the elastomeric element abuts a transition of the exterior of the mandrel to the undercut region.', '13.', 'The system as recited in claim 12, wherein the undercut region extends around the entire circumference of the mandrel.', '14.', 'The system as recited in claim 12, further comprising an electrical line engaging at least one bypass conduit of the plurality of bypass conduits to enable transmission of electrical signals past the swellable packer.', '15.', 'The system as recited in claim 12, further comprising a hydraulic line engaging at least one bypass conduit of the plurality of bypass conduits to enable transmission of hydraulic fluid past the swellable packer.', '16.', 'The system as recited in claim 12, further comprising a shunt tube engaging at least one bypass conduit of the plurality of bypass conduits to enable transmission of fluid past the swellable packer.', '17.', 'A method, comprising:\nforming a mandrel with an internal geometry and an external geometry such that an internal geometry cross-sectional center is offset from an external geometry cross-sectional center;\nproviding the mandrel with an undercut region disposed along its exterior;\npositioning a swellable elastomeric element around the mandrel and along the undercut region, wherein the swellable elastomeric element abuts a transition of the exterior of the mandrel to the undercut region;\nsealing the swellable elastomeric element to the mandrel; and\nrouting a bypass conduit longitudinally through the mandrel externally of the internal geometry and radially inside of the swellable elastomeric element.', '18.', 'The method as recited in claim 17, wherein routing the bypass conduit comprises routing a plurality of bypass conduits.\n\n\n\n\n\n\n19.', 'The method as recited in claim 17, wherein forming comprises forming the internal geometry with a circular cross-section.', '20.', 'The method as recited in claim 19, wherein forming the internal geometry with a circular cross-section comprises maintaining a constant diameter of the circular cross-section along a longitudinal length of the mandrel.'] | ['FIG.', '1 is an illustration of a well string deployed in a borehole, the well string comprising at least one swellable packer, according to an embodiment of the disclosure;; FIG.', '2 is an orthogonal view of an example of a swellable packer, according to an embodiment of the disclosure;; FIG.', '3 is a cross-sectional view of an example of a swellable packer taken generally along a longitudinal axis of the swellable packer, according to an embodiment of the disclosure;; FIG.', '4 is a cross-sectional view showing a portion of the swellable packer illustrated in FIG.', '3, according to an embodiment of the disclosure;; FIG. 5 is another cross-sectional illustration showing a portion of an example of a swellable packer, according to an embodiment of the disclosure;; FIG.', '6 is an end view of an example of a mandrel which may be used in a swellable packer, according to an embodiment of the disclosure; and; FIG. 7 is a side view of a portion of the mandrel illustrated in FIG.', '6, according to an embodiment of the disclosure.'] |
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US11073009 | Drilling energy calculation based on transient dynamics simulation and its application to drilling optimization | Jun 29, 2016 | Wei Chen, Christopher Bogath, Richard John Harmer, Yani Dong, Chanhui Bin, Yuelin Shen, Sujian Huang | Schlumberger Technology Corporation | International Preliminary Report on Patentability for the equivalent International patent application PCT/CN2016/087548 dated Jan. 10, 2019.; Extended Search Report for the counterpart European patent application 16906613.1 dated Jan. 16, 2020.; Bailey, et al., “Development and Application of a BHA Vibrations Model,” International Petroleum Technology Conference held in Kuala Lumpur, Malaysia, Dec. 3-5, 2008.; Bailey, et al., “Managing Drilling Vibrations Through BHA Design Optimization,” Dec. 2010 SPE Drilling & Completion, pp. 458-471.; Bybee, “Drilling Vibrations Modeling and Field Validation,” JPT, Dec. 2008, pp. 73-75.; International Search Report and Written Opinion for the equivalent International patent application PCT/CN2016/087548 dated Mar. 27, 2017. | 4958960; September 25, 1990; Turner et al.; 7059427; June 13, 2006; Power et al.; 7139689; November 21, 2006; Huang; 7140452; November 28, 2006; Hutchinson; 20130087385; April 11, 2013; Pena; 20130146358; June 13, 2013; DiSantis; 20140129148; May 8, 2014; Harmer et al.; 20140158428; June 12, 2014; Boone et al.; 20150083493; March 26, 2015; Wassell | 2012/080812; June 2012; WO; 2016/060881; April 2016; WO | ['A method for drilling a well includes applying energy input to a drill string (31) by at least one of rotating the drill string (31) from surface and operating a drilling motor (41) disposed in the drill string (31) to operate a drill bit (2) at a bottom of the drill string (31); an amount of the applied energy not consumed in drilling formations caused by at least one of motion, deformation, and interaction of the drill string (31) is calculated; an amount of the applied energy used to drill formations below the drill bit (2) is calculated; and at least one drilling operating parameter is adjusted based on energy calculation before or during drilling operation.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates generally to the field of drilling subsurface wellbores.', 'More specifically, the disclosure relates to methods and apparatus for determining an amount of energy used to turn a drill string and/or sections thereof that is communicated to a drill bit used to drill through subsurface formations.', 'Calculations of energy loss may be used to aid drilling job planning, drilling job execution and drilling job post evaluation.', 'Drilling is a process in which supplied energy and gravity act on a drill string from the surface, and/or by certain types of drilling motors coupled within the drill string.', 'The energy is transferred through drill string, and is used to cut the formations at the bottom of the wellbore to extend its length.', 'Part of the energy input may be converted to drill string elastic strain/kinetic energy; other portions of the input energy may be dissipated as thermal energy generated by frictional torque and axial drag between the drill string and the wall of the wellbore.', 'From an energy point of view, drilling optimization is a process used to minimize the energy loss due to drilling dynamics and to make as full use as practical of the energy input to the drill string to drill the formations.', 'Drilling energy analysis methods known in the art include, for example, “Vybs” bottom hole assembly (BHA) analysis model and energy-based performance indices.', 'Descriptions of the foregoing may be found in Transactions of the International Petroleum Technology Conference (IPTC) Paper No., 12737-MS entitled, \nDevelopment and Application of a BHA Vibrations Model\n.', 'Other references include Society of Petroleum Engineers International (SPE) Paper No. 112650\n, Drilling Vibrations Modeling and Field Validation\n, and Paper No. 139426, entitled, \nManaging Drilling Vibrations Through BHA Design Optimization.', 'The methods described in the foregoing two SPE papers are based on a lumped-parameter model using the state vectors and transfer-function matrices.', 'The state vector is a complete description of BHA response at any given position at given time.', 'The total system response includes a static solution plus a dynamic perturbation about the static equilibrium state.', 'In the foregoing described methods, the response of only the BHA section and one stand of heavy weight drill pipe (HWDP) are simulated.', 'Two vibration excitation modes are utilized in the described methods: (1) flex mode wherein harmonic side force is applied at the drill bit, and the frequency is 1×, 2×, or 3× of input bit RPM, and (2) twirl mode, wherein identical mass eccentricity is applied at each model element.', 'The performance parameters generated by such methods include: \n \n \n \nBHA performance indices developed in the model;', 'BHA bending strain energy;\n \nTransmitted bending strain energy;\n \nCurvature index of BHA top-point; and\n \nContact force index.', 'U.S. Patent Application Publication No. 2014/0129148 entitled, Downhole determination of drilling state discloses using downhole measurements made by sensors in certain components of the BHA (accelerometer, magnetometer, and strain gauge) to calculate BHA strain and kinetic energy terms as follows: \n \n \n \nEnergy of axial motion and deformation;\n \nEnergy of rotational motion and deformation;\n \nEnergy of lateral motion and bending deformation; and wherein\n \nthe total energy per unit length of BHA is obtained by summing the energy terms in different directions, and the foregoing terms can be used to detect changes in the operating state of the drill string and/or BHA automatically.', 'SUMMARY\n \nOne aspect of the disclosure relates to a method for drilling a well.', 'A method according to this aspect of the disclosure includes applying energy to a drill string at at least one of a surface of the drill string and a motor disposed in the drill string to drive a drill bit at a bottom of the drill string.', 'An amount of the applied energy not consumed in drilling formations caused by deformation and motion of the drill string is calculated.', 'An amount of the applied energy used to drill formations below the drill bit is calculated.', 'At least one of the bit, a bottom hole assembly component, and at least one drilling operating parameter is selected or adjusted based on energy calculation before or during drilling operation.', 'Other aspects and advantages of methods according to the disclosure will be apparent from the description and claims which follow.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is a pictorial view of a wellbore drilling system.', 'FIG.', '2A\n shows a schematic representation of energy input to a drill string and main mechanisms by which such energy is consumed.\n \nFIG.', '2B\n shows various elements of a sample drill string operating in a wellbore to illustrate in more detail the mechanisms that consume the energy input to the drill string.\n \nFIG.', '3\n shows schematically how energy applied to the drill string is consumed by axial motion.\n \nFIG.', '4\n shows schematically how energy applied to the drill string is consumed by axially oriented rotation.\n \nFIG.', '5\n shows schematically how energy applied to the drill string is consumed by tilt of the drill string.\n \nFIG.', '6\n shows schematically how energy applied to the drill string may be consumed by various strain sustained by the drill string.\n \nFIG.', '7\n shows an example of parameters used in a model according to the present disclosure wherein all rotational energy is applied to the drill string from the surface.\n \nFIG.', '8\n shows graphs of simulated bit rotational speed (RPM), bit lateral acceleration and bit rate of penetration through formations using the parameters shown in \nFIG.', '7\n.\n \nFIG.', '9\n shows graphs of strain and kinetic energy when the drill string undergoes a state change from stick-slip motion to whirling motion.\n \nFIG.', '10\n shows a graph illustrating that during initial drilling, almost all the surface input energy is used to cut the rock although the bit has stick-slip motion.', 'After entering whirling mode, more of the input energy is lost due to the increased contact interactions between drill string and wellbore.\n \nFIG.', '11\n shows another graph including time averaged power wherein during initial drilling, almost all the surface energy input is used to cut the rock.', 'After entering whirling mode, more energy is lost due to the increased contact interactions between drill string and wellbore.', 'In this case, only about 40% energy input from surface is used for rock cutting during whirling mode.\n \nFIG.', '12\n shows graphs illustrating that drilling hard formations results in a lower RPM variation and higher lateral vibration.\n \nFIG.', '13\n shows graphs of a comparison of drilling two different formations.', 'Drilling hard formation shows much higher bending strain energy and translational kinetic energy.', 'Since bending and translational energies are calculated based on the entire BHA, it is possible to use the foregoing measured at the BHA as lateral vibration indices of the entire BHA.\n \nFIG.', '14\n shows graphs indicating that in terms of ratio of energy loss with reference to energy input, more energy is dissipated by wellbore wall contact interactions in hard rock drilling.', 'This matches the trend of lateral acceleration of the two different formation cases (more lateral acceleration means more wellbore contact and more energy loss).', 'FIG.', '15\n shows a schematic diagram of parameters to be modeled using an example embodiment according to the disclosure wherein a drilling motor is included in the drill string.\n \nFIG.', '16\n shows a graph of energy with reference to motor speed and drill string surface rotation speed.', 'Energy losses are shown in the graph.\n \nFIG.', '17\n shows a graph of the case wherein RPM=50, WOB=10,000 lbs., drilling fluid flow is 350 gallons per minute.', 'Energy is calculated as Power (5 sec moving average).', 'Calculated energy loss is about 12% of the total energy input (surface+drilling motor).', 'FIG.', '18\n shows a flow chart of an example embodiment of a method according to the present disclosure.\n \nFIG.', '19\n shows an example computer system that may be used in some embodiments.', 'DETAILED DESCRIPTION\n \nIn \nFIG.', '1\n, a drilling unit or “drilling rig” is designated generally at \n11\n.', 'The drilling rig \n11\n in \nFIG.', '1\n is shown as a land-based drilling rig.', 'However, as will be apparent to those skilled in the art, the examples described herein will find equal application on marine drilling rigs, such as jack-up rigs, semisubmersibles, drill ships, and the like.', 'The drilling rig \n11\n includes a derrick \n13\n that is supported on the ground above a rig floor \n15\n.', 'The drilling rig \n11\n includes lifting gear, which includes a crown block \n17\n mounted to derrick \n13\n and a traveling block \n19\n.', 'The crown block \n17\n and the traveling block \n19\n are interconnected by a cable \n21\n that is driven by draw works \n23\n to control the upward and downward movement of the traveling block \n19\n.', 'The draw works \n23\n may be configured to be automatically operated to control rate of drop or release of the drill string into the wellbore during drilling.', 'One non-limiting example of an automated draw works release control system is described in U.S. Pat.', 'No. 7,059,427 issued to Power et al. and incorporated herein by reference.', 'The traveling block \n19\n carries a hook \n25\n from which may be suspended a top drive \n27\n.', 'The top drive \n27\n supports a drill string, designated generally by the numeral \n31\n, in a wellbore \n33\n.', 'According to an example implementation, the drill string \n31\n may in signal communication with and mechanically coupled to the top drive \n27\n through an instrumented sub \n29\n.', 'As will be described in more detail, the instrumented top sub \n29\n may include sensors (not shown separately) that provide drill string torque information.', 'Other types of torque sensors may be used in other examples, or proxy measurements for torque applied to the drill string \n31\n by the top drive \n27\n may be used, non-limiting examples of which may include electric current or hydraulic fluid flow drawn by a motor (not shown) in the top drive.', 'A longitudinal end of the drill string \n31\n includes a drill bit \n2\n mounted thereon to drill the formations to extend (drill) the wellbore \n33\n.', 'The top drive \n27\n can be operated to rotate the drill string \n31\n in either direction, as will be further explained.', 'A load sensor \n26\n may be coupled to the hook \n25\n in order to measure the weight load on the hook \n25\n.', 'Such weight load may be related to the weight of the drill string \n31\n, friction between the drill string \n31\n and the wellbore \n33\n wall and an amount of the weight of the drill string \n31\n that is applied to the drill bit \n2\n to drill the formations to extend the wellbore \n33\n.', 'The drill string \n31\n may include a plurality of interconnected sections of drill pipe \n35\n a bottom hole assembly (BHA) \n37\n, which may include stabilizers, drill collars, and a suite of measurement while drilling (MWD) and or logging while drilling (LWD) instruments, shown generally at \n51\n.', 'A steerable drilling motor \n41\n may be connected proximate the bottom of BHA \n37\n.', 'The steerable drilling motor \n41\n may be any type known in the art for rotating the drill bit \n2\n and/or selected portions of the drill string \n31\n and to enable change in trajectory of the wellbore during slide drilling (explained in the Background section herein) or to perform rotary drilling (also explained in the Background section herein).', 'Example types of drilling motors include, without limitation, positive displacement fluid operated motors, turbine fluid operated motors, electric motors and hydraulic fluid operated motors.', 'The present example steerable drilling motor \n41\n may be operated by drilling fluid flow.', 'Drilling fluid may be delivered to the drill string \n31\n by mud pumps \n43\n through a mud hose \n45\n.', 'In some examples, pressure of the drilling mud may be measured by a pressure sensor \n49\n.', 'During drilling, the drill string \n31\n is rotated within the wellbore \n33\n by the top drive \n27\n, in a manner to be explained further below.', 'As is known in the art, the top drive \n27\n is slidingly mounted on parallel vertically extending rails (not shown) to resist rotation as torque is applied to the drill string \n31\n.', 'During drilling, the bit \n2\n may be rotated by the steerable drilling motor \n41\n, which in the present example may be operated by the flow of drilling fluid supplied by the mud pumps \n43\n.', 'Although a top drive rig is illustrated, those skilled in the art will recognize that the present example embodiment may also be used in connection with drilling systems in which a rotary table and kelly are used to apply torque to the drill string \n31\n at the surface.', 'Drill cuttings produced as the bit \n2\n drills into the subsurface formations to extend the wellbore \n33\n are carried out of the wellbore \n33\n by the drilling mud as it passes through nozzles, jets or courses (none shown) in the drill bit \n2\n.', 'Although a steerable motor is shown in \nFIG.', '1\n, in some embodiments, no drilling motor may be used, or a “straight” motor (one that is not intended to alter the wellbore trajectory) may be used to equal effect.', 'Signals from the pressure sensor \n49\n, the hookload sensor \n26\n, the instrumented top sub \n29\n and from an MWD/LWD system or steering tool \n51\n (which may be communicated using any known wellbore to surface communication system), may be received in a control unit \n48\n.', 'The control unit \n48\n may have a general purpose programmable computer (not shown separately) or may communicate with a different computer or computer system located remotely from the drilling rig \n11\n for data processing as will be further explained below.', 'In operating the drilling system shown in \nFIG.', '1\n, certain operating parameters may be controlled by the drilling system operator (the driller).', 'Such parameters include the hookload, the drill string RPM applied at surface, whether by the top drive as illustrated or by a rotary table.', 'The drilling rig mud pump flow rate may also be controlled by the driller.', 'If a directional drilling motor is used, the “toolface” angle (direction of a bend in the housing of such motor) may also be controlled by the driller.', 'The foregoing may be referred to as “drilling operating parameters.”', 'The response of the drill string (including various modes of vibration) and the drill bit in drilling formations may be referred to as “drilling response parameters.”', 'In some embodiments, as will be further explained, one or more drilling operating parameters may be adjusted by the driller in order to optimize the amount of applied energy that is consumed by drilling formations, while minimizing the amount of energy dissipated in drill string actions that do not transfer energy to drilling the formations.', 'While the example embodiment of a drilling system shown in \nFIG.', '1\n applies energy to the drill string in the form of rotational energy (whether by rotating the drill string at the surface and/or operating a rotary-type drilling motor disposed in the drill string, methods according to the present disclosure are not limited to applying and using rotational energy in the drill string and/or drill bit.', 'Other types of drilling systems and drill bits include, for example, and without limitation, percussion bits and percussion motors.', 'A non-limiting example of an hydraulically powered percussion motor and associated drill bit are disclosed in U.S. Pat.', 'No. 4,958,960 issued to Cyphelly.', 'Having explained a drilling system that may be used in some embodiments, methods according to the present disclosure that may be used to calculate: (i) an amount of the input energy that is actually expended in drilling through formations; and (ii) the amount of the total energy input is dissipated in various modes which do not contribute to extension of the wellbore.', 'Consider the drill string as a dynamic system.', 'System energy input may be from a surface top drive (or kelly/rotary table as explained with reference to \nFIG.', '1\n) and/or a drilling motor disposed in the drill string.', 'Effective use of the input energy is to drill and remove the formation (i.e., lengthening the wellbore).', 'However, some of all of the input energy may be dissipated due to shock, vibration and frictional contact between the drill string and the wall of the wellbore.', 'The purpose of drilling optimization according to the present disclosure is to minimize the energy loss caused by, e.g., and without limitation the foregoing interactions of the drill string.', 'The foregoing is illustrated schematically in \nFIG.', '2A\n in the general sense.', 'FIG.', '2B\n shows a schematic illustration of the various interactions between the drill string and the wellbore to better define the parameters which cause loss of energy applied to the drill string that would ideally be used to drill the formations.', 'The input energy to the entire drill string is shown at the rig (top drive or rotary table).', 'Additional energy may be input proximate the BHA using a drilling motor as shown in \nFIG.', '2B\n.', 'Sources of energy consumption include drilling the formations, indicated by Bit/Rock interaction in \nFIG.', '2B\n.', 'Energy losses, i.e., energy not used in drilling the formation may result from Elastic strain energy (ε, σ) due to bending moment, torque, and axial force, contact between the wall of the wellbore and the drill string (which may cause both rotational and longitudinal friction).', 'Kinetic energy of axial motion of the drill string (\nFIG.', '3\n), rotation of the drill string (\nFIG.', '4\n), tilt motion of the drill string (\nFIG.', '5\n) and lateral motion of the drill string (\nFIG.', '3\n).', 'In a method according to the present disclosure, the entire drill string may be “meshed” into a finite element analysis (FEA) program of types well known in the art.', "The mesh size is a matter of discretion for the system user or designer and may be selected to provide results to a size range consistent with the user's or designer's objectives.", 'One example of such program as applied to dynamic drill string analysis is disclosed in U.S. Pat.', 'No. 7,139,689 issued to Huang and incorporated herein by reference.', 'First, the energy that is input to the drill string may be calculated based on hookload (suspended drill string weight in the drilling rig), on torque applied by the top drive (or rotary table) and torque applied by the drilling motor (if used).', 'The work (energy input) done by top drive or rotary table torque (STOR) may be defined by the expression” \n \nW\nSTOR\n=∫STOR·\nd\n(REV\ntable\n)', '(1) \n wherein REV\ntable \nrepresents the surface rotation revolution imparted to the drill string.', 'The work by hookload may be defined as: \n \nW\nHL\n=−∫HookLoad·\nd\n(MD)\u2003\u2003(2) \n wherein MD is the measured depth of drill string, and the negative sign indicates that the direction of increased measured depth is opposite to the direction of hookload.', 'The work by net drill string weight may be represented by: \n \nW\nWT\n=∫[∫\nWT\nDS\n(\nx\n)·cos(\nInc\n(\nx\n))·\ndx\n]·\nd\n(MD)\u2003\u2003(3) \n \nwhere WT\nDS\n(x) is the wet weight distribution of drill string versus the distance x, Inc(x) is the inclination of drill string from vertical versus the distance x.', 'The surface weight on bit (SWOB) may be determined by the expression: \n SWOB=∫\nWT\nDS\n(\nx\n)·cos(\nInc\n(\nx\n))·\ndx\n−HookLoad\u2003\u2003(4)', 'The total energy applied to the drill string from the surface may be expressed as: \n \nW\ninput\n=W\nSTOR', '+W\nHL\n+W\nWT\n=∫STOR·\nd\n(REV\ntable\n)', '+∫SWOB·\nd\n(MD)\u2003\u2003(5)', 'If a drilling motor is used, its energy applied to that portion of the drill string below the axial position of the drilling motor, in the case of a positive displacement motor, may be calculated by the expression: \n \nW\ninput_PDM\n=∫P\ndiff\n·dQ\n\u2003\u2003(6) \n wherein P\ndiff \nis the pressure drop cross the motor, and Q the flow volume passing the motor.', 'Corresponding expressions for energy input from a drilling motor that is a turbine type are known in the art.', 'When both surface rotation of the drill string and a motor are used, the total energy applied to the drill string will be the sum of Eqs.', '(5) and (6).', 'It will be appreciated that by using FEA transient dynamics simulation, each discrete time interval will have the foregoing parameters calculated; the integral sign is intended to represent that the total energy is the sum of the energy generated within each discrete time interval in transient dynamics simulation.', 'From the transient dynamics simulation, the axial displacement, rotational revolution of top node (representing surface), surface weight-on-bit, and surface torque at the discrete time point t\nn \nare output and represented by ux\ntop\n(t\nn\n), REV\ntable\n(t\nn\n), SWOB(t\nn\n), and STOR(t\nn\n) respectively.', 'One can calculate the surface energy input to drill string using the classic trapezoidal numerical integration method.', 'W\n \ninput\n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)', '=\n \n \n \n \n∑\n \n \ni\n \n=\n \n \n1\n \n\u2062\n \n…\n \n\u2062\n \n \n \n \n\u2062\n \nN\n \n \n \n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \nSWOB\n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n+\n \n \nSWOB\n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n·\n \n \n⌊\n \n \n \n \nux\n \ntop\n \n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n-\n \n \n \nux\n \ntop\n \n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n⌋\n \n \n \n2\n \n \n \n+\n \n \n \n∑\n \n \ni\n \n=\n \n \n1\n \n\u2062\n \n…\n \n\u2062\n \n \n \n \n\u2062\n \nN\n \n \n \n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \nSTOR\n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n+\n \n \nSTOR\n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n·\n \n \n[\n \n \n \n \nREV\n \ntop\n \n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n-\n \n \n \nREv\n \ntop\n \n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n \n2\n \n \n \n \n \n \n \n \n(\n \n7\n \n)', 'Here, W\ninput\n(t\nN\n) is the surface energy input at time t\nN\n.', 'Following the same procedure, one can calculate the motor input to drill string as:\n \n \n \n \n \n \n \n \n \n \n \n \nW\n \n \ni\n \n\u2062\n \nnput\n \n\u2062\n \n_\n \n\u2062\n \nPDM\n \n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n=\n \n \n \n∑\n \n \ni\n \n=\n \n \n1\n \n\u2062\n \n…\n \n\u2062\n \n \n \n \n\u2062\n \nN\n \n \n \n \n \n \n \n\u2062\n \n \n \n \n⌊\n \n \n \n \nP\n \ndiff\n \n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)', '+\n \n \n \nP\n \ndiff\n \n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n⌋\n \n \n·\n \n \n[\n \n \n \nQ\n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n-\n \n \nQ\n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n \n2\n \n \n \n \n \n \n \n(\n \n8\n \n)\n \n \n \n \n \n \n \n Here, W\ninput_PDM\n(t\nn\n), P\ndiff\n(t\nn\n), and Q(t\nn\n) are motor energy input, motor differential pressure, and flow volume at time tn.', 'Once the total energy applied to the drill string is calculated, various parameters that consume energy (including that used in drilling formations) may be calculated so as to enable determining how the input energy is distributed.', 'Reaction axial force at the drill bit (DWOB) and torque at the drill bit (DTOB) are generated as bit cuts the rock.', 'Energy used by drilling formations equals to the work done by the DWOB and DTOB as in the following expression:', 'W\ndrilling\n=∫DWOB·d\n(MD\nbit\n)+∫\nDTOB·d\n(REV\nbit\n)\u2003\u2003(9) \n wherein REV\nbit \nis the rotation revolution of bit, and MD\nbit \nis the axial drill ahead distance at bit.', 'The integration can be also evaluated using the trapezoidal numerical integration method based on the transient dynamics simulation outputs.', '', 'W\n \ndrilling\n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n=\n \n \n \n \n∑\n \n \ni\n \n=\n \n \n1\n \n\u2062\n \n…\n \n\u2062\n \n \n \n \n\u2062\n \nN\n \n \n \n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \nDWOB\n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n+\n \n \nDWOB\n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n·\n \n \n[\n \n \n \n \nux\n \nbit\n \n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n-\n \n \n \nux\n \nbit\n \n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n \n2\n \n \n \n+\n \n \n \n∑\n \n \ni\n \n=\n \n \n1\n \n\u2062\n \n…\n \n\u2062\n \n \n \n \n\u2062\n \nN\n \n \n \n \n \n \n \n\u2062\n \n \n \n \n[\n \n \n \nDTOB\n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n+\n \n \nDTOB\n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n·\n \n \n[\n \n \n \n \nREV\n \nbit\n \n \n\u2061\n \n \n(\n \n \nt\n \ni\n \n \n)\n \n \n \n-\n \n \n \nREV\n \nbit\n \n \n\u2061\n \n \n(\n \n \nt\n \n \ni\n \n-\n \n1\n \n \n \n)\n \n \n \n \n]\n \n \n \n2\n \n \n \n \n \n \n \n \n(\n \n10\n \n)\n \n \n \n \n \n \n \n wherein W\ndrilling\n(t\nn\n), DWOB(t\nn\n), DTOB(t\nn\n), ux\nbit\n(t\nn\n), and REV\nbit\n(t\nn\n) are rock drilling energy, axial force on bit, torque on bit, bit axial displacement, and bit rotational revolution at time t\nn \nrespectively.', 'The strain energy is mechanical energy stored in an elastic material upon deformation caused by mechanical loading.', 'The strain energy may be expressed as: \n \nU\nStrain\n=½∫εσ\ndV\n\u2003\u2003(11)', 'For a drill string, the strain energy can be decomposed into three parts: (i) torsional strain energy resulting from torque; (ii) bending strain energy caused by bending moment; (iii) tensile strain energy caused by axial force.', 'The shear strain (energy) due to shear force is negligible as predicted by the Euler-Bernoulli theory.', 'Consider a beam with uniform cross section.', 'The foregoing strain energy components may be calculated according to the respective formulas shown in \nFIG.', '6\n.', 'For axial loading, the strain energy may be calculated by the expression:\n \n \n \n \n \n \n \n \n \nU\n \n \nSE\n \n\u2062\n \n_\n \n\u2062\n \nAxial\n \n \n \n=\n \n \n \n \nP\n \n2\n \n \n\u2062\n \nL\n \n \n \n2\n \n\u2062\n \n \n \n \n\u2062\n \nAE\n \n \n \n \n \n \n \n(\n \n12\n \n)\n \n \n \n \n \n \n \n wherein P is axial force, L the beam length, A the cross section area, and E is elastic modulus.', 'Torsional strain energy may be calculated by the expression: \n \n \n \n \n \n \n \n \n \nU\n \n \nSE\n \n\u2062\n \n_', '\u2062\n \nTor\n \n \n \n=\n \n \n \n \nT\n \n2\n \n \n\u2062\n \nL\n \n \n \n2\n \n\u2062\n \n \n \n \n\u2062\n \n \nGI\n \nx\n \n \n \n \n \n \n \n \n(\n \n13\n \n)\n \n \n \n \n \n \n \n wherein T is the externally applied torque, G the shear modulus, and I\nx \nthe area moment of inertia about the beam axis.', 'and bending strain energy may be calculated by the expression: \n \n \n \n \n \n \n \n \n \nU\n \n \nSE\n \n\u2062\n \n_', '\u2062\n \nBending\n \n \n \n=\n \n \n \n \nM\n \n2\n \n \n\u2062\n \nL\n \n \n \n2\n \n\u2062\n \n \n \n \n\u2062\n \n \nEI\n \nyz\n \n \n \n \n \n \n \n \n(\n \n14\n \n)', 'Wherein M is the applied bending moment, and I\nyz \nis the bending moment of inertia.', 'In numerical method (FEA) mentioned in this disclosure, the drill string is meshed using beam elements.', 'For each beam element, the foregoing strain energy parameters are calculated using Eq.', '(12-14).', 'The total strain energy of drill string are the sum of strain energy of each mesh element.', 'U\n \nStraint\n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n=\n \n \n \n∑\n \n \ni\n \n=\n \n \nall\n \n\u2062\n \n \n \n \n\u2062\n \nele\n \n \n \n \n \n \n \n\u2062\n \n \n[\n \n \n \n \n \n \n \nP\n \ni\n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n2\n \n \n\u2062\n \n \nL\n \ni\n \n \n \n \n2\n \n\u2062\n \n \nA\n \ni\n \n \n\u2062\n \nE\n \n \n \n+\n \n \n \n \n \n \nT\n \ni\n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n2\n \n \n\u2062\n \n \nL\n \ni\n \n \n \n \n2\n \n\u2062\n \n \nI\n \n \nx\n \n,\n \ni\n \n \n \n\u2062\n \nG\n \n \n \n+\n \n \n \n \n \n \nM\n \ni\n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n2\n \n \n\u2062\n \n \nL\n \ni\n \n \n \n \n2\n \n\u2062\n \n \nI\n \n \nyz\n \n,\n \ni\n \n \n \n\u2062\n \nE\n \n \n \n \n]\n \n \n \n \n \n \n \n(\n \n15\n \n)\n \n \n \n \n \n \n \n Here, U\nstrain\n(t\nN\n) is the total strain energy at time t\nN\n.', 'P\ni\n(t\nN\n), T\ni\n(t\nN\n), and M\ni\n(t\nN\n) are the axial force, torque, and bending moment on i-th FEA beam element at time t\nN\n.', 'A\ni\n, I\nx,i\n, and I\nyz,i \nare cross section area, area moment of inertia, and bending moment of inertia of i-th FEA beam element.', 'Kinetic energy is the energy that an object possesses due to its motion.', 'The kinetic energy may be decomposed into a translation component and a rotary component.', 'The foregoing kinetic energy components are illustrated with formulas for calculating them, respectively, in \nFIGS.', '3 and 4\n.', 'For each FEA beam element, kinetic energy of axial or lateral translational motion may be calculated by the expression: \n \nU\nKTran\n=½\nm|{right arrow over (v)}|\n2\n\u2003\u2003(16)', 'Here, m is the mass of the beam element, and v the translational velocity vector of mass center of element.', 'Axial rotational kinetic energy may be calculated by the expression: \n \nU\nKRot\n=½\nJ\nx\nω\n2\n\u2003\u2003(17)', 'Here, J\nx \nis the polar mass moment of inertia of the beam element, and co the axial rotation speed.', 'Kinetic energy used to tilt the axis of one FEA beam element is illustrated with a formula in \nFIG.', '5\n.', 'The tilt rotation kinetic energy may be calculated by the expression: \n \nU\nKRotTilt\n=½\nJ\nyz\nω\ntilt\n2\n\u2003\u2003(18) \n wherein J\nyz \nis the mass moment of inertia about axis located at beam center and perpendicular to beam axis, and ω\ntilt \nthe tilt rotation speed.', 'The total kinetic energy of drill string are the sum of kinetic energy calculated on each FEA element.', 'U\n \nKinetic\n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n=\n \n \n \n∑\n \n \ni\n \n=\n \n \nall\n \n\u2062\n \n \n \n \n\u2062\n \nele\n \n \n \n \n \n \n \n\u2062\n \n \n[\n \n \n \n \nU\n \n \nKTran\n \n,\n \ni\n \n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n+\n \n \n \nU\n \n \nKRot\n \n,\n \ni\n \n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n+\n \n \n \nU\n \n \nKRotTilt\n \n,\n \ni\n \n \n \n\u2061\n \n \n(\n \n \nt\n \nN\n \n \n)\n \n \n \n \n]\n \n \n \n \n \n \n \n(\n \n19\n \n)\n \n \n \n \n \n \n \n Here, U\nKinetic\n(t\nN\n) is the total kinetic energy at time t\nN\n.', 'U\nKTran,i\n(t\nN\n), U\nKRot,i\n(t\nN\n), and U\nKRotTilt,i\n(t\nN\n) are the translational, axial rotational, and tilt rotational kinetic energy of i-th FEA beam element at time t\nN\n.', 'Energy loss in the drilling process is defined as the energy consumed by the work done by contact friction and all types of damping mechanisms (like contact restitution and material damping).', 'Considering the principle of conservation of energy, the energy loss W\nloss\n(t\nN\n) at time t\nN \ncan be expressed as: \n \nW\nloss\n(\nt\nN\n)\nW\ninput\n(\nt\nN\n)+\nW\ninput_PDM\n(\nt\nN\n)−\nW\ndrilling\n(\nt\nN\n)−\nU\nStrain\n(\nt\nN\n)−\nU\nKinetic\n(\nt\nN\n)\u2003\u2003(20)', 'An example set of calculations using a method according to the present disclosure may be better understood with reference to \nFIG.', '7\n.', 'A drill string is illustrated schematically at \n120\n.', 'The drill string has selected diameter (internal and external), selected weight, selected moment of inertia, selected elastic properties and a drill bit at a bottom end thereof.', 'Components of the BHA and their respective mechanical properties are shown at \n122\n.', 'Arrangement of cutting elements and other mechanical properties of the drill bit are shown at \n124\n.', 'Drilling operating parameters (weight on bit, drill string rotational speed) used in the calculations are shown at \n126\n.', 'Mechanical interaction properties between the formation (wellbore) and the drill string are shown at \n128\n.', 'Finally at \n130\n, properties of the formation (rock) being drilled are illustrated.', 'The present example simulation was conducted for 109 revolutions of the drill string.', 'It will be appreciated that any other simulation may be performed for more or fewer drill string rotations as the user may find desirable.', 'Because all of the forces acting on each meshed element of the drill string are calculated, a simulation conducted according to the present disclosure can also calculate the drill string mode of motion, e.g., and without limitation, normal rotary drilling with determinable contact points/lengths between the drill string and the wellbore wall, stick slip motion, lateral vibration of the drill string and/or BHA, whirling motion and axial vibration.', 'As will be explained below, the mode of motion may have a substantial effect on the amount of total applied energy that is ultimately consumed by drilling formations, rather than being dissipated by one or more of the above described mechanisms.', 'Results of the above simulation are shown graphically in \nFIG.', '8\n.', 'FIG.', '8\n includes graphs of bit RPM, lateral acceleration on the bit and the rate of drilling the formation (rate of penetration—ROP).', 'It may be observed in \nFIG.', '8\n that at about 16 seconds, the drill string movement mode changes from “stick-slip” (wherein the drill string becomes momentarily stuck in the wellbore and subsequently is freed to rotate) to “backward whirl” (wherein the axis of the drill string precesses in a direction opposite the rotation of the drill string) and correspondingly consumes energy by frictional contact with the wellbore wall.', 'It may be observed that the ROP drops substantially when the movement mode changes to backward whirl.', 'FIG.', '9\n shows graphs of both strain and kinetic energy for the same set of conditioned used to generate the graphs shown in \nFIG.', '8\n.', 'During stick-slip, bending strain energy and translation kinetic energy terms are negligible compared to torsional strain energy and axial rotation kinetic energy.', 'As whirling begins, bending strain energy and translation kinetic energy increase dramatically, and oscillation of torsional strain and kinetic energy substantially vanish because the bit RPM becomes stable.\n \nFIG.', '10\n shows a graph that illustrates during initial drilling, almost all the surface energy input is used to drill the formation.', 'After entering whirling mode, more energy is lost due to the increased contact interactions between the drill string and the wellbore.\n \nFIG.', '11\n shows a graph or applied and consumed power for the simulation shown with reference to \nFIG.', '9\n.', 'As may be observed in \nFIG.', '11\n, during initial drilling, almost all the surface energy input is used to drill the formation.', 'After entering whirling mode, more energy is lost due to the increased contact interactions between drill string and wellbore.', 'In this case, only about 40% energy input from surface is used for formation drilling in whirl mode.', 'It will be appreciated that while stick-slip drilling results in much higher transfer of energy applied to the drill string into drilling formation, stick-slip drilling should be carefully monitored for excessive buildup of torque in the drill string and its sudden release.', 'U.S. Pat.', 'No. 7,140,452 issued to Hutchinson discloses how under certain circumstances, torsional stick-slip may result in the released torque causing certain drill string components to rotationally accelerate such that the breaking torque of threaded connections is exceeded.', 'When selecting drilling operating parameters for use in a method according to the present disclosure, maximum rotational acceleration on torsional release of any part of the drill string should be determined, such that the breaking torque is not exceeded.', 'FIG.', '12\n shows a comparison of results obtained for hard formations (designated UL_3000) as contrasted with softer formations (designated WE_3000).', 'From the graphed results, it may be readily determined that harder formations tend to have higher lateral vibration on the drill bit and lower bit RPM variation for the used set of drilling operating parameters.', 'FIG.', '13\n shows graphs of bending strain energy (SE) and translational kinetic energy (KE) when drilling hard formations (UL_3000) as contrasted with softer formations (WL_3000).', 'Drilling hard formation (UL_3000) shows much higher bending strain energy and translational kinetic energy.', 'Since bending SE and translational KE are calculated based on the entire BHA, these parameters can be used as lateral vibration indices for the entire BHA.\n \nFIG.', '14\n shows graphs for the same formations of the power transmitted to the bit for drilling the formations and the lateral acceleration experienced by the drill bit.', 'In terms of the ratio of energy loss to energy input, more energy is dissipated by contact interactions in hard rock drilling (UL_3000).', 'The foregoing is consistent with the trend of lateral acceleration of two cases (more lateral acceleration means more wellbore contact and more energy loss).', 'It is contemplated that the energy loss ratio could be used an indicator of drilling efficiency.', 'FIG.', '15\n illustrates an example drill string and BHA for a simulation that includes a drilling motor (shown proximate the drill bit in the left hand panel of \nFIG.', '15\n.', 'In the present example, energy input and energy loss may be calculated for both the rotary input at the surface (top drive or rotary table) and the drilling motor.', 'Referring to \nFIG.', '16\n, energy input for both the top drive and the drilling motor, as well as their respective energy losses are shown graphically.', 'Energy input at the motor is about three times that provided at surface top drive.', 'FIG.', '17\n shows a graph of power and power loss for both the top drive and the drilling motor.', 'Energy loss is about 12% of the total energy input (top drive [or rotary table]+ motor).', 'In other embodiments, a different procedure may be used to determine parasitic energy loss, i.e., energy consumed other than by drilling formations.', 'The total energy applied to the drill string (and to the drill bit when a drilling motor is used) is described in Eqs.', '(5) and (6).', 'The amount of work (energy) consumed by drilling formations is described by Eq.', '(7).', 'Total energy losses from any or all of the parameters described herein will be represented by the difference between the total energy input (Eqs. 5 and/or 6) and the energy used in drilling formations (Eq. 7).', 'To summarize the present disclosure and possible benefits of a method according to the present disclosure, subsurface formation drilling is a process in which energy is input at the surface and in some example embodiments by a drilling motor in the drill string.', 'The energy is transferred through the drill string and BHA, and is then used to drill formations below the drill bit.', 'Part of the energy input may be converted to drill string elastic strain/kinetic energy, and as well as being dissipated due to contact friction between the drill string and the wall of the wellbore.', 'The amounts of energy used to drill the formations and the amount of energy lost due to any or all of the foregoing factors may be calculated.', 'Drill string strain energy and kinetic energy reflect how much energy resides in the drill string in the form of elastic deformation and dynamic motion.', 'These parameters may be used as state indicators for the entire drill string deformation and vibration.', 'Energy loss is an effective measure of drilling efficiency.', 'A transient dynamic simulation method may be useful for energy calculation because such methods output a continuous history of kinetic and force responses of entire drill string.', 'Clear signatures of strain energy and kinetic energy can be found for different vibration modes using a method according to the present disclosure.', 'In a further embodiment, if the calculations suggest excessive amounts of input energy are being dissipated by any one or more of the foregoing energy dissipating interactions of the drill string and/or accelerations of the drill string, one or more drilling operating parameters may be adjusted in order to reduce the dissipated energy, thereby transferring more of the input energy into drilling the formations.', 'The drilling system design can affect drilling energy input and transfer during drilling.', 'Selection of different bits, reamers, mud motors, and other bottom hole assembly tools can affect how effective the energy is utilized to destroy the formation.', 'The disclosed energy calculation based on drilling dynamics simulation can be applied to plan drilling system for a specific job, including selection of drill bits, drilling tools and drill stems, placement of drilling tools, design of well bore sizes and trajectory, selection of drilling parameters, etc.', 'Energy calculation can be conducted based on the planned drill string and wellbore trajectory to assess the energy input requirements for the planned drilling operation.', 'This information can be used to guide the selection of proper surface power supply and downhole drive system (such as motor and turbine).', 'Since kinetic energy and strain energy of drill string represent the energy possessed by drill string in the form of vibration and deformation, they can be used as performance indicators of the entire drill string.', 'In the well planning stage, the kinetic energy for different drilling systems can be calculated and relatively compared to help choose the most stable one (with least kinetic energy) for a specific job.', 'The kinetic energy can be applied to compare the drilling stability of different drilling parameters.', 'The kinetic energy of drill system can be compared to a pre-specified threshold to evaluate if the vibration level is acceptable or not.', 'The strain energy indicator can be utilized to evaluate the robustness of drill string.', 'Lower strain energy means smaller deformation and lower stress.', 'The strain energy can be applied to plan drilling system and practice to lower the drill string lost-in-hole failure risk.', 'The effective usage of drilling energy is to drilling formation.', 'The difference between energy input and energy used for formation drilling is energy loss, which can be used as a drilling efficiency indicator.', 'The energy calculation can be conducted in the planning phase to compare energy loss for different drilling systems and different drilling parameters.', 'Among the several given BHA options and drilling parameter range derived from offset well experiences and tool limits, an optimization process can be performed to select BHA and parameters yielding the lowest energy loss.', 'During execution phase, simulation of different drilling parameters can be conducted during drilling.', 'Energy calculation can be done for each simulated scenarios to help select favorable drilling parameters or adjust downhole tool functions.', 'The depth-by-depth lithology data of offset well is used to map the formation top in the current well before drilling.', 'This helps select the rock type used in drilling dynamics simulation.', 'A bit wear model can be built into dynamic simulation to predict the dull condition of bit based on the cutter loading conditions, travel velocity, and formation abrasiveness.', 'The downhole logging tool can send the real-time downhole dynamics and mechanics measurement data to surface.', 'These information can be used to calculate the strain and kinetic energy of drill string at the measurement location.', 'When the discrepancy between simulated and measured energy parameters is found, a real-time calibration process for drilling dynamics model is activated to adjust modeling parameters to match the downhole measurements.', 'The calibrated dynamics model can be used to calculate the real-time energy distribution in the drill string and to predict the energy input requirement for the upcoming operations.', 'The kinetic energy indicator can be closely monitored through the real-time simulation to identify the adverse downhole vibration modes (such as stick-slip or backward whirling) based on comparison of indicator with specific thresholds.', 'The strain energy can be calculated during drilling to identify the overloading condition of drill string and to raise warning to driller when a specific threshold is exceeded.', 'A poor drilling efficiency condition can be identified by monitoring when the predicted energy loss ratio is higher than a certain threshold.', 'The calculation could be conducted during the post well analysis stage.', 'The actual drilling system and parameters used in the job can be simulated to understand energy input, energy transfer, and the energy dissipation.', 'The downhole measurement data from logging tools and surface drilling data can be used to calibrate the dynamics model.', 'The calibrated model is utilized to analyze how the energy is distributed in drill string and to identify the sources/factors leading to poor drilling efficiency condition (high energy loss ratio) and severe shock and vibration (high kinetic energy).', 'The energy calculation can be also used to troubleshoot the cause of downhole tool failures such as twist off.', 'The energy calculation procedure can be applied to evaluate the new proposed drilling system and drilling practices to identify the possible improvement areas for future jobs.', 'A flow chart of one example embodiment of a method according to the present disclosure is shown in \nFIG.', '18\n, in which at \n130\n energy is applied to to a drill string at at least one of a surface of the drill string and by a motor disposed in the drill string to operate a drill bit at a bottom of the drill string.', 'At \n132\n an amount of the applied energy not consumed in drilling formations caused by at least one of motion, deformation, and interaction of the drill string is calculated.', 'At \n134\n an amount of the applied energy used to drill formations below the drill bit is calculated.', 'Finally, at \n136\n at least one of a drill string parameter and a drilling operating parameter to optimize the applied energy used to drill the formations is adjusted.', 'FIG.', '19\n shows an example computing system \n100\n in accordance with some embodiments.', 'The computing system \n100\n may be an individual computer system \n101\nA or an arrangement of distributed computer systems.', 'The individual computer system \n101\nA may include one or more analysis modules \n102\n that may be configured to perform various tasks according to some embodiments, such as the tasks explained with reference to \nFIGS.', '2 through 18\n.', 'To perform these various tasks, the analysis module \n102\n may operate independently or in coordination with one or more processors \n104\n, which may be connected to one or more storage media \n106\n.', 'A display device \n105\n such as a graphic user interface of any known type may be in signal communication with the processor \n104\n to enable user entry of commands and/or data and to display results of execution of a set of instructions according to the present disclosure.', 'The processor(s) \n104\n may also be connected to a network interface \n108\n to allow the individual computer system \n101\nA to communicate over a data network \n110\n with one or more additional individual computer systems and/or computing systems, such as \n101\nB, \n101\nC, and/or \n101\nD (note that computer systems \n101\nB, \n101\nC and/or \n101\nD may or may not share the same architecture as computer system \n101\nA, and may be located in different physical locations, for example, computer systems \n101\nA and \n101\nB may be at a well drilling location, while in communication with one or more computer systems such as \n101\nC and/or \n101\nD that may be located in one or more data centers on shore, aboard ships, and/or located in varying countries on different continents).', 'A processor may include, without limitation, a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.', 'The storage media \n106\n may be implemented as one or more computer-readable or machine-readable storage media.', 'Note that while in the example embodiment of FIG.', 'the storage media \n106\n are shown as being disposed within the individual computer system \n101\nA, in some embodiments, the storage media \n106\n may be distributed within and/or across multiple internal and/or external enclosures of the individual computing system \n101\nA and/or additional computing systems, e.g., \n101\nB, \n101\nC, \n101\nD. Storage media \n106\n may include, without limitation, one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices.', 'Note that computer instructions to cause any individual computer system or a computing system to perform the tasks described above may be provided on one computer-readable or machine-readable storage medium, or may be provided on multiple computer-readable or machine-readable storage media distributed in a multiple component computing system having one or more nodes.', 'Such computer-readable or machine-readable storage medium or media may be considered to be part of an article (or article of manufacture).', 'An article or article of manufacture can refer to any manufactured single component or multiple components.', 'The storage medium or media can be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions can be downloaded over a network for execution.', 'It should be appreciated that computing system \n100\n is only one example of a computing system, and that any other embodiment of a computing system may have more or fewer components than shown, may combine additional components not shown in the example embodiment of \nFIG.', '19\n, and/or the computing system \n100\n may have a different configuration or arrangement of the components shown in \nFIG.', '19\n.', 'The various components shown in \nFIG.', '19\n may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.', 'Further, the acts of the processing methods described above may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices.', 'These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of the present disclosure.', 'Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” together with an associated function.'] | ['1.', 'A method for drilling a well, comprising:\napplying energy to a drill string y at least one of a surface of the drill string and by a motor disposed in the drill string to operate a drill bit at a bottom of the drill string;\ncalculating an amount of the applied energy not consumed in drilling formations caused by at least one of motion, deformation, and interaction of the drill string;\ncalculating an amount of the applied energy used to drill formations below the drill bit;\ncalculating a rate of penetration that depends on the applied energy and the amount of the applied energy not consumed in drilling formations and the amount of the applied energy used to drill formations; and\nutilizing the calculations, adjusting at least one of a drill string parameter and a drilling operating parameter to control the applied energy used to drill the formations.', '2.', 'The method of claim 1 wherein the motion of the drill string comprises axial translational motion at a plurality of locations along the drill string.', '3.', 'The method of claim 1 wherein the motion of the drill string comprises torsional rotation at a plurality of locations along the drill string.', '4.', 'The method of claim 1 wherein the motion of the drill string comprises lateral translational motion at a plurality of locations along the drill string.', '5.', 'The method of claim 1 wherein the deformation of the drill string comprises axial contraction/extension and lateral bending at a plurality of locations along the drill string.', '6.', 'The method of claim 1 wherein the deformation of the drill string comprises rotational twist at a plurality of locations along the drill string.', '7.', 'The method of claim 1 wherein the applying energy at the surface comprises rotating at least one of a top drive and a rotary table.', '8.', 'The method of claim 1 wherein the interaction of the drill string comprises frictional contact between the drill string and a wall of the wellbore at a plurality of locations along the drill string.', '9.', 'The method of claim 1 wherein the at least one drilling operating parameter comprises hookload.', '10.', 'The method of claim 1 wherein the at least one drilling operating parameter comprises rotational speed of the drill bit.\n\n\n\n\n\n\n11.', 'The method of claim 1 wherein the at least one drilling operating parameter comprises drilling fluid flow rate through the drill string.', '12.', 'The method of claim 1 further comprising characterizing a mode of motion of the drill string using the calculated energy amounts.', '13.', 'A method for drilling a well, comprising:\nrotating a drill string having a drill bit at a bottom end on formations disposed below the drill bit;\ndetermining a total amount of energy input applied to the drill string by at least one of rotating the drill string from a surface location and operating a drilling motor in the drill string;\ncalculating an amount of energy expended by drilling the formations below the drill bit, wherein the calculating comprises calculating a rate of penetration;\ndetermining an amount of the applied energy not consumed in drilling formations caused by at least one of motion, deformation, and interaction of the drill string as a difference between the total amount of energy input applied to the drill string and the amount of energy expended drilling the formations; and\nbased at least in part on the difference, adjusting at least one drilling operating parameter to control the amount of energy expended drilling the formations.\n\n\n\n\n\n\n14.', 'The method of claim 13 wherein the motion of the drill string comprises axial translational motion at a plurality of locations along the drill string.', '15.', 'The method of claim 13 wherein the motion of the drill string comprises torsional rotation at a plurality of locations along the drill string.', '16.', 'The method of claim 13 wherein the motion of the drill string comprises lateral translational motion at a plurality of locations along the drill string.', '17.', 'The method of claim 13 wherein the deformation of the drill string comprises axial contraction/extension and lateral bending at a plurality of locations along the drill string.', '18.', 'The method of claim 13 wherein the deformation of the drill string comprises rotational twist at a plurality of locations along the drill string.', '19.', 'The method of claim 13 wherein the applying rotational energy at the surface comprises rotating at least one of a top drive and a rotary table.', '20.', 'The method of claim 13 wherein the interaction of the drill string comprises frictional contact between the drill string and a wall of the wellbore at a plurality of locations along the drill string.', '21.', 'The method of claim 13 wherein the at least one drilling operating parameter comprises hookload.', '22.', 'The method of claim 13 wherein the at least one drilling operating parameter comprises rotational speed of the drill bit.\n\n\n\n\n\n\n23.', 'The method of claim 13 wherein the at least one drilling operating parameter comprises drilling fluid flow rate through the drill string.', '24.', 'The method of claim 13 further comprising characterizing a mode of motion of the drill string using the calculated energy amounts.'] | ['FIG.', '1 is a pictorial view of a wellbore drilling system.; FIG.', '2A shows a schematic representation of energy input to a drill string and main mechanisms by which such energy is consumed.;', 'FIG.', '2B shows various elements of a sample drill string operating in a wellbore to illustrate in more detail the mechanisms that consume the energy input to the drill string.;', 'FIG.', '3 shows schematically how energy applied to the drill string is consumed by axial motion.;', 'FIG.', '4 shows schematically how energy applied to the drill string is consumed by axially oriented rotation.; FIG.', '5 shows schematically how energy applied to the drill string is consumed by tilt of the drill string.; FIG.', '6 shows schematically how energy applied to the drill string may be consumed by various strain sustained by the drill string.; FIG.', '7 shows an example of parameters used in a model according to the present disclosure wherein all rotational energy is applied to the drill string from the surface.;', 'FIG.', '8 shows graphs of simulated bit rotational speed (RPM), bit lateral acceleration and bit rate of penetration through formations using the parameters shown in FIG.', '7.; FIG.', '9 shows graphs of strain and kinetic energy when the drill string undergoes a state change from stick-slip motion to whirling motion.;', 'FIG.', '10 shows a graph illustrating that during initial drilling, almost all the surface input energy is used to cut the rock although the bit has stick-slip motion.', 'After entering whirling mode, more of the input energy is lost due to the increased contact interactions between drill string and wellbore.; FIG.', '11 shows another graph including time averaged power wherein during initial drilling, almost all the surface energy input is used to cut the rock.', 'After entering whirling mode, more energy is lost due to the increased contact interactions between drill string and wellbore.', 'In this case, only about 40% energy input from surface is used for rock cutting during whirling mode.; FIG.', '12 shows graphs illustrating that drilling hard formations results in a lower RPM variation and higher lateral vibration.; FIG.', '13 shows graphs of a comparison of drilling two different formations.', 'Drilling hard formation shows much higher bending strain energy and translational kinetic energy.', 'Since bending and translational energies are calculated based on the entire BHA, it is possible to use the foregoing measured at the BHA as lateral vibration indices of the entire BHA.; FIG.', '14 shows graphs indicating that in terms of ratio of energy loss with reference to energy input, more energy is dissipated by wellbore wall contact interactions in hard rock drilling.', 'This matches the trend of lateral acceleration of the two different formation cases (more lateral acceleration means more wellbore contact and more energy loss).', '; FIG.', '15 shows a schematic diagram of parameters to be modeled using an example embodiment according to the disclosure wherein a drilling motor is included in the drill string.; FIG.', '16 shows a graph of energy with reference to motor speed and drill string surface rotation speed.', 'Energy losses are shown in the graph.; FIG.', '17 shows a graph of the case wherein RPM=50, WOB=10,000 lbs., drilling fluid flow is 350 gallons per minute.', 'Energy is calculated as Power (5 sec moving average).', 'Calculated energy loss is about 12% of the total energy input (surface+drilling motor).', '; FIG.', '18 shows a flow chart of an example embodiment of a method according to the present disclosure.; FIG.', '19 shows an example computer system that may be used in some embodiments.; FIG.', '9 shows graphs of both strain and kinetic energy for the same set of conditioned used to generate the graphs shown in FIG.', '8.', 'During stick-slip, bending strain energy and translation kinetic energy terms are negligible compared to torsional strain energy and axial rotation kinetic energy.', 'As whirling begins, bending strain energy and translation kinetic energy increase dramatically, and oscillation of torsional strain and kinetic energy substantially vanish because the bit RPM becomes stable.; FIG.', '10 shows a graph that illustrates during initial drilling, almost all the surface energy input is used to drill the formation.', 'After entering whirling mode, more energy is lost due to the increased contact interactions between the drill string and the wellbore.; FIG.', '11 shows a graph or applied and consumed power for the simulation shown with reference to FIG.', '9.', 'As may be observed in FIG.', '11, during initial drilling, almost all the surface energy input is used to drill the formation.', 'After entering whirling mode, more energy is lost due to the increased contact interactions between drill string and wellbore.', 'In this case, only about 40% energy input from surface is used for formation drilling in whirl mode.; FIG.', '12 shows a comparison of results obtained for hard formations (designated UL_3000) as contrasted with softer formations (designated WE_3000).', 'From the graphed results, it may be readily determined that harder formations tend to have higher lateral vibration on the drill bit and lower bit RPM variation for the used set of drilling operating parameters.; FIG.', '13 shows graphs of bending strain energy (SE) and translational kinetic energy (KE) when drilling hard formations (UL_3000) as contrasted with softer formations (WL_3000).', 'Drilling hard formation (UL_3000) shows much higher bending strain energy and translational kinetic energy.', '; FIG.', '14 shows graphs for the same formations of the power transmitted to the bit for drilling the formations and the lateral acceleration experienced by the drill bit.', 'In terms of the ratio of energy loss to energy input, more energy is dissipated by contact interactions in hard rock drilling (UL_3000).', 'The foregoing is consistent with the trend of lateral acceleration of two cases (more lateral acceleration means more wellbore contact and more energy loss).', 'It is contemplated that the energy loss ratio could be used an indicator of drilling efficiency.', '; FIG.', '15 illustrates an example drill string and BHA for a simulation that includes a drilling motor (shown proximate the drill bit in the left hand panel of FIG.', '15.', 'In the present example, energy input and energy loss may be calculated for both the rotary input at the surface (top drive or rotary table) and the drilling motor.', 'Referring to FIG.', '16, energy input for both the top drive and the drilling motor, as well as their respective energy losses are shown graphically.', 'Energy input at the motor is about three times that provided at surface top drive.; FIG.', '17 shows a graph of power and power loss for both the top drive and the drilling motor.', 'Energy loss is about 12% of the total energy input (top drive [or rotary table]+ motor).', '; FIG.', '19 shows an example computing system 100 in accordance with some embodiments.', 'The computing system 100 may be an individual computer system 101A or an arrangement of distributed computer systems.', 'The individual computer system 101A may include one or more analysis modules 102 that may be configured to perform various tasks according to some embodiments, such as the tasks explained with reference to FIGS.', '2 through 18.', 'To perform these various tasks, the analysis module 102 may operate independently or in coordination with one or more processors 104, which may be connected to one or more storage media 106.', 'A display device 105 such as a graphic user interface of any known type may be in signal communication with the processor 104 to enable user entry of commands and/or data and to display results of execution of a set of instructions according to the present disclosure.'] |
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US11078746 | Expanding and collapsing apparatus and methods of use | Nov 9, 2017 | Gareth Brown, Robin McGowan | SCHLUMBERGER TECHNOLOGY CORPORATION | Examination Report issued in the related GB application 1618952.4, dated Jan. 7, 2020 (4 pages).; International Preliminary Report on Patentability issued in the related PCT application PCT/GB2017/053381, dated May 14, 2019 (8 pages).; International Search Report and Written Opinion issued in the related PCT application PCT/GB2017/053381, dated Mar. 15, 2018 (14 pages).; Combined Search and Examination Report issued in the related GB application 1618952.4, dated May 2, 2017 (9 pages).; Communication Pursuant to Article 94(3) issued in EP Application 17818203.6, dated Oct. 6, 2020 (7 Pages).; Search Report issued in the related GB application 1618952.4, dated Dec. 1, 2020 (7 pages).; Examination Report issued in the related GB application 1618952.4, dated Dec. 1, 2020 (7 pages).; 1st Chinese Office Action issued in the related Chinese Patent Application No. 2017800774837 dated Mar. 2, 2021, 17 pages with English translation. | 2701615; February 1955; Riordan, Jr.; 3572627; March 1971; Jones; 3915424; October 1975; LeRouax; 4098516; July 4, 1978; Murman; 4544165; October 1, 1985; Coone; 4576042; March 18, 1986; Johnson; 4923007; May 8, 1990; Sanford et al.; 7290603; November 6, 2007; Hiorth et al.; 7921921; April 12, 2011; Bishop et al.; 8083001; December 27, 2011; Conner et al.; 8167033; May 1, 2012; White; 20030047880; March 13, 2003; Ross; 20040194969; October 7, 2004; Hiorth et al.; 20060005963; January 12, 2006; Hiorth et al.; 20110048744; March 3, 2011; Conner et al.; 20110073328; March 31, 2011; Clemens et al.; 20110265986; November 3, 2011; Porter et al.; 20120227987; September 13, 2012; Castriotta et al.; 20130161006; June 27, 2013; Robisson; 20130206410; August 15, 2013; Guerrero; 20130319654; December 5, 2013; Hiorth et al.; 20130333875; December 19, 2013; Hiorth; 20150152704; June 4, 2015; Tunget; 20150275618; October 1, 2015; Clemens et al. | 2003252894; April 2004; AU; 105705726; June 2016; CN; 1197632; April 2002; EP; 2242897; October 2010; EP; 2432600; May 2007; GB; 2545817; June 2017; GB; 2546005; July 2017; GB; 2546007; July 2017; GB; 2549163; October 2017; GB; 321083; March 2006; NO; 2006103434; October 2006; WO; 2008062186; May 2008; WO; 2009098465; August 2009; WO; 2012079913; June 2012; WO; 2012079914; June 2012; WO; 2014108692; July 2014; WO | ['The invention provides an expanding and collapsing apparatus and methods of use.', 'The apparatus comprises a plurality of elements (52) assembled together to form a ring structure (54) around a longitudinal axis.', 'The ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements.', 'At least one set of structural elements (56) each having a first end and a second end are operable to move between the expanded condition and the collapsed condition by movement of the first end in an axial direction, and by movement of the second end in a radial dimension.', 'At least one set of elements is operable to be moved by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'In another aspect, the plurality of elements (82) comprises at least one set of structural elements (86) extending longitudinally on the apparatus and operable to slide with respect to one another, wherein the sliding movement in a selected plane perpendicular to the longitudinal axis is tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'Applications of the invention include oilfield devices, including anti-extrusion rings, plugs, packers, locks, patching tools, connection systems, and variable diameter tools run in a wellbore.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a 371 national stage application of PCT/GB2017/053381, filed Nov. 9, 2017, which claims the benefit of Great Britain Application No. 1618952.4, filed Nov. 9, 2016, the disclosures of which are incorporated herein by reference.', 'FIELD OF THE INVENTION', 'The present invention relates to an expanding and collapsing apparatus and methods of use, and in particular aspects, to an expanding apparatus in the form of a ring, operable to move between a collapsed condition and an expanded condition.', 'The invention also relates to tools and devices incorporating the expansion apparatus and methods of use.', 'Preferred embodiments of the invention relate to oilfield apparatus (including downhole apparatus and wellhead apparatus) incorporating the apparatus and methods of use.\n \nBACKGROUND TO THE INVENTION\n \nIn many fields of mechanical engineering, and in the field of hydrocarbon exploration and production in particular, it is known to provide expansion mechanisms for the physical interaction of tubular components.', 'Expansion mechanisms may expand outwardly to engage an external surface, or may collapse inwardly to engage an internal surface.', 'Applications are many and varied, but in hydrocarbon exploration and production include the actuation and setting of flow barriers and seal elements such as plugs and packers, anchoring and positioning tools such as wellbore anchors, casing and liner hangers, and locking mechanisms for setting equipment downhole.', 'Other applications include providing anti-extrusion, mechanical support or back up for elements such as elastomers or inflatable bladders.', 'A typical anti-extrusion ring is positioned between a packer or seal element and its actuating slip members, and is formed from a split or segmented metallic ring.', 'During deployment of the packer or seal element, the segments move to a radially expanded condition.', 'During expansion and at the radially expanded condition, spaces are formed between the segments, as they are required to occupy a larger annular volume.', 'These spaces create extrusion gaps, which may result in failure of the packer or seal under working conditions.', 'Various configurations have been proposed to minimise the effect of spaces between anti-extrusion segments, including providing multi-layered rings, such that extrusion gaps are blocked by an offset arrangement of segments.', 'For example, U.S. Pat.', 'No. 6,598,672 describes an anti-extrusion ring for a packer assembly which has first and second ring portions which are circumferentially offset to create gaps in circumferentially offset locations.', 'U.S. Pat.', 'No. 2,701,615 discloses a well packer comprising an arrangement of crowned spring metal elements which are expanded by relative movement.', 'Other proposals, for example those disclosed in U.S. Pat.', 'Nos. 3,572,627, 7,921,921, US 2013/0319654, U.S. Pat.', 'Nos. 7,290,603 and 8,167,033 include arrangements of circumferentially lapped segments.', 'U.S. Pat.', 'No. 3,915,424 describes a similar arrangement in a drilling BOP configuration, in which overlapping anti-extrusion members are actuated by a radial force to move radially and circumferentially to a collapsed position which supports annular sealing elements.', 'Such arrangements avoid introducing extrusion gaps during expansion, but create a ring with uneven or stepped faces or flanks.', 'These configurations do not provide an unbroken support wall for a sealing element, are spatially inefficient, and may be difficult to reliably move back to their collapsed configurations.', 'U.S. Pat.', 'No. 8,083,001 proposes an alternative configuration in which two sets of wedge shaped segments are brought together by sliding axially with respect to one another to create an expanded gauge ring.', 'Applications of existing expanding and collapsing apparatus are limited by the expansion ratios that can be achieved.', 'In anchoring, positioning, setting, locking and connection applications, radially expanding and collapsing structures are typically circumferentially distributed at discrete locations when at their increased outer diameter.', 'This reduces the surface area available to contact an auxiliary engagement surface, and therefore limits the maximum force and pressure rating for a given size of device.', 'SUMMARY OF THE INVENTION', 'It is amongst the claims and objects of the invention to provide an expanding and collapsing apparatus and methods of use which obviate or mitigate disadvantages of previously proposed expanding and collapsing apparatus.', 'It is amongst the aims and objects of the invention to provide an oilfield apparatus, including but not limited to a downhole apparatus, a wellhead apparatus, or a drilling apparatus, incorporating an expanding and collapsing apparatus, which obviates or mitigates disadvantages of prior art oilfield apparatus.', 'Further aims and objects of the invention will be apparent from reading the following description.', 'In the context of this description, the terms “ring” and “ring structure” are used to designate an arrangement of one or more components or elements joined to itself to surround an axis, but is not limited to arrangements which are rotationally symmetric or symmetric about a plane perpendicular to the axis.', 'According to a first aspect of the invention, there is provided an apparatus comprising: a plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements;\n \nwherein the plurality of elements comprises at least one set of structural elements each having a first end and a second end, wherein the structural elements are operable to move between the expanded condition and the collapsed condition by movement of the first end in an axial direction, and by movement of the second end in at least a radial dimension;\n \nand wherein the plurality of elements comprises at least one set of elements operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'The second end may be operable to move in a radial direction and an axial direction of the apparatus.', 'The structural elements may be operable to move in a circumferential direction of the apparatus.', 'Preferably, the structural elements extend longitudinally on the apparatus.', 'An outermost dimension of the second end of a structural element may be disposed at a radial distance from the longitudinal axis which is greater than a radial distance of an outermost dimension of the first end when the apparatus is in the expanded condition and/or a partially expanded condition.', 'Alternatively, or in addition, an outermost dimension of the second end of a structural element may be disposed at a radial distance from the longitudinal axis which is greater than a radial distance of an outermost dimension of the first end when the apparatus is in the collapsed condition.', 'The apparatus may comprise a retaining ring which connects to the first ends of the structural elements.', 'The retaining ring is preferably moveable axially on the apparatus, and may be operable to move the first end of the structural elements axially on the apparatus.', 'The set of structural elements may together form a substantially conical structure in an expanded condition (including a partially, fully, or substantially fully expanded condition).', 'Alternatively, or in addition, the set of structural elements may together form a substantially conical structure in the collapsed condition and/or a partially expanded condition.', 'The substantially conical structure may be a truncated conical structure, and/or may define a partially convex outer profile in at least its collapsed condition.', 'In an embodiment, the plurality of elements comprises at least one set of ring elements, distinct from the set of structural elements, operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'The set of structural elements may be directly or indirectly connected to the set of ring elements, and they may together be operable to be moved between the expanded condition and the collapsed condition.', 'In an alternative embodiment, the structural elements may comprise structural ring elements, operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'The ring elements and/or structural ring elements may describe an angle at an outer surface of the ring structure (θ\n1\n) of 45 degrees or less.', 'Such a configuration corresponds to eight or more ring elements assembled together to form the ring structure.', 'Preferably, the described angle is 30 degrees or less, corresponding to twelve or more ring elements assembled together to form the ring.', 'More preferably, the described angle is in the range of 10 degrees to 20 degrees, corresponding to eighteen to thirty-six elements assembled together to form the ring.', 'In a particular preferred embodiment, described angle is 15 degrees, corresponding to twenty-four ring elements assembled together to form the ring structures.', 'The ring elements may comprise first and second contact surfaces which may be oriented on first and second planes.', 'The first and second orientation planes may intersect or meet (i.e. be a tangent to) an inner surface of the ring structure formed by the segments at first and second lines.', 'The orientation planes may be tangential to the inner surface of the ring structure in its expanded condition.', 'Alternatively, the inner surface of the ring structure may have a truncated (increased) inner diameter, and the orientation planes may be tangential to a circle with smaller diameter than the inner surface of the ring structure.', 'The orientation planes may therefore intersect the inner surface of the ring structure in its expanded condition, at an angle (which may be defined as θ\n2 \nbetween a radial plane from the centre of the ring structure and the intersection or tangent point.', 'Where the structural elements extend longitudinally on the apparatus, they may be operable to slide with respect to one another, with the sliding movement in a selected plane perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'In an embodiment, the structural elements extend longitudinally on the apparatus and are operable to slide with respect to one another, with the sliding movement in any selected plane along the length of the structural element and perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'In a further alternative embodiment, the apparatus may comprise one or more sets of structural ring elements, operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure, and one or more sets of ring elements, distinct from the one or more sets of structural ring elements.', 'The structural element may be pivotally connected to a ring element at its second end.', 'Preferably, the structural element is connected to a ring element by a connection configured to enable the transfer of a tensile force between the structural element and a ring element.', 'This enables a tension to be pulled between the structural element and a ring element (or vice versa), which may assist with retraction of the apparatus from an expanded or partially expanded condition.', 'The structural element may for example be connected to a ring element by a ball and socket or knuckle and socket connection.', 'Where the apparatus comprises a retaining ring, the structural element may be connected to the retaining ring at its first end, by a connection which enables the transfer of a tensile force between the structural element and the retaining ring, for example by a ball and socket or knuckle and socket connection.', 'Therefore a tension may be pulled between the structural element and the retaining ring (or vice versa), which may assist with retraction of the apparatus from an expanded or partially expanded condition.', 'Where the set of structural elements together form a substantially conical structure, the substantially conical structure may comprise openings in the conical surface between the structural elements.', 'In such an embodiment, a structural element may comprise a strut or spoke, and/or the apparatus may comprise a plurality of struts or spokes circumferentially distributed about the longitudinal axis.', 'In an embodiment of the invention, the substantially conical structure may comprise a substantially continuous conical surface in the expanded condition, or a partially expanded or substantially expanded condition.', 'The substantially conical structure may comprise a hollow cone.', 'The substantially conical structure may comprise a substantially or fully uniform wall thickness.', 'Alternatively, or in addition, the substantially conical structure may comprise a tapering wall thickness.', 'The substantially conical structure may comprise a cylindrical portion extending from its flared end.', 'The hollow cone may be formed from the set of structural ring elements in the expanded or a substantially expanded condition.', 'Each of the structural ring elements may be a segment of a cone.', 'The structural ring elements may extend longitudinally on the apparatus and may be operable to slide with respect to one another, with the sliding movement in any selected plane along the length of the structural element and perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'The structural ring element may be pivotally connected to a ring element at its second end.', 'The structural ring element may be pivotally connected to a ring element by a ball and socket or knuckle and socket connection.', 'Where the apparatus comprises a retaining ring, the structural ring element may be pivotally connected to the retaining ring at its first end, by a connection which enables the transfer of a tensile force between the structural element and the retaining ring, for example by a ball and socket or knuckle and socket connection.', 'Therefore a tension may be pulled between the structural element and the retaining ring (or vice versa), which may assist with retraction of the apparatus from an expanded or partially expanded condition.', 'The apparatus may comprise a first set of structural elements, a second set of structural elements, and a set of ring elements distinct from the structural elements.', 'The first set of structural elements may be connected to the set of ring elements at a first axial side of the set of ring elements, and the second set of structural elements may be connected to the set of ring elements at a second axial side of the set of ring elements.', 'The first and/or second set of structural elements may comprise structural ring elements, which may be segments of a cone.', 'Where the structural ring elements are segments of a cone, they may describe an angle at an outer surface of the cone (θ\n1\n) of 45 degrees or less.', 'Such a configuration corresponds to eight or more ring elements assembled together to form the ring structure.', 'Preferably, the described angle is 15 degrees or less, corresponding to twelve or more structural ring elements assembled together to form the structural ring.', 'More preferably, the described angle is in the range of 10 degrees to 20 degrees, corresponding to eighteen to thirty-six structural elements assembled together to form the structural ring.', 'In a particular preferred embodiment, described angle is 15 degrees, corresponding to twenty-four ring elements assembled together to form the structural ring.', 'The ring elements may comprise first and second contact surfaces which may be oriented on first and second planes.', 'The first and second orientation planes may intersect or meet (i.e. be a tangent to) an inner surface of the ring structure formed by the segments at first and second lines.', 'The orientation planes may be tangential to the inner surface of the ring structure in its expanded condition.', 'The orientation planes of the first and second contact surfaces may intersect on a radial plane P which bisects the radial planes at the tangent points (i.e. is at an angle of θ\n1\n/2 to both).', 'This intersection plane P may define the expanding and collapsing path of the cone segment.', 'The collapsed condition may be a first condition of the apparatus, and the expanded condition may be a second condition of the apparatus.', 'Thus the apparatus may be normally collapsed, and may be actuated to be expanded.', 'Alternatively, the expanded condition may be a first condition of the apparatus, and the collapsed condition may be a second condition of the apparatus.', 'Thus the apparatus may be normally expanded, and may be actuated to be collapsed.', 'The ring structure may comprise one or more ring surfaces, which may be presented to an auxiliary surface, for example the surface of a tubular, when actuated to an expanded condition or a collapsed condition.', 'The one or more ring surfaces may include a ring surface which is parallel to the longitudinal axis of the apparatus.', 'The ring surface may be an outer ring surface, and may be a substantially cylindrical surface.', 'The ring surface may be arranged to contact or otherwise interact with an inner surface of a tubular or bore.', 'Alternatively, the ring surface may be an inner surface of the ring structure, and may be a substantially cylindrical surface.', 'The ring surface may be arranged to contact or otherwise interact with an outer surface of a tubular or cylinder.', 'The ring surface may be substantially smooth.', 'Alternatively, the ring surface may be profiled, and/or may be provided with one or more functional formations thereon, for interacting with an auxiliary surface.', 'In the collapsed condition, the ring elements may be arranged generally at collapsed radial positions, and may define a collapsed outer diameter and inner diameter of the ring structure.', 'In the expanded condition, the ring elements may be arranged generally at expanded radial positions, and may define an expanded outer diameter and inner diameter of the ring structure.', 'The ring surface may be located at or on the expanded outer diameter of the ring structure, or may be located at or on the collapsed inner diameter of the ring structure.', 'In the collapsed condition, the elements may occupy a collapsed annular volume, and in the expanded condition the elements may occupy an expanded annular volume.', 'The collapsed annular volume and the expanded annular volume may be discrete and separated volumes, or the volumes may partially overlap.', 'The ring elements may be configured to move between their expanded and collapsed radial positions in a path which is tangential to a circle described around and concentric with the longitudinal axis.', 'Preferably, each ring element of the ring structure comprises a first contact surface and second contact surface respectively in abutment with first and second adjacent elements.', 'The ring elements may be configured to slide relative to one another along their respective contact surfaces.', 'The first contact surface and/or the second contact surface may be oriented tangentially to a circle described around and concentric with the longitudinal axis.', 'The first contact surface and the second contact surface are preferably non-parallel.', 'The first contact surface and the second contact surface may converge towards one another in a direction towards an inner surface of the ring structure (and may therefore diverge away from one another in a direction away from an inner surface of the ring structure).', 'At least some of the ring elements are preferably provided with interlocking profiles for interlocking with an adjacent element.', 'Preferably the interlocking profiles are formed in the first and/or second contact surfaces.', 'Preferably, a ring element is configured to interlock with a contact surface of an adjacent element.', 'Such interlocking may prevent or restrict separation of assembled adjacent elements in a circumferential and/or radial direction of the ring structure, while enabling relative sliding movement of adjacent elements.', 'Preferably, at least some of, and more preferably all of, the ring elements assembled to form a ring are identical to one another, and each comprises an interlocking profile which is configured to interlock with a corresponding interlocking profile on another ring element.', 'The interlocking profiles may comprise at least one recess such as groove, and at least one protrusion, such as a tongue or a pin, configured to be received in the groove.', 'The interlocking profiles may comprise at least one dovetail recess and dovetail protrusion.', 'The first and second contact surfaces of a ring element may be oriented on first and second planes, which may intersect an inner surface of the ring at first and second intersection lines, such that a sector of an imaginary cylinder is defined between the longitudinal axis and the intersection lines.', 'The central angle of the sector may be 45 degrees or less.', 'Such a configuration corresponds to eight or more ring elements assembled together to form the ring structure.', 'Preferably, the central angle of the sector is 30 degrees or less, corresponding to twelve or more ring elements assembled together to form the ring.', 'More preferably, the central angle of the sector is in the range of 10 degrees to 20 degrees, corresponding to eighteen to thirty-six ring elements assembled together to form the ring.', 'In a particular preferred embodiment, the central angle of the sector is 15 degrees, corresponding to twenty-four ring elements assembled together to form the ring structure.', 'Each ring element may comprise one, preferably two, structural elements connected to the ring structure.', 'The structural elements may comprise structural ring elements, and may be defined by the same central angles as the ring elements.', 'Preferably, an angle described between the first contact and second contact surfaces corresponds to the central angle of the sector.', 'Preferably therefore, an angle described between the first contact and second contact surfaces is in the range of 10 degrees to 20 degrees, and in a particular preferred embodiment, the angle described between the first contact and second contact surfaces is 15 degrees, corresponding to twenty-four elements assembled together to form the ring structure.', 'In a preferred embodiment, the apparatus comprises a support surface for the ring structure.', 'The support surface may be the outer surface of a mandrel or tubular.', 'The support surface may support the ring structure in a collapsed condition of the apparatus.', 'The support surface may be the inner surface of a mandrel or tubular.', 'The support surface may support the ring structure in an expanded condition of the apparatus.', 'In some embodiments, the apparatus is operated in its expanded condition, and in other embodiments, the apparatus is operated in its collapsed condition.', 'Preferably, at least some of the elements forming the ring structure are mutually supportive in an operating condition of the apparatus.', 'Where the operating condition of the apparatus its expanded condition (i.e. when the apparatus is operated in its expanded condition), the apparatus may comprise a substantially solid cylindrical ring structure in its expanded condition, and the ring elements may be fully mutually supported.', 'In an embodiment, the substantially solid cylindrical ring structure of the apparatus may be supported by one or more substantially conical structures formed from the structural elements.', 'The structural elements may be fully mutually supported.', 'In an embodiment, the apparatus may comprise one or more substantially conical structures in its expanded condition, and the structural elements may be fully mutually supported.', 'Where the operating condition of the apparatus its collapsed condition (i.e. when the apparatus is operated in its collapsed condition), the ring structure is preferably a substantially solid ring structure in its collapsed condition, and the ring elements may be fully mutually supported.', 'The apparatus may comprise a formation configured to impart a radial expanding or collapsing force component to the structural elements of a ring structure from an axial actuation force.', 'The apparatus may comprise a pair of formations configured to impart a radial expanding or collapsing force component to the structural elements of a ring structure from an axial actuation force.', 'The formation (or formations) may comprise a wedge or wedge profile, and may comprise a cone wedge or wedge profile.', 'The apparatus may comprise a biasing means, which may be configured to bias the ring structure to one of its expanded or collapsed conditions.', 'The biasing means may comprise a circumferential spring, a garter spring, or a spiral retaining ring.', 'The biasing means may be arranged around an outer surface of a ring structure, to bias it towards a collapsed condition, or may be arranged around an inner surface of a ring structure, to bias it towards an expanded condition.', 'One or more elements may comprise a formation such as a groove for receiving the biasing means.', 'Preferably, grooves in the elements combine to form a circumferential groove in the ring structure.', 'Multiple biasing means may be provided on the ring structure.', 'According to a second aspect of the invention, there is provided an apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements;\n \nwherein the plurality of elements comprises at least one set of structural elements extending longitudinally on the apparatus and operable to slide with respect to one another, wherein the sliding movement in a selected plane perpendicular to the longitudinal axis is tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'In an embodiment, the structural elements extend longitudinally on the apparatus and are operable to slide with respect to one another, with the sliding movement in any selected plane along the length of the structural element and perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'The structural elements may each have a first end and a second end, wherein the structural elements are operable to move between the expanded condition and the collapsed condition by movement of the first end in an axial direction, and by movement of the second end in at least a radial dimension;\n \nand wherein the plurality of elements comprises at least one set of elements operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'Embodiments of the second aspect of the invention may include one or more features of the first aspect of the invention or its embodiments, or vice versa.', 'According to a third aspect of the invention, there is provided an expanding and collapsing ring apparatus comprising:\n \na plurality of elements assembled together to form a ring structure around a longitudinal axis;\n \nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition;\n \nwherein in the expanded condition, the plurality of elements combine to form a conical structure having a substantially smooth conical outer surface.', 'The substantially smooth conical outer surface may be substantially unbroken.', 'Preferably, the ring structure comprises a pair of conical structures having substantially smooth conical outer surfaces.', 'Thus one or more flanks or faces of the ring structure, which are the surfaces presented in the longitudinal direction, may have smooth surfaces.', 'The apparatus may also comprise a solid ring structure having a substantially smooth circular profile in a plane perpendicular to the longitudinal axis.', 'The plurality of elements may comprise at least one set of structural elements.', 'The plurality of elements may comprise at least one set of elements operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'Where the structural elements extend longitudinally on the apparatus, they may be operable to slide with respect to one another, with the sliding movement in a selected plane perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'In an embodiment, the structural elements extend longitudinally on the apparatus and are operable to slide with respect to one another, with the sliding movement in any selected plane along the length of the structural element and perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'The structural elements may each have a first end and a second end, wherein the structural elements are operable to move between the expanded condition and the collapsed condition by movement of the first end in an axial direction, and by movement of the second end in at least a radial dimension;\n \nand wherein the plurality of elements comprises at least one set of elements operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'Embodiments of the third aspect of the invention may include one or more features of the first or second aspects of the invention or their embodiments, or vice versa.', 'According to a fourth aspect of the invention, there is provided an oilfield apparatus comprising:\n \na plurality of elements assembled together to form a first ring structure around a longitudinal axis;\n \na plurality of elements assembled together to form a second ring structure around a longitudinal axis;\n \nwherein the first and second ring structures are operable to be moved between expanded conditions and collapsed conditions;\n \nwherein in their expanded conditions, the plurality of elements of the first and second ring structures combine to form first and second conical structures;\n \nand wherein at least one of the first and second ring structures provides mechanical support to the other of the first and second ring structures in their expanded conditions.', 'Embodiments of the fourth aspect of the invention may include one or more features of the first to third aspects of the invention or their embodiments, or vice versa.', 'According to a fifth aspect of the invention, there is provided a fluid barrier apparatus for a borehole or conduit, the fluid barrier apparatus comprising an expanding and collapsing apparatus according to any preceding aspect of the invention.', 'The fluid barrier apparatus may comprise a sealing apparatus for a borehole or conduit, and may be configured to hold a pressure differential across the sealing apparatus.', 'Embodiments of the fifth aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.', 'According to a sixth aspect of the invention, there is provided a sealing assembly for a borehole or conduit, the sealing assembly comprising:\n \nat least one expanding and collapsing apparatus according to any preceding aspect of the invention and a sealing element;\n \nwherein the at least one expanding and collapsing apparatus is arranged to provide mechanical support to the sealing element in its expanded condition.', 'The sealing apparatus may comprise a first expanding and collapsing apparatus according to any preceding aspect of the invention and a second expanding and collapsing apparatus according to any preceding aspect of the invention.', 'The sealing element may be disposed between the first and second expanding and collapsing apparatus, and may be mechanically supported by the first and second expanding and collapsing apparatus in their expanded conditions.', 'Embodiments of the sixth aspect of the invention may include one or more features of the first to fifth aspects of the invention or their embodiments, or vice versa.', 'According to a further aspect of the invention, there is provided an oilfield tool comprising the apparatus of any preceding aspect of the invention.', 'The oilfield tool may be a downhole tool.', 'Alternatively, the oilfield tool may comprise a wellhead tool.', 'The downhole tool may comprise a downhole tool selected from the group consisting of a plug, a packer, an anchor, a tubing hanger, or a downhole locking tool.', 'The plug may be a bridge plug, and may be a retrievable bridge plug.', 'Alternatively, the plug may be a permanent plug.', 'According to a further aspect of the invention, there is provided variable diameter downhole tool, the tool comprising an apparatus according to a previous aspect of the invention.', 'The downhole tool may be selected from the group consisting of a wellbore centraliser, a wellbore broach tool, and a wellbore drift tool.', 'According to a further aspect of the invention, there is provided a connector system comprising a first connector and a second connector, wherein one of the first and second connectors comprises the apparatus of any of the preceding aspects of the invention.', 'According to a further aspect of the invention, there is provided a patch apparatus for a fluid conduit or tubular, the patch apparatus comprising the apparatus of any of the preceding aspects of the invention.', 'According to a further aspect of the invention there is provided a method of expanding or collapsing an expanding and collapsing apparatus, the method comprising:\n \nproviding a plurality of elements assembled together to form a ring structure around a longitudinal axis, wherein the plurality of elements comprises at least one set of structural elements each having a first end and a second end,\n \nmoving the first ends of the structural segments in an axial direction, and moving the second ends of the structural segments in at least a radial dimension;\n \nand moving at least one set of elements between the expanded and collapsed conditions by sliding them with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'According to a further aspect of the invention there is provided a method of expanding or collapsing an expanding and collapsing apparatus, the method comprising:\n \nproviding a plurality of elements assembled together to form a first ring structure around a longitudinal axis; and a plurality of elements assembled together to form a second ring structure around a longitudinal axis;\n \nmoving the first and second ring structures between expanded conditions and collapsed conditions;\n \nwherein in their expanded conditions, the plurality of elements of the first and second ring structures combine to form first and second conical structures;\n \nand wherein at least one of the first and second ring structures provides mechanical support to the other of the first and second ring structures in their expanded conditions.', 'According to a further aspect of the invention there is provided a method of forming a fluid barrier or seal in a bore comprising the method or apparatus of a previous aspect of the invention.', 'The bore may be a wellbore, and may be a cased or lined wellbore.', 'Embodiments of the further aspects of the invention may include one or more features of any preceding aspect of the invention or its embodiments, or vice versa.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nThere will now be described, by way of example only, various embodiments of the invention with reference to the drawings, of which:\n \nFIGS.', '1A to 1D\n are respectively perspective, first end, part sectional and second end views of an apparatus useful for understanding the invention, shown in a collapsed condition;\n \nFIGS.', '2A to 2D\n are respectively perspective, first side, part sectional and second side views of the apparatus of \nFIGS.', '1A to 1D\n, shown in an expanded condition;\n \nFIG.', '3\n is a geometric representation of an element of the apparatus of \nFIGS.', '1A to 1D\n, shown from one side;\n \nFIGS.', '4A to 4F\n are respectively first perspective, second perspective, plan, first end, lower, and second end views of an element of the apparatus of \nFIGS.', '1A to 1D\n;\n \nFIGS.', '5A to 5C\n are respectively isometric, side and end views of an apparatus according to an embodiment of the invention in a collapsed condition;\n \nFIGS.', '6A to 6C\n are respectively isometric, side and end views of the apparatus of \nFIGS.', '5A to 5C\n in a partially expanded condition;\n \nFIGS.', '7A to 7C\n are respectively isometric side and end views of the apparatus of \nFIGS.', '5A to 5C\n in a fully expanded condition;\n \nFIG.', '8\n is a geometric representation of an element of the apparatus of \nFIGS.', '5A to 5C\n, shown from one side;\n \nFIGS.', '9A to 9F\n are respectively first perspective, second perspective, plan, first end, lower, and second end views of an element of the apparatus of \nFIGS.', '5A to 5C\n;\n \nFIGS.', '10A and 10B\n are respectively isometric and longitudinal sectional views of an apparatus according to an alternative embodiment of the invention in a collapsed position;\n \nFIGS.', '10C and 10D\n are respectively cross sectional views of the apparatus of \nFIGS.', '10A and 10B\n through lines C-C and D-D;\n \nFIGS.', '11A and 11B\n are respectively isometric and longitudinal sectional views of the apparatus of \nFIGS.', '10A to 10D\n in an expanded condition;\n \nFIGS.', '11C and 11D\n are respectively cross sectional views of the apparatus of \nFIGS.', '11A and 11B\n through lines C-C and D-D respectively;\n \nFIG.', '12\n is an isometric view of a structural element of the apparatus of \nFIGS.', '10A to 10D\n;\n \nFIG.', '13\n is an isometric view of a ring element of the apparatus of \nFIGS.', '10A to 10D\n;\n \nFIGS.', '14A and 14B\n are views of the structural element of \nFIG.', '12\n with reference to a virtual cone of which the structural element is a segment;\n \nFIGS.', '15A to 15C\n are geometric reference diagrams, useful for understanding how a structural element of an embodiment of the invention may be formed;\n \nFIGS.', '16A to 16C\n are respectively first isometric, lower, and second isometric end views of a ring element of an apparatus according to an alternative embodiment of the invention;\n \nFIGS.', '17A and 17B\n are respectively first and second isometric views of a structural element of an apparatus according to an alternative embodiment of the invention;\n \nFIGS.', '18A and 18B\n are longitudinal sectional views of an apparatus incorporating the ring element and structural element of \nFIGS.', '16A to 17B\n respectively in collapsed and expanded conditions;\n \nFIGS.', '19A to 19C\n are respectively isometric, longitudinal sectional and end views of an apparatus according to an alternative embodiment of the invention in a collapsed condition;\n \nFIGS.', '20A to 20C\n are respectively isometric, longitudinal sectional and end views of the apparatus of \nFIGS.', '19A to 19C\n in an expanded condition;\n \nFIGS.', '21A to 21C\n are respectively isometric, longitudinal sectional and cross sectional views of an apparatus according to an alternative embodiment of the invention in a collapsed condition;\n \nFIGS.', '22A and 22B\n are respectively partially cut away isometric and longitudinal sectional views of the apparatus of \nFIGS.', '21A to 21C\n in an expanded condition;\n \nFIGS.', '22C and 22D\n are respectively cross sectional views of the apparatus of \nFIGS.', '22A and 22B\n through lines C-C and D-D;\n \nFIGS.', '23A to 23C\n are respectively isometric, longitudinal sectional and end views of a seal apparatus according to an alternative embodiment of the invention in a collapsed condition;\n \nFIGS.', '24A and 24C\n are respectively isometric, longitudinal sectional and end views of the apparatus of \nFIGS.', '22A to 22C\n in an expanded condition.', 'DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS\n \nExemplary embodiments of the invention will be described with reference to \nFIGS.', '5 to 24\n.', 'Referring firstly to \nFIGS.', '1 to 4\n, the principles of the invention will be described with reference to an expanding apparatus in the form of a simple ring.', 'In this arrangement, the expanding apparatus, generally depicted at \n10\n, comprises an expanding ring structure configured to be expanded from a first collapsed or unexpanded condition (shown in \nFIGS.', '1A to 1D\n) and a second expanded condition (shown in \nFIGS.', '2A to 2D\n).', 'The apparatus of this arrangement and embodiments of the invention may be referred to as “expanding apparatus” for convenience, as they are operable to move to an expanded state from a normal collapsed state.', 'However, the apparatus may equally be referred to as a collapsing apparatus, or an expanding or collapsing apparatus, as they are capable of being expanded or collapsed depending on operational state.', 'The expanding apparatus \n10\n comprises a plurality of elements \n12\n assembled together to form a ring structure \n11\n.', 'The elements \n12\n define an inner ring surface which is supported by the outer surface of cylinder \n14\n.', 'Each element comprises an inner surface \n20\n, an outer surface \n21\n and first and second contact surfaces \n22\n, \n23\n.', 'The first and second contact surfaces are oriented in non-parallel planes, which are tangential to a circle centred on the longitudinal axis of the apparatus.', 'The planes converge towards the inner surface of the element.', 'Therefore, each element is in the general form of a wedge, and the wedges are assembled together in a circumferentially overlapping fashion to form the ring structure \n11\n.', 'In use, the first and second contact surfaces of adjacent elements are mutually supportive.', 'As most clearly shown in \nFIG.', '3\n, when the ring structure is expanded to its optimal outer diameter, the orientation planes of the first and second contact surfaces intersect an inner surface of the ring structure, and together with the longitudinal axis of the apparatus, the lines of intersection define a sector of a cylinder.', 'In this case, the ring structure is formed from twenty-four identical elements, and the central angle θ\n1 \nis 15 degrees.', 'The angle described between the orientation planes of the first and second contact surface is the same as the central angle of the cylindrical sector, so that the elements are arranged rotationally symmetrically in the structure.', 'Each element is based on a notional wedge-shaped segment of a ring centred on an axis, with each notional wedge-shaped segment being inclined with respect to the radial direction of the ring.', 'The nominal outer diameter of the segment is at the optimum expansion condition of the ring (with radius shown at r\n1\n).', 'The orientation planes of the first and second contact surfaces of the element are tangential to a circle with radius r\n3 \nconcentric with the ring at points t\n1\n, t\n2\n.', 'The angle described between the tangent points is equal to the angle θ\n1 \nof the segment.', 'The orientation planes of the first and second contact surfaces of each notional wedge-shaped segment intersect one another on a radial plane P which bisects radial planes located at the tangent points (i.e. is at an angle of θ\n1\n/2 to both).', 'This intersection plane P defines the expanding and collapsing path of the segment.', 'In the configuration shown in \nFIGS.', '1 and 2\n, notional wedge-shaped segments are modified by removal of the tips \n29\n of the wedges, to provide a curved or arced inner surface \n20\n with radius r\n2 \nwhen the ring is in its expanded condition shown in \nFIGS.', '2A\n and \n2\nD. The modification of the wedge-shaped elements can be thought of as an increase in diameter of an internal bore through the ring structure by 2(r\n2\n−r\n3\n), or a truncation of the inner diameter.', 'This change in the inner diameter from the notional inner diameter r\n3 \nto which the contact surfaces are tangential to a truncated inner diameter r\n2\n, has the effect of changing an angle between the contact surfaces and the radial plane from the centre of the ring.', 'Taking angle θ\n2 \nto be the angle described between the contact surface and a radial plane defined between the centre point of the ring structure and the point at which the orientation surface meets or intersects a circle at the radial position of the inner surface, θ\n2 \nis changed in dependence on the amount by which the segment has its inner diameter truncated.', 'For the notional wedge shaped segment, the orientation planes of the contact surfaces are tangential to a circle at the inner diameter at r\n1 \n(i.e. angle θ\n2 \nis 90 degrees).', 'For the modified elements \n12\n, the orientation planes of the contact surfaces instead intersect a circle at the (increased) inner diameter at r\n2 \nand are inclined at a reduced angle θ\n2\n.', 'The angle θ\n2 \nat which the segment is inclined is related to the amount of material removed from the notional wedge-shaped segment, but is independent from the central angle θ\n1 \nof the wedge.', 'Angle θ\n2 \nis selected to provide element dimensions suitable for manufacture, robustness, and fit within the desired annular volume and inner and outer diameters of the collapsed ring.', 'As the angle θ\n2 \napproaches 90 degrees, a shallower, finer wedge profile is created by the element, which may enable optimisation of the collapsed volume of the ring structure.', 'Although a shallower, finer wedge profile may have the effect of reducing the size of the gaps created at the inner surface of the ring in the collapsed condition and/or enabling a more compact collapsed condition, there are some consequences.', 'These include the introduction of flat sections at the inner surfaces of the elements, which manifest as spaces at the inner diameter of the ring when in an expanded or partially expanded condition.', 'When θ\n2\n=90 degrees, at the segments are purely tangential to inner diameter, the collapsed volume for a given outer diameter and inner diameter is most efficient, but the inner surface of the ring structure is polygonal with flat sections created by each segment.', 'In some configurations, these flat sections may be undesirable.', 'There may also be potential difficulties with manufacture of the elements and robustness of the elements and assembled ring structure.', 'However, in many applications, where the profile of the inner surface of the expanded ring is not critical, for example when the inner diameter of the ring structure is floating, and/or the true inner diameter is defined by an actuation wedge profile rather than the inner surface of the ring, this compromise may not be detrimental to the operation of the apparatus, and the reduced collapse volume may justify an inclination angle θ\n2 \nof (or approaching) 90 degrees.', 'In the apparatus of \nFIGS. 1 to 4\n, the angle θ\n2 \nis 75 degrees.', 'Relaxing θ\n2 \nto a reduced angle provides a smooth outer diameter and inner diameter profile to the expanded ring, as a portion of the inner circular arc is retained at the expense of slightly increased collapsed volume.', 'It should be noted that the angle θ\n2 \nis independent from the angle θ\n1\n.', 'Where the ring structure is desired to have a circular inner surface, preferred arrangements may have an angle θ\n2 \nwhich is in the range of (90 degrees-2θ\n1\n) to 90 degrees inclusive, and particularly preferred arrangements have an angle θ\n2 \nin the range of 70 degrees to 90 degrees (most preferably in the range of 73 degrees to 90 degrees).', 'In general, to provide sufficient truncation of the inner diameter to retain a useful portion of an inner arc and provide a smooth inner surface to the ring structure, a maximum useful value of θ\n2 \nis (90 degrees-θ\n1\n/2).', 'This would be 82.5 degrees in the described arrangements.', 'In other configurations, also in accordance with embodiments of the invention (and as will be described below) the geometry of the notional wedge-shaped segments forming the elements may be unmodified (save for the provision of functional formations such as for interlocking and/or retention of the elements), without the removal of material from the tip of the notional wedge-shaped segments.', 'Such embodiments may be preferred when there is no requirement for the ring structure to have a circular inner surface.', 'As most clearly shown in \nFIGS.', '4A to 4F\n, the first and second contact surfaces of the element have corresponding interlocking profiles \n24\n formed therein, such that adjacent elements can interlock with one another.', 'In this case, the interlocking profiles comprise a dovetail groove \n25\n and a corresponding dovetail tongue \n26\n.', 'The interlocking profiles resist circumferential and/or radial separation of the elements in the ring structure, but permit relative sliding motion between adjacent elements.', 'The interlocking profiles also facilitate smooth and uniform expansion and contraction of the elements during use.', 'It will be appreciated that alternative forms of interlocking profiles, for example comprising recesses and protrusions of other shapes and forms, may be used within the scope of the invention.', 'The elements are also provided with inclined side wall portions \n27\n, which may facilitate deployment of the apparatus in use.', 'The side wall portions are formed in an inverted cone shape which corresponds to the shape and curvature of the actuating cone wedges profiles when the apparatus is in its maximum load condition (typically at its optimum expansion condition).', 'Each element is also provided with a groove \n28\n, and in the assembled ring structure, the grooves are aligned to provide a circular groove which extends around the ring.', 'The groove accommodates a biasing element (not shown), for example a spiral retaining ring of the type marketed by Smalley Steel Ring Company under the Spirolox brand, or a garter spring.', 'In this case, the biasing means is located around the outer surface of the elements, to bias the apparatus towards the collapsed condition shown in \nFIGS.', '1A to 1D\n.', 'Although one groove for accommodating a biasing means is provided in this arrangement, in embodiments of the invention, multiple grooves and biasing means may be provided.', 'The apparatus \n10\n comprises a wedge member \n16\n, which in this case is an annular ring having a conical surface \n18\n opposing one side of the ring structure \n11\n.', 'The wedge angle corresponds with the angle of the inclined conical side walls \n27\n of the elements.', 'A corresponding wedge shaped profile (not shown) is optionally provided on the opposing side of the ring structure to facilitate expansion of the ring elements.', 'In alternative arrangements this optional additional wedge may be substituted with an abutment shoulder.', 'Operation of the expansion apparatus \n10\n will now be described.', 'In the first, collapsed or unexpanded condition, shown most clearly in \nFIG.', '1C\n, the elements are assembled in a ring structure \n11\n which extends to a first outer diameter.', 'In this configuration, and as shown in \nFIGS.', '1B and 1C\n, the wedge member \n16\n defines the maximum outer diameter of the apparatus in the first condition.', 'The elements are biased towards the unexpanded condition by a spiral retaining ring (not shown), and are supported on the inner surface by the outer surface of the cylinder \n14\n.', 'In use, an axial actuation force is imparted on the wedge member \n16\n.', 'Any of a number of suitable means known in the art can be used for application of the axial actuation force, for example, the application of a force from an outer sleeve positioned around the cylinder.', 'The force causes the wedge member \n16\n to move axially with respect to the cylinder, and transfer a component of the axial force onto the recessed side wall of the elements.', 'The angle of the wedge transfers a radial force component to the elements \n12\n, which causes them to slide with respect to one another along their respective contact surfaces.', 'The movement of the expanding elements is tangential to a circle defined around the longitudinal axis of the apparatus.', 'The contact surfaces of the elements mutually support one another before, during, and after expansion.', 'The radial position of the elements increases on continued application of the axial actuation force until the elements are located at a desired outer radial position.', 'This radial position may be defined by a controlled and limited axial displacement of the wedge member, or alternatively can be determined by an inner surface of a bore or tubular in which the apparatus is disposed.', 'FIGS.', '2A to 2D\n show clearly the apparatus in its expanded condition.', 'At an optimal expansion condition, shown in \nFIGS.', '2B and 2D\n, the outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements.', 'The outer surface of the expansion apparatus can be optimised for a specific diameter, to form a perfectly round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.', 'It is a feature of the described arrangement that the elements are mutually supported before, throughout, and after the expansion, and do not create gaps between the individual elements during expansion or at the fully expanded position.', 'In addition, the arrangement of elements in a circumferential ring, and their movement in a plane perpendicular to the longitudinal axis, facilitates the provision of smooth side faces or flanks on the expanded ring structure.', 'With deployment of the elements in the plane of the ring structure, the overall width of the ring structure does not change.', 'This enables use of the apparatus in close axial proximity to other functional elements.', 'The apparatus has a range of applications, some of which are illustrated in the following example embodiments.', 'However, additional applications of the apparatus are possible which exploit its ability to effectively perform one or more of blocking or sealing an annular path; contacting an auxiliary surface; gripping or anchoring against an auxiliary surface; locating or engaging with radially spaced profiles; and/or supporting a radially spaced component.', 'Aspects of the present invention extend the principles described above to expanding apparatus comprising combinations of structural elements, ring elements, and combinations thereof, which have particular applications and advantages to systems in which an increased expansion ratio is desirable.', 'The following embodiments of the invention describe examples of such apparatus.', 'Referring now to \nFIGS.', '5A to 7C\n, there is shown an expansion apparatus in accordance with a first embodiment of the invention.', 'FIGS.', '5A to 5C\n are respectively isometric, side and end views of an apparatus, generally shown at \n50\n, shown in a collapsed condition on a central mandrel \n60\n.', 'FIGS.', '6A to 6C\n are corresponding views of the apparatus \n50\n in a partially expanded condition and \nFIGS.', '7A to 7C\n corresponding views of the apparatus \n50\n in a fully expanded condition.', 'The apparatus \n50\n comprises an expansion assembly \n51\n formed from a plurality of elements, including a set of ring elements \n52\n assembled together to form a centrally disposed ring structure \n54\n, and two sets \n55\na\n, \n55\nb \nof structural elements \n56\n.', 'The ring elements \n52\n are similar to the elements \n12\n, and their form and function will be understood from \nFIGS.', '1 to 4\n and their accompanying description.', 'The ring elements \n52\n are shown in more detail in \nFIGS.', '8 and 9A to 9F\n, and comprise the inner and outer surfaces, first and second contact surfaces, interlocking profiles, and a groove for retaining a circumferential spring, which features are equivalent in form and function to the features of the elements \n12\n.', 'Biasing means in the form of a circumferential spring (not shown) retains the centre ring structure in its collapsed condition shown in \nFIGS.', '5A to 5C\n.', 'The geometry of the individual ring elements \n52\n differs from the geometry of the ring elements \n12\n, in that the elements are based on a notional wedge-shaped segment which is unmodified (save for the provision of functional formations such as for interlocking and/or retention of the elements), and without the removal of material from the tip of the notional wedge-shaped segments.', 'This arrangement may be preferred when there is no requirement for the ring structure to have a circular inner surface, as is the case with the “floating” ring structure of the apparatus \n50\n.', 'Each element comprises an outer surface \n221\n and first and second contact surfaces \n222\n, \n223\n.', 'The first and second contact surfaces are oriented in non-parallel planes, which are tangential to a circle centred on the longitudinal axis of the apparatus with radius r\n3\n.', 'The inner surface of the ring structure is defined at r\n3\n, and therefore the orientation planes are fully tangential (and angle θ\n2\n is 90 degrees).', 'The planes converge towards the inner surface of the element to an intersection line on a radial plane P which bisects the radial planes at the tangent points (i.e. is at an angle of θ\n1\n/2 to both).', 'This intersection plane P defines the expanding and collapsing path of the segment.', 'Therefore, each element is in the general form of a wedge, and the wedges are assembled together in a circumferentially overlapping fashion to form the ring structure \n54\n.', 'In use, the first and second contact surfaces \n222\n, \n223\n of adjacent elements are mutually supportive.', 'In this case, the ring structure \n54\n is formed from twenty-four identical elements, and the angle described between the first and second contact surfaces is 15 degrees, so that the elements are arranged rotationally symmetrically in the structure.', 'As most clearly shown in \nFIGS.', '9A to 9F\n, the first and second contact surfaces of the element have corresponding interlocking profiles \n224\n formed therein, such that adjacent elements can interlock with one another.', 'In this case, the interlocking profiles comprise a dovetail groove \n225\n and a corresponding dovetail tongue \n226\n.', 'The interlocking profiles resist circumferential and/or radial separation of the elements in the ring structure, but permit relative sliding motion between adjacent elements.', 'The interlocking profiles also facilitate smooth and uniform expansion and contraction of the elements during use.', 'The elements \n52\n differ from the elements \n12\n in that the tongue and groove are inverted, with the tongue on the element \n52\n on the (longer) contact surface \n223\n.', 'This facilitates increased contact between adjacent elements throughout the expanding and contracted range.', 'It will be appreciated that alternative forms of interlocking profiles, for example comprising recesses and protrusions of other shapes and forms, may be used within the scope of the invention.', 'Each element is also provided with a groove \n228\n, and in the assembled ring structure, the grooves are aligned to provide a circular groove which extends around the ring.', 'The groove accommodates a biasing element (not shown), for example a spiral retaining ring of the type marketed by Smalley Steel Ring Company under the Spirolox brand, or a garter spring.', 'In this case, the biasing means is located around the outer surface of the elements, to bias the apparatus towards the collapsed condition shown in \nFIGS.', '5A to 5D\n.', 'Although one groove for accommodating a biasing means is provided in this arrangement, in embodiments of the invention, multiple grooves and biasing means may be provided.', 'The structural elements \n56\n are in the form of spokes or struts.', 'First ends of each of the spokes \n56\n are connected to a respective retaining ring \n57\n \na\n, \n57\n \nb\n.', 'Each ring element \n52\n is connected to a pair of spokes \n56\n, one from each of the respective sets \n55\n \na\n, \n55\n \nb\n, at their second ends.', 'The first and second ends are provided with balls or knuckles \n58\n, which are received in respective sockets \n59\n (not shown in \nFIG.', '8 or 9\n for clarity of the geometry) in the retaining rings and ring elements to create a pivoting and rotating connection.', 'In a first, collapsed condition, the apparatus has a first outer diameter, which is defined by the outer edges of the ring elements \n52\n.', 'Operation of this embodiment of the apparatus will be described, with additional reference to \nFIGS.', '6A to 7C\n.', 'The apparatus is actuated to be radially expanded to a second diameter by an axial actuation force, which acts on one or both of the retaining rings to move one or both with respect to the mandrel \n60\n.', 'The retaining rings function as pusher rings for the apparatus.', 'Any of several suitable means known in the art can be used for application of the axial actuation force, for example, the application of a force from an outer sleeve positioned around the cylinder.', 'The axial actuation force acts through the sets of spokes to impart axial and radial force components onto the ring elements.', 'The pivot point between the ring elements and the spoke is set radially further out from the mandrel than the pivot point between the retaining rings and the spokes.', 'This ensures that any compressive force on the end rings has a radial component to act radially on the ring element.', 'Radial expansion of the ring structure \n54\n is initially resisted by the circumferential spring.', 'When the force of the spring is overcome, the ring elements of the centre ring structure are moved radially outward from the collapsed position, towards the partially expanded condition shown in \nFIGS.', '6A to 6C\n.', 'As the ring structure \n54\n moves radially outward, the spokes pivot with respect to the retaining rings and the ring elements to create a pair of substantially conical supports for the ring structure \n54\n.', 'The ring elements \n52\n slide tangentially with respect to one another to expand the centre ring structure as the first ends of the spokes are moved towards one another.', 'As the retaining rings and sets of spokes are brought towards the position shown in \nFIGS.', '7A to 7C\n, the ring elements \n52\n slide with respect to one another into the radially expanded condition.', 'The radial movement of the elements of the outer rings is the same as the movement of the elements described with reference to \nFIGS.', '1 to 4\n: the ring elements slide with respect to one another in a tangential direction, while remaining in mutually supportive planar contact.', 'The interlocking arrangement of the ring elements enables the apparatus to move uniformly between the contracted and expanded condition.', 'The resulting expanded condition is shown in \nFIGS.', '7A to 7C\n.', 'The apparatus forms an expanded ring structure which is solid, with no gaps between its elements, and which has a smooth circular outer surface at its fully expanded condition.', 'The outer diameter of the expanded ring is significantly greater than the outer diameter of the ring structures in their collapsed state, with the increased expansion resulting from the combination of sets of structural elements supporting the ring structure \n54\n.', 'The open structure of the conical support renders this embodiment particularly suitable for applications such as lightweight centralisation, swaging applications, removable support structures, and/or adjustable drift tools.', 'Maintaining the axial force on the retaining rings will keep the apparatus in an expanded condition, and a reduction in the axial force to separate the retaining rings enables the ring structure and sets of spokes to collapse under the retention forces of the spring element.', 'Collapsing of the apparatus to a collapsed condition is therefore achieved by releasing the axial actuation force.', 'Separation of the retaining rings collapses the ring structure under the retaining force of its biasing spring, back to the collapsed position shown in \nFIGS.', '5A to 5C\n.', 'In addition, the connections between the spokes and the ring elements, and the spokes and the retaining ring (which in this embodiment are ball and socket or knuckle and socket connections), are configured to enable the transfer of a tensile force.', 'This enables a tension to be pulled between the retaining rings, the structural elements and the ring elements (or vice versa).', 'This axial interlocking of the spokes and ring elements ties the components together longitudinally, and enables a tension to be pulled between the elements to retract the apparatus towards or to its collapsed condition.', 'Pulling a tension may facilitate collapsing of the apparatus to its original outer diameter, in conjunction with the action of a biasing spring, or in alternative embodiments, the tensile force may be used to retract the apparatus without the use of a biasing spring.', 'The apparatus may therefore be a passive device, with no default condition defined by a biasing means.', 'The combination of structural elements and the ring structure enables the provision of an expanding and collapsing apparatus having the advantages of an expanded ring structure that is solid, with no gaps between its elements, and a smooth circular outer surface at its fully expanded condition, with increased maximum expansion ratios.', 'The arrangements provide increased maximum expansion ratios with few additional moving parts and little increase in complexity over with the ring structure of \nFIGS.', '1 to 4\n.', 'Referring now to \nFIGS.', '10A to 11D\n, there is shown an expanding and collapsing apparatus according to an alternative embodiment of the invention, generally depicted at \n80\n.', 'FIGS.', '10A and 10B\n are respectively isometric and longitudinal sectional views of the apparatus in a collapsed position, and \nFIGS.', '10C and 10D\n are respectively cross sectional views of the through lines C-C and D-D of \nFIG.', '10B\n.', 'FIGS.', '11A to 11D\n are corresponding views of the apparatus in an expanded condition.', 'The apparatus \n80\n is similar to the apparatus \n50\n, and will be understood from \nFIGS.', '5 to 9\n and the accompanying description.', 'The apparatus \n80\n comprises an expansion assembly \n81\n formed from a plurality of elements, including a set of ring elements \n82\n assembled to form a centrally disposed ring structure \n84\n.', 'The ring elements \n82\n, most clearly shown in \nFIG.', '13\n, are similar in form and function to the ring elements \n52\n of the previous embodiment of the invention.', 'Two sets \n85\na\n, \n85\nb \nof structural elements \n86\n are in the form of cone segments, shown most clearly in \nFIG.', '12\n.', 'The cone segment \n86\n has an outer surface \n91\n, an upper planar contact surface \n93\n, and a lower planar contact surface \n95\n.', 'First ends of each of the cone segment \n86\n are connected to a respective retaining ring \n87\na\n, \n87\nb \nby a hook \n88\n for engaging with an undercut in the retaining ring.', 'Each ring element \n82\n is connected to a pair of segments \n86\n, one from each of the respective sets \n85\na\n, \n85\nb\n, at their second ends.', 'The second ends of the segments \n86\n are provided with balls or knuckles \n83\n, which are received in respective recesses \n89\n in the ring elements to create a pivoting and rotating connection.', 'In a first, collapsed condition, the apparatus has a first outer diameter, which is defined by the outer edges of the ring elements \n84\n.', 'Operation of this embodiment of the apparatus is similar to the operation of the apparatus \n50\n.', 'The apparatus is actuated to be radially expanded to a second diameter by an axial actuation force, which acts on one or both of the retaining rings to move one or both with respect to the mandrel \n90\n.', 'The axial actuation force acts through the sets of cone segments to impart axial and radial force components onto the ring elements.', 'Radial expansion of the ring structure \n84\n is initially resisted by the circumferential spring, but when the force of the spring is overcome, the ring elements of the central ring structure \n84\n are moved radially outward from the collapsed position, towards the expanded condition shown in \nFIGS.', '11A to 11D\n.', 'As the ring structure \n84\n moves radially outward, the segments pivot with respect to the retaining rings and the ring elements to create a pair of conical support structures for the ring \n84\n.', 'Each ring segment is supported in an A-frame arrangement.', 'The ring elements \n82\n slide tangentially with respect to one another to expand the centre ring structure as the first ends of the cone segments are moved towards one another.', 'In addition, on any selected plane along the length of the cone segment perpendicular to the longitudinal axis (for example section C-C of \nFIGS. 100 and 10D\n), the cone segment is moving tangentially to a circle that is in the selected plane and concentric with the longitudinal axis.', 'Movement of the cone segments \n86\n with respect to one another is governed by their shape, and \nFIGS.', '14A, 14B, and 15A to 15C\n are useful for understanding the manner in which the shape of the cone segments is created in embodiments of the invention.', 'FIGS.', '14A and 14B\n show the cone segment \n86\n, complete with hook \n88\n and knuckle \n83\n, as a segment of a hollow cone \n92\n.', 'FIGS.', '15A to 15C\n are geometric reference diagrams, useful for understanding how a simplified cone segment \n96\n of an embodiment of the invention may be formed.', 'Referring to \nFIGS.', '15A to 15C\n, the starting point for forming the cone segment \n96\n is a hollow cone \n102\n (\nFIG.', '15C\n), with an internal cone angle, minimum inner diameter and outer diameter, and maximum inner diameter and outer diameter.', 'The cone can have any internal and external angle, and need not have a uniform wall thickness (although the example cone \n102\n does have a uniform wall thickness).', 'On the small end of the cone, as shown in \nFIG.', '15B\n, the cross sectional profile of the cone segment is based on a notional wedge-shaped segment of a ring, as described with respect to previous embodiments.', 'The ring is centred on an axis, with the notional wedge-shaped segment being inclined with respect to the radial direction of the ring.', 'The nominal outer diameter of the segment is at the optimum expansion condition of the ring (with radius shown at r\n1\n).', 'As with the embodiment of \nFIGS.', '5 to 9\n, the orientation planes of upper and lower contact surfaces of the segment element are tangential to a circle centred on the longitudinal axis of the apparatus with radius r\n3\n.', 'The inner surface of the ring structure is defined at r\n3\n, and therefore the orientation planes are fully tangential (and angle θ\n2 \nis 90 degrees).', 'The angle described between the tangent points is equal to the angle θ\n1 \nof the segment.', 'The orientation planes of the first and second contact surfaces of each notional wedge-shaped segment intersect on a radial plane P which bisects the radial planes at the tangent points (i.e. is at an angle of θ\n1\n/2 to both).', 'This intersection plane P defines the expanding and collapsing path of the segment.', 'In this apparatus, the segment angle θ\n1 \nis 15 degrees, and the radial plane P is inclined to the radial plane at the tangent point by 7.5 degrees.', 'Having determined the profile \n104\n of one end of the segment, the internal angle of the inside face of the cone \n102\n defines the inclined angle of the upper and lower planar surfaces of a formed segment which extend from the end profile \n104\n.', 'The upper planar surface \n93\n is defined by a cut through the body of the cone from the upper line of the end profile \n104\n, where the cut remains tangential to the inner surface of the cone throughout the length of the cone.', 'The lower planar surface \n95\n is defined by a cut through the body of the cone from the lower line of the end profile \n104\n, where the cut remains tangential to the inner surface of the cone throughout the length of the cone.', 'The outer surface \n91\n of the segment is simply the outer surface of cone between the upper and lower planar surfaces.', 'The geometry of a cross-section of the cone segment is the same at each position through the length of the segment: the outer surface \n91\n is at the nominal outer diameter of the segment at the optimum expansion condition of the ring; the first and second contact surfaces of the cone segment are tangential to the circle at radius r\n3\n, and the orientation planes of the first and second contact surfaces intersect on a radial plane P inclined at an angle of θ\n1\n/2 to the radial planes at the tangent points.', 'The same radial plane P can be described as being inclined to the upper contact surface by an angle of 90−θ\n1\n/2 degrees and inclined to the lower contact surface by an angle of 90+θ\n1\n/2.', 'This principle is used to determine the basic shape of the cone segment, which may then be detailed with additional features such as grooves and undercuts to create the functional cone segment \n86\n.', 'In use, as the retaining rings \n87\n and sets of cone segments are brought towards the position shown in \nFIGS.', '11A to 11D\n, the ring elements \n82\n and the structural ring elements \n86\n slide with respect to one another into the radially expanded condition.', 'The radial movement of the elements of the outer rings is the same as the movement of the elements described with reference to \nFIGS.', '1 to 4\n: the elements \n82\n and \n86\n slide with respect to one another in a tangential direction, while remaining in mutually supportive planar contact.', 'The centrally positioned ring segments ensure that the outer structural segments remain held in a uniform pattern, equally spaced and evenly deployed.', 'The expansion of the centre ring also controls the alignment and the order of the outer structural segments.', 'The resulting expanded condition is shown in \nFIGS.', '11A to 11D\n.', 'The apparatus is preferably expanded to an optimal expansion condition, at which the planar surfaces of cone segments are in full contact, and where the outer diameter defined by the ring structure \n84\n is slightly smaller than the inner diameter of a conduit or borehole in which the apparatus is located.', 'Further thrust on the retaining rings causes over-expansion of the ring structure, without substantially affecting the surface profile of the conical or cylindrical ring structures.', 'Maintaining the axial force on the retaining rings will keep the apparatus in an expanded condition, and a reduction in the axial force to separate the retaining rings enables the ring structure and sets of spokes to collapse under the retention forces of the spring element.', 'Collapsing of the apparatus to a collapsed condition is therefore achieved by releasing the axial actuation force.', 'Separation of the retaining rings collapses the ring structure \n82\n under the retaining force of its biasing spring, back to the collapsed position shown in \nFIGS.', '10A to 10C\n.', 'The combination of structural elements and the ring structure enables the provision of an expanding and collapsing apparatus with increased maximum expansion ratios.', 'The arrangements provide increased maximum expansion ratios with few additional moving parts and little increase in complexity over with the ring structure of \nFIGS.', '1 to 4\n.', 'The apparatus forms an expanded ring structure which is solid, with no gaps between its elements, and which has a smooth circular outer surface at its fully expanded condition.', 'In addition, the conical support structures created by the cone segments are formed as solid, smooth flanks of the expanded apparatus.', 'This facilitates use of the conical structures as deployment or actuation devices, or support structures for seal elements and other mechanical structures, as will be described in more detail below.', 'A variation to the apparatus \n80\n will now be described with reference \nFIGS.', '16A to 18B\n.', 'FIGS.', '18A and 18B\n are longitudinal sectional views of an apparatus \n280\n, which is similar to the apparatus \n80\n and which will be understood from \nFIGS.', '10 to 15\n and the accompanying description.', 'FIGS.', '16A to 16C\n are various views of a ring element \n282\n of the apparatus \n280\n, and \nFIGS.', '17A and 17B\n are isometric views of a structural element \n286\n.', 'The basic geometry of the ring element \n282\n and structural element \n286\n is the same as the geometry of the elements \n82\n and \n86\n as previously described.', 'As with the apparatus \n80\n, a hook \n288\n is provided for engaging with an undercut in the retaining ring.', 'However, the elements of this embodiment differ in the configuration of their connection to one another.', 'Instead of the spherical ball joint and socket provided in components of the apparatus \n80\n, the apparatus \n280\n has a knuckle joint \n283\n provided on the structural element \n286\n, and a corresponding socket \n289\n on the ring element \n282\n.', 'The socket \n289\n comprises an opening on the lower contact surface for receiving the knuckle \n283\n, and a U-shaped slot in the side wall which enables the elements to be assembled while retaining the knuckle, and allows a tension to be pulled between the structural element and the retaining ring (or vice versa).', 'Corresponding side walls of the ring element \n282\n and the structural element \n286\n are also provided with a cooperating arrangement of knurls \n272\n and sockets \n274\n.', 'The knurls \n272\n self-locate in the sockets \n274\n when the apparatus is in its expanded condition, shown in \nFIG.', '18B', 'and provide additional support to the structure.', 'In this embodiment, two knurls are provided on each side wall of each ring element, with corresponding sockets provided on the contacting side wall of the structural element, but it will be appreciated that in alternative embodiments the position may be reversed, and/or other configurations of locating formations may be provided.', 'Although the foregoing embodiments include combinations of cylindrical ring structures and conical support assemblies, the principles of the invention can also be applied to alternative configurations, including expanding cone structures without connection to cylindrical rings.', 'An example embodiment is described with reference to \nFIGS.', '19A to 20D\n.', 'FIGS.', '19A to 19C\n are respectively isometric, longitudinal sectional and end views of an apparatus, generally depicted at \n140\n, in a collapsed condition.', 'FIGS.', '20A to 20C\n are corresponding views of the apparatus \n140\n in an expanded condition.', 'The apparatus \n140\n comprises an expansion assembly \n141\n formed from a plurality of elements, including a set of ring elements \n142\n assembled together to form conical ring structure \n154\n.', 'The elements \n142\n are assembled on a mandrel \n150\n, with first ends of the elements connected to a retaining ring \n147\n.', 'Second ends of the elements \n142\n are adjacent an actuating wedge cone \n143\n.', 'The ring elements \n142\n are similar to the cone segments \n86\n, and their form and function will be understood from \nFIGS.', '10A to 11D\n and the accompanying description.', 'The shape of the ring elements \n142\n is created by the principles described with reference to \nFIGS.', '14A to 15C\n.', 'The cone segments comprise an outer surface, an upper planar contact surface, and a lower planar contact surface.', 'The contact surfaces are mutually supportive when assembled to form the ring structure.', 'In a first, collapsed condition, the apparatus has a first outer diameter, which is defined by the outer edges of the second ends of the ring elements \n142\n.', 'The shape of the assembly in its collapsed condition is substantially conical.', 'In use, the apparatus is actuated to be radially expanded to a second diameter by an axial actuation force, which acts on one or both of the retaining ring \n147\n or the wedge \n143\n to move one or both with respect to the mandrel \n150\n.', 'The force causes the wedge member \n143\n to move axially with respect to the elements, and transfer a component of the axial force onto inner surfaces of the elements.', 'The angle of the wedge transfers a radial force component to the elements \n142\n, which causes them to slide with respect to one another along their respective contact surfaces.', 'The movement of the expanding elements is tangential to a circle defined around the longitudinal axis of the apparatus.', 'The contact surfaces of the elements mutually support one another before, during, and after expansion.', 'The radial position of the elements increases on continued application of the axial actuation force until the elements are located at a desired outer radial position.', 'This radial position may be defined by a controlled and limited axial displacement of the wedge member, or alternatively can be determined by an inner surface of a bore or tubular in which the apparatus is disposed.', 'FIGS.', '20A to 20C\n show the apparatus in its expanded condition.', 'At an optimal expansion condition, shown in \nFIGS. 20B and 20C\n, the outer surfaces of the individual elements combine to form a complete conical surface with no gaps in between the individual elements.', 'At the second end of the elements \n142\n, a cylindrical surface \n145\n is formed at the optimal expanded condition.', 'The outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements.', 'The outer surface of the expansion apparatus can be optimised for a specific diameter, to form a perfectly smooth cone and round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.', 'It is a feature of the described arrangement that the elements are mutually supported before, throughout, and after the expansion, and do not create gaps between the individual elements during expansion or at the fully expanded position.', 'In addition, the arrangement of elements in a circumferential ring, and their movement in a plane perpendicular to the longitudinal axis, facilitates the provision of smooth side faces or flanks on the expanded ring structure.', 'This enables use of the apparatus in close axial proximity to other functional elements.', 'The apparatus \n140\n may be used in conjunction with the apparatus of other embodiments in order to provide an assembly of expanding apparatus.', 'An example embodiment is described with reference to \nFIGS.', '21A to 22D\n.', 'FIGS.', '21A to 21C\n are respectively isometric, longitudinal sectional and cross sectional views of an apparatus, generally depicted at \n160\n, in a collapsed condition.', 'FIGS.', '22A and 22B\n are respectively partially cut away isometric and longitudinal sectional views of the apparatus \n160\n in an expanded condition.', 'FIGS.', '22C and 22D\n are respectively cross sectional views of the apparatus of \nFIGS.', '22A and 22B\n through lines C-C and D-D of \nFIG.', '22B\n.', 'The apparatus \n160\n comprises a mandrel \n170\n supporting a centrally disposed expanding apparatus \n162\n, which is of the same form of the apparatus \n80\n, with the same functionality and operation.', 'Either side of apparatus \n162\n are expanding apparatus \n164\na\n, \n164\nb \ncomprising cone structures of similar construction as the apparatus \n140\n, with the same functionality and operation.', 'Axially outside of the apparatus \n164\na\n, \n164\nb \nare additional expanding apparatus \n166\na\n, \n166\nb\n, which comprise cone structures of similar construction as the apparatus \n140\n, and have the same functionality and operation.', 'In use, the apparatus \n160\n is actuated to be radially expanded to a second diameter by an axial actuation force, which acts on one or both of the retaining rings \n167\na\n, \n167\nb \nto move one or both with respect to the mandrel \n170\n.', 'Relative movement of the outer retaining rings causes the expanding apparatus to expand to their expanded conditions, driven by the conical wedge surfaces of the respective retaining rings \n163\na\n, \n163\nb\n,', '165\na \nand \n165\nb.', 'The expanded condition of the apparatus \n160\n is shown in \nFIGS.', '22A to 22D\n.', 'As described above with reference to \nFIGS.', '10 and 11\n, the apparatus \n162\n expands to a form which defines first and second hollow conical support structures at first and second flanks of the apparatus.', 'The internal angles of the hollow cones formed by expanding apparatus \n164\na \nand \n164\nb \ncorrespond to the external cone angles of the apparatus \n162\n, and the apparatus \n164\na \nand \n164\nb \nare brought into abutment with the outer flanks of the apparatus \n162\n to create a nested, layered support structure.', 'Similarly, the internal angles of the hollow cones formed by expanding apparatus \n166\na \nand \n166\nb \ncorrespond to the external cone angles of the apparatus \n164\na \nand \n164\nb\n, and the apparatus \n166\na \nand \n166\nb \nare brought into abutment with the outer flanks defined by apparatus \n164\na \nand \n164\nb\n.', 'The combined apparatus, as most clearly shown in \nFIG.', '22B\n, provides additional support for the cylindrical ring structure \n161\n of the apparatus \n162\n due to the increase in effective wall thickness created by the abutment of conical support structures in a nested arrangement.', 'Each conical surface is substantially or completely smooth, and therefore the contact between conical support structures over the majority of the surfaces to optimise mechanical support.', 'In this embodiment, the direction in which the cone segments are layered differs between adjacent apparatus; the layering of cone segments in apparatus \n164\na\n, \n164\nb \nis reversed compared to the direction of layering in apparatus \n162\n, \n166\na \nand \n166\nb\n.', 'This results in a cross-ply effect between support layers in the expanded condition, most clearly shown in \nFIG.', '22A\n, enhancing mechanical support and load bearing through the apparatus, and increasing the convolution of any path between segments of adjacent support layers.', 'Retraction of the apparatus to a collapsed condition is performed by releasing or reversing the axial force on the outermost retaining rings \n167\na\n, \n167\nb\n.', 'This is facilitated by lips \n171\n provided on the inner surface of the cone segments, most clearly shown in \nFIGS.', '21B and 22A\n.', 'When the expanding cone is in a collapsed condition, the lips \n171\n of its cone segments engage with an external rim on the retaining ring of an adjacent expanding cone.', 'When the outermost pair of expanding cones \n166\na\n, \n166\nb \nis collapsed under tension, the lips engage the rim of the retaining rings \n165\na\n, \n165\nb \nto impart tension to the retaining rings and retract the expanding cones \n164\na\n, \n164\nb\n.', 'Similarly, the when the expanding cones \n164\na\n, \n164\nb \nare collapsed under tension, the lips \n171\n engage the rim of the retaining rings \n163\na\n, \n163\nb \nto impart tension to the retaining rings and retract the expanding apparatus \n162\n.', 'Although two pairs of expanding cones are provided to support the apparatus \n162\n in the embodiment of \nFIGS.', '21 to 22\n, in alternative embodiments fewer or greater numbers of expanding cones may be used, depending on the application.', 'In some applications, support may be provided by a single expanding cone brought into abutment with just one of the flanks of the apparatus \n162\n.', 'Alternatively, multiple expanding cones may be used in a nested configuration to support just one of the flanks of the apparatus \n162\n.', 'Alternatively, unequal numbers of expanding cones may be used to support opposing flanks of the apparatus \n162\n.', 'Within the scope of the invention, the expanding apparatus used in nested configurations as described with reference to \nFIGS.', '21 and 22\n may have different physical properties including but not limited to configuration, size, wall thickness, conical angle, and/or material selection, depending on application.', 'For example, in a variation to the embodiment described with reference to \nFIGS.', '21 and 22\n, the cone segments of apparatus \n164\na \nand \n164\nb \ndiffer from the cone segments of the apparatus \n162\n, \n166\na \nand \n166\nb \nto provide an improved sealing effect.', 'The cone segments of the apparatus \n164\na\n, \n164\nb \nare formed from metal which is coated with a compliant polymeric material, such as a silicone polymer coating.', 'All surfaces of the elements are coated, and the mutually supportive arrangement of the cone segments within the apparatus \n164\na\n, \n164\nb\n, combined with the support from the adjacent apparatus \n162\n, \n166\na \nand \n166\nb\n, keeps them in compression in their operating condition.', 'This enables the combined apparatus to function effectively as a flow barrier, and in some applications, the barrier created is sufficient to seal against differential pressures to create a fluid tight seal.', 'In variations to the described embodiment, the material selected for the cone segments itself is a compliant or elastomeric material such as an elastomer, polymer or rubber rather than a coated metallic or other hard material.', 'Alternatively, the segments may comprise a skeleton or internal structure formed from a metallic or other hard material, coated or encased in a compliant or elastomeric material such as an elastomer, polymer or rubber an elastomer, polymer or rubber.', 'The cone segments of all, some or one of the expanding apparatus may be formed from these alternative materials, or different materials may be used for different expanding apparatus.', 'An individual expanding apparatus of the invention may be configured to provide sealing functionality, and may therefore similarly be fully or partially formed from compliant or elastomeric materials.', 'Referring now to \nFIGS.', '23A to 24C\n, there is shown an expanding and collapsing apparatus in accordance with an alternative embodiment of the invention, configured as a seal for a fluid conduit or borehole.', 'The apparatus, generally depicted at \n180\n, comprises an expansion assembly \n181\n formed from a plurality of elements, including a set of ring elements \n182\n assembled together to form conical ring structure \n184\n.', 'The elements \n182\n are assembled on a mandrel \n190\n, with first ends of the elements connected to a retaining ring \n187\n.', 'Second ends of the elements \n182\n are adjacent an actuating wedge cone \n183\n.', 'The ring elements \n182\n are similar to the cone segments \n86\n and \n142\n, and their form and function will be understood from \nFIGS.', '10A to 11D, 19A to 20B\n, and the accompanying description.', 'The shape of the ring elements \n182\n is created by the principles described with reference to \nFIGS.', '14A to 15C\n.', 'The cone segments comprise an outer surface, an upper planar contact surface, and a lower planar contact surface.', 'The contact surfaces are mutually supportive when assembled to form the ring structure.', 'In a first, collapsed condition, the apparatus has a first outer diameter, which is defined by the outer edges of the second ends of the ring elements \n182\n.', 'The shape of the assembly in its collapsed condition is substantially conical.', 'The apparatus \n180\n differs from the apparatus \n140\n in that it is provided with a pleated layer \n195\n of compliant sealing material.', 'The layer \n195\n surrounds the retaining ring \n187\n and the expanding assembly \n181\n over the majority of its length, and is pleated to follow the profiled surface of upstanding edges and grooves defined by the collapsed assembly \n181\n.', 'The apparatus is actuated by an axial actuation force, which acts on one or both of the retaining ring \n187\n or the wedge \n183\n.', 'As the apparatus is expanded to the expanded condition shown in \nFIGS.', '24A to 24C\n, the layer \n195\n is unfolded to form a compliant conical sheath \n197\n around the expanded conical structure.', 'The apparatus \n180\n is just one example of how the invention may be applied to a fluid barrier or sealing apparatus, and other fluid barrier or sealing configurations are within the scope of the invention.', 'For example, the apparatus may be configured to operate in conjunction with a sealing element, for example an elastomeric body or an inflatable bladder, disposed beneath a hollow conical structure formed by the expanded cone segments.', 'The invention may be used to provide an anti-extrusion ring or back-up ring for a wide range of expanding, radially expanding or swelling elements.', 'For example, the apparatus may be used as an anti-extrusion or back-up ring for compressible, inflatable and/or swellable packer systems.', 'Alternatively, or in addition, the expansion apparatus may provide support or back-up for any suitable flow barrier or seal element in the fluid conduit.', 'This may function to improve the integrity of the fluid barrier or seal, and/or enable a reduction in the axial length of the seal element or flow barrier without compromising its functionality.', 'A particular advantage is that equipment incorporating the expansion apparatus of the present invention can be rated to a higher maximum working pressure.', 'In the foregoing embodiments, where the expanding and collapsing apparatus is used to create a seal, the seal is typically disposed between two expanding ring structures.', 'In alternative embodiments (not illustrated), an expanding ring structure can be used to provide a seal, or at least a restrictive flow barrier directly.', 'To facilitate this, the elements which are assembled together to create the ring structures may be formed from metal or a metal alloy which is coated with a polymeric, elastomeric or rubber material.', 'An example of such a material is a silicone polymer coating.', 'All surfaces of the elements may be coated, for example by a dipping or spraying process, and the mutually supportive arrangement of the elements keeps them in compression in their operating condition.', 'This enables the ring structures themselves to function as flow barriers, and in some applications, the barrier created is sufficient to seal against differential pressures to create a fluid tight seal.', 'A further application of the invention is to a fluid conduit patch tool and apparatus.', 'A typical patching application requires the placement and setting of a tubular section over a damaged part of a fluid conduit (such as a wellbore casing).', 'A patch tool comprises a tubular and a pair of setting mechanisms at axially separated positions on the outside of the conduit for securing the tubular to the inside of the fluid conduit.', 'It is desirable for the setting mechanisms to provide an effective flow barrier, but existing patch systems are often deficient in providing a fluid-tight seal with the inner surface of the fluid conduit.', 'A patch tool incorporating the expanding apparatus of the invention has the advantage of high expansion for a slim outer diameter profile, which enables the tool to be run through a restriction in the fluid conduit, to patch a damaged part of the conduit which has a larger inner diameter than the restriction.', 'For example, the patching tool could be run through a part of the fluid conduit that has already been patched.', 'In a further alternative embodiment of the invention (not illustrated) the characteristics of the expanding/collapsing apparatus are exploited to provide a substrate which supports a seal or another deformable element.', 'As described herein, the expanded ring structures of the invention provide a smooth circular cylindrical surface and/or a smooth conical surface at their optimum expanded conditions.', 'This facilitates their application as a functional endo-skeleton for a surrounding sheath.', 'In one example application, a deformable elastomeric sheath is provided over an expanding ring structure.', 'When in its collapsed condition, the sheath is supported by the collapsed ring structures.', 'The ring structures are deployed in the manner described with reference to \nFIGS.', '10 and 11\n, against the retaining force of the circumferential spring element and any additional retaining force provided by the sheath, and the sheath is deformed to expand with the ring structure into contact with the surrounding surface.', 'The sheath is sandwiched between the smooth outer surface of the ring structure and the surrounding surface to create a seal.', 'It will be appreciated that the apparatus could be used as an endo-skeleton to provide structural support for components other than deformable sheaths, including tubulars, expanding sleeves, locking formations and other components in fluid conduits or wellbores.', 'The expansion apparatus of the invention may be applied to a high expansion packer or plug, and in particular a high expansion retrievable bridge plug.', 'The ring structure may be arranged to provide a high-expansion anti-extrusion ring for a seal element of a plug.', 'Alternatively, or in addition, elements of ring structures of the apparatus may be provided with engaging means to provide anchoring forces which resist movement in upward and/or downward directions.', 'The elements of the rings structure may therefore function as slips, and may in some cases function as an integrated slip and anti-extrusion ring.', 'Advantages over previously proposed plugs include the provision of a highly effective anti-extrusion ring; providing an integrated slip and anti-extrusion assembly, which reduces the axial length of the tool; providing slips with engaging surfaces which extend around the entire circumference of the tool to create an enlarged anchoring surface, which enables a reduction in the axial length of the slips for the same anchoring force; the ability of slips of a ring structure of one particular size to function effectively over a wider range of tubular inner diameters and tubing weights/wall thicknesses.', 'Alternatively, or in addition, the apparatus may be used to anchor any of a wide range of tools in a wellbore, by providing the surfaces of the element with engaging means to provide anchoring forces which resist movement in upward and/or downward directions.', 'Variations to embodiments of the invention include the provision of functional formations on the basic elements in various arrangements.', 'These may include knurls and sockets for location and support, hooks, balls and sockets or knuckles and sockets for axial connection, and/or pegs and recesses to prevent relative rotation of the elements with respect to one another and/or with respect to the underlying structure of the apparatus.', 'The invention also has benefits in creating a seal and/or filling an annular space, and an additional example application is to downhole locking tools.', 'A typical locking tool uses one or more radially expanding components deployed on a running tool.', 'The radially expanding components engage with a pre-formed locking profile at a known location in the wellbore completion.', 'A typical locking profile and locking mechanism includes a recess for mechanical engagement by the radially expanding components of the locking tool.', 'A seal bore is typically provided in the profile, and a seal on the locking tool is designed to seal against the seal bore.', 'One advantage of the application of the invention to locking mechanism is that the locking mechanism may be provided with an integrated seal element between two expanding ring structures, and does not require a seal assembly at an axially separated point.', 'This enables a reduction in the length of the tool.', 'The integrated seal is surrounded at its upper and lower edges by the surfaces of the ring structures, which avoid extrusion of the seal.', 'In addition, each of the ring structures provides a smooth, unbroken circumferential surface which may engage a locking recess, providing upper and lower annular surfaces in a plane perpendicular to the longitudinal axis of the bore.', 'This annular surface may be smooth and unbroken around the circumference of the ring structures, and therefore the lock is in full abutment with upper and lower shoulders defined in the locking profile.', 'This is in contrast with conventional locking mechanisms which may only have contact with a locking profile at a number of discrete, circumferentially-separated locations around the device.', 'The increased surface contact can support larger axial forces being directed through the lock.', 'Alternatively, an equivalent axial support can be provided in a lock which has reduced size and/or mass.', 'Another advantage of this embodiment of the invention is that a seal bore (i.e. the part of the completion with which the elastomer creates a seal) can be recessed in the locking profile.', 'The benefit of such configuration is that the seal bore is protected from the passage of tools and equipment through the locking profile.', 'This avoids impact with the seal bore which would tend to damage the seal bore, reducing the likelihood of reliably creating a successful seal.', 'Similar benefits may be delivered in latching arrangements used in connectors, such as so called “quick connect” mechanisms used for latched connection of tubular components.', 'A significant advantage of the invention in connection system applications is that the expansion apparatus forms a solid and smooth ring in an expanded latched position.', 'An arrangement of radially split elements would, when expanded, form a ring with spaces between elements around their sides.', 'In contrast, the provision of a continuous engagement surface on the expansion ring which provides full annular contact with the recess results in a latch capable of supporting larger axial forces.', 'In addition, the by minimising or eliminating gaps between elements, the device is less prone to ingress of foreign matter which could impede the collapsing action of the mechanism.', 'These principles may also be applied to subsea connectors such as tie-back connectors, with optional hydraulic actuation of their release mechanism.', 'Additional applications of the principles of the invention include variable diameter tools, examples of which include variable diameter drift tools and variable diameter centralising tools.', 'The position of a wedge member and a cooperating surface may be adjusted continuously or to a number of discrete positions, to provide a continuously variable diameter, or a number of discrete diameters.', 'In one aspect, the invention provides an expanding and collapsing apparatus and methods of use.', 'The apparatus comprises a plurality of elements assembled together to form a ring structure around a longitudinal axis.', 'The ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements on actuation by an axial force.', 'At least one set of structural elements each having a first end and a second end are operable to move between the expanded condition and the collapsed condition by movement of the first end in an axial direction, and by movement of the second end in at least a radial dimension.', 'The plurality of elements comprises at least one set of elements operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', 'In another aspect, the expanding and collapsing ring comprises a plurality of elements assembled together to form a ring structure oriented in a plane around a longitudinal axis.', 'The plurality of elements comprises at least one set of structural elements extending longitudinally on the apparatus and operable to slide with respect to one another, wherein the sliding movement in a selected plane perpendicular to the longitudinal axis is tangential to a circle in the selected plane and concentric with the longitudinal axis.', 'Applications of the invention include oilfield devices, including anti-extrusion rings, plugs, packers, locks, patching tools, connection systems, and variable diameter tools run in a wellbore.', 'The invention in its various forms benefits from the novel structure and mechanism of the apparatus.', 'The invention also enables high expansion applications.', 'In addition, at an optimal expansion condition the outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements, and therefore the apparatus can be optimised for a specific diameter, to form a perfectly round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.', 'It is a feature of an aspect of the invention that the elements are mutually supported before, throughout, and after the expansion, and do not create gaps between the individual elements during expansion or at the fully expanded position.', 'In addition, the arrangement of elements in a circumferential ring facilitates the provision of smooth side faces or flanks on the expanded ring structure.', 'This enables use of the apparatus in close axial proximity to other functional elements, and/or as ramps or surfaces for deployment of other expanding structures.', 'In addition, each of the ring structures provides a smooth, unbroken circumferential surface which may be used in engagement or anchoring applications, including in plugs, locks, and connectors.', 'This may provide an increased anchoring force, or full abutment with upper and lower shoulders defined in a locking or latching profile, enabling tools or equipment be rated to a higher maximum working pressure.', 'Various modifications to the above-described embodiments may be made within the scope of the invention, and the invention extends to combinations of features other than those expressly claimed herein.', 'In particular, the different embodiments described herein may be used in combination, and the features of a particular embodiment may be used in applications other than those specifically described in relation to that embodiment.'] | ['1.', 'An expanding and collapsing apparatus comprising:\na plurality of elements assembled together to form a ring structure around a longitudinal axis, wherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of elements;\nwherein the plurality of elements comprises at least one set of structural elements each having a first end and a second end, wherein the structural elements are operable to move between the expanded condition and the collapsed condition by movement of the first end in an axial direction, and by movement of the second end in at least a radial direction;\nwherein the plurality of elements comprises at least one set of ring elements operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure;\nwherein the ring elements comprise first and second contact surfaces oriented on first and second planes;\nwherein the first and second planes intersect one another on a radial plane P which bisects the first and second planes between the centre of the ring and tangent points of an inner surface of the ring structure.', '2.', 'The apparatus according to claim 1, wherein the set of structural elements together forms a substantially conical structure in the expanded condition.', '3.', 'The apparatus according to claim 1, wherein the set of structural elements together forms a substantially conical structure in the collapsed condition and/or a partially expanded condition.', '4.', 'The apparatus according to claim 1, wherein each of the ring elements describes an angle (θ1) at an outer surface of the ring structure in the range of 10 degrees to 20 degrees.', '5.', 'The apparatus according to claim 1, wherein the first and second planes are tangential to an inner surface of the ring structure formed by the ring elements at first and second lines.', '6.', 'The apparatus according to claim 1, wherein the structural elements comprise structural ring elements, operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', '7.', 'The apparatus according to claim 6, wherein the structural ring elements extend longitudinally on the apparatus, and are operable to slide with respect to one another, with the sliding movement in a selected plane perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', '8.', 'The apparatus according to claim 1, wherein each structural element is pivotally connected to a ring element at its second end.', '9.', 'The apparatus according to claim 1, comprising a retaining ring, wherein the structural element is connected to the retaining ring at its first end, by a connection which enables the transfer of a tensile force between the structural element and the retaining ring.', '10.', 'The apparatus according to claim 1, wherein the set of structural elements together forms a substantially conical structure having a conical surface comprising openings in the conical surface between the structural elements.', '11.', 'The apparatus according to claim 1, wherein the structural elements are struts or spokes, and the apparatus comprises a plurality of struts or spokes circumferentially distributed about the longitudinal axis.\n\n\n\n\n\n\n12.', 'The apparatus according to claim 1, comprising a formation configured to impart a radial expanding or collapsing force component to the structural elements of the ring structure from an axial actuation force.\n\n\n\n\n\n\n13.', 'The apparatus according to claim 12, wherein the formation comprises a wedge or wedge profile.', '14.', 'The apparatus according to claim 1, wherein the structural elements are segments of a cone, the segments of the cone comprise first and second contact surfaces oriented on first and second planes, and the first and second planes are tangential to an inner surface of the ring structure formed by the segments at first and second lines.', '15.', 'An expanding and collapsing apparatus comprising:\na plurality of identical ring elements assembled together to form a ring structure around a longitudinal axis; and\nat least one set of structural elements extending longitudinally on the apparatus and operable to slide with respect to one another, wherein the sliding movement in a selected plane perpendicular to the longitudinal axis is tangential to a circle in the selected plane and concentric with the longitudinal axis;\nwherein the ring structure is operable to be moved between an expanded condition and a collapsed condition by movement of the plurality of identical ring elements, each identical element being in contact with an adjacent identical element in the expanded and collapsed conditions.', '16.', 'The apparatus according to claim 15, wherein the structural elements extend longitudinally on the apparatus and are operable to slide with respect to one another, with the sliding movement in any selected plane along the length of the structural element and perpendicular to the longitudinal axis being tangential to a circle in the selected plane and concentric with the longitudinal axis.', '17.', 'The apparatus according to claim 15, wherein the structural elements each have a first end and a second end, wherein the structural elements are operable to move between the expanded condition and the collapsed condition by movement of the first end in an axial direction, and by movement of the second end in at least a radial direction;\nand wherein the plurality of identical ring elements is operable to be moved between the expanded and collapsed conditions by sliding with respect to one another in a direction tangential to a circle concentric with the ring structure.', '18.', 'The apparatus according to claim 15, wherein each structural element of the at least one set of structural elements is in the form of a cone segment such that a plurality of structural elements together form a substantially conical structure having a conical surface.', '19.', 'A method of expanding or collapsing an expanding and collapsing apparatus, the method comprising:\nproviding a plurality of elements assembled together to form a ring structure around a longitudinal axis, wherein the plurality of elements comprises: at least one set of structural elements each having a first end and a second end and at least one set of ring elements each having first and second contact surfaces oriented on first and second planes, wherein the first and second planes intersect one another on a radial plane P which bisects the first and second planes between the centre of the ring and tangent points of an inner surface of the ring structure;\nmoving the first ends of the structural elements in an axial direction, and moving the second ends of the structural elements in at least a radial direction;\nand moving at least one set of ring elements of the plurality of elements between the expanded and collapsed conditions by sliding them with respect to one another in a direction tangential to a circle concentric with the ring structure.'] | ['FIGS.', '1A to 1D are respectively perspective, first end, part sectional and second end views of an apparatus useful for understanding the invention, shown in a collapsed condition;; FIGS.', '2A to 2D are respectively perspective, first side, part sectional and second side views of the apparatus of FIGS.', '1A to 1D, shown in an expanded condition;; FIG. 3 is a geometric representation of an element of the apparatus of FIGS.', '1A to 1D, shown from one side;; FIGS.', '4A to 4F are respectively first perspective, second perspective, plan, first end, lower, and second end views of an element of the apparatus of FIGS.', '1A to 1D;; FIGS.', '5A to 5C are respectively isometric, side and end views of an apparatus according to an embodiment of the invention in a collapsed condition;; FIGS.', '6A to 6C are respectively isometric, side and end views of the apparatus of FIGS.', '5A to 5C in a partially expanded condition;; FIGS.', '7A to 7C are respectively isometric side and end views of the apparatus of FIGS.', '5A to 5C in a fully expanded condition;; FIG. 8 is a geometric representation of an element of the apparatus of FIGS.', '5A to 5C, shown from one side;; FIGS.', '9A to 9F are respectively first perspective, second perspective, plan, first end, lower, and second end views of an element of the apparatus of FIGS.', '5A to 5C;; FIGS.', '10A and 10B are respectively isometric and longitudinal sectional views of an apparatus according to an alternative embodiment of the invention in a collapsed position;; FIGS.', '10C and 10D are respectively cross sectional views of the apparatus of FIGS.', '10A and 10B through lines C-C and D-D;; FIGS.', '11A and 11B are respectively isometric and longitudinal sectional views of the apparatus of FIGS.', '10A to 10D in an expanded condition;; FIGS. 11C and 11D are respectively cross sectional views of the apparatus of FIGS.', '11A and 11B', 'through lines C-C and D-D respectively;; FIG.', '12 is an isometric view of a structural element of the apparatus of FIGS.', '10A to 10D;; FIG.', '13 is an isometric view of a ring element of the apparatus of FIGS.', '10A to 10D;; FIGS.', '14A and 14B are views of the structural element of FIG.', '12 with reference to a virtual cone of which the structural element is a segment;; FIGS.', '15A to 15C are geometric reference diagrams, useful for understanding how a structural element of an embodiment of the invention may be formed;; FIGS. 16A to 16C are respectively first isometric, lower, and second isometric end views of a ring element of an apparatus according to an alternative embodiment of the invention;; FIGS.', '17A and 17B are respectively first and second isometric views of a structural element of an apparatus according to an alternative embodiment of the invention;; FIGS.', '18A and 18B are longitudinal sectional views of an apparatus incorporating the ring element and structural element of FIGS.', '16A to 17B respectively in collapsed and expanded conditions;; FIGS.', '19A to 19C are respectively isometric, longitudinal sectional and end views of an apparatus according to an alternative embodiment of the invention in a collapsed condition;; FIGS.', '20A to 20C are respectively isometric, longitudinal sectional and end views of the apparatus of FIGS.', '19A to 19C in an expanded condition;; FIGS.', '21A to 21C are respectively isometric, longitudinal sectional and cross sectional views of an apparatus according to an alternative embodiment of the invention in a collapsed condition;; FIGS.', '22A and 22B are respectively partially cut away isometric and longitudinal sectional views of the apparatus of FIGS.', '21A to 21C in an expanded condition;; FIGS.', '22C and 22D are respectively cross sectional views of the apparatus of FIGS.', '22A and 22B through lines C-C and D-D;; FIGS.', '23A to 23C are respectively isometric, longitudinal sectional and end views of a seal apparatus according to an alternative embodiment of the invention in a collapsed condition;; FIGS.', '24A and 24C are respectively isometric, longitudinal sectional and end views of the apparatus of FIGS.', '22A to 22C in an expanded condition.', '; FIGS.', '2A to 2D show clearly the apparatus in its expanded condition.', 'At an optimal expansion condition, shown in FIGS.', '2B and 2D, the outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements.', 'The outer surface of the expansion apparatus can be optimised for a specific diameter, to form a perfectly round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.; FIGS.', '20A to 20C show the apparatus in its expanded condition.', 'At an optimal expansion condition, shown in FIGS. 20B and 20C, the outer surfaces of the individual elements combine to form a complete conical surface with no gaps in between the individual elements.', 'At the second end of the elements 142, a cylindrical surface 145 is formed at the optimal expanded condition.', 'The outer surfaces of the individual elements combine to form a complete circle with no gaps in between the individual elements.', 'The outer surface of the expansion apparatus can be optimised for a specific diameter, to form a perfectly smooth cone and round expanded ring (within manufacturing tolerances) with no extrusion gaps on the inner or outer surfaces of the ring structure.', 'The design of the expansion apparatus also has the benefit that a degree of under expansion or over expansion (for example, to a slightly different radial position) does not introduce significantly large gaps.'] |
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US11077465 | Screen assembly for a vibratory separator | Jun 27, 2019 | John Fedders | Schlumberger Technology Corporation | International Search Report and Written Opinion issued in International Patent application PCT/US2020/038306 dated Oct. 5, 2020, 9 pages. | 5615776; April 1, 1997; Bjorklund; 6698593; March 2, 2004; Folke et al.; 8561804; October 22, 2013; Carr; 20090294335; December 3, 2009; Roppo et al.; 20100236995; September 23, 2010; Carr; 20110036759; February 17, 2011; Ballman; 20140124417; May 8, 2014; Holton; 20180179837; June 28, 2018; Holton et al. | Foreign Citations not found. | ['Systems and methods for a screen assembly configurable in a multi-screen configuration.', 'The screen assembly in the multi-screen configuration includes a lower shaker screen and an upper shaker screen.', 'A track is configured to be disposed on an inside wall of a vibratory separator and includes an upper retainer and a lower retainer.', 'A screen clamping assembly is disposed in the track and includes a small spacer disposed between the lower shaker screen and the upper shaker screen in the track when the screen assembly is in the multi-screen configuration.', 'An actuator is disposed in the track and has a clamped position where the actuator is actuated to provide a clamping force to clamp the lower shaker screen, the upper shaker screen, and the small spacer between the upper retainer and the lower retainer of the track.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nMany applications call for filtering screens be secured to a machine, whether temporarily or permanently.', 'Some examples of this include water treatment applications, hazardous material handling applications, and drilling applications.', 'For example, in oilfield environments, fluid used in oilfield activities are generally filtered via a screening process.', 'Failure to keep solids out of the drilling fluid could mean diminished rate of penetration, equipment damage, non-productive time, and higher costs.', 'Further, efficient screening reduces the time required to filter the fluid.', 'One mechanism for separating the contaminants and/or undesirable objects from drilling fluid is the use of screen assemblies in vibratory separators (e.g., shale shakers).', 'The screen assemblies include at least one shaker screen to filter contaminants and/or undesirable objects from the drilling fluid as the vibratory separator vibrates.', 'The screen assemblies may include a screen clamping assembly to clamp at least one screen in a vibratory separator.', 'Depending on the application, different screen configurations may be needed to filter the drilling fluid.', 'For example, some screen configurations may have a single screen and other screen configurations may have multiple screens.', 'In addition, the screen configurations may include a screen configuration with a shaker screen at one level and another screen configuration with a shaker screen at a first level and another shaker screen at a second level.', 'Providing vibratory separators having different screen configurations for different applications can increase the time for filtering the drilling fluid.', 'There exists a need to more efficiently provide different screen configurations for filtering drilling fluid with vibratory separators.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'However, many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limited the scope of the claimed subject matter.', 'In one embodiment, a screen assembly includes a lower shaker screen and an upper shaker screen.', 'The screen assembly is configurable in a multi-screen configuration including the lower shaker screen and the upper shaker screen.', 'A track is configured to be disposed on an inside wall of a vibratory separator and includes an upper retainer and a lower retainer.', 'A screen clamping assembly is disposed in the track.', 'The screen clamping assembly includes a small spacer having a first spacer dimension selected to correspond to the multi-screen configuration.', 'The small spacer is disposed between the lower shaker screen and the upper shaker screen in the track to space the lower shaker screen at a lower level and the upper shaker screen at an upper level in the track when the screen assembly is in the multi-screen configuration.', 'The screen clamping assembly further includes an actuator disposed in the track.', 'The screen clamping assembly has a clamped position where the actuator is actuated to provide a clamping force to clamp the lower shaker screen, the upper shaker screen, and the small spacer between the upper retainer and the lower retainer of the track.', 'In another embodiment, a method for installing a screen assembly of a vibratory separator is provided.', 'The method includes installing the screen assembly in a multi-screen configuration where the screen assembly has a lower shaker screen, an upper shaker screen, a track, and an actuator disposed in the track.', 'Installing the screen assembly in the multi-screen configuration includes inserting in the track the lower shaker screen at a lower level, inserting in the track above the lower shaker screen a small spacer having a first spacer dimension selected to correspond to the multi-screen configuration, and inserting in the track above the small spacer the upper shaker screen at an upper level.', 'Installing the screen assembly in the multi-screen configuration further includes actuating the actuator disposed in the track to provide a clamping force to clamp the small spacer, lower shaker screen, and the upper shaker screen inserted in the track between an upper retainer and a lower retainer of the track in a clamped position of the multi-screen configuration.', 'In another embodiment, a method for configuring a screen assembly on a vibratory separator between a multi-screen configuration and a single screen configuration is provided.', 'The method includes installing the screen assembly in a multi-screen configuration where the screen assembly has a lower shaker screen, an upper shaker screen, a track, and an actuator disposed in the track.', 'Installing the screen assembly in the multi-screen configuration includes inserting in the track the lower shaker screen at a lower level, inserting in the track above the lower shaker screen a small spacer having a first spacer dimension selected to correspond to the multi-screen configuration, and inserting in the track above the small spacer the upper shaker screen at an upper level.', 'Installing the screen assembly in the multi-screen configuration further includes actuating the actuator disposed in the track to provide a clamping force to clamp the small spacer, lower shaker screen, and the upper shaker inserted in the track between an upper retainer and a lower retainer of the track in a clamped position of the multi-screen configuration.', 'The method further includes installing the screen assembly in a single screen configuration including when the screen assembly is in the multi-screen configuration, removing the upper shaker screen and the small spacer from the track.', 'The method of installing the screen assembly in a single screen configuration further including after removing the upper shaker screen and the small spacer from the track, inserting in the track above the lower shaker screen and adjacent the actuator a large spacer having a second spacer dimension larger than the first spacer dimension of the small spacer and selected to correspond to the single screen configuration.', 'The method of installing the screen assembly in a single screen configuration further including actuating the actuator to provide a clamping force to clamp the large spacer and the first shaker screen between the upper retainer and the lower retainer of the track in a clamped position of the single screen configuration.', 'BRIEF DESCRIPTION OF THE FIGURES\n \nCertain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements.', 'It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.', 'It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:\n \nFIG.', '1\n shows a perspective view of an example vibratory separator;\n \nFIG.', '2A\n shows a perspective partial view of an embodiment of a screen assembly installed in the vibratory separator in a single screen configuration of the present disclosure;\n \nFIG.', '2B\n shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in a multi-screen configuration of the present disclosure;\n \nFIG.', '3A\n shows an assembly view of an embodiment of the screen assembly being installed in the single screen configuration of the present disclosure;\n \nFIG.', '3B\n shows a view of an embodiment of the screen assembly installed in the single screen configuration of the present disclosure;\n \nFIG.', '3C\n shows an assembly view of an embodiment of the screen assembly being installed in the multi-screen configuration of the present disclosure;\n \nFIG.', '3D\n shows a view of an embodiment of the screen assembly installed in the multi-screen configuration of the present disclosure;\n \nFIG.', '4\n shows a flowchart depicting a method for installing the screen assembly in the multi-screen configuration of the present disclosure;\n \nFIG.', '5\n shows a flowchart depicting a method for installing the screen assembly between a multi-screen configuration and a single screen configuration of the present disclosure;\n \nFIG.', '6\n shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in the single screen configuration of the present disclosure;\n \nFIG.', '7A\n shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in the single screen configuration of the present disclosure;\n \nFIG.', '7B\n shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in the multi-screen configuration of the present disclosure;\n \nFIG.', '7C\n shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in an uninstalled screen configuration of the present disclosure;\n \nFIG.', '8\n shows a perspective partial view of an embodiment of a large spacer of the screen assembly shown in \nFIG.', '7A\n; and\n \nFIG.', '9\n shows a perspective cross-sectional, partial view of an embodiment of the large spacer of the screen assembly shown in \nFIG.', '7A\n.', 'DETAILED DESCRIPTION', 'In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure.', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments are possible.', 'This description is not to be taken in a limiting sense, but rather made merely for the purpose of describing general principles of the implementations.', 'The scope of the described implementations should be ascertained with reference to the issued claims.', 'As used herein, the terms “upper” and “lower” and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements.', 'The disclosure generally relates to screen assemblies for vibratory separators.', 'Specifically, the disclosed systems, devices, apparatus, and/or methods relate to screen assemblies for improved installation of one or more screens in different configurations.\n \nFIG.', '1\n depicts an example vibratory separator \n100\n.', 'Vibratory separator \n100\n may be a vibratory shaker used in the oilfield industry to process wellbore fluids.', 'Vibratory separator \n100\n includes at least one screen assembly \n102\n, a pair of inner walls \n104\n, a feed end \n106\n, and a discharge end \n108\n.', 'The screen assembly \n102\n is disposed on the inside walls \n104\n and may include one or more shaker screens \n112\n.', 'Drilling fluid, along with drill cuttings and debris, may be deposited on top of the shaker screen \n112\n at the feed end \n106\n.', 'The screen assembly \n102\n may be vibrated (e.g., 25-40 Hz frequency range) by a motor or motors for the purpose of screening or separating the drilling fluid on screen assembly \n102\n.', 'The liquid and fine particles of the drilling fluid may pass through the screen assembly \n102\n by force of gravity and acceleration caused by the motor and may be recovered underneath the screen assembly \n102\n.', 'Solid particles greater than a certain size may migrate and vibrate across the screen assembly \n102\n where they may be discharged at the discharge end \n108\n.', 'The screen assembly \n102\n may include filtering elements, such as mesh, attached to a screen frame.', 'The filtering elements may further define the largest solid particle capable of passing therethrough.\n \nFIG.', '2A\n shows a partial view of a screen assembly \n202\n installed in a vibratory separator \n200\n in a single screen configuration, in accordance with at least one embodiment of the present disclosure.', 'FIG.', '2A\n shows a view from a discharge end \n208\n of a left section of the vibratory separator \n200\n.', 'The screen assembly \n202\n includes a pair of tracks \n210\n, lower shaker screen \n212\n-\n1\n, also referred to as a first shaker screen, and a pair of screen clamping assemblies \n214\n.', 'Screen assembly \n202\n is shown disposed on one of the opposing inner walls \n204\n of the vibratory separator \n200\n.', 'The inner walls \n204\n may form part of a basket of the vibratory separator \n200\n.', 'The pair of tracks \n210\n oppose one another on opposite inner walls \n204\n of the vibratory separator \n200\n.', 'FIG.', '2A\n shows the track \n210\n disposed on the inner wall \n204\n of the left section of the vibratory separator \n200\n and another track \n210\n is disposed on the inner wall \n204\n of the right section of the vibratory separator \n200\n, as shown in \nFIG.', '2A\n.', 'Lower shaker screen \n212\n-\n1\n includes a screen frame \n226\n and a filtering media \n228\n attached to the screen frame \n226\n.', 'Track \n210\n includes an upper retainer \n216\n, a lower retainer \n218\n, and a fixture wall \n220\n extending between the upper retainer \n216\n and lower retainer \n218\n.', 'Both the upper retainer \n216\n and the lower retainer \n218\n extend from the fixture wall \n220\n and the inner wall \n204\n.', 'The track \n210\n has a “U” shape and has a track channel that runs the length of track \n210\n.', 'Track \n210\n is secured to the inner wall \n204\n by welding track \n210\n to the inner wall \n204\n or using one or more attachment devices, for example mechanical fasteners such as screws and bolts or other conventional attachment devices.', 'The upper retainer \n216\n includes a bottom surface \n222\n and the lower retainer \n218\n includes a top surface \n224\n.', 'Screen clamping assembly \n214\n includes an actuator \n230\n, a large spacer \n232\n, and a seal \n234\n disposed in the track \n210\n between the upper retainer \n216\n and the lower retainer \n218\n.', 'The actuator \n230\n is disposed adjacent to the bottom surface \n222\n of the upper retainer \n216\n in the embodiment shown in \nFIG.', '2A\n.', 'In the embodiment shown, actuator \n230\n may be a bladder \n236\n having a nozzle \n238\n.', 'Bladder \n236\n may be actuated by inflating the bladder \n236\n and may be de-actuated by deflating the bladder \n236\n.', 'A fluid media such as air, water, or any similar item is pumped into the bladder \n236\n via nozzle \n238\n causing the bladder \n236\n to expand and press down on the large spacer \n232\n, seal \n234\n, and lower shaker screen \n212\n-\n1\n to clamp and secure the lower shaker screen \n212\n-\n1\n at a lower level in the track \n210\n of screen assembly \n202\n to form a lower deck.', 'When inflated, the bladder \n236\n may clamp and secure the lower shaker screen \n212\n-\n1\n in a clamped position.', "Because the bladder \n236\n is restrained by the upper retainer \n216\n, the bladder's expansion forces the bladder \n236\n downward onto the large spacer \n232\n.", 'The force on the large spacer \n232\n from the bladder \n236\n is transferred to the lower shaker screen \n212\n-\n1\n.', 'In this manner, the screen \n212\n-\n1\n is clamped and/or pinned in place between the upper retainer \n216\n and the lower retainer \n218\n.', 'This restricts movement of the lower shaker screen \n212\n-\n1\n along the length of the track \n210\n.', 'When deflated, the bladder \n236\n releases the downward force against the large spacer \n232\n and lower shaker screen \n212\n-\n1\n, and the lower shaker screen \n212\n-\n1\n is in an unclamped position.', 'In some embodiments, the actuator \n230\n may be a mechanical clamp or mechanical wedge.', 'Seal \n234\n is disposed between the large spacer \n232\n and the lower shaker screen \n212\n-\n1\n.', 'Seal \n234\n is a separate component in the embodiment shown \nFIG.', '2\n.', 'In other embodiments, the seal \n234\n may be attached to the large spacer \n232\n or lower shaker screen \n212\n-\n1\n.', 'In other embodiments, the seal \n234\n may be removed from the single screen configuration.', 'The seal \n234\n is configured to extend along the length of the large spacer \n232\n and abuts against a bottom surface of the large spacer \n232\n and a top surface of the screen frame \n226\n.', 'Screen assembly \n202\n further includes a spacer retainer assembly \n242\n.', 'The spacer retainer assembly \n242\n may secure the large spacer \n232\n in place when the actuator \n230\n is de-actuated.', 'Spacer retainer assembly \n242\n includes a spacer retainer \n246\n and a spacer keyway \n244\n, also referred to as a spacer slot, in the large spacer \n232\n.', 'The spacer retainer \n246\n has an elongated section and a head section \n252\n sized for the spacer keyway \n244\n.', 'The elongated section of the spacer retainer \n246\n extends through the spacer keyway \n244\n.', 'The elongated section of the spacer retainer \n246\n may extend into the fixture wall \n220\n of track \n210\n to secure spacer retainer \n246\n to the track \n210\n and inner wall \n204\n of the vibratory shaker \n200\n.', 'In some embodiments, spacer retainer \n246\n is mechanically attached to the track \n210\n and/or inner wall \n204\n, for example by a press fit or screw threads on the spacer retainer \n246\n that screw into mating screw threads in the track \n210\n and/or inner wall \n204\n.', 'The spacer retainer \n246\n may be welded to the track \n210\n and/or the inner wall \n204\n of the vibratory separator \n200\n or the spacer retainer \n246\n may be screwed into a weld nut or threaded insert connected to the track \n210\n or inner wall \n204\n.', 'Welding the spacer retainer \n246\n provides a more permanent installation of the spacer retainer \n246\n.', 'A threaded installation of the spacer retainer \n246\n allows for removal of the spacer retainer \n246\n in case of damage and replaced with a spacer retainer \n246\n that is undamaged.', 'The head section \n252\n of the spacer retainer \n246\n is sized to be larger than the spacer keyway \n244\n so as to abut against an inner surface of the large spacer \n232\n when the elongated section of the spacer retainer \n246\n is inserted in the spacer keyway \n244\n so as to secure the large spacer \n232\n in the track \n210\n.', 'In some embodiments, there may be multiple spacer retainer assemblies \n342\n spaced apart from one another along the length of the tracks \n210\n and the large spacers \n232\n to allow the large spacers \n232\n or small spacers \n233\n to be installed and supported in the tracks \n210\n.', 'FIG.', '2A\n shows the spacer retainer assembly \n242\n in a spacer retained position where the large spacer \n232\n is secured in place in the track \n210\n by the spacer retainer assembly \n242\n.', 'Spacer retainer \n246\n may be removed from the large spacer \n232\n to position the spacer retainer assembly \n242\n in a spacer unretained position where the large spacer \n232\n is not secured in place within the track \n210\n by the spacer retainer assembly \n242\n.', 'The large spacer \n232\n may be removed from the track \n210\n by sliding the large spacer \n232\n from the track \n210\n after the spacer retainer \n246\n has been removed.', 'FIG.', '2B\n shows a partial view of the screen assembly \n202\n installed in the vibratory separator \n200\n in a multi-screen configuration, in accordance with at least one embodiment of the present disclosure.', 'FIG.', '2B\n shows a view from a discharge end \n208\n of a right section of the vibratory separator \n200\n.', 'The screen assembly \n202\n includes the pair of tracks \n210\n, the lower shaker screen \n212\n-\n1\n, an upper shaker screen \n212\n-\n2\n, and the screen clamping assembly \n214\n.', 'Screen assembly \n202\n is shown disposed on one of the opposing inner walls \n204\n of the vibratory separator \n200\n.', 'Lower shaker screen \n212\n-\n1\n may be the same lower shaker screen \n212\n-\n1\n used in the single screen configuration.', 'In other embodiments, the lower shaker screen \n212\n-\n1\n may be another shaker screen \n212\n.', 'When in the multi-screen configuration, screen clamping assembly \n214\n includes the actuator \n230\n, a small spacer \n233\n, and a seal \n234\n disposed in the track \n210\n between the upper retainer \n216\n and the lower retainer \n218\n.', 'Large spacer \n232\n is not used in the screen clamping assembly \n214\n when the screen clamping assembly \n214\n is in the multi-screen configuration.', 'Large spacer \n232\n has been replaced by the small spacer \n233\n for the multi-screen configuration.', 'Small spacer \n233\n is configured to have a first spacer dimension selected to correspond to the multi-screen configuration.', 'Small spacer \n233\n is selected to have the first spacer dimension to accommodate at least the lower shaker screen \n212\n-\n1\n, small spacer \n233\n, and upper shaker screen \n212\n-\n2\n in the track \n210\n.', 'The first spacer dimension may be the height of the small spacer \n233\n when positioned in the track \n210\n between the lower shaker screen \n212\n-\n1\n and \n212\n-\n2\n.', 'In some embodiments, the height of the small spacer \n233\n may range from 2 inches (5.08 cm) to 3 inches (7.62 cm).', 'In other embodiments, the height of the small spacer \n233\n may have different ranges.', 'For the single screen configuration, the large spacer \n232\n is configured to have a second spacer dimension selected to correspond to the single screen configuration.', 'Large spacer \n232\n-\n2\n is selected to have the second spacer dimension to accommodate at least the lower shaker screen \n212\n-\n1\n and large spacer \n232\n within the track \n210\n.', 'The second spacer dimension may be the height of the large spacer \n232\n when positioned in the track \n210\n between the actuator \n230\n and the lower shaker screen \n212\n-\n1\n.', 'The height of the large spacer \n232\n may range from 3.5 inches (8.89 cm) to 4.5 inches (11.43 cm).', 'In other embodiments, the height of the large spacer \n232\n may have different ranges.', 'The multi-screen configuration needs to accommodate both the lower shaker screen \n212\n-\n1\n and the upper shaker screen \n212\n-\n2\n in the track \n210\n, while the single shaker screen configuration does not need to accommodate both the lower shaker screen \n212\n-\n1\n and the upper shaker screen \n212\n-\n2\n.', 'Accordingly, the first spacer dimension of the small spacer \n233\n is less than the second spacer dimension of the large spacer \n232\n.', 'When screen assembly \n202\n is in the multi-screen configuration, actuator \n230\n formed by bladder \n236\n may be actuated to place the screen assembly \n210\n in a clamped position and may be de-actuated to place the screen assembly \n210\n in an unclamped position.', 'In the bladder \n236\n shown in \nFIG.', '2B\n, a fluid media such as air, water, or any similar item is pumped via nozzle \n238\n into the bladder \n236\n causing the bladder \n236\n to expand and press down on the upper shaker screen \n212\n-\n2\n.', 'Upper shaker screen \n212\n-\n2\n transfers the force applied by the bladder \n236\n to the small spacer \n233\n, seal \n234\n, and lower shaker screen \n212\n-\n1\n to clamp and secure the lower shaker screen \n212\n-\n1\n at a lower level and the upper shaker screen \n212\n-\n2\n at an upper level in the track \n210\n of the screen assembly \n202\n.', 'The lower shaker screen \n212\n-\n1\n forms a lower deck and the upper shaker screen \n212\n-\n2\n forms an upper deck.', 'The lower shaker screen \n212\n-\n1\n is disposed below the upper shaker screen \n212\n-\n2\n and is spaced apart from the upper shaker screen \n212\n-\n2\n by the small spacer \n233\n.', 'The large spacer \n232\n used for the single screen configuration, shown in \nFIG.', '2A\n, has a spacer dimension that is too large to be used in the multi-screen configuration shown in \nFIG.', '2B\n, and has been replaced with the small spacer \n233\n for the multi-screen configuration.', 'In this manner, the lower shaker screen \n212\n-\n1\n and the upper shaker screen \n212\n-\n2\n are clamped and/or pinned in place in the track \n210\n between the upper retainer \n216\n and the lower retainer \n218\n.', 'When in the clamped position, the lower shaker screen \n212\n-\n1\n and the upper shaker screen \n212\n-\n2\n are clamped in the track \n210\n.', 'FIG.', '3A\n shows an assembly view of an embodiment of a screen assembly \n302\n being installed in the single screen configuration, and \nFIG.', '3B\n shows the screen assembly \n302\n in the single screen configuration after installation.', 'Screen assembly \n302\n includes a spaced-apart pair of tracks \n310\n, a lower shaker screen \n312\n-\n1\n, and a pair of screen clamping assemblies \n314\n.', 'Screen clamping assemblies \n314\n are referenced with numeral \n314\n in \nFIG.', '3B\n and \nFIG.', '3D\n.', 'Tracks \n310\n each have an upper retainer \n316\n, a lower retainer \n318\n with a screen clamping assembly \n314\n disposed in each track \n310\n.', 'Screen clamping assemblies \n314\n each include a seal \n334\n, a large spacer \n332\n, a bladder \n336\n, and nozzle \n338\n.', 'Bladders \n336\n extend adjacent to and below the upper retainers \n316\n.', 'Lower shaker screen \n312\n-\n1\n is shown being slid into tracks \n310\n as part of the installation process to install or assemble the screen assembly \n302\n from an un-installed position to an installed position.', 'Lower shaker screen \n312\n-\n1\n abuts the lower retainers \n318\n while being slid into the tracks \n310\n.', 'Seals \n334\n may be slid in the tracks \n310\n above the lower shaker screen \n312\n-\n1\n that has been installed in the tracks \n310\n.', 'Seals \n334\n may be a separate component that may be slid in separately into the tracks \n310\n.', 'In other embodiments, seals \n334\n may be integral with the large spacers \n332\n.', 'Large spacers \n332\n then may be placed in the tracks \n310\n above the seals \n334\n to place the screen assembly \n302\n in the single screen configuration.', 'In some embodiments, bladders \n336\n are in a de-actuated position when the large spacers \n332\n are slid into the tracks \n310\n to allow for enough space for the large spacers \n332\n to be slid in the tracks \n310\n above the lower shaker screen \n312\n-\n1\n.', 'In some embodiments, the large spacers \n332\n may be positioned between the lower retainers \n316\n and the lower shaker screen \n312\n-\n1\n with the seals \n334\n positioned between the lower shaker screen \n312\n-\n1\n and the large spacers \n332\n.', 'In the embodiment where the large spacers \n332\n are positioned below the lower shaker screen \n312\n-\n1\n, the large spacers \n332\n act as wear strip for supporting the screens.', 'A spacer retainer assembly \n342\n in an un-installed position is shown in \nFIG.', '3A\n.', 'Spacer retainer assembly \n342\n includes a spacer retainer \n346\n that fits into a spacer keyway \n344\n in the large spacer \n332\n.', 'Spacer retainer \n346\n may include an elongated section \n350\n and a head section \n352\n.', 'In some embodiments, spacer retainer assembly \n342\n further includes a track retainer slot \n348\n in the track \n310\n.', 'The track retainer slot \n348\n is sized to allow the elongated section \n350\n of the spacer retainer \n346\n to fit therein.', 'The elongated section \n350\n of the spacer retainer \n346\n fits in the spacer keyway \n344\n in the large spacer \n332\n and extends into the track retainer slot \n348\n.', 'The head section \n352\n of the spacer retainer \n346\n is sized to be larger than the spacer keyway \n344\n to secure the large spacer \n332\n in place in the tracks \n310\n.', 'In some embodiments, spacer retainer \n346\n is mechanically attached to the track \n310\n, for example by a press fit or screw threads on the spacer retainer \n346\n that screw into mating screw threads in the track retainer slot \n348\n.', 'Spacer retainer assembly \n346\n may be placed in an installed position by inserting the elongated section \n350\n of the spacer retainer \n346\n in the spacer keyway \n344\n and in the track retainer slot \n348\n.', 'In some embodiments, there may be multiple spacer retainer assemblies \n342\n spaced apart from one another along the length of the large spacers \n332\n for use in holding the large spacers \n332\n in place in the tracks \n310\n.', 'Spacer retainers \n342\n provides the benefit of holding the large spacers \n332\n in place in the tracks \n310\n when the screen assembly \n302\n is in the unclamped position and to secure the large spacers \n332\n in alignment in the tracks \n310\n.', 'With the spacer retainer \n342\n in the installed position, screen assembly \n302\n is in the single screen configuration shown in \nFIG.', '3B\n.', 'Bladders \n336\n may then be actuated to place the screen assembly \n302\n in the clamped position.', 'FIG.', '3C\n shows an assembly view of an embodiment of a screen assembly \n302\n being installed in the multi-screen configuration, and \nFIG.', '3D\n shows the screen assembly \n302\n in the multi-screen configuration after installation.', 'When in the multi-screen configuration, screen assembly \n302\n includes the lower screen \n312\n-\n1\n in addition to an upper shaker screen \n312\n that is spaced from the lower shaker screen by a small spacer \n333\n.', 'Lower shaker screen \n312\n-\n1\n is shown being slid into tracks \n310\n as part of the installation process to install or assemble the screen assembly \n302\n from an un-installed position to an installed position.', 'Lower shaker screen \n312\n-\n1\n abuts the lower retainers \n318\n while being slid into the tracks \n310\n.', 'Seals \n334\n may be slid in the tracks \n310\n above the lower shaker screen \n312\n-\n1\n that has been installed in the tracks \n310\n.', 'In some embodiments, seals \n334\n may be integral with the small spacer \n333\n.', 'Small spacers \n333\n may be placed into the tracks \n310\n above the seals \n334\n.', 'Small spacers \n333\n are secured to the tracks \n310\n by the spacer retainers \n346\n.', 'In some embodiments, the small spacers \n333\n hang from the spacer retainers \n346\n in the tracks \n310\n.', 'In some embodiments, there may be multiple spacer retainer assemblies \n342\n spaced apart from one another along the length of the tracks \n210\n and small spacers \n333\n to allow the small spacers \n233\n to be secured with the multiple space retainer assemblies \n342\n in the tracks \n210\n.', 'Upper shaker screen \n312\n-\n2\n is inserted in the tracks \n310\n above the small spacers \n333\n.', 'In some embodiments, bladders \n336\n are in a de-actuated position when the large spacers \n332\n are slid into the tracks \n310\n to allow for enough space for the upper shaker screen \n312\n-\n2\n to be slid in the tracks \n310\n above the small spacers \n332\n and lower shaker screen \n312\n-\n1\n to place the screen assembly \n302\n in the multi-screen configuration shown in \nFIG.', '3D\n.', 'Bladders \n336\n may then be actuated to place the screen assembly \n302\n in the clamped position.', 'FIG.', '4\n is a flowchart showing an embodiment of an installation method \n400\n for installing a screen assembly of a vibratory separator in a multi-screen configuration of the present disclosure.', 'The screen assembly in the multi-screen configuration includes a lower shaker screen, an upper shaker screen, a track, and an actuator disposed in the track.', 'The installation method \n400\n begins by an installer inserting in the track the lower shaker screen at a lower level (block \n402\n).', 'The installer inserts in the track above the lower shaker screen a small spacer (block \n404\n).', 'The small spacer has a first spacer dimension selected to correspond to the multi-screen configuration.', 'The installer inserts in the track above the small spacer the upper shaker screen at an upper level (block \n406\n).', 'The small spacer is configured to separate the lower shaker screen from the upper shaker screen so that a lower screen deck is formed by the lower shaker screen and an upper screen deck is formed by the upper shaker screen.', 'The lower shaker screen, small spacer, and upper shaker screen may be slid into the track during installation and may be slid into a pair of spaced-apart tracks.', 'A clamping assembly includes the actuator and is used to clamp the lower shaker screen and the upper shaker screen in the track.', 'The installer actuates the actuator disposed in the track to provide a clamping force to clamp the small spacer, lower shaker screen, and the upper shaker screen inserted in the track between an upper retainer and a lower retainer of the track in a clamped position of the multi-screen configuration (block \n408\n).', 'When in the installed position, the screen assembly in the multi-screen configuration clamps the lower shaker screen and the upper shaker screen in the track so that the screen assembly is ready to withstand the vibrations during operations.', 'In operation, the screen assembly in the multi-screen configuration has a lower screen deck formed by the lower shaker screen and an upper screen deck formed by the upper shaker screen.', 'Drilling fluid, along with drill cuttings and debris, may be deposited on top of the upper shaker screen at the feed end.', 'The screen assembly may be vibrated (e.g., 25-40 Hz frequency range) by a motor or motors for the purpose of screening or separating the drilling fluid on the upper shaker screen.', 'The liquid and fine particles of the drilling fluid may pass through the upper shaker screen by force of gravity and acceleration caused by the motor and flows through the space between the upper shaker screen and the lower shaker screen and is deposited on the lower shaker screen forming a spaced-apart, lower screen deck.', 'The liquid and fine particles of the drilling fluid after filtering by the upper shaker screen may pass through the lower shaker screen by force of gravity and acceleration caused by the motor and may be recovered underneath the lower shaker screen and screen assembly.', 'Solid particles greater than a certain size may migrate and vibrate across both the upper shaker screen and the lower shaker screen where they may be discharged at the discharge end.', 'The filtering elements of the upper shaker screen may define the largest solid particle capable of passing therethrough.', 'The filtering elements of the lower shaker screen may define the largest solid particle capable of passing therethrough.', 'In some embodiments, the filtering elements of the upper shaker screen may define larger solid particles capable of passing through the filter elements of the upper shaker screen compared to the filtering elements of the lower shaker screen.', 'In some embodiments, the filtering elements of the upper shaker screen and the lower shaker screen are the same.\n \nFIG.', '5\n is a flowchart showing an embodiment of an installation method \n500\n for installing a screen assembly of a vibratory separator between a multi-screen configuration and a single screen configuration of the present disclosure.', 'The installation method \n500\n for installing the screen assembly in the multi-screen configuration includes the blocks \n502\n-\n508\n that are the same as the installation method \n400\n for installing the screen assembly in the multi-screen configuration described with respect to \nFIG.', '4\n.', 'Blocks \n502\n-\n508\n are performed as described with respect to blocks \n402\n-\n408\n of \nFIG.', '4\n.', 'When the screen assembly is in the multi-screen configuration, an installer may remove the upper shaker screen and the small spacer from the track (block \n510\n).', 'In some embodiments, before removing the upper shaker screen and the small spacer (block \n510\n), the installer may de-actuate the actuator to position the screen assembly in the multi-screen configuration from a clamped position to an unclamped position.', 'The upper shaker screen and small spacer may be removed from the tracks.', 'After removing the upper shaker screen and the small spacer from the track, the installer inserts in the track above the lower shaker screen and adjacent the actuator a large spacer (block \n512\n).', 'The large spacer has a second spacer dimension larger than the first spacer dimension of the small spacer and is selected to correspond to the single screen configuration.', 'The large spacer may be slid into the track during installation and may be slid into the pair of spaced-apart tracks.', 'The installer may actuate the actuator to provide a clamping force to clamp the large spacer and the first shaker screen between the upper retainer and the lower retainer of the track in a clamped position of the single screen configuration (block \n514\n).', 'When in the clamped position, the screen assembly is installed in the single screen configuration and the screen assembly is ready to withstand the vibrations during operations.', 'In operation, the screen assembly in the single screen configuration has a lower screen deck formed by the lower shaker screen.', 'Drilling fluid, along with drill cuttings and debris, may be deposited on top of the lower shaker screen at the feed end.', 'The screen assembly may be vibrated (e.g., 25-40 Hz frequency range) by a motor or motors for the purpose of screening or separating the drilling fluid on the lower shaker screen.', 'The liquid and fine particles of the drilling fluid may pass through the lower shaker screen by force of gravity and acceleration caused by the motor and flows and may be recovered underneath the lower shaker screen and screen assembly.\n \nFIG.', '6\n shows a partial view of a screen assembly \n602\n installed in a vibratory separator \n200\n in a single screen configuration, in accordance with at least one embodiment of the present disclosure.', 'Like components of embodiments of the screen assemblies are labeled with like reference numbers.', 'In \nFIG.', '6\n, large spacer \n632\n is shown installed in the track \n210\n by spacer retainer \n246\n disposed in a spacer keyway \n644\n.', 'Spacer keyway \n644\n may be a “T” slot or other slot cut into the large spacer \n632\n configured to permit large spacer \n632\n to be hooked onto the spacer retainer \n246\n to install the large spacer \n632\n in the track \n210\n and unhooked from the spacer retainer \n246\n to remove the large spacer \n632\n from the track \n210\n.\n \nSpacer keyway \n644\n includes a first slot section \n660\n and a second slot section \n662\n.', 'For example, the spacer keyway \n644\n may be configured to allow vertical movement of the large spacer \n632\n hooked on the spacer retainer \n246\n to accommodate movement of the large spacer \n632\n when positioned between the clamped position and the unclamped position in the track \n210\n.', 'This vertical movement of the large spacer \n632\n when attached to the spacer retainer \n246\n allows the large spacer \n632\n to be vertically moved in the track \n210\n to unhook the large spacer \n632\n from the spacer retainer \n246\n to remove the large spacer \n632\n from the track \n210\n.', 'When the large spacer \n632\n is positioned in the clamped position, the second slot section \n662\n of the spacer keyway \n644\n is adjacent to and abuts against the head section \n252\n of the spacer retainer \n246\n preventing the large spacer \n632\n from moving outwardly and away from the track \n210\n, as shown in \nFIG.', '6\n.', 'When the large spacer \n632\n is positioned in the unclamped position, the large spacer \n632\n may be moved upwards in the track \n210\n to position the first slot section \n660\n of the spacer keyway \n644\n adjacent to the head section \n252\n of the spacer retainer \n246\n.', 'First slot section \n660\n of the spacer keyway \n644\n is configured to be larger than the second slot section \n662\n of the spacer keyway \n644\n and head section \n252\n of the spacer retainer \n246\n.', 'With the large spacer \n632\n in this position, the head section \n252\n may be removed through the first slot section \n660\n of the spacer keyway \n644\n and the large spacer \n632\n may be removed from the track \n210\n.', 'Spacer keyway \n644\n and spacer retainer \n246\n form a spacer retainer assembly \n642\n.', 'Multiple spacer retainer assemblies \n642\n are spaced apart from one another along the length of the large spacer \n632\n.', 'FIG.', '6\n shows two spacer retainer assemblies \n642\n, and additional spacer retainer assemblies \n642\n may be spacer apart along the length of the large spacers \n632\n.', 'Spacer retainer assemblies \n642\n may be used for both large spacers \n632\n and small spacers \n233\n configured with retainer assemblies \n642\n.', 'The spacer retainer assemblies \n642\n provide the advantage of allowing an installer to slip either the large spacers \n632\n or small spacers \n233\n on the spacer retainers \n246\n so that the large spacers or small spacers sit on the spacer retainers \n246\n with the spacer retainers \n246\n extending in respective spacer keyways \n644\n.', 'The installer may change between large spacers \n632\n and small spacers \n233\n without the use of tools and to position the screen assembly \n602\n between the single screen configuration and the multi-screen configuration.', 'The installer installs and uninstalls the large spacers \n632\n or small spacers \n233\n on or off the spacer retainers \n246\n when the actuator \n230\n is in in the de-actuated position.', 'Actuator \n230\n is actuated to provide a force that holds the large spacers \n632\n and lower shaker screen \n212\n-\n1\n in place in the tracks \n210\n when in the clamped position of the single screen configuration or the small spacers \n233\n, lower shaker screen \n212\n-\n1\n, and upper shaker screen \n212\n-\n2\n in place in the tracks \n210\n when in the clamped position of the multi-screen configuration.', 'An actuator seal \n669\n may be disposed between the upper retainer \n216\n and the bladder \n236\n of the actuator \n230\n.', 'When moving from the unclamped position to the clamped position, the force from the actuator \n230\n may move the large spacers \n632\n downwards and the spacer keyways \n644\n may move downward with respect to the spacer retainers \n246\n that are fixed with respect to tracks \n210\n to position the retainer head sections \n252\n in the second slot sections \n662\n of the respective spacer keyways \n644\n.', 'Retainer head sections \n252\n block the large spacers \n632\n from moving out of the tracks \n210\n when the vibratory separator \n200\n vibrates the screen assembly \n602\n.\n \nFIG.', '7A\n shows a partial view of a screen assembly \n702\n installed in the vibratory separator \n200\n in the single screen configuration, in accordance with at least one embodiment of the present disclosure.', 'Like components of embodiments of the screen assemblies are labeled with like reference numbers.', 'FIG.', '7A\n shows a view from a discharge end \n208\n of the left section of the vibratory separator \n200\n.', 'Screen assembly \n702\n includes a pair of tracks \n710\n and a lower shaker screen \n712\n-\n1\n.', 'Screen assembly \n702\n further includes disposed in each track a large spacer \n732\n, an actuator \n230\n, and a seal \n734\n.', 'FIG.', '7A\n shows the seal \n734\n disposed in a channel \n770\n.', 'Track \n710\n includes an upper retainer \n716\n and a lower retainer \n718\n.', 'The lower retainer \n718\n includes an upper surface \n719\n, and the lower shaker screen \n712\n-\n1\n rests on and is supported by the upper surface \n719\n of the lower retainer \n718\n.', 'In some embodiments, the upper surface \n719\n may be disposed at a thirty-degree angle with respect to the inner wall \n204\n to help limit solids build-up on the lower retainer \n718\n during operations.', 'In some embodiments, the lower shaker screen \n712\n-\n1\n has a bottom surface \n713\n having an angle that matches the angle of the upper surface \n719\n of the lower retainer \n718\n.\n \nFIG.', '7B\n shows a partial view of the screen assembly \n702\n installed in the vibratory separator \n200\n in the multi-screen configuration, in accordance with at least one embodiment of the present disclosure.', 'FIG.', '7B\n shows a view from a discharge end \n208\n of the right section of the vibratory separator \n200\n.', 'The screen assembly \n702\n includes tracks \n710\n, a lower shaker screen \n712\n-\n1\n, and an upper shaker screen \n712\n-\n2\n.', 'Screen assembly \n702\n further includes disposed in each track \n710\n the large spacers \n733\n and the actuator \n230\n.', 'In some embodiments, a seal (not shown) may be disposed in a channel (not shown) in the small spacer \n733\n in a manner as shown in \nFIG.', '7A\n and \nFIG.', '10\n for the large spacer \n732\n.', 'The lower shaker screen \n712\n-\n1\n rests on and is supported by the upper surface \n719\n of the lower retainer \n718\n.', 'Upper shaker screen \n712\n-\n2\n is disposed above and rests on small spacer \n733\n.', 'In some embodiments, large spacers \n732\n and small spacers \n733\n are made with materials that are moldable, including urethane.', 'FIG.', '7C\n shows a partial view of a screen assembly \n702\n installed in the vibratory separator \n200\n in an uninstalled screen configuration.', 'When in the uninstalled screen configuration, the large spacer \n732\n and the small spacer \n733\n are removed from the tracks \n710\n.', 'Spacer retainers \n746\n are spaced apart along the length of the track \n710\n.', 'Each spacer retainer \n746\n extends from a fixture wall \n720\n of the track \n710\n and is disposed in the track channel.', 'Each spacer retainer \n746\n includes a head section \n752\n.', 'In some embodiments, the spacer retainer \n746\n has a “T” shape.', 'In some embodiments, the spacer retainer \n746\n has other shapes.', 'Spacer retainer \n746\n may be attached to the track \n710\n and/or inner wall \n204\n by welding or other attachment mechanism, as discussed with respect to spacer retainer \n246\n.', 'Spacer retainers \n746\n allow an installer to position the screen assembly \n702\n between the single screen configuration and the multi-screen configuration without the use of tools.', 'When the screen assembly \n702\n is in the uninstalled screen configuration, large spacers \n732\n may be attached to the spacer retainers \n746\n so that each large spacer \n732\n may be suspended in one of the tracks \n710\n, and the lower shaker screen \n712\n-\n1\n and seal \n734\n may be inserted into each track \n710\n to place the screen assembly \n702\n in the single screen configuration.', 'Likewise, when the screen assembly \n702\n is in the uninstalled screen configuration, small spacers \n733\n may be attached to the spacer retainers \n746\n so that each small spacer \n733\n may be suspended in one of the tracks \n710\n, and the lower shaker screen \n712\n-\n1\n, upper shaker screen \n712\n-\n2\n, and seal \n734\n may be inserted into each track \n710\n to place the screen assembly \n702\n in the multi-screen configuration.', 'Referring to \nFIG.', '8\n and \nFIG.', '9\n, the large spacer \n732\n with a spacer keyway \n744\n is shown.', 'FIG.', '8\n shows a partial perspective view of the large spacer \n732\n having one of the spacer keyways \n744\n.', 'Spacer keyway \n744\n is shown disposed in a spacer back surface \n772\n of the large spacer \n732\n.', 'Spacer keyway \n744\n may also be disposed in small spacer \n733\n in a similar manner.', 'Spacer keyway \n744\n includes a first slot section \n760\n and a second slot section \n762\n.', 'First slot section \n760\n may be a lower slot section and the second slot section \n762\n may be an upper slot section, as shown in \nFIG.', '8\n.', 'Spacer keyway \n744\n further includes a pair of sockets \n764\n disposed on opposite sides of the second slot section \n762\n, as depicted in \nFIG.', '8\n.', 'Spacer keyway \n744\n further includes a first internal surface \n765\n and second internal surface \n766\n that define each socket \n764\n.', 'Large spacer \n732\n or small spacer \n733\n may be attached to the spacer retainers \n746\n by inserting the spacer retainers \n746\n into respective spacer keyways \n744\n.', 'Each spacer retainer \n746\n is aligned with one of the spacer keyways \n734\n.', 'Each spacer retainer \n746\n includes an elongated section \n750\n and the head section \n752\n.', 'Head section \n752\n of the spacer retainer \n746\n is inserted into the first slot section \n760\n.', 'Head section \n752\n is configured to fit within the first slot section \n760\n and to be slidable into the second slot section \n762\n as the large spacer \n732\n or small spacer \n733\n is moved downward with respect to the spacer retainer \n746\n.', 'As the head section \n752\n moves into the second slot section \n762\n, the head section \n752\n moves through an opening between the first slot section \n760\n and the second slot section \n762\n and the head section is disposed in the sockets \n764\n.', 'The large spacer \n732\n or the small spacer \n733\n are positioned in a locked position when the head section \n752\n is positioned in the sockets \n764\n.', 'End portions of the head section \n752\n are disposed in the sockets \n764\n with opposing internal surfaces \n765\n, \n766\n of the large spacer \n732\n or small spacer \n733\n adjacent to the head section \n752\n to block the large spacer \n732\n or small spacer \n733\n from moving outwardly from the track \n710\n.', 'Referring to \nFIG.', '9\n, one-half of the spacer retainer \n746\n and matching spacer keyway \n762\n is shown.', 'Spacer retainer \n746\n is shown with a portion of the head section \n752\n inserted into one of the sockets \n764\n.', 'Another portion (not shown) of the head section \n752\n is inserted into an opposite socket \n764\n (not shown).', 'When the spacer retainers \n746\n and the spacer keyways \n762\n are in this position, the large spacer \n732\n or small spacer \n733\n is in the locked position in the tracks \n710\n.', 'After the large spacer \n732\n or the small spacer \n733\n has been attached to the spacer retainers \n746\n, the other components of either the multi-screen configuration or the single screen configuration may be installed in the tracks \n710\n.', 'In some embodiments, the components of the screen assembly \n732\n may be installed in a different order.', 'Actuator \n230\n may be actuated to provide a downward force to move either the large spacer \n732\n or the small spacer \n733\n downwards in the tracks \n710\n to position the large spacer \n732\n or small spacer \n733\n in a locked position.', 'Each spacer retainer \n746\n is configured to move in its respective spacer keyway \n744\n to allow for downwards movement of the large spacer \n732\n or the small spacer \n733\n when the screen assembly \n702\n is placed in the clamped position.', 'Likewise, each spacer retainer \n746\n is configured to move in its respective spacer keyway \n744\n to allow for upwards movement of the large spacer \n732\n or the small spacer \n733\n when the screen assembly \n702\n is placed in the unclamped position, Large spacer \n732\n or small spacer \n733\n may be uninstalled from the tracks \n710\n by moving the moving the large spacer \n732\n or the small spacer \n733\n upwards to align each spacer retainer \n746\n in the first section \n760\n of the matching spacer keyway \n744\n so that the spacer retainers \n746\n can be removed from the spacer keyways \n734\n.', 'Spacer retainers \n746\n are disposed in the spacer keyways \n734\n during operation of the vibratory separator \n200\n.', 'Spacer retainers \n746\n are protected from drilling fluids and contaminants during operation because the spacer retainers \n746\n are in the body of the large spacer \n732\n or the small spacer \n733\n during operations.', 'The positioning of the spacer retainers \n746\n in the body of the large spacer \n732\n or small spacer \n733\n may help reduce maintenance needs and contaminant build-up on the spacer retainers \n746\n allowing for more effective attachment of the large spacer \n732\n and the small spacer \n733\n in the track \n710\n.', 'The disclosed systems, devices, apparatus, and/or methods disclose screen assemblies for improved installation of one or more screens in different configurations.', 'The screen assembly is positionable in a multi-screen configuration where the screen assembly includes a single screen deck that may be formed by a lower shaker screen.', 'The screen assembly also allows for the screen assembly to be positioned in a multi-screen configuration that has a dual screen deck with a lower deck and an upper deck formed by the lower shaker screen and the upper shaker screen spaced apart by the small spacer.', 'The screen assembly uses an actuator in the track to clamp the at least one shaker screen in both the single screen configuration and the multi-screen configuration.', 'The screen assembly of embodiments of the present disclosure provides the benefit of using one actuator for two different configurations.', 'The screen assembly of embodiments of the present disclosure provides the benefit of using only one pair of tracks on opposite walls of the vibratory separator for the at least one shaker screen used for the different screen configurations that include a single screen deck formed by the lower shaker screen and a multi-screen deck formed by the lower shaker screen and the upper shaker screen.', 'The screen assembly of embodiments of the present disclosure helps avoid the need for two different vibratory separators that would each have a separate screen configuration that may be needed for different operations.', 'The screen assembly of embodiments of the present disclosure helps avoid the need to make substantial modifications to a vibratory separator to re-configure a vibratory separator to a different configuration.', 'The screen assembly of embodiments of the present disclosure is configurable between the multi-screen configuration and single screen configuration without the need for tools.', 'Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure.', 'Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.', 'The scope of the invention should be determined only by the language of the claims that follow.', 'The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group.', 'The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U. S. C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” together with an associated function.'] | ['1.', 'A screen assembly comprising:\na lower shaker screen and an upper shaker screen, and wherein the screen assembly is configurable in a multi-screen configuration comprising the lower shaker screen and the upper shaker screen;\na track configured to be disposed on an inside wall of a vibratory separator and comprising an upper retainer and a lower retainer; and\na screen clamping assembly disposed in the track, the screen clamping assembly comprising: a small spacer having a first spacer dimension selected to correspond to the multi-screen configuration, and wherein the small spacer is disposed between the lower shaker screen and the upper shaker screen in the track to space the lower shaker screen at a lower level and the upper shaker screen at an upper level in the track when the screen assembly is in the multi-screen configuration; and an actuator disposed in the track and having a clamped position where the actuator is actuated to provide a clamping force to clamp the lower shaker screen, the upper shaker screen, and the small spacer between the upper retainer and the lower retainer of the track.', '2.', 'The screen assembly of claim 1, wherein the multi-screen configuration has an unclamped position where the actuator is de-actuated to release the clamping force on the lower shaker screen, the upper shaker screen and the small spacer; and wherein the lower shaker screen, upper shaker screen, and the small spacer are configured to be removed from the track when in the unclamped position of the multi-screen configuration.', '3.', 'The screen assembly of claim 2, wherein the upper retainer is configured to extend from an inner wall of a vibratory separator and the lower retainer is configured to extend from the inner wall of the vibratory separator, and wherein the actuator comprises a bladder disposed below the upper retainer, and wherein the bladder is inflatable to position the actuator in an actuated position and deflatable to position the actuator in a de-actuated position.', '4.', 'The screen assembly of claim 3, wherein the bladder comprises a nozzle configured to inflate and deflate the bladder, and wherein the upper retainer comprises a top retainer wall and the nozzle extends through the top retainer wall.', '5.', 'The screen assembly of claim 1, wherein the screen clamping assembly further comprises a screen seal, and wherein the screen seal is disposed between the small spacer and the lower shaker screen when the screen assembly is in the multi-screen configuration.', '6.', 'The screen assembly of claim 1, wherein the screen assembly is configurable in a single screen configuration and further comprises:\na first shaker screen;\na large spacer having a spacer dimension larger than the small spacer and sized to correspond to the single screen configuration, and wherein the large spacer is disposed adjacent the actuator and between the actuator and the first shaker screen to position the first shaker screen in the track at a first level when the screen assembly is in the single screen configuration;\nwherein the single screen configuration has a clamped position where the actuator is actuated to provide a clamping force to clamp the larger spacer and the first shaker screen between the upper retainer and the lower retainer of the track.', '7.', 'The screen assembly of claim 6, wherein the single screen configuration has an unclamped position where the actuator is de-actuated to release the clamping force on the first shaker screen and the large spacer; and wherein the first shaker screen and the large spacer are configured to be removed from the track when in the unclamped position of the single screen configuration.', '8.', 'The screen assembly of claim 7, wherein when the screen assembly is in the multi-screen configuration, the upper retainer extends over at least a portion of a top surface of the upper shaker screen, a top surface of the lower shaker screen, and a top surface of the small spacer, and the lower retainer extends under at least a portion of a bottom surface of the lower shaker screen, a bottom surface of the upper shaker screen, and a bottom surface of the small spacer; and wherein when the screen assembly is in the single screen configuration the upper retainer extends over at least a portion of a top surface of the first shaker screen and a top surface of the large spacer, and the lower retainer extends under at least a portion of a bottom surface of the first shaker screen and a bottom surface of the large spacer.', '9.', 'The screen assembly of claim 6, wherein the screen clamping assembly further comprises a screen seal, wherein the screen seal is disposed between the small spacer and the lower shaker screen when the screen assembly is in the multi-screen configuration, and wherein the screen seal is disposed between the large spacer and the first shaker screen when the screen assembly is in the single screen configuration.', '10.', 'The screen assembly of claim 6, wherein the screen clamping assembly further comprises a spacer retainer assembly, and wherein the spacer retainer assembly comprises:\na spacer keyway in the large spacer; and\na spacer retainer sized for the spacer keyway disposed in the track and configured to secure the large spacer in the track.', '11.', 'A method for installing a screen assembly of a vibratory separator, comprising:\ninstalling the screen assembly in a multi-screen configuration, wherein the screen assembly has a lower shaker screen, an upper shaker screen, a track, and an actuator disposed in the track, and comprising: inserting in the track the lower shaker screen at a lower level; inserting in the track above the lower shaker screen a small spacer having a first spacer dimension selected to correspond to the multi-screen configuration; inserting in the track above the small spacer the upper shaker screen at an upper level; and actuating the actuator disposed in the track to provide a clamping force to clamp the small spacer, lower shaker screen, and the upper shaker screen inserted in the track between an upper retainer and a lower retainer of the track in a clamped position of the multi-screen configuration.', '12.', 'The method of claim 11, further comprising:\nwhen in the clamped position of the multi-screen configuration, de-actuating the actuator to release the clamping force to position the screen assembly in an unclamped position where the actuator is de-actuated to release the clamping force on the lower shaker screen, the upper shaker screen and the small spacer; and\nwhen in the unclamped position of the multi-screen configuration, slidably removing the lower shaker screen, upper shaker screen, and the small spacer from the track.', '13.', 'The method of claim 11, further comprising installing the screen assembly into a single screen configuration, comprising:\ninserting a first shaker screen into the track at a first level;\ninserting in the track above the first shaker screen and adjacent the actuator a large spacer having a second spacer dimension larger than the first spacer dimension of the small spacer and selected to correspond to the single screen configuration; and\nactuating the actuator to provide a clamping force to clamp the large spacer and the first shaker screen inserted in the track between the upper retainer and the lower retainer of the track in a clamped position of the single screen configuration.', '14.', 'The method of claim 13, wherein the first shaker screen is the lower shaker screen.', '15.', 'The method of claim 13, wherein installing the screen assembly in the single screen configuration further comprises securing the large spacer in the track with a spacer retainer assembly, and wherein the spacer retainer assembly comprises a spacer keyway in the large spacer and a spacer retainer sized for the spacer keyway and extending through the spacer keyway for securing the large spacer in the track.', '16.', 'A method for configuring a screen assembly on a vibratory separator between a multi-screen configuration and a single screen configuration, comprising:\ninstalling the screen assembly in a multi-screen configuration, wherein the screen assembly has a lower shaker screen, an upper shaker screen, a track, and an actuator disposed in the track, and comprising: inserting in the track the lower shaker screen at a lower level; inserting in the track above the lower shaker screen a small spacer having a first spacer dimension selected to correspond to the multi-screen configuration; inserting in the track above the small spacer the upper shaker screen at an upper level; and actuating the actuator disposed in the track to provide a clamping force to clamp the small spacer, lower shaker screen, and the upper shaker inserted in the track between an upper retainer and a lower retainer of the track in a clamped position of the multi-screen configuration; and\ninstalling the screen assembly in a single screen configuration, comprising: when the screen assembly is in the multi-screen configuration, removing the upper shaker screen and the small spacer from the track; after removing the upper shaker screen and the small spacer from the track, inserting in the track above the lower shaker screen and adjacent the actuator a large spacer having a second spacer dimension larger than the first spacer dimension of the small spacer and selected to correspond to the single screen configuration; and actuating the actuator to provide a clamping force to clamp the large spacer and the first shaker screen between the upper retainer and the lower retainer of the track in a clamped position of the single screen configuration.', '17.', 'The method of claim 16, further comprising:\nwhen in the clamped position of the multi-screen configuration, de-actuating the actuator to position the screen assembly from the clamped position to an unclamped position where the actuator is de-actuated to release the clamping force on the lower shaker screen, the upper shaker screen and the small spacer; and\nwhen in the unclamped position of the multi-screen configuration, slidably removing the upper shaker screen and the small spacer from the track.', '18.', 'The method of claim 17, wherein the installing the screen assembly in the multi-screen configuration further comprises inserting a screen seal between the small spacer and the lower shaker screen.\n\n\n\n\n\n\n19.', 'The method of claim 16, wherein installing the screen assembly in the multi-screen configuration further comprises:\nafter removing the large spacer when the screen assembly is in the single screen configuration, inserting the small spacer and the upper shaker screen into the track; and\nactuating the actuator to provide a clamping force to clamp the first shaker screen, the upper shaker screen and the small spacer between the upper retainer and the lower retainer of the track in a clamped position of the multi-screen configuration.', '20.', 'The method of claim 16, wherein installing the screen assembly in the single screen configuration further comprises securing the large spacer in the track with a spacer retainer assembly, and wherein the spacer retainer assembly comprises a spacer keyway in the large spacer and a spacer retainer configured for the spacer keyway and disposed in the track, and wherein the spacer keyway includes a socket configured to slidably receive the spacer retainer in the internal socket to position the large spacer in a locked position.'] | ['FIG.', '1 shows a perspective view of an example vibratory separator;; FIG.', '2A shows a perspective partial view of an embodiment of a screen assembly installed in the vibratory separator in a single screen configuration of the present disclosure;; FIG.', '2B shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in a multi-screen configuration of the present disclosure;; FIG.', '3A shows an assembly view of an embodiment of the screen assembly being installed in the single screen configuration of the present disclosure;; FIG.', '3B shows a view of an embodiment of the screen assembly installed in the single screen configuration of the present disclosure;; FIG.', '3C shows an assembly view of an embodiment of the screen assembly being installed in the multi-screen configuration of the present disclosure;; FIG.', '3D shows a view of an embodiment of the screen assembly installed in the multi-screen configuration of the present disclosure;; FIG.', '4 shows a flowchart depicting a method for installing the screen assembly in the multi-screen configuration of the present disclosure;; FIG.', '5 shows a flowchart depicting a method for installing the screen assembly between a multi-screen configuration and a single screen configuration of the present disclosure;; FIG.', '6 shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in the single screen configuration of the present disclosure;; FIG.', '7A shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in the single screen configuration of the present disclosure;; FIG.', '7B shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in the multi-screen configuration of the present disclosure;; FIG.', '7C shows a perspective partial view of an embodiment of the screen assembly installed in the vibratory separator in an uninstalled screen configuration of the present disclosure;; FIG.', '8 shows a perspective partial view of an embodiment of a large spacer of the screen assembly shown in FIG.', '7A; and; FIG.', '9 shows a perspective cross-sectional, partial view of an embodiment of the large spacer of the screen assembly shown in FIG.', '7A.; FIG.', '1 depicts an example vibratory separator 100.', 'Vibratory separator 100 may be a vibratory shaker used in the oilfield industry to process wellbore fluids.', 'Vibratory separator 100 includes at least one screen assembly 102, a pair of inner walls 104, a feed end 106, and a discharge end 108.', 'The screen assembly 102 is disposed on the inside walls 104 and may include one or more shaker screens 112.', 'Drilling fluid, along with drill cuttings and debris, may be deposited on top of the shaker screen 112 at the feed end 106.', 'The screen assembly 102 may be vibrated (e.g., 25-40 Hz frequency range) by a motor or motors for the purpose of screening or separating the drilling fluid on screen assembly 102.', 'The liquid and fine particles of the drilling fluid may pass through the screen assembly 102 by force of gravity and acceleration caused by the motor and may be recovered underneath the screen assembly 102.', 'Solid particles greater than a certain size may migrate and vibrate across the screen assembly 102 where they may be discharged at the discharge end 108.', 'The screen assembly 102 may include filtering elements, such as mesh, attached to a screen frame.', 'The filtering elements may further define the largest solid particle capable of passing therethrough.; FIG.', '2A shows a partial view of a screen assembly 202 installed in a vibratory separator 200 in a single screen configuration, in accordance with at least one embodiment of the present disclosure.', 'FIG.', '2A shows a view from a discharge end 208 of a left section of the vibratory separator 200.', 'The screen assembly 202 includes a pair of tracks 210, lower shaker screen 212-1, also referred to as a first shaker screen, and a pair of screen clamping assemblies 214.', 'Screen assembly 202 is shown disposed on one of the opposing inner walls 204 of the vibratory separator 200.', 'The inner walls 204 may form part of a basket of the vibratory separator 200.', 'The pair of tracks 210 oppose one another on opposite inner walls 204 of the vibratory separator 200.', 'FIG.', '2A shows the track 210 disposed on the inner wall 204 of the left section of the vibratory separator 200 and another track 210 is disposed on the inner wall 204 of the right section of the vibratory separator 200, as shown in FIG.', '2A.', 'Lower shaker screen 212-1 includes a screen frame 226 and a filtering media 228 attached to the screen frame 226.; FIG.', '2A shows the spacer retainer assembly 242 in a spacer retained position where the large spacer 232 is secured in place in the track 210 by the spacer retainer assembly 242.', 'Spacer retainer 246 may be removed from the large spacer 232 to position the spacer retainer assembly 242 in a spacer unretained position where the large spacer 232 is not secured in place within the track 210 by the spacer retainer assembly 242.', 'The large spacer 232 may be removed from the track 210 by sliding the large spacer 232 from the track 210 after the spacer retainer 246 has been removed.', '; FIG.', '2B shows a partial view of the screen assembly 202 installed in the vibratory separator 200 in a multi-screen configuration, in accordance with at least one embodiment of the present disclosure.', 'FIG.', '2B shows a view from a discharge end 208 of a right section of the vibratory separator 200.', 'The screen assembly 202 includes the pair of tracks 210, the lower shaker screen 212-1, an upper shaker screen 212-2, and the screen clamping assembly 214.', 'Screen assembly 202 is shown disposed on one of the opposing inner walls 204 of the vibratory separator 200.', 'Lower shaker screen 212-1 may be the same lower shaker screen 212-1 used in the single screen configuration.', 'In other embodiments, the lower shaker screen 212-1 may be another shaker screen 212.; FIG.', '3A shows an assembly view of an embodiment of a screen assembly 302 being installed in the single screen configuration, and FIG.', '3B shows the screen assembly 302 in the single screen configuration after installation.', 'Screen assembly 302 includes a spaced-apart pair of tracks 310, a lower shaker screen 312-1, and a pair of screen clamping assemblies 314.', 'Screen clamping assemblies 314 are referenced with numeral 314 in FIG.', '3B and FIG.', '3D. Tracks 310 each have an upper retainer 316, a lower retainer 318 with a screen clamping assembly 314 disposed in each track 310.', 'Screen clamping assemblies 314 each include a seal 334, a large spacer 332, a bladder 336, and nozzle 338.', 'Bladders 336 extend adjacent to and below the upper retainers 316.; FIG.', '3C shows an assembly view of an embodiment of a screen assembly 302 being installed in the multi-screen configuration, and FIG.', '3D shows the screen assembly 302 in the multi-screen configuration after installation.', 'When in the multi-screen configuration, screen assembly 302 includes the lower screen 312-1 in addition to an upper shaker screen 312 that is spaced from the lower shaker screen by a small spacer 333.; FIG.', '4 is a flowchart showing an embodiment of an installation method 400 for installing a screen assembly of a vibratory separator in a multi-screen configuration of the present disclosure.', 'The screen assembly in the multi-screen configuration includes a lower shaker screen, an upper shaker screen, a track, and an actuator disposed in the track.', 'The installation method 400 begins by an installer inserting in the track the lower shaker screen at a lower level (block 402).', 'The installer inserts in the track above the lower shaker screen a small spacer (block 404).', 'The small spacer has a first spacer dimension selected to correspond to the multi-screen configuration.', 'The installer inserts in the track above the small spacer the upper shaker screen at an upper level (block 406).', 'The small spacer is configured to separate the lower shaker screen from the upper shaker screen so that a lower screen deck is formed by the lower shaker screen and an upper screen deck is formed by the upper shaker screen.', 'The lower shaker screen, small spacer, and upper shaker screen may be slid into the track during installation and may be slid into a pair of spaced-apart tracks.; FIG. 5 is a flowchart showing an embodiment of an installation method 500 for installing a screen assembly of a vibratory separator between a multi-screen configuration and a single screen configuration of the present disclosure.', 'The installation method 500 for installing the screen assembly in the multi-screen configuration includes the blocks 502-508 that are the same as the installation method 400 for installing the screen assembly in the multi-screen configuration described with respect to FIG.', '4.', 'Blocks 502-508 are performed as described with respect to blocks 402-408 of FIG.', '4.', 'When the screen assembly is in the multi-screen configuration, an installer may remove the upper shaker screen and the small spacer from the track (block 510).', 'In some embodiments, before removing the upper shaker screen and the small spacer (block 510), the installer may de-actuate the actuator to position the screen assembly in the multi-screen configuration from a clamped position to an unclamped position.', 'The upper shaker screen and small spacer may be removed from the tracks.', 'After removing the upper shaker screen and the small spacer from the track, the installer inserts in the track above the lower shaker screen and adjacent the actuator a large spacer (block 512).', 'The large spacer has a second spacer dimension larger than the first spacer dimension of the small spacer and is selected to correspond to the single screen configuration.', 'The large spacer may be slid into the track during installation and may be slid into the pair of spaced-apart tracks.', 'The installer may actuate the actuator to provide a clamping force to clamp the large spacer and the first shaker screen between the upper retainer and the lower retainer of the track in a clamped position of the single screen configuration (block 514).', 'When in the clamped position, the screen assembly is installed in the single screen configuration and the screen assembly is ready to withstand the vibrations during operations.; FIG.', '6 shows a partial view of a screen assembly 602 installed in a vibratory separator 200 in a single screen configuration, in accordance with at least one embodiment of the present disclosure.', 'Like components of embodiments of the screen assemblies are labeled with like reference numbers.', 'In FIG.', '6, large spacer 632 is shown installed in the track 210 by spacer retainer 246 disposed in a spacer keyway 644.', 'Spacer keyway 644 may be a “T” slot or other slot cut into the large spacer 632 configured to permit large spacer 632 to be hooked onto the spacer retainer 246 to install the large spacer 632 in the track 210 and unhooked from the spacer retainer 246 to remove the large spacer 632 from the track 210.; FIG.', '7A shows a partial view of a screen assembly 702 installed in the vibratory separator 200 in the single screen configuration, in accordance with at least one embodiment of the present disclosure.', 'Like components of embodiments of the screen assemblies are labeled with like reference numbers.', 'FIG.', '7A shows a view from a discharge end 208 of the left section of the vibratory separator 200.', 'Screen assembly 702 includes a pair of tracks 710 and a lower shaker screen 712-1.', 'Screen assembly 702 further includes disposed in each track a large spacer 732, an actuator 230, and a seal 734. FIG.', '7A shows the seal 734 disposed in a channel 770.', 'Track 710 includes an upper retainer 716 and a lower retainer 718.', 'The lower retainer 718 includes an upper surface 719, and the lower shaker screen 712-1 rests on and is supported by the upper surface 719 of the lower retainer 718.', 'In some embodiments, the upper surface 719 may be disposed at a thirty-degree angle with respect to the inner wall 204 to help limit solids build-up on the lower retainer 718 during operations.', 'In some embodiments, the lower shaker screen 712-1 has a bottom surface 713 having an angle that matches the angle of the upper surface 719 of the lower retainer 718.; FIG.', '7B shows a partial view of the screen assembly 702 installed in the vibratory separator 200 in the multi-screen configuration, in accordance with at least one embodiment of the present disclosure.', 'FIG.', '7B shows a view from a discharge end 208 of the right section of the vibratory separator 200.', 'The screen assembly 702 includes tracks 710, a lower shaker screen 712-1, and an upper shaker screen 712-2.', 'Screen assembly 702 further includes disposed in each track 710 the large spacers 733 and the actuator 230.', 'In some embodiments, a seal (not shown) may be disposed in a channel (not shown) in the small spacer 733 in a manner as shown in FIG.', '7A and FIG.', '10 for the large spacer 732.', 'The lower shaker screen 712-1 rests on and is supported by the upper surface 719 of the lower retainer 718.', 'Upper shaker screen 712-2 is disposed above and rests on small spacer 733.', 'In some embodiments, large spacers 732 and small spacers 733 are made with materials that are moldable, including urethane.; FIG.', '7C shows a partial view of a screen assembly 702 installed in the vibratory separator 200 in an uninstalled screen configuration.', 'When in the uninstalled screen configuration, the large spacer 732 and the small spacer 733 are removed from the tracks 710.', 'Spacer retainers 746 are spaced apart along the length of the track 710.', 'Each spacer retainer 746 extends from a fixture wall 720 of the track 710 and is disposed in the track channel.', 'Each spacer retainer 746 includes a head section 752.', 'In some embodiments, the spacer retainer 746 has a “T” shape.', 'In some embodiments, the spacer retainer 746 has other shapes.', 'Spacer retainer 746 may be attached to the track 710 and/or inner wall 204 by welding or other attachment mechanism, as discussed with respect to spacer retainer 246.'] |
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US11078742 | BOP health monitoring system and method | May 13, 2019 | Se Un Park, Rajesh Kumar Bade, Daniel Barker, Daniel Edgardo Viassolo | Schlumberger Technology Corporation | Se Un Park et al., “Towards Automated Condition Monitoring of Blowout Preventer Wellbore Packers”, Annual Conference of the Prognostics and Health Management Society, 2018. (Year: 2018).; Canh Ly et al., “Fault Diagnosis and Failure Prognosis for Engineering Systems: A Global Perspective”, 5th Annual IEEE Conference on Automation Science and Engineering Bangalore, India, Aug. 22-25, 2009. (Year: 2009).; Taimoor S. Khawaja et al., “An Efficient Novelty Detector for Online Fault Diagnosis based on Least Squares Support Vector Machines”, IEEE AUTOTESTCON 2008, Salt Lake City, UT, Sep. 8-11, 2008. (Year: 2008).; Ahmed Mosallam, “Data Driven PHM Applications for Oil & Gas Industry”, Schlumberger Research & Production Center, 2019. (Year: 2019).; International Standards Organization (ISO), “Condition Monitoring and Diagnostics of Machines—Prognostics part 1: General Guidelines,” 15013381-1, 2004 (e), vol. ISO/IEC Directives Part 2, I. O. f. S. (ISO), Genève, Switzerland, International Standards Organization, Jun. 11, 2004.; Schwabacher, et al., “A survey of artificial intelligence for prognostics,” Proceedings of AAAI Fall Symposium, Nov. 9-11, 2007, Arlington, VA. | 7124057; October 17, 2006; Forster; 8138931; March 20, 2012; Keast; 8874307; October 28, 2014; Behr; 9410392; August 9, 2016; Jaffrey; 9677573; June 13, 2017; Jaffrey; 10024754; July 17, 2018; Hervieux; 10087745; October 2, 2018; Gottlieb; 10287869; May 14, 2019; Jaffrey; 10467881; November 5, 2019; Chen; 10570689; February 25, 2020; Jaffrey; 10585068; March 10, 2020; Gottlieb; 10724307; July 28, 2020; Bushman; 10751950; August 25, 2020; Donaldson; 10900347; January 26, 2021; Amsellem; 20030005486; January 2, 2003; Ridolfo; 20030216888; November 20, 2003; Ridolfo; 20140064029; March 6, 2014; Jaffrey; 20140069531; March 13, 2014; Jaffrey; 20140123746; May 8, 2014; Jaffrey; 20150233398; August 20, 2015; Jaffrey; 20150308253; October 29, 2015; Clark; 20150337599; November 26, 2015; Bullock; 20160131692; May 12, 2016; Jaffrey; 20160215608; July 28, 2016; Jaffrey; 20160237773; August 18, 2016; Dalton; 20160341628; November 24, 2016; Hervieux; 20170130575; May 11, 2017; Jaffrey; 20170152967; June 1, 2017; Jaffrey; 20180135379; May 17, 2018; Bushman; 20180142543; May 24, 2018; Gupta; 20190011051; January 10, 2019; Yeung; 20190017344; January 17, 2019; Lambert; 20190226295; July 25, 2019; Zonoz; 20190271225; September 5, 2019; Amsellem; 20190278260; September 12, 2019; Dalton; 20200096132; March 26, 2020; Fassbender | Foreign Citations not found. | ['A blowout preventer (BOP) health monitoring system includes a controller having a tangible, machine readable-medium storing one or more instructions executable by a processor.', 'The one or more instructions are configured to receive feedback from a sensor, where the feedback is indicative of a pressure within a BOP stack over time, determine a position of a plurality of components of the BOP stack, determine a start point and an end point of a pressure test based on the feedback, determine a decay and a hold duration of the pressure test based on the feedback, the start point, and the end point, determine a health index of the BOP stack based on the decay and the hold duration, and provide an output indicative of a condition of the BOP stack based on the health index.'] | ['Description\n\n\n\n\n\n\nCROSS REFERENCE TO RELATED APPLICATIONS', 'This is a non-provisional patent application of co-pending U.S. Provisional Patent Application Ser.', 'No. 62/670,838, filed on May 13, 2018 which is hereby incorporated in its entirety for all intents and purposes by this reference.', 'BACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'A blowout preventer (BOP) is a component that is designed to be placed on top of a wellhead of a mineral extraction system.', 'The BOP may be activated to block a flow of fluid from a wellbore toward a platform or rig of the mineral extraction system.', 'For example, the BOP may be activated by directing hydraulically energized packer elements or rams that form a seal between the wellbore and the wellhead.', 'Periodic testing of a BOP may enable operators to maintain and control an integrity of the BOP.', 'For instance, a pressure test may simulate a ‘kick’ (e.g., an increase in wellbore pressure) to assess an ability of BOP packers or rams to isolate the well pressure from the wellhead and/or the platform.', 'The pressure tests may be formed at periodic intervals to determine the integrity of the BOP components.', 'High pressure fluid used during the pressure test may cause various components (e.g., pipes, conduits, packers, rams, and/or elastomeric components) to incur wear, which may affect a performance of the BOP.', 'During the pressure test, the drilling and/or production processes of the mineral extraction system may be shut down or otherwise stopped.', 'For instance, during the pressure test, components of the BOP may be closed to apply pressure to the BOP and measure the pressure changes at various sensors to determine that the BOP can hold the specified pressure.', 'Unfortunately, existing testing methods may be time consuming, which may reduce production of the mineral extraction system.', 'SUMMARY', 'In an embodiment, a blowout preventer (BOP) health monitoring system includes a controller having a tangible, machine readable-medium storing one or more instructions executable by a processor.', 'The one or more instructions are configured to receive feedback from a sensor, where the feedback is indicative of a pressure within a BOP stack over time, determine a position of a plurality of components of the BOP stack, determine a start point and an end point of a pressure test based on the feedback, determine a decay and a hold duration of the pressure test based on the feedback, the start point, and the end point, determine a health index of the BOP stack based on the decay and the hold duration, and provide an output indicative of a condition of the BOP stack based on the health index.', 'In another embodiment, a system includes a blowout preventer (BOP) stack having one or more valves and a BOP, a sensor configured to monitor a pressure within the BOP stack, and a BOP health monitoring system having a controller with a tangible, machine readable-medium storing one or more instructions executable by a processor.', 'The one or more instructions are configured to receive feedback from the sensor, where the feedback is indicative of a pressure within the BOP stack over time, determine a start point and an end point of a pressure test based on the feedback, determine a decay and a hold duration of the pressure test based on the feedback, the start point, and the end point, determine a health index of the BOP stack based on the decay and the hold duration, and provide an output indicative of a condition of the BOP stack based on the health index.', 'In another embodiment, a method includes receiving feedback from a sensor indicative of a pressure within a BOP stack over time, determining a start point and an end point of a pressure test based on the feedback, determining a decay and a hold duration of the pressure test based on the feedback, the start point, and the end point, determining a health index of the BOP stack based on the decay and the hold duration, and providing an output indicative of a condition of the BOP stack based on the health index.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n is a graphical representation of an embodiment of results produced by an improved blowout preventer (BOP) health monitoring system, in accordance with an embodiment of the present disclosure;\n \nFIG.', '2\n is a graphical representation of an embodiment of results produced by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure;\n \nFIGS.', '3A and 3B\n are graphical representations of embodiments of results produced by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure;\n \nFIG.', '4\n is a schematic of an embodiment of the improved BOP health monitoring system included in a BOP system or stack, in accordance with an embodiment of the present disclosure;\n \nFIG.', '5\n is a table illustrating an example of an embodiment of a pressure test configuration for the BOP system of \nFIG.', '4\n, in accordance with an embodiment of the present disclosure;\n \nFIG.', '6\n is a flow chart of an embodiment of a decision tree executed by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure; and\n \nFIG.', '7\n is a flow chart of an embodiment of a process performed by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nReference will now be made in detail to specific embodiments illustrated in the accompanying drawings and figures.', 'In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the disclosure.', 'However, it will be apparent to one of ordinary skill in the art that embodiments may be practiced without these specific details.', 'In other instances, well-known methods, procedures, components, have not been described in detail so as not to unnecessarily obscure aspects of the embodiments.', 'It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms.', 'These terms are only used to distinguish one element from another.', 'For example, a first object could be termed a second object, and, similarly, a second object could be termed a first object, without departing from the scope of the present disclosure.', 'The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.', 'As used in the description and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise.', 'It will also be understood that the term “and/or” as used herein refers to and encompasses any and possible combinations of one or more of the associated listed items.', 'It will be further understood that the terms “includes,” “including,” “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, operations, elements, components, and/or groups thereof.', 'Further, as used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context.', 'The present disclosure relates to systems and methods for monitoring the health of blowout preventer (BOP) stacks in mineral extraction systems.', 'As used herein, a BOP stack may refer to a system that includes one or more BOPs positioned above a wellhead, one or more valves, one or more fluid conduits, other suitable components, or any combination thereof.', 'Specifically, the present disclosure relates to a BOP health monitoring system (e.g., a signal-based monitoring system) that uses pressure test data and related system data in order to determine a health of a BOP stack and/or components of the BOP stack (e.g., packers, elastomeric components, rams, valves, among others).', 'In some embodiments, the BOP health monitoring system further uses underlying physics of the BOP stack to determine to the health of the BOP stack.', 'The BOP health monitoring system may include a controller or another suitable computing device that includes a processor and a memory device.', 'The processor may be utilized to execute instructions stored on the memory device and may include a general purpose processor, a special purpose processor, one or more application specific integrated circuits (ASICS), and/or a combination thereof.', 'In some embodiments, the processor includes a reduced instruction set processor.', 'The memory may include volatile memory, such as random access memory (RAM), and/or nonvolatile memory, such as read-only memory (ROM).', 'The memory device stores processor-executable instructions that may be utilized to receive feedback from one or more sensors, analyze the feedback, determine various test configurations, determine a health index of the BOP stack, determine a health index of one or more specific components of the BOP stack, and/or perform other functions described herein.', 'According to some embodiments, the BOP health monitoring system utilizes a prognostic health monitoring (PHM) algorithm that monitors and/or analyzes pressure test data.', 'For example, pressure test data may include feedback indicative of a pressure of a fluid within the BOP stack and/or at the wellbore over time.', 'In some embodiments, the BOP health monitoring system is configured to identify and characterize pressure tests by searching start and end points of pressure test data when considering physical constraints of a given BOP stack (e.g., a number of components that may be tested, a pressure threshold of tested components, a duration at which components may maintain a pressure, among others).', 'Further, the BOP health monitoring system may be configured to infer a status of one or more BOP components based on analysis of the pressure test data.', 'A BOP stack might comprise numerous components, such as annular BOPs, ram BOPs, connectors, conduits, and/or gate-valves.', 'Furthermore, pressure tests of the BOP components may be performed on various combinations of pressure-holding components of the BOP (e.g., packers, rams, and/or valves) in a closed position.', 'For example, a pressurized line may have multiple valves (e.g., inner and/or outer valves, upper, middle, and/or lower valves) and each valve may include one or more inlets and/or outlets, which may be tested to determine the status of subcomponents of the valves (e.g., a first side of a choke valve and/or a second side of a choke valve).', 'Also, pressure tests may be configured to test annular BOPs and/or ram BOPs, which may experience pressure resistance in a single direction (i.e., pressure coming from the wellbore).', 'Embodiments of the present disclosure provide systems and methods that enable identification of which components of a BOP stack are under a pressure test and efficiently perform pressure tests by testing each component while avoiding redundant pressure tests.', 'Accordingly, as pressure testing often limits operational and/or production activities of the mineral extraction system, test plan optimization may minimize non-productive time of the mineral extraction system.', 'In embodiments of the disclosure, the BOP health monitoring system is configured to monitor a health of BOP stacks in mineral extraction systems using automated testing techniques.', 'The BOP health monitoring system is configured to perform feature extraction of pressure test data based on a simulation model.', 'For example, the BOP health monitoring system may utilize the simulation model to automatically identify components tested, while detecting characteristic data points in time-series pressure measurements.', 'Further, the BOP health monitoring system is configured to evaluate the features and/or characteristic data points, such as pressure decay and/or hold durations, to determine the health of the BOP stack and/or specific BOP components.', 'In some embodiments, the extracted features are further processed in subsequent steps and augmented with existing BOP data to produce health indices (H/s) of the BOP system as an output.', 'Further still, the BOP health monitoring system is configured to design and simulate BOP pressure test plans with different configurations of components that are included in a given BOP structure.', 'For instance, the BOP health monitoring system may be configured to automatically identify components undergoing a test, select test scenarios, and optimize future pressure test plans.', 'The BOP health monitoring system enables automatic identification of tested components as well as automated test planning using a specific configuration of a BOP stack, constraints of BOP components, and/or known test plans.', 'Using known states of BOP components, the BOP health monitoring system can determine lines and cavities that are pressurized, components tested and/or undergoing testing, pressurized sides of tested components, and components whose status is irrelevant (e.g., components that may not be tested and/or do not require testing).', 'As such, the BOP health monitoring system discussed herein can be used in automating pressure test planning.', 'In some embodiments, a given BOP stack may include two P/T (pressure and temperature) sensors.', 'In other embodiments, the BOP stack may include one P/T sensor or more than two P/T sensors.', 'In still further embodiments, the BOP stack may include any suitable number P/T sensors and/or another type of sensor.', 'In any case, a number of sensors included in the BOP may be based on the structure and/or a number of components of the BOP stack.', 'In some embodiments, a first sensor may be positioned in and/or proximate to a pipe ram cavity or a shear ram cavity above a wellhead connector to provide wellbore pressure data.', 'Additionally or alternatively, a second sensor may be located along a choke line and/or a kill line.', 'Wellbore pressure data may be indicative of a pressure applied to packers and/or rams of the BOP stack because of the proximity of such components to the wellbore (e.g., see \nFIG.', '4\n).', 'In some embodiments, the BOP health monitoring system of the present disclosure processes the wellbore pressure data in order to determine a health of the BOP stack and/or components of the BOP stack.\n \nFIG.', '1\n is a graphical representation of an embodiment of noisy pressure data (e.g., received by a controller of the BOP health monitoring system) with discontinuous pressure values and noise, where time \n10\n (e.g., measured in minutes) is represented by the x-axis, and pressure \n12\n (e.g., measured in bars) is represented by the y-axis.', 'As shown in \nFIG.', '1\n, points \n14\n indicate a start of a respective pressure test and points \n16\n indicate an end of the respective pressure tests.', 'A decay level may be determined based on a slope and/or a difference between points \n14\n and points \n16\n for each respective pressure test.', 'As is described in detail herein, the decay level of each pressure test may be used as a characteristic feature by the BOP health monitoring system.', 'As shown in the illustrated embodiment of \nFIG.', '1\n, the pressure data is recorded at various times, but several pressure data points \n18\n may be considered as noise, extraneous data, or even erroneous.', 'Some of these data points \n18\n can be easily removed when performing analysis on the pressure test data.', 'For example, negative pressure values or pressure values greater than a maximum working pressure of the BOP may be considered erroneous and automatically eliminated from the pressure test data.', 'Other data points \n18\n may be treated as noise and may be filtered using a suitable de-noising technique.', 'Existing pressure data analysis presents complexities based on resolution of the decay levels, sampling intervals, and/or a combination of both.', 'In particular, P/T sensors may include a data compression mechanism and/or an associated data-historian, which may result in sparse datasets that cause irregular sampling intervals between data points.', 'Additionally, pressure tests that exhibit relatively small differential pressures cause graphs to look flat, thereby leading to sparse data sets.', 'Evaluating small pressure drops and/or irregular sample time-series data may be complex to analyze using existing techniques.', 'In embodiments of the present disclosure, the BOP health monitoring system may be configured to resample and/or interpolate such data for further processing.', 'For example, the BOP health monitoring system may be configured to employ signal processing techniques such as linear interpolations, bicubic interpolations, radial basis functions, and/or other suitable techniques to effectively analyze small pressure drops and/or irregular sample time-series data.', 'Additionally, resampling may be performed over a given sampling interval after interpolation is applied.', 'In embodiments of the present disclosure, both time domain and frequency domain post-processing algorithms may be considered for extracting informative features.', 'Further still, the BOP health monitoring system may utilize statistical analysis to extrapolate pressure test data.', 'The characteristic points of pressure tests might include the points \n14\n and the points \n16\n.', 'As shown in the illustrated embodiments of \nFIGS.', '1 and 2\n, a pressure test pattern is approximately rectangular.', 'This pattern has a seemingly flat top, but in fact has a small negative slope during the pressure tests.', 'The transitions of either pressure rise or pressure drop applied during the pressure tests are sudden and can be seen as vertical lines over time \n10\n, as seen in \nFIGS.', '1 and 2\n.', 'In an embodiment of the present disclosure, by limiting the pressure test pattern to rectangular, the first order differentials of the pressure test data, as instantaneous or point-wise slopes, enables characteristic points in the data set to be identified.', 'However, point-wise differentials might be noisy with large variations because of the nature of the noise included within the pressure test data.', 'Therefore, evaluation of the differentials over a larger, fixed period of time may stabilize the value.', 'By utilizing differentials over a larger, fixed period of time, identification of the characteristic points in both high pressure (HP) tests and low pressure (LP) tests may be determined, as shown in \nFIG.', '2\n.', 'Because HP tests may follow the LP tests, the characteristic points of a respective HP test may be determined and then the characteristic points may be determined for the corresponding LP test.', 'In embodiments of the present disclosure, a unit pressure test may be defined as an LP test and an HP test immediately following the corresponding LP test.', 'FIG.', '2\n presents an example of the detection results similar to \nFIG.', '1\n, but with less noise and with both HP tests and LP tests.', 'As shown in \nFIGS.', '1 and 2\n, a typical pressure operation may include multiple individual pressure tests corresponding to a unique BOP Stack configuration.', 'The American Petroleum Institute (API) issues regulations that may define limits as pass criteria for pressure tests performed on a BOP stack.', 'These limits can include hold-duration between the starting and ending points of pressure tests and global decay (e.g., pressure difference from the ending to the starting points of tests).', 'In embodiments of the BOP health monitoring system disclosed herein, other characteristic features such as local decays defined by specific time-windows, the size of window in terms of time, the number of data points within the window, and statistics (mean, standard deviation) of data points within the window might be used to provide an improved indication of a health of the BOP stack.', 'For example, in some embodiments, the BOP health monitoring system may be configured to determine the local decay and associated statistics within a moving, size-varying window.', 'As such, the BOP health monitoring system may incrementally extend the window by covering a new data point in the time domain based upon an arbitrary datum, and for each window, repeatedly evaluate the local decay, slope, mean, standard variation, the number of data points within the window, and the window size in time.', 'Other statistics, such as instantaneous slope or point-wise first order differentials, might further be determined by the BOP health monitoring system (e.g., a controller of the BOP health monitoring system).', 'Based on the above features, embodiments of the disclosure might define health indices based on two algorithms.', 'For example, the BOP health monitoring system may be configured to determine how the pressure test results compare to a target specification using threshold values for decay (e.g., global decay or local decay) and hold duration.', 'Equation 1 below represents the health index for decay (e.g., global decay or local decay) and Equation 2 below represents the health index for hold duration.', 'HI(\ns\n)=max(\nT\ns\n−s,\n0)/|\nT\ns\n|\u2003\u2003(1) \n HI(\nd\n)=max(\nT\nd\n−d,\n0)/\nd\n\u2003\u2003(2)', 'In Equation 1, s represents a decay value (e.g., negative slope in pressure over time or a target time window) and T\ns \nis the threshold for the decay (e.g., slope).', 'In Equation 2, d represents duration time of the pressure hold and T\nd \nis the threshold for the duration time of the pressure hold.', 'The overall health index (HI) is the sum of the decay health index and the duration health index, HI(s) and HI(d), respectively, as shown in Equation 3 below.', 'HI=HI(\ns\n)+HI(\nd\n)\u2003\u2003(3) \n \nAdditionally, in some embodiments, the health index may be generated based on local decay over a target window of time.', 'As such, a standard deviation of the plurality of tests may also be included in the overall health index (HI), as shown in Equation 4 below.', 'In other embodiments, the slope, mean, number of data points within the target window, and/or the window size in time may also be included in the overall health index calculation.', 'In still further embodiments, any weighted combination of individual health indices, such as HI(s), HI(d), HI(std. dev.), etc., may be utilized to generate the overall health index, HI, as shown in Equation 5 below.', 'For example, a first weight, w\n1\n, may be assigned to a first health index, k\n1\n, a second weight, w\n2\n, may be assigned to a second health index, k\n2\n, a third weight, w\n3\n, may be assigned to a third health index, k\n3\n, and so forth.', 'As such, when decay, s, is the first health index, k\n1\n, and the first weight, w\n1\n, is 1, when hold duration, d, is the second health index, k\n2\n, and the second weight, w\n2\n, is also 1, and when standard deviation, std. dev., is the third health index, k\n3\n, and the third weight, w\n3\n, is 0, then Equation 5 may be reduced to Equation 3 set forth above.', 'HI=HI(\ns\n)+HI(\nd\n)+HI(std.', 'dev.)', '(4) \n HI=\nw\n1\nHI(\nk\n1\n)+\nw\n2\nHI(\nk\n2\n)+\nw\n3\nHI(\nk\n3\n)+ . . .', '(5) \n \nFIGS.', '3A and 3B\n are graphical representations of embodiments of several health indices evaluated from different decays (e.g., global decays or local decays) and hold durations.', 'For example, \nFIG.', '3A\n represents health indices over different decays, HI(s).', 'FIG.', '3B\n represents health indices over different hold durations, HI(d).', 'In these examples, the decay threshold is 1.3 bar/minute (e.g., absolute values are considered) and the hold duration threshold is 12 minutes.', 'Any other decay threshold and/or hold duration threshold may be used as appropriate for the assessed BOP system.', 'If the absolute value of a decay becomes larger than the threshold, HI increases from zero.', 'If the hold duration is less than the threshold, then the corresponding HI also increases from zero.', 'In the example of \nFIGS.', '3A and 3B\n, the health index is chosen as zero (0) as the index for “healthy,” monotonically increasing to one-hundred (100) for “unhealthy.”', 'The choice of starting/ending indexes as well as direction (e.g. monotonically decreasing, increasing, etc.) is however arbitrary and may be amended as appropriate to the tested system.', "The threshold values for decay and hold duration may be obtained and/or otherwise retrieved from industrial regulatory guidelines, government agencies, equipment owner's past experience, equipment manufacturer recommendations, and/or industry group practices.", 'In some embodiments, health indices are defined such that for a healthy state, HI=0.', "The health indices increase as non-negative numbers as the component's health decreases.", 'The healthiest state covers the cases where the hold duration and decay of the pressure hold period are less than the corresponding threshold values.', 'The decays and decay thresholds are expected to be negative as the pressure tends to drop over time during the hold period.', 'In embodiments of the disclosure, the pressure drop can be modeled as either exponential and/or linear.', 'For example, the pressure drop rate is proportional to the difference between the contained high pressure and outside pressure (i.e., dP/dt=−k P(t), where k is a constant, P represents pressure, and t represents time).', 'As such, the pressure may be modeled as exponential decay, P(t)=P\n0\n exp(−kt), with the initial pressure P\n0\n.', 'In some cases, when the pressure drop rate is constant over time due to system control (i.e., dP/dt=−k) then the drop is simply linear, P(t)=P\n0\n−kt.', 'To reduce costs, every BOP stack component might not be equipped with a pressure sensor.', 'Accordingly, the BOP health monitoring system may be configured to identify which components are being tested during a specific pressure test.', 'For a given BOP structure, one can manually compile all the possible test scenarios before testing and build a dictionary of test configurations that may indicate an open/closed position of each component during a respective pressure test.', 'The dictionary of test configurations may thus be utilized to determine which components are being tested during the respective pressure test.', 'Unfortunately, manually compiling the dictionary of test configurations may become increasingly cumbersome as the number of test configurations increases.', 'Therefore, the BOP health monitoring system of the present disclosure may be configure to automatically generate the dictionary of test configurations.', 'Moreover, the BOP health monitoring system may be configured to determine which components are being tested in real time as tests are performed or offline upon completion of a test.', 'Further still, the BOP health monitoring system may be configured to compare a given test to the automatically generated dictionary of test configurations in order to identify redundancies in a pressure test plan and optimize the pressure test plan.', 'In other words, the BOP health monitoring system may reduce a total number of pressure tests within a target test configuration plan to reduce non-productive time of the mineral extraction system.', 'In some embodiments, the BOP health monitoring system includes a BOP stack pressure test simulator that defines a state and/or a position of valves, BOPs, and pressure sources of a BOP stack at the time of the pressure test and/or during hold periods of the pressure test.', 'As such, the BOP stack pressure test simulator may be configured to determine which components of the BOP stack are being tested during a given pressure test.', 'The BOP health monitoring system may store this information in the form of a schematic diagram of the BOP stack, a table, a matrix, text string, data, another suitable format, or a combination thereof.', 'For example, \nFIG.', '4\n is a schematic of a test configuration of a BOP stack \n30\n that includes a BOP health monitoring system \n32\n, in accordance with embodiments of the present disclosure.', 'As shown in the illustrated embodiment of \nFIG.', '4\n, the BOP health monitoring system \n32\n may include a controller \n34\n that is communicatively coupled to various components of the BOP stack \n30\n.', 'The controller \n34\n includes a processor \n36\n configured to execute one or more instructions stored on a memory device \n38\n of the controller \n34\n.', 'For example, the memory device \n38\n stores instructions configured to receive feedback (e.g., pressure data, temperature data and/or a status of the components of the BOP stack \n30\n) from a sensor \n40\n and/or another suitable device (e.g., another sensor and/or another controller).', 'The one or more instructions stored on the memory device \n38\n may be executed by the processor \n36\n in order to analyze the feedback and determine the health indices set forth above.', 'As shown in the illustrated embodiment, the sensor \n40\n is positioned between a wellhead \n44\n and the BOP stack \n30\n.', 'In other embodiments, the sensor \n40\n may be positioned in another suitable location within the BOP stack.', 'The BOP stack \n30\n illustrated in \nFIG.', '4\n includes a variety of components that are utilized to perform pressure tests and/or to block a fluid flow from the wellhead \n44\n toward a surface, rig, and/or platform of the mineral extraction system.', 'For example, the BOP stack \n30\n includes a first pipe ram BOP \n46\n, a second pipe ram BOP \n48\n, a third pipe ram BOP \n50\n, a first shearing BOP \n52\n, a second shearing BOP \n54\n, and/or an annular BOP \n56\n.', 'In other embodiments, the BOP stack \n30\n may include any suitable number and/or types of BOPs.', 'Further, the BOP stack \n30\n includes a kill line \n58\n that may be configured to supply pressurized fluid from a fluid source \n60\n to the BOP stack \n30\n to perform the pressure tests.', 'The BOP stack \n30\n may also include a choke line \n62\n that is configured to direct pressurized fluid from the BOP stack \n30\n back toward the fluid source \n60\n.', 'In other embodiments, the pressurized fluid may be supplied by the choke line \n62\n and directed back toward the fluid source \n60\n via the kill line \n58\n.', 'In still further embodiments, the kill line \n58\n or the choke line \n62\n may act alone to both supply the pressurized fluid to the BOP stack \n30\n and direct the pressurized fluid back to the fluid source \n60\n.', 'As shown in the illustrated embodiment of \nFIG.', '4\n, the BOP stack \n30\n may include a plurality of valves \n64\n fluidly coupling the kill line \n58\n, components of the BOP stack \n30\n, and the choke line \n62\n to one another.', 'A position of the plurality of valves \n64\n may be adjusted based on control signals from the controller \n34\n.', 'As should be understood, the respective positions of each valve of the plurality of valves \n64\n may determine which components of the BOP stack \n30\n are tested during a given pressure test.', 'Accordingly, the controller \n34\n may open and/or close various valves of the plurality of valves \n64\n to test specific components of the BOP stack \n30\n to determine a health of the specific components.', 'As shown in the illustrated embodiment of \nFIG.', '4\n, the BOP stack \n30\n includes an upper outer choke (UOC) valve \n66\n, an upper inner choke (UIC) valve \n68\n, a lower outer choke (LOC) valve \n70\n, a lower inner choke (LIC) valve \n72\n, a choke isolation valve (CIV) \n74\n, an upper outer kill (UOK) valve \n76\n, an upper inner kill (UIK) valve \n78\n, a lower outer kill (LOK) valve \n80\n, a lower inner kill (LIK) valve \n82\n, a kill isolation valve (KIV) \n84\n, an outer gas bleed (OB) valve \n86\n, an inner gas bleed (IB) valve \n88\n, and/or a mud boost valve (MBV) \n90\n.', 'In other embodiments, the BOP stack \n30\n may include additional or fewer valves.', 'Further, the plurality of valves \n64\n may include any suitable type of valve, such as ball valves, butterfly valves, choke valves, solenoid valves, another suitable type of valve, or any combination thereof.\n \nFIG.', '5\n is a table illustrating an example of an embodiment of the pressure test configuration for the BOP stack \n30\n of \nFIG.', '4\n (e.g., a perpendicular position of a valve of the plurality of valves \n64\n indicates that the valve is in a closed position).', 'In the pressure test configuration shown in \nFIGS. 4 and 5\n, the annular BOP \n56\n, the OB valve \n86\n, the UOC valve \n66\n, and the LOC valve \n70\n are tested via pressurized fluid supplied from the kill line \n58\n.', 'In \nFIG.', '5\n, the abbreviated terms utilized above for the plurality of valves \n62\n are listed for reference.', 'The numerals “0” and “1” indicate the open and closed state for components, respectively.', 'By investigating the pressurized area from the pressure source to the blocked or closed valves, the BOP health monitoring system \n32\n enables pressurized areas to be identified, thereby identifying the tested components of the BOP stack \n30\n.', 'For example, when a test pressure is run into the BOP stack \n30\n, using known gate logic, the pressurized and/or non-pressurized status of any given area or component of the BOP stack \n30\n may be ascertained and recorded.', 'In some embodiments, additional components or situations may be tested, such as 1) a specific side of a valve of the plurality of valves \n64\n (e.g., most valves have two sides) 2) a specific BOP, 3) one of a pair (inner and outer) of valves of the plurality of valves \n64\n (e.g., the inner valve is closed and tested, while the outer valve may be open), 4) a directional resistance in pressure of a specific BOP (i.e., a side of the BOP incurring pressure coming from the wellbore).', 'In some cases, a position and/or status of certain components may be irrelevant to a given test, which may enable the BOP health monitoring system \n32\n to perform the tests independently of such components.', 'For example, a position of the (MBV) \n90\n does not affect the results of a pressure test when pressurized fluid is supplied via the kill line \n58\n because the MBV \n90\n is physically separate from the possible flow paths of the pressurized fluid.', 'Therefore, the BOP health monitoring system \n32\n may determine that such component is to be “ignored” and indicate that such component may be in either the open or the closed position during the pressure test.', 'Table 1 below represents an example test configuration under practical constraints derived from an automated pressure test configuration identified by the BOP health monitoring system \n32\n.', 'A compilation of each pressure test configuration may help optimize the planning of BOP pressure tests to reduce an amount of pressure tests performed to test each component.', 'The set of all the test configuration generated by the BOP health monitoring system \n32\n may be considered a proposed set, and if an actual configuration is not within the set, an operator may flag a warning (e.g., by indicating HI=−1).', 'The coding system of the test configurations may determine which components are tested and/or ignorable.', 'For example, in Table 1 below the numeral “0” represents a component in open position (e.g., a component not being tested and in the open position in order to perform the pressure test), an “X” represents an ignorable component (e.g., a component which may be in the open position or the closed position), and a “T” represents a tested component (e.g., a component in a closed position and undergoing the pressure test).', 'The encoding is in the order of the annular BOP \n56\n, the second shearing BOP \n54\n, the first shearing BOP \n52\n, the third pipe ram BOP \n50\n, the second pipe ram BOP \n48\n, the first pipe ram BOP \n46\n, the UOC valve \n66\n, the UIC valve \n68\n, the LOC valve \n70\n, the LIC valve \n72\n, the CIV \n74\n, the UOK valve \n76\n, the UIK valve \n78\n, the LOK valve \n80\n, the LIK valve \n82\n, the KIV \n84\n, the OB valve \n86\n, the IB valve \n88\n, and the MBV \n90\n.', 'TABLE 1\n \n \n \n \n \n \n \n \n \n \nComponent Number\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n1\n \n2\n \n3\n \n4\n \n5\n \n6\n \n7\n \n8\n \n9\n \n10\n \n11\n \n12\n \n13\n \n14\n \n15\n \n16\n \n17\n \n18\n \n19\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nTest Status\n \nOpen\n \nClose\n \nClose\n \nOpen\n \nOpen\n \nOpen\n \nClose\n \nOpen\n \nOpen\n \nClose\n \nClose\n \nClose\n \nOpen\n \nOpen\n \nOpen\n \nOpen\n \nClose\n \nClose\n \nClose\n \n \n \nConfigura-\n \n0\n \nT\n \nX\n \n0\n \n0\n \nX\n \nX\n \n0\n \n0\n \nT\n \nX\n \nX\n \n0\n \nX\n \nX\n \n0\n \nT\n \nX\n \nX\n \n \n \ntion Encode', 'After completion of a pressure test, the extracted configuration may be looked up in the test configuration dictionary or input into the simulator to identify tested components.', 'Further, data collected during the pressure test may be utilized to generate feature values and health indices of the tested components (e.g., via the controller \n34\n), as set forth above.', 'If there is a discrepancy between extracted configurations and expected or stored configurations (e.g., a non-matching configuration), either the test may have been performed incorrectly or the test configuration dictionary may not be complete or is lacking a test configuration.', 'In the event the dictionary is incomplete, the test record for the performed pressure test may be given a health index HI=−1, to differentiate it from the normal nonnegative range of health indices and warn the operator.', 'Further, blind spots may exist in various pressure tests that arise from a lack of sensors for a given BOP stack.', 'These blind spots may relate to various components of a given BOP stack configuration that may not be tested.', 'For instance, if the pressured fluid is supplied to the BOP stack via the kill line \n58\n, returned to the fluid source via the choke line \n62\n, and all outer valves are closed (e.g., the UOC valve \n66\n, the LOC valve \n70\n, the UOK valve \n76\n, and/or the LOK valve \n80\n), then the increased pressure does not reach the sensor \n40\n, and thus there is no active pressure change detected by the sensor \n40\n.', 'In such case, the BOP health monitoring system \n32\n may issue a visual warning (e.g., a notification on a computing device, a flashing light emitting diode (LED), and/or another suitable warning) to the operator so these blind spots can be identified and such pressure tests removed from the target test configuration plan.', 'The automated configuration analysis of the BOP health monitoring system \n32\n enables the BOP health monitoring system \n32\n to apply the method to a variety of BOP structures and to efficiently plan pressure tests as a cost saving measure in operations of a mineral extraction system.', 'Using the disclosed automation, operators may perform grid-searching of all the test configurations or adopt a Monte Carlo approach to cover all the components to be tested, while reducing the number of tests and reducing costs.', 'In some embodiments, pressure data measured along the choke line \n62\n, the kill line \n58\n, and/or additional wellbore locations might also be used to detect additional pressure tests configurations in addition to pressure data received from the sensor \n40\n.', 'Further, a duration of an increase in pressure that initiates a seal pressure hold of a given component may be utilized as an indication of elastomer wear.', 'For example, the duration may increase as the component is used over time and indicate performance loss from the original level because less elastomer volume may be present in the component.', 'As such, this duration may also be used in evaluating an overall health of the BOP stack \n30\n and/or individual components of the BOP stack \n30\n.', 'In some embodiments, after a pressure test, certain investigative or analytical steps may be undertaken to isolate or identify specific unhealthy or worn BOP components (e.g., components having a health index value greater than a threshold value, such as 10, 15, 25, 50, or another suitable value).', 'Such steps may include, anomaly-detection, fault-detection, fault-prediction, or a remaining useful life (RUL) estimation.', 'Depending on the diagnosis, one or any combination of these steps may be performed to determine that a component of the BOP stack \n30\n is in a faulty or worn condition.', 'To determine which, if any, of the steps to perform, the BOP health monitoring system \n32\n may utilize one or more decision algorithms based on the results of the pressure test.', 'For example, the BOP health monitoring system \n32\n may perform a test penalty algorithm, a drill-down decision tree algorithm, a feature-based exclusion algorithm, or any combination thereof.', 'The test penalty algorithm may assign a fraction (e.g., a percentage) of pressure test results (e.g., a healthy or unhealthy health index) to each tested component of the pressure test.', 'For instance, the fraction of the pressure test results assigned to each tested component may be an equal amount.', 'In other embodiments, the fraction of the pressure test may be weighted based on various characteristics of the tested components (e.g., pressure rating, known physical condition).', 'Increased fractions assigned to a tested component may enable the BOP health monitoring system \n32\n to determine which tested component of a respective pressure test resulted in an unhealthy health index.\n \nFIG.', '6\n is a flow chart of an embodiment of the drill-down decision tree algorithm \n100\n.', 'To perform the drill-down decision tree algorithm \n100\n, the BOP health monitoring system \n32\n may alter a target test configuration plan to determine which component of the BOP stack \n30\n may be worn or subject to a fault.', 'For instance, the BOP health monitoring system \n32\n may alter the target test configuration plan for the BOP stack \n30\n in order to perform additional tests that may isolate a component that may be worn or in need of maintenance.', 'As shown in the illustrated embodiment of \nFIG.', '6\n, the BOP health monitoring system \n32\n may perform a first pressure test \n102\n to begin the target test configuration plan of the BOP stack \n30\n.', 'In some embodiments, the first pressure test \n102\n may test two components of the BOP stack \n30\n (e.g., the annular BOP \n56\n and one of the UOC valve \n66\n, LOC valve \n70\n, UOK valve \n76\n, and/or the LOK valve \n80\n).', 'After the pressure test results are determined, the BOP health monitoring system \n32\n may perform additional tests to isolate one of the two tested components (e.g., when the pressure test results indicate an unhealthy health index) and/or continue with a second pressure test \n104\n of the target test configuration plan that tests additional components of the BOP stack \n30\n (e.g., when the pressure test results indicate a healthy health index).', 'As such, the drill-down decision tree algorithm may be configured to perform additional pressure tests that would otherwise not be performed by the target test configuration plan of the BOP health monitoring system \n32\n.', 'These additional pressure tests may isolate a specific component to determine that the specific component has incurred wear and/or a fault.', 'When the pressure test results of a respective pressure test indicate that the tested components have a healthy health index (e.g., a health index less than a threshold, such as 5, 10, 15, 25, 50, or another suitable value), the BOP health monitoring system \n32\n may continue to test additional components of the BOP stack \n30\n in accordance with the target test configuration plan generated for the particular structure of the BOP stack \n30\n.', 'Further, the BOP health monitoring system \n32\n may perform a feature based exclusion algorithm to determine a specific component of the BOP stack \n30\n that has generated an unhealthy health index.', 'For example, the feature based exclusion algorithm may utilize feedback from the sensor \n40\n and/or another sensor included in the BOP stack \n30\n.', 'The BOP health monitoring system \n32\n may utilize pressure and/or temperature profiles over time and associate the profiles with a specific class of components of the BOP stack \n30\n (e.g., a valve of the plurality of valves \n36\n, a BOP sealing element).', 'Accordingly, upon determining that a pressure test results in an unhealthy health index, the BOP health monitoring system \n32\n may use signal-driven or model-driven classification methods to analyze the profile of the feedback from the sensor \n40\n, or another suitable sensor, to determine which type or class of component may have resulted in the unhealthy health index.', 'Further, the BOP health monitoring system may then modify the target test configuration plan of the BOP stack \n30\n to isolate and identify a specific component from the class and/or type of component identified.', 'In some embodiments, multiple types of health-indicators (e.g., health indices) may be tracked at different component levels of the BOP stack \n30\n, such as the BOP stack \n30\n generally, a component class or type of the BOP stack \n30\n (e.g., one or more valves of the plurality of valves \n64\n and/or BOPs), and individual components of the BOP stack \n30\n.', 'For example, while the BOP health monitoring system \n30\n may provide a health index for the BOP stack \n30\n generally, the BOP health monitoring system \n30\n may be configured to provide class health indices and/or individual component health indices by performing the algorithms that diagnose classes and/or individual components of the BOP stack \n30\n discussed above.', 'Generating more specific health indices enables maintenance procedures to be performed for one or more specific components to ensure a target performance of the BOP stack \n30\n.', 'In some embodiments, a specific health index for a class of components or an individual component of the BOP stack \n30\n may be tagged with additional information such as an anticipated condition of the class of components or individual component of the BOP stack \n30\n, estimated remaining useful life (RUL) of the class of components or individual component of the BOP stack \n30\n, and/or a confidence level of a condition of the class of components or specific component of the BOP stack \n30\n.', 'This information may be provided to operators, such that informed decisions on maintenance may be made to reduce a non-production time of a mineral extraction system.', 'Health indices and/or other additional information may be transmitted directly between the BOP health monitoring system (e.g., the controller \n34\n) and a Computerized Maintenance Management System (CMMS) of the mineral extraction system having the BOP stack \n30\n.', 'Therefore, an operator may determine when maintenance should be performed while also considering other operational, logistical, and administrative constraints of the mineral extraction system.\n \nFIG.', '7\n is a block diagram of an embodiment of a process \n120\n performed by the BOP health monitoring system \n32\n to diagnose the health of the BOP stack \n30\n.', 'The process \n120\n may be stored as one or more instructions on the memory \n38\n and configured to be executed by the processor \n36\n of the controller \n34\n of the BOP health monitoring system \n32\n.', 'As shown in the illustrated embodiment of \nFIG.', '7\n, at block \n122\n, the processor \n36\n may receive feedback from the sensor \n40\n indicative of a pressure at a location within the BOP stack \n30\n over time.', 'At block \n124\n, the processor \n36\n may identify individual pressure tests from the feedback and filter out any data that is not associated with a pressure test (e.g., data points between individual pressure tests, data points identified as noise, among others).', 'Accordingly, at block \n126\n, the processor \n36\n identifies feature characteristics of the data.', 'As set forth above, the feature characteristics of the data may include a decay of a respective pressure test (e.g., a slope between a starting point of a pressure test and an ending point of a pressure test) and/or a hold duration of the respective pressure test (e.g., a duration at which an increased pressure was maintained in the BOP stack \n30\n).', 'The processor \n36\n may then determine the health index based on the feature characteristics using Equations 1, 2, 3, and/or 4 set forth above, as shown at block \n128\n.', 'Upon determination of the health index for the respective pressure test or tests, the processor \n36\n may determine which components of the BOP stack \n30\n were tested, as shown at block \n130\n.', 'As set forth above, such a determination may be made based on information corresponding to a target test configuration plan of the BOP stack \n30\n and/or using another suitable technique.', 'Based on the health index determined at block \n128\n, the processor \n36\n may determine whether to continue with a target test plan to test additional components and/or to modify the test plan to identify a component that may have generated an unhealthy health index, as shown at block \n132\n.', 'For example, when the processor \n36\n generates a healthy health index at block \n128\n, the processor \n36\n may return to block \n124\n and/or block \n122\n to run another pressure test consistent with the target test plan that tests additional components of the BOP stack \n130\n.', 'When the processor \n36\n generates an unhealthy health index at block \n128\n, the processor \n36\n may proceed to block \n134\n to determine and/or identify a specific component of the BOP stack \n130\n that may have caused the unhealthy health index.', 'When the processor \n36\n proceeds to block \n134\n based on a determination of an unhealthy health index, the processor \n36\n may perform the test penalty algorithm, the drill-down decision tree algorithm, the feature based exclusion algorithm, or any combination thereof, to identify the specific component of the BOP stack \n30\n, as shown at block \n136\n.', 'As such, the processor \n36\n may modify the target test configuration plan to perform additional tests that isolate specific components of the BOP stack \n30\n to determine which tested component may have caused the unhealthy health index.', 'Further, upon identification of the specific component of the BOP stack \n30\n that caused the unhealthy health index, the processor \n36\n may output a signal (e.g., a notification to a computing device and/or a blinking LED) to alert an operator that maintenance may be performed on the specific component, as shown at block \n138\n.', 'As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation.', 'The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”', 'The foregoing description, for purpose of explanation, has been described with reference to specific embodiments.', 'However, the illustrative discussions above are not intended to be exhaustive or to limit the disclosure to the precise forms disclosed.', 'Many modifications and variations are possible in view of the above teachings.', 'Moreover, the order in which the elements of the methods described herein are illustrate and described may be re-arranged, and/or two or more elements may occur simultaneously.', 'The embodiments were chosen and described in order to best explain the principals of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosure and various embodiments with various modifications as are suited to the particular use contemplated.'] | ['1.', 'A blowout preventer (BOP) health monitoring system, comprising:\na controller having a tangible, machine readable-medium storing one or more instructions executable by a processor, wherein the one or more instructions are configured to: receive feedback from a sensor, wherein the feedback is indicative of a pressure within a BOP stack over time; determine a position of a plurality of components of the BOP stack; determine a start point and an end point of a pressure test based on the feedback; determine a decay and a hold duration of the pressure test based on the feedback, the start point, and the end point; determine a health index of the BOP stack based on the decay and the hold duration; and provide an output indicative of a condition of the BOP stack based on the health index.', '2.', 'The system of claim 1, wherein the one or more instructions are configured to determine one or more components of the plurality of components of the BOP stack being tested by the pressure test based on the position of the plurality of components of the BOP stack.', '3.', 'The system of claim 2, wherein the one or more instructions are configured to modify a target test configuration plan of the BOP stack when the health index exceeds a threshold value.', '4.', 'The system of claim 3, wherein the one or more instructions are configured to modify the target test configuration plan by performing a second pressure test that isolates a component of the one or more components to determine a second health index indicative of wear incurred by the component.', '5.', 'The system of claim 3, wherein the one or more instructions are configured to generate the target test configuration plan of the BOP health monitoring system based on a structure of the BOP stack, the plurality of components of the BOP stack, a flow path of pressurized fluid directed toward and away from the BOP stack, or any combination thereof.', '6.', 'The system of claim 5, wherein the target test configuration plan of the BOP health monitoring system is configured to minimize a total number of pressure tests performed to test each of the component of the plurality of components of the BOP stack.', '7.', 'The system of claim 6, wherein the one or more instructions are configured to eliminate pressure tests from the target test configuration plan that do not test any component of the plurality of components of the BOP stack.', '8.', 'The system of claim 5, wherein the one or more instructions are configured to generate a matrix for each pressure test of the target test configuration plan that identifies tested components of the plurality of components, non-tested components of the plurality of components, and extraneous components of the plurality of components for each pressure test of the target test configuration plan.', '9.', 'The system of claim 1, wherein the feedback from the sensor is indicative of the pressure within an annulus of the BOP stack.', '10.', 'The system of claim 1, wherein the one or more instructions are configured to determine the health index of the BOP stack via a comparison between the decay and a decay threshold, a comparison between the hold duration and a hold duration threshold, or both.\n\n\n\n\n\n\n11.', 'The system of claim 1, wherein the output indicative of a condition of the BOP stack based on the health index comprises suggested timing for performing maintenance on or performing troubleshooting of the BOP stack.', '12.', 'A system, comprising:\na blowout preventer (BOP) stack comprising one or more valves and a BOP;\na sensor configured to monitor a pressure within the BOP stack; and\na BOP health monitoring system comprising a controller having a tangible, machine readable-medium storing one or more instructions executable by a processor, wherein the one or more instructions are configured to: receive feedback from the sensor, wherein the feedback is indicative of a pressure within the BOP stack over time; determine a start point and an end point of a pressure test based on the feedback; determine a decay and a hold duration of the pressure test based on the feedback, the start point, and the end point; determine a health index of the BOP stack based on the decay and the hold duration; and provide an output indicative of a condition of the BOP stack based on the health index.\n\n\n\n\n\n\n13.', 'The system of claim 12, wherein the one or more instructions are configured to filter the feedback to reduce noise, erroneous data, or both.\n\n\n\n\n\n\n14.', 'The system of claim 12, wherein the one or more instructions are configured to interpolate the feedback to determine a local decay of the pressure test.', '15.', 'The system of claim 14, wherein the one or more instructions are configured to further determine the health index based on the local decay.', '16.', 'The system of claim 12, wherein the one or more instructions are configured to generate a target test configuration plan of the BOP health monitoring system based on a structure of the BOP stack, components included in the BOP stack, a flow path of pressurized fluid directed toward and away from the BOP stack, or any combination thereof.', '17.', 'A method, comprising:\nreceiving feedback from a sensor indicative of a pressure within a BOP stack over time;\ndetermining a start point and an end point of a pressure test based on the feedback;\ndetermining a decay and a hold duration of the pressure test based on the feedback, the start point, and the end point;\ndetermining a health index of the BOP stack based on the decay and the hold duration; and\nproviding an output indicative of a condition of the BOP stack based on the health index.', '18.', 'The method of claim 17, comprising receiving second feedback indicative of a position of a plurality of components of the BOP stack and determining one or more components of the plurality of components of the BOP stack that are being tested by the pressure test based on the second feedback.', '19.', 'The method of claim 18, comprising modifying a target test configuration plan of the BOP stack when the health index exceeds a threshold value.', '20.', 'The method of claim 19, wherein modifying the target test configuration plan comprises performing a second pressure test that isolates a component of the one or more components to determine a second health index indicative of wear incurred by the component.'] | ['FIG.', '1 is a graphical representation of an embodiment of results produced by an improved blowout preventer (BOP) health monitoring system, in accordance with an embodiment of the present disclosure;; FIG.', '2 is a graphical representation of an embodiment of results produced by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure;; FIGS.', '3A and 3B are graphical representations of embodiments of results produced by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure;; FIG. 4 is a schematic of an embodiment of the improved BOP health monitoring system included in a BOP system or stack, in accordance with an embodiment of the present disclosure;; FIG.', '5 is a table illustrating an example of an embodiment of a pressure test configuration for the BOP system of FIG.', '4, in accordance with an embodiment of the present disclosure;; FIG.', '6 is a flow chart of an embodiment of a decision tree executed by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure; and; FIG. 7 is a flow chart of an embodiment of a process performed by the improved BOP health monitoring system, in accordance with an embodiment of the present disclosure.; FIG.', '1 is a graphical representation of an embodiment of noisy pressure data (e.g., received by a controller of the BOP health monitoring system) with discontinuous pressure values and noise, where time 10 (e.g., measured in minutes) is represented by the x-axis, and pressure 12 (e.g., measured in bars) is represented by the y-axis.', 'As shown in FIG.', '1, points 14 indicate a start of a respective pressure test and points 16 indicate an end of the respective pressure tests.', 'A decay level may be determined based on a slope and/or a difference between points 14 and points 16 for each respective pressure test.', 'As is described in detail herein, the decay level of each pressure test may be used as a characteristic feature by the BOP health monitoring system.; FIGS.', '3A and 3B are graphical representations of embodiments of several health indices evaluated from different decays (e.g., global decays or local decays) and hold durations.', 'For example, FIG.', '3A represents health indices over different decays, HI(s).', 'FIG.', '3B represents health indices over different hold durations, HI(d).', 'In these examples, the decay threshold is 1.3 bar/minute (e.g., absolute values are considered) and the hold duration threshold is 12 minutes.', 'Any other decay threshold and/or hold duration threshold may be used as appropriate for the assessed BOP system.', 'If the absolute value of a decay becomes larger than the threshold, HI increases from zero.', 'If the hold duration is less than the threshold, then the corresponding HI also increases from zero.', 'In the example of FIGS.', '3A and 3B, the health index is chosen as zero (0) as the index for “healthy,” monotonically increasing to one-hundred (100) for “unhealthy.”', 'The choice of starting/ending indexes as well as direction (e.g. monotonically decreasing, increasing, etc.) is however arbitrary and may be amended as appropriate to the tested system.; FIG.', '5 is a table illustrating an example of an embodiment of the pressure test configuration for the BOP stack 30 of FIG.', '4 (e.g., a perpendicular position of a valve of the plurality of valves 64 indicates that the valve is in a closed position).', 'In the pressure test configuration shown in FIGS. 4 and 5, the annular BOP 56, the OB valve 86, the UOC valve 66, and the LOC valve 70 are tested via pressurized fluid supplied from the kill line 58.', 'In FIG.', '5, the abbreviated terms utilized above for the plurality of valves 62 are listed for reference.', 'The numerals “0” and “1” indicate the open and closed state for components, respectively.; FIG.', '6 is a flow chart of an embodiment of the drill-down decision tree algorithm 100.', 'To perform the drill-down decision tree algorithm 100, the BOP health monitoring system 32 may alter a target test configuration plan to determine which component of the BOP stack 30 may be worn or subject to a fault.', 'For instance, the BOP health monitoring system 32 may alter the target test configuration plan for the BOP stack 30 in order to perform additional tests that may isolate a component that may be worn or in need of maintenance.', 'As shown in the illustrated embodiment of FIG.', '6, the BOP health monitoring system 32 may perform a first pressure test 102 to begin the target test configuration plan of the BOP stack 30.', 'In some embodiments, the first pressure test 102 may test two components of the BOP stack 30 (e.g., the annular BOP 56 and one of the UOC valve 66, LOC valve 70, UOK valve 76, and/or the LOK valve 80).', 'After the pressure test results are determined, the BOP health monitoring system 32 may perform additional tests to isolate one of the two tested components (e.g., when the pressure test results indicate an unhealthy health index) and/or continue with a second pressure test 104 of the target test configuration plan that tests additional components of the BOP stack 30 (e.g., when the pressure test results indicate a healthy health index).', '; FIG. 7 is a block diagram of an embodiment of a process 120 performed by the BOP health monitoring system 32 to diagnose the health of the BOP stack 30.', 'The process 120 may be stored as one or more instructions on the memory 38 and configured to be executed by the processor 36 of the controller 34 of the BOP health monitoring system 32.', 'As shown in the illustrated embodiment of FIG. 7, at block 122, the processor 36 may receive feedback from the sensor 40 indicative of a pressure at a location within the BOP stack 30 over time.', 'At block 124, the processor 36 may identify individual pressure tests from the feedback and filter out any data that is not associated with a pressure test (e.g., data points between individual pressure tests, data points identified as noise, among others).', 'Accordingly, at block 126, the processor 36 identifies feature characteristics of the data.', 'As set forth above, the feature characteristics of the data may include a decay of a respective pressure test (e.g., a slope between a starting point of a pressure test and an ending point of a pressure test) and/or a hold duration of the respective pressure test (e.g., a duration at which an increased pressure was maintained in the BOP stack 30).', 'The processor 36 may then determine the health index based on the feature characteristics using Equations 1, 2, 3, and/or 4 set forth above, as shown at block 128.'] |
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US11078758 | Pressure control equipment systems and methods | Aug 9, 2018 | Nicolas Arteaga, Emmanuel Guilhamon, Erwan Olliero, Silvestre Meza, Vikas Rakhunde | Schlumberger Technology Corporation | International Preliminary Report on Patentability issued in International Patent application PCT/US2019/043131, dated Feb. 9, 2021, 8 pages. | 4825953; May 2, 1989; Wong et al.; 6164619; December 26, 2000; Wayne et al.; 6305471; October 23, 2001; Milloy; 6394460; May 28, 2002; Leggett et al.; 6676103; January 13, 2004; Wood; 6845958; January 25, 2005; Wood et al.; 7464765; December 16, 2008; Isaacks et al.; 7611120; November 3, 2009; Wood; 8443878; May 21, 2013; McCollin; 8567490; October 29, 2013; Van Winkle; 8770274; July 8, 2014; Van Winkle; 9644447; May 9, 2017; Joensen et al.; 20140158380; June 12, 2014; Varkey; 20140174727; June 26, 2014; Huizer; 20160003033; January 7, 2016; Coles et al.; 20180135366; May 17, 2018; Olsen; 20180355682; December 13, 2018; Pessin; 20190203575; July 4, 2019; Schlosser | 2499737; August 2013; GB; WO-2015104173; July 2015; WO; WO-2018026744; February 2018; WO | ['A system includes one or more processors configured to provide one or more control signals to cause supply of electric power from a power supply to one or more electric actuators.', 'The one or more electric actuators are configured to adjust one or more components of a cable pressure control equipment (PCE) stack.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'Natural resources, such as oil and gas, are used as fuel to power vehicles, heat homes, and generate electricity, in addition to a myriad of other uses.', 'Once a desired resource is discovered below the surface of the earth, drilling and production systems are often employed to access and extract the resource.', 'These systems may be located onshore or offshore depending on the location of a desired resource.', 'Such systems generally include a wellhead assembly through which the resource is extracted.', 'At various times, operations may be carried out to inspect or to service the well, for example.', 'During these operations, pressure control equipment is mounted above the wellhead to protect other surface equipment from surges in pressure within the wellbore or to carry out other supportive functions.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:\n \nFIG.', '1\n is a schematic diagram of an embodiment of an offshore system having a pressure control equipment (PCE) stack of the disclosure;\n \nFIG.', '2\n is a side view of an embodiment of the PCE stack of \nFIG.', '1\n;\n \nFIG.', '3\n is a schematic diagram of a control system and the PCE stack of \nFIG.', '1\n;\n \nFIG.', '4\n is a perspective view of a tool trap assembly that may be used in the PCE stack of \nFIG.', '1\n;\n \nFIG.', '5\n is a flow diagram of an embodiment of a method of operating the PCE stack of \nFIG.', '1\n based on a signal received from a leak sensor;\n \nFIG.', '6\n flow diagram of an embodiment of a method of operating the PCE stack of \nFIG.', '1\n based on a signal received from pressure sensors;\n \nFIG.', '7\n is flow diagram of an embodiment of a method of operating the PCE stack of \nFIG.', '1\n based on a signal received from a position sensor; and\n \nFIG.', '8\n is a perspective view of an embodiment of an automated crane system that may be utilized to assemble the PCE stack of \nFIG.', '1\n.', 'DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS\n \nOne or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only exemplary of the present disclosure.', 'Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'In the present disclosure, the terms wireline, Streamline™, slickline, coiled tubing, or other spoolable rod will all be considered a communication conduit and “conduit” or “wireline” or “cable” terms will be used in the following paragraphs as generally referring to any of these conduits used with the described pressure control equipment.', 'The present embodiments generally relate to wireline pressure control equipment (PCE) systems and methods.', 'Wireline PCE stacks are coupled to and/or positioned vertically above a wellhead during wireline operations in which a tool supported on a wireline is lowered through the wireline PCE stack to enable inspection and/or maintenance of a well, for example.', 'The wireline PCE stack includes components that seal about the wireline as it moves relative to the wireline PCE stack.', 'The wireline PCE stack may isolate the environment, as well as other surface equipment, from pressurized fluid within the well.', 'With some existing wireline PCE stacks, an operator may provide manual inputs to control a hydraulic actuator to adjust components of the wireline PCE stack.', 'However, such existing wireline PCE stacks may be large, inefficient, and/or expensive to operate due to the use of hydraulic actuators and/or due to involvement of the operator, for example.', 'Accordingly, the present embodiments include a control system (e.g., electronic control system) for the wireline PCE stack.', 'Additionally, one or more electric actuators may be controlled by the control system to adjust components of the wireline PCE stack.', 'The control system may control the electric actuators based on signals received from one or more sensors positioned about the wireline PCE stack, thereby enabling automated operation (e.g., automatic actuation based on signals received from one or more sensors) of the wireline PCE stack.', 'For example, a position sensor (e.g., any suitable sensor or switch, such as a pressure switch, capable of detecting the position of an object) may be located within a tool trap of the wireline PCE stack.', 'The position sensor may detect that a plate of the tool trap is in an open position due to passage of the tool through the tool trap, and the position sensor may provide a signal to a controller of the control system.', 'In response to receipt of the signal, the controller may adjust a winch to withdraw the wireline at a slower rate to block the winch from pulling the wireline out of the wireline PCE stack and/or to facilitate catching the tool with a tool catcher of the wireline PCE stack.', 'In certain embodiments, some or all of the actuators are electric actuators and/or the wireline PCE stack is devoid of other types of actuators (e.g., hydraulic or pneumatic).', 'Compared to these other types of actuators, the disclosed configuration may advantageously enable faster actuation times (e.g., faster opening and closing times) and eliminate temperature sensitivity due to use of hydraulic fluids.', 'Furthermore, electric actuators may generally be lighter and smaller, and thus may advantageously enable simplified maintenance, transportation, and installation.', 'The use of electric actuators is particularly useful in combination with the sensors and other automated control features disclosed herein, as the entire system may then be electric and run on electric power.', 'However, while the present embodiments relate to a wireline PCE stack that includes electric actuators controlled via the control system to facilitate discussion, it should be appreciated that an operator may additionally or alternatively provide manual inputs to control one or more of the electric actuators to adjust components of the wireline PCE stack in the manner disclosed herein and/or the control system may be used with other types of actuators, such as pneumatic or hydraulic actuators.', 'For example, in response to detection of the tool passing through the tool trap, the control system may provide an indication (e.g., visual or audible alarm) and/or instructions (e.g., via a display) to the operator to adjust the winch, and the operator may then provide a manual input to control one or more actuators to adjust the winch.', 'With the foregoing in mind, \nFIG.', '1\n is a schematic diagram of an embodiment of an offshore system \n10\n.', 'The offshore system \n10\n includes a wellhead \n12\n, which is coupled to a mineral deposit \n14\n via a wellbore \n16\n.', 'The wellhead \n12\n may include any of a variety of other components such as a spool, a hanger, and a “Christmas” tree.', 'In the illustrated embodiment, a wireline pressure control equipment (PCE) stack \n18\n (e.g., cable PCE stack) is coupled to the wellhead \n12\n to facilitate wireline operations, which are carried out by lowering a conduit \n20\n (e.g., communication conduit, wireline, slickline, spoolable rod, or coiled tubing) and a tool \n22\n (e.g., configured to collect data about the mineral deposit \n14\n and/or the wellbore \n16\n) through a bore \n24\n defined by the wireline PCE stack \n18\n, through a bore \n26\n defined by the wellhead \n12\n, and into the wellbore \n16\n.', 'As shown, a control system \n28\n (e.g., an electronic control system) is provided to control and provide power to various components of the wireline PCE stack \n18\n.', 'For example, the control system \n28\n may control one or more electric actuators based on signals received from one or more sensors positioned about the wireline PCE stack \n18\n.', 'FIG.', '2\n is a side view of an embodiment of the wireline PCE stack \n18\n that may be used in the offshore system \n10\n of \nFIG.', '1\n.', 'The wireline PCE stack \n18\n includes various components that enable the wireline PCE stack \n18\n to seal about the conduit \n20\n as it moves relative to the wireline PCE stack \n18\n.', 'Thus, the wireline PCE stack \n18\n may isolate the environment, as well as other surface equipment, from pressurized fluid within the wellbore \n16\n (\nFIG.', '1\n).', 'In the illustrated embodiment, the wireline PCE stack \n18\n includes a stuffing box \n30\n, a tool catcher \n32\n, a lubricator section \n34\n, a tool trap \n36\n, a blowout preventer (BOP) stack \n38\n (e.g., wireline valve stack), and a connector \n40\n to couple the wireline PCE stack \n18\n to the wellhead \n12\n (\nFIG.', '1\n) or other structure.', 'These components are annular structures stacked vertically with respect to one another (e.g., coaxial) to enable the conduit \n20\n to extend through the wireline PCE stack \n18\n (e.g., from a first end \n42\n to a second end \n44\n of the wireline PCE stack \n18\n) into the wellhead \n12\n.', 'As shown, the conduit \n20\n extends from the first end \n42\n of the wireline PCE stack \n18\n and over a sheave \n46\n to a winch \n48\n, and rotation of the winch \n48\n (e.g., a drum or spool of the winch \n48\n) raises and lowers the conduit \n20\n with the tool \n22\n through the wireline PCE stack \n18\n.', 'It should be appreciated that the wireline PCE stack \n18\n may include various other components (e.g., cable tractoring wheels to pull the conduit \n20\n through the stuffing box \n30\n, a pump-in sub to enable fluid injection).', 'In some embodiments, the wireline PCE stack \n18\n is devoid of common components (e.g., grease injector system mounted on and/or vertically above the lubricator section \n34\n).', 'The stuffing box \n30\n is configured to seal against the conduit \n20\n (e.g., to seal an annular space about the conduit \n20\n) to block a flow of fluid from the bore \n24\n (\nFIG.', '1\n) vertically above the stuffing box \n30\n.', 'In the illustrated embodiment, the stuffing box \n30\n includes a housing supporting an annular packing material or other compressible annular structure that forms a seal against the conduit \n20\n.', 'In some embodiments, movement of a lever \n50\n (e.g. bar or other driving component), adjusts a compressive force (e.g., in a vertical direction) on the annular packing material to adjust the seal against the conduit \n20\n.', 'For example, movement of the lever \n50\n in one direction may squeeze the annular packing material vertically, thereby driving the annular packing material radially (e.g., toward the conduit \n20\n) to increase a surface area and/or an effectiveness of the seal against the conduit \n20\n.', 'The tool catcher \n32\n is configured to engage or catch the tool \n22\n to block the tool \n22\n from being withdrawn vertically above the tool catcher \n32\n and/or to block the tool \n22\n from falling vertically into the wellbore \n16\n.', 'In the illustrated embodiment, the tool catcher \n32\n includes a plate (e.g., collar or flapper) that adjusts from an open position in which the plate enables the tool \n22\n to move across the tool catcher \n32\n and a closed position in which the plate engages the tool \n22\n, thereby blocking movement of the tool \n22\n across the tool catcher \n32\n.', 'The lubricator section \n34\n may include one or more annular pipes joined to one another, and the lubricator section \n34\n may support or surround the tool \n22\n while it is withdrawn from the wellbore \n16\n.', 'The tool trap \n36\n is configured to block the tool \n22\n from falling vertically into the wellbore \n16\n.', 'In the illustrated embodiment, the tool trap \n36\n includes a plate (e.g., collar or flapper) that adjusts from an open position in which the plate enables the tool \n22\n to move across the tool trap \n36\n and a closed position in which the plate blocks the tool \n22\n from falling vertically into the wellbore \n16\n.', 'In some embodiments, the plate is biased (e.g., via a biasing member, such as a spring) toward the closed position.', 'During withdrawal of the tool \n22\n from the wellbore \n16\n, the tool \n22\n may contact and exert an upward force on the plate to drive the plate to the open position, and the biasing member may return the plate to the closed position after the tool \n22\n moves vertically above the tool trap \n36\n.', 'The BOP stack \n38\n may include one or more BOPs (e.g., wireline valves) that are configured to seal the bore \n24\n.', 'Each BOP may include rams that are configured to move toward one another to seal the bore \n24\n.', 'For example, in some embodiments, one BOP may be a shear ram that is configured to shear the conduit \n20\n and to seal the bore \n24\n, and one BOP may be a pipe ram that is configured to seal about the wireline \n36\n.', 'In certain embodiments, one or more ports \n52\n (e.g., bleed off ports) may be provided along the wireline PCE stack \n18\n, such as proximate to an upper end of the lubricator section \n34\n.', 'For example, in the illustrated embodiment, the one or more ports include a port \n52\n positioned between the tool catcher \n32\n and the stuffing box \n30\n.', 'The port \n52\n fluidly couples a bore of the lubricator section \n34\n to a drain conduit \n54\n (e.g., pipe or hose), which may extend to any suitable fluid container, for example.', 'As discussed in more detail below, a valve (e.g., bleed off port valve) may be actuated to adjust fluid flow between the bore of the lubricator section \n34\n and the drain conduit \n54\n via the port \n52\n.', 'The port \n52\n may be utilized to bleed off air trapped within the lubricator section \n34\n.', 'As discussed in more detail below, some or all of the various components of the wireline PCE stack \n18\n may be adjusted via electric actuators that are controlled by control signals received from the control system \n28\n.', 'In some embodiments, the wireline PCE stack \n18\n is devoid of other types of actuators (e.g., hydraulic or pneumatic actuators).', 'Furthermore, one or more sensors may be positioned about the wireline PCE stack \n18\n, the one or more sensors may provide signals indicative of one or more characteristics of the wireline PCE stack \n18\n to the control system \n28\n, and the control system \n28\n may generate the control signals based on the signals received from the one or more sensors.', 'FIG.', '3\n is a schematic diagram of the control system \n28\n and the wireline PCE stack \n18\n.', 'As shown, a stuffing box actuator \n60\n is provided to adjust the lever \n50\n (\nFIG.', '2\n) of the stuffing box \n30\n, thereby adjusting the seal formed against the conduit \n20\n (\nFIG. 2\n).', 'A bleed off port valve actuator \n61\n is provided to adjust a valve \n63\n (e.g., bleed off port valve) between an open position and a closed position to adjust fluid flow between the bore of the lubricator section \n34\n and the bleed off port \n52\n (\nFIG.', '2\n).', 'A tool catcher actuator \n62\n is provided to adjust the plate of the tool catcher \n32\n between the open position and the closed position.', 'A tool trap actuator \n64\n is provided to adjust the plate of the tool trap \n36\n between the open position and the closed position.', 'A BOP actuator \n66\n (e.g., wireline actuator) is provided for the BOP assembly \n38\n (e.g., one or more respective actuators \n66\n may be provided for each BOP in the BOP assembly \n38\n).', 'One or more of the actuators \n60\n, \n61\n, \n62\n, \n64\n, \n66\n may be electric actuators that are configured to receive and respond to control signals (e.g., electric voltage or current) from a controller \n68\n of the control system \n28\n.', 'The winch \n48\n may also be configured to receive and respond to control signals from the controller \n68\n of the control system \n28\n.', 'As shown, the controller \n68\n includes a processor \n70\n, a memory \n72\n, a user interface \n74\n, and a power supply \n76\n (e.g., electric power supply).', 'One or more sensors may be positioned about the wireline PCE stack \n18\n to facilitate the techniques disclosed herein.', 'As shown, a leak sensor \n78\n is positioned proximate to the stuffing box \n30\n (e.g., vertically above the stuffing box or within the stuffing box \n30\n) to detect the presence of fluid.', 'In one embodiment, the leak sensor \n78\n may be an ultrasonic sensor (e.g., acoustic sensor) configured to detect sound waves generated as the conduit \n20\n contacts and passes through the packing material of the stuffing box \n30\n.', 'The leak sensor \n78\n may send a signal indicative of the sound waves to the controller \n68\n, and the processor \n70\n may process the signal to determine whether a leak exists (e.g., fluid is present at or vertically above the packing material and/or at or vertically above the intended location of the seal formed against the conduit \n20\n).', 'In some embodiments, the processor \n70\n may process the signal to determine a characteristic (e.g., frequency) of the sound waves and then determine whether a leak exists based on the characteristic.', 'More particularly, the processor \n70\n may compare the characteristic to a known characteristic (e.g., known or predetermined signature, pattern, or number based on modeled data, empirical data from many stuffing boxes \n30\n, or prior data from the same stuffing box \n30\n), and then determine whether a leak exists based on the comparison.', 'For example, if the characteristic varies from the known characteristic by more than a threshold amount or percentage (e.g., 5, 10, or 15 percent) or fails to match a signature, the processor \n70\n may determine that a leak exists.', 'In response to determining that the leak exists, the processor \n70\n may provide a control signal to the actuator \n60\n to tighten the seal against the conduit \n20\n (e.g., by adjusting the lever \n50\n).', 'The processor \n70\n may continue to control the actuator \n60\n to tighten the seal until feedback from the leak sensor \n78\n indicates that an acceptable amount of fluid (e.g., no fluid) is present and that the leak is repaired.', 'In this manner, the control system \n28\n may automatically control the stuffing box \n30\n based on signals received from the leak sensor \n78\n.', 'If the lever \n50\n has been adjusted to a limit position (e.g., the lever \n50\n cannot be further adjusted to tighten the seal against the conduit \n20\n) and the leak is still detected, the processor \n70\n may provide a control signal to stop the winch \n48\n to stop movement of the conduit \n20\n within the wireline PCE stack \n18\n and then a control signal to one or more actuators \n66\n to close rams of one or more BOPs of the BOP stack \n38\n, thereby sealing the bore \n24\n of the wireline PCE stack \n18\n via the BOP stack \n38\n.', 'It should be appreciated that the leak sensor \n78\n may have any of a variety of configurations that enable the leak sensor \n78\n to detect a leak or the presence of fluid.', 'In some embodiments, the leak sensor \n78\n may include a camera that provides images to the processor \n70\n, which may process the images via image recognition or template matching techniques to determine whether a leak exists, for example.', 'In some embodiments, the leak sensor \n78\n may include a conductive element that forms an open circuit in the absence of fluid, and that forms a closed circuit in the presence of fluid (e.g., when the fluid connects two open ends of the conductive element).', 'In such cases, the processor \n70\n may receive a signal indicative of the status of the circuit (e.g., a resistance value indicative of whether the circuit is open or closed) from the leak sensor \n78\n and may determine whether a leak exists based on the status of the circuit.', 'As shown in \nFIG.', '3\n, a first pressure sensor \n80\n is positioned vertically above the BOP stack \n38\n and a second pressure sensor \n82\n is positioned vertically below the BOP stack \n38\n.', 'More particularly, the first pressure sensor \n80\n is configured to detect a first pressure within the bore \n24\n vertically above the BOP stack \n38\n (e.g., vertically above an uppermost ram of the BOP stack \n38\n), and the second pressure sensor \n82\n is configured to detect a second pressure within the bore \n24\n vertically below the BOP stack \n38\n (e.g., vertically below a lowermost ram of the BOP stack \n38\n).', 'The first and second pressure measurements may be used to evaluate the seal formed by the BOP stack \n38\n.', 'For example, rams of one or more BOPs of the BOP stack \n38\n may be actuated from the open position to the closed position to the seal the bore \n24\n at various times (e.g., when the leak sensor \n78\n indicates a leak that cannot be stopped by the stuffing box \n30\n, upon completion of wireline operations, or upon a sudden increase in pressure in the wellbore \n16\n).', 'While the rams of one or more BOPs of the BOP stack \n38\n are in the closed position, the first pressure sensor \n80\n and the second pressure sensor \n82\n may send respective signals indicative of the first pressure and the second pressure to the processor \n70\n, and the processor \n70\n may process the respective signals to determine whether the rams of the one or more BOPs of the BOP stack \n38\n seal the bore \n24\n.', 'In some embodiments, the processor \n70\n may process the respective signals to determine the pressure at each location (e.g., the first pressure vertically above and the second pressure vertically below the BOP stack \n38\n) and then determine whether the rams of the one or more BOPs seal the bore \n24\n based on the pressure at each location.', 'More particularly, the processor \n70\n may compare the first pressure to the second pressure, and then determine the whether the seal is adequate based on the comparison.', 'For example, if the first pressure and the second pressure are equal or substantially equal (e.g., within 5, 10, 15, 20, or 25 percent of one another), the processor \n70\n may determine that the seal is inadequate.', 'If the first pressure is less than or substantially less than the second pressure (e.g., less than or equal to 5, 10, 15, 20, or 25 percent of the second pressure), the processor \n70\n may determine that the seal is adequate.', 'In response to a determination that the seal is inadequate, the processor \n70\n may provide a control signal to one or more actuators \n66\n to adjust the rams of one or more other BOPs of the BOP stack \n38\n to the closed position.', 'The first pressure and the second pressure may then be compared to one another in the manner set forth above to determine whether the seal is adequate.', 'It should be appreciated that the pressure within the bore \n24\n vertically above the BOP stack \n38\n may be vented (e.g., via a pump-in sub) after moving the rams to the closed position and prior to comparing the first pressure to the second pressure to assess the seal formed by the rams of the one or more BOPs of the BOP stack \n38\n.', 'In some embodiments, the pressure sensors \n80\n, \n82\n may be configured to monitor pressure while the rams of the one or more BOPs of the BOP stack \n38\n are in an open position, and the tool catcher actuator \n62\n may be controlled to adjust the tool catcher \n32\n and/or the winch \n48\n may be controlled to lower the tool \n22\n (\nFIG.', '2\n) through the wireline PCE stack \n18\n in response to detecting fluid pressure below a threshold pressure, for example.', 'As shown in \nFIG.', '3\n, a position sensor \n84\n (e.g., a tool trap sensor) may be located within the tool trap \n36\n of the wireline PCE stack \n18\n.', 'FIG.', '4\n illustrates a side view of an embodiment of the tool trap \n36\n to facilitate discussion.', 'In the disclosed embodiments, the position sensor \n84\n may be positioned within the tool trap \n36\n to detect that a plate \n86\n of the tool trap \n36\n is in an open position \n90\n (e.g., a fully open position or a partially open position) due to passage of the tool \n22\n through the tool trap \n36\n.', 'In operation, the plate \n86\n may be actuated via the tool trap actuator \n64\n to move from a closed position \n88\n in which the plate \n86\n is in the bore \n24\n to block the tool \n22\n from falling into the wellbore \n16\n (\nFIG.', '1\n) to the open position \n90\n in which the plate \n86\n is withdrawn from the bore \n24\n to enable the tool \n22\n to be lowered into the wellbore \n16\n.', 'The plate \n86\n may return to the closed position \n88\n (e.g., via a biasing member) after the tool \n22\n is lowered into the wellbore \n16\n.', 'During withdrawal of the tool \n22\n from the wellbore \n16\n, the tool \n22\n may contact and exert an upward force on the plate \n86\n to drive the plate \n86\n to the open position \n90\n, and the plate \n86\n may return to the closed position \n88\n (e.g., via the biasing member) after the tool \n22\n moves vertically above the plate \n86\n.', 'Thus, by monitoring the position of the plate \n86\n of the tool trap \n36\n, the control system \n28\n may also indirectly detect the position of the tool \n22\n (e.g., relative to the tool trap \n36\n, such as vertically below or vertically above the tool trap \n26\n).', 'More particularly, the position sensor \n84\n may send a signal indicative of the position of the plate \n86\n of the tool trap \n36\n to the controller \n68\n, and the processor \n70\n may process the signal to determine whether the plate \n86\n is being driven (e.g., is or was driven) to the open position \n90\n by the tool \n22\n.', 'The processor \n70\n may also consider signals that indicate that the tool \n22\n is being withdrawn via the winch \n48\n and/or that the tool trap actuator \n64\n is not adjusting the plate \n86\n to the open position \n90\n.', 'For example, the processor \n70\n may determine that the plate \n86\n is being driven to the open position \n90\n by the tool \n22\n if the plate \n86\n moves toward or reaches the open position \n90\n while the tool \n22\n is being withdrawn.', 'In response to determining that the plate \n86\n is being driven to the open position \n90\n by the tool \n22\n, the processor \n70\n may provide a control signal to a winch actuator (e.g., motor or other drive source) of the winch \n48\n to adjust (e.g., slow or reduce) the rate at which the conduit \n20\n and the tool \n22\n are withdrawn from the wireline PCE stack \n18\n.', 'Such techniques may block the winch \n48\n from pulling the conduit \n20\n out of the wireline PCE stack \n18\n and/or may facilitate catching the tool \n22\n with the tool catcher \n32\n, such as by reducing the force with which the tool \n22\n impacts the plate of the tool catcher \n32\n, for example.', 'It should be appreciated that the position sensor \n84\n may be any suitable sensor or switch, such as a pressure switch, capable of detecting the position of the plate \n86\n of the tool trap \n36\n and/or motion of the plate \n86\n within the tool trap \n36\n.', 'It should also be appreciated that optical sensors, cameras, or acoustic sensors may be utilized to detect the position of the plate \n86\n of the tool trap \n36\n.', 'For example, optical sensors or acoustic sensors may detect an interruption in light or sound waves within the tool trap \n26\n due to the plate \n86\n being in the open position \n90\n.', 'The position sensor \n84\n may be mounted to or supported by a housing \n94\n (e.g., an annular wall of an annular housing), as shown, or the position sensor \n84\n may be mounted to or supported on the plate \n86\n.', 'Furthermore, the position sensor \n84\n may additionally or alternatively be configured to directly monitor the position of the tool \n22\n or to detect the tool \n22\n as it passes through the tool trap \n36\n.', 'The tool trap \n36\n illustrated in \nFIG.', '4\n includes one plate \n86\n supported on a pivot rod \n92\n that is driven to rotate via the tool trap actuator \n64\n.', 'However, it should be appreciated that the plate \n86\n may move into and out of the bore \n24\n without rotation and/or the tool trap \n36\n may include multiple plates \n86\n (e.g., two opposed plates).', 'The controller \n68\n may be configured to provide various outputs or indications (e.g., audible alarms, text messages) to the operator and/or may allow the operator to provide various inputs to control the various components of the wireline PCE stack \n18\n.', 'For example, the controller \n68\n may instruct the user interface \n74\n to display the data collected by the leak sensor \n78\n, the first pressure sensor \n80\n, the second pressure sensor \n82\n, and/or the position sensor \n84\n.', 'Additionally or alternatively, the controller \n68\n may instruct the user interface \n74\n to display information indicative of the determined information, such as whether a leak at the leak sensor \n82\n exists, whether the seal formed by the BOP stack \n38\n is adequate, and/or whether the tool \n22\n has moved across the tool trap \n36\n during withdrawal of the tool \n22\n through the wireline PCE stack \n18\n.', 'Additionally or alternatively, the controller \n68\n may instruct the user interface \n74\n to display the actions or responses instructed by the controller \n68\n, such as the response to control the stuffing box actuator \n60\n to adjust the lever \n50\n to adjust the seal at the stuffing box \n30\n, the adjustment of rams of another BOP of the BOP stack \n38\n to the closed position, and/or the adjustment of the winch \n48\n following detection of the tool \n22\n within the tool trap \n36\n.', 'The user interface \n74\n may also enable the operator to control various components of the wireline PCE stack \n18\n, such as in the various ways disclosed herein.', 'For example, the operator may provide an input that causes the controller \n68\n to adjust the stuffing box actuator \n60\n to adjust the lever \n50\n to adjust the seal at the stuffing box \n30\n.', 'The controller \n68\n also includes the power supply \n76\n that provides power (e.g., electric power) to operate the controller \n68\n, as well as to provide the control signals (e.g., electric voltage or current) to the actuators \n60\n, \n62\n, \n64\n, \n66\n to actuate the various components of the wireline PCE stack \n18\n.', 'The processor \n70\n may provide power control signals to instruct and/or to regulate the supply of the electric power from the power supply \n76\n to the actuators \n60\n, \n62\n, \n64\n, \n66\n.', 'For example, the processor \n70\n may provide the power control signal to cause the power supply \n76\n to direct an appropriate amount of electric power to one of the actuators \n60\n, \n62\n, \n64\n, \n66\n at a particular time.', 'It should be appreciated that the controller \n68\n may include various other components, such as a communication device that is capable of communicating the data or the other information to various other devices (e.g., a remote computing system).', 'It should also be appreciated that the processor \n70\n may include one or more processors that may be used to execute instructions or software.', 'The memory \n72\n may include a volatile memory, such as random access memory (RAM), and/or a nonvolatile memory, such as ROM.', 'The memory \n72\n may store a variety of information and may be used for various purposes.', 'For example, the memory \n72\n may store processor-executable instructions (e.g., firmware or software) for the processor \n70\n to execute, such as instructions for processing the signals from the one or more sensors to determine characteristics of the wireline PCE stack \n18\n.', 'As noted above, the wireline PCE stack \n18\n may include the port \n52\n (\nFIG.', '2\n) and associated components, such as the valve \n63\n and the actuator \n61\n, that facilitate operations to bleed off trapped air within the wireline PCE stack \n18\n (e.g., within the bore of the lubricator section \n34\n).', 'In some embodiments, a first flow sensor \n79\n that is configured to detect fluid flow (e.g., a fluid flow rate) proximate to or within the port \n52\n (\nFIG.', '2\n) may be used with the wireline PCE stack \n18\n.', 'During operation, air may become trapped within the wireline PCE stack \n18\n.', 'This trapped air may be detected by one or more sensors within the wireline PCE stack \n18\n or via other techniques.', 'When trapped air is detected (e.g., by the processor \n70\n, such as based on measurements obtained by one or more sensors), the port \n52\n, the bleed off bleed off port valve actuator \n61\n, and the valve \n63\n may be utilized to bleed off the trapped air.', 'For example, upon detection of trapped air, the processor \n70\n may provide a control signal to the actuator \n61\n to adjust the valve \n63\n to the open position.', 'The processor \n70\n may also provide a control signal to one or more actuators \n66\n to adjust the rams of one or more BOPs of the BOP stack \n38\n to the closed position, and the processor \n70\n may further provide a control signal to a pump or other device to provide fluid into the lubricator section \n34\n, such as through another port in the wireline PCE stack \n18\n.', 'Then, once the lubricator section \n34\n fills with the fluid, the fluid will flow through the port \n52\n and will be detectable by the first flow sensor \n79\n.', 'The first flow sensor \n79\n may send a signal indicative of the fluid to the controller \n68\n, and the processor \n70\n may process the signal to determine whether the fluid is present at the port \n52\n [\nFIG.', '2\n]).', 'In response to determining that the fluid is present at the port \n52\n and/or that the trapped air has been released through the port \n52\n, the processor \n70\n may provide a control signal to the bleed off port valve actuator \n61\n to adjust the valve \n63\n to the closed position, the processor \n70\n may provide a control signal to one or more actuators \n66\n to adjust the rams of one or more BOPs of the BOP stack \n38\n to the open position, and/or the processor \n70\n may provide a control signal to the actuator \n60\n to tighten the seal of the stuffing box \n30\n against the conduit \n20\n (e.g., by adjusting the lever \n50\n) to resume other types of operations.', 'In some embodiments, a second flow sensor \n81\n may be provided proximate to the BOP stack \n38\n, such as vertically above the BOP stack \n38\n.', 'In some embodiments, the second flow sensor \n81\n may be integrated into or supported within the BOP stack \n38\n.', 'The second flow sensor \n81\n may measure fluid flow through the BOP stack \n38\n, such as fluid flow of fluid intentionally routed through a manifold of the BOP stack \n38\n to balance pressure across a closed ram and/or fluid flow of fluid through the bore \n24\n of the BOP stack \n38\n.', 'These fluid flow measurements may be used to confirm flow of the intentionally routed fluid and/or to evaluate the seal formed by the BOP stack \n38\n.', 'For example, rams of one or more BOPs of the BOP stack \n38\n may be actuated from the open position to the closed position to the seal the bore \n24\n at various times (e.g., when the leak sensor \n78\n indicates a leak that cannot be stopped by the stuffing box \n30\n, upon completion of wireline operations, or upon a sudden increase in pressure in the wellbore \n16\n).', 'While the rams of one or more BOPs of the BOP stack \n38\n are in the closed position, the second fluid sensor \n81\n may send a signal indicative of the fluid flow to the processor \n70\n, and the processor \n70\n may process the signal to determine whether the rams of the one or more BOPs of the BOP stack \n38\n seal the bore \n24\n.', 'As noted above with respect the discussion of the pressure sensors \n82\n, \n84\n, in response to a determination that the seal is inadequate, the processor \n70\n may provide a control signal to one or more actuators \n66\n to adjust the rams of one or more other BOPs of the BOP stack \n38\n to the closed position.', 'Similarly, fluid flow measurements obtained by the first fluid flow sensor \n79\n may be utilized to detect fluid flow vertically above the BOP stack \n38\n, and thus, may be used to determine whether the rams of the one or more BOPs of the BOP stack \n38\n seal the bore \n24\n and/or to facilitate adjustment of additional rams to the closed position to seal the bore \n24\n.', 'It should be appreciated that flow sensors may be provided to detect fluid flow at various locations the wireline PCE stack \n18\n, such as one or more additional flow sensors at the port \n52\n, one or more flow sensors vertically below the BOP stack \n38\n, and/or one or more additional flow sensors vertically above the BOP stack \n38\n and/or within the BOP stack \n38\n to carry out the techniques disclosed herein.', 'Furthermore, the flow sensors \n79\n, \n81\n may be used to facilitate various other operations.', 'For example, a flow sensor may be positioned proximate to the stuffing box \n30\n (e.g., vertically above the stuffing box or within the stuffing box \n30\n) to detect fluid flow across the stuffing box \n30\n, and the fluid flow measurements obtained by the flow sensor may be utilized to trigger various actions similar to those described above with respect to the leak sensor (e.g., determine whether a leak exists and control the actuator \n60\n to tighten the seal of the stuffing box \n30\n).', 'In some embodiments, the flow sensors (e.g., the flow sensors \n79\n, \n81\n or other flow sensors) may be configured to monitor flow while the rams of the one or more BOPs of the BOP stack \n38\n are in an open position, and the tool catcher actuator \n62\n may be controlled to adjust the tool catcher \n32\n and/or the winch \n48\n may be controlled to lower the tool \n22\n (\nFIG.', '2\n) through the wireline PCE stack \n18\n in response to detecting fluid flow below a threshold flow rate (e.g., no flow), for example.', 'The flow sensors disclosed herein may be any suitable type of flow sensors, such as ultrasonic flow sensors, for example.', 'It should be appreciated that flow sensors disclosed herein may be capable of distinguishing between air and fluid, thereby facilitating determination and control steps performed by the processor \n70\n.', 'FIGS.', '5-7\n are flow diagrams of embodiments of methods of operating the wireline PCE stack \n18\n.', 'The methods include non-limiting examples of using the one or more processors to provide one or more control signals to cause supply of electric power from the power supply to one or more electric actuators that are configured to adjust one or more components of the wireline PCE stack.', 'The methods disclosed herein includes various steps represented by blocks.', 'It should be noted that at least some steps of the methods may be performed as an automated procedure by a system, such as the control system \n28\n.', 'Although the flow charts illustrate the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Additionally, steps may be added to or omitted from of the methods.', 'Further, certain steps or portions of the methods may be performed by separate devices.', 'For example, a first portion of each method may be performed by the processor \n70\n, while a second portion of the methods may be performed by another processor or an operator.', 'In addition, insofar as steps of the methods disclosed herein are applied to received signals, it should be understood that the received signals may be raw signals or processed signals.', 'That is, the methods may be applied to an output of the received signals.', 'FIG.', '5\n is a flow diagram of an embodiment of a method \n100\n of operating the wireline PCE stack \n18\n based on a signal received from the leak sensor \n78\n.', 'As shown, in step \n102\n, the processor \n70\n may receive a signal from the leak sensor \n78\n positioned proximate to the stuffing box \n30\n of the wireline PCE stack \n18\n.', 'In step \n104\n, the processor \n70\n may determine whether the signal indicates a leak.', 'For example, the leak sensor \n78\n may be an ultrasonic sensor and the signal may be indicative of sound waves generated as the conduit \n20\n passes through the packing material of the stuffing box \n40\n.', 'The processor \n70\n may determine a characteristic of the sound waves and then may compare the characteristic to a known characteristic to determine whether the signal indicates a leak.', 'In response to determining that no leak exists, the method \n100\n may return to step \n102\n.', 'In response to determining that a leak exists, the method \n100\n may proceed to step \n106\n.', 'In step \n106\n, the processor \n70\n may determine whether the packing material of the stuffing box \n30\n is in a limit position (e.g., based on whether the lever \n50\n of the stuffing box \n30\n is in a limit position).', 'For example, because the stuffing box actuator \n60\n that adjusts the lever \n50\n is controlled via the controller \n68\n, the processor \n70\n may readily access or request information indicative of the position of the lever \n50\n, such as from the memory \n72\n or via a feedback signal indicative of the position of the lever \n50\n from the stuffing box actuator \n62\n or other position sensor configured to monitor the position of the lever \n50\n, for example.', 'In response to determining that the packing material and/or the lever \n50\n is in the limit position and that the leak exists, the method \n100\n may proceed to step \n108\n.', 'In step \n108\n, the processor \n70\n may provide a control signal to the BOP actuator \n66\n to adjust rams of a BOP of the BOP stack \n38\n to the closed position to seal the bore \n24\n.', 'The processor \n70\n may provide a control signal to the winch \n48\n to stop movement of the conduit \n20\n prior to step \n108\n.', 'In response to determining that the packing material and/or lever \n50\n is not in the limit position \n50\n and that the leak exists, the method \n100\n may proceed to step \n110\n.', 'In step \n110\n, the processor \n70\n may provide a control signal to the stuffing box actuator \n60\n to adjust the lever \n50\n to tighten the seal between the packing material of the stuffing box \n30\n and the conduit \n20\n.', 'It should be appreciated that the method \n100\n may return to step \n102\n to continue monitoring for leaks following step \n108\n or \n110\n.', 'As noted above, various leak sensors may be utilized to enable the disclosed techniques.', 'Because the other mechanisms (e.g., other than the lever \n50\n) may be utilized to tighten the seal formed by the packing material, it should be appreciated that the method may more generally be carried out based on information indicative of whether the packing material is in the limit position (e.g., cannot be tightened or compressed further to improve the seal).', 'FIG.', '6\n is a flow diagram of an embodiment of a method \n120\n of operating the wireline PCE stack \n18\n based on signals received from the first pressure sensor \n80\n and the second pressure sensor \n82\n while rams of a BOP of the BOP stack \n28\n are in a closed position.', 'As shown, in step \n122\n, the processor \n70\n may receive a first signal indicative of a first pressure from the first pressure sensor \n80\n positioned vertically above a ram of the BOP stack \n38\n of the wireline PCE stack \n18\n.', 'In step \n124\n, the processor \n70\n may receive a second signal indicative of a second pressure from the second pressure sensor \n82\n positioned vertically below the ram of the BOP stack \n38\n of the wireline PCE stack \n18\n.', 'In step \n126\n, the processor \n70\n may determine whether the first signal and the second signal indicate a leak across the rams of the BOP stack \n38\n.', 'In some embodiments, the processor \n70\n may compare the first pressure to the second pressure, and then determine the whether the seal formed by the ram of the BOP stack \n38\n is adequate based on the comparison.', 'For example, if the first pressure and the second pressure are equal or substantially equal, the processor \n70\n may determine that the seal is inadequate.', 'If the first pressure is less than or substantially less than the second pressure, the processor \n70\n may determine that the seal is adequate.', 'In response to determining that the seal is adequate, the method \n120\n may return to step \n122\n.', 'In response to determining that the seal is inadequate, the method \n120\n may proceed to step \n128\n.', 'In step \n128\n, the processor \n70\n may provide a control signal to the BOP actuator \n66\n to adjust other rams of the BOP stack \n38\n to the closed position to seal the bore \n24\n.', 'It should be appreciated that the method \n120\n may return to step \n122\n to continue monitoring the seal formed by the BOP stack \n38\n following step \n128\n.', 'FIG.', '7\n is a flow diagram of an embodiment of a method \n130\n of operating the wireline PCE stack \n18\n based on signals received from the position sensor \n84\n of the tool trap \n36\n.', 'As shown, in step \n132\n, the processor \n70\n may receive a signal indicative of a position of the plate \n86\n of the tool trap \n36\n from the position sensor \n84\n.', 'In step \n134\n, the processor \n70\n may determine whether the signal indicates that the plate \n86\n of the tool trap \n36\n is being driven (e.g., is or was driven) to the open position \n90\n by the tool \n22\n.', 'To assist in the determination, the processor \n70\n may also consider signals that indicate that the tool \n22\n is being withdrawn via the winch \n48\n and/or that the tool trap actuator \n64\n is not adjusting the plate \n86\n to the open position \n90\n.', 'In response to determining that the plate \n86\n of the tool trap \n36\n is in the closed position \n100\n or is in the open position \n90\n via the tool trap actuator \n64\n, for example, the method \n130\n may return to step \n132\n.', 'In response to determining that the plate \n86\n of the tool trap \n36\n is being driven to the open position \n90\n by the tool \n22\n, the method \n130\n may proceed to step \n136\n.', 'In step \n136\n, the processor \n70\n may provide a control signal to the winch \n48\n to adjust (e.g., reduce) a rate at which the winch \n48\n withdraws the conduit \n20\n and the tool \n22\n from the wireline PCE stack \n18\n.', 'As noted above, various position sensors may be utilized to enable the disclosed techniques.\n \nFIG.', '8\n is a perspective view of an embodiment of an automated crane \n140\n that may be utilized to assemble the wireline PCE stack \n18\n (\nFIG.', '1\n).', 'As shown, the automated crane system \n140\n includes a crane \n142\n and a wireline PCE kit \n144\n.', 'The wireline PCE kit \n144\n may include various components that may be stacked on one another to form the wireline PCE stack \n18\n.', 'For example, the illustrated wireline PCE kit \n144\n includes the stuffing box \n30\n, the tool catcher \n32\n, the lubricator section \n34\n, the tool trap \n36\n, and the BOP stack \n38\n.', 'Each component may be supported in a separate portion or in a designated area within a box \n146\n (e.g., transport box or storage rack).', 'For example, the components may be placed within the box \n146\n at manufacturing and/or prior to transport to the well.', 'Each box \n146\n may have an identical arrangement (e.g., regardless of the well to which it will be transported) or each box \n146\n may have a unique arrangement.', 'While the components are shown in a vertical arrangement within the box \n146\n, it should be appreciated that the box \n146\n may be designed to support the components in other arrangements.', 'The crane \n140\n may include a controller \n150\n having a processor \n152\n and a memory \n154\n.', 'The processor \n152\n may be configured to retrieve (e.g., from the memory \n154\n or from another external storage) information related to the respective position of each component within the box \n146\n.', 'The processor \n152\n is configured to operate (e.g., autonomously operate) to lift each component from the box \n146\n and place each component on top of the wellhead \n12\n to form the wireline PCE stack \n18\n.', 'For example, the processor \n152\n may instruct the various actuators of the crane \n142\n to first lift the BOP stack \n38\n and position the BOP stack \n38\n on the wellhead \n12\n, then to lift the tool trap \n36\n and position the tool trap \n36\n on the BOP stack \n38\n, then to lift the lubricator section \n34\n and position the lubricator section \n34\n on the tool trap \n36\n, and so forth, until the wireline PCE stack \n18\n is complete.', 'In some embodiments, the lifting and positioning steps may be completely automated, and thus, the crane \n142\n may build the wireline PCE stack \n18\n, including making some or all mechanical, electric, and hydraulic connections, without any inputs or control by the operator.', 'To facilitate the automated construction in this manner, the components of the wireline PCE stack \n18\n may include lifting connections that are engaged by a lifting component (e.g., hook) of the crane \n142\n.', 'Furthermore, the components of the wireline PCE stack \n18\n may include stab-in connections to facilitate coupling the BOP stack \n38\n to the wellhead \n12\n and coupling the components to one another (e.g., mechanical, electric, and/or hydraulic coupling).', 'While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein.', 'However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed.', 'Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.'] | ['1.', 'A system, comprising:\none or more processors configured to provide one or more control signals to cause supply of electric power from a power supply to one or more electric actuators that are configured to adjust one or more components of a cable pressure control equipment (PCE) stack,\nwherein a first control signal of the one or more control signals instructs supply of the electric power to a stuffing box actuator of the one or more electric actuators to adjust a packing material of a stuffing box of the one or more components,\nwherein a second control signal of the one or more control signals instructs supply of the electric power to a winch actuator of the one or more electric actuators to adjust a rate of rotation of a drum of a winch of the one or more components, and\nwherein a third control signal of the one or more control signals instructs supply of the electric power to a valve actuator of the one or more electric actuators to adjust a ram of a valve of the one or more components.', '2.', 'The system of claim 1, comprising the power supply.', '3.', 'The system of claim 1, comprising the one or more electric actuators and the one or more components of the cable PCE stack, wherein the one or more components comprise the stuffing box, the valve, and the winch.', '4.', 'The system of claim 1, comprising one or more sensors configured to monitor one or more conditions of the cable PCE stack and to provide one or more sensor signals indicative of the one or more conditions to the one or more processors.', '5.', 'The system of claim 4, wherein the one or more processors are configured to process the one or more sensor signals and to provide the one or more control signals based on the one or more sensor signals.', '6.', 'The system of claim 4, wherein the one or more sensors comprise a leak sensor, a pressure sensor, and a position sensor.\n\n\n\n\n\n\n7.', 'The system of claim 1, comprising a cable extending through the cable PCE stack, wherein the cable comprises a wireline, slickline, coiled tubing, or spoolable rod.\n\n\n\n\n\n\n8.', 'A system, comprising:\none or more processors configured to provide one or more control signals to cause supply of electric power from a power supply to one or more electric actuators that are configured to adjust one or more components of a cable pressure control equipment (PCE) stack,\nwherein the one or more processors are configured to receive a leak signal from a leak sensor, determine whether a leak is present based on the leak signal, and provide a stuffing box control signal of the one or more control signals to supply the electric power to a stuffing box actuator of the one or more electric actuators to adjust a packing material of a stuffing box in response to determining that the leak is present.', '9.', 'The system of claim 8, wherein the one or more processors are configured to receive a position signal from a position sensor, determine whether a plate of a tool trap is driven to an open position by a tool within the cable PCE stack based on the position signal, and provide a winch control signal of the one or more control signals to supply the electric power to a winch actuator to reduce a rate at which the tool is withdrawn from the cable PCE stack in response to determining that the plate is driven to the open position by the tool.\n\n\n\n\n\n\n10.', 'The system of claim 8, wherein the one or more processors are configured to receive a first pressure signal from a first pressure sensor, receive a second pressure signal from a second pressure sensor, determine whether a seal formed by rams of a first valve is adequate based on the first pressure signal and the second pressure signal, provide a cable control signal of the one or more control signals to supply the electric power to a valve actuator to move rams of a second valve to a respective closed position in response to determining that the seal formed by the first valve is inadequate.\n\n\n\n\n\n\n11.', 'The system of claim 8, comprising the power supply.', '12.', 'The system of claim 8, comprising a cable extending through the cable PCE stack, wherein the cable comprises a wireline, slickline, coiled tubing, or spoolable rod.\n\n\n\n\n\n\n13.', 'A method, comprising:\ngenerating, using one or more processors, one or more control signals to cause supply of electric power from a power supply to one or more electric actuators that are configured to adjust one or more components of a cable pressure control equipment (PCE) stack;\ngenerating, using the one or more processors, a first control signal of the one or more control signals to cause supply of the electric power to a stuffing box actuator of the one or more actuators to adjust a packing material of a stuffing box of the one or more components;\ngenerating, using the one or more processors, a second control signal of the one or more control signals to cause supply of the electric power to a winch actuator of the one or more actuators to adjust a rate of rotation of a drum of a winch of the one or more components; and\ngenerating, using the one or more processors, a third control signal of the one or more control signals to cause supply of electric power to a valve actuator of the one or more actuators to adjust a ram of a valve of the one or more components.', '14.', 'The method of claim 13, comprising:\nreceiving, at the one or more processors, one or more signals from one or more sensors configured to monitor one or more conditions of the cable PCE stack;\ndetermining, using the one or more processors, the one or more conditions of the cable PCE stack; and\nproviding the one or more control signals based on the one or more conditions of the cable PCE stack.'] | ['FIG.', '1 is a schematic diagram of an embodiment of an offshore system having a pressure control equipment (PCE) stack of the disclosure;; FIG.', '2 is a side view of an embodiment of the PCE stack of FIG.', '1;; FIG. 3 is a schematic diagram of a control system and the PCE stack of FIG.', '1;; FIG. 4 is a perspective view of a tool trap assembly that may be used in the PCE stack of FIG.', '1;; FIG. 5 is a flow diagram of an embodiment of a method of operating the PCE stack of FIG.', '1 based on a signal received from a leak sensor;; FIG.', '6 flow diagram of an embodiment of a method of operating the PCE stack of FIG.', '1 based on a signal received from pressure sensors;; FIG. 7 is flow diagram of an embodiment of a method of operating the PCE stack of FIG.', '1 based on a signal received from a position sensor; and; FIG.', '8 is a perspective view of an embodiment of an automated crane system that may be utilized to assemble the PCE stack of FIG.', '1.; FIG. 2 is a side view of an embodiment of the wireline PCE stack 18 that may be used in the offshore system 10 of FIG.', '1.', 'The wireline PCE stack 18 includes various components that enable the wireline PCE stack 18 to seal about the conduit 20 as it moves relative to the wireline PCE stack 18.', 'Thus, the wireline PCE stack 18 may isolate the environment, as well as other surface equipment, from pressurized fluid within the wellbore 16 (FIG. 1).; FIG.', '3 is a schematic diagram of the control system 28 and the wireline PCE stack 18.', 'As shown, a stuffing box actuator 60 is provided to adjust the lever 50 (FIG. 2) of the stuffing box 30, thereby adjusting the seal formed against the conduit 20 (FIG. 2).', 'A bleed off port valve actuator 61 is provided to adjust a valve 63 (e.g., bleed off port valve) between an open position and a closed position to adjust fluid flow between the bore of the lubricator section 34 and the bleed off port 52 (FIG. 2).', 'A tool catcher actuator 62 is provided to adjust the plate of the tool catcher 32 between the open position and the closed position.', 'A tool trap actuator 64 is provided to adjust the plate of the tool trap 36 between the open position and the closed position.', 'A BOP actuator 66 (e.g., wireline actuator) is provided for the BOP assembly 38 (e.g., one or more respective actuators 66 may be provided for each BOP in the BOP assembly 38).', 'One or more of the actuators 60, 61, 62, 64, 66 may be electric actuators that are configured to receive and respond to control signals (e.g., electric voltage or current) from a controller 68 of the control system 28.', 'The winch 48 may also be configured to receive and respond to control signals from the controller 68 of the control system 28.', 'As shown, the controller 68 includes a processor 70, a memory 72, a user interface 74, and a power supply 76 (e.g., electric power supply).', '; FIGS.', '5-7 are flow diagrams of embodiments of methods of operating the wireline PCE stack 18.', 'The methods include non-limiting examples of using the one or more processors to provide one or more control signals to cause supply of electric power from the power supply to one or more electric actuators that are configured to adjust one or more components of the wireline PCE stack.', 'The methods disclosed herein includes various steps represented by blocks.', 'It should be noted that at least some steps of the methods may be performed as an automated procedure by a system, such as the control system 28.', 'Although the flow charts illustrate the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate.', 'Additionally, steps may be added to or omitted from of the methods.', 'Further, certain steps or portions of the methods may be performed by separate devices.', 'For example, a first portion of each method may be performed by the processor 70, while a second portion of the methods may be performed by another processor or an operator.', 'In addition, insofar as steps of the methods disclosed herein are applied to received signals, it should be understood that the received signals may be raw signals or processed signals.', 'That is, the methods may be applied to an output of the received signals.; FIG. 5 is a flow diagram of an embodiment of a method 100 of operating the wireline PCE stack 18 based on a signal received from the leak sensor 78.', 'As shown, in step 102, the processor 70 may receive a signal from the leak sensor 78 positioned proximate to the stuffing box 30 of the wireline PCE stack 18.', 'In step 104, the processor 70 may determine whether the signal indicates a leak.', 'For example, the leak sensor 78 may be an ultrasonic sensor and the signal may be indicative of sound waves generated as the conduit 20 passes through the packing material of the stuffing box 40.', 'The processor 70 may determine a characteristic of the sound waves and then may compare the characteristic to a known characteristic to determine whether the signal indicates a leak.;', 'FIG. 6 is a flow diagram of an embodiment of a method 120 of operating the wireline PCE stack 18 based on signals received from the first pressure sensor 80 and the second pressure sensor 82 while rams of a BOP of the BOP stack 28 are in a closed position.', 'As shown, in step 122, the processor 70 may receive a first signal indicative of a first pressure from the first pressure sensor 80 positioned vertically above a ram of the BOP stack 38 of the wireline PCE stack 18.', 'In step 124, the processor 70 may receive a second signal indicative of a second pressure from the second pressure sensor 82 positioned vertically below the ram of the BOP stack 38 of the wireline PCE stack 18.; FIG.', '7 is a flow diagram of an embodiment of a method 130 of operating the wireline PCE stack 18 based on signals received from the position sensor 84 of the tool trap 36.', 'As shown, in step 132, the processor 70 may receive a signal indicative of a position of the plate 86 of the tool trap 36 from the position sensor 84.', 'In step 134, the processor 70 may determine whether the signal indicates that the plate 86 of the tool trap 36 is being driven (e.g., is or was driven) to the open position 90 by the tool 22.', 'To assist in the determination, the processor 70 may also consider signals that indicate that the tool 22 is being withdrawn via the winch 48 and/or that the tool trap actuator 64 is not adjusting the plate 86 to the open position 90.; FIG.', '8 is a perspective view of an embodiment of an automated crane 140 that may be utilized to assemble the wireline PCE stack 18 (FIG. 1).', 'As shown, the automated crane system 140 includes a crane 142 and a wireline PCE kit 144.', 'The wireline PCE kit 144 may include various components that may be stacked on one another to form the wireline PCE stack 18.', 'For example, the illustrated wireline PCE kit 144 includes the stuffing box 30, the tool catcher 32, the lubricator section 34, the tool trap 36, and the BOP stack 38.', 'Each component may be supported in a separate portion or in a designated area within a box 146 (e.g., transport box or storage rack).', 'For example, the components may be placed within the box 146 at manufacturing and/or prior to transport to the well.', 'Each box 146 may have an identical arrangement (e.g., regardless of the well to which it will be transported) or each box 146 may have a unique arrangement.', 'While the components are shown in a vertical arrangement within the box 146, it should be appreciated that the box 146 may be designed to support the components in other arrangements.'] |
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US11072982 | Aligned disc choke for managed pressure drilling | Dec 11, 2017 | Jerod Bushman, Gocha Chochua, Shelby Wayne Carter, Henrix Soto, Jeffrey Ham | Schlumberger Technology Corporation | International Preliminary Report on Patentability for the equivalent International patent application PCT/US2017/065497 dated Jun. 27, 2019.; International Search Report and Written Opinion for the equivalent International patent application PCT/US2017/065497 dated Mar. 15, 2018.; Search and Examination Report R. 62 issued in European patent application 17880881.2 dated Jun. 25, 2020, 9 pages.; Office Action issued in Azerbaijan patent application a2019 0070 dated Nov. 11, 2020, 4 pages includes English Translation. | 6904891; June 14, 2005; Tominaga et al.; 7108080; September 19, 2006; Tessari; 7325606; February 5, 2008; Vail, III; 8485264; July 16, 2013; Hutin; 9027673; May 12, 2015; Vail, III; 9157295; October 13, 2015; Head; 9611700; April 4, 2017; Zhou; 9957774; May 1, 2018; Clark; 20060144620; July 6, 2006; Cooper; 20070278011; December 6, 2007; Barnett; 20080105434; May 8, 2008; Orbell et al.; 20100319995; December 23, 2010; Johnson; 20120132442; May 31, 2012; Head; 20130140034; June 6, 2013; Ghasripoor et al.; 20140216816; August 7, 2014; Lehr; 20160201426; July 14, 2016; Cohen | 2011/084153; July 2011; WO; 2011119668; September 2011; WO | ['A conduit forming part of a drilling fluid return path from a wellbore has at least one flow restrictor disposed on an interior surface of the conduit.', 'A drill string is disposed through the interior of the conduit and has at least one flow restrictor disposed on an exterior surface of the drill string.', 'The drill string is longitudinally movable through the conduit to enable placing the flow restrictor in the conduit, and the flow restrictor on the drill string at a selected longitudinal distance from each other.'] | ['Description\n\n\n\n\n\n\nThis application claims the benefit of and priority to two U.S. Provisional Applications, having Ser.', 'No. 62/433,527, filed 13 Dec. 2016, and Ser.', 'No. 62/437,855, filed on 22 Dec. 2016, which are incorporated by reference herein.', 'The disclosure relates generally to the field of “managed pressure” wellbore drilling.', 'More specifically, the disclosure relates to managed pressure control apparatus and methods which may not require the use of a rotating control device (“RCD”), rotating blowout preventer or similar apparatus to restrict or close a wellbore annulus.', 'BACKGROUND\n \nManaged pressure drilling uses well pressure control systems that control return flow of drilling fluid in a wellbore annulus to maintain a selected pressure or pressure profile in a wellbore.', 'U.S. Pat.', 'No. 6,904,891 issued to van Riet describes one such system for controlling wellbore pressure during the drilling of a wellbore through subterranean formations.', "The system described in the '891 patent includes a drill string extending into the wellbore.", 'The drill string may include a bottom hole assembly (“BHA”) including a drill bit, drill collars, sensors (which may be disposed in one or more of the drill collars), and a telemetry system capable of receiving and transmitting sensor data between the BHA and a control system disposed at the surface.', 'Sensors disposed in the bottom hole assembly may include pressure and temperature sensors.', 'The control system may comprise a telemetry system for receiving telemetry signals from the sensors and for transmitting commands and data to certain components in the BHA.', 'A drilling fluid (“mud”) pump or pumps may selectively pump drilling fluid from a drilling fluid reservoir, through the drill string, out from the drill bit at the end of the drill string and into an annular space created as the drill string penetrates the subsurface formations.', 'A fluid discharge conduit is in fluid communication with the annular space for discharging the drilling fluid to the reservoir to clean the drilling fluid for reuse.', 'A fluid back pressure system is connected to the fluid discharge conduit.', 'The fluid back pressure system may include a flow meter, a controllable orifice fluid choke, a backpressure pump and a fluid source coupled to the pump intake.', 'The backpressure pump may be selectively activated to increase annular space drilling fluid pressure.', "Other examples may exclude the back-pressure pump.\n \nSystems such as those described in the van Riet '891 patent comprise a RCD or similar rotatable sealing element at a selected position, in some implementations at or near the upper end of the wellbore.", 'The upper end of the wellbore may be a surface casing extending into the subsurface and cemented in place, or in the case of marine wellbore drilling, may comprise a conduit called a “riser” that extends from a wellhead disposed on the water bottom and extending to a drilling platform proximate the water surface.', "Further, in such systems as described in the van Riet '891 patent, a fluid discharge line from the upper end of the wellbore but below the RCD may comprise devices such as a controllable orifice choke such that drilling fluid returning from the wellbore may have its flow controllably restricted to provide a selected fluid pressure in the wellbore or a selected fluid pressure profile (i.e., fluid pressure with respect to depth in the wellbore).", 'It is desirable to provide control of fluid pressure in a wellbore without the need to use RCDs or similar rotating pressure control devices at the upper end of the well.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n illustrates an example embodiment of a drilling system including a well pressure control apparatus.', 'FIG.', '2\n illustrates a detailed view of one example embodiment of a well pressure control apparatus.\n \nFIG.', '3\n shows the pressure control apparatus of \nFIG.', '2\n in the fully closed position.', 'DETAILED DESCRIPTION\n \nFIG.', '1\n shows an example drilling apparatus that may be used in some embodiments.', 'While the present example embodiment is described with reference to drilling a well below the bottom of a body of water, it should by clearly understood that other embodiments may be used about drilling a well below the land surface.', 'A drilling vessel \n10\n floats on the surface of a body of water \n13\n.', 'A wellhead \n15\n is positioned on the water bottom \n17\n.', 'The wellhead \n15\n which defines the upper surface or “mudline” of a wellbore \n22\n drilled through sub-bottom formations \n18\n.', 'A drill string \n19\n having a drill bit \n20\n disposed at a bottom end thereof are suspended from a derrick \n21\n mounted on the drilling vessel \n10\n.', 'The drill string \n19\n may extend from the derrick \n21\n to the bottom of the wellbore \n22\n.', 'A length of structural casing \n27\n extends from the wellhead \n15\n to a selected depth in the wellbore \n22\n.', 'In the present example embodiment, a riser \n23\n may extend from the upper end of a blowout preventer stack \n24\n coupled to the wellhead \n15\n, upwardly to the drilling vessel \n10\n.', 'The riser \n23\n may comprise flexible couplings such as ball joints \n25\n proximate each longitudinal end of the riser \n23\n to enable some movement of the drilling vessel \n10\n without causing damage to the riser \n23\n.', 'A flow control \n35\n may be disposed at a selected longitudinal position along the riser \n23\n.', 'In the present example embodiment, the flow control \n35\n may be disposed proximate a drilling fluid outlet \n33\n coupled proximate the top of the riser \n23\n.', 'The drilling fluid outlet \n33\n may comprise a flowmeter \n40\n to measure the rate at which fluid is discharged from the riser \n23\n, and thus the wellbore \n22\n.', 'A drilling fluid treatment system \n32\n which may comprise components (none shown separately for clarity) such as a gas separator, one or more shaker tables and a clean drilling fluid return line \n32\nA which returns cleaned drilling fluid to a tank or reservoir \n32\nB.\n \nA pump \n31\n disposed on the drilling vessel \n10\n may lift drilling fluid from the tank \n32\nB and discharge the lifted drilling fluid into a standpipe \n31\nA or similar conduit.', 'The standpipe \n31\nA is in fluid communication with the interior of the drill string \n19\n at the upper end of the drill string \n19\n such that the discharged drilling fluid moves through the drill string \n19\n downwardly and is ultimately discharged through nozzles, jets or courses on the drill bit \n20\n and thereby into the wellbore \n22\n.', 'The drilling fluid moves along the interior of the wellbore \n22\n upwardly into the riser \n23\n until it reaches the fluid outlet \n33\n.', 'A pressure sensor \n44\n and a flowmeter \n42\n may be placed in fluid communication with the pump \n31\n discharge at any selected position between the pump \n31\n and the upper end of the drill string \n19\n.', 'The pressure sensor \n44\n may measure pressure of the drilling fluid in the standpipe \n31\nA and the flowmeter may measure rate of flow of the drilling fluid through the standpipe \n31\nA to enable determining pressure of the drilling fluid at any longitudinal position along the wellbore \n22\n and/or the riser \n23\n.', 'In some embodiments, a pressure sensor may be disposed proximate the bottom end of the drill string \n19\n, such pressure sensor being shown at \n46\n.', 'The pressure sensor \n46\n may communicates measurements to the drilling vessel \n10\n using signal transmission devices known in the art.', 'In some embodiments, a flow control \n135\n may be disposed within the casing \n27\n proximate its upper end.', 'Such placement of a flow control \n135\n may be used for drilling below the land surface, where the casing may perform the function of a return conduit for the drilling fluid.', 'For purposes of defining the scope of the present disclosure, the flow control shown at \n35\n in the riser \n23\n and the flow control \n135\n in the casing \n27\n may be used for the same purpose, namely to control discharge of the drilling fluid from the wellbore \n22\n so that a selected wellbore drilling fluid pressure may be maintained.', 'An example embodiment of a flow control may be better understood with reference to \nFIGS.', '2 and 3\n.', 'The flow control, e.g., as shown at \n35\n in \nFIG.', '1\n or at \n135\n in \nFIG.', '1\n may comprise at least one flow restrictor \n36\n disposed on the interior surface of the riser \n23\n (or on the interior surface of the casing \n22\n for land drilling or riser less marine drilling).', 'The drill string \n19\n may comprise at least one flow restrictor \n38\n on its exterior surface.', 'In the embodiment shown in \nFIG.', '2\n there are three such corresponding flow restrictors \n36\n, \n38\n, however the number of such flow restrictors is not intended to limit the scope of the present disclosure.', 'In \nFIG.', '2\n the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n are longitudinally displaced from each other such that drilling fluid may flow freely in the annular space \n37\n between the drill string \n19\n and the riser \n23\n (or casing \n27\n in \nFIG.', '1\n).', 'In some embodiments, the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n each may be a substantially circular disc.', 'Such embodiments may enable substantial closure of the well to flow in the annular space \n37\n while enabling rotation of the drill string \n19\n to continue.', 'In \nFIG.', '3\n, the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n are at the same longitudinal position, such that flow in the annular space \n37\n is restricted.', 'Either or both of the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n may comprise one or more openings \n36\nA, \n38\nA, respectively, such that when the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n are at the same longitudinal position, flow through the annular space is not completely stopped, but may be restricted by a predetermined amount.', 'Such openings may be of any suitable configuration, for example and without limitation, holes, slots, and one or more notches in the exterior surface.', 'In some embodiments, the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n may have respective inner and outer diameters that differ from each other by a selected amount, such that a predetermined flow restriction is provided when the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n are at the same longitudinal position.', 'In some embodiments, where a plurality of the flow restrictors \n36\n on the interior of the riser \n23\n and the flow restrictors \n38\n on the exterior of the drill string \n19\n are used, a longitudinal spacing between the flow restrictors \n36\n on the interior of the riser \n23\n and the flow restrictors \n38\n on the exterior of the drill string \n19\n may be respectively longitudinally spaced apart by a length of each segment (“joint”) of the drill string \n19\n.', 'The flow control \n35\n may be used in managed pressure drilling to maintain a selected pressure or pressure profile (pressure with respect to depth in the wellbore \n22\n) in the wellbore (\n22\n in \nFIG.', '1\n).', 'Methods for estimating pressure may comprise measuring pressure and flow rate of drilling fluid entering the drill string \n19\n, e.g., using pressure sensor \n44\n and flowmeter \n42\n, measuring flow rate of the drilling fluid out of the wellbore, e.g., using flowmeter \n40\n, and using the foregoing measurements in a hydraulics model.', 'Using such measurements and calculating wellbore pressure using a hydraulics model is described in U.S. Pat.', 'No. 6,904,891 issued to van Riet.', 'In some embodiments, where a wellbore pressure sensor is used, e.g., as shown at \n46\n, the wellbore fluid pressure may be measured directly, or may be used to calibrate the pressure determined from the hydraulics model.', 'The wellbore fluid pressure may be controlled by moving the flow restrictor(s) \n36\n on the interior of the riser \n23\n and the flow restrictor(s) \n38\n on the exterior of the drill string \n19\n longitudinally with respect to each other to provide a selected flow restriction in the riser \n23\n or casing \n27\n.', 'In the present example embodiment, such longitudinal motion may be performed by lifting or lowering the drill string \n19\n.', 'While the present disclosure describes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of what has been disclosed herein.', 'Accordingly, the scope of the disclosure should be limited only by the attached claims.'] | ['1.', 'A system, comprising:\na drill string extending into a wellbore drilled through subsurface formations;\na pump having an inlet in fluid communication with a supply of drilling fluid, the pump having an outlet in fluid communication with an interior of the drill string;\na conduit extending from a selected axial position in the wellbore to a position proximate a surface end of the wellbore; and\nat least one flow restrictor disposed on an interior surface of the conduit; and\nat least one flow restrictor disposed on an exterior surface of the drill string and arranged to function cooperatively with the at least one flow restrictor on the interior surface of the conduit to selectively restrict flow of drilling fluid between the drill string and the conduit.', '2.', 'The system of claim 1 wherein at least one of the flow restrictor on the exterior of the drill string and the flow restrictor on the interior of the conduit comprises at least one opening such that a selected flow restriction results when the flow restrictor on the drill string and the flow restrictor in the conduit are at a same longitudinal position in the wellbore.', '3.', 'The system of claim 1 wherein the flow restrictor on the exterior of the drill string has a selected outer diameter and the flow restrictor on the interior of the conduit has a selected inner diameter, a difference between the selected outer diameter and the selected inner diameter creating a selected diameter annular space when the flow restrictor on the drill string and the flow restrictor in the conduit are at a same longitudinal position in the wellbore.', '4.', 'The system of claim 1, wherein the at least one flow restrictor on the interior surface comprises a plurality of longitudinally spaced apart flow restrictors disposed on the interior surface of the conduit and wherein the at least one flow restrictor on the exterior surface comprises a corresponding plurality of longitudinally spaced apart flow restrictors disposed on the exterior surface of the drill string.', '5.', 'The system of claim 4 wherein a longitudinal spacing between adjacent ones of the flow restrictors on the interior of the conduit and on the exterior of the drill string corresponds to a length of each of a plurality of segments of the drill string.', '6.', 'The system of claim 4 wherein at least one of (I) each of the flow restrictors on the exterior of the drill string and (ii) each of the flow restrictors on the interior of the conduit comprises at least one opening such that a selected flow restriction results when the flow restrictors on the drill string and the flow restrictors in the conduit are at correspondingly same longitudinal positions in the wellbore.', '7.', 'The system of claim 4 wherein each of the flow restrictors on the exterior of the drill string has a selected outer diameter and each of the flow restrictors on the interior of the conduit has a selected inner diameter, a difference between the selected outer diameter and the selected inner diameter creating a selected diameter annular space when the flow restrictors on the drill string and the flow restrictors in the conduit are at correspondingly same longitudinal positions in the wellbore.', '8.', 'The system of claim 4, wherein each of the flow restrictors on the exterior of the drill string has a selected outer diameter and each of the flow restrictors on the interior of the conduit comprises a substantially circular disc.', '9.', 'A method, comprising:\npumping drilling fluid through a drill string extended into a wellbore drilled through subsurface formations;\nreturning the pumped drilling fluid through an annular space between an exterior of the drill string and an interior of a conduit disposed to a selected depth in the wellbore; and\nselectively restricting discharge of fluid from the interior of the conduit by controlling a longitudinal distance between at least one flow restrictor disposed on an interior surface of the conduit and at least one flow restrictor disposed on an exterior surface of the drill string and arranged to function cooperatively with the at least one flow restrictor on the interior surface of the conduit.', '10.', 'The method of claim 9, further comprising measuring a pressure of the drilling fluid in the conduit below the flow restrictors and controlling the longitudinal distance to maintain a selected measured pressure.', '11.', 'The method of claim 9, further comprising measuring a pressure of drilling fluid entering an interior of the drill string and measuring a flow rate of drilling fluid entering the drill string or a flow rate of drilling fluid exiting the conduit, and controlling the longitudinal distance to maintain a selected measured pressure and measured flow rate.', '12.', 'The method of claim 9, further comprising selectively restricting discharge of fluid from the interior of the conduit by controlling a longitudinal distance between each of a plurality of longitudinally spaced apart flow restrictors disposed on the interior surface of the conduit and a corresponding plurality of flow restrictors disposed on the exterior surface of the drill string and arranged to function cooperatively with the flow restrictors on the interior of the conduit.', '13.', 'An apparatus, comprising:\na conduit forming part of a drilling fluid return path from a wellbore, the conduit comprising at least one flow restrictor disposed on an interior surface of the conduit; and\na drill string disposed through the interior of the conduit, the drill string comprising at least one flow restrictor disposed on an exterior surface of the drill string, the drill string longitudinally movable through the conduit to enable placing the flow restrictor in the conduit and the flow restrictor on the drill string at a selected longitudinal distance from each other.\n\n\n\n\n\n\n14.', 'The apparatus of claim 13, further comprising a plurality of longitudinally spaced apart flow restrictors disposed on the interior surface of the conduit a corresponding plurality of longitudinally spaced apart flow restrictors disposed on the exterior surface of the drill string.', '15.', 'The apparatus of claim 13, wherein at least one of the flow restrictor on the drill string and the flow restrictor in the conduit comprises at least one opening therein, such that a selected flow restriction is provided when the flow restrictor on the drill string and the flow restrictor in the conduit are at a same longitudinal position as each other.'] | ['FIG. 1 illustrates an example embodiment of a drilling system including a well pressure control apparatus.; FIG.', '2 illustrates a detailed view of one example embodiment of a well pressure control apparatus.; FIG.', '3 shows the pressure control apparatus of FIG.', '2 in the fully closed position.;', 'FIG. 1 shows an example drilling apparatus that may be used in some embodiments.', 'While the present example embodiment is described with reference to drilling a well below the bottom of a body of water, it should by clearly understood that other embodiments may be used about drilling a well below the land surface.'] |
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US11073630 | Attenuating tool borne noise acquired in a downhole sonic tool measurement | May 30, 2017 | Robert Hughes Jones, Toshimichi Wago, Can Evren Yarman | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in the Related PCT application PCT/US2018/034826, dated Sep. 11, 2018 (12 pages).; International Preliminary Report on Patentability issued in the Related PCT application PCT/US2018/034826, dated Dec. 12, 2019 (9 pages). | 5146433; September 8, 1992; Kosmala; 5448531; September 5, 1995; Dragoset, Jr.; 5831934; November 3, 1998; Gill; 5886303; March 23, 1999; Rodney; 6671224; December 30, 2003; Pabon; 8811118; August 19, 2014; Reckmann; 20050128874; June 16, 2005; Herkenhoff; 20050261835; November 24, 2005; Wang; 20080259726; October 23, 2008; van Manen; 20110141849; June 16, 2011; Brittan; 20130128696; May 23, 2013; Vassallo; 20140192618; July 10, 2014; Pabon; 20140286127; September 25, 2014; Goujon; 20150124562; May 7, 2015; Yoneshima et al.; 20150177404; June 25, 2015; Pabon; 20170031047; February 2, 2017; Cheng et al.; 20180003846; January 4, 2018; Wago; 20180320514; November 8, 2018; Felkl | 2010093557; August 2010; WO | ['A technique includes receiving data representing a measurement acquired by a tool motion sensor of a downhole sonic measurement tool; and receiving data representing a measurement acquired by a pressure sensor of the sonic measurement tool.', 'The technique includes modifying the measurement acquired by the pressure sensor based at least in part on the measurement acquired by the tool motion sensor to attenuate tool borne noise.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nHydrocarbon fluids, such as oil and natural gas, are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation.', 'During drilling and at other stages of exploration through production, various downhole tools may be used to acquire data for purpose of evaluating, analyzing, and monitoring the well bore and the surrounding geological strata.', 'In some cases, the acquired data includes sonic or seismic data, i.e., data acquired by sensors, or receivers, in response to sonic/seismic energy interacting with the wellbore and the surrounding geological strata.', 'The acquired data may be processed and interpreted for purposes of deriving information regarding the hydrocarbon-bearing formation, the well and other aspects pertaining to subterranean exploration.', 'SUMMARY', 'In accordance with an example implementation, a technique includes receiving data representing a measurement acquired by a tool motion sensor of a downhole sonic measurement tool; and receiving data representing a measurement acquired by a pressure sensor of the sonic measurement tool.', 'The technique includes modifying the measurement acquired by the pressure sensor based at least in part on the measurement acquired by the tool motion sensor to attenuate tool borne noise.', 'In accordance with another example implementation, an apparatus that is usable within a well includes a tool body; a sonic source that is attached to the tool body; a pressure sensor and an accelerometer.', 'The pressure sensor is attached to the tool body to sense a pressure associated with firing of the sonic source; and the accelerometer is attached to the tool body to sense a component related to the pressure sensed by the pressure sensor attributable to tool borne noise.', 'In accordance with another example implementation, an article includes a non-transitory computer readable storage medium to store instructions that when executed by a processor-based system cause the processor-based system to receive data representing a measurement acquired by a tool motion sensor of a downhole sonic measurement tool; receive data representing a measurement acquired by a pressure sensor of the sonic measurement tool; and modify the measurement acquired by the pressure sensor based at least in part on the measurement acquired by the tool motion sensor to attenuate tool borne noise.', 'In accordance with yet another example implementation, an article includes a non-transitory computer readable storage medium to store instructions that when executed by a processor-based system cause the processor-based system to receive data representing a compensating signal based on a measurement acquired by a tool motion sensor of a downhole sonic measurement tool in a test environment; receive data representing a measurement acquired by a pressure sensor of the sonic measurement tool downhole in the well; and modify the measurement acquired by the pressure sensor based at least in part on the compensating signal to attenuate tool borne noise.', 'Advantages and other features will become apparent from the following description, drawings and claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n is an illustration of a sonic measurement tool in a borehole according to an example implementation.', 'FIGS.', '2A, 2B and 2C\n are flow diagrams depicting techniques to compensate measurements acquired by a downhole sonic measurement tool to attenuate tool borne noise according to example implementations.\n \nFIG.', '3\n is an illustration of a pressure versus time waveform produced by the firing of a source of the sonic measurement tool according to an example implementation.', 'FIG.', '4\n illustrates acceleration versus time waveforms sensed by accelerometers of the sonic measurement tool in response to the firing of the source according to an example implementation.\n \nFIG.', '5\n illustrates pressure versus time waveforms sensed by pressure sensors of the sonic measurement tool in response to the firing of the source according to an example implementation.\n \nFIG.', '6\n illustrates pressure versus time waveforms produced by applying compensation to the pressure versus time waveforms of \nFIG.', '5\n to remove tool borne noise according to an example implementation.', 'FIG.', '7\n is a schematic diagram of a data processing system according to an example implementation.', 'DETAILED DESCRIPTION\n \nReference throughout the specification to “one implementation,” “an implementation,” “some implementations,” “one aspect,” “an aspect,” or “some aspects” means that a particular feature, structure, method, or characteristic described in connection with the implementation or aspect is included in at least one implementation of the present disclosure.', 'Thus, the appearance of the phrases “in one implementation” or “in an implementation” or “in some implementations” in various places throughout the specification are not necessarily all referring to the same implementation.', 'Furthermore, the particular features, structures, methods, or characteristics may be combined in any suitable manner in one or more implementations.', 'The words “including” and “having” shall have the same meaning as the word “comprising.”', 'As used throughout the specification and claims, the term “downhole” refers to a subterranean environment, particularly in a well or wellbore.', '“Downhole tool” is used broadly to mean any tool used in a subterranean environment including, but not limited to, a logging tool, an imaging tool, an acoustic tool, a permanent monitoring tool, and a combination tool.', 'The various techniques disclosed herein may be utilized to facilitate and improve data acquisition and analysis in downhole tools and systems.', 'In this, downhole tools and systems are provided that utilize arrays of sensing devices that are configured or designed for attachment and detachment in downhole sensor tools or modules that are deployed for purposes of sensing data relating to environmental and tool parameters downhole, within a borehole.', 'The tools and sensing systems disclosed herein may effectively sense and store characteristics relating to components of downhole tools as well as formation parameters at elevated temperatures and pressures.', 'The sensing systems herein may be incorporated in tool systems such as wireline logging tools, measurement-while-drilling and logging-while-drilling tools, permanent monitoring systems, drill bits, drill collars, sondes, among others.', 'For purposes of this disclosure, when any one of the terms wireline, cable line, slickline or coiled tubing or conveyance is used it is understood that any of the referenced deployment means, or any other suitable equivalent means, may be used with the present disclosure without departing from the spirit and scope of the present disclosure.', 'Moreover, inventive aspects lie in less than all features of a single disclosed implementation.', 'Thus, the claims following the Detailed Description are hereby expressly incorporated into this Detailed Description, with each claim standing on its own as a separate implementation.', 'Borehole acoustic logging is a major part of subsurface formation evaluation that is key to oil and gas exploration and production.', 'The logging may be achieved, for example, using a sonic measurement tool, which includes one or multiple acoustic transducers, or sources, and one or multiple sensors, or receivers.', 'The sonic measurement tool may be deployed in a fluid-field wellbore for purposes of exciting and recording acoustic waveforms.', 'The receivers thus, may acquire data representing acoustic energy that results from the acoustic energy that is emitted by the acoustic sources of the sonic measurement tool.', 'The acoustic propagation in the borehole is affected by the properties of rocks surrounding the wellbore.', 'More specifically, the fluid-filled borehole supports propagation of certain number of borehole guided acoustic modes that are generated by energy from a source that is placed inside the borehole fluid.', 'These borehole acoustic modes are characterized by their acoustic slowness (i.e., reciprocal of velocity) dispersions, which contain valuable information about the rock mechanical properties.', 'Therefore, the acoustic logging may provide answers pertaining to such diverse applications as geophysical calibration of seismic imaging, geomechanical assessment of wellbore stability, and stress characterization for fracture stimulation.', 'In the context of this application, “acoustic energy” refers to energy in the sonic frequency spectrum, and may be, as example, energy between 200 Hertz (Hz) and 30 kiloHertz (kHz).', 'In addition to formation slowness, acoustic logging is used in well integrity applications to determine the cement condition between the casing and the borehole.', 'In general, the energy that is emitted by the sources of the sonic measurement tool may travel through rock formations as either body waves or surface waves (also called “flexural waves”).', 'The body waves include compressional waves, or P-waves, which are waves in which small particle vibrations occur in the same direction as the direction in which the wave is traveling.', 'The body waves may also include shear waves, or S-waves, which are waves in which particle motion occurs in a direction that is perpendicular to the direction of wave propagation.', 'In addition to the body waves, there are a variety of borehole guided modes whose propagation characteristics can be analyzed to estimate certain rock properties of the surrounding formation.', 'For instance, axi-symmetric Stoneley and borehole flexural waves are of particular interest in determining the formation shear slownesses.', 'As described herein, the flexural waves may also include waves that propagate along the sonic measurement tool.', 'The sonic measurement tool may include multiple acoustic sources that are associated with multiple source classifications, or categories.', 'For example, the sonic measurement tool may include one or multiple monopole sources.', 'In response to energy from a monopole sonic source, the receivers of the sonic measurement tool may acquire data representing energy attributable to various wave modes, such as data representing P-waves, S-waves and Stoneley waves.', 'The sonic measurement tool may also include one or multiple directional sources, such as quadrupole sources, which produce additional borehole guided waves, which travel through the fluid in the borehole and along the sonic tool itself.', 'Data representing these flexural waves may be processed for such purposes as determining the presence or absence of azimuthal anisotropy and/or determining a formation shear slowness.', 'The speeds at which the aforementioned waves travel are affected by various properties of the downhole environment, such as the rock mechanical properties, density and elastic dynamic constants, the amount and type of fluid present in the formation, the makeup of rock grains, the degree of inter-grain cementation and so forth.', 'Therefore, by measuring the speed of acoustic wave propagation in the borehole, it is possible to characterize the surrounding formations based on sensed parameters relating to these properties.', 'The speed, or velocity of a given sonic wave, or waveform, may be expressed in terms of the inverse of its velocity, which is referred to herein as the “slowness.”', 'In this context, an “acoustic wave” or “acoustic waveform” may refer to a particular time segment of energy recorded by one or multiple receivers and may correspond to a particular acoustic waveform mode, such as a body wave, flexural or other guided borehole waves.', 'Certain acoustic waves are non-dispersive, or do not significantly vary with respect to frequency.', 'Other acoustic waves, however, are dispersive, meaning that the wave-slownesses vary as a function of frequency.', 'Referring to \nFIG.', '1\n, in accordance with example implementations, a downhole sonic measurement tool \n100\n may be deployed in a wellbore \n110\n for purposes of acquiring acoustic measurements produced by the firing of one or multiple sonic sources of the sonic measurement tool \n100\n.', 'For example, the sonic measurement tool \n100\n may include a source \n130\n (a monopole, dipole and/or quadrupole sources, for example), which may be fired for purposes of producing acoustic energy that travels through the surrounding formation.', 'The sonic measurement tool \n100\n may include one or multiple other sources, in accordance with example implementations.', 'The sonic measurement tool \n100\n may also contain one or multiple, receivers, or sensors \n120\n (one or multiple pressure sensors, for example), depending on the particular implementation.', 'Energy that is produced by the firing of a given acoustic source of the sonic measurement tool \n120\n, such as the source \n130\n, may be sensed by one or multiple receivers, or sensors \n120\n (specific sensors \n120\n-\n1\n, \n120\n-\n2\n, \n120\n-\n3\n and \n120\n-\n4\n, being depicted in \nFIG.', '1\n) for purposes of measuring the speed and amplitude of acoustic wave propagation.', 'From the measured acoustic wave propagation, it may be possible to characterize the surrounding geologic formations.', 'In accordance with example implementations, the sonic measurement tool \n100\n may be a cement evaluation tool that is used for purposes of evaluating the cement bond between a casing (not depicted in \nFIG.', '1\n) and the borehole \n110\n.', 'More specifically, in accordance with example implementations, the sonic measurement tool \n100\n may measure the pressure waveform amplitude at each sensor \n120\n and compare that amplitude to that of a non-cemented reference measurement (referred to as a free pipe measurement).', 'If the cement bond is poor, the received amplitude will be similar to that of free pipe, and if the cement bond is good, the pressure wave will be highly attenuated and will have substantially lower amplitude than the free pipe.', 'Tool borne noise may present particular challenges in evaluating the cement bond in the above-described manner as it could arrive at approximately the same time as energy propagating through the casing.', 'In this manner, the energy from the source \n130\n may propagate in two paths to each sensor \n120\n.', 'As specifically illustrated in \nFIG.', '1\n for the sensor \n120\n-\n1\n, the two paths include a direct path \n154\n that is associated with a stronger received signal, and an indirect path \n150\n that is associated with energy that propagates through the formation and arrive at the sensor \n120\n-\n1\n at a later time.', 'The casing wave propagation speed/slowness may be similar to the tool arrival speed, due to the casing and tool body both being made of steel, thereby presenting potential challenges in acquiring noise-free pressure amplitude measurements that are representative of the cement bond.', 'Techniques and systems are described herein for purposes of attenuating, if not removing, the tool borne noise, even for such a challenging case.', 'One way to attenuate tool borne noise is through active cancellation.', 'In this manner, an active cancelling transmitter may be built in the sonic measurement tool so that the acoustic wave that is produced by the transmitter constructively interferes with the tool body acoustic wave.', 'The use of this active cancellation approach, however, may present several challenges.', 'For example, with this approach, an extra transmitter is added to the tool, thereby increasing the expense, consuming energy and affecting overall reliability of the tool.', 'With active cancellation, both sources are fired simultaneously or near simultaneously, thereby requiring a relatively high degree of timing accuracy (a timing accuracy less than 1 microsecond (μs), for example).', 'To achieve sufficient constructive interference, active cancellation uses a relatively complex firing waveform.', 'The cancelled waveform may therefore, be a high voltage, complex waveform and moreover, the waveform may vary with tool position, well condition and potentially other factors.', 'In accordance with example implementations that are described herein, tool borne noise is passively attenuated from measured pressure signals, or traces, using signal processing instead of using active noise attenuation or using an attenuator.', 'In this context, “attenuating” tool borne noise refers to removing, or eliminating, at least part (if not all) of the tool borne noise.', 'More specifically, in accordance with example implementations, the sonic measurement tool \n100\n includes one or multiple tool motion sensors, such as one or multiple accelerometers \n134\n, depending on the particular implementation.', 'As described herein, in accordance with example implementations, the accelerometer \n134\n acquires a measurement, which represents the motion of the body of the sonic measurement tool \n100\n in response to the firing of an acoustic source, such as the source \n130\n.', 'The measurement by the accelerometer \n134\n, in turn, is decoupled from the well fluid and formation; and as such, the measurement may be considered to be closely related to the tool borne noise.', 'Therefore, based at least in part on measurements acquired by one or multiple such accelerometers \n134\n, the tool borne noise may be estimated and removed from the pressure measurements.', 'As a more specific example, in accordance with some implementations, each pressure sensor \n120\n may have an associated accelerometer \n134\n that is located near or at the pressure sensor \n120\n.', 'For example, in accordance with some implementations, a given pressure sensor \n120\n may have an associated accelerometer \n134\n that is located within one meter of the pressure sensor \n120\n.', 'The accelerometers \n134\n may or may not be disposed inside a pressure sealed chamber \n140\n, which houses electronics (such as a telemetry circuit \n141\n and a controller \n144\n, for example) of the sonic measurement tool \n100\n, depending on the particular implementation.', 'In accordance with example implementations, the accelerometers \n134\n are coupled to the tool body (such as coupled to the collar of the tool \n100\n, for example) and are not coupled to the well fluid.', 'Moreover, unlike conventional arrangements, the accelerometer \n134\n is constructed to sense energy in a frequency spectrum that is associated with the sonic pressure measurement.', 'For example, in accordance with some implementations, the accelerometer \n134\n may be sensitive to energy in a range from 1 to 150 kHz or above, for example.', 'Moreover, in accordance with example implementations, the accelerometer \n134\n may have one or multiple sensitive axes of measurement.', "For example, in accordance with some implementations, the accelerometer \n134\n may have a sensitive axis that is aligned with the tool's longitudinal axis to sense acceleration along this axis.", 'In accordance with example implementations, the accelerometer \n134\n may have multiple sensitive axes and accordingly, the accelerometers \n134\n may measure accelerations along multiple orthogonal axes (along three orthogonal axes, for example).', 'Although accelerometers are described herein as a specific example of tool motion sensors, other sensors may be used, in accordance with further example implementations.', 'For example, in accordance with some implementations, the sonic measurement tool may include velocity sensors, which acquire data representing a sensed velocity of the body of the sonic measurement tool.', 'Thus, referring to \nFIG.', '2A\n in conjunction with \nFIG.', '1\n, in accordance with some implementations, a technique \n200\n includes receiving (block \n204\n) data representing one or multiple measurements that are acquired by one or multiple tool motion sensors of a downhole sonic measurement tool and receiving (block \n206\n) data representing one or multiple measurements acquired by one or multiple pressure sensors of the sonic measurement tool.', 'The measurement(s) acquired by the pressure sensor(s) may be modified, pursuant to block \n208\n, based at least in part on the measurement(s) acquired by the tool motion sensor(s) to attentuate tool borne noise.', 'FIGS.', '3, 4, 5 and 6\n illustrate attenuation of tool borne noise in accordance with example implementations.', 'Referring to \nFIG.', '3\n in conjunction with \nFIG.', '1\n, the acoustic source \n130\n may be fired, resulting in emitted energy, as depicted at reference numeral \n304\n in a pressure versus time waveform \n300\n for the source \n130\n.', 'The firing of the acoustic source \n130\n produces energy that propagates through the tool body and arrives at the accelerometers \n134\n, as depicted in \nFIG.', '4\n.', 'In this manner, referring to \nFIG.', '4\n in conjunction with \nFIG.', '1\n, the accelerometers \n134\n-\n1\n, \n134\n-\n2\n, \n134\n-\n3\n, and \n134\n-\n4\n sense energy \n404\n that directly propagates from the source \n130\n to produce corresponding sensed acceleration signals \n402\n-\n1\n, \n402\n-\n2\n, \n402\n-\n3\n and \n404\n-\n4\n, respectively.', 'The tool borne energy directly propagating from the acoustic source \n134\n, in turn, combines with the energy propagating through the fluid and formation to result in composite pressure versus time waveforms \n500\n that are sensed by the sensors \n120\n, as illustrated in \nFIG.', '5\n.', 'In this manner, referring to \nFIG.', '5\n in conjunction with \nFIG.', '1\n, a time window \n510\n of the pressure versus time waveforms \n500\n is attributable to the tool borne noise.', 'In accordance with example portions of the sensed pressures, which are attributable to the tool borne noise, are identified and removed.', 'For example, in accordance with some implementations, the signals that are provided by the accelerometers \n134\n may be time integrated to derive corresponding tool body velocity versus time profiles.', 'From these velocity versus time profiles, the arrival time of the energy that propagates through the tool body may be estimated to correspondingly identify the time segments of the sensed pressure versus time waveforms, which are associated with the tool borne noise.', 'As such, as illustrated in \nFIG.', '5\n, the time window \n510\n may be identified so that the sensed pressures within the time window \n510\n subtracted from the pressure signals to derive compensated pressure signal \n610\n that are illustrated in \nFIG.', '6\n.', 'Thus, as depicted in \nFIG.', '6\n, tool borne noise has been substantially removed, if not eliminated, in a corresponding time window \n610\n of the pressure signal \n600\n.', 'Thus, referring to \nFIG.', '2B\n, in accordance with example implementations, a technique \n220\n includes receiving (block \n222\n) data representing one or multiple measurements that are acquired by one or multiple tool motion sensors of a sonic measurement tool and receiving (block \n224\n) data representing one or multiple measurements acquired by one or multiple pressure sensors of the sonic measurement tool.', 'The tool body velocity may then be determined, pursuant to block \n226\n, based at least in part on the measurement(s) acquired by the tool motion sensor(s).', 'In this manner, the tool motion sensors may be accelerometers, and determining the tool body velocity may involve time integrating the accelerations sent by the accelerometers.', 'The technique \n220\n includes estimating (block \n228\n) the arrival time(s) of the tool borne noise in the pressure sensor measurement(s) based on the determined tool body velocity.', 'The tool borne noise may then be determined, pursuant to block \n230\n, for each pressure sensor measurement based at least in part on the estimated arrival time(s) and the measurement(s) acquired by the pressure sensor(s).', 'The pressure sensor measurement(s) may then be modified (block \n232\n) based at least in part on the determined tool borne noise.', 'In accordance with further example implementations, a tool-borne noise compensating signal that is applied to the pressure amplitude that is sensed by a given pressure sensor of the sonic measurement tool may be pre-determined based on measurements that are acquired in a test environment (measurements made by placing the sonic measurement tool in a water pit, for example).', 'More specifically, in accordance with example implementations, the sonic measurement tool receives data representing a compensating signal, which was constructed based on a measurement acquired by a tool motion sensor of the sonic measurement tool downhole sonic measurement tool in a test environment.', 'The test environment can be a test well, water pit, or the like.', 'For example, the measurement can be taken in a test well, in which the borehole diameter is large that the tool, such that the tool and formation arrival are well separated in time and slowness thus having a “clean” tool-borne-noise signature that can be used as calibration.\n \nDownhole in the well, the sonic measurement tool receives data representing a measurement acquired by a pressure sensor of the sonic measurement tool; and the tool modifies the measurement acquired by the pressure sensor based at least in part on the compensating signal to attenuate tool borne noise.', 'In accordance with further example implementations, a more robust, baseline technique may be used to attenuate tool borne noise.', 'In this manner, through the duration of a job in which the sonic measurement tool is moved to different downhole locations and used to acquire measurements at these locations, the arrival time and signature of the tool borne noise remain relatively constant in the sensed accelerations, whereas the energy path experienced by the indirectly propagating energy from the acoustic source varies.', 'In this regard, at the different downhole locations of the sonic measurement tool, the energy propagating from the acoustic source may experience different mud types, formation types, borehole sizes, and so forth.', 'Based on this premise, the tool borne noise may be characterized with more “conditions,” and the noise may be eliminated with more accuracy, as compared to, for example, estimating the tool borne noise from a single firing for a particular depth of the sonic measurement tool.', 'Referring to \nFIG.', '2C\n, in accordance with example implementations, a technique \n250\n includes moving (block \n252\n) a sonic measurement tool downhole to the next downhole location at which pressure measurements are to be acquired.', 'Pursuant to the technique \n250\n, data representing one or multiple measurements acquired by one or multiple tool motion sensors of the sonic measurement tool are received (block \n254\n), as well as data representing one or multiple measurement(s) acquired by one or multiple pressure sensors of the sonic measurement tool (block \n256\n).', 'According to the technique \n250\n, a tool borne noise is then determined, pursuant to block \n258\n, for each pressure sensor measurement.', 'In response to determining (decision block \n260\n) that an update to the tool borne noise signature depth range is to be made, the sonic measurement tool is moved (block \n252\n) and blocks \n254\n, \n256\n and \n258\n are repeated.', 'Once all the measurements have been acquired, the technique \n250\n includes averaging, or stacking, the determined tool borne noises, pursuant to block \n262\n.', 'In this manner, the stacking averages out the varying conditions experienced by energy propagating through the fluid and surrounding formations at the different measurement locations of the tool \n100\n.', 'Accordingly, the pressure measurement(s) may then be compensated, pursuant to block \n264\n, based at least in part on the result of the stacking of the tool borne noises.', 'Referring to \nFIG.', '7\n, in accordance with some implementations, a data processing system \n700\n may be used for purposes of determining/identifying tool borne noise and compensating pressure measurements to attenuate the tool borne noise, as described herein.', 'Depending on the particular implementation, the data processing system \n700\n may be part of the sonic measurement tool (part of the controller \n144\n of the tool \n100\n, as depicted in \nFIG.', '1\n), may be part of an Earth-disposed processing system, may be part of a processing system disposed remotely from the well, and so forth, depending on the particular implementation.', 'In general, the data processing system \n700\n may be a processor-based architecture that is formed from one or multiple actual physical machines that are made up of actual hardware \n710\n and machine executable instructions \n750\n, or “software.”', 'In accordance with some implementations, the hardware \n710\n may include one or multiple processors \n714\n (one or multiple central processing units (CPUs), one or multiple CPU processing cores, and so forth).', 'The hardware \n710\n may further include a memory \n718\n, which may, for example, contain data representing acceleration measurements acquired by accelerometers of the sonic measurement tool, data representing measurements acquired by other tool motion sensors of the sonic measurement tool, data representing pressure measurements acquired by the pressure sensors of the sonic measurement tool, parameters related to techniques to model the tool borne noise as a function of sensed acceleration, and so forth.', 'The memory \n718\n may further store executable instructions that, when executed by the processor(s) \n714\n, cause the processor(s) \n714\n to perform some or all of one or more of the techniques that are described herein.', 'In general, the memory \n718\n is a non-transitory memory that may be formed from, as examples, semiconductor storage devices, memristors, magnetic storage devices, phase change memory devices, a combination of one or more of these storage technologies, and so forth, depending on the particular implementation.', 'In accordance with example implementations, the hardware \n710\n of the data processing system \n700\n may include various other components, such as one or multiple telemetry interfaces \n720\n (that communicate with the telemetry interface \n141\n of the tool \n100\n, for example), a display and so forth.', 'In accordance with some implementations, the display may display pressure measurements, tool borne noise-compensated pressure measurements, acceleration measurements, and so forth.', 'In accordance with some implementations, the machine executable instructions \n750\n may include, for example, instructions \n754\n that when executed by the processor(s) \n714\n may cause the processor(s) \n714\n to form a tool borne noise compensation engine that performs time integration of acceleration measurements, tool arrival estimation, transformation of sensed acceleration into tool borne noise compensations for pressure signals, attenuation of tool borne measurements to derive compensated pressure measurements, and so forth, as described herein.', 'In accordance with some implementations, the instructions \n754\n, when executed by the processor(s) \n714\n may cause the processor(s) \n714\n to form a tool borne compensation to apply a tool borne noise compensation signal that was derived from measurement(s) acquired in the test environment, as described herein.', 'Moreover, in accordance with example implementations, the machine executable instructions \n750\n may include one or multiple other sets of instructions to form various other components of the data processing system \n700\n, such as, for example, a set \n758\n of instructions that when executed cause the processor(s) \n714\n to form an operating system.', 'In accordance with further example implementations, all or part of the above-described processor-based architecture may be replaced by dedicated, hardwired circuitry or by an application specific integrated circuit (ASIC).', 'Thus, many implementations are contemplated, which are within the scope of the appended claims.', 'Although only a few example implementations have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example implementations without materially departing from this disclosure.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.', 'In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.', 'Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.', 'It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.'] | ['1.', 'A method comprising:\nreceiving data representing a measurement acquired by a pressure sensor of a downhole sonic measurement tool;\nreceiving data representing a measurement acquired by a tool motion sensor of the downhole sonic measurement tool; and\ndetermining a velocity of the downhole sonic measurement tool based at least in part on the measurement acquired by the tool motion sensor;\nestimating an arrival time of tool borne noise in the measurement acquired by the pressure sensor based on the velocity of the downhole sonic measurement tool;\ndetermining tool borne noise for the measurement acquired by the pressure sensor based at least in part on the estimated arrival time and the measurement acquired by the pressure sensor;\nmodifying the measurement acquired by the pressure sensor based at least in part on the tool borne noise;\nwherein the tool motion sensor comprises an accelerometer disposed proximate the pressure sensor and provides an acceleration signal.', '2.', 'The method of claim 1, wherein the tool borne noise comprises noise attributable to energy from a source of the downhole sonic measurement tool propagating through a body of the downhole sonic measurement tool.', '3.', 'The method of claim 1, wherein receiving data acquired by the tool motion sensor comprises receiving data acquired by a sensor disposed outside of a pressure sealed chamber in which electronics of the downhole sonic measurement tool are disposed.', '4.', 'The method of claim 1, wherein receiving the data representing the measurement acquired by the pressure sensor comprises receiving data representing movement of the downhole sonic measurement tool in response to energy produced by firing of a source of the sonic measurement tool.', '5.', 'The method of claim 1, wherein receiving data representing the measurement acquired by the tool motion sensor comprises receiving data representing energy sensed by the tool motion sensor in a frequency range of 1 to up to 150 kiloHertz.', '6.', 'The method of claim 1, wherein compensating the measurement acquired by the pressure sensor comprises determining a velocity of energy propagating along a tool body of the downhole sonic measurement tool from a sonic source of the downhole sonic tool and based on the identified velocity of energy, identifying a time segment of a pressure versus time profile associated with the tool borne noise.', '7.', 'The method of claim 1, wherein compensating the measurement acquired by the pressure sensor comprises:\nmoving the sonic measurement tool to a downhole position;\nacquiring the measurement of the tool motion sensor when the sonic measurement tool is at the given downhole position;\nacquiring the measurement by the pressure sensor when the sonic measurement tool is at the given downhole location;\nrepeating acquiring the measurements of the tool motion and pressure at one or more other downhole locations of the sonic measurement tool; and\ndetermining the tool borne noise based at least in part on results of the measurements of the pressure and the tool motion at the locations of the sonic measurement tool.', '8.', 'The method of claim 7, wherein determining the tool borne noise based on the measurements of pressure and tool motion at the downhole locations of the sonic measurement tool comprises stacking estimated tool borne noises derived from the measurements of pressure and tool motion at each of the downhole locations.', '9.', 'The method of claim 8, wherein the stacking relies on differences in the formation or well properties affecting propagation of energy from the sonic source through well fluid or through a formation.', '10.', 'An article comprising non-transitory computer readable storage medium to store instructions that when executed by a processor-based system cause the processor-based system to:\nreceive data representing a measurement acquired by a pressure sensor of a downhole sonic measurement tool;\nreceive data representing a measurement acquired by a tool motion sensor of the downhole sonic measurement tool;\ndetermine a velocity of the downhole sonic measurement tool based at least in part on the measurement acquired by the tool motion sensor;\nestimate an arrival time of tool borne noise in the measurement acquired by the pressure sensor based on the velocity of the downhole sonic measurement tool;\ndetermine tool borne noise for the measurement acquired by the pressure sensor based at least in part on the estimated arrival time and the measurement acquired by the pressure sensor; and\nmodify the measurement acquired by the pressure sensor based at least in part on the measurement acquired by the tool motion sensor to attenuate tool borne noise;\nwherein the tool motion sensor comprises an accelerometer disposed proximate the pressure sensor.\n\n\n\n\n\n\n11.', 'The article of claim 10, wherein the tool borne noise comprises noise attributable to energy from a source of the downhole sonic measurement tool propagating through a body of the downhole sonic measurement tool.\n\n\n\n\n\n\n12.', 'The article of claim 10, the computer readable storage medium storing instructions that when executed by the processor-based system cause the processor-based system to receive data acquired by a sensor disposed outside of a pressure sealed chamber in which electronics of the downhole sonic measurement tool are disposed.', '13.', 'The article of claim 10, the computer readable storage medium storing instructions that when executed by the processor-based system cause the processor-based system to receive data representing movement of the sonic measurement tool in response to energy produced by firing of a source of the downhole sonic measurement tool.\n\n\n\n\n\n\n14.', 'An article comprising non-transitory computer readable storage medium to store instructions that when executed by a processor-based system cause the processor-based system to:\nreceive data representing a measurement acquired by a pressure sensor of a downhole sonic measurement tool downhole in the well;\nreceive data representing a compensating signal based on a measurement acquired by a tool motion sensor of a downhole sonic measurement tool in a test environment;\ndetermine a velocity of the downhole sonic measurement tool based at least in part on the measurement acquired by the tool motion sensor;\nestimate an arrival time of tool borne noise in the measurement acquired by the pressure sensor based on the velocity of the downhole sonic measurement tool;\ndetermine tool borne noise for the measurement acquired by the pressure sensor based at least in part on the estimated arrival time and the measurement acquired by the pressure sensor; and\nmodify the measurement acquired by the pressure sensor based at least in part on the compensating signal to attenuate tool borne noise;\nwherein the tool motion sensor comprises an accelerometer disposed proximate the pressure sensor.'] | ['FIG.', '1 is an illustration of a sonic measurement tool in a borehole according to an example implementation.;', 'FIGS.', '2A, 2B and 2C are flow diagrams depicting techniques to compensate measurements acquired by a downhole sonic measurement tool to attenuate tool borne noise according to example implementations.; FIG.', '3 is an illustration of a pressure versus time waveform produced by the firing of a source of the sonic measurement tool according to an example implementation.', '; FIG.', '4 illustrates acceleration versus time waveforms sensed by accelerometers of the sonic measurement tool in response to the firing of the source according to an example implementation.; FIG.', '5 illustrates pressure versus time waveforms sensed by pressure sensors of the sonic measurement tool in response to the firing of the source according to an example implementation.; FIG.', '6 illustrates pressure versus time waveforms produced by applying compensation to the pressure versus time waveforms of FIG.', '5 to remove tool borne noise according to an example implementation.', '; FIG. 7 is a schematic diagram of a data processing system according to an example implementation.; FIGS. 3, 4, 5 and 6 illustrate attenuation of tool borne noise in accordance with example implementations.', 'Referring to FIG.', '3 in conjunction with FIG.', '1, the acoustic source 130 may be fired, resulting in emitted energy, as depicted at reference numeral 304 in a pressure versus time waveform 300 for the source 130.', 'The firing of the acoustic source 130 produces energy that propagates through the tool body and arrives at the accelerometers 134, as depicted in FIG.', '4.', 'In this manner, referring to FIG.', '4 in conjunction with FIG.', '1, the accelerometers 134-1, 134-2, 134-3, and 134-4 sense energy 404 that directly propagates from the source 130 to produce corresponding sensed acceleration signals 402-1, 402-2, 402-3 and 404-4, respectively.'] |
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US11073013 | Electric dipole surface antenna configurations for electromagnetic wellbore instrument telemetry | Dec 17, 2015 | Dean M. Homan, Jon Brunetti, David L. Smith, Erwann Lemenager | SCHLUMBERGER TECHNOLOGY CORPORATION | International Preliminary Report on Patentability issued in International Application PCT/US2015/066496 dated Jun. 20, 2017. 14 pages.; International Search Report and Written Opinion issued in International Application PCT/US2015/066496 dated Mar. 7, 2016. 18 pages. | 4523148; June 11, 1985; Maciejewski; 4739325; April 19, 1988; MacLeod; 5359324; October 25, 1994; Clark; 5883516; March 16, 1999; Van Steenwyk et al.; 7145473; December 5, 2006; Wisler et al.; 20040222901; November 11, 2004; Dodge; 20050133262; June 23, 2005; Chen; 20050167098; August 4, 2005; Lovell et al.; 20100017156; January 21, 2010; Ziolkowski et al.; 20110017512; January 27, 2011; Codazzi; 20110168446; July 14, 2011; Lemenager; 20140292592; October 2, 2014; Gosling; 20160356911; December 8, 2016; Wilson | Foreign Citations not found. | ['An apparatus for detecting an electromagnetic signal originating in a wellbore includes an antenna comprising a pair of spaced apart electrodes in the ground spaced apart by a first distance having a midpoint at a second distance from the wellbore.', 'The system includes at least one of a shielded electrical cable connecting each electrode to an input of a detector circuit, wherein the shielding is connected to produce common mode noise rejection; b) a second spaced apart electrode pair antenna spaced apart by one half the first distance and having a midpoint spaced √2/2 times the second distance from the surface of the wellbore, c) a second electrode pair antenna having a common midpoint with and being orthogonal to the at least one electric dipole antenna; and d) wherein the at least one electric dipole antenna is disposed in a second wellbore, the second wellbore having substantially no electrically conductive pipe therein.'] | ['Description\n\n\n\n\n\n\nCROSS REFERENCE TO RELATED APPLICATIONS', 'The present application claims the benefit of, and priority to, U.S. Provisional Patent Application No. 62/093,910, filed Dec. 18, 2014, which is hereby incorporated by reference in its entirety.', "BACKGROUND\n \nThis disclosure is related to the field of electromagnetic telemetry used to communicate signals from instruments disposed in a wellbore to the Earth's surface.", 'More particularly, the disclosure relates to antenna configurations used to detect electromagnetic telemetry signals emitted by such instruments.', 'U.S. Patent Application Publication No. 2011/0168446A1 and U.S. Pat.', "No. 7,145,473 B2 describe examples of electromagnetic telemetry for communicating signals between equipment disposed at the Earth's surface and LWD and/or MWD instruments in a wellbore.", 'One type of electromagnetic telemetry known in the art includes a an electric dipole antenna formed by an insulated gap between conductive segments on a drill collar associated with the MWD and/or LWD instruments, or by a toroid disposed on the outer surface of the collar.', 'A time varying voltage impressed across the insulated gap (or the toroid) generates an electromagnetic field which can be used to communicate between a surface electric dipole receiver antenna or a plurality of differently oriented electric dipole antennas and the MWD/LWD instrument.', 'See the basic concept shown in \nFIG.', '1\n.', 'A surface transceiving sensor, i.e., a dipole antenna, may be composed of an electrode placed in the ground a selected distance from a drilling unit or “rig” and the well casing.', 'The voltage between the electrode and the well casing is measured and signals from the MWD and/or LWD instruments encoded into the transmitted electromagnetic field are decoded from the measured voltages.', 'Conversely, voltage imparted across the casing and electrode may induce an electromagnetic field in the subsurface that is detectable by the dipole antenna or toroid on the MWD/LWD instrument and internally decoded.', 'The foregoing signal communication from wellbore to surface may be referred to as “uplink” communication and the surface to wellbore communication may be referred to as “downlink” communication.', 'Referring to \nFIG.', '1\n, an electromagnetic telemetry system known in the art is shown to explain the basic components thereof.', 'U.S. Patent Application Publication No. 2011/0168446A1 and U.S. Pat.', 'No. 7,145,473B2 referred to above describe adaptations of the system shown in \nFIG.', '1\n and may be referred to for more details.', 'A drilling unit or “rig” is shown generally at \n28\n and has equipment (not shown separately) to raise, lower and rotate a drill string \n18\n with a bottom hole assembly (BHA) \n23\n at its lower end.', 'A drill bit \n26\n is disposed at the longitudinal end of the BHA \n23\n and is rotated, either by the drilling unit \n28\n and/or a motor (not shown) in the drill string \n18\n to axially extend the length of a wellbore \n11\n.', 'When the wellbore \n11\n is initialed drilled to a selected depth, a casing \n14\n may be inserted into the wellbore \n11\n and cemented in place.', 'Drilling may then resume.', 'The BHA \n23\n may include an MWD and/or LWD instrument, shown generally at \n23\nA. The MWD/LWD instrument may be any type known in the art and may include sensors (not show separately) for measuring orientation of the BHA \n23\n, as well as sensors for measuring shock and vibration of the BHA \n23\n, and/or sensors for measuring one or more physical parameters of the formations (including conductive layers \n16\n and a reservoir formation \n20\n) through which the instrument \n23', 'A passes during drilling and any subsequent movement within or along the wellbore \n11\n.', 'Such physical parameters may be of any kind known in the art, and may include, without limitation, electrical resistivity, acoustic velocity, natural gamma radiation, spectrally analyzed natural gamma radiation, density, neutron porosity and/or capture cross section, and nuclear magnetic resonance relaxation times.', 'The foregoing are only examples and in no way are intended to limit the scope of the present disclosure.', 'In the present example circuitry (not shown) in the instrument \n23\nA may be used to impart a time varying voltage across an insulating gap \n24\n disposed between conductive components \n22\n, \n22\nA of the instrument \n23\nA.', 'The circuitry (not shown) in the instrument \n23\nA may include devices to encode measurements from the various sensors (not shown) in the instrument into the time varying voltage.', 'The imparted voltage generates a time varying electromagnetic field in the formations \n20\n, \n16\n which includes the encoded measurement data.', 'In the present example, a voltage induced between an electrode \n12\n inserted into the ground at a selected distance from the drilling rig \n28\n and the casing \n14\n may be measured and decoded into data encoded into the time varying voltage by a surface measurement and decoding system, shown generally at \n10\n and which may be of any type known in the art.', 'Electrical noise may be induced in any device used to detect the electromagnetic telemetry signal.', 'Sources of such electrical noise may include surface-induced low frequency noise.', "Such noise may be induced by poor grounding of drilling rig power generators and low frequency vibration of the steel drilling rig structure in the presence of the Earth's magnetic field, among other sources.", 'SUMMARY\n \nAn apparatus according to one aspect of the disclosure for detecting an electromagnetic signal originating in a wellbore includes an electric dipole antenna.', 'The electric dipole antenna may include a pair of spaced apart electrodes in the ground spaced apart by a first distance and having a point between the electrodes at a second distance from the surface of the wellbore.', 'The system includes at least one of: a) a shielded electrical cable connecting each electrode to an input of a detector circuit, wherein the shielding is connected to produce common mode noise rejection; b) a second spaced apart electrode pair antenna spaced apart by one half the first distance and having a midpoint spaced √2/2 times the second distance from the surface of the wellbore a connected in inverse polarity to the at least one antenna; c) a second electrode pair antenna having a common point with and being orthogonal to the at least one electric dipole antenna and electrically connected thereto; and d) wherein the at least one electric dipole antenna is disposed in a second wellbore, the second wellbore having substantially no electrically conductive pipe therein.', 'The apparatus may also include a voltage measuring circuit connected to an input of the at least one electric dipole antenna.', 'A method for detecting an electromagnetic signal originating in a wellbore according to another aspect includes measuring a voltage induced by the electromagnetic field in at least one electric dipole antenna.', 'The electric dipole antenna may include a pair of electrodes spaced apart by a first distance and spaced at a midpoint therebetween from a surface of the wellbore by a second distance.', 'A method according to this aspect further includes at least one of: a) a shielded electrical cable connects each electrode to an input of a detector circuit, wherein the shielding is connected to produce common mode noise rejection; b) a second spaced apart electrode pair antenna spaced apart by one half the first distance and having a midpoint spaced √2/2 times the second distance from the surface of the wellbore is connected to the at least one electric dipole antenna in inverse polarity, c) a second electrode pair antenna having a common midpoint with and being orthogonal to the at least one electric dipole antenna is connected therewith; and d) wherein the at least one electric dipole antenna is disposed in a second wellbore, the second wellbore having substantially no electrically conductive pipe therein.', 'Other aspects and advantages will be apparent from the description and claims that follow.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n shows an example electromagnetic telemetry system known in the art prior to the present disclosure.\n \nFIG.', '2\n shows one example embodiment of a drilling, measurement and telemetry system.', 'FIG.', '3A\n shows one example embodiment of an electromagnetic signal transmitter.', 'FIG.', '3B\n shows another example embodiment of an electromagnetic signal transmitter.\n \nFIG.', '4\n shows an example embodiment of an electrode arrangement and connecting cables therefor.\n \nFIG.', '5\n shows an example of crossed electric dipole antennas that may be used in some embodiments.\n \nFIG.', '6\n shows another example arrangement of electrodes and connecting cables.\n \nFIG.', '7\n shows an example dipole antenna disposed in a monitor wellbore.', 'DETAILED DESCRIPTION\n \nFIG.', '2\n shows an example embodiment of a drilling and measurement system that may be used in various embodiments according to the present disclosure.', 'The system \n110\n shown in \nFIG.', '2\n may be deployed in either onshore or offshore applications.', 'In a system \n110\n as shown in \nFIG.', '2\n, a wellbore \n111\n may be formed in subsurface formations by rotary drilling in a manner that is well known in the art.', 'Although the wellbore \n111\n in \nFIG.', '2\n is shown as being drilled substantially straight and vertically, the wellbore \n111\n may be directionally drilled, including having a substantially horizontal section, with equal effect as a substantially vertical wellbore.', 'A drill string \n112\n is suspended within the wellbore \n111\n and may have a bottom hole assembly (BHA) \n100\n which includes a drill bit \n105\n at its lower end.', 'The system \n110\n includes a platform and derrick assembly \n110\nA positioned over the wellbore \n111\n.', 'The platform and derrick assembly \n110\nA includes a rotary table \n116\n, a kelly \n117\n, a hook \n118\n and a rotary swivel \n119\n.', 'In a drilling operation, the drill string \n112\n may be rotated by the rotary table \n116\n (energized by means not shown), which engages the kelly \n117\n at the upper end of the drill string \n112\n.', 'The kelly \n117\n is suspended from the hook \n118\n.', 'The hook \n118\n may be attached to a traveling block (not shown), through the kelly \n117\n and the rotary swivel \n119\n which permits rotation of the kelly \n117\n and thereby the drill string \n112\n relative to the hook \n118\n.', 'As is well known, a top drive system could be used in other embodiments with equal effect substituting the kelly \n117\n, rotary table \n116\n and swivel \n119\n.', 'Accordingly, the scope of the disclosure is not limited to using a platform and derrick assembly \n110\nA that has a kelly, rotary table and swivel.', 'Drilling fluid or mud \n126\n may be stored in a pit \n127\n formed at the well site (or on a drilling platform in marine drilling).', 'A pump \n129\n moves the drilling mud \n126\n from the tank or pit \n127\n to the interior of the drill string \n112\n via a port in the swivel \n119\n, which causes the drilling fluid \n126\n to flow downwardly through the drill string \n112\n, as indicated by directional arrow \n108\n.', 'The drilling mud \n126\n exits the drill string \n112\n via ports (not shown) in the drill bit \n105\n, and then circulates upwardly through an annular space region between the outside of the drill string \n112\n and the wall of the wellbore \n111\n, as indicated by directional arrows \n109\n.', 'In this known manner, the drilling mud \n126\n lubricates and cools the drill bit \n105\n and carries formation cuttings up to the surface as it is returned (after removal of entrained drill cuttings and other contaminants) to the pit \n127\n for recirculation.', 'The BHA \n100\n is shown as having one MWD module \n130\n and one or more LWD modules \n120\n with reference number \n120\nA depicting an electromagnetic signal transmitter.', 'As used herein, the term “module” as applied to the MWD and LWD devices is understood to mean either a single measuring instrument or multiple measuring instruments contained in a single modular device, or multiple modular devices.', 'Additionally, the BHA \n100\n may include a rotary steerable directional drilling system (RSS) and motor \n150\n or a steerable drilling motor.', 'The LWD module(s) \n120\n may be housed in a drill collar and can include one or more types of well logging sensors.', 'The LWD module(s) \n120\n may include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment.', 'By way of example, the LWD module(s) \n120\n may include one or more of a nuclear magnetic resonance (NMR) logging tool, a nuclear logging tool, a resistivity logging tool, an acoustic logging tool, or a dielectric logging tool, and so forth, and may include capabilities for measuring, processing, and storing information, and for communicating with the surface equipment (e.g., by suitably operating the electromagnetic signal transmitter \n120\nA).', 'The MWD module \n130\n may also be housed in a drill collar, and may contain one or more devices for measuring characteristics of the drill string \n112\n and drill bit \n105\n.', 'In the present embodiment, the MWD module \n130\n may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick/slip measuring device, a direction measuring device, and an inclination measuring device (the latter two sometimes being referred to collectively as a “D&I package”).', 'The MWD module \n130\n may further include an apparatus (not shown) for generating electrical power for the MWD module \n130\n and the LWD module(s) \n120\n.', 'For example, electrical power generated in the MWD module \n130\n may be used to power the MWD module \n130\n and the LWD module(s) \n120\n.', 'In the present example embodiment, the electrical power may be generated by a mud flow driven turbine generator (not shown) or may be stored in batteries (not shown) and may be used to operate the measurement devices in the respective modules \n120\n, \n130\n and the electromagnetic signal transmitter \n120\nA. Any of the LWD module(s) \n120\n and the MWD module \n130\n may include circuitry to drive the electromagnetic signal transmitter \n120\nA to generate an encoded electromagnetic signal that includes any or all of the various sensor measurements made by the devices in the respective modules \n120\n, \n130\n.', 'The electromagnetic signal transmitter \n120\nA may be, for example and without limitation an insulating gap disposed between electrodes, wherein a time varying voltage corresponding to the electromagnetic transmitter signal to be generated is imparted across the electrodes.', 'In other embodiments, the electromagnetic transmitter \n120\nA may be a toroidal wire coil through which a time varying electrical current is passed.', 'The amplitude of the time varying current may correspond to the electromagnetic transmitter signal that is to be generated.', 'The wellbore \n111\n may include a casing \n155\n inserted, and in some embodiments cemented therein to a selected depth in the wellbore \n111\n.', 'The foregoing examples of an electromagnetic signal transmitter are shown in \nFIGS.', '3A and 3B\n, respectively.', 'In \nFIG.', '3A\n, a transmitter driver \n120\nE may be in signal communication at its input with a telemetry encoder (not shown separately) in either of the MWD module (\n130\n in \nFIG.', '3\n) or the LWD module (\n120\n in \nFIG.', '3\n).', 'The transmitter driver \n120\nE output may be coupled to a toroidal coil \n120\nC disposed in a recess on the exterior of a drill collar \n120\nB in which the functional components of the electromagnetic signal transmitter \n120\nA may be disposed.', 'The toroidal coil \n120\nC may be covered on its exterior by a wear resistant shield \n120\nD. \nFIG.', '3B\n shows another example embodiment of the electromagnetic signal transmitter \n120\nA, in which the transmitter driver \n120\nE has its output electrically connected to first electrodes \n120\nF electrically isolated by insulators \n120\nH from a second electrode \n120\nG. In the present example embodiment, a time varying voltage corresponding to the encoded electromagnetic telemetry signal may be imparted across the first \n120\nF and second \n120\nH electrodes.', 'For both the foregoing embodiments, the time varying current or voltage induces an electromagnetic field in the formations surrounding the electromagnetic signal transmitter \n120\nA, one or more components of which may be detected as will be further explained below.', 'Returning to \nFIG.', '2\n, the detected electromagnetic telemetry signals may be processed in a surface recording and control system \n152\n located at the surface, in some embodiments proximate the platform and derrick assembly \n110\nA.', 'The surface recording and control system \n152\n may include one or more processor-based computing systems.', 'In the present context, a processor or processor-based computing system may include a microprocessor, programmable logic devices (PLDs), field-gate programmable arrays (FPGAs), application-specific integrated circuits (ASICs), system-on-a-chip processors (SoCs), or any other suitable integrated circuit capable of executing encoded instructions stored, for example, on tangible computer-readable media (e.g., read-only memory, random access memory, a hard drive, optical disk, flash memory, etc.).', 'Such instructions may correspond to, for example, workflows and the like for carrying out a drilling operation, algorithms and routines for processing data received at the surface from the BHA \n100\n (e.g., as part of an inversion to obtain one or more desired formation parameters), and the like.', 'The surface recording and control system \n152\n may include circuitry (not shown separately in \nFIG.', '2\n) for detecting and decoding signals induced in one or more dipole antennas as a result of the electromagnetic telemetry signals as will be further explained below.', 'Having shown example embodiments of a wellbore drilling and measuring system, including an electromagnetic telemetry signal transmitter forming part of a set of wellbore drilling and measuring instruments, example methods and apparatus for detecting the electromagnetic telemetry signal for decoding and processing thereof will now be explained with reference to \nFIGS.', '4 through 7\n.', 'The methods and apparatus to be described below may use electric dipole antennas.', 'Voltages corresponding to amplitudes of electromagnetic fields may be induced in such antennas as is known in the art.', 'The voltage V induced on an electric dipole antenna by an electromagnetic field source far away (e.g., in the “far field” of the electromagnetic signal transmitter \n120\nA in \nFIG.', '2\n) wherein the dipole antenna is aligned radially with a drilling system (\n110\nA in \nFIG.', '2\n) or wellbore casing (\n155\n in \nFIG.', '2\n), that is, disposed along a line extending radially outwardly therefrom, may be determined by the expression:\n \n \n \n \n \n \n \n \nV\n \n=\n \n \n \n \n \nωμ\n \n0\n \n \n\u2062\n \nP\n \n \n \n4\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \n \nr\n \n3\n \n \n \n \n\u2062\n \n \n(\n \n \n1\n \n-\n \nikr\n \n \n)', '\u2062\n \n \ne\n \n \n-\n \nikr\n \n \n \n \n \n \n \n \n(\n \n1\n \n)\n \n \n \n \n \n \n \n \nwherein ω represents the angular frequency of the field induced by the electromagnetic signal transmitter (\n120\nA in \nFIG.', '2\n), μ\n0 \nrepresents the dielectric permittivity of free space, r represents the radial distance between the antenna poles (i.e., the length of the dipole) and P represents the electromagnetic signal transmitter electric field amplitude.', 'e represents the natural logarithm base and i represents the imaginary number √−1 in the above equation.', 'An electric dipole noise source having a low frequency (e.g., less than 100 Hz) located near the dipole antenna may induce voltage in the dipole antenna that may be expressed as:\n \n \n \n \n \n \n \n \n \n \nV\n \ni\n \nn\n \n \n=\n \n \n \nE\n \n_\n \n \nn\n \n \n \n\u2063\n \n \n \n \n·\n \n \n \nd\n \n_\n \n \ni\n \n \n \n=\n \n \n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \n \nμ\n \n0\n \n \n\u2062\n \n \nω\n \nn\n \n \n\u2062\n \n \nI\n \nn\n \n \n \n \n4\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \n \nx\n \n2\n \n \n \n \n\u2061\n \n \n[\n \n \n \n(\n \n \n \nx\n \n^\n \n \n×\n \n \n \nd\n \n_\n \n \nn\n \n \n \n)\n \n \n·\n \n \n(\n \n \n \nx\n \n^\n \n \n×\n \n \n \nd\n \n_\n \n \ni\n \n \n \n)\n \n \n \n]\n \n \n \n \n,\n \n \ni\n \n=\n \nx\n \n \n,\n \ny\n \n \n \n \n \n \n(\n \n2\n \n)\n \n \n \n \n \n \n \n where \n \nd\nn\n=a cos(α){circumflex over (x)}+a sin (α)ŷ\n \nd\nx\n=L{circumflex over (x)}\n \nd\ny\n=Lŷ\n \nThe induced noise voltage on each of two orthogonal, collocated electric dipole antennas Px, Py may be expressed as:\n \n \n \n \n \n \n \n \n \n \nV\n \nx\n \n \n=\n \n \n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \n \nμ\n \n0\n \n \n\u2062\n \n \nω\n \nn\n \n \n\u2062\n \n \nI\n \nn\n \n \n \n \n4\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \n \nx\n \n2\n \n \n \n \n\u2062\n \naL\n \n\u2062\n \n \n \n \n\u2062\n \nsin\n \n\u2062\n \n \n \n \n\u2062\n \n \n(\n \nα\n \n)', '\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \ny\n \n \n=\n \n \n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \n \nμ\n \n0\n \n \n\u2062\n \n \nω\n \nn\n \n \n\u2062\n \n \nI\n \nn\n \n \n \n \n4\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \n \nx\n \n2\n \n \n \n \n\u2062\n \naL\n \n\u2062\n \n \n \n \n\u2062\n \n \ncos\n \n\u2061\n \n \n(\n \nα\n \n)\n \n \n \n \n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n In the above expressions, x and y are Cartesian coordinates of a coordinate system having the casing (\n155\n in \nFIG.', '2\n) as the origin (0, 0), {circumflex over (x)} and ŷ are unit vectors in the respective x and y coordinate axes, and L represents an arbitrary distance from the casing (\n155\n in \nFIG.', '2\n).', 'α represents the angle subtended between the direction of the dipole antenna and the x axis, ω\nn \nrepresents the angular frequency of the noise source and I\nn \nrepresents the current amplitude of the noise source.', 'From the foregoing equations it is possible to form some conclusions about the electromagnetic telemetry signal and drilling system generated noise as will be explained in more detail below.', 'Although the above expressions use Cartesian coordinates, it should be understood that any other coordinate system including, for example and without limitation polar coordinates may be used with equal effect and the coordinate system chosen is not intended to limit the scope of the present disclosure.', 'FIG.', '4\n shows a schematic dipole antenna arrangement wherein the electromagnetic signal transmitter current density is shown at \n156\n.', 'A \n160\nC shield of a “twinax” cable \n158\n (a cable including a twisted pair of insulated electrical conductors \n160\nA and \n160\nB disposed inside an electrically conductive shield \n160\nC) may have one of the two conductors \n160\nA thereof in the present example connected to a first coaxial cable \n159\n and thence connected to an electrode \n153\n of the dipole antenna \n161\n disposed nearest the drilling system \n110\nA or casing \n155\n at a distance L from the drilling system \n110\nA or casing \n155\n.', 'The other twinax cable \n158\n insulated, shielded electrical conductor \n160\nB may be connected to another length of coaxial cable \n159\n, the interior conductor of which may be connected to another ground electrode \n153\nA disposed at a distance 3L from the drilling system \n110\nA or casing \n155\n.', 'The twinax cable \n158\n may extend to a voltage measuring circuit forming part of the receiver electronics in the surface recording and control system (\n152\n in \nFIG.', '2\n).', 'The radial direction of a line connecting the two electrodes \n153\n, \n153\nA may be selected to correspond to the direction of the current density \n156\n.', 'Such direction may be determined based on the orientation of the electromagnetic signal transmitter (\n120\nA in \nFIG.', '2\n) in the wellbore (\n111\n in \nFIG.', '2\n).', 'The receiver circuitry may have a balanced front end, composed of an instrumentation amplifier or differential amplifier.', 'In the present example embodiment, a normal input (+) to the amplifier \n160\n may be electrically connected to one electrode \n153\nA, and an inverting input (−) thereof may be electrically connected to the other electrode \n153\n of the dipole antenna \n161\n.', 'The twinax cable \n158\n shield \n160\nC may be connected to a center tap resistor or transformer tap \n163\n the end terminals of which may be connected between the normal (+) and inverting (−) inputs to the amplifier \n160\n.', 'The foregoing example balanced front end configuration may be expected to substantially cancel any stray capacitance in the twinax cable \n158\n and the coaxial cables \n159\n and may maximize common mode rejection to the input of the amplifier \n160\n.', 'The foregoing cable configuration between the amplifier and the electrodes \n153\n, \n153\nA may be expected to provide an observable decrease in electrical noise originating from the drilling system \n110\nA.', 'In other embodiments, the electrodes \n153\n, \n153\nA of the dipole antenna \n161\n may each be connected to the respective inputs (+), (−) of the amplifier \n160\n using the interior conductor of a separate coaxial cable \n159\n extending from each amplifier input to each electrode \n153\n, \n153\nA. Both coaxial cable shields may be connected to the center tap as shown in \nFIG.', '4\n.', 'Referring to \nFIG.', '5\n, a further reduction in electrical noise induced by the drilling system \n110\nA, shown as an arrow indicating an electric dipole P\nnoise \nin the figure, may be obtained using the assumption that the electric field (or current density) of the electromagnetic telemetry signal is oriented radially outwardly, i.e., along the ρ direction as shown at \n156\n, from the casing \n155\n and that the magnetic field thereof is in the o-direction, transverse to the electric field direction ρ.', 'It may be assumed the electromagnetic telemetry signal is predominantly received on the electric dipole antenna P\nρ\n extending in the ρ direction and noise induced by the drilling system \n110\nA may be an electric dipole randomly oriented at an angle α with respect to the telemetry signal electric dipole direction ρ.', 'A second electric dipole antenna, shown as P\nØ\n may be oriented substantially perpendicularly to the electric dipole antenna, shown as Pρ and predominantly detect only the electrical noise generated by the drilling system \n110\nA, because the second dipole antenna is substantially insensitive to the electric field of the electromagnetic telemetry signal.', 'Then the difference between the voltage in antenna Pρ and that induced in antenna P\nØ\n is less sensitive to noise as shown in the voltage equation below: \n \nV=V\nρ\n−V\nφ\n,\u2003\u2003(4)', 'The induced voltages on each of the orthogonal dipole antennas P\nρ \nP\nØ\n may be represented by the expressions: \n \nV\nρ\n=V\nsignal\n+V\nnoise \ncos(α) \n \nV\nφ\n≈V\nnoise \nsin(α),\u2003\u2003(5) \n where α is the angle between the radial direction of the Pρ antenna and the unknown direction of the noise electric dipole P\nnoise\n.', 'A difference signal as expressed in Eq.', '(4) may be obtained, for example, by electrical connection of the Pρ dipole antenna to a normal input (+) of an operational amplifier (see \nFIG.', '4\n) and electrical connection of the orthogonal dipole antenna Pρ to the inverting input (−) thereof.', 'V=V\nsignal\n+V\nnoise\n(cos(α)−sin(α))', '(6) \n \nIt is within the scope of the present disclosure to place the above described crossed dipoles around the drilling system \n110\nA at such a position and orientation that the difference between the sine and cosine terms are nearly zero, that is at α of 45° and 225° so as to reduce drilling system induced noise.', 'If the noise amplitude is relatively large compared to the electromagnetic telemetry signal amplitude, then it is possible to use the ratio V\nφ\n/V\nρ\n=V tan(α) to solve for α.', 'The dipole antennas P\nρ \nP\nØ\n may then be moved about the drilling system \n110\nA to a new crossed-dipole antenna orientation.', 'α□ tan\n−1\n(\nV\nφ\n/V\nρ\n)\u2003\u2003(7) \n \nAnother method to reduce noise is to observe that the near-field noise is strongly radial distance sensitive, while the far-field electromagnetic telemetry signal is relatively constant with respect to radial distance from the casing \n155\n.', 'Therefore, constructing two antennas A\n1\n, A\n2\n that are anti-parallel, where one antenna A\n1\n is half the length (L) of the other antenna A\n2\n (length 2L) and centered, respectively at distances of √2(L) and 2(L) from the casing \n155\n as shown in \nFIG.', '6\n may enable further noise reduction.', 'When the difference between the voltages induced in each of the foregoing two antennas is measured, the noise amplitude is reduced to near zero, while the electromagnetic telemetry signal amplitude is only halved.', 'The foregoing relies on the near field and far field properties of the respective electromagnetic field sources:\n \n \n \n \n \n \n \n \n \nV\n \n=\n \n \n \nV\n \nρ1\n \n \n-\n \n \nV\n \nρ2\n \n \n \n \n,\n \n \n \n \n \n(\n \n8\n \n)\n \n \n \n \n \n \nwhere\n \n \n \n \n \n \n \n \n \n \n \n \n \n \nV\n \nρ1\n \n \n\u2061\n \n \n(\n \n \nx\n \n1\n \n \n)\n \n \n \n≈\n \n \n \nV\n \nsignal\n \n \n+\n \n \n \nV\n \n \nnoise\n \n\u2062\n \n \n \n \n \n \n\u2062\n \n \n \n \n\u2062\n \n \n(\n \n \nx\n \n1\n \n \n)', '\u2062\n \n \n \n \n \n\u2062\n \n \n \nV\n \nρ2\n \n \n\u2061\n \n \n(\n \n \nx\n \n2\n \n \n)\n \n \n \n=\n \n \n \n \nV\n \nsignal\n \n \n2\n \n \n+\n \n \n \n \nV\n \n \nnoise\n \n\u2062\n \n \n \n \n \n \n\u2061\n \n \n(\n \n \nx\n \n2\n \n \n)\n \n \n \n.', '(\n \n9\n \n)', 'The difference between voltages induced in the respective antennas A\n1\n, A\n2\n is substantially equal to zero: \n \nV\nnoise\n(\nx\n1\n)−\nV\nnoise\n(\nx\n2\n)=0\u2003\u2003(10) \n that is, when the conditions below are met for each antenna A\n1\n, A\n2\n: \n \n \n \n \n \n \n \n \n \n \n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \n \nμ\n \n0\n \n \n\u2062\n \n \nω\n \nn\n \n \n\u2062\n \n \nI\n \nn\n \n \n \n \n4\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \n \nx\n \n1\n \n2\n \n \n \n \n\u2062\n \n \naL\n \n1\n \n \n\u2062\n \n \ncos\n \n\u2061\n \n \n(\n \nα\n \n)', '=\n \n \n \n \ni\n \n\u2062\n \n \n \n \n\u2062\n \n \nμ\n \n0\n \n \n\u2062\n \n \nω\n \nn\n \n \n\u2062\n \n \nI\n \nn\n \n \n \n \n4\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \n \nx\n \n2\n \n2\n \n \n \n \n\u2062\n \n \naL\n \n2\n \n \n\u2062\n \n \ncos\n \n\u2061\n \n \n(\n \nα\n \n)', '\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n \nL\n \n1\n \n \n \nx\n \n1\n \n2\n \n \n \n=\n \n \n \nL\n \n2\n \n \n \nx\n \n2\n \n2\n \n \n \n \n,\n \n \n \n \n\u2062\n \n \n \nL\n \n2\n \n \n=\n \n \n \nL\n \n1\n \n \n2\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \n \n1\n \n \nx\n \n1\n \n2\n \n \n \n=\n \n \n1\n \n \n2\n \n\u2062\n \n \nx\n \n2\n \n2\n \n \n \n \n \n,\n \n \n \n \n\u2062\n \n \n \nx\n \ni\n \n \n=\n \n \n2\n \n\u2062\n \nL\n \n \n \n \n\u2062\n \n \n \n \n \n\u2062\n \n \n \nx\n \n2\n \n \n=\n \n \n \n2\n \n \n\u2062\n \nL\n \n \n \n \n \n \n \n(\n \n11\n \n)\n \n \n \n \n \n \n \n the difference between the induced voltages in the two antennas may be expressed as: \n \n \n \n \n \n \n \n \nV\n \n=\n \n \n \nV\n \nsignal\n \n \n2\n \n \n \n \n \n \n(\n \n12\n \n)', 'Some experimentation to find the radial distance 2L for the full length antenna A\n2\n may be required to effectively cancel the noise by determining the difference between the voltages induced in the two antennas A\n1\n, A\n2\n.', 'In another embodiment as shown in \nFIG.', '7\n, one or more electric diploe antennas \n163\n maybe inserted into a wellbore having electrically non-conductive casing therein, where at the bottom a distance of at least L is open (uncased).', 'A twinax cable (\nFIG.', '4\n) or two coaxial cables may connect to the input of a voltage measuring circuit \n160\n, or as shown in \nFIG.', '4\n, to each of two electrodes \n153\nD, \n153\nE separated by a distance of L.', 'The present example embodiment may increase the amplitude of the detected telemetry signal and reduce the amplitude of detected drilling system noise.', 'Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims.'] | ['1.', 'An apparatus for detecting an electromagnetic signal originating in a wellbore, comprising:\nat least one electric dipole antenna comprising first and second electrodes spaced apart by a first distance along a radial direction from the wellbore and having a midpoint therebetween spaced from the wellbore by a second distance along the radial direction, a dipole moment of the at least one electric dipole antenna being substantially aligned with an electric field direction of the electromagnetic signal;\na shielded electrical cable connecting an amplifier in a voltage measuring circuit to the first and second electrodes, the shielded electrical cable including a twisted pair of first and second insulated electrical conductors deployed in an electrically conductive shield, the first and second insulated electrical conductors connected to center conductors of corresponding first and second coaxial cables at the midpoint, the first and second coaxial cables running along the radial direction between the midpoint and the corresponding first and second electrodes, the center conductors of the first and second coaxial cables connected to the first and second electrodes;\nand\na surface recording and control system configured to receive an output signal from the amplifier.', '2.', 'The apparatus of claim 1, wherein the electrically conductive shield is connected to:\na center tap of a resistor or a transformer bridging inputs to a signal amplifier and wherein the configuration between the amplifier and the electrodes results in an observable decrease in electrical noise.', '3.', 'The apparatus of claim 1 wherein the amplifier comprises a differential amplifier.', '4.', 'The apparatus of claim 1, wherein the first and second distances are equal to one another.', '5.', 'An apparatus for detecting an electromagnetic signal originating in a wellbore, comprising:\na first electric dipole antenna comprising a pair of electrodes spaced apart by a distance 2(L) and having a first midpoint that is spaced a distance 2(L) from a casing included in the wellbore;\na second electric dipole antenna comprising a pair electrodes spaced apart by a distance L and having a second midpoint that is spaced a distance √2(L) from the casing included in the wellbore;\nthe first and second antennas are anti-parallel to one another;\na voltage measuring circuit connected to an input of the first electric dipole antenna and an input of the second electric dipole antenna; and\na surface recording and control system which receives voltages induced in the first and second electric dipole antennas measured by the measuring circuit and processes the voltages induced in each of the first and second electric dipole antennas.', '6.', 'The apparatus of claim 5, further comprising processing the voltages induced in the first and second antennas according to the formula\nV=Vρ1−Vρ2\nwhere V is a difference between the voltage Vρ1 in the first antenna and the voltage Vρ2 in the second antenna.', '7.', 'The apparatus of claim 5, wherein a shielded electrical cable connects the first electric dipole antenna to the voltage measuring circuit.', '8.', 'The apparatus of claim 5, wherein the voltage measuring circuit comprises an amplifier and the apparatus further comprises a shielded electrical cable connecting the amplifier to the pair of electrodes in the first electric dipole antenna, the shielded electrical cable including a twisted pair of first and second insulated electrical conductors deployed in an electrically conductive shield, the first and second insulated electrical conductors connected to center conductors of corresponding first and second coaxial cables at the first midpoint, the first and second coaxial cables running along a radial direction between the first midpoint and corresponding first and second electrodes in the pair of electrodes of the first electric dipole antenna, the center conductors of the first and second coaxial cables connected to the first and second electrodes of the first electric dipole antenna.', '9.', 'An apparatus for detecting an electromagnetic signal originating in a wellbore, comprising:\na first electric dipole antenna Pp comprising a pair of electrodes spaced apart by a first distance and spaced from a surface of the wellbore by a second distance, the first electric dipole antenna being oriented in a direction of the electromagnetic signal;\na second electric dipole antenna Po comprising a pair of electrodes spaced apart by the first distance and having a common point with and being orthogonal to the first electric dipole antenna;\na voltage measuring circuit connected to the first and second electric dipole antennas; and\na surface recording and control system which receives voltages induced in each of the first and second electric dipole antennas and processes the voltages according to the formula: V=Vρ−Vφ\nwhere V is a difference between the voltage Vρin antenna Pρand the voltage Vφin antenna PØ.\n\n\n\n\n\n\n10.', 'The apparatus of claim 9, wherein the first electric dipole antenna is oriented in a direction that is selected such that it makes an angle α of about 45 degrees with a dipole noise source located at the wellbore.', '11.', 'The apparatus of claim 9, wherein a shielded electrical cable connects the first electric dipole antenna to the voltage measuring circuit.', '12.', 'The apparatus of claim 9, wherein the voltage measuring circuit comprises an amplifier and the apparatus further comprises a shielded electrical cable connecting the amplifier to the pair of electrodes in the first electric dipole antenna, the shielded electrical cable including a twisted pair of first and second insulated electrical conductors deployed in an electrically conductive shield, the first and second insulated electrical conductors connected to center conductors of corresponding first and second coaxial cables at a midpoint between the pair of electrodes of the first electric dipole antenna, the first and second coaxial cables running along a radial direction between the midpoint and corresponding first and second electrodes in the pair of electrodes of the first electric dipole antenna, the center conductors of the first and second coaxial cables connected to the first and second electrodes of the first electric dipole antenna.'] | ['FIG.', '1 shows an example electromagnetic telemetry system known in the art prior to the present disclosure.', '; FIG.', '2 shows one example embodiment of a drilling, measurement and telemetry system.;', 'FIG.', '3A shows one example embodiment of an electromagnetic signal transmitter.;', 'FIG.', '3B shows another example embodiment of an electromagnetic signal transmitter.', '; FIG.', '4 shows an example embodiment of an electrode arrangement and connecting cables therefor.; FIG.', '5 shows an example of crossed electric dipole antennas that may be used in some embodiments.; FIG.', '6 shows another example arrangement of electrodes and connecting cables.; FIG.', '7 shows an example dipole antenna disposed in a monitor wellbore.; FIG.', '2 shows an example embodiment of a drilling and measurement system that may be used in various embodiments according to the present disclosure.', 'The system 110 shown in FIG.', '2 may be deployed in either onshore or offshore applications.', 'In a system 110 as shown in FIG.', '2, a wellbore 111 may be formed in subsurface formations by rotary drilling in a manner that is well known in the art.', 'Although the wellbore 111 in FIG.', '2 is shown as being drilled substantially straight and vertically, the wellbore 111 may be directionally drilled, including having a substantially horizontal section, with equal effect as a substantially vertical wellbore.; FIG.', '4 shows a schematic dipole antenna arrangement wherein the electromagnetic signal transmitter current density is shown at 156.', 'A 160C shield of a “twinax” cable 158 (a cable including a twisted pair of insulated electrical conductors 160A and 160B disposed inside an electrically conductive shield 160C) may have one of the two conductors 160A thereof in the present example connected to a first coaxial cable 159 and thence connected to an electrode 153 of the dipole antenna 161 disposed nearest the drilling system 110A or casing 155 at a distance L from the drilling system 110A or casing 155.', 'The other twinax cable 158 insulated, shielded electrical conductor 160B may be connected to another length of coaxial cable 159, the interior conductor of which may be connected to another ground electrode 153A disposed at a distance 3L from the drilling system 110A or casing 155.', 'The twinax cable 158 may extend to a voltage measuring circuit forming part of the receiver electronics in the surface recording and control system (152 in FIG.', '2).', 'The radial direction of a line connecting the two electrodes 153, 153A may be selected to correspond to the direction of the current density 156.', 'Such direction may be determined based on the orientation of the electromagnetic signal transmitter (120A in FIG.', '2) in the wellbore (111 in FIG.', '2).', 'The receiver circuitry may have a balanced front end, composed of an instrumentation amplifier or differential amplifier.', 'In the present example embodiment, a normal input (+) to the amplifier 160 may be electrically connected to one electrode 153A, and an inverting input (−) thereof may be electrically connected to the other electrode 153 of the dipole antenna 161.', 'The twinax cable 158 shield 160C may be connected to a center tap resistor or transformer tap 163 the end terminals of which may be connected between the normal (+) and inverting (−) inputs to the amplifier 160.', 'The foregoing example balanced front end configuration may be expected to substantially cancel any stray capacitance in the twinax cable 158 and the coaxial cables 159 and may maximize common mode rejection to the input of the amplifier 160.', 'The foregoing cable configuration between the amplifier and the electrodes 153, 153A may be expected to provide an observable decrease in electrical noise originating from the drilling system 110A.', 'In other embodiments, the electrodes 153, 153A of the dipole antenna 161 may each be connected to the respective inputs (+), (−) of the amplifier 160 using the interior conductor of a separate coaxial cable 159 extending from each amplifier input to each electrode 153, 153A. Both coaxial cable shields may be connected to the center tap as shown in FIG.', '4.'] |
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US11073635 | Compensated spectroscopy measurements | Jun 14, 2019 | Tong Zhou, David Rose, Jeffrey Miles | SCHLUMBERGER TECHNOLOGY CORPORATION | J. A. Grau, J. S. Schweitzer, “Elemental Concentrations from Thermal Neutron Capture Gamma-ray Spectra in Geological Formations”, Nucl. Geophys. vol. 3, No. 1, pp. 1-9, 1989, Int. J. Radiat. Appl. Instrum. Part E.; J. A. Grau, J. S. Schweitzer, D. V. Ellis, R. C. Hertzog, “A Geological Model for Gamma-ray Spectroscopy Logging Measurements”, Nucl. Geophys. vol. 3, No. 4, pp. 351-359, 1989. | 4788424; November 29, 1988; Preeg; 4937446; June 26, 1990; McKeon et al.; 5045693; September 3, 1991; McKeon et al.; 5408097; April 18, 1995; Wraight et al.; 5471057; November 28, 1995; Herron; 20080023629; January 31, 2008; Herron et al.; 20120091328; April 19, 2012; Suparman; 20140042311; February 13, 2014; Zhou et al.; 20140343857; November 20, 2014; Pfutzner et al.; 20160077234; March 17, 2016; Zhou et al.; 20160195636; July 7, 2016; Grau et al.; 20180113233; April 26, 2018; Vinokurov; 20190129061; May 2, 2019; Zhou | Foreign Citations not found. | ['Elemental concentrations in subterranean formations may be determined using neutron spectroscopy.', 'For example, neutrons may be emitted by a downhole tool into the formation and produce gamma rays via inelastic scattering of fast neutrons or capture of slow neutrons.', 'The borehole surrounding a downhole tool may introduce artifacts in the neutron spectroscopy measurement.', 'Embodiments of the present disclosure are directed to techniques that reduce artifacts signals in downhole tools that include one or multiple detectors based at least in part on the inelastic and capture measurements.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates to neutron-induced gamma-ray spectroscopy for determining concentrations of elements that are present in both the borehole and the formation.', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.', 'Producing hydrocarbons from a wellbore drilled into a geological formation is a remarkably complex endeavor.', 'In many cases, decisions involved in hydrocarbon exploration and production may be informed by measurements from downhole well-logging tools that are conveyed deep into the wellbore.', 'The measurements may be used to infer properties and characteristics of the geological formation surrounding the wellbore.', 'The discovery and observation of resources using downhole techniques generally takes place down in the wellbore with sensors.', 'These sensors may be a part of a tool-string that may be attached to a drill or other downhole device.', 'One particular type of sensor uses a method of direct carbon measurement using neutron-induced gamma-ray spectroscopy.', 'In an open-hole well, a type of analysis known as “oxide closure” may be used to identify certain features of the geological formation from neutron-induced gamma-ray spectroscopy.', 'In a well that has been cased, however, oxide closure may not always produce accurate results.', 'While techniques have been developed to avoid using oxide closure for cased-hole wells, these techniques may produce a result that varies depending on borehole conditions.', 'SUMMARY\n \nA summary of certain embodiments disclosed herein is set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'One embodiment of the present disclosure relates to a system for determining a property of a geological formation that includes a neutron source configured to emit neutrons into a borehole of the geological formation.', 'The system also includes two or more gamma-ray detectors configured to receive gamma rays resulting from interactions between the neutrons emitted by the neutron source and the geological formation to generate a plurality of independent measurements, wherein each independent measurement of the plurality of independent measurements is associated with a different region within a geological formation.', 'Further, the system includes a processor.', 'The processor is configured to acquire a first energy spectrum which contains at least in part a first independent measurement of the plurality of independent measurements.', 'The processor is also configured to acquire a second energy spectrum which contains at least in part a second independent measurement of the plurality of independent measurements.', 'Further, the processor is configured to determine the elemental concentration based at least in part on a combination of the first energy spectrum and the second energy spectrum.', 'Another embodiment of the present disclosure relates to a method for determining an elemental concentration in a geological formation.', 'The method includes emitting neutrons, from a neutron generator placed into a borehole in the geological formation, to cause capture events and inelastic scattering events that generate photons.', 'The method also includes detecting, using one or more detectors, the photons associated with the capture events to generate a plurality of independent measurements, wherein a first independent measurement of the plurality of independent measurements comprises capture measurements and wherein a second independent measurement of the plurality of independent measurements comprises inelastic measurement.', 'Further, the method includes acquiring a first energy spectrum which contains at least in part the first independent measurement.', 'Further still, the method includes acquiring a second energy spectrum which contains at least in part the second independent measurement.', 'Even further, the method includes determining the elemental concentration based at least in part on a combination of the first energy spectrum and the second energy spectrum.', 'Another embodiment of the present disclosure relates to a method for determining an elemental concentration in a formation.', 'The method includes a method for determining an elemental concentration in a geological formation.', 'The method includes emitting neutrons, from a neutron generator, placed into the borehole in the geological formation, to cause capture and inelastic scattering events that generate photons.', 'The method also includes detecting, using one or more detectors, the photons associated with the capture events to generate a plurality of independent measurements, wherein a first independent measurement of the plurality of independent measurements comprises early capture measurements and wherein a second independent measurement of the plurality of independent measurements comprises late capture measurements.', 'Further, the method includes acquiring a first energy spectrum which contains at least in part the first independent measurement.', 'Further still, the method includes acquiring a second energy spectrum which contains at least in part the second independent measurement.', 'Even further, the method includes determining the elemental concentration based at least in part on a combination of the first energy spectrum and the second energy spectrum.', 'Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:\n \nFIG.', '1\n is an example of a neutron-induced gamma-ray spectroscopy system, in accordance with an embodiment;\n \nFIG.', '2\n is an example of a neutron-induced gamma-ray spectroscopy downhole tool, in accordance with an embodiment;\n \nFIG.', '3\n shows a pulsing scheme, in accordance with an embodiment;\n \nFIG.', '4\n shows capture and inelastic cumulative fractional signals detected by a first detector and a second detector as a function of depth of investigation, in accordance with an embodiment in an open hole condition;\n \nFIG.', '5\n shows various cumulative fractional signals detected by a first detector and a second detector as a function of depth of investigation, in accordance with an embodiment in a cased hole condition;\n \nFIG.', '6\n is a flow diagram illustrating an elemental yield evaluation method, in accordance with an embodiment;\n \nFIG.', '7\n is a flow diagram illustrating a method for determining apparent element weight, in accordance with an embodiment;\n \nFIG.', '8\n is a flow diagram illustrating a first method for determining borehole and formation compensation, in accordance with an embodiment;\n \nFIG.', '9\n is a flow diagram illustrating a second method for determining borehole and formation compensation, in accordance with an embodiment;\n \nFIG.', '10\n is a flow diagram illustrating a third method for determining borehole and formation compensation, in accordance with an embodiment; and\n \nFIG.', '11\n is a flow diagram illustrating a fourth method for determining borehole and formation compensation, in accordance with an embodiment.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'As referred to herein, “independent” in the context of “independent measurements”, “two measurements are independent,” and the like, refers to data acquired by detectors that differs based at least on the region of a geological formation represented by the data.', 'That is, a first independent measurement may be different from a second independent measurement in that each independent measurement is acquired by different detectors, is acquired at different DOIs with a single or multiple detectors, acquired at different timing gates (e.g., early timing gate and a late timing gate), or are from difference sources (e.g., capture or inelastic, early capture or late capture, and the like), or any combination.', 'Downhole neutron spectroscopy technology has been used to measure elemental concentrations in the oil and gas industry for several decades.', 'Some neutron spectroscopy logging tools can measure the energy spectra of gamma rays that are induced by either inelastic scattering of fast neutrons or capture of slow neutrons.', 'Elemental relative yields can then be computed from the measured energy spectra using a linear decomposition method or similar methods.', 'In some embodiments, the elemental concentrations can be computed from the elemental relative yields, elemental sensitivities, and the FY2W factor, as shown in Equation 1 below:\n \n \n \n \n \n \n \n \n \nW\n \ni\n \n \n=\n \n \nFY\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \nW\n \n×\n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n \n \n \n(\n \n1\n \n)', 'Here, W\ni \nis the weight fraction of the i\nth \nelement with respect to the rock (on either a dry-weight or total-weight basis), Y\ni \nis the relative yield of the i\nth \nelement, S\ni \nis the sensitivity of the i\nth \nelement, and FY2W is the Factor of Yields to Weights, which accounts for all environmental effects that determine how the relative yields of the total spectrum are related to the weight basis of the set W\ni\n.', 'In some embodiments, the weight fraction of each element may be a weight percent, and the weight percent or fraction may be relative to some number of elements present in a formation, minerals in the formation, or a region within a formation.', 'In reality, the presence of materials in the wellbore introduces complexity.', 'If the i\nth \nelement is present in the wellbore, a measurement will have some of the relative yield Y\ni \ncoming from the wellbore so that the corresponding dry weight percent W\ni \nis a mix of wellbore and formation components.', 'Certain methods exist to compute FY2W from the available measured capture elemental relative yields.', 'Among these methods are techniques that are collectively known as oxides closure.', 'First, these methods disregard all the elements that exist in the formation pore space or wellbore (such as H, Cl, etc.), and the method assumes all other elements (Si, Ca, Fe, Mg, Al, etc.) may exist in formation rocks but not in the wellbore.', 'Second, it assumes that all major rock elements are in the form of oxides or carbonates.', 'Last, since the sum of the weight fractions of all rock elements, including the associated unmeasured oxygen and carbon, is equal to 1, one can back-compute the required FY2W value.', 'In open-hole conditions, the assumption that there are no rock elements (Si, Ca, Fe, Mg, Al, etc.)', 'in the wellbore works well.', 'However, in cased hole conditions, this assumption may not be valid, since there could be Si or Ca in cement, and Fe in casing.', 'Certain methods use raw measurements from a spectroscopy tool to predict the FY2W values for both capture and inelastic yields without doing oxide closure.', 'Using the predicted capture and inelastic FY2W, one can convert all the capture and inelastic elemental relative yields to apparent elemental concentrations.', 'For the elements present in the formation and not in the borehole (e.g., or in substantially large amounts), the apparent elemental concentrations are essentially the formation elemental concentrations.', 'For the elements present in both formation and borehole (H, O, Cl in borehole water; C in borehole oil; Ca and S\ni \nin cement, Fe in casing, etc.), the apparent elemental concentrations will have a borehole component and corrections may be applied to obtain the formation elemental concentration.', 'The present disclosure relates to techniques to determining properties (e.g., elemental concentrations) of different regions in a wellbore based on a differential sensitivity to the geological formation and the borehole, well completion, and the like.', 'For example, the techniques may remove a borehole component in the apparent elemental concentrations from a wellbore and to get formation concentrations for formation evaluation applications.', 'In one embodiment, the present disclosure is directed to determining an elemental concentration (e.g., weight percent or weight fraction) for one or more elements present in a formation or a subset of a formation.', 'That is, the elemental concentration for each element represents a relative amount of each element compared to a subset of elements that are present within a formation.', 'It should be appreciated by one of ordinary skill in the art that the elemental concentration may be used to determine an absolute concentration based on the formation bulk density and one or more measured elemental concentrations.', 'One can also use the present techniques to remove the formation component and to get borehole elemental concentrations for applications relating to well integrity, production fluid holdup, and gravel pack evaluation.', 'In some embodiments, additionally or alternatively, the elemental concentration for an element may be determined based on spectral standards for the element, where each spectral standard is specific for each of the at least two different regions (e.g., a formation region and a borehole region).', 'For a pulsed neutron tool equipped with two spectroscopy detectors, one can use the difference in the apparent elemental concentrations measured by the two detectors as a measure of the borehole elemental concentrations for borehole evaluation applications.', 'One can also use the difference to compensate for the presence of the borehole contribution in the apparent elemental concentrations to get the accurate formation elemental concentrations for formation evaluation applications.', 'The principle of these methods is that the two detectors will have different depths of investigation.', 'The one with shorter source-to-detector spacing will read shallower and is more sensitive to the borehole and less sensitive to the formation.', 'The one with longer source-to-detector spacing will read deeper and is more sensitive to the formation and less sensitive to the borehole.', 'The relative sensitivities can be enhanced by back-shielding one or both of the detectors (U.S. Pat.', 'Nos. 4,937,446A, 5,045,693A, Patent application: US20140343857A1)', 'or by using a borehole fluid excluder behind one of the detectors (U.S. Pat. No. 5,408,097A), which are incorporated herein by reference in their entireties and for all purposes.', 'A similar compensation can also be done based on a single spectroscopy detector.', 'For the elements that can be measured by both capture and inelastic spectroscopy (including but not limited to S\ni\n, Ca, Mg, S, Al, Fe, etc.), one can use the difference between the capture and inelastic apparent elemental concentrations for borehole evaluation or to compensate the borehole component to get formation concentrations for formation evaluation.', 'This is because the inelastic spectroscopy has a shallower depth of investigation (DOI) than the capture one.', 'For the elements that may be measured by capture spectroscopy, one can, additionally or alternatively, use the difference between the capture spectra in an earlier timing gate and a later timing gate.', 'This is because an early capture spectrum has a shallower DOI than the late one.', 'With the foregoing in mind, \nFIG.', '1\n illustrates a well-logging system \n10\n that may employ the systems and methods of this disclosure.', 'The well-logging system \n10\n may be used to convey a downhole tool \n12\n through a geological formation \n14\n via a borehole \n16\n.', 'In the example of \nFIG.', '1\n, the downhole tool \n12\n is conveyed on a cable \n18\n via a logging winch system (e.g., vehicle \n20\n).', 'Although the vehicle \n20\n is schematically shown in \nFIG.', '1\n as a mobile logging winch system carried by a truck, the vehicle \n20\n may be substantially fixed (e.g., a long-term installation that is substantially permanent or modular).', 'Any suitable cable \n18\n for well logging may be used.', 'The cable \n18\n may be spooled and unspooled on a drum \n22\n and an auxiliary power source \n24\n may provide energy to the vehicle \n20\n and/or the downhole tool \n12\n.', 'Moreover, while the downhole tool \n12\n is described as a wireline downhole tool, it should be appreciated that any suitable conveyance may be used.', 'For example, the downhole tool \n12\n may instead be conveyed as a logging-while-drilling (LWD) tool as part of a bottom hole assembly (BHA) of a drill string, conveyed on a slickline or via coiled tubing, and so forth.', 'For the purposes of this disclosure, the downhole tool \n12\n may be any suitable downhole tool that uses neutron-induced gamma-ray spectroscopy within the borehole \n16\n (e.g., downhole environment).', 'The gamma-ray spectroscopy may include, but is not limited to, inelastic, capture, or delayed activation gamma-ray spectroscopy.', 'For example, the gamma-ray spectroscopy may include any suitable neutron-induced gamma-ray spectroscopies.', 'As discussed further below, the downhole tool \n12\n may receive energy from an electrical energy device or an electrical energy storage device, such as the auxiliary power source \n24\n or another electrical energy source to power the tool.', 'Additionally, in some embodiments the downhole tool \n12\n may include a power source within the downhole tool \n12\n, such as a battery system or a capacitor to store sufficient electrical energy to activate the neutron emitter and record gamma-ray radiation.', 'Data signals \n26\n may be transmitted from a data processing system \n28\n to the downhole tool \n12\n, and the data signals may be related to the spectroscopy results may be returned to the data processing system \n28\n from the downhole tool \n12\n, additionally, the data signals \n26\n may include control signals.', 'The data processing system \n28\n may be any electronic data processing system that can be used to carry out the systems and methods of this disclosure.', 'For example, the data processing system \n28\n may include a processor \n30\n, which may execute instructions stored in memory \n32\n and/or storage \n34\n.', 'As such, the memory \n32\n and/or the storage \n34\n of the data processing system \n28\n may be any suitable article of manufacture that can store the instructions.', 'The memory \n32\n and/or the storage \n34\n may be read-only memory (ROM), random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive, to name a few examples.', 'A display \n36\n, which may be any suitable electronic display, may display images generated by the processor \n30\n.', 'The data processing system \n28\n may be a local component of the vehicle \n20\n (e.g., within the downhole tool \n12\n), a remote device that analyzes data from other vehicles \n20\n, a device located proximate to the drilling operation, or any combination thereof.', 'In some embodiments, the data processing system \n28\n may be a mobile computing device (e.g., tablet, smart phone, or laptop) or a server remote from the vehicle \n20\n.\n \nFIG.', '2\n shows a downhole tool \n12\n for detecting neutron-induced gamma ray spectroscopy.', 'As shown, the downhole tool \n12\n includes two gamma ray detectors (e.g., first detector \n42\n and second detector \n44\n).', 'However, in certain embodiments, the downhole tool \n12\n may have one scintillator gamma ray detector (e.g., first detector \n42\n or second detector \n44\n).', 'Some of the methods in this disclosure can be applied to single-detector spectroscopy tools, and some are more suitable for multi-detector spectroscopy tools.', 'The downhole tool \n12\n is equipped with a neutron source \n40\n (e.g., pulsed neutron generator (PNG)) that emits neutrons (e.g., generally illustrated by the arrow \n41\n).', 'A PNG may be turned on and off repeatedly in a pattern.', 'Additionally, the downhole tool \n12\n includes shielding \n46\n that may prevent neutrons from the neutron source \n40\n from transmitting directly into the first detector \n42\n and second detector \n44\n (e.g., without first passing through the geological formation \n14\n or borehole \n16\n).', 'The instantaneity of the inelastic gamma-rays and the decay of capture gamma-rays can be seen in plot \n50\n of \nFIG.', '3\n where the x-axis depicts time in μs and the y-axis depicts a normalized count rate of both types of detected gamma-rays on a logarithmic scale.', 'The difference between capture and inelastic gamma-rays can be seen from the result of a PNG pulsing scheme.', 'The pulsing scheme may include multiple “on” periods (e.g., indicated by the peaks) and “off” periods of the neutron source and an extended off period, which result in the gamma-ray detections of plot \n50\n.', 'For example, the on periods may be 20 μs, the off periods may be 30 μs, and an extended off period may extend, for example, up to 1 millisecond.', 'However, multiple different pulsing schemes of on periods and off periods may also be used.', 'In the illustrated embodiment shown in plot \n50\n, when an on period begins, the count rate may instantly jump due to the increase in inelastic gamma-ray detection.', 'Similarly, when an additional off period begins, the count rate may immediately drop.', 'Conversely, during the span of an on period, the count rate may continuously increase due to the increase in capture gamma-rays.', 'Likewise, during a subsequent off period, the count rate may decrease exponentially due to capture gamma-ray decay emissions.', 'Throughout the pulsing scheme, measurements pertaining to the energy levels of the gamma-rays may also be taken to determine elemental relative yields of the environment.', 'In some embodiments, the pulsing scheme may be repeated multiple times to gather more data.', 'After the final pulse of the pulsing scheme, the extended off period may begin.', 'An exponential decay relates to the decay of the isotopes in the environment and the detection of corresponding capture gamma-rays.', 'The decay constant of the decay may be correlated (i.e., inversely proportional) to a sigma value representative of properties of the borehole \n16\n and geological formation \n14\n (e.g., sigma).', 'However, due to the elements within and the geometries and properties of the borehole \n16\n and the geological formation \n14\n, the borehole \n16\n and formation \n14\n may have different sigma values (borehole sigma and formation sigma).', 'To account for both, an apparent sigma may be calculated to balance the effects from each location.', 'Additionally, borehole sigma and formation sigma may be correlated to the decay more or less at different times during the decay \n64\n.', 'For example, earlier times during the decay may have more borehole effect on the apparent sigma than later times.', 'As such, the use of timing gates when taking measurements and determining the apparent sigma may be done judiciously to achieve a balance of the borehole sigma and formation sigma.', 'More details can be found in US patent application 2014/0042311 A1, which is incorporated herein by reference in its entirety for all purposes.', 'The radial depth of investigation of the measurement is affected by several factors, including: the source-to-detector spacing, the reaction giving rise to the spectrum (either inelastic or capture), and the timing of the capture spectrum acquisition.', 'FIG.', '4\n shows a comparison of the cumulative signal received from increasing radial depths.', 'The signal from the inelastic and capture reactions are plotted separately for each of two detectors with different spacing.', 'That is, lines \n52\n and \n54\n are the Near inelastic signal and capture signal, respectively (referred to as “Near” because they are measured by the first detector \n42\n, which is nearer to the neutron source \n40\n than the second detector \n44\n).', 'The lines \n56\n and \n58\n are the Far inelastic signal and capture signal, respectively (referred to as “Far” because they are measured by the second detector \n44\n, which is farther from the neutron source \n40\n than the first detector \n42\n).', 'On average, a Far-spaced detector (e.g., second detector \n44\n) receives a deeper signal in terms of depth of investigation (DOI) than does a Near-spaced detector (e.g., first detector \n42\n), and the capture signal can be deeper than the inelastic signal.', 'These aspects of the measurement may be understood as follows.', 'The inelastic spectroscopy measurement is based on the spectrum of gamma rays induced by inelastic reactions of fast neutrons with the nuclei around the tool.', 'The capture spectroscopy measurement is based on the spectrum of gamma rays induced by the capture of slow neutrons by the nuclei around the tool.', 'The inelastic signal can have a shallower depth of investigation (DOI) than the capture signal, because the inelastic signal can be generated by fast neutrons above a certain energy threshold (approximately 1 MeV).', 'After a small number of collisions with the surrounding medium (one collision or at most a few collisions), neutrons have fallen below the energy threshold for inelastic reactions.', 'Capture reactions preferentially occur for slow neutrons near thermal equilibrium with the surrounding medium.', 'The neutrons giving rise to capture reactions therefore undergo many more collisions and are likely to diffuse outward from the tool before being captured.', 'The result is that the point-of-origin for the capture spectrum is typically deeper than that of the inelastic spectrum, on average.', 'At the same time, the DOI of each detector depends on its distance from the source.', 'The inelastic signal detected in a Far-spaced detector is more likely to originate from a deeper radial position, on average, than the inelastic signal for a Near-spaced detector.', 'Similarly, the capture signal of a Far detector is deeper than in a Near detector.', 'FIG.', '5\n shows how the radial DOI of the capture spectrum for two detectors is affected by the timing of the capture acquisition gates.', 'Lines \n62\n, \n64\n, and \n66\n are the signals for Near (e.g., measured by first detector \n42\n) capture total, early capture, and late capture, respectively.', 'Lines \n68\n, \n70\n, and \n72\n are the signals for Far (e.g., measured by second detector \n44\n) capture total, early capture, and late capture, respectively.', 'The capture signal acquired late after the PNG burst comes from a deeper radial position, on average, than the capture signal acquired soon after the PNG burst.', 'The late signal has more time for neutron diffusion to occur, which increases the relative population of neutrons at greater radial depths.', 'The basic principle of the spectral analysis may be simplified to the linear model shown below: \n Spec=Σ\ni=1\nN\n(\nY\ni\n·Std\ni\n)\u2003\u2003(2) \n where “Spec” is the corrected measured net spectrum, which can be net capture or net inelastic.', 'The correction includes pileup correction, background subtraction, gain, offset and non-linearity adjustment.', '“Y\ni\n” is the capture or inelastic elemental relative yield for the i\nth \nelement.', '“N” is the total number of elements to solve.', '“Std\ni\n” is the elemental standard for the i\nth \nelement after proper degradation to match the tool detector response.', 'The degradation may include resolution degradation and non-Gaussian shape degradation.', 'The elemental standards are known from laboratory measurements or modeling.', 'After solving Equation 2, one can get a set of capture yields and a set of inelastic yields for each spectroscopy detector.', 'In some embodiments, it is helpful to convert the yields into elemental weight concentrations.', 'In other embodiments, the present techniques can be applied to the yields directly.', 'Assuming an infinite homogeneous formation, and neglecting the borehole and logging tool geometry, the total counts N of gamma rays induced by neutrons can be written as in Equation 3:\n \n \n \n \n \n \n \n \nN\n \n=\n \n \n \n \n∑\n \ni\n \n \n\u2062\n \n \nN\n \ni\n \n \n \n=\n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n(\n \n \nϕ\n \n·\n \n \nN\n \nA\n \n \n·\n \n \nρ\n \ni\n \n \n·\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n)\n \n \n \n \n \n \n \n \n(\n \n3\n \n)\n \n \n \n \n \n \n \n where ϕ is the average neutron flux in the formation, N\nA \nis the Avogadro constant, ρ\ni \nis the partial density of the i\nth \nelement, σ\ni \nis the gamma ray production cross section of the i\nth \nelement, M\ni \nis the atomic mass of the i\nth \nelement, and Ni is the number of gamma rays produced from the i\nth \nelement.', 'The relative yield of the i\nth \nelement can then be calculated by Equation 4, taking its fractional contribution to the total gamma-ray production:', 'Y\n \ni\n \n \n=\n \n \n \n \nN\n \ni\n \n \nN\n \n \n=\n \n \n \nϕ\n \n·\n \n \nN\n \nA\n \n \n·\n \n \nρ\n \ni\n \n \n·\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n(\n \n \nϕ\n \n·\n \n \nN\n \nA\n \n \n·\n \n \nρ\n \ni\n \n \n·\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n)\n \n \n \n \n \n \n \n \n \n(\n \n4\n \n)', 'The sensitivity S\ni \nof the i\nth \nelement may be defined as follows, using its mass-normalized gamma-ray production cross section:\n \n \n \n \n \n \n \n \n \nS\n \ni\n \n \n=\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n \n \n \n(\n \n5\n \n)', 'This form of the elemental sensitivity is simple because it describes gamma-ray production in the homogeneous medium, and may not describe the probability of gamma rays reaching a detector or being detected once there.', 'The sensitivities for a realistic detection system may include these efficiencies, as will be discussed below.', 'By rearranging Equation 4, one can compute the weight fraction W\ni \nof the i\nth \nelement based on the relative yield as follows:\n \n \n \n \n \n \n \n \n \nW\n \ni\n \n \n=\n \n \n \n \nρ\n \ni\n \n \nρ\n \n \n=\n \n \n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n=\n \n \nFY\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \n \nW\n \n·\n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n \n \n \n \n \n \n(\n \n6\n \n)', 'In this infinite homogeneous case, the computation of the weight fraction based on the relative yield has been reduced to Equation 1.', 'The conversion from the relative yield to the weight fraction is to apply a gain factor, called FY2W.\n \nIn a more realistic condition, the downhole geometry can be divided into borehole and formation regions.', 'Equation 3 then becomes Equation 7, where the superscript “f” represents the formation and “b” represents the borehole.', 'N\n \n=\n \n \n \n \n \n∑\n \ni\n \n \n\u2062\n \n \nN\n \ni\n \nf\n \n \n \n+\n \n \n \n∑\n \ni\n \n \n\u2062\n \n \nN\n \ni\n \nb\n \n \n \n \n=\n \n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n(\n \n \n \nϕ\n \nf\n \n \n·\n \n \nN\n \nA\n \n \n·\n \n \nρ\n \ni\n \nf\n \n \n·\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n)\n \n \n \n+\n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n(\n \n \n \nϕ\n \nb\n \n \n·\n \n \nN\n \nA\n \n \n·\n \n \nρ\n \ni\n \nb\n \n \n·\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n)\n \n \n \n \n \n \n \n \n \n(\n \n7\n \n)\n \n \n \n \n \n \n \n \nIn this case, the relative yield will contain the signal coming from both formation and borehole, as shown in Equation 8:\n \n \n \n \n \n \n \n \n \nY\n \ni\n \n \n=\n \n \n \n \n \nN\n \ni\n \nf\n \n \n+\n \n \nN\n \ni\n \nb\n \n \n \nN\n \n \n=\n \n \n \n \n \n(\n \n \n \n \nϕ\n \nf\n \n \n·\n \n \nρ\n \ni\n \nf\n \n \n \n+\n \n \n \nϕ\n \nb\n \n \n·\n \n \nρ\n \ni\n \nb\n \n \n \n \n)\n \n \n·\n \n \nN\n \nA\n \n \n \n\u2062\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n(\n \n \n \nϕ\n \nf\n \n \n·\n \n \nN\n \nA\n \n \n·\n \n \nρ\n \ni\n \nf\n \n \n·\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n)\n \n \n \n+\n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n(\n \n \n \nϕ\n \nb\n \n \n·\n \n \nN\n \nA\n \n \n·\n \n \nρ\n \ni\n \nb\n \n \n·\n \n \n \nσ\n \ni\n \n \n \nM\n \ni\n \n \n \n \n)\n \n \n \n \n \n \n \n \n \n \n(\n \n8\n \n)\n \n \n \n \n \n \n \n \nUsing the same definition of elemental sensitivity as given in Equation 5, the yields of Equation 8 can be re-arranged to express the elemental weight fractions as follows:\n \n \n \n \n \n \n \n \n \nW\n \ni\n \n \n=\n \n \n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n∑\n \ni\n \n \n\u2062\n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n=\n \n \n \n(\n \n \n \n \nϕ\n \nf\n \n \n·\n \n \nρ\n \ni\n \nf\n \n \n \n+\n \n \n \nϕ\n \nb\n \n \n·\n \n \nρ\n \ni\n \nb\n \n \n \n \n)\n \n \n \n(\n \n \n \n \nϕ\n \nf\n \n \n·\n \n \nρ\n \nf\n \n \n \n+\n \n \n \nϕ\n \nb\n \n \n·\n \n \nρ\n \nb\n \n \n \n \n)\n \n \n \n \n \n \n \n \n(\n \n9\n \n)\n \n \n \n \n \n \n \n \nHere, ρ\nf \nis the total formation density and ρ\nb \nis the total borehole density; ϕ\nf \nis neutron flux in the formation region and ϕ\nb \nis neutron flux in the borehole region.', 'This approach is a first-order treatment for elemental sensitivities, because it assumes that gamma rays created in the borehole and formation have equal probabilities of being detected.', 'In a more advanced treatment, it is possible to extend the expression for sensitivity by including factors for the efficiencies of gamma-ray transport and detection.', 'These factors vary for each element according to its energy spectrum and the point of origin of the gamma rays.', 'Based on Equation 9, one can compute the formation weight fraction W\ni\nf \nof the i\nth \nelement from the measured relative yields.', 'Unlike the simple infinite homogeneous example, the conversion from the relative yield to the weight fraction involves a gain factor and an offset.', 'The gain factor (FY2W) is driven by the spatial distribution of the neutron flux, including its evolution over time, and the relative probabilities (or cross sections) for neutron interactions with the set of elemental nuclei in the different regions, as well as the detector response (comprising aspects like source-to-detector spacing, detector efficiency, and so on).', 'The gain factor may be obtained as a function of geometrical or compositional properties of the environment (such as bit size), or from an oxide closure computation, or as a function of other detector-based measurements (detector count rate ratios, apparent sigma, etc.), or from computational modeling, or local calibrations, or a combination of any of those methods.', 'The offset factor is proportional to the borehole weight fraction of the i\nth \nelement.', 'When the borehole region has no i\nth \nelement present, the offset is equal to zero.', 'The computation of formation weight fractions can be expressed as follows:\n \n \n \n \n \n \n \n \n \nW\n \ni\n \nf\n \n \n=\n \n \n \n \nρ\n \ni\n \nf\n \n \n \nρ\n \nf\n \n \n \n=\n \n \n \n \n \n(\n \n \n1\n \n+\n \n \n \n \nϕ\n \nb\n \n \n·\n \n \nρ\n \nb\n \n \n \n \n \nϕ\n \nf\n \n \n·\n \n \nρ\n \nf\n \n \n \n \n \n)\n \n \n·\n \n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n∑\n \nj\n \n \n\u2062\n \n \n \nY\n \nj\n \n \n \nS\n \nj\n \n \n \n \n \n \n-\n \n \n \n \nϕ\n \nb\n \n \n·\n \n \nρ\n \ni\n \nb\n \n \n \n \n \nϕ\n \nf\n \n \n·\n \n \nρ\n \nf\n \n \n \n \n \n=\n \n \n \nFY\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \n \nW\n \n·\n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n-\n \n \nBeff\n \n·\n \n \n \nρ\n \ni\n \nb\n \n \n \nρ\n \nf\n \n \n \n \n \n \n \n \n \n \n \n(\n \n10\n \n)', 'In this treatment, the coefficient Beff is defined as the ratio of the neutron flux in the borehole region with respect to the neutron flux in the formation region.', 'It is a strong function of DOI.', 'The deeper the DOI, the smaller the coefficient.', 'Therefore, we can use one apparent weight fraction measurement with a shallow DOI to compensate the other apparent weight fraction measurement with a deeper DOI, no matter how much of this element is present in the borehole region.', 'Once again, the FY2W factor is a gain factor on the elemental yields, and it now describes the normalization of the total sensitivity-weighted yields as well as how much of the total yields arise from the formation versus borehole, based on the flux-weighted densities in the two regions.', 'The above analysis neglects the different detection probability of gamma rays from the borehole and formation.', 'The neutron flux terms from Equation 10 can be weighted by their relative importance G, which may be interpreted as the relative probabilities for detecting gamma rays from each region or position.', 'The expanded expression is:\n \n \n \n \n \n \n \n \n \nW\n \ni\n \nf\n \n \n=\n \n \n \n \nρ\n \ni\n \nf\n \n \n \nρ\n \nf\n \n \n \n=\n \n \n \n \n \n(\n \n \n1\n \n+\n \n \n \n \nϕ\n \nb\n \n \n\u2062\n \n \nG\n \nb\n \n \n\u2062\n \n \nρ\n \nb\n \n \n \n \n \nϕ\n \nf\n \n \n\u2062\n \n \nG\n \nf\n \n \n\u2062\n \n \nρ\n \nf\n \n \n \n \n \n)\n \n \n·\n \n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n∑\n \nj\n \n \n\u2062\n \n \n \nY\n \nj\n \n \n \nS\n \nj\n \n \n \n \n \n \n\u2062\n \n \n \n \nϕ\n \nb\n \n \n\u2062\n \n \nG\n \nb\n \n \n\u2062\n \n \nρ\n \ni\n \nb\n \n \n \n \n \nϕ\n \nf\n \n \n\u2062\n \n \nG\n \nf\n \n \n\u2062\n \n \nρ\n \nf\n \n \n \n \n \n=\n \n \n \nFY\n \n\u2062\n \n \n \n \n\u2062\n \n2\n \n\u2062\n \n \nW\n \n·\n \n \n \nY\n \ni\n \n \n \nS\n \ni\n \n \n \n \n \n-\n \n \nBeff\n \n·\n \n \n \nρ\n \ni\n \nb\n \n \n \nρ\n \nf\n \n \n \n \n \n \n \n \n \n \n \n(\n \n11\n \n)\n \n \n \n \n \n \n \n where G\nb \nand G\nf \nare the relative probabilities for detecting an average gamma ray that originates in the borehole and formation, respectively.', 'The gain FY2W is redefined to contain the new factors, and the coefficient Beff is now the ratio of importance-weighted neutron fluxes in the two regions.', 'In practice, the new factors are automatically subsumed within an empirical calibration.', 'FY2W can be derived in the same ways as described above.', 'Similarly, Beff can be derived as a function of geometrical or compositional properties of the environment (such as bit size), or as a function of other detector-based measurements (e.g., detector count rate ratios, apparent sigma, . . . ), or from computational modeling, or local calibrations, or a combination of any of those methods.', 'When applying the techniques that will be discussed in the present disclosure, it can be advantageous to first convert the yields into formation elemental weight concentrations.', 'In this way, two apparent elemental weight fraction measurements with two different DOIs will read the same value when this element is present in the formation region, but not present or significantly present (e.g., in a large enough concentration that would be detectable) in the borehole.', 'The two will separate when this element is present in the borehole region, and the difference is relatable to the amount of the element in the borehole.', 'It would be appreciated by one of ordinary skill in the art that the formation elemental weight fraction may not be the sole quantity to which the relative yields can be converted to enable the use of the techniques in the present disclosure.', 'The gain factor FY2W can be generalized as a normalization factor, which is used to normalize two relative elemental yields with different DOI to the same value when this element is present in the formation region, but not present or significantly present in other regions (e.g., the borehole \n16\n).', 'This normalization factor (or gain factor, or FY2W) can be a constant value for one relative yield measurement (when the borehole condition in the well is constant and stable), so that it can be determined locally.', 'This factor can also be determined using the known downhole parameters, such as bit size, casing size, casing weight, borehole fluid type, borehole fluid density, formation lithology, formation porosity, and so on.', 'This factor can be calculated depth by depth using the oxide closure method or based on a capture gamma-ray decay rate, an apparent sigma value that may balance contributions from elements present in both a borehole and a formation.', 'The present techniques are directed to techniques to separate the elemental contributions in the apparent elemental weight percentages, such as the borehole and formation elemental contributions in an apparent elemental weight percent.', 'The present techniques combine at least two independent measurements of an element, where each measurement has a different characteristic depth of investigation, to estimate the borehole or formation contributions to the elemental measurement.', 'Some techniques combine a measurement from two detectors.', 'Some techniques combine two measurements made by a single detector (e.g., either first detector \n42\n or second detector \n44\n).', 'These techniques are discussed in detail below.', 'These techniques are relevant for borehole evaluation applications such as cement integrity, casing corrosion, scale detection, production holdup, borehole salinity, gravel pack evaluation, or the like, or formation evaluation applications such as rock lithology, formation hydrogen, formation salinity, formation porosity, oil saturation, water saturation, fluid typing, or the like.\n \nFIG.', '6\n illustrates an example of a process \n73\n for determining an elemental weight percent and/or element concentration based on measurements from one or more detector.', 'Although described in a particular order, which represents a particular embodiment, it should be noted that the process \n73\n may be performed in any suitable order.', 'Additionally, embodiments of the process \n73\n may omit process blocks and/or include additional process blocks.', 'Moreover, in some embodiments, the process \n73\n may be implemented at least in part by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as memory \n32\n implemented in a data processing system \n28\n, using processing circuitry, such as a processor \n30\n implemented in the data processing system \n28\n.', 'The process \n73\n includes receiving (process block \n74\n) a first independent measurement of an element associated with a first region of a borehole.', 'The process \n73\n also includes receiving (process block \n75\n) a second independent measurement of an element associated with a region of a geological formation.', 'As discussed herein, each independent measurement (e.g., the first independent measurement and the second independent measurement) generally represents a different DOI within the geological formation \n14\n.', 'For example, the first independent measurement may be different from the second independent measurement in that each independent measurement is acquired by different detectors, is acquired at different DOIs with a single or multiple detectors, acquired at different timing gates (e.g., early timing gate and a late timing gate), or are from difference sources (e.g., capture or inelastic, early capture or late capture, and the like).', 'In some embodiments, each measurement may relate to a single element and each independent measurement relates to the same element.', 'It should be noted that the type of independent measurements may depend on the element being investigated.', 'For example, certain elements may be detectable from inelastic scattering of gamma-rays or capture events.', 'Further, the process includes identifying (process block \n76\n) a weight percent of the element based on the first and second independent measurements.', 'In some embodiments, the weight percent of the element is identified based on a difference or ratio of the first independent measurement, the second independent measurement, or any additional independent measurements.', 'In some embodiments, the combination of elemental measurements is performed with apparent elemental weight concentrations, as computed above.', 'As discussed earlier, the FY2W in \nFIG.', '7\n can be generalized as a gain factor or normalization factor, and the apparent elemental weight concentration can be generalized as normalized relative yield measurements.', 'Following the process \n80\n in \nFIG.', '7\n, one can compute the apparent capture elemental weight percent and apparent inelastic elemental weight percent for one or multiple detectors.', 'The phrase “weight percent” refers to the concentration of an element measured as a percentage of the total weight of a set of elements, such as those comprising the formation.', 'The process \n80\n includes a combining a detector \n1\n capture relative yield \n82\n and a detector \n1\n capture FY2W to determine the apparent capture elemental weight for a first detector (e.g., detector \n40\n).', 'The process \n80\n also includes combining detector \n1\n inelastic relative yields and a detector \n1\n inelastic FY2W to determine an apparent inelastic elemental weight percent \n92\n for the first detector.', 'Further, the process \n80\n includes combining detector \n2\n capture relative yields \n94\n with a detector \n2\n capture FY2W to determine an apparent capture elemental weight 98 percent for a second detector (e.g., detector \n42\n).', 'Further still, the process includes combining detector \n2\n inelastic relative yields \n100\n with detector inelastic FY2W \n102\n to determine an apparent inelastic element weight percent \n104\n for the second detector.', 'The concentrations may also be measured as weight fractions or any other suitable units.', 'S1_CAPi is the capture relative sensitivity (normalized by silicon sensitivity) for the i\nth \nelement and first detector \n42\n.', 'S1_INEi is the inelastic relative sensitivity (normalized by silicon sensitivity) for the i\nth \nelement and detector \n42\n.', 'W1_CAPi is the apparent capture elemental weight percent for the i\nth \nelement and first detector \n42\n.', 'W1_INEi is the apparent inelastic elemental weight percent for the i\nth \nelement and first detector \n42\n.', 'The term “apparent” means it may contain some borehole effects.', "If there's no i\nth \nelement in the borehole, the apparent i\nth \nelement weight percent will be an accurate formation elemental weight percent.", 'If the i\nth \nelement is present in the borehole, some of the contribution to the relative yield of the i\nth \nelement will come from the borehole and the apparent i\nth \nelement weight percent will contain borehole signal.', 'In some cases, the apparent elemental weight percent can be larger than 100%.', '(One such example would be the apparent iron weight percent in a cased hole with a lot of iron in the casing, because the computation of FY2W is designed to describe the formation elements.)', 'In one example embodiment of the process \n73\n, each independent measurement (e.g., the first independent measurement, the second independent measurement, and additional independent measurements) is acquired by different detector.', 'To illustrate one embodiment of the process \n73\n, \nFIG.', '8\n shows an example of a process \n106\n for determining a weight percent of an element based on capture measurements from two detectors.', 'In general, a first capture weight percent \n108\n and a second capture weight percent \n110\n are received as inputs.', 'A difference \n112\n between the first capture weight percent \n108\n and the second capture weight percent \n110\n is determined by a processor (e.g., processor \n30\n).', 'Additionally, an average capture weight percent \n114\n may be determined.', 'A borehole weight percent \n116\n may be determined based on the difference \n112\n and a formation weight percent \n118\n may be determined based on the difference \n112\n and the average capture weight percent \n114\n.', 'The first detector \n42\n shown in \nFIG.', '2\n has a shorter source-to-detector spacing, which provides a shallower depth of investigation than the second detector \n44\n, which has a longer source-to-detector spacing.', 'Shielding and different radial positioning of the detectors may also be used to enhance the borehole sensitivity of the shallow detector and to enhance the relative formation sensitivity of the deep-reading detector.', 'The apparent elemental weight percent measured by the short spacing detector will have more borehole elemental contribution and less formation elemental contribution than the one measured by the long spacing detector.', 'Following the process \n106\n shown in \nFIG.', '7\n, one can compute the difference and the average between the two.', 'When there is no i\nth \nelement present in the borehole, the two apparent weight percent from the two detectors should read the same, the difference is zero, and the average will be the measured formation elemental weight percent.', 'When there is a non-zero amount of the i\nth \nelement present in the borehole, the two detector measurements will separate and the difference can be used for a borehole evaluation.', 'A borehole elemental weight can be computed from the difference, using a function that may also take inputs of borehole geometry parameters (hole size, casing size, casing weight, casing ID, tubing size, etc.).', 'Furthermore, the difference can also be used to compensate borehole contribution in the apparent weight percent measured by either of the detectors or the average one.', 'Some additional measurements or user input parameters can help to improve the accuracy of the compensation.', 'Those can be (but are not limited to) the estimated FY2W for one of the detectors, hole size, casing size, apparent sigma measurements, ratios of count rates from one detector to another during various timing windows, and so on.', 'One such example of a compensation function may be expressed as: \n Borehole_', 'Wi=f\n(DIFF_CAPi)=DIFF_CAPi*Σ\nk\na\nk\n(\nFY\n2\nW\n_1_CAP)\nk\n\u2003\u2003(12) \n where Borehole_Wi is the borehole elemental weight percent, DIFF_CAPi is the difference between the apparent weight percent of the two detectors, as shown in the process \n106\n of \nFIG.', '7\n, and FY2W_1_CAP is the estimated FY2W of detector \n1\n for the capture analysis.', 'This example uses a polynomial function of FY2W for the borehole compensation function, where the polynomial may be a second-order (quadratic) polynomial.', 'It will be appreciated by those skilled in the art that other compensation functions are also possible using the above non-inclusive list of inputs.', 'In some applications, the borehole apparent weight percent can be filtered or averaged before being applied as a compensation for the formation weight percent.', 'The filtering may be performed with respect to measurement depth or time, and may serve to reduce statistical noise in the borehole estimate.', 'The difference DIFF_CAPi can be filtered directly, or the filtering may be performed on Borehole_Wi.', 'Filtering can have many forms from a boxcar filter to more complex filters, including Bayesian filter methods such as Kalman filters or higher order fits to the borehole contributions.', 'Sharp transitions can be handled by adaptive filtering.', 'To illustrate another embodiment of the process \n73\n, \nFIG.', '9\n shows an example of a process \n120\n for determining a weight percent of an element based on capture measurements from two detectors.', 'The process \n120\n uses the apparent inelastic elemental weight percent measured by two detectors, instead of their capture weights as shown in the process \n106\n.', 'In general, a first inelastic weight percent \n122\n and a second inelastic weight percent \n124\n are received as inputs.', 'A difference \n126\n between the first inelastic weight percent \n122\n and the second inelastic weight percent \n124\n is determined by a processor (e.g., processor \n30\n).', 'Additionally, an average inelastic weight percent \n128\n may be determined.', 'A borehole weight percent \n130\n may be determined based on the difference \n126\n and a formation weight percent \n132\n may be determined based on the difference \n126\n and the average inelastic weight percent \n128\n.', 'The discussion from the illustrated process \n106\n are also applicable here, including regarding the compensation correction, the use of additional inputs, and the use of filtering.', 'The processes \n106\n and \n120\n are more suitable for multi-detector spectroscopy measurements.', 'Some spectroscopy tools may have one detector.', 'In that case, the processes \n134\n and \n148\n shown in \nFIG.', '10\n and \nFIG.', '11\n, respectively) can be used.', 'To illustrate another embodiment of the process \n73\n which may be employed using independent measurements from a single detector, \nFIG.', '8\n shows an example of a process \n134\n for determining a weight percent of an element based on capture measurements from two detectors.', 'The process \n134\n uses the apparent inelastic and capture elemental weight percent measured by one detector.', 'As shown, a capture weight percent \n136\n and an inelastic weight percent \n138\n are received as inputs.', 'A difference \n140\n between the capture weight percent \n136\n and inelastic weight percent \n138\n is determined by a processor (e.g., processor \n30\n).', 'Additionally, an average weight percent \n142\n may be determined.', 'A borehole weight percent \n144\n may be determined based on the difference \n140\n and a formation weight percent \n146\n may be determined based on the difference \n140\n and the average weight percent \n142\n.', 'The discussion from the method illustrated by process \n106\n is also applicable here, including regarding the compensation correction, the use of additional inputs, and the use of filtering.', 'The process \n134\n of \nFIG.', '10\n illustrates the basic principle of another embodiment of the present techniques.', 'It uses the apparent weight percent of an element that can be measured by both capture and inelastic spectroscopy.', 'The capture measurement can have a deeper DOI than the inelastic measurement.', 'So, the capture apparent weight percent can have more formation contribution and less borehole contribution than the inelastic one.', 'Following the same principle, the difference can be used for borehole evaluation, and to compensate the borehole contribution in the individual capture or inelastic apparent weight percents or the average one to get an accurate formation elemental weight percent for formation evaluation applications.', 'This method can may be applied to elements which may be measured by both capture and inelastic spectroscopy, including S\ni\n, Ca, Mg, Al, Fe, S, and so on.', 'For the elements which may be measured by capture but not inelastic scattering, the process \n148\n illustrated in \nFIG.', '11\n can be used.', 'FIG.', '11\n shows an example of a process \n148\n for determining a weight percent of an element based on capture measurements from one or two detectors.', 'As shown, an early capture weight percent \n150\n and a late capture weight percent \n152\n are received as inputs.', 'A difference \n154\n between the early capture weight percent \n150\n and the late capture weight percent \n152\n is determined by a processor (e.g., processor \n30\n).', 'Additionally, an average capture weight percent \n156\n may be determined.', 'A borehole weight percent \n158\n may be determined based on the difference \n154\n and a formation weight percent \n160\n may be determined based on the difference \n154\n and the average capture weight percent \n156\n.', 'The discussion from the illustrated processes \n106\n, \n120\n, and \n134\n are also applicable here, including regarding the compensation correction, the use of additional inputs, and the use of filtering.', 'The capture spectra (e.g., early capture and late capture) recorded during different timing gates (relative to the neutron burst-on time) will have different DOI.', 'The data acquired in an early timing gate (sooner after the neutron bursts) has a shallower DOI, more borehole contribution, and less formation contribution than the one in a later timing gate.', 'Following the same principle, the difference can be used for borehole evaluation, and to compensate the borehole contribution in the individual early or late capture apparent weight percent or the average one to get an accurate formation elemental weight percent for formation evaluation applications.', 'All the above processes (e.g., process \n106\n, process \n120\n, process \n134\n, and process \n148\n) and combinations of elemental measurements may be applied to normalized spectral yields directly, in addition to or as an alternative to the use of elemental weight concentrations.', 'An environmentally dependent correction factor may account for the “gain” effects that were introduced previously and which are handled in the above methods by the FY2W factor.', 'For example, the yields of two different detectors may be combined (analogous to process \n106\n), with Yield1_CAPi being the capture yield for element i from detector \n1\n, and with Yield2_CAPi being the capture yield for element i from detector \n2\n.', 'The difference Yield_Diff_CAPi is the difference between the two yields, and the compensated borehole yield may be defined as Borehole_Yi=f(Yield_Diff_CAPi, env), which uses the yield difference in a correction function which is a function of the surrounding environment.', 'The inputs to the function may be geometrical or compositional properties of the environment (such as bit size) and/or they may be other measurements (detector count rate ratios, apparent sigma, etc.).', 'The borehole yield can be used to correct either of the separate detector yields or an average of the two.', 'The corrected borehole or formation yields can be used to estimate some aspect of the borehole or formation regions.', 'The following discussion presents several non-limiting examples of embodiments of the present techniques described herein.', 'Example 1\n \nHydrogen may be measured by capture spectroscopy.', 'One can use the process \n106\n (if with two detectors) or the process \n148\n (with single detector) to get formation and borehole hydrogen weight percent.', 'The formation hydrogen can be used for formation evaluation to get water vs oil saturation, total porosity, kerogen maturity or other kerogen properties (if combined with carbon measurement), formation salinity (if combined with chlorine and carbon measurements), and so on.', 'The borehole hydrogen can be used to get borehole liquid vs gas holdup (since liquid has a lot more hydrogen than gas), borehole salinity (if combined with borehole chlorine and carbon measurements), scale buildup (scale built up inside the casing will exclude completion brine and cause borehole hydrogen to decrease), and so on.', 'Example 2\n \nChlorine may be measured by capture spectroscopy.', 'One can use the process \n106\n (if with two detectors) or the process \n148\n (with a single detector) to get formation and borehole chlorine weight percent.', 'The formation chlorine can be used for formation evaluation to get water vs oil saturation, formation salinity (if combined with hydrogen and carbon measurements or with measurements of total porosity, lithology, and carbon), and so on.', 'The borehole chlorine can be used to get borehole water vs oil/gas holdup, borehole salinity (if combined with borehole hydrogen and carbon measurements), and so on.', 'One of ordinary skill in the art would appreciate that the techniques of the present disclosure do not require the use of elemental ratios as the two independent measurements, either from the two detectors or two acquisition times.', 'For example, to estimate salinity of the formation or borehole, the techniques of the present disclosure do not use a Cl/H ratio for each detector.', 'Rather, the techniques of the present disclosure show how the two independent measurements of Cl are combined to estimate the absolute Cl concentration in the borehole or formation.', 'The same procedure can be applied to estimate the absolute concentration of H in either region.', 'And the absolute Cl and H concentrations can be combined to estimate the salinity of either region, if desired.', 'Example 3\n \nCalcium may be measured by both capture and inelastic spectroscopy.', 'All processes, \n106\n, \n120\n, \n134\n, and \n148\n can be applied to calcium.', 'Since cement typically contains calcium, the borehole calcium can be used for cement evaluation and well integrity applications.', 'The formation calcium can be used to solve the formation rock lithology (quartz has no calcium while carbonate has calcium).', 'Example 4\n \nSilicon may be measured by both capture and inelastic spectroscopy.', 'All processes \n106\n, \n120\n, \n134\n, and \n148\n can be applied to silicon.', 'Since some type of cements can contain silicon, the borehole silicon can be used for cement evaluation and well integrity applications.', 'Gravel pack contains a lot of silicon, so the borehole silicon can also be used for gravel pack evaluation.', 'The formation silicon can be used to solve the formation rock lithology (quartz has silicon while carbonate has none).', 'Example 5\n \nIron may be measured by both capture and inelastic spectroscopy.', 'All processes \n106\n, \n120\n, \n134\n, and \n148\n can be applied to iron.', 'Since casing typically contains a lot of iron, the borehole iron can be used for casing corrosion and well integrity applications.', 'The formation iron can be used to solve the formation rock lithology (shale, pyrite).', 'Example 6\n \nCarbon may be measured by inelastic spectroscopy, and thus, the process \n120\n can be applied.', 'The borehole carbon can be used for borehole oil holdup measurement.', 'The formation carbon can be used for oil saturation measurement, kerogen volume measurement, or evaluation of kerogen maturity or other kerogen properties such as density (if combined with formation hydrogen and other measurements).', 'As noted above in Example 2, this application is novel and distinct from prior art because the techniques of the present disclosure do not require the use of elemental ratios as the two independent measurements from the two detectors.', 'For example, to estimate the oil saturation of the formation, the techniques of the present disclosure do not use a C/O ratio for each detector.', 'Rather, the techniques of the present disclosure teach how the two independent measurements of C are combined to estimate the absolute C concentration in the borehole or formation.', 'This information can be used directly to estimate borehole oil holdup or formation oil saturation.', 'Example 7\n \nOxygen may be measured by inelastic spectroscopy.', 'For example, the process \n120\n may be applied.', 'The borehole oxygen can be used for borehole water vs. oil holdup measurement.', 'The formation oxygen can be used for rock lithology and water vs oil saturation measurement.', 'Example 8\n \nPotassium may be measured by both capture and inelastic spectroscopy.', 'All processes \n106\n, \n120\n, \n134\n, and \n148\n can be applied to potassium.', 'Some drilling fluids contain KCl brine or other potassium-bearing additives which create a borehole contribution to the total potassium measurement.', 'The formation potassium, after compensation for the borehole signal, can be used for rock lithology (for example, feldspars contain potassium).', 'Example 9\n \nGadolinium may be measured by capture spectroscopy.', 'One can use the process \n106\n (if with two detectors) or the process \n148\n (with single detector) to get formation and borehole gadolinium weight percent.', 'The formation gadolinium measurement can be used to solve lithology, and shale volume.', 'In some applications, the cased hole cement can be doped with gadolinium, so that the borehole gadolinium measurement can be used for cement evaluation.', 'The gravel packs can also be doped with gadolinium, in that case the borehole gadolinium measurement can be used for gravel pack evaluation.', 'The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms.', 'It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.'] | ['1.', 'A system for determining a property of a geological formation, comprising:\na neutron source configured to emit neutrons into a borehole of the geological formation;\ntwo or more gamma-ray detectors configured to receive gamma rays resulting from interactions between the neutrons emitted by the neutron source and the geological formation to generate a plurality of independent measurements, wherein each independent measurement of the plurality of independent measurements is associated with a different region within the geological formation or the borehole, or both the geological formation and the borehole; and\na processor configured to:\nacquire a first energy spectrum which contains at least in part a first independent measurement of the plurality of independent measurements;\nacquire a second energy spectrum which contains at least in part a second independent measurement of the plurality of independent measurements; and\ndetermine an elemental concentration based at least in part on a combination of the first energy spectrum and the second energy spectrum, wherein a first independent measurement of the plurality of independent measurements comprises a capture measurement and wherein a second independent measurement of the plurality of independent measurements comprises an inelastic measurement.', '2.', 'The system of claim 1, wherein at least two independent measurements of the plurality of independent measurements are from different detectors of the two or more gamma-ray detectors.', '3.', 'The system of claim 2, wherein a first independent measurement of the plurality of independent measurements comprises a capture measurement acquired in a first timing gate relative to a pulsed neutron burst emitted by the neutron source and a second independent measurement of the plurality of independent measurements comprises a capture measurement acquired in a second timing gate relative to the pulsed neutron burst emitted by the neutron source.', '4.', 'The system of claim 2, wherein the at least two independent measurements of the plurality of independent measurements comprise capture measurements.', '5.', 'The system of claim 4, wherein the energy spectra contain gamma rays from at least one element, the at least one element comprising hydrogen, chlorine, or both.\n\n\n\n\n\n\n6.', 'The system of claim 2, wherein the at least two independent measurements of the plurality of independent measurements comprise inelastic measurements.', '7.', 'The system of claim 6, wherein the energy spectra contain gamma rays from at least one element, the at least one element comprising carbon, oxygen, or both.\n\n\n\n\n\n\n8.', 'The system of claim 1, wherein a first gamma-ray detector of the two or more gamma-ray detectors is configured to acquire a first energy spectrum of the energy spectra from a first depth of investigation, and wherein a second gamma-ray detector of the two or more gamma-ray detectors acquires a second energy spectrum of the energy spectra from a second depth of investigation.', '9.', 'The system of claim 1, wherein the processor is configured to:\ndetermine an apparent borehole weight concentration based at least in part on an additional combination of at least two of a plurality of element yields, wherein the elemental concentration is determined based at least in part on the apparent borehole weight concentration.\n\n\n\n\n\n\n10.', 'A method for determining an elemental concentration in a geological formation, comprising:\nemitting neutrons, from a neutron generator placed into a borehole in the geological formation, to cause capture events and inelastic scattering events that generate photons;\ndetecting, using one or more detectors, the photons associated with the capture events to generate a plurality of independent measurements, wherein a first independent measurement of the plurality of independent measurements comprises capture measurements and wherein a second independent measurement of the plurality of independent measurements comprises inelastic measurements;\nacquiring a first energy spectrum which contains at least in part the first independent measurement;\nacquiring a second energy spectrum which contains at least in part the second independent measurement; and\ndetermining the elemental concentration based at least in part on a combination of the first energy spectrum and the second energy spectrum, wherein the borehole of the geological formation is completed with casing, cement, tubing, or gravel packs, or any combination thereof, and wherein the elemental concentration relates to an element present in both the geological formation and the casing, cement, tubing, or gravel packs, or any combination thereof.', '11.', 'The method of claim 10, wherein the first energy spectrum and the second energy spectrum contain gamma rays from at least one element, the at least one element comprising calcium, silicon, iron, potassium, aluminum, and sulfur.\n\n\n\n\n\n\n12.', 'The method of claim 10, comprising determining an apparent borehole weight concentration based at least in part on a combination of the first energy spectrum and the second energy spectrum, wherein the elemental concentration is determined based at least in part on the apparent borehole weight concentration.', '13.', 'The method of claim 12, comprising filtering the apparent borehole weight concentration to generate a filtered apparent borehole weight concentration, wherein the elemental concentration is determined based at least in part on the filtered apparent borehole weight concentration.', '14.', 'The method of claim 10, wherein the photons are detected during a time period defined by timing gates occurring during a pulsing scheme of the neutron generator, operatively controlled by a processor.', '15.', 'A method for determining an elemental concentration in a geological formation, comprising:\nemitting neutrons, from a neutron generator, placed into the borehole in the geological formation, to cause capture and inelastic scattering events that generate photons;\ndetecting, using one or more detectors, the photons associated with the capture events to generate a plurality of independent measurements, wherein a first independent measurement of the plurality of independent measurements comprises early capture measurements and wherein a second independent measurement of the plurality of independent measurements comprises late capture measurements;\nacquiring a first energy spectrum which contains at least in part the first independent measurement;\nacquiring a second energy spectrum which contains at least in part the second independent measurement; and\ndetermining the elemental concentration based at least in part on a combination of the first energy spectrum and the second energy spectrum.', '16.', 'The method of claim 15, wherein the elemental concentration relates to an element present in both the geological formation and cement present in the borehole of the geological formation.', '17.', 'The method of claim 15, wherein the energy spectra contain gamma rays from chlorine.', '18.', 'The method of claim 15, comprising determining an apparent borehole element weight concentration based at least in part on an additional combination of at least two of the plurality of element yields, wherein the elemental concentration is determined based at least in part on the apparent borehole weight concentration.'] | ['FIG.', '1 is an example of a neutron-induced gamma-ray spectroscopy system, in accordance with an embodiment;; FIG.', '2 is an example of a neutron-induced gamma-ray spectroscopy downhole tool, in accordance with an embodiment;; FIG.', '3 shows a pulsing scheme, in accordance with an embodiment;; FIG.', '4 shows capture and inelastic cumulative fractional signals detected by a first detector and a second detector as a function of depth of investigation, in accordance with an embodiment in an open hole condition;; FIG.', '5 shows various cumulative fractional signals detected by a first detector and a second detector as a function of depth of investigation, in accordance with an embodiment in a cased hole condition;; FIG.', '6 is a flow diagram illustrating an elemental yield evaluation method, in accordance with an embodiment;; FIG. 7 is a flow diagram illustrating a method for determining apparent element weight, in accordance with an embodiment;; FIG. 8 is a flow diagram illustrating a first method for determining borehole and formation compensation, in accordance with an embodiment;; FIG.', '9 is a flow diagram illustrating a second method for determining borehole and formation compensation, in accordance with an embodiment;; FIG.', '10 is a flow diagram illustrating a third method for determining borehole and formation compensation, in accordance with an embodiment; and; FIG.', '11 is a flow diagram illustrating a fourth method for determining borehole and formation compensation, in accordance with an embodiment.; FIG.', '2 shows a downhole tool 12 for detecting neutron-induced gamma ray spectroscopy.', 'As shown, the downhole tool 12 includes two gamma ray detectors (e.g., first detector 42 and second detector 44).', 'However, in certain embodiments, the downhole tool 12 may have one scintillator gamma ray detector (e.g., first detector 42 or second detector 44).', 'Some of the methods in this disclosure can be applied to single-detector spectroscopy tools, and some are more suitable for multi-detector spectroscopy tools.', 'The downhole tool 12 is equipped with a neutron source 40 (e.g., pulsed neutron generator (PNG)) that emits neutrons (e.g., generally illustrated by the arrow 41).', 'A PNG may be turned on and off repeatedly in a pattern.', 'Additionally, the downhole tool 12 includes shielding 46 that may prevent neutrons from the neutron source 40 from transmitting directly into the first detector 42 and second detector 44 (e.g., without first passing through the geological formation 14 or borehole 16).; FIG.', '5 shows how the radial DOI of the capture spectrum for two detectors is affected by the timing of the capture acquisition gates.', 'Lines 62, 64, and 66 are the signals for Near (e.g., measured by first detector 42) capture total, early capture, and late capture, respectively.', 'Lines 68, 70, and 72 are the signals for Far (e.g., measured by second detector 44) capture total, early capture, and late capture, respectively.', 'The capture signal acquired late after the PNG burst comes from a deeper radial position, on average, than the capture signal acquired soon after the PNG burst.', 'The late signal has more time for neutron diffusion to occur, which increases the relative population of neutrons at greater radial depths.;', 'FIG. 6 illustrates an example of a process 73 for determining an elemental weight percent and/or element concentration based on measurements from one or more detector.', 'Although described in a particular order, which represents a particular embodiment, it should be noted that the process 73 may be performed in any suitable order.', 'Additionally, embodiments of the process 73 may omit process blocks and/or include additional process blocks.', 'Moreover, in some embodiments, the process 73 may be implemented at least in part by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as memory 32 implemented in a data processing system 28, using processing circuitry, such as a processor 30 implemented in the data processing system 28.'] |
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housing to direct a laser beam to form a radial slot extending through the casing and into the subterranean formation.', 'The motor rotates the deflector.', 'The sensor generates information related to depth of the radial slot in real-time as the radial slot is formed by the laser beam.', 'The processing device receives the information generated by the sensor and causes the motor to rotate the deflector based on the received information.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a national stage application of PCT Application No.', 'PCT/US2015/058199, entitled CREATING RADIAL SLOTS IN A SUBTERRANEAN FORMATION, filed Oct. 30, 2015, which claims priority to and the benefit of U.S. Provisional Application No. 62/072,894, entitled “LASER CUTTING SEQUENCE AND CONTROL SYSTEM FOR CUTTING SLOTS IN WELLBORES”, filed Oct. 30, 2014, the entire disclosures of each being hereby incorporated herein by reference.', 'BACKGROUND OF THE DISCLOSURE\n \nOilfield operations may be performed to locate and gather downhole fluids, such as those containing hydrocarbons.', 'Wellbores may be drilled along a selected trajectory to reach one or more subterranean rock formations containing the hydrocarbons and other downhole fluids.', 'The trajectory may be defined to facilitate passage through the subterranean rock formations and to facilitate production.', 'The selected trajectory may have vertical, angled, and/or horizontal portions, based on stresses, boundaries, and/or other characteristics of the formation.', 'Fracturing operations may include creating and/or expanding fractures in the formation to create and/or increase flow pathways within the formation, such as by injecting fracturing fluid into the formation via a wellbore penetrating the formation.', 'Fracturing may be affected by various factors related to the wellbore, such as the presence of casing and cement in the wellbore, open-hole completions, and the intended spacing for fracturing and/or injection, among other examples.', 'Prior to fracturing operations, the formation may be perforated along a plane that is transverse (i.e., perpendicular) to a wellbore axis.', 'Fracturing fluid is then pumped into the perforations to propagate fractures along the same plane.', 'However, at distances further away from the wellbore, the direction of the fractures may change if the perforations were not cut deep enough.', 'Changes in the direction of the fractures may result in complex fluid pathways extending to the wellbore, resulting in a bottleneck that may reduce overall hydraulic conductivity of the fractures and, thus, adversely impact hydrocarbon productivity.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus that includes a laser cutting apparatus conveyable within a casing lining at least a portion of a wellbore that extends into a subterranean formation.', 'The laser cutting apparatus includes a housing, a deflector, a motor, a sensor, and a processing device.', 'The deflector is operable for rotation relative to the housing to direct a laser beam to form a radial slot extending through the casing and into the subterranean formation.', 'The motor is operable to rotate the deflector.', 'The sensor is operable to generate information related to depth of the radial slot in real-time as the radial slot is formed by the laser beam.', 'The processing device is operable to receive the information generated by the sensor and cause the motor to rotate the deflector based on the received information.', 'The present disclosure also introduces a method that includes conveying a laser cutting apparatus within a casing lining at least a portion of a wellbore that extends into a subterranean formation, and transmitting a laser beam to a deflector of the laser cutting apparatus.', 'The method also includes operating a motor of the laser cutting apparatus to control rotation of the deflector, thus directing the laser beam deflected by the deflector to form a radial slot extending through the casing to a predetermined depth within the subterranean formation, including operating the motor to sequentially rotate the deflector to each one of a plurality of angular positions and maintain the deflector at each successive one of the plurality of angular positions until the laser beam penetrates the subterranean formation to a predetermined depth at that angular position, such that the radial slot extends through a predetermined angle encompassing the plurality of angular positions.', 'The present disclosure also introduces a method that includes conveying a laser cutting apparatus within a casing lining at least a portion of a wellbore that extends into a subterranean formation, and transmitting a laser beam to a deflector of the laser cutting apparatus.', 'The method also includes operating a motor of the laser cutting apparatus to repeatedly rotate the deflector through a plurality of cycles, where each of the plurality of cycles comprises a first substantially continuous rotation of the deflector through a predetermined angle in a first rotational direction and a second substantially continuous rotation of the deflector through the predetermined angle in a second rotational direction, thus directing the laser beam deflected by the deflector to form a radial slot extending radially through the casing and, with each successive one of the plurality of cycles, extend the radial slot to a predetermined depth within the subterranean formation, such that opposing first and second sides of the radial slot are angularly disposed at the predetermined angle.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a sectional view of an example implementation of a portion of the apparatus shown in \nFIG.', '1\n according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of an example implementation of a portion of the apparatus shown in \nFIG.', '1\n according to one or more aspects of the present disclosure.', 'FIG.', '4\n is a schematic view of the apparatus shown in \nFIG.', '3\n during operation according to one or more aspects of the present disclosure.', 'FIG.', '5\n is a schematic view of the apparatus shown in \nFIG.', '3\n during operation according to one or more aspects of the present disclosure.', 'FIG.', '6\n is a schematic view of the apparatus shown in \nFIG.', '3\n during operation according to one or more aspects of the present disclosure.', 'FIG.', '7\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.\n \nFIG.', '1\n is a schematic view of at least a portion of an example implementation of a wellsite system \n100\n according to one or more aspects of the present disclosure.', 'The wellsite system \n100\n is operable at a wellsite \n105\n adjacent a wellbore \n120\n extending from the wellsite \n105\n into one or more subterranean formations \n130\n.', 'In the context of the present disclosure, the term “subterranean formation” (or simply “formation”) may be given its broadest possible meaning and may include, without limitation, various rocks and other natural materials, as well as cement and other artificial materials, including rock layer formations, such as, granite, basalt, sandstone, dolomite, sand, salt, limestone, rhyolite, quartzite, and shale, among others.', 'The wellbore \n120\n comprises a central axis \n150\n and a wellbore diameter \n154\n.', 'When utilized in cased-hole implementations, a cement sheath \n124\n may secure a casing \n122\n within the wellbore \n120\n.', 'The example wellsite system \n100\n is operable to form radial slots and/or perforations (hereafter collectively referred to as radial slots) \n132\n in the wellbore casing \n122\n, the cement sheath \n124\n, and the formation \n130\n.', 'At the wellsite \n105\n, the wellsite system \n100\n may comprise a control and power center \n180\n, which may provide control signals and electrical power via electrical conductors \n181\n, \n182\n, \n183\n extending between the control and power center \n180\n and a laser source \n190\n, a laser generator chiller \n185\n, and a tool string \n110\n positioned within the wellbore \n120\n.', 'The laser source \n190\n may provide energy in the form of a laser beam to a laser cutting apparatus \n200\n that forms at least a portion of the tool string \n110\n.', 'An optical conductor \n191\n, such as may comprise one or more fiber optic cables, may convey the laser beam from the laser source \n190\n to the laser cutting apparatus \n200\n.', 'The wellsite system \n100\n may further comprise a fluid source \n140\n from which a fluid (hereinafter referred to as a “surface fluid”) may be conveyed by a fluid conduit \n141\n to a spool \n160\n of coiled tubing \n161\n and/or other conduits that may be deployed into the wellbore \n120\n.', 'The spool \n160\n may be rotated to advance and retract the coiled tubing \n161\n within the wellbore \n120\n.', 'The optical conductor \n191\n, the electrical conductor \n181\n, and the fluid conduit \n141\n may be attached to the coiled tubing \n161\n by, for example, a swivel or other rotating coupling \n163\n.', 'The coiled tubing \n161\n may be operable to convey the surface fluid received from the fluid source \n140\n along the length of the wellbore \n120\n to the tool string \n110\n coupled at the downhole end of the coiled tubing \n161\n.', 'The coiled tubing \n161\n may be further operable to transmit or convey therein the optical conductor \n191\n and/or the electrical conductor \n181\n from the wellsite \n105\n to the tool string \n110\n.', 'The electrical and optical conductors \n181\n, \n191\n may be disposed within the coiled tubing \n161\n inside a protective metal carrier (not shown) to insulate and protect the conductors \n181\n, \n191\n from the surface fluid inside the coiled tubing \n161\n.', 'However, the optical conductor \n191\n and/or the electrical conductor \n181\n may also or instead be conveyed into the wellbore \n120\n on the outside of the coiled tubing \n161\n.', 'The wellsite system \n100\n may further comprise a support structure \n170\n, such as may include a coiled tubing injector \n171\n and/or other apparatus operable to facilitate movement of the coiled tubing \n161\n in the wellbore \n120\n.', 'Other support structures may be also or instead included, such as a derrick, a crane, a mast, a tripod, and/or other structures.', 'A diverter \n172\n, a blow-out preventer (BOP) \n173\n, and/or a fluid handling system \n174\n may also be included as part of the wellsite system \n100\n.', 'For example, during deployment, the coiled tubing \n161\n may be passed from the injector \n171\n, through the diverter \n172\n and the BOP \n173\n, and into the wellbore \n120\n.', 'The tool string \n110\n may be conveyed along the wellbore \n120\n via the coiled tubing \n161\n in conjunction with the coiled tubing injector \n171\n, such as may be operable to apply an adjustable uphole and downhole force to the coiled tubing \n161\n to advance and retract the tool string \n110\n within the wellbore \n120\n.', 'Although \nFIG.', '1\n depicts a coiled tubing injector \n171\n, it is to be understood that other means operable to advance and retract the tool string \n110\n, such as a crane, a winch, a draw-works, a top drive, and/or other lifting device coupled to the tool string \n110\n via the coiled tubing \n161\n and/or other conveyance means (e.g., wireline, drill pipe, production tubing, etc.), may also or instead be included as part of the wellsite system \n100\n.', 'During cutting operations, the surface fluid may be conveyed through the coiled tubing \n161\n and be directed into the radial slots \n132\n adjacent to the tool string \n110\n.', 'Thereafter, the surface fluid and other wellbore fluid may exit the radial slots \n132\n into an annular area between the sidewall of the casing \n122\n and the tool string \n110\n and flow in the uphole direction out of the wellbore \n120\n.', 'The diverter \n172\n may direct the returning fluid to the fluid handling system \n174\n through one or more conduits \n176\n.', 'The fluid handling system \n174\n may be operable to clean the returning fluid and/or prevent the returning fluid from escaping into the environment.', 'The cleaned surface fluid may then be returned to the fluid source \n140\n or otherwise contained for later use, treatment, and/or disposal.', 'The tool string \n110\n may comprise a first portion \n111\n, a second portion \n112\n coupled with the first portion \n111\n, and the laser cutting apparatus \n200\n coupled with the second portion \n112\n.', 'The tool string \n110\n is further shown in connection with the optical conductor \n191\n and the electrical conductor \n181\n, which may extend through at least a portion of the first and second portions \n111\n, \n112\n of the tool string \n110\n and the laser cutting apparatus \n200\n.', 'As stated above, the optical conductor \n191\n may be operable to transmit the laser beam from the laser source \n190\n to the laser cutting apparatus \n200\n, whereas the electrical conductor \n181\n may be operable to transmit electrical control signals and/or electrical power between the control and power center \n180\n and the first and second portions \n111\n, \n112\n of the tool string \n110\n and/or the laser cutting apparatus \n200\n.', 'The electrical conductor \n181\n may also permit electrical communication between the first and second portions \n111\n, \n112\n of the tool string \n110\n and the laser cutting apparatus \n200\n, and may comprise various electrical connectors and/or interfaces (not shown) for electrical connection with the first and second portions \n111\n, \n112\n of the tool string \n110\n and the laser cutting apparatus \n200\n.', 'Although the electrical conductor \n181\n is depicted in \nFIG.', '1\n as a single continuous electrical conductor, the wellsite system \n100\n may comprise a plurality of electrical conductors (not shown) extending along the coiled tubing \n161\n, wherein one or more of the conductors may be separately connected with the first portion \n111\n, the second portion \n112\n, and/or the laser cutting apparatus \n200\n.', 'Also, although \nFIG.', '1\n depicts the laser cutting apparatus \n200\n being coupled at the downhole end of the tool string \n110\n, the laser cutting apparatus \n200\n may be coupled between the first and second portions \n111\n, \n112\n of the tool string \n110\n, or further uphole in the tool string \n110\n with respect to the first and the second portions \n111\n, \n112\n.', 'The tool string \n110\n may also comprise more than one instance of the laser cutting apparatus \n200\n, as well as other apparatus not explicitly described herein.', 'The first and second portions \n111\n, \n112\n of the tool string \n110\n may each be or comprise at least a portion of one or more downhole tools, modules, and/or other apparatus operable in wireline, while-drilling, coiled tubing, completion, production, and/or other operations.', 'For example, the first and second portions \n111\n, \n112\n may each be or comprise at least a portion of an acoustic tool, a density tool, a directional drilling tool, a drilling tool, an electromagnetic (EM) tool, a formation evaluation tool, a gravity tool, a formation logging tool, a magnetic resonance tool, a formation measurement tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a surveying tool, a telemetry tool, and/or a tough logging condition tool.', 'However, other downhole tools are also within the scope of the present disclosure.', 'Although \nFIG.', '1\n depicts the tool string \n110\n comprising two portions \n111\n, \n112\n directly and/or indirectly coupled with the laser cutting apparatus \n200\n, it is to be understood that the tool string \n110\n may comprise a different number of portions each directly and/or indirectly coupled with the laser cutting apparatus \n200\n.', 'The first portion \n111\n may be or comprise a logging tool, such as a casing collar locator (CCL) operable to detect ends of collars of the casing \n122\n by sensing a magnetic irregularity caused by the relatively high mass of the collar ends.', 'The CCL may transmit a signal in real-time to wellsite equipment, such as the control and power center \n180\n, via the electrical conductor \n181\n.', 'The CCL signal may be utilized to determine the position of the laser cutting apparatus \n200\n with respect to known casing collar numbers and/or positions within the wellbore \n120\n.', 'Therefore, the CCL may be utilized to detect and/or log the location of the laser cutting apparatus \n200\n within the wellbore \n120\n.', 'Although the first portion \n111\n comprising the CCL is depicted as separate tool indirectly coupled with the laser cutting apparatus \n200\n, it is to be understood that the CCL or other locator tool may be integrated into the laser cutting apparatus \n200\n.', 'The second portion \n112\n of the tool string \n110\n may be or comprise an inclination sensor and/or other orientation sensors, such as one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for utilization in determining the orientation of the tool string \n110\n relative to the wellbore \n120\n.', 'Although the second portion \n112\n comprising the orientation sensor(s) is depicted as a separate tool coupled with the laser cutting apparatus \n200\n, it is to be understood that the orientation sensor(s) may be integrated into the laser cutting apparatus \n200\n.', 'An anchoring device \n115\n may also be included as part of the tool string \n110\n, such as may be operable to positionally fix or set the laser cutting apparatus \n200\n relative to the wellbore \n120\n (e.g., against the casing \n122\n) at an intended location for cutting the radial slots \n132\n in the casing \n122\n and/or the formation \n130\n.', 'For example, the anchoring device \n115\n may positively fix or set the laser cutting apparatus \n200\n along the central axis \n150\n of the wellbore \n120\n, such that a central axis \n215\n (e.g., see \nFIG.', '2\n) of the laser cutting apparatus \n200\n may substantially coincide with the central axis \n150\n of the wellbore \n120\n.', 'Centralizing of the laser cutting apparatus \n200\n along the wellbore \n120\n may further centralize an axis of rotation \n251\n of a deflector \n250\n of the laser cutting apparatus \n200\n (e.g., see \nFIG.', '2\n), such that the central axis \n150\n of the wellbore \n120\n and the axis of rotation \n251\n substantially coincide.', 'The anchoring device \n115\n may be controlled mechanically, hydraulically, electrically, and/or otherwise, including in implementations permitting retraction of the anchoring device \n115\n before moving the coiled tubing \n161\n to another location.', 'The anchoring device \n115\n may be selected from various fixation or setting devices, such as an anchor or a packer, which may be operable to centralize, anchor, and/or fix the tool string \n110\n and/or the laser cutting apparatus \n200\n at a predetermined stand-off distance and/or position along the wellbore \n120\n.', 'The anchoring device \n115\n may also or instead comprise embedding or friction elements, such as bumpers or slips, which may engage the inner surface of the casing \n122\n.', 'Although \nFIG.', '1\n depicts the anchoring device \n115\n as part of the laser cutting apparatus \n200\n, it is to be understood that the anchoring device \n115\n may be included in the tool string \n110\n as a separate tool or portion, such as part of the first and/or second portions \n111\n, \n112\n of the tool string \n110\n.\n \nFIG.', '1\n further depicts coordinates axes X, Y, and Z, which may be utilized as references to aid in identifying relative positions of certain aspects of the tool string \n110\n or components thereof within three-dimensional space.', 'The X-axis extends in a downhole direction along the central axis \n150\n of the wellbore \n120\n, and may substantially coincide with the central axis \n215\n of the laser cutting apparatus \n200\n during operation of the laser cutting apparatus \n200\n.', 'The Y-axis extends vertically with respect to the Earth and perpendicularly with respect to the X-axis, and the Z-axis extends perpendicularly with respect to the X- and Y-axes.', 'The laser cutting apparatus \n200\n is operable to create the radial slots \n132\n and other radial slots not shown in \nFIG.', '1\n.', 'The radial slots \n132\n may be utilized to initiate one or more hydraulic fractures along a plane that is substantially transverse to the central axis \n150\n of the wellbore \n120\n, such as along the plane defined by the Y- and Z-axes, hereafter referred to as the Y-Z plane.', 'The radial slots \n132\n may penetrate deep enough into the formation \n130\n around the wellbore \n120\n so as to permit the hydraulic fracture(s) to propagate along the Y-Z plane as initiated.', 'As described below, the radial slots \n132\n may extend through or penetrate the casing \n122\n, the cement sheath \n124\n, and the formation \n130\n a predetermined depth \n152\n.', 'The predetermined depth \n152\n may be equal to about twice the wellbore diameter \n154\n, although other radial slot depths are also within the scope of the present disclosure.', 'Hydrocarbon productivity may be enhanced by forming the radial slots \n132\n through the formation \n130\n along a plane substantially transverse to the central axis \n150\n, such as the Y-Z plane.', 'Each radial slot \n132\n may be of angular sector geometry, circumferentially extending through a predetermined angle around the central axis \n150\n and the wellbore \n120\n.', 'One or more radial slots \n132\n may be formed at multiple positions along the wellbore \n120\n by moving the tool string \n110\n via the coiled tubing \n161\n, such as for a multi-stage fracturing treatment within a single coiled tubing trip.', 'However, the laser cutting apparatus \n200\n may also be operable in applications other than hydraulic fracture initiation, including applications in which shallower radial slots may be utilized.', 'As shown in \nFIG.', '1\n, the radial slots \n132\n may be substantially oriented along the direction of gravity.', 'Such orientation may be achieved via utilization of an inclination sensor and/or other orientation sensor(s), such as described above with respect to the second portion \n112\n of the tool string \n110\n, which may be utilized to measure the direction of gravity relative to the laser cutting apparatus \n200\n.', 'The orientation sensor(s) may also or instead be incorporated into a tool controller (such as the tool controller \n220\n shown in \nFIG.', '2\n), which may be operable to communicate signals from the orientation sensor(s) to the wellsite \n105\n via the electrical conductor \n181\n, although the signals may also or instead be processed by the controller \n220\n.', 'Accordingly, the orientation of the laser cutting apparatus \n200\n and/or the deflector \n250\n may be adjusted to form the radial slots \n132\n in a plane that is substantially coincident with the direction of gravity.', 'Although \nFIG.', '1\n shows the laser cutting apparatus \n200\n disposed within a horizontal portion of the wellbore \n120\n to form the radial slots \n132\n extending along the substantially vertical Y-Z plane, it is to be understood that the laser cutting apparatus \n200\n may also be utilized to form the radial slots \n132\n in a vertical or partially deviated portion of the wellbore \n120\n.', 'Because the radial slots \n132\n may be formed along a plane that is normal or transverse to the central axis \n150\n of the wellbore \n120\n, the resulting radial slots \n132\n may be formed along a plane extending substantially horizontally or diagonally with respect to the wellsite \n105\n.', 'FIG.', '2\n is a sectional view of at least a portion of an example implementation of the tool string \n110\n shown in \nFIG.', '1\n according to one or more aspects of the present disclosure.', 'The following description refers to \nFIGS.', '1 and 2\n, collectively.', 'The laser cutting apparatus \n200\n comprises a housing \n210\n, which defines an internal space \n205\n and a fluid pathway \n214\n within the laser cutting apparatus \n200\n.', 'The housing \n210\n may comprise a first housing section \n211\n and a second housing section \n212\n.', 'The first housing section \n211\n may be rotationally coupled with the second housing section \n212\n in a manner permitting the first housing section \n211\n to rotate relative to the second housing section \n212\n, such as about the axis of rotation \n251\n, which may substantially coincide with the central axis \n215\n of the laser cutting apparatus \n200\n and/or other portions of the tool string \n110\n.', 'The first housing section \n211\n may be disposed at the downhole end of the laser cutting apparatus \n200\n, and may comprise a bowl-shaped or other configuration having an open end \n217\n and a closed end \n216\n.', 'The open end \n217\n of the first housing section \n211\n may be rotatably engaged or otherwise coupled with the second housing section \n212\n, such as to permit the above-described rotation of the first housing section \n211\n relative to the second housing section \n212\n.', 'For example, the open end \n217\n of the first housing section \n211\n may be coupled with the second housing section \n212\n via a sliding joint \n219\n.', 'The closed end \n216\n of the first housing section \n211\n may be rounded, sloped, tapered, pointed, beveled, chamfered, and/or otherwise shaped with respect to the central axis \n215\n of the laser cutting apparatus \n200\n in a manner that may decrease friction forces between the laser cutting apparatus \n200\n and the casing \n122\n, the wellbore \n120\n, and/or wellbore fluid as the laser cutting apparatus \n200\n is conveyed downhole.', 'The first housing section \n211\n may enclose internal components of the laser cutting apparatus \n200\n and/or prevent the wellbore fluid from leaking into the interior space \n205\n of the laser cutting apparatus \n200\n.', 'The first housing section \n211\n may further comprise a window \n213\n that may permit transmission of a laser beam \n290\n from within the laser cutting apparatus \n200\n to a region external to the laser cutting apparatus \n200\n.', 'The window \n213\n may include an optically transparent material, such as glass or a transparent polymer, or the window \n213\n may be an aperture extending through a sidewall of the first housing section \n211\n.', 'The window \n213\n may have a substantially circular, rectangular, or other geometry, or may extend circumferentially around the entire first housing section \n211\n.', 'During cutting operations, the internal space \n205\n of the first housing section \n211\n may be filled with the surface fluid communicated through the coiled tubing \n161\n, such as to permit uninterrupted transmission of the laser beam \n290\n through the internal space \n205\n and/or to equalize internal pressure of the laser cutting apparatus \n200\n with hydrostatic wellbore pressure.', 'However, instead of being filled with the surface fluid, the internal space \n205\n of the first housing section \n211\n may be filled with gas, such as nitrogen, or may be substantially evacuated (e.g., at a vacuum), among other implementations permitting substantially uninterrupted transmission of the laser beam \n290\n through the internal space \n205\n.', 'The second housing section \n212\n may couple the laser cutting apparatus \n200\n with the second portion \n112\n of the tool string \n110\n or the coiled tubing \n161\n, such as may facilitate communication of the laser beam \n290\n to the laser cutting apparatus \n200\n.', 'For example, the second housing section \n212\n may be operable to receive therein or couple with the optical conductor \n191\n and/or otherwise permits transmission of the laser beam \n290\n from the laser source \n190\n to the deflector \n250\n.', 'The deflector \n250\n is operable to direct the laser beam \n290\n through the window \n213\n of the first housing section \n211\n to be incident upon intended locations along the casing \n122\n, the cement sheath \n124\n, and/or the formation \n130\n, including via rotation about the axis of rotation \n251\n.', 'For example, the cutting apparatus \n200\n may comprise a motor \n260\n operable to rotate the deflector \n250\n to control the rotational or angular direction or position of the deflector \n250\n.', 'The motor \n260\n may comprise a stator \n262\n and a rotor \n264\n.', 'The stator \n262\n may be fixedly coupled with respect to the second housing section \n212\n, and the rotor \n264\n may be coupled with or otherwise carry and thus rotate the deflector \n250\n.', 'For example, a body \n255\n may be coupled with or otherwise rotate with the rotor \n264\n, and the deflector \n250\n may be coupled with or otherwise carried with the body \n255\n.', 'The body \n255\n may comprise an optical passage or other opening permitting the laser beam \n290\n to pass from the optical conductor \n191\n to the deflector \n250\n.', 'The deflector \n250\n is or comprises a light deflecting member operable to direct the laser beam \n290\n emitted from the optical conductor \n191\n through the window \n213\n to be incident upon the casing \n122\n, the cement sheath \n124\n, and/or the formation \n130\n.', 'The deflector \n250\n may be or comprise a lens, a prism, a mirror, or another light deflecting member.', 'Although depicted as a single light deflecting member, the deflector \n250\n may comprise two or more prisms or mirrors, or the deflector \n250\n may comprise a rhomboid prism, among other example implementations within the scope of the present disclosure.', 'Instead of the first housing section \n211\n being rotatable, the first housing section \n211\n may be or comprise a non-rotatable protection cover fixedly coupled with the second housing section \n212\n.', 'In such implementations, the sliding joint \n219\n may not exist, and the first housing section \n211\n may instead be fixedly connected with the second housing section \n212\n via a threaded joint or other connection means.', 'Such implementations of the first housing section \n211\n may also not comprise the window \n213\n or other openings transparent to the laser beam \n290\n, but may instead comprise a material (e.g., aluminum) may be cut by the laser beam \n290\n.', 'During cutting operations in which one or more radial slots are to be formed at different depths within the wellbore \n120\n, the laser cutting apparatus \n200\n may be conveyed to the deepest position within the wellbore \n120\n at which radial slots \n132\n are to be formed such that the deepest one or more slots \n132\n are formed first, and then the next deepest slots \n132\n, and so on.', 'However, before the first (deepest) slots are formed, the laser beam \n290\n may be activated and the deflector \n250\n may be rotated through 360 degrees to cut off at least a portion (e.g., an end portion) of the first housing section \n211\n, which then falls off into the wellbore \n120\n.', 'The laser beam \n290\n, directed by the deflector \n250\n, may then be utilized to form the first set of radial slots \n132\n.', 'Thereafter, the tool string \n110\n, including the laser cutting apparatus \n200\n, may be moved along the wellbore \n120\n in the uphole direction until the laser cutting apparatus \n200\n is positioned at the next predetermined location at which another set of radial slots \n132\n are to be formed.', 'The above-described process may be repeated until each of the intended radial slots \n132\n are created, and the laser cutting apparatus \n200\n may then be removed from the wellbore \n120\n.', 'Limiting the amount of movement of the laser cutting apparatus \n200\n after the end portion of the first housing section \n211\n is cut off, especially movement in the downhole direction, may prevent or minimize contact between the deflector \n250\n and the side of the wellbore \n120\n or other obstacles in the wellbore \n120\n, such as may prevent or minimize damage to the deflector \n250\n that might otherwise occur if the laser cutting apparatus \n200\n is moved in the downhole direction after the end portion is cut off.', 'It is to be understood that the cutting operations described above are also applicable to implementations of the laser cutting apparatus \n200\n comprising the rotatable first housing section \n211\n.', 'However, because the rotatable housing section \n211\n is not cut off, the deflector \n250\n and other components are continuously covered, permitting the laser cutting apparatus \n200\n to be more readily moved in the downhole direction through the wellbore \n120\n without risking damage.', 'The second housing section \n212\n may also couple the laser cutting apparatus \n200\n with the second portion \n112\n of the tool string \n110\n or the coiled tubing \n161\n, such as may facilitate communication of the surface fluid from the coiled tubing \n161\n to the laser cutting apparatus \n200\n.', 'For example, the second housing section \n212\n may be operable to receive therein or couple with the coiled tubing \n161\n to direct the surface fluid along the fluid pathway \n214\n into the laser cutting apparatus \n200\n, as indicated in \nFIG.', '2\n by arrows \n202\n.', 'Thereafter, the surface fluid may be directed by additional fluid pathways \n218\n toward the body \n255\n, which may direct the surface fluid into the internal space \n205\n and/or out of the laser cutting apparatus \n200\n.', 'The body \n255\n comprises a fluid pathway \n256\n directing the surface fluid from the fluid pathway \n218\n into the internal space \n205\n.', 'At least a portion of the body \n255\n may extend radially outwards through the first housing section \n211\n, and this or another portion of the body \n255\n comprises a fluid pathway \n257\n directing the surface fluid from the fluid pathway \n218\n to outside the first housing section \n211\n.', 'The fluid pathway \n257\n may terminate with a fluid nozzle \n240\n and/or other means operable to form a stream \n142\n of surface fluid expelled from the fluid pathway \n257\n.', 'Although the nozzle \n240\n is depicted in \nFIG.', '2\n as being flush with the exterior of the first housing section \n211\n, the nozzle \n240\n may also protrude outward from the exterior of the first housing section \n211\n.', 'The body \n255\n may operatively couple the rotor \n264\n and the first housing section \n211\n, such as may permit the motor \n260\n to rotate the first housing section \n211\n.', 'The connection between the body \n255\n and the rotor \n264\n further permits the motor \n260\n to simultaneously rotate the deflector \n250\n and direct the nozzle \n240\n in the same direction.', 'That is, the nozzle \n240\n and the deflector \n250\n may be angularly aligned, relative to rotation around the axis \n251\n, such that the nozzle \n240\n may direct the fluid stream \n142\n in substantially the same direction that the deflector \n250\n directs the laser beam \n290\n (e.g., within about five degrees from each other).', 'For example, the nozzle \n240\n may be operable to discharge the fluid stream \n142\n along a radial path that substantially overlaps or coincides with a radial path of the laser beam \n290\n.', 'Accordingly, the fluid stream \n142\n may impact a portion of the formation \n130\n that is being cut by the laser beam \n290\n to flush out formation particles, dust, fumes, and/or other contaminants (hereafter collectively referred to as contaminants) generated during cutting operations.', 'The fluid stream \n142\n may also displace contaminants and wellbore fluid from the region generally defined by the path of the laser beam \n290\n extending from the laser cutting apparatus \n200\n and into the formation \n130\n, such as may aid in preventing the contaminants and wellbore fluid from diffusing or otherwise interfering with the laser beam \n290\n.', 'The surface fluid communicated from the fluid source \n140\n via the coiled tubing \n161\n and expelled through the nozzle \n240\n is substantially transparent to the laser beam \n290\n.', 'For example, the surface fluid may comprise nitrogen, water with an appropriate composition and salinity, and/or another fluid that does not deleteriously interfere with the laser beam \n290\n.', 'The fluid composition may depend on the wavelength of the laser beam \n290\n.', 'For example, the spectrum of absorption of water for infrared light may have some wavelength intervals where water is substantially transparent to the laser beam \n290\n.', 'Accordingly, the laser cutting apparatus \n200\n may be operable to emit the laser beam \n290\n having a wavelength that may be transmitted through the water with little or no interference.', 'The laser cutting apparatus \n200\n may further comprise a depth sensor \n230\n operable to monitor the depth of the radial slots \n132\n being formed by the laser beam \n290\n.', 'The depth sensor \n230\n may be operatively connected with the motor \n260\n, such as may permit the motor \n260\n to control the angular position of the depth sensor \n230\n in an intended direction to measure the depth of the radial slots \n132\n.', 'For example, the depth sensor \n230\n may be coupled with or otherwise carried by the body \n255\n.', 'The depth sensor \n230\n and the deflector \n250\n may be angularly aligned, relative to rotation around the axis \n251\n, such that a sensing direction of the depth sensor \n230\n and the direction of the laser beam \n290\n deflected by the deflector \n250\n may be substantially similar (e.g., within about five degrees of each other).', 'Thus, the depth sensor \n230\n may be operable to detect the depth of the radial slot \n132\n in real-time as the radial slot \n132\n is being cut by the laser beam \n290\n.', 'For example, the depth sensor \n230\n may be operable to emit a sensor signal into the radial slot \n132\n along a path that substantially coincides with the path of the laser beam \n290\n.', 'The depth sensor \n230\n may receive the sensor signal that is reflected back by the uncut portion of the formation \n130\n.', 'The depth sensor \n230\n and/or another portion of the tool string \n110\n may be operable to calculate or determine the depth of the radial slot \n132\n based on travel duration of the sensor signal, such as between a first time at which the sensor signal is emitted from the depth sensor \n230\n and a second time at which the depth sensor \n230\n receives the reflected sensor signal.', 'The controller \n220\n may be connected with the electrical conductor \n181\n for transmitting and/or receiving electrical signals communicated between the controller \n220\n and the control and power center \n180\n.', 'The controller \n220\n may be operable to receive, process, and/or record the signals or information generated by and/or received from the control and power center \n180\n, various components of the laser cutting apparatus \n200\n, and/or the first and second portions \n111\n, \n112\n of the tool string \n110\n.', 'For example, the controller \n220\n may be operable to receive and process signals from the CCL and/or orientation sensor(s) described above, such as to acquire the position and/or the orientation of the laser cutting apparatus \n200\n.', 'The controller \n220\n may be further operable to transmit the acquired position and/or orientation information to the control and power center \n180\n via the electrical conductor \n181\n.', 'The controller \n220\n may also be operable to receive, store, and/or execute computer programs or coded instructions, such as may cause the laser cutting apparatus \n200\n and/or other components of the tool string \n110\n to perform at least a portion of a method and/or process described herein.', 'The controller \n220\n may be programmed or otherwise receive the coded instructions at the wellsite \n105\n prior to conveying the laser cutting apparatus \n200\n within the wellbore \n120\n.', 'The controller \n220\n may be programmed with information related to location, geometry, and other parameters related to formation of the radial slots \n132\n, such as the number and orientation of the radial slots \n132\n with respect to the central axis \n150\n of the wellbore \n120\n and/or the direction of gravity.', 'The controller \n220\n may be programmed such that each radial slot \n132\n or set of radial slots \n132\n may comprise a unique (e.g., different) predefined geometry.', 'Based on such information or programming, the controller \n220\n may be operable to control the laser cutting apparatus \n100\n, including extending the anchoring device \n115\n, activating the laser source \n190\n (or indicating a “ready” status therefor), and rotating the motor \n260\n to control the angular position of the deflector \n250\n, the nozzle \n240\n, and/or the depth sensor \n230\n.', 'Therefore, the controller \n220\n and/or the programming may facilitate a substantially automatic radial slot \n132\n formation process, perhaps with no or minimal communication with the control and power center \n180\n while the laser cutting apparatus \n200\n remains at certain depth within the wellbore \n120\n during formation of the radial slot(s) \n132\n at that depth.', 'The radial slots \n132\n created by the laser cutting apparatus \n200\n may comprise a continuous or substantially continuous 360-degree slot that extends through the casing \n122\n and the cement sheath \n124\n and into the formation \n130\n surrounding the wellbore \n120\n, along the plane substantially transverse to the central axis \n150\n, such as the Y-Z plane.', 'The radial slots \n132\n may also comprise a set of discontinuous (i.e., discrete) radial slots that extend through the casing \n122\n and the cement sheath \n124\n and into the formation \n130\n surrounding the wellbore \n120\n, along the plane substantially transverse to the central axis \n150\n, such as the Y-Z plane.', 'Although not extending a full 360-degrees, such discontinuous pattern of radial slots \n132\n may be utilized to initiate or assist in initiating a transverse fracture with respect to the central axis \n150\n.', 'The discontinuous pattern of the radial slots \n132\n may be operable to maintain the mechanical integrity of the casing \n122\n by avoiding a full severing of the casing \n122\n around its circumference, such that the casing \n122\n may be cut less than 360-degrees around its circumference.', 'FIG.', '3\n is a schematic view of a portion of the laser cutting apparatus \n200\n shown in \nFIGS.', '1 and 2\n disposed within the horizontal portion of the wellbore \n120\n prior to initiating cutting operations according to one or more aspects of the present disclosure.', 'As described above and depicted in \nFIG.', '3\n, the laser cutting apparatus \n200\n may be disposed within the wellbore \n120\n such that the axis of rotation \n251\n of the deflector \n250\n substantially coincides with the central axis \n150\n of the wellbore \n120\n.', 'The laser cutting apparatus \n200\n is depicted in \nFIG.', '3\n prior to forming radial slots \n132\n, \n134\n having geometries defined by profiles \n131\n, \n133\n, respectively.', 'The radial slots \n132\n, \n134\n may extend symmetrically on opposing sides of the wellbore \n120\n along the Y-Z plane, extending substantially transverse with respect to the central axis \n150\n of the wellbore \n120\n and substantially vertically or parallel to the direction of gravity.', 'Each radial slot \n132\n, \n134\n may extend through the casing \n122\n, the cement sheath \n124\n, and into the formation \n130\n through a predetermined angle \n156\n, which in the example implementation depicted in \nFIG.', '3\n is about sixty degrees.', 'Each radial slot \n132\n, \n134\n may terminate along opposing first and second sides \n136\n, \n137\n, which are separated by the predetermined angle \n156\n.', 'Each radial slot \n132\n, \n134\n may extend to the predetermined depth \n152\n measured between the central axis \n150\n and a radially outward end \n135\n of each radial slot \n132\n, \n134\n.', 'The predetermined depth \n152\n of each radial slot \n132\n, \n134\n may be about twice the wellbore diameter \n154\n.', 'FIG.', '3\n also shows a plurality of circular profiles \n155\n, each having a diameter that is substantially equal to the wellbore diameter \n154\n, superimposed over each radial slot profile \n131\n, \n133\n to visually demonstrate the geometric relationship between the wellbore diameter \n154\n and the predetermined depth \n152\n of the radial slots \n132\n, \n134\n.', 'The circular profiles \n155\n show that the predetermined depth \n152\n of each radial slot \n132\n, \n134\n is twice the wellbore diameter \n154\n.', 'Although \nFIG.', '3\n depicts two radial slot profiles \n131\n, \n133\n extending through the casing \n122\n, the cement sheath \n124\n, and the formation \n130\n, it is to be understood that other radial slot configurations are also within the scope of the present disclosure.', 'For example, other radial slot configurations may include three, four, five, or more radial slots.', 'Furthermore, although the depicted radial slot profiles \n131\n, \n133\n extend through the predetermined angle \n156\n of about sixty degrees, other values of the predetermined angle \n156\n within the scope of the present disclosure may range between about ten degrees and about 120 degrees.', 'Moreover, it is to be understood that the laser cutting apparatus \n200\n may be operable to form radial slots ranging from a single perforation comprising a width of the laser beam \n290\n to a radial slot extending 360 degrees around the central axis \n150\n.\n \nFIG.', '4\n depicts an example implementation of the formation of the radial slot \n132\n shown in \nFIG.', '3\n in which the laser cutting apparatus \n200\n is forming the radial slot \n132\n according to the geometry defined by the profile \n131\n described above.', 'The laser cutting apparatus \n200\n is forming the radial slot \n132\n by operating the motor \n260\n to sequentially rotate the deflector \n250\n to each one of a plurality of angular positions, relative to rotation around the axis \n251\n, and maintain the deflector \n250\n at each successive one of the plurality of angular positions until the laser beam \n290\n penetrates the formation \n130\n to the predetermined depth \n152\n at that angular position.', 'That is, the motor \n260\n is controlled to maintain the deflector \n250\n at an angular position until the laser beam \n290\n penetrates the formation \n130\n to the predetermined depth \n152\n, then the motor \n260\n is controlled to rotate the deflector \n250\n to the next (adjacent) angular position and maintain the deflector \n250\n at that angular position until the laser beam \n290\n again penetrates the formation \n130\n to the predetermined depth \n152\n, and this process is repeated until the radial slot \n132\n extends through the predetermined angle \n156\n encompassing the plurality of angular positions.', 'For example, the motor \n260\n may maintain the deflector \n250\n at a first angular position until the laser beam \n290\n penetrates the casing \n122\n, the cement sheath \n124\n, and the formation \n130\n to the predetermined depth \n152\n, thus forming a first, angularly-incremental cut or perforation \n138\n.', 'After the angularly-incremental perforation \n138\n is finished, the motor \n260\n may be actuated to change the angular position of the deflector \n250\n by an incremental angle to a second (adjacent) angular position where the motor \n260\n again maintains the deflector \n250\n until the laser beam \n290\n again penetrates the casing \n122\n, the cement sheath \n124\n, and the formation \n130\n to the predetermined depth \n152\n.', 'Such steps may be repeated until the angularly-incremental perforations \n138\n collectively form the radial slot \n132\n through the predetermined angle \n156\n.', 'In \nFIG.', '4\n, arrows \n157\n depict such progression of the angularly-incremental formation of the radial slot \n132\n.', 'Each of the plurality of angular positions may be angularly offset from neighboring angular positions by an angular increment corresponding to a width of the laser beam \n290\n.', 'For example, at each of the plurality of angular positions, the laser beam \n290\n may ultimately reach a location at the radial outward end \n135\n of the radial slot, and the distance between neighboring ones of such locations may be substantially equal to the width of the laser beam \n290\n.', 'FIG.', '4\n also depicts the fluid stream \n142\n discharged by the nozzle \n240\n and circulating within a formed portion of the radial slot \n132\n.', 'As described above, the nozzle \n240\n and the deflector \n250\n may be substantially aligned in a manner permitting the fluid stream \n142\n to impact the portion of the formation \n130\n being cut by the laser beam \n290\n.', 'Such alignment of the nozzle \n240\n and the deflector \n250\n may also permit the fluid stream \n142\n to initially substantially overlap or coincide with the path of the laser beam \n290\n (although such overlap is minimized in the example depicted in \nFIG.', '4\n so that the path of the laser beam \n290\n is visible).', 'During cutting operations, the path of the fluid stream \n142\n initially flowing in a radially outward direction may thus wash away or otherwise move contaminants away from the path of the laser beam \n290\n, such as may prevent or reduce scattering of the laser beam \n290\n.', 'The fluid stream \n142\n then returns along or towards the first side \n136\n of the radial slot \n132\n and/or other previously formed portions of the radial slot \n132\n.\n \nFIG.', '5\n depicts another example implementation of the formation of the radial slot \n132\n shown in \nFIG.', '3\n utilizing the laser cutting apparatus \n200\n.', 'However, instead of forming angularly-incremental cuts or penetrations each extending along the entire predetermined depth \n152\n of the radial slot \n132\n, \nFIG.', '5\n depicts the radial slot \n132\n formed by a plurality of radially-incremental cuts or perforations \n139\n that each extend through the predetermined angle \n156\n.', 'During such cutting operations, the motor \n260\n is controlled to repeatedly rotate the deflector \n250\n through a plurality of cycles, wherein each cycle comprises a first substantially continuous rotation of the deflector \n250\n through the predetermined angle \n156\n in a first rotational direction, indicated in \nFIG.', '5\n by arrow \n151\n, and a second substantially continuous rotation of the deflector \n250\n through the predetermined angle \n156\n in a second rotational direction, indicated in \nFIG.', '5\n by arrow \n153\n.', 'Thus, each successive performance of a cycle (or half-cycle) extends the entire radial slot \n132\n, throughout the predetermined angle \n156\n, closer to the predetermined depth \n152\n.', 'During each pass (e.g., half of each cycle), the laser beam \n290\n forms the radially-incremental cut or perforation \n139\n extending an incremental distance in the radial direction and along the entire predetermined angle \n156\n of the radial slot \n132\n.', 'With each subsequent pass, the depth of the radial slot \n132\n increases, until the radial slot \n132\n reaches the predetermined depth \n152\n.', 'The direction of progression of the radial slot \n132\n thus formed is indicated in \nFIG.', '5\n by arrows \n158\n.', 'FIG.', '5\n further shows the fluid stream \n142\n discharged by the nozzle \n240\n and circulating within the previously formed portion of the radial slot \n132\n.', 'As described above, the nozzle \n240\n and the deflector \n250\n may be substantially aligned in a manner permitting the fluid stream \n142\n to impact the portion of the formation \n130\n being cut by the laser beam \n290\n.', 'Such alignment may permit the fluid stream \n142\n to initially substantially overlap or coincide with the path of the laser beam \n290\n.', 'Thus, the initial path of the fluid stream \n142\n may wash away or otherwise move contaminants away from the path of the laser beam \n290\n, such as may prevent or reduce scattering of the laser beam \n290\n during the cutting operations.', 'The fluid stream \n142\n may then return along a previously formed portion of the radial slot \n132\n away from the laser beam \n290\n, such as along and/or towards the first side \n136\n of the radial slot \n132\n when the deflector \n250\n is rotating in direction \n153\n and along and/or towards the second side \n137\n of the radial slot when the deflector \n250\n is rotating in direction \n151\n.', 'A passage for the fluid stream \n142\n to enter and exit the radial slot \n132\n may be wider and/or exist earlier in operations when forming the radially-incremental perforations \n139\n along the entire predetermined angle \n156\n, relative to the formation of such passage when forming the angularly-incremental perforations \n138\n described above with respect to \nFIG.', '4\n.', 'Such wider and/or earlier-formed passage may permit greater separation between inward- and outward-flowing portions of the fluid stream \n142\n, which may aid in cleaning contaminants away from the path of the laser beam \n290\n.\n \nFIG.', '6\n is another schematic view of \nFIG.', '5\n demonstrating that a penetration depth \n159\n may be monitored as the radial slot \n132\n progresses in the radially outward direction toward the predetermined depth \n152\n.', 'The penetration depth \n159\n may be monitored in real-time by the depth sensor \n230\n while the radial slot \n132\n is being formed.', 'For example, the depth sensor \n230\n may comprise a signal emitter \n232\n operable to emit a signal \n235\n directed toward the outward end \n135\n of the radial slot \n132\n, as indicated by arrow \n236\n.', 'The depth sensor \n230\n may further comprise a signal receiver \n234\n operable to receive a returning signal \n237\n after the emitted signal \n235\n is reflected back by the uncut formation at the outward end of the radial slot \n132\n, as indicated by arrow \n238\n.', 'The depth sensor \n230\n may be operable to calculate or determine the penetration depth \n159\n of the radial slot based on a duration of travel of the signal \n235\n, \n237\n between the emitter \n232\n and the receiver \n234\n.', 'However, the controller \n220\n may also or instead be utilized to determine the penetration depth \n159\n of the radial slot \n132\n.', 'For example, the depth sensor \n230\n may be in communication with the controller \n220\n, such as to initiate emission of the signal \n235\n by the controller \n220\n and to receive the information generated by the depth sensor \n230\n.', 'Once the signal \n235\n, \n237\n is transmitted and received, the controller \n220\n may be operable to determine the penetration depth \n159\n of the radial slot \n132\n based on the received signal \n237\n or based on the duration of travel of the signal \n235\n, \n237\n from the emitter \n232\n to the receiver \n234\n.', 'The penetration depth \n159\n into the formation \n130\n may be measured at least once during each cycle of the deflector \n250\n.', 'The depth sensor \n230\n may be an acoustic sensor operable to emit an acoustic signal into the radial slot \n132\n and detect reflection of the acoustic signal from the outward end \n135\n of the radial slot \n132\n.', 'The depth sensor \n230\n may also be an electromagnetic sensor operable to emit an electromagnetic signal into the radial slot \n132\n and detect reflection of the electromagnetic signal from the outward end \n135\n of the radial slot \n132\n.', 'The depth sensor \n230\n may also be a light sensor operable to emit a light signal into the radial slot \n132\n and detect reflection of the light signal from the outward end \n135\n of the radial slot \n132\n.', 'As described above, although not as illustrated in \nFIG.', '6\n, the depth sensor \n230\n and the deflector \n250\n may be substantially aligned in a manner permitting the emitted signal \n235\n and/or a detection direction of the depth sensor \n230\n to substantially coincide with the laser beam \n290\n.', 'As also described above, the depth sensor \n230\n and the deflector \n250\n may be operatively coupled with the motor \n260\n, such that the deflector \n250\n and the depth sensor \n230\n may rotate together.', 'However, as shown in \nFIG.', '6\n, the laser beam \n290\n and depth sensor \n230\n (and, thus, the direction of the sensor signals \n235\n, \n237\n) may instead be angularly offset to permit the depth sensor \n230\n to measure the depth of the radial slot \n132\n at a location that is angularly offset from the laser beam \n290\n, such as to reduce interference caused by the laser beam \n290\n and/or contaminants generated by the laser beam \n290\n.', 'The depth sensor \n230\n may also be a light sensor operable to detect reflection of a portion of the laser beam \n290\n reflected from the outward end \n135\n of the radial slot \n132\n.', 'For example, the laser beam \n290\n may be periodically interrupted and pulsed at predetermined times during the laser cutting operations while the depth sensor \n230\n detects at least a portion of the laser beam \n290\n reflected back by the outward end \n135\n of the radial slot \n132\n being formed.', 'The depth sensor \n230\n and/or the controller \n220\n may then perform the duration of travel calculations to determine the penetration depth \n159\n.', 'After the penetration depth \n159\n is known, the controller \n220\n may be operable to cause the motor \n260\n to rotate the deflector \n250\n based on the determined penetration depth \n159\n.', 'For example, the controller \n220\n may be operable to slow down the motor \n260\n to decrease angular velocity of the deflector \n250\n and, thus, decrease the angular velocity of the laser beam \n290\n.', 'Such decrease may be based on the determined penetration depth \n159\n to, for example, deliver a substantially constant amount of laser energy per unit length of the formation \n130\n being cut.', 'For example, as the penetration depth \n159\n and length of the outward end \n135\n of the radial slot \n132\n increase, the rotational rate of the defector \n250\n laser beam cycle rate may be proportionally or otherwise decreased to permit the laser beam \n290\n to maintain the substantially constant amount of laser energy delivered by the laser beam \n290\n per unit length of the outward end \n135\n of the radial slot \n132\n being formed.\n \nFIG.', '6\n shows the depth sensor \n230\n being utilized while the laser cutting apparatus \n200\n forms the radial slot \n132\n by forming the plurality of radially-incremental perforations \n139\n extending along the entire predetermined angle \n156\n, as described above with respect to \nFIG.', '5\n.', 'However, the depth sensor \n230\n may also be utilized to measure the penetration depth \n159\n while the radial slots \n132\n are formed by forming the plurality of angularly-incremental perforations \n138\n each extending to the predetermined depth \n152\n, as described above with respect to \nFIG.', '4\n.', 'For example, as the motor \n260\n directs the deflector \n250\n to a predetermined angular position to form an angularly-incremental perforation \n138\n, the motor \n260\n may simultaneously direct the depth sensor \n230\n to the predetermined angular position to monitor in real-time the penetration depth \n159\n of the angularly-incremental perforation \n138\n as it is being formed.', 'After the controller \n220\n determines that the penetration depth \n159\n is substantially equal to the predetermined depth \n152\n, via utilization of information received from the depth sensor \n230\n, the controller \n220\n may cause the motor \n260\n to change the angular position of the laser beam \n290\n by the incremental angle to form the next angularly-incremental perforation \n138\n.', 'Such steps may be repeated until the radial slot \n132\n extends through the predetermined angle \n156\n.', 'Because each angularly-incremental perforation \n138\n is narrow (e.g., generally the width of the laser beam \n290\n), the depth sensor \n230\n and the deflector \n250\n may be aligned such that the sensor signal \n235\n and the laser beam \n290\n substantially align or coincide.', 'FIG.', '7\n is a schematic view of at least a portion of an example implementation of an apparatus \n500\n according to one or more aspects of the present disclosure.', 'The apparatus \n500\n may be or form a portion of the control and power center \n180\n shown in \nFIG.', '1\n and/or the controller \n220\n shown in \nFIG.', '2\n, and may thus be operable to form at least a portion of a method and/or process according to one or more aspects described above, including for and/or during the formation of radial slots \n132\n, \n134\n in a formation \n130\n.', 'The apparatus \n500\n is or comprises a processing system \n501\n that may execute example machine-readable instructions to implement at least a portion of one or more of the methods and/or processes described herein.', 'The processing system \n500\n may be or comprise, for example, one or more processors, controllers, special-purpose computing devices, servers, personal computers, personal digital assistant (PDA) devices, smartphones, smart glasses, tablets, internet appliances, and/or other types of computing devices.', 'The processing system \n501\n may comprise a processor \n512\n such as, for example, a general-purpose programmable processor.', 'The processor \n512\n may comprise a local memory \n514\n, and may execute coded instructions \n532\n present in the local memory \n514\n and/or another memory device.', 'The processor \n512\n may execute, among other things, machine-readable instructions or programs to implement the methods and/or processes described herein.', 'The programs stored in the local memory \n514\n may include program instructions or computer program code that, when executed by an associated processor, control formation of radial slots \n132\n, \n134\n in a formation \n130\n.', 'The processor \n512\n may be, comprise, or be implemented by one or a plurality of processors of various types suitable to the local application environment, and may include one or more of general- or special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples.', 'Other processors from other families are also appropriate.', 'The processor \n512\n may be in communication with a main memory, such as may include a volatile memory \n518\n and a non-volatile memory \n520\n, perhaps via a bus \n522\n and/or other communication means.', 'The volatile memory \n518\n may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM) and/or other types of random access memory devices.', 'The non-volatile memory \n520\n may be, comprise, or be implemented by read-only memory, flash memory and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n518\n and/or the non-volatile memory \n520\n.', 'The processing system \n501\n may also comprise an interface circuit \n524\n.', 'The interface circuit \n524\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a satellite interface, a global positioning system (GPS) and/or a cellular interface or receiver, among others.', 'The interface circuit \n524\n may also comprise a graphics driver card.', 'The interface circuit \n524\n may also comprise a device such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.).', 'One or more input devices \n526\n may be connected to the interface circuit \n524\n.', 'The input device(s) \n526\n may permit a user to enter data and commands into the processor \n512\n.', 'The input device(s) \n526\n may be, comprise, or be implemented by, for example, a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among others.', 'One or more output devices \n528\n may also be connected to the interface circuit \n524\n.', 'The output devices \n528\n may be, comprise, or be implemented by, for example, display devices (e.g., a light-emitting diode (LED) display, a liquid crystal display (LCD, or a cathode ray tube (CRT) display, among others), printers, and/or speakers, among others.', 'The processing system \n501\n may also comprise one or more mass storage devices \n530\n for storing machine-readable instructions and data.', 'Examples of such mass storage devices \n530\n include floppy disk drives, hard drive disks, compact disk (CD) drives, and digital versatile disk (DVD) drives, among others.', 'The coded instructions \n532\n may be stored in the mass storage device \n530\n, the volatile memory \n518\n, the non-volatile memory \n520\n, the local memory \n514\n, and/or on a removable storage medium \n534\n, such as a CD or DVD.', 'Thus, the modules and/or other components of the processing system \n501\n may be implemented in accordance with hardware (embodied in one or more chips including an integrated circuit such as an ASIC), or may be implemented as software or firmware for execution by a processor.', 'In particular, in the case of firmware or software, the embodiment can be provided as a computer program product including a computer readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor.', 'In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art should readily recognize that the present disclosure introduces an apparatus comprising: a laser cutting apparatus conveyable within a casing lining at least a portion of a wellbore that extends into a subterranean formation, wherein the laser cutting apparatus comprises: a housing; a deflector operable for rotation relative to the housing to direct a laser beam to form a radial slot extending through the casing and into the subterranean formation; a motor operable to rotate the deflector; a sensor operable to generate information related to depth of the radial slot in real-time as the radial slot is formed by the laser beam; and a processing device operable to receive the information generated by the sensor and cause the motor to rotate the deflector based on the received information.', 'The laser cutting apparatus may further comprise a body connected to and rotatable by operation of the motor, and the deflector and the sensor may each be connected to and rotate with the body.', 'The sensor may be a light sensor operable to detect reflection of a portion of the laser beam from an end of the radial slot.', 'The processing device may be further operable to determine the depth of the radial slot in real-time based on time of travel of the laser beam from the deflector to the light sensor.', 'The sensor may be an acoustic sensor operable to emit an acoustic signal into the radial slot and detect reflection of the acoustic signal from an end of the radial slot.', 'The sensor may be an electromagnetic sensor operable to emit an electromagnetic signal into the radial slot and detect reflection of the electromagnetic signal from an end of the radial slot.', 'The sensor may comprise a signal emitter and a signal receiver.', 'The signal emitter may be operable to emit a signal into the radial slot, and the signal receiver may be operable to receive the signal reflected by an end of the radial slot.', 'The processing device may be further operable to determine the depth of the radial slot in real-time based on a duration of travel of the signal between the emitter and the receiver.', 'The deflector may be in optical communication with a laser source located at a wellsite surface from which the wellbore extends.', 'The wellbore extends from a wellsite surface, and the laser cutting apparatus may be conveyable within the casing via coiled tubing operable to communicate a fluid from the wellsite surface to the laser cutting apparatus.', 'The fluid may be substantially transparent to the laser beam.', 'The deflector may be operable to direct the laser beam along a first radial path, and the laser cutting apparatus may further comprise a nozzle operable to discharge the fluid along a second radial path that at least partially overlaps the first radial path.', 'At least a portion of the second radial path may substantially coincide with the first radial path.', 'The laser cutting apparatus may further comprise a body connected to and rotatable by operation of the motor, and the deflector and the nozzle may each be connected to and rotate with the body.', 'A depth of the radial slot may be at least twice the diameter of the wellbore, measured from a central axis of the wellbore.', 'The radial slot may extend along a plane substantially perpendicular to a central axis of the wellbore.', 'The plane may be substantially parallel to the direction of gravity.', 'The apparatus may further comprise: a laser source located at a wellsite surface from which the wellbore extends; and an optical conductor conducting the laser beam from the laser source to the deflector.', 'The present disclosure also introduces a method comprising: conveying a laser cutting apparatus within a casing lining at least a portion of a wellbore that extends into a subterranean formation; transmitting a laser beam to a deflector of the laser cutting apparatus; and operating a motor of the laser cutting apparatus to control rotation of the deflector, thus directing the laser beam deflected by the deflector to form a radial slot extending through the casing to a predetermined depth within the subterranean formation, including operating the motor to sequentially rotate the deflector to each one of a plurality of angular positions and maintain the deflector at each successive one of the plurality of angular positions until the laser beam penetrates the subterranean formation to a predetermined depth at that angular position, such that the radial slot extends through a predetermined angle encompassing the plurality of angular positions.', 'Each of the plurality of angular positions may correspond to a width of the laser beam.', 'Conveying the laser cutting apparatus within the casing may be via coiled tubing.', 'Transmitting the laser beam to the deflector may comprise transmitting the laser beam from a laser source located at a wellsite surface from which the wellbore extends.', 'The predetermined depth may be at least twice a diameter of the wellbore, measured from a central axis of the wellbore.', 'The wellbore extends from a wellsite surface.', 'Conveying the laser cutting apparatus within the casing may be via coiled tubing, and the method may further comprise communicating a fluid from the wellsite surface to the laser cutting apparatus via the coiled tubing.', 'The fluid may be substantially transparent to the laser beam.', 'The deflector may be operable to direct the laser beam along a first radial path at each of the plurality of angular positions.', 'The method may further comprise discharging the fluid from a nozzle of the laser cutting apparatus along a second radial path at each of the plurality of angular positions.', 'The second radial path may at least partially overlap the first radial path.', 'The method may further comprise measuring a penetration depth of the laser beam into the subterranean formation in real-time at each of plurality of angular positions.', 'Measuring the penetration depth may comprise: emitting a signal into the radial slot; receiving the signal reflected by an end of the radial slot; and determining depth of the radial slot based on a duration of travel of the signal.', 'Measuring the penetration depth may utilize a light sensor, an acoustic sensor, and/or an electromagnetic sensor.', 'The present disclosure also introduces a method comprising: conveying a laser cutting apparatus within a casing lining at least a portion of a wellbore that extends into a subterranean formation; transmitting a laser beam to a deflector of the laser cutting apparatus; and operating a motor of the laser cutting apparatus to repeatedly rotate the deflector through a plurality of cycles, wherein each of the plurality of cycles comprises a first substantially continuous rotation of the deflector through a predetermined angle in a first rotational direction and a second substantially continuous rotation of the deflector through the predetermined angle in a second rotational direction, thus directing the laser beam deflected by the deflector to form a radial slot extending radially through the casing and, with each successive one of the plurality of cycles, extend the radial slot to a predetermined depth within the subterranean formation, such that opposing first and second sides of the radial slot are angularly disposed at the predetermined angle.', 'Operating the motor may further comprise decreasing angular velocity of the first and second substantially continuous rotations of the deflector during one or more of the plurality of cycles.', 'The angular velocity of the first and second substantially continuous rotations of the deflector may be decreased during one or more of the plurality of cycles by an amount permitting the laser beam to deliver a substantially constant amount of energy per unit length of the subterranean formation being cut at a penetration depth of the laser beam in that one of the plurality of cycles.', 'Conveying the laser cutting apparatus within the casing may be via coiled tubing.', 'Transmitting the laser beam to the deflector may comprise transmitting the laser beam from a laser source located at a wellsite surface from which the wellbore extends.', 'The predetermined depth may be at least twice a diameter of the wellbore, measured from a central axis of the wellbore.', 'The wellbore extends from a wellsite surface.', 'Conveying the laser cutting apparatus within the casing may be via coiled tubing, and the method may further comprise communicating a fluid from the wellsite surface to the laser cutting apparatus via the coiled tubing.', 'The fluid may be substantially transparent to the laser beam.', 'The deflector may be operable to direct the laser beam along a first radial path as the deflector is moved through the first and second substantially continuous rotations, and the method may further comprise discharging the fluid from a nozzle of the laser cutting apparatus along a second radial path as the deflector is moved through the first and second substantially continuous rotations.', 'The second radial path may at least partially overlap the first radial path at each point of the first and second substantially continuous rotations of the deflector.', 'The method may further comprise measuring a penetration depth of the laser beam into the subterranean formation at least once during each of the plurality of cycles.', 'Measuring the penetration depth may comprise: emitting a signal into the radial slot; receiving the signal reflected by an end of the radial slot; and determining depth of the radial slot based on a duration of travel of the signal.', 'Measuring the penetration depth may utilize a light sensor, an acoustic sensor, and/or an electromagnetic sensor.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'An apparatus, comprising:\na laser cutting apparatus conveyable within a casing lining at least a portion of a wellbore that extends into a subterranean formation, wherein the laser cutting apparatus comprises: a housing; a deflector operable for rotation relative to the housing to direct a laser beam to form a radial slot extending through the casing and into the subterranean formation; a motor operable to rotate the deflector; a sensor operable to generate information related to a penetration depth of the radial slot into the subterranean formation in real-time as the radial slot is formed by the laser beam; a body connected to and rotatable by operation of the motor, and wherein the deflector and the sensor are each connected to and rotate with the body; and a processing device operable to receive the information generated by the sensor and cause the motor to rotate the deflector based on the received information.', '2.', 'The apparatus of claim 1 wherein the sensor is a light sensor operable to detect reflection of a portion of the laser beam from an end of the radial slot, and wherein the processing device is further operable to determine the penetration depth of the radial slot in real-time based on time of travel of the laser beam from the deflector to the light sensor.', '3.', 'The apparatus of claim 1 wherein the sensor is an acoustic sensor operable to emit an acoustic signal into the radial slot and detect reflection of the acoustic signal from an end of the radial slot.', '4.', 'The apparatus of claim 1 wherein the sensor is an electromagnetic sensor operable to emit an electromagnetic signal into the radial slot and detect reflection of the electromagnetic signal from an end of the radial slot.', '5.', 'The apparatus of claim 1 wherein the sensor comprises a signal emitter and a signal receiver, wherein the signal emitter is operable to emit a signal into the radial slot, wherein the signal receiver is operable to receive the signal reflected by an end of the radial slot, and wherein the processing device is further operable to determine the penetration depth of the radial slot in real-time based on a duration of travel of the signal between the signal emitter and the signal receiver.', '6.', 'The apparatus of claim 1 wherein:\nthe wellbore extends from a wellsite surface;\nthe laser cutting apparatus is conveyable within the casing via coiled tubing operable to communicate a fluid from the wellsite surface to the laser cutting apparatus;\nthe fluid is substantially transparent to the laser beam;\nthe deflector is operable to direct the laser beam along a first radial path; and\nthe laser cutting apparatus further comprises a nozzle operable to discharge the fluid along a second radial path that at least partially overlaps the first radial path.', '7.', 'A method, comprising:\nconveying a laser cutting apparatus within a casing lining at least a portion of a wellbore that extends into a subterranean formation;\ntransmitting a laser beam to a deflector of the laser cutting apparatus; and\noperating a motor of the laser cutting apparatus to control rotation of a body connected to the deflector and at least one sensor of the laser cutting apparatus, thus directing the laser beam deflected by the deflector to form a radial slot extending through the casing to a predetermined depth within the subterranean formation, including operating the motor to sequentially rotate the deflector to each one of a plurality of angular positions and to maintain the deflector at each successive one of the plurality of angular positions until the laser beam penetrates the subterranean formation to the predetermined depth at the respective angular position based on a penetration depth measured by the at least one sensor, such that the radial slot extends through a predetermined angle encompassing the plurality of angular positions.', '8.', 'The method of claim 7 wherein each of the plurality of angular positions corresponds to a width of the laser beam.', '9.', 'The method of claim 7 wherein:\nthe wellbore extends from a wellsite surface;\nconveying the laser cutting apparatus within the casing is via coiled tubing;\nthe method further comprises communicating a fluid from the wellsite surface to the laser cutting apparatus via the coiled tubing;\nthe fluid is substantially transparent to the laser beam;\nthe deflector is operable to direct the laser beam along a first radial path at each of the plurality of angular positions;\nthe method further comprises discharging the fluid from a nozzle of the laser cutting apparatus along a second radial path at each of the plurality of angular positions; and\nthe second radial path at least partially overlaps the first radial path.', '10.', 'The method of claim 7 further comprising measuring the penetration depth of the laser beam into the subterranean formation in real-time at each of the plurality of angular positions using the at least one sensor of the laser cutting apparatus.', '11.', 'The method of claim 10 wherein measuring the penetration depth comprises:\nemitting a signal into the radial slot;\nreceiving the signal reflected by an end of the radial slot; and\ndetermining depth of the radial slot based on a duration of travel of the signal.', '12.', 'The method of claim 10 wherein the at least one sensor comprises at least one of a light sensor, an acoustic sensor, and an electromagnetic sensor.\n\n\n\n\n\n\n13.', 'A method, comprising:\nconveying a laser cutting apparatus within a casing lining at least a portion of a wellbore that extends into a subterranean formation;\ntransmitting a laser beam to a deflector of the laser cutting apparatus; and\noperating a motor of the laser cutting apparatus to repeatedly rotate a body connected to the deflector and at least one sensor of the laser cutting apparatus through a plurality of cycles, wherein each of the plurality of cycles comprises a first substantially continuous rotation of the deflector through a predetermined angle in a first rotational direction and a second substantially continuous rotation of the deflector through the predetermined angle in a second rotational direction, thus directing the laser beam deflected by the deflector to form a radial slot extending radially through the casing and, with each successive one of the plurality of cycles, extend the radial slot to a predetermined depth within the subterranean formation based on a penetration depth measured by the at least one sensor, such that opposing first and second sides of the radial slot are angularly disposed at the predetermined angle.\n\n\n\n\n\n\n14.', 'The method of claim 13 wherein operating the motor further comprises decreasing angular velocity of the first and second substantially continuous rotations of the deflector during one or more of the plurality of cycles.', '15.', 'The method of claim 14 wherein the angular velocity of the first and second substantially continuous rotations of the deflector is decreased during one or more of the plurality of cycles by an amount to deliver a substantially constant amount of energy per unit length of the subterranean formation being cut at the penetration depth of the laser beam in that one of the plurality of cycles.', '16.', 'The method of claim 13 wherein:\nthe wellbore extends from a wellsite surface;\nconveying the laser cutting apparatus within the casing is via coiled tubing;\nthe method further comprises communicating a fluid from the wellsite surface to the laser cutting apparatus via the coiled tubing;\nthe fluid is substantially transparent to the laser beam;\nthe deflector is operable to direct the laser beam along a first radial path as the deflector is moved through the first and second substantially continuous rotations;\nthe method further comprises discharging the fluid from a nozzle of the laser cutting apparatus along a second radial path as the deflector is moved through the first and second substantially continuous rotations; and\nthe second radial path at least partially overlaps the first radial path at each point of the first and second substantially continuous rotations of the deflector.', '17.', 'The method of claim 13 further comprising measuring the penetration depth of the laser beam into the subterranean formation at least once during each of the plurality of cycles using the at least one sensor of the laser cutting apparatus.', '18.', 'The method of claim 17 wherein measuring the penetration depth comprises:\nemitting a signal into the radial slot;\nreceiving the signal reflected by an end of the radial slot; and\ndetermining depth of the radial slot based on a duration of travel of the signal.', '19.', 'The method of claim 17 wherein the at least one sensor comprises at least one of a light sensor, an acoustic sensor, and an electromagnetic sensor.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a sectional view of an example implementation of a portion of the apparatus shown in FIG.', '1 according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of an example implementation of a portion of the apparatus shown in FIG.', '1 according to one or more aspects of the present disclosure.', '; FIG.', '4 is a schematic view of the apparatus shown in FIG.', '3 during operation according to one or more aspects of the present disclosure.', '; FIG.', '5 is a schematic view of the apparatus shown in FIG.', '3 during operation according to one or more aspects of the present disclosure.', '; FIG.', '6 is a schematic view of the apparatus shown in FIG.', '3 during operation according to one or more aspects of the present disclosure.', '; FIG. 7 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.; FIG. 1 is a schematic view of at least a portion of an example implementation of a wellsite system 100 according to one or more aspects of the present disclosure.', 'The wellsite system 100 is operable at a wellsite 105 adjacent a wellbore 120 extending from the wellsite 105 into one or more subterranean formations 130.', 'In the context of the present disclosure, the term “subterranean formation” (or simply “formation”) may be given its broadest possible meaning and may include, without limitation, various rocks and other natural materials, as well as cement and other artificial materials, including rock layer formations, such as, granite, basalt, sandstone, dolomite, sand, salt, limestone, rhyolite, quartzite, and shale, among others.', 'The wellbore 120 comprises a central axis 150 and a wellbore diameter 154.', 'When utilized in cased-hole implementations, a cement sheath 124 may secure a casing 122 within the wellbore 120.; FIG.', '1 further depicts coordinates axes X, Y, and Z, which may be utilized as references to aid in identifying relative positions of certain aspects of the tool string 110 or components thereof within three-dimensional space.', 'The X-axis extends in a downhole direction along the central axis 150 of the wellbore 120, and may substantially coincide with the central axis 215 of the laser cutting apparatus 200 during operation of the laser cutting apparatus 200.', 'The Y-axis extends vertically with respect to the Earth and perpendicularly with respect to the X-axis, and the Z-axis extends perpendicularly with respect to the X- and Y-axes.; FIG.', '2 is a sectional view of at least a portion of an example implementation of the tool string 110 shown in FIG.', '1 according to one or more aspects of the present disclosure.', 'The following description refers to FIGS.', '1 and 2, collectively.;', 'FIG. 3 is a schematic view of a portion of the laser cutting apparatus 200 shown in FIGS.', '1 and 2 disposed within the horizontal portion of the wellbore 120 prior to initiating cutting operations according to one or more aspects of the present disclosure.', 'As described above and depicted in FIG.', '3, the laser cutting apparatus 200 may be disposed within the wellbore 120 such that the axis of rotation 251 of the deflector 250 substantially coincides with the central axis 150 of the wellbore 120.', 'The laser cutting apparatus 200 is depicted in FIG.', '3', 'prior to forming radial slots 132, 134 having geometries defined by profiles 131, 133, respectively.', 'The radial slots 132, 134 may extend symmetrically on opposing sides of the wellbore 120 along the Y-Z plane, extending substantially transverse with respect to the central axis 150 of the wellbore 120 and substantially vertically or parallel to the direction of gravity.', 'Each radial slot 132, 134 may extend through the casing 122, the cement sheath 124, and into the formation 130 through a predetermined angle 156, which in the example implementation depicted in FIG.', '3 is about sixty degrees.', 'Each radial slot 132, 134 may terminate along opposing first and second sides 136, 137, which are separated by the predetermined angle 156.', 'Each radial slot 132, 134 may extend to the predetermined depth 152 measured between the central axis 150 and a radially outward end 135 of each radial slot 132, 134.', 'The predetermined depth 152 of each radial slot 132, 134 may be about twice the wellbore diameter 154.', 'FIG.', '3 also shows a plurality of circular profiles 155, each having a diameter that is substantially equal to the wellbore diameter 154, superimposed over each radial slot profile 131, 133 to visually demonstrate the geometric relationship between the wellbore diameter 154 and the predetermined depth 152 of the radial slots 132, 134.', 'The circular profiles 155 show that the predetermined depth 152 of each radial slot 132, 134 is twice the wellbore diameter 154.; FIG.', '4 depicts an example implementation of the formation of the radial slot 132 shown in FIG.', '3 in which the laser cutting apparatus 200 is forming the radial slot 132 according to the geometry defined by the profile 131 described above.', 'The laser cutting apparatus 200 is forming the radial slot 132 by operating the motor 260 to sequentially rotate the deflector 250 to each one of a plurality of angular positions, relative to rotation around the axis 251, and maintain the deflector 250 at each successive one of the plurality of angular positions until the laser beam 290 penetrates the formation 130 to the predetermined depth 152 at that angular position.', 'That is, the motor 260 is controlled to maintain the deflector 250 at an angular position until the laser beam 290 penetrates the formation 130 to the predetermined depth 152, then the motor 260 is controlled to rotate the deflector 250 to the next (adjacent) angular position and maintain the deflector 250 at that angular position until the laser beam 290 again penetrates the formation 130 to the predetermined depth 152, and this process is repeated until the radial slot 132 extends through the predetermined angle 156 encompassing the plurality of angular positions.; FIG. 4 also depicts the fluid stream 142 discharged by the nozzle 240 and circulating within a formed portion of the radial slot 132.', 'As described above, the nozzle 240 and the deflector 250 may be substantially aligned in a manner permitting the fluid stream 142 to impact the portion of the formation 130 being cut by the laser beam 290.', 'Such alignment of the nozzle 240 and the deflector 250 may also permit the fluid stream 142 to initially substantially overlap or coincide with the path of the laser beam 290 (although such overlap is minimized in the example depicted in FIG.', '4 so that the path of the laser beam 290 is visible).', 'During cutting operations, the path of the fluid stream 142 initially flowing in a radially outward direction may thus wash away or otherwise move contaminants away from the path of the laser beam 290, such as may prevent or reduce scattering of the laser beam 290.', 'The fluid stream 142 then returns along or towards the first side 136 of the radial slot 132 and/or other previously formed portions of the radial slot 132.; FIG.', '5 depicts another example implementation of the formation of the radial slot 132 shown in FIG.', '3 utilizing the laser cutting apparatus 200.', 'However, instead of forming angularly-incremental cuts or penetrations each extending along the entire predetermined depth 152 of the radial slot 132, FIG.', '5 depicts the radial slot 132 formed by a plurality of radially-incremental cuts or perforations 139 that each extend through the predetermined angle 156.', 'During such cutting operations, the motor 260 is controlled to repeatedly rotate the deflector 250 through a plurality of cycles, wherein each cycle comprises a first substantially continuous rotation of the deflector 250 through the predetermined angle 156 in a first rotational direction, indicated in FIG.', '5 by arrow 151, and a second substantially continuous rotation of the deflector 250 through the predetermined angle 156 in a second rotational direction, indicated in FIG.', '5 by arrow 153.', 'Thus, each successive performance of a cycle (or half-cycle) extends the entire radial slot 132, throughout the predetermined angle 156, closer to the predetermined depth 152.; FIG.', '5 further shows the fluid stream 142 discharged by the nozzle 240 and circulating within the previously formed portion of the radial slot 132.', 'As described above, the nozzle 240 and the deflector 250 may be substantially aligned in a manner permitting the fluid stream 142 to impact the portion of the formation 130 being cut by the laser beam 290.', 'Such alignment may permit the fluid stream 142 to initially substantially overlap or coincide with the path of the laser beam 290.', 'Thus, the initial path of the fluid stream 142 may wash away or otherwise move contaminants away from the path of the laser beam 290, such as may prevent or reduce scattering of the laser beam 290 during the cutting operations.', 'The fluid stream 142 may then return along a previously formed portion of the radial slot 132 away from the laser beam 290, such as along and/or towards the first side 136 of the radial slot 132 when the deflector 250 is rotating in direction 153 and along and/or towards the second side 137 of the radial slot when the deflector 250 is rotating in direction 151.; FIG.', '6 is another schematic view of FIG.', '5 demonstrating that a penetration depth 159 may be monitored as the radial slot 132 progresses in the radially outward direction toward the predetermined depth 152.', 'The penetration depth 159 may be monitored in real-time by the depth sensor 230 while the radial slot 132 is being formed.', 'For example, the depth sensor 230 may comprise a signal emitter 232 operable to emit a signal 235 directed toward the outward end 135 of the radial slot 132, as indicated by arrow 236.', 'The depth sensor 230 may further comprise a signal receiver 234 operable to receive a returning signal 237 after the emitted signal 235 is reflected back by the uncut formation at the outward end of the radial slot 132, as indicated by arrow 238.', 'The depth sensor 230 may be operable to calculate or determine the penetration depth 159 of the radial slot based on a duration of travel of the signal 235, 237 between the emitter 232 and the receiver 234.', 'However, the controller 220 may also or instead be utilized to determine the penetration depth 159 of the radial slot 132.', 'For example, the depth sensor 230 may be in communication with the controller 220, such as to initiate emission of the signal 235 by the controller 220 and to receive the information generated by the depth sensor 230.', 'Once the signal 235, 237 is transmitted and received, the controller 220 may be operable to determine the penetration depth 159 of the radial slot 132 based on the received signal 237 or based on the duration of travel of the signal 235, 237 from the emitter 232 to the receiver 234.', 'The penetration depth 159 into the formation 130 may be measured at least once during each cycle of the deflector 250.; FIG.', '6 shows the depth sensor 230 being utilized while the laser cutting apparatus 200 forms the radial slot 132 by forming the plurality of radially-incremental perforations 139 extending along the entire predetermined angle 156, as described above with respect to FIG.', '5.', 'However, the depth sensor 230 may also be utilized to measure the penetration depth 159 while the radial slots 132 are formed by forming the plurality of angularly-incremental perforations 138 each extending to the predetermined depth 152, as described above with respect to FIG.', '4.', 'For example, as the motor 260 directs the deflector 250 to a predetermined angular position to form an angularly-incremental perforation 138, the motor 260 may simultaneously direct the depth sensor 230 to the predetermined angular position to monitor in real-time the penetration depth 159 of the angularly-incremental perforation 138 as it is being formed.', 'After the controller 220 determines that the penetration depth 159 is substantially equal to the predetermined depth 152, via utilization of information received from the depth sensor 230, the controller 220 may cause the motor 260 to change the angular position of the laser beam 290 by the incremental angle to form the next angularly-incremental perforation 138.', 'Such steps may be repeated until the radial slot 132 extends through the predetermined angle 156.', 'Because each angularly-incremental perforation 138 is narrow (e.g., generally the width of the laser beam 290), the depth sensor 230 and the deflector 250 may be aligned such that the sensor signal 235 and the laser beam 290 substantially align or coincide.', '; FIG. 7 is a schematic view of at least a portion of an example implementation of an apparatus 500 according to one or more aspects of the present disclosure.', 'The apparatus 500 may be or form a portion of the control and power center 180 shown in FIG.', '1', 'and/or the controller 220 shown in FIG. 2, and may thus be operable to form at least a portion of a method and/or process according to one or more aspects described above, including for and/or during the formation of radial slots 132, 134 in a formation 130.'] |
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US11073633 | NMR ASIC | Aug 27, 2015 | Yi-Qiao Song, Soumyajit Mandal, Yiqiao Tang, David McCowan | Schlumberger Technology Corporation | Anders, J. et al., “An integrated CMOS Receiver Chip for NMR-Applications”, Custom Integrated Circuits Conference, 2009, pp. 471-474.; Hassibi, A. et al., “A Spectral-Scanning Nuclear Magnetic Resonance Imaging (MRI) Transceiver”, IEEE Journal of Solid-State Circuits, 2009, 44(6), pp. 1805-1813.; Makhonin, M. N. et al., “Fast control of nuclear spin polarization in an optically pumped single quantum dot”, Nature Materials, 2011, pp. 844-848.; Song, Y.-Q. et al., “Reduction of Spin Polarization near Landau Filling Factor v=3 in GaAs/AlGaAs Quantum Wells”, Physical Review Letters, 1999, 82(13), pp. 2768-2771.; Sun, N. et al., “CMOS RF Biosensor Utilizing Nuclear Magnetic Resonance”, IEEE Journal of Solid-State Circuits, 2009, 44(5), pp. 1629-1643.; Sun, N. et al., “Palm NMR and 1-Chip NMR”, IEEE Journal of Solid-State Circuits, 2011, 46(1), pp. 342-352.; Tycko, R. et al., Electronic States in Gallium Arsenide Quantum Wells Probed by Optically Pumped NMR, Science, 1995, 268(5216), pp. 1460-1463.; Tycko, R. et al., “Optical Pumping in Solid State Nuclear Magnetic Resonance”, Journal of Physical Chemistry, 1996, 100(31), pp. 13240-13250.; Anders, J. et al., “A fully integrated IQ-receiver for NMR microscopy”, Journal of Magnetic Resonance, 2009, 209(1), pp. 1-7. | 4707797; November 17, 1987; Briggs; 5166620; November 24, 1992; Panosh; 5796252; August 18, 1998; Kleinberg; 6268726; July 31, 2001; Prammer; 8988076; March 24, 2015; Mandal et al.; 10295636; May 21, 2019; Song et al.; 20020033699; March 21, 2002; Toufaily; 20100156413; June 24, 2010; Chen et al.; 20110091987; April 21, 2011; Weissleder et al.; 20110234220; September 29, 2011; Mitchell; 20110248765; October 13, 2011; Tumer et al.; 20120025720; February 2, 2012; Chen; 20130099590; April 25, 2013; Ma | 2009108326; September 2009; WO | ['An NMR system includes a radio frequency (RF) NMR application-specific integrated circuit (ASIC) chip configured to generate an RF output signal and a rectifier configured to receive the RF output signal and convert the RF output signal to (a) a direct current (DC) pulsed field gradient (PFG) signal or (b) a DC trigger signal for at least one of (i) activating at least one component of an NMR system external to the NMR RF ASIC chip and (ii) synchronizing at least one component of an NMR system external to the NMR RF ASIC chip.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS\n \nThis application claims priority to U.S. Provisional Patent Application Ser.', 'No. 62/042,609, filed on Aug. 27, 2014 and which is incorporated herein by reference in its entirety, and U.S. Provisional Patent Application Ser.', 'No. 62/186,728, filed on Jun. 30, 2015 and which is incorporated herein by reference in its entirety.', 'TECHNICAL FIELD', 'This disclosure relates to nuclear magnetic resonance (NMR) and control thereof.', 'Some examples relate more specifically to NMR measurements taken in the field or in a laboratory.', 'Such measurements may include, for example, downhole measurements using NMR well-logging tools, including, for example, wireline and logging-while-drilling (LWD) tools.\n \nBACKGROUND\n \nNuclear Magnetic Resonance (NMR) is a routinely used technique for reservoir characterization due to its capability of measuring the hydrogen nuclei in the reservoir fluids.', 'As both water and hydrocarbons like oil and gas contain hydrogen nuclei, they can be measured and quantified by NMR tools.', 'Furthermore NMR measurement of relaxation times (T\n1\n and T\n2\n) and diffusion coefficients enable understanding of the dynamics of these fluids, resulting in the interpretation of their physical state (i.e. free or bound), the sizes of the pores they are confined in, the viscosity and type of hydrocarbons and the permeability of the rock system.', 'Diffusion is typically measured by the application of pulse sequences in combination with magnetic field gradients.', 'Both static gradient produced by the magnet itself or pulsed gradient produced by running electrical current in coils have been used.', 'The pulsed field gradient (PFG) method can be beneficial due to its better SNR.', 'In particular for small samples, the PFG coils can be also very small and highly efficient to produce large field gradient with minimal power.', 'This is very useful for, e.g., miniaturized NMR systems.', 'Pulsed field gradient (PFG) capability is utilized in performing diffusion experiments and many spectroscopy experiments.', 'The electrical current pulses generated by the PFG unit (which could be a part of the NMR ASIC of some example embodiments of the present application) will be sent to the coils in the NMR probe to produce magnetic field gradients.', 'For example, for diffusion measurements, typically two gradient pulses δ of equal amplitude and duration are used to produce signal decay due to diffusion, as shown in \nFIG.', '1\n.', 'FIG.', '1\n shows an example of a pulsed-gradient spin echo (PGSE) pulse sequence used for diffusion measurements.', 'The upper line \n101\n depicts the sequence of the RF pulses, and the lower line \n102\n depicts the sequence of the pulsed field gradient.', 'The amount of decay is then used to obtain the diffusion coefficient of a pure fluid or a distribution of diffusion coefficients of a complex fluid that contains a range of molecules.', 'In addition, NMR experiments are often performed together with other devices (which may provide electrical, magnetic field, or optical pulses to the sample).', 'For example, laser light excitation could be applied to the sample before or during the NMR pulse sequences in order to perform optically-detected NMR (see “Fast control of nuclear spin polarization in an optically pumped single quantum dot”, M. N. Makhonin, K. V. Kavokin, P. Senellart, A. Lemaître, A. J. Ramsay, M. S. Skolnick, and A. I. Tartakovskii, Nature Materials 10, 844-848 (2011) doi:10.1038/nmat3102) or laser-enhanced NMR (see “Reduction of spin polarization near Landau filling factor ν=3 in GaAs/AlGaAs quantum wells”, Y.-Q. Song, B. M. Goodson, K. Maranowski, A. C. Gossard, Physical Review Letters 82, 2768-2771 (1999) and “Optical pumping in solid state nuclear magnetic resonance”, R. Tycko and J. A. Reimer, J. Phys.', 'Chem. 100, 13240-13250 (1996)).', 'Synchronization of these devices requires either input or output digital or analog signals from the NMR ASIC to the external devices.', 'An example of an application for an external trigger is shown in connection with \nFIGS.', '2A, 2B, and 2C\n (reproduced from Tycko, R., Barrett, S. E., Dabbagh, G., Pfeiffer, L. N., & West, K. W. (1995).', 'Electronic states in gallium arsenide quantum wells probed by optically pumped NMR.', 'Science (New York, N.Y.), 268(5216), 1460-1463.', 'doi:10.1126/science. 7539550).', 'An optical pumping NMR system typically includes a laser and a conventional NMR system.', 'The sample can be irradiated by the laser.', 'The laser can be turned on and off using an electrical trigger signal.', 'This signal can be used to shut down the power to the laser or it controls a shutter.', 'The timing diagram of \nFIG.', '2A\n shows the sequence of the experiment, which includes first executing a few RF pulses \n201\n to initialize the magnetization, then turning the laser on using the external trigger function, then turning off the laser, then executing the main NMR pulse sequence \n202\n to obtain data.', 'Although there are existing implementations of NMR application-specific integrated circuits (NMR ASICs), such NMR ASICs have limited functionality and are RF only.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'As indicated above, existing NMR ASICs have limited functionality and are RF only.', 'In contrast to such RF NMR ASICs, some example embodiments of the present invention provide Full NMR ASICS, which are not limited to RF.', 'Some examples provide an NMR application-specific integrated circuit that includes: an on-chip pulse sequence generator configured to generate radio-frequency NMR pulse sequences; an on-chip radio-frequency transmitter configured to transmit the radio-frequency NMR pulse sequences generated by the on-chip pulse sequence generator; an on-chip radio-frequency receiver configured to receive radio-frequency signals corresponding to an excitation period of the NMR pulse sequences generated by the on-chip pulse sequence generator; and at least one of (a) an on-chip pulse field gradient unit configured to generate pulses defining a pulsed field gradient, (b) an on-chip external trigger configured to provide trigger signals that can be sent to an external device, (c) an on-chip external input configured to receive input from a device external to the NMR application-specific integrated circuit, and (d) an on-chip configuration memory configured to store values of the configuration of the NMR application-specific integrated circuit.', 'Some examples provide an NMR application-specific integrated circuit that includes: an on-chip pulse field gradient unit configured to generate pulses defining a pulse field gradient; at least one of (a) an on-chip external trigger configured to provide trigger signals that can be sent to an external device and (b) an on-chip external input configured to receive input from a device external to the NMR application-specific integrated circuit; and an on-chip configuration memory configured to store values of the configuration of the NMR application-specific integrated circuit.', 'Some examples provide a method that includes performing an NMR analysis using the NMR application-specific integrated circuit.', 'Some examples provide a method that includes generating a radio frequency (RF) signal using an NMR RF application-specific integrated circuit (ASIC) chip; and converting the RF signal into a direct current (DC) pulsed field gradient (PFG).', 'Some examples provide a method that includes generating a radio frequency (RF) signal using an NMR RF application-specific integrated circuit (ASIC) chip, converting the RF signal to a direct current (DC) trigger pulse; and at least one of (a) activating at least one component of an NMR system external to the NMR RF ASIC chip and (b) synchronizing at least one component of an NMR system external to the NMR RF ASIC chip.', 'Some examples provide a system that includes a radio frequency (RF) NMR radio application-specific integrated circuit (ASIC) chip configured to generate an RF output signal, and a rectifier configured to receive the RF output signal and convert the RF output signal to (a) a direct current (DC) pulsed field gradient (PFG) signal or (b) a DC trigger signal for at least one of (i) activating at least one component of an NMR system external to the NMR RF ASIC chip and (ii) synchronizing at least one component of an NMR system external to the NMR RF ASIC chip.', 'Further features and aspects of example embodiments of the present invention are described in more detail below with reference to the appended Figures.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFIG.', '1\n shows a pulsed-gradient spin echo (PGSE) pulse sequence used for NMR diffusion measurements.', 'FIG.', '2A\n shows a timing diagram for optically pumped NMR measurements.', 'FIG.', '2B\n shows the \n7 1\nGa NMR spectra at 1.9 K, 7.05 T, and ν=0.88 (θ=0°) with τ\nD\n=1 s and indicated values of τ\nL\n(200-mW light).', 'FIG.', '2C\n shows spectrum obtained with τ\nL\n=2 s and with the laser shutter open during acquisition of the NMR signals, illustrating light-induced shift and signal broadening from nuclei in GaAs wells.\n \nFIG.', '3\n shows a simplified schematic of a gradient driver circuit in accordance with example embodiments of the present invention.\n \nFIG.', '4\n shows an example tunable resonant circuit using a varactor.\n \nFIG.', '5\n shows an example tunable resonant circuit using a digitally-controlled capacitor bank.\n \nFIG.', '6\n shows a block diagram of an example NMR ASIC.\n \nFIG.', '7\n shows a diode and input and output signals.', 'FIG.', '8A\n shows a Gaetz bridge rectifier circuit (having a full-wave rectifier using four diodes) and input and output signals thereof.', 'FIG.', '8B\n shows a full-wave rectifier using a center tap transformer and two diodes, and input and output signals thereof.', 'FIG.', '9\n shows a simple practical circuit for producing DC pulses from RF pulses, where R and C are a resistor and a capacitor, respectively.\n \nFIG.', '10\n shows a frequency response of the filter circuit of \nFIG.', '9\n, with R=10 k ohm and C=1 nF.\n \nFIG.', '11\n shows a Sallen-Key low-pass filter of unit-gain.\n \nFIGS.', '12A and 12B\n show simulation results of a PWM circuit.\n \nFIG.', '13\n shows a circuit diagram for generating DC pulses from RF pulses.\n \nFIG.', '14\n shows a simulation of DC amplitude as a function of acquisition time in milliseconds, with an inset showing the RF pulses and tuning parameters to obtain a desired DC amplitude.\n \nFIGS.', '15A and 15B\n show an output signal and RF pulses.\n \nFIG.', '16\n shows an output signal and RF pulses.\n \nFIG.', '17\n shows an overall system configuration.', 'DETAILED DESCRIPTION', 'A highly application-specific integrated circuit (ASIC) in accordance with example embodiments performs many functions that are integral for an NMR system.', 'For example, example NMR ASICs contain the arbitrary pulse generator, transmitter and receiver, the three essential components of an NMR spectrometer.', 'The transmitter produces RF pulses (typically with the frequency of many MHz) with specific duration and amplitude and phases and is used to excite the NMR signal.', 'The precise timing of the pulses is achieved by the internal clock circuit.', 'Known ASICs are not capable of producing DC voltage or current pulses and pulse sequences to satisfy the need of producing DC pulses with precise timing and amplitude for the PFG applications.', 'This description provides, inter alia, methods and devices for using NMR RF ASIC to produce DC pulses of precise timing and amplitude for the application of PFG for diffusion measurement.', 'An NMR ASIC is quite complex and contains many parts for different functionalities.', 'The overall architecture of an example NMR ASIC \n600\n is illustrated in \nFIG.', '6\n and described in further detail below.', 'The interconnections between different parts are illustrated with lines and arrows.', 'This ASIC \n600\n will operate together with several other components/chips, including, for example, power supplies and a stable frequency source (e.g. a crystal oscillator).', 'These other components may also include a microcontroller that provides the ASIC with the pulse sequence codes and also transfers the acquired data.', 'Examples of such microcontrollers include the PIC32MX family of CPUs by Microchip Technology Inc., the SM320F28335-HT from Texas Instruments, and the HT83C51 from Honeywell.', 'These microcontrollers typically have SPI interfaces (ports) to allow high-speed communication with other SPI devices.', 'The data from the NMR ASIC \n600\n would be transferred to the microcontroller via one of these SPI ports for further processing.', 'The microcontroller also hosts the pulse sequence data to be transferred into the NMR ASIC \n600\n in order to be executed.', 'Because of the capabilities of the microcontroller and its memory, a large range of pulse sequences can be implemented.', 'In addition, the microcontroller can address other external memory modules, such as flash memory that may contain additional pulse sequence data.', 'The microcontroller can also use SPI or other digital interfaces to communicate and control other devices to perform peripheral measurements, such as environmental temperature, pressure, magnetic field, battery condition, etc.', 'The existing NMR ASICs, however, do not have all the functionalities as illustrated in \nFIG.', '6\n.', 'They only contain a transmitter, receiver, and sequencer, or a subset of these three components.', 'The on-chip PFG controller \n603\n is not believed to be in any prior NMR ASIC.', 'Example implementations of the present application provide that the RF pulse output can be used to produce DC pulses with precision timing to be used as PFG.', 'Since the sequencers are designed to output RF pulses with precise timing (both the duration of the pulses and the time within the sequence), the resulting DC pulses will exhibit the same precision as the RF pulses.', 'In accordance with some example embodiments, a chip, which may be an application-specific integrated circuit (ASIC) chip, may include one or more of the following structures: a pulse sequence generator, an RF transmitter (TX), a receiver (RX), an analog-to-digital converter (ADC) for the receiver, a pulse field gradient (PFG) unit, output triggers, input triggers, and configuration memory.', 'Referring, for example, to \nFIG.', '6\n, an NMR ASIC chip \n600\n includes a TX \n601\n, an RX and ADC unit \n602\n, and PFG unit \n603\n, a configuration memory and control unit \n604\n, and a sequencer \n605\n.', 'In some examples the triggers may be incorporated into the PFG unit \n603\n, while in some examples the triggers are provided as one or more separate unites on the chip \n600\n.', 'The on-chip pulse sequence generator, i.e., pulse sequencer, \n605\n provides essentially arbitrary pulse sequences.', 'The pulse sequence generator may be configured to provide any suitable number of pulse sequences.', 'The pulse sequencer and the TX cooperate to generate RF signals in accordance with user-defined parameter data stored in the memory (such as the on-chip memory \n604\n), and such RF signals may be supplied to an external antenna for emitting excitation signals from the external antenna during the excitation period of the NMR pulse sequence.', 'The RX receives electrical signals generated by an external antenna during the acquisition period of the NMR pulse sequence.', 'The on-chip TX is configured to provide amplitude and phase control for the RF pulses.', 'Some examples provide 5-bit amplitude and phase control to provide 32 different amplitudes and phases for the RF pulses.', 'It should be understood, however, that any suitable amplitude and phase control may be provided.', 'The on-chip RX may be, for example, an analog receiver which may provide two channels (I and Q) after demodulation.', 'The on-chip ADC may be provided for both I and Q channels within the ASIC to simplify the signal detection and remove the analog output from the chip altogether.', 'It should be understood, however, that other examples may maintain analog output in addition to or as an alternative to the digital output.', 'The on-chip PFG unit may include a PFG circuit configured to generate digitally-programmable unipolar or bipolar field gradient pulses that can be used for diffusion measurements.', 'In some examples, these pulses are generated by using an analog feedback loop to sense and control the current flowing through an off-chip gradient coil.', 'Different gradient coils can be used to generate field gradients in different directions, such as, for example, the x, y, and z axes.', 'The on-chip output triggers are configured to provide trigger signals that can be sent to external devices to, for example, initiate the operation of the device, terminate operation of the device, and/or initiate a particular pulse sequence of the device.', 'These are typically digital signals, although analog outputs can be used as an alternative or in combination with the digital signals.', 'Multiple output triggers may be combined to form a multi-bit signal, for example, to apply to a DAC (Digital-Analog Converter) to generate an analog voltage signal whose output voltage is fully controlled by the NMR ASIC.', 'This analog signal, for example, could be used to drive an external PFG unit (for example, external to the one within the ASIC \n600\n).', 'The input triggers are inputs from external devices to the NMR ASIC.', 'These signals can be either digital or analog.', 'These signals are typically read by the pulse sequencer and may cause the NMR ASIC to continue a pulse sequence, pause the sequence, or terminate the sequence.', 'The on-chip configuration memory \n604\n is provided and configured to store the values of the ASIC configuration, such as receiver gain, receiver LO phase, tuning and matching condition, etc.', 'More detailed descriptions of example designs and circuits of the NMR ASIC are provided, for example, below.', 'On-Chip ADC for Receiver\n \nOn-chip buffer memory (such as SRAM) may be provided to temporarily hold the digitized data until it can be read by an external micro-controller.', 'The memory may be connected to an SPI bus (or other digital bus) in order to be read by the micro-controller.', 'The amount of memory for a particular application may be estimated.', 'Typical NMR data is acquired every 5 μs or slower, and each acquired data point is made of two real numbers.', 'Each of these numbers may contain, in some examples, 8-16 bits, and is typically converted within 1 μs by the ADC.', 'Thus the data rate is approximately 3-6 Mbits per second maximum in such examples.', 'An SPI bus of 5-10 MHz will have no problem to read the data off the NMR ASIC.', 'Thus, a small buffer of 40-100 bytes would be sufficient for data transfer in such non-limiting examples.', 'PFG Circuit', 'In accordance with some example implementations, the goal of the PFG circuit is to apply and control pulsed magnetic field gradients, which are proportional to currents flowing through one or more gradient coils.', 'However, analog signal processing, both in ASICs and in board-level designs, is generally performed using voltages, not currents.', 'As a result, PFG circuits often use a series resistor to convert the coil current into a proportional voltage drop.', 'A voltage-based negative feedback loop is then used to regulate the coil current to its desired value.', 'This loop may be designed and configured to remain stable and well-behaved over all possible changes in coil inductance, operating temperature, output current level, and other system parameters.', 'Sensing and regulating the load current (instead of the load voltage) simplifies the dynamics of the system by eliminating the load impedance from the feedback loop.', 'The same advantage underlies the recent popularity of current-mode control for DC/DC converters.', 'It should be appreciated, however, that other example implementations may nevertheless utilize sensing and regulation via load voltage.', 'In accordance with example implementations, a gradient driver circuit \n300\n in accordance with \nFIG.', '3\n is provided.', 'This arrangement is described in further detail in this description.', 'External Outputs\n \nThe pulse sequencer may be provided with bits to control the corresponding logic outputs.', 'When the pulse code is loaded, the corresponding bits will be set (e.g. logic 1 or 0 correspond to voltage low or high).', 'The output of these bits is connected, possibly via driver circuits, to the external pins.', 'These pins are further connected to the intended other circuits/devices external to the NMR ASIC.', 'External Inputs\n \nThere may be some inputs from external pins into the chip.', 'For illustration, one pin may be called P\nin\n.', 'The logic of this P\nin \ncould be either 1 or 0, corresponding to low or high voltage.', 'One bit, called P\nc\n, in the pulse code may be dedicated to this function, When the sequencer arrives at this code, it may examine the value of P\nc\n.', 'If it is set to 1, then the sequencer checks P\nin\n.', 'If P\nin\n=1, then the sequence proceeds.', 'If P\nin\n=0, then the sequencer pauses the sequence.', 'If P\nc\n=0, then the sequencer ignores P\nin \nand continues to execute the sequence.', 'Tuning: Analog and Digital\n \nAnalog Tuning\n \nReferring, for example, to \nFIG.', '4\n, The RF probe in NMR may use a resonant tuning circuit \n400\n, such as a parallel resonance formed by an inductor \n401\n (the coil, inductance L) and a capacitor \n402\n (capacitance C).', 'The resonance frequency of such circuit is\n \n \n \n \n \nf\n \n=\n \n \n \n1\n \n \n2\n \n\u2062\n \nπ\n \n\u2062\n \n \nLC\n \n \n \n \n.', 'Consider an NMR tool with a proton resonance frequency of 1 MHz.', 'In this case we can use a coil of L=10 μH, and a tuning capacitor of C=16 nF.', 'In order to use the same coil for sodium (Na) NMR, the capacitance is increased by a factor of about 16, i.e., C(Na)=260 nF. Another way to assemble a RF probe for Na is to increase the inductance of the coil, for example to L(Na)=40 μH, and the capacitance will then be 64 nF.\n \nIn practical applications the value of the tuning capacitor often has to be adjusted by a few percent during tool operation in order to account for changes in the Larmor frequency, coil inductance, etc.', 'Variable tuning capacitors are needed for this purpose.', 'For low power NMR systems, such as for very small coils, the voltage applied to the coil is low, e.g. 10-30 V. In such system, PIN diodes can be used as RF switches and varactors (also named varicaps) can be used as the variable tuning and matching capacitors.', 'A typical circuit that uses varactor tuning is shown in \nFIG.', '4\n.', 'Referring to \nFIG.', '4\n, the diode \n403\n with an extra bar is the symbol for a varactor.', 'A DC voltage needs to be applied across the varactor \n403\n in order to change/control its capacitance.', 'Additional conventional capacitors (such as ceramic capacitors) can be added in parallel to the coil in order to vary the tuning range.', 'As can be seen in \nFIG.', '4\n, a precision analog voltage is utilized to adjust the tuning and matching.', 'This voltage can be applied from the ASIC as an analog voltage output.', 'In some example implementations, however, the output trigger lines from the ASIC are used to form an analog voltage using an external DAC on the circuit board.', 'The control value of such analog voltage can be stored on the ASIC.', 'Digital Tuning\n \nWhen the NMR system needs high power (such as a few kW), the use of varactor may not be appropriate in some circumstances.', 'Such systems often use some forms of switches \n503\n (e.g., electromechanical and/or solid state switches) to select the connection to a bank of ceramic capacitors \n502\n in order to vary the tuning or matching capacitors \n504\n, as illustrated in \nFIG.', '5\n.', 'Referring to the tunable resonant circuit \n500\n of \nFIG.', '5\n, which includes inductor \n501\n, each RF switch \n503\n is controlled by a driver circuit.', 'The driver circuit is controlled by an output line from the ASIC.', 'Thus, a few output lines from the ASIC can precisely adjust the total capacitance of the tuning circuit.', 'One example is given below.', 'It may be assumed that the tuning capacitors \n504\n are C\n0\n, C\n1\n, . . .', ', C\n7\n, and that C\n1\n=C\n0\n*2, C\n2\n=C\n1\n*2, . .', '.', ', C\n7\n=C\n6\n*2.', 'Eight control lines form a binary number p, where p\n0\n, p\n1\n, p\n2\n, etc. are the digits.', 'The total capacitance is then given by\n \n \n \n \n \n \n \nC\n \nT\n \n \n=\n \n \n \n∑\n \n \ni\n \n=\n \n0\n \n \n7\n \n \n\u2062\n \n \n \np\n \ni\n \n \n*\n \n \nC\n \ni\n \n \n \n \n \n,\n \n \n \n \n and thus \n \nC\nT\n=pC\n0\n.', 'Here p is the binary value with the digits, p=[p\n7 \np\n6 \np\n5 \np\n4 \np\n3 \np\n2 \np\n1 \np\n0\n], and p=0-255 in this example.', 'As a result, the capacitance value can span the range of (1-255)C\n0\n.', 'For example, if p=00001111, then the capacitance will be [1111](binary)=15 (decimal), thus C\nT\n=15C\n0\n.', 'If we add another fixed capacitor C\nf \nin parallel with C\nT\n, the full tuning capacitor will be \n \nC\nT\n=(1−255)\nC\n0\n+C\nf\n.', 'Thus the capacitance controlled by the switches (C\nT\n) will determine the frequency range over which the resonant circuit can be tuned.', 'The number of digits can be further increased to increase the tuning range.', 'The tuning value (digital code p) can be stored inside the NMR ASIC \n600\n since this value typically does not change during a single NMR experiment.', 'Configuration Memory\n \nThe NMR ASIC contains local memory in order to store the pulse sequence parameters.', 'These parameters are organized into a series of pulse codes, where each code defines an RF pulse, time delay, and acquisition parameters.', 'The local memory is dedicated to the pulse sequence parameters as these parameters (such as pulse lengths and phases) change constantly during one pulse sequence.', 'On the other hand, some of the parameters controlling the performance of the ASIC do not change during a pulse sequence, such as receiver gain and tuning parameters, and they may be substantially the same for several pulse sequences.', 'These parameters then can, in accordance with some examples, be stored in a separate “configuration” memory that is not tied to the pulse sequences.', 'The configuration memory can also be used to store loop numbers, as described in greater detail below.', 'If a frequency synthesizer is implemented, the value of the frequency can also be stored in the configuration memory.', 'Such memory can be made using SRAM (Static Random Access Memory).', 'Variable Frequency Synthesizer\n \nNMR measurements are usually performed at the Larmor frequency of the spin under investigation.', 'This frequency is proportional to the strength of the applied magnetic field, \n \nf\nL\n=γB\n0 \n \n where B\n0 \nis the magnetic field and γ is a constant known as the gyromagnetic ratio.', 'Different nuclei have different values of γ, so the Larmor frequency is different for different nuclei at the same magnetic field.', 'In addition, the magnetic field within the sample region may be inhomogeneous, i.e., can vary with position, as is the case with NMR well-logging tools.', 'In this case, different frequencies correspond to different regions within the sample volume.', 'As a result, varying the NMR operating frequency allows the detection of different areas of the sample.', 'This process, which is often known as depth profiling or radial profiling, is similar in principle to magnetic resonance imaging (MRI).', 'Thus there is often a need to adjust the operating frequency of the NMR ASIC.', 'External frequency synthesizers can be used for this purpose.', 'Some such synthesizers may employ a phase-locked loop (PLL) with a fractional-N divider in order to generate a large range of frequencies.', 'An optional frequency synthesizer circuit \n606\n can also be integrated into the NMR ASIC \n600\n.', 'Similar PLL circuits have been integrated into an ASIC within an existing SLB tool, the Nonconductive-Mud Geological Imager (NGI).', 'All of the frequency synthesizers, either from a separate chip or integrated within the NMR ASIC, utilize a stable frequency reference to operate.', 'This reference source may be, for example, a quartz crystal oscillator or a MEMS oscillator.', 'Pulse Sequencer Support of Features', 'In some example embodiments, the pulse sequence includes a series of pulse codes.', 'Each pulse code specifies the following aspects of the pulse: \n \n \n \nRF pulse duration.', 'RF pulse phase.', 'RF pulse amplitude.', 'The length of the time delay after the pulse.', 'An acquisition bit, to indicate whether to turn on signal acquisition or not.', 'A loop-start bit and a loop-end bit to control the looping of a portion of the sequence.', 'Positive and negative PFG amplitudes during the delay period, 10 bits each (the duration of the PFG pulses is determined by the delay time).', 'The range of the bit size may be, for example, 5-12.', 'Additional digital outputs (e.g. 10 bits).', 'Additional digital inputs (e.g. 2 bits).', 'An amount of on-chip memory is utilized to define each pulse code.', 'The memory may allow for, as an example, 256 different 96-bit pulse codes, i.e., 256×96=24 kB of memory.', 'The chip may contain loop-start and loop-end bits in order to execute a looping structure in a part of the pulse sequence.', 'This allows for executing repetitive pulse sequences such as the CPMG.', 'In some example implementations, the NMR ASIC \n600\n includes a loop counter variable in the configuration memory \n604\n.', 'This variable is used to signal the termination of the loop.', 'Such a loop counter can be implemented in accordance with the following non-limiting example.', 'As part of the pulse sequence, a loop number is loaded into the configuration memory \n604\n, e.g., a loop number of 100.', 'That means the loop should be executed 100 times and then the pulse sequence, via sequencer \n605\n, should exit the loop and continue to finish the remainder of the pulse sequence.', 'At the beginning of the loop, the loop number is loaded into a memory called, as an example, loop counter.', 'The value of the loop counter will decrease by 1 every time the loop-start is executed.', 'At the loop-end pulse code, the sequencer will examine whether the loop counter is zero.', 'If it is zero, then it exits the loop in order to finish the remainder of the sequence; otherwise, it continues back to loop-start.', 'The pulse sequence will be terminated if the next pulse code is zero or if it reaches the end of the sequence memory.', 'The pulse sequence can also be terminated by the chip shutdown command.', 'This structure can certainly be extended to have multiple loops and multiple loop numbers.', 'Known systems that utilize a loop structure can only run the loop as the last part of the sequence.', 'By including a loop counter, example embodiments of the present invention are not confined to this limitation.', 'Overall Architecture of the NMR ASIC', 'The overall architecture of the NMR ASIC is illustrated in \nFIG.', '6\n.', 'The major components are discussed, for example, above.', 'The interconnections between different parts are illustrated with lines and arrows.', 'This ASIC \n600\n operates together with several other components/chips.', 'It interfaces with power supplies, and a stable frequency source (e.g. a crystal oscillator).', 'It also interfaces a microcontroller that provides it with the pulse sequence codes, configuration setting, and also transfers the acquired data.', 'Examples of such microcontrollers are the PIC32MX family of CPUs by Microchip Technology Inc., the SM320F28335-HT from Texas Instruments, and the HT83C51 from Honeywell.', 'These microcontrollers typically have SPI interfaces (ports) to allow high-speed communication with other SPI devices.', 'The data from the NMR ASIC may be transferred to the microcontroller via one of these SPI ports for further processing.', 'The microcontroller also hosts the pulse sequence data to be transferred into the NMR ASIC in order to be executed.', 'Because of the capabilities of the microcontroller and its memory, a large range of pulse sequences can be implemented.', 'In addition, the microcontroller can address other external memory modules, such as flash memory that may contain additional pulse sequence data.', 'The microcontroller can also use SPI or other digital interfaces to communicate and control other devices to perform peripheral measurements, such as environmental temperature, pressure, magnetic field, battery condition, etc.', 'As illustrated in \nFIG.', '6\n, the microcontroller communicates with the NMR ASIC via an SPI interface \n607\n.', 'Through this interface \n607\n, the pulse sequence data can be loaded into the sequencer \n605\n, and configuration data can be loaded into the configuration memory \n604\n (to set the operating frequency, tuning, receiver gain, etc.).', 'It should be understood that other digital interfaces, such as CAN or I\n2\nC, can also be used for this purpose instead of SPI.', 'The full NMR ASIC \n600\n may have a shut-down pin, that when activated turns off the entire chip \n600\n to lower the power consumption.', 'This pin will be controlled by the microcontroller.', 'As part of the SPI interface of the NMR ASIC \n600\n, a SPI address decoder may be used to determine the target of the SPI data, i.e., whether it will be delivered to the sequence memory \n608\n or to the configuration memory \n604\n.', 'In some implementations, the sequence and configuration memory blocks can communicate via separate SPI interfaces.', 'This is feasible since modern microcontrollers may contain, as a non-limiting example, multiple (e.g., 5 or more) SPI ports.', 'Converting an RF Pulse to a DC Pulse\n \nIn some examples, the conversion of an oscillating voltage or current signal to a DC signal may be performed by a device called a rectifier.', 'In some examples, the rectifier is provided as a component separate from the NMR ASIC \n600\n.', 'In some examples, the rectifier is provided as an integrated component of the NMR ASIC.', 'The use of a rectifier to convert an oscillating voltage or current signal to a DC signal allows, in some examples, the use of known NMR ASIC chips, which do not have PFG capability, to be implemented in a PFG-capable NMR circuit.', 'In some examples, the non-PFG NMR ASIC chip is implemented together with a rectifier arrangement as described herein in order to provide PFG capability.', 'Referring to \nFIG.', '7\n, the simplest form of rectifier is a diode \n700\n which only allows current to flow through the diode \n700\n in one direction.', 'FIG.', '7\n shows a simple circuit for rectification, with the input of an AC current \n705\n on the left-hand side (IN) of the diode \n700\n (anode) and the signal appearing on the right-hand side (OUT) with only positive lobes \n710\n.', 'Since a diode only allows current to flow from anode to cathode, the positive current lobes \n710\n will flow though and the negative currently lobes \n715\n will not, resulting in the output waveform with only positive lobes \n710\n.', 'The average of the current over the length of the pulse is now positive, thus a DC component of the current is realized.', 'Referring, for example, to \nFIGS.', '8A and 8B\n, other examples are Graetz bridge \n800\n (full-wave rectifier using four diodes) and a full-wave rectifier \n850\n.', 'These types of rectifiers effectively use both negative and positive voltage supply, improving the operating efficiency.', 'In Graetz bridge configuration, MOSFETS may be used instead of diodes, avoiding voltage drop and therefore increasing the output dynamic range.', 'The oscillatory part of the current can be filtered out by including a filter circuit at the output, such as a RC filter.', 'A practical filter circuit \n900\n is shown in \nFIG.', '9\n.', 'Since the AC waveform is at the RF frequency, f\n0\n, the RF component in the output waveform is primarily f\n0\n, 2f\n0\n, and higher harmonics.', 'Such harmonics can be removed by application of low-pass filters that only allows low frequency signal to pass through.', 'The output of a signal of frequency f may be analyzed for this circuit:\n \n \n \n \n \n \n\uf603\n \n \n \nV\n \n0\n \n \n \nV\n \nin\n \n \n \n\uf604\n \n \n=\n \n \n \n[\n \n \n1\n \n \n1\n \n+\n \n \n \n(\n \n \n2\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \nfRC\n \n \n)', '2\n \n \n \n \n]\n \n \n \n1\n \n/\n \n2\n \n \n \n \n \n \n \nThus the frequency where the output is reduced by 3 db is ½πRC.', 'A graph of the frequency response is shown in \nFIG.', '10\n.', 'In particular, \nFIG.', '10\n shows the frequency response of the RC circuit shown in \nFIG.', '9\n.', 'R=10 k ohm, C=1', 'nF.', 'The horizontal axis of \nFIG.', '10\n is the frequency of in kHz, and the vertical axis of \nFIG.', '10\n is the gain in dB. It is evident that the output is reduced significantly at frequency higher than 50 kHz.', '(½πRC=16 kHz).', 'It may be desirable to connect the output of such filter to a buffer circuit (such as an OPAMP) to boost the current output and reduce the sensitivity to the impedance of the next stage.', 'Other filter topologies can be used.', 'For example, a Sallen-Key low-pass filter uses an active component (OPAMP or instrument AMP) to improve the frequency response.', 'For example, \nFIG.', '11\n shows a Sallen-Key low-pass filter \n900\n of unit-gain.', 'The filter type is the 2nd-order Sallen-key low-pass filter whose transfer function is expressed as below.', 'H\n \n\u2061\n \n \n(\n \ns\n \n)', '=\n \n \n1\n \n \n1\n \n+\n \n \n \ns\n \n\u2061\n \n \n(\n \n \n \nR\n \n1\n \n \n+\n \n \nR\n \n2\n \n \n \n)\n \n \n \n\u2062\n \n \nC\n \n2\n \n \n \n+\n \n \n \ns\n \n2\n \n \n\u2062\n \n \nR\n \n1\n \n \n\u2062\n \n \nR\n \n2\n \n \n\u2062\n \n \nC\n \n1\n \n \n\u2062\n \n \nC\n \n2\n \n \n \n \n \n \n \n \n \nThe cut-off frequency of the filter is\n \n \n \n \n \n \nf\n \n0\n \n \n=\n \n \n1\n \n \n2\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \nR\n \n1\n \n \n\u2062\n \n \nR\n \n2\n \n \n\u2062\n \n \nC\n \n1\n \n \n\u2062\n \n \nC\n \n2\n \n \n \n \n \n \n \n \n \n \nIf R\n1\n=R\n2\n=R and C\n1\n=C\n2\n=C, the frequency becomes:\n \n \n \n \n \n \nf\n \n0\n \n \n=\n \n \n1\n \n \n2\n \n\u2062\n \nπ\n \n\u2062\n \n \n \n \n\u2062\n \nRC\n \n \n \n \n \n \n \nFor 50 kHz of cut-off frequency, C=1 nF and R=3.18 k ohms.', 'PFG Amplitude Control\n \nThe amplitude of the PFG signal is to be modulated/controlled for a diffusion experiment.', 'However, at least some of the RF ASIC designed for NMR do not have the ability to vary the amplitude of the RF pulses.', 'The Pulse-width modulation (PWM) method may be applied to produce amplitude varying PFG pulses using the fixed amplitude RF pulses.', 'With the use of a low-pass filter at the output of the rectifier, only low frequency signal is passed through which is similar to an integral of the signal.', 'For example, if there is a series of 200 1-μs long pulses with 1-μs time between them, the total length of the sequence will be 400 μs long.', 'The average output will be ½ of the signal with a 400-μs long pulse.', 'Broadly speaking, this method is called Pulse-Width Modulation (PWM) that uses a rectangular pulse wave whose pulse duty cycle is modulated resulting in the variation of the average value of the waveform.', 'If we consider a pulse waveform, with low value 0, a high value Y\nMAX \nand a duty cycle D, the average value of the waveform is given by: \n \nY\nAVG\n=D×Y\nMAX \n \n \nReferring to \nFIGS.', '12A and 12B\n, a simulation of the circuit shows curves \n1201\n and \n1202\n that correspond to input pulses, 1 μs on and 1 μs off.', 'Curves \n1205\n and \n1206\n correspond to the output signal after the filter.\n \nFIG.', '12A\n corresponds to a 50% duty cycle, and \nFIG.', '12B\n corresponds to a 75% duty cycle resulting in a higher output voltage, demonstrating the PWM method.', 'There are many ways to implement the PWM concept, such as Delta modulation, Delta-sigma modulation, time proportioning, etc.\n \nAll of these methods utilize accurate timing of the pulses and it can be readily supplied by the NMR ASIC.', 'PFG Test Results\n \nOne of the PWM circuits tested is shown in \nFIG.', '13\n, which is a circuit diagram for generating DC pulse from RF pulse.', 'A full-bridge rectifier is followed by a low-pass filter.', 'RC time equals 180 μs.', 'The ASIC probe +', 'and − are fed into V\n1\n.', 'The DC output is measured after R\n4\n.', 'To obtain the desired DC amplitude, the first pulse length is set to be T\n0\n, as shown in \nFIG.', '14\n.', 'DC amplitude after the pulse is V=V\n0\n(1−e\n−T0/RC\n).', 'The voltage amplitude V is maintained by tuning the ratio T\non\n/T\noff\n, where T\non \nand T\noff \nare the duration of subsequent pulses and interval in between.', 'It can be shown that under the limit T\non\n, T\noff\n<<RC, V sustains when the relation T\non\n=T\noff\n×V/(V\n0\n−V) holds.', 'FIG.', '14\n is the simulation result on output DC amplitude as a function of acquisition time in milliseconds, given the proper combination of T\n0\n, T\non \nand T\noff\n.', 'The inset portion of \nFIG.', '14\n shows the RF pulses and tuning parameters to obtain a desired DC amplitude.', 'It becomes evident that a wide range of DC amplitudes can be achieved and maintained by a prudent selection of T\n0\n, T\non\n, and T\noff\n.', 'FIGS.', '15A, 15B, and 16\n show testing results on the circuit with different sets of parameters.', 'They are snapshots of ASIC RF pulses and DC output on an oscilloscope.', 'Indeed a wide range of DC amplitudes was achieved.', 'FIG.', '15A\n shows output signal \n1501\n with T\n0\n=350 μs, T\non\n=120 πs, T\noff\n=30 μs, and the RF pulses \n1502\n.', 'DC amplitude is stabilized 4.08 V. \nFIG.', '15B\n shows a zoomed-in view of the first 25 RF pulses \n1502\n and corresponding output DC voltage \n1501\n.\n \nFIG.', '16\n shows Output signal \n1601\n with T\n0\n=20 μs, T\non\n=5 μs, T\noff\n=30 μs, and the RF pulses \n1602\n.', 'DC amplitude is stabilized at 0.64 V.', 'PFG Circuit—Current Driver\n \nThe goal of the PFG circuit is to control static magnetic field gradients, which are proportional to currents flowing through one or more gradient coils.', 'However, analog signal processing, both in ASICs and in board-level designs, is usually performed using voltages, not currents.', 'As a result, PFG circuits often use a series resistor to convert the coil current into a proportional voltage drop.', 'A voltage-based negative feedback loop is then used to regulate the coil current to its desired value.', 'This loop must be designed properly in order to remain stable and well-behaved over all possible changes in coil inductance, operating temperature, output current level, and other system parameters.', 'Fortunately, sensing and regulating the load current (instead of the load voltage) simplifies the dynamics of the system by eliminating the load impedance from the feedback loop.', 'The same characteristic underlies the recent popularity of current-mode control for DC/DC converters.', 'In accordance with example implementations, there are two main circuit topologies used for current sensing: low-side, in which one end of the sensing resistor is connected to a known voltage (such as a DC power supply or ground), and high-side, in which both ends of the resistor can float.', 'For maximum flexibility, we decided to use separate sense resistors and feedback loops for positive and negative output currents.', 'Low-side sense resistors in such dual-loop designs should not be referenced to ground, because it is common to both current paths.', 'They can instead be referenced to the corresponding supply voltages (V\nSS \nand V\nDD\n), but only if these voltages remain completely stable during the pulse, i.e., exhibit no droop.', 'In other words, the corresponding DC voltage regulators must be designed to continuously supply the maximum output current.', 'In reality, however, the output has very low duty cycle and is only needed in short bursts, which means that the low-side scheme is very inefficient.', 'Some examples therefore use a high-side sensing scheme.', 'Here each sense resistor R\nsense \nis placed in series with its corresponding regulated current source (e.g., a MOSFET), cuch as the example shown in \nFIG.', '3\n.', 'As a result, the sensed voltages are largely independent of VSS and V\nDD\n, as long as they are large enough to keep the MOSFETs saturated.', 'In other words, these voltages can drop by considerable amounts during pulses without affecting the output current.', 'Hence voltage regulators with relatively small output current capabilities can be used to generate V\nSS \nand V\nDD\n, as long as enough capacitance is present at their outputs.', 'These capacitors are discharged during high-current pulses, and later recharged by the regulators.', 'FIG.', '3\n shows a simplified schematic of the gradient driver circuit.', 'The differential amplifiers, integrators, and voltage read-back amplifiers are implemented using op-amps.', 'The input voltages ν\nIN,P \nand ν\nIN,N \nare generated by digital-to-analog converters (DACs).', 'A differential amplifier (voltage gain=k\n1\n) may be used to sense and amplify the voltage across each resistor.', 'The amplified voltage is then compared with the desired value (ν\nIN,P \nor ν\nIN,N\n), integrated, low-pass filtered, and finally fed back into the gate terminal of the MOSFET to complete the feedback loop.', 'As a result, the coil current in steady state is directly proportional to the corresponding input voltage, and is given by i\nL\n(t)=ν\nIN\n(t)/(k\n1\nR\nsense\n).', 'The purpose of the low-pass filter is to reduce the loop bandwidth so that it remains stable with large inductive loads.', 'Finally, the output of the differential amplifier is further amplified (voltage gain=k\n2\n).', 'This “read back” voltage ν\nOUT\n(t)=(k\n1 \nk\n2\nR\nsense\n)i\nL\n(t) is directly proportional to the coil current i\nL\n(t), and can be used for monitoring and recording the coil current.', 'The conversion factor (transimpedance) between these two variables is simply (k\n1 \nk\n2\nR\nsense\n).', 'Use of RF ASIC for Trigger Pulses\n \nAs discussed earlier, some NMR experiments require electronic triggers at specific time of the experiment in order to activate/synchronize with other equipment.', 'These triggers are typically logic pulses, such as DC pulses of a few volts, for example, TTL pulses (0 to 5 V).', 'The timing of these pulses (the time of their execution and the duration of them) is important for the proper synchronization of equipment.', 'Similar to the conversion of RF pulses for PFG, rectification of RF pulses can be used to generate trigger pulses too.', 'Trigger pulses are often short, such as a few microseconds.', 'As a result, the low-pass filter associated with the circuit would be required to be of broader bandwidth.', 'For example, in order to properly execute trigger pulses of 1 μs, bandwidth of larger than 1 MHz would be needed.', 'Thus the component selection for the low pass filter will be different for PFG.', 'Overall System Configuration\n \nFor some applications, an ideal NMR ASIC would have implemented the PFG, and triggers internally (on-chip).', 'However, development of ASIC for a given application may be costly and time-consuming, and there are scenarios where using the existing ASIC is beneficial and cost effective.', 'For such cases, referring to \nFIG.', '17\n, a system \n1700\n may include multiple RF ASICs \n1710\n, \n1720\n, and \n1730\n, all connected to the micro-Controller (μC) \n1750\n.', 'The μC \n1750\n will program all the ASICs \n1710\n, \n1720\n, and \n1730\n according to the desired pulse sequences which include the operation of PFG unit and external triggers.', 'In fact, the PFG unit will have a sequence that is different from that of the RF ASIC, however, their operations are all synchronized by the pulse sequencer \n1711\n, \n1721\n, \n1731\n imbedded in each unit.', 'The signal to begin the execution of all the pulse sequences can be initiated from the μC \n1750\n so that all units \n1710\n, \n1720\n, and \n1730\n will operate in sync.', 'FIG.', '17\n provides the schematic of overall system configuration.', 'In the system of \nFIG.', '17\n, non-PFG capable NMR ASIC chips \n1710\n, \n1720\n, and \n1730\n are integrated into a system that allows PFG capability and trigger functionality in addition to NMR transmission (TX) and receipt (RX) signals.', 'In the illustrated example, the system includes three RF-only (non-PFG capable) NMR ASIC chips \n1710\n, \n1720\n, and \n1730\n, although it should be understood that other examples may provide more or less than three NMR ASIC chips.', 'The first RF-only NMR ASIC chip \n1710\n is coupled via a duplexer \n1760\n with the NMR coil \n1765\n for transmission of TX and RX signals.', 'The second RF-only NMR ASIC chip \n1720\n is coupled to a PFG driver \n1770\n to convert the RF signals of the second RF-only NMR ASIC chip \n1720\n to a pulse field gradient.', 'The third RF-only NMR ASIC chip \n1730\n is coupled to a trigger driver \n1780\n to convert RF signals of the third RF-only NMR ASIC chip \n1730\n to trigger signals.', 'Coordination of the functions provided by the three chips and related components is handled by a processor such as the microcontroller (μC) \n1750\n.', 'Although example NMR ASICs include many features and capabilities, the circuit implementations of these features may be conventional and well-known in the art of electronic engineering and ASIC design.', 'For example, the expanded memory for the sequencer and configuration memory can use conventional SRAM design techniques (e.g. memory cells with 6 or 4 transistors).', 'There are also many methods to implement such features.', 'For example, many different topologies are available for the implementation of ADCs, such as direct conversion, successive approximation, sigma-delta, etc.', 'Also, certain applications may require high temperature operation, such as well-logging.', 'The detailed design and manufacturing processes for such high temperature chips may be different from normal (low temperature) chips.', 'For example, silicon-on-insulator (SOI) processes can be used to reduce on-chip leakage currents, which may prevent operation at high temperatures.', 'In some embodiments, the controller is located within a borehole tool and configured to operate in high-temperature and high-pressure conditions.', 'Although illustrated example embodiments described herein refer to an ASIC, it should be understood that other implementations may take other forms.', 'For example, some implementations may utilize non-application-specific integrated circuits.', 'Illustrative embodiments of the present disclosure are not limited to wireline logging operations.', 'For example, the embodiments described herein can also be used with any suitable means of conveyance, such as coiled tubing.', 'Furthermore, various embodiments of the present disclosure may also be applied in logging-while-drilling (LWD) operations, sampling-while-drilling operations, measuring-while-drilling operations, or any other operation where sampling of the formation is performed.', 'Furthermore, various embodiments of the present disclosure are not limited to oil and gas field applications.', 'The methods and systems described herein can also be applied to, for example, petrochemical refining and chemical manufacturing.', 'Although several example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the scope of this disclosure.', 'Moreover the features described herein may be provided in any combination.', 'Accordingly, all such modifications are intended to be included within the scope of this disclosure.'] | ['1.', 'An NMR application-specific integrated circuit chip, comprising:\nan on-chip pulse sequence generator included as part of the NMR application-specific integrated circuit chip and configured to generate NMR pulse sequences;\nan on-chip transmitter included as part of the NMR application-specific integrated circuit chip and configured to transmit the NMR pulse sequences generated by the on-chip pulse sequence generator;\nan on-chip receiver included as part of the NMR application-specific integrated circuit chip and configured to receive signals corresponding to an excitation period of the NMR pulse sequences generated by the on-chip pulse sequence generator;\nan on-chip pulse field gradient unit included as part of the NMR application-specific integrated circuit chip and configured to generate pulses defining a pulse field gradient;\nat least one of (a) an on-chip external trigger included as part of the NMR application-specific integrated circuit chip and configured to provide trigger signals that can be sent to an external device and (b) an on-chip external input included as part of the NMR application-specific integrated circuit chip and configured to receive input from a device external to the NMR application-specific integrated circuit chip; and\nan on-chip configuration memory included as part of the NMR application-specific integrated circuit chip and configured to store values of the configuration of the NMR application-specific integrated circuit chip.', '2.', 'The NMR application-specific integrated circuit chip of claim 1, wherein the on-chip configuration memory includes a loop counter variable, the application-specific integrated circuit being configured to terminate a pulse sequence based on a value of the loop counter variable.', '3.', 'The NMR application-specific integrated circuit chip of claim 1, further comprising an on-chip analog-to-digital converter included as part of the NMR application-specific integrated circuit chip.', '4.', 'The NMR application-specific integrated circuit chip of claim 1, further comprising an on-chip frequency synthesizer included as part of the NMR application-specific integrated circuit chip.', '5.', 'The NMR application-specific integrated circuit chip of claim 1, wherein the NMR application-specific integrated circuit is part of a wellbore logging tool.', '6.', 'A method comprising:\nperforming an NMR analysis using the NMR application-specific integrated circuit chip of claim 1.\n\n\n\n\n\n\n7.', 'The method according to claim 6, further comprising applying the pulse field gradient during the NMR analysis, the pulse field gradient being controlled via the on-chip pulse field gradient unit.', '8.', 'The method according to claim 7, wherein the method is performed downhole in a wellbore.', '9.', 'The NMR application-specific integrated circuit chip of claim 1, wherein the on-chip pulse field gradient unit included as part of the NMR application-specific integrated circuit chip employs pulse width modulation of a fixed frequency RF pulse to produce a variable amplitude direct-current PFG signal.', '10.', 'An NMR system comprising:\na radio frequency (RF) NMR application-specific integrated circuit (ASIC) chip configured to generate an RF output signal; and\na rectifier and low-pass filter configured to receive the RF output signal and convert the RF output signal to (a) a direct current (DC) pulsed field gradient (PFG) signal or (b) a DC trigger signal for at least one of (i) activating at least one component of an NMR system external to the RF NMR ASIC chip and (ii) synchronizing at least one component of an NMR system external to the RF NMR ASIC chip, wherein the RF NMR ASIC chip includes a current-mode driver circuit that measures both a current level and voltage level of the DC PFG signal, wherein the current-mode driver circuit includes at least one differential amplifier circuit with two inputs across a sense resistor in order to measure the current level of the DC PFG signal.', '11.', 'The NMR system of claim 10, wherein the rectifier is included as part of the RF NMR ASIC chip.', '12.', 'The NMR system of claim 10, wherein the RF NMR ASIC chip employs pulse width modulation of a fixed frequency RF pulse such that the rectifier and low-pass filter produce a variable amplitude DC PFG signal.', '13.', 'The NMR system of claim 10, wherein the current-mode driver circuit further includes at least one integrator circuit with one input coupled to a voltage reference and another input coupled to the output of the differential circuit amplifier circuit in order to measure the voltage level of the DC PFG signal.', '14.', 'The NMR system of claim 13, wherein the current-mode driver circuit further includes a MOSFET having a gate terminal and a source-drain current path coupled to the sense resistor, wherein output of the integrator circuit is supplied to the gate terminal of MOSFET.'] | ['FIG.', '1 shows a pulsed-gradient spin echo (PGSE) pulse sequence used for NMR diffusion measurements.; FIG.', '2A shows a timing diagram for optically pumped NMR measurements.;', 'FIG.', '2B shows the 7 1Ga NMR spectra at 1.9 K, 7.05 T, and ν=0.88 (θ=0°) with τD=1 s and indicated values of τL(200-mW light).', '; FIG.', '2C shows spectrum obtained with τL=2 s and with the laser shutter open during acquisition of the NMR signals, illustrating light-induced shift and signal broadening from nuclei in GaAs wells.; FIG.', '3 shows a simplified schematic of a gradient driver circuit in accordance with example embodiments of the present invention.; FIG.', '4 shows an example tunable resonant circuit using a varactor.; FIG.', '5 shows an example tunable resonant circuit using a digitally-controlled capacitor bank.; FIG.', '6 shows a block diagram of an example NMR ASIC.; FIG.', '7 shows a diode and input and output signals.;', 'FIG.', '8A shows a Gaetz bridge rectifier circuit (having a full-wave rectifier using four diodes) and input and output signals thereof.;', 'FIG.', '8B shows a full-wave rectifier using a center tap transformer and two diodes, and input and output signals thereof.', '; FIG.', '9 shows a simple practical circuit for producing DC pulses from RF pulses, where R and C are a resistor and a capacitor, respectively.; FIG.', '10 shows a frequency response of the filter circuit of FIG. 9, with R=10 k ohm and C=1 nF.; FIG.', '11 shows a Sallen-Key low-pass filter of unit-gain.; FIGS.', '12A and 12B show simulation results of a PWM circuit.', '; FIG.', '13 shows a circuit diagram for generating DC pulses from RF pulses.; FIG.', '14 shows a simulation of DC amplitude as a function of acquisition time in milliseconds, with an inset showing the RF pulses and tuning parameters to obtain a desired DC amplitude.; FIGS.', '15A and 15B show an output signal and RF pulses.; FIG.', '16 shows an output signal and RF pulses.; FIG.', '17 shows an overall system configuration.; FIG.', '7 shows a simple circuit for rectification, with the input of an AC current 705 on the left-hand side (IN) of the diode 700 (anode) and the signal appearing on the right-hand side (OUT) with only positive lobes 710.', 'Since a diode only allows current to flow from anode to cathode, the positive current lobes 710 will flow though and the negative currently lobes 715 will not, resulting in the output waveform with only positive lobes 710.', 'The average of the current over the length of the pulse is now positive, thus a DC component of the current is realized.; FIG.', '12A corresponds to a 50% duty cycle, and FIG.', '12B corresponds to a 75% duty cycle resulting in a higher output voltage, demonstrating the PWM method.; FIGS.', '15A, 15B, and 16 show testing results on the circuit with different sets of parameters.', 'They are snapshots of ASIC RF pulses and DC output on an oscilloscope.', 'Indeed a wide range of DC amplitudes was achieved.; FIG.', '15A shows output signal 1501 with T0=350 μs, Ton=120 πs, Toff=30 μs, and the RF pulses 1502.', 'DC amplitude is stabilized 4.08 V. FIG.', '15B shows a zoomed-in view of the first 25 RF pulses 1502 and corresponding output DC voltage 1501.; FIG.', '16 shows Output signal 1601 with T0=20 μs, Ton=5 μs, Toff=30 μs, and the RF pulses 1602.', 'DC amplitude is stabilized at 0.64 V.; FIG.', '3 shows a simplified schematic of the gradient driver circuit.', 'The differential amplifiers, integrators, and voltage read-back amplifiers are implemented using op-amps.', 'The input voltages νIN,P and νIN,N are generated by digital-to-analog converters (DACs).'] |
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US11066334 | Binderless cBN sintering with cubic press | Jun 27, 2017 | Yahua Bao | SCHLUMBERGER TECHNOLOGY CORPORATION | Taniguchi, Takashi, et al. “Sintering of Cubic Boron Nitride without Additives at 7.7 GPa and above 2000 ° C.” Journal of Materials Research, vol. 14, No. 1, 1999, pp. 162-169., doi: 10.1557/jmr.1999.0024. (Year: 1999).; Funk J.E., Dinger D.R. (1994) Fundamentals of Particle Packing, Monodisperse Spheres. In: Predictive Process Control of Crowded Particulate Suspensions. Springer, Boston, MA (Year: 1994).; Akaishi, M., Satoh, T., Ishii, M. et al. Synthesis of translucent sintered cubic boron nitride. J Mater Sci Lett 12, 1883-1885 (1993). https://doi.org/10.1007/BF00882529 (Year: 1993).; “Drying & Firing.” Materials Science and Engineering: an Introduction 8e, by William D. Callister, John Wiley & Sons, 2012, pp. 521-522. (Year: 2012).; “Boron Nitride.” Wikipedia, Wikimedia Foundation, Jun. 23, 2016, web.archive.org/web/20160623212914/en.wikipedia.org/wiki/Boron_nitride#Preparation_of_cubic_BN. (Year: 2016).; Funk, James E., and Dennis R. Dinger. Predictive Process Control of Crowded Particulate Suspensions: Applied to Ceramic Manufacturing. Kluwer, 2001 (Year: 2001).; Hansen, Tony. Drying Shrinkage, Jan. 6, 2016, digitalfire.com/glossary/drying shrinkage. (Year: 2016).; International Search Report and Written Opinion issued in International Patent application PCT/US2017/039363 dated Sep. 28, 2017, 10 pages.; Akaishi et al., “Synthesis of translucent sintered cubic boron nitride”Journal of Materials Science Letters, vol. 12, pp. 1883-1885 (1993).; Sumiya et al., “Mechanical properties of high purity polycrystalline cBN synthesized by direct conversion sintering method” Journal of Materials Science, vol. 35, pp. 1181-1186 (2000).; Taniguchi, T., High-pressure synthesis of binderless cubic boron nitride sintered bodies, The Reiview of High Pressure Science and Technology, V.21 (2011) No. 4, 292-299.; Taniguchi, t., et al, Sintering of cubic boron nitride without additives at 7.7GPa and above 2000° C., Journal of Materials Research, 1 (1999), 162-169.; Liu G., et al, Submicron cubic boron nitride as hard as diamond, Applied Physics Letters, 98 (2011 ), 203112.; International Preliminary Report on Patentability issued in International Patent application PCT/US2017/039363, dated Jan. 1, 2019, 6 pages.; First Office Action and Search Report issued in Chinese Patent Application 201780039792.5 dated Mar. 24, 2021.; Office action issued in Japanese patent application 2018-567864 dated Mar. 18, 2021. | 4150098; April 17, 1979; Sirota et al.; 4188194; February 12, 1980; Corrigan; 5271749; December 21, 1993; Rai; 5691260; November 25, 1997; Suzuki et al.; 6071841; June 6, 2000; Sumiya; 7404832; July 29, 2008; Ohtsubo; 8382868; February 26, 2013; Goudemond et al.; 8657893; February 25, 2014; Wardoyo; 9416304; August 16, 2016; Ishida et al.; 9422161; August 23, 2016; Dongli Yu; 9522850; December 20, 2016; Matsuda; 20080302023; December 11, 2008; Goudemond; 20150298290; October 22, 2015; Ishida et al.; 20160318808; November 3, 2016; Kasonde | 2002333; February 1979; GB; H03159964; July 1991; JP; 2590413; March 1997; JP; H11246271; September 1999; JP | ['A method of sintering a binderless cBN body includes providing a boron nitride particle mixture into a pressure chamber, the boron nitride particle mixture having a first type of boron nitride particles and boron nitride filler particles, and the boron nitride filler particles having a different size and/or type than the first type of boron nitride particles, and sintering the boron nitride particle mixture in the pressure chamber to form the cBN body by generating a pressure in the pressure chamber of less than 7.7 GPa and heating the boron nitride particle mixture to a temperature ranging from about 1900° C. to about 2300° C., wherein the cBN body has a density of at least 97 percent.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'This application claims priority to and the benefit of U.S. Provisional Application No. 62/356,225, filed on Jun. 29, 2016, the entirety of which is incorporated herein by reference.', 'BACKGROUND\n \nCubic boron nitride (cBN) particles may be sintered together in the presence of a ceramic or metallic binder to form a polycrystalline cubic boron nitride (PCBN) composite material having designed material properties, such as increased wear resistance or toughness.', 'For example, PCBN composite materials may be formed by high-pressure high-temperature (HPHT) sintering of a mixture including cBN particles as a hard phase (e.g., an ultra-hard material), and aluminum (Al) metal powder, which becomes a liquid sintering reactant.', 'HPHT sintering of PCBN may include using pressures of between about 4-7 GPa and temperatures of between about 1200° C. and', '1500° C.', 'In some applications, cBN particles may be sintered together without use of a binder in a binderless cBN sintering process.', 'However, known binderless cBN sintering processes include use of ultra-high pressures greater than 7.7 GPa and high temperatures greater than 2000° C. (e.g., between 2200° C. and 2400° C.).', 'Such ultra-high pressure and high temperature conditions may be difficult and costly to achieve compared to the pressure and temperature conditions used for forming PCBN.', 'PCBN may be used in a variety of machining applications including, for example, in tools for friction stir welding, processing, or joining.', 'A tool used for friction stir welding may include a strong pin including PCBN that is moved along a joint between two pieces of material to super-plastically deform a portion of each piece of material and weld the two pieces together.', 'Other applications may include using PCBN for cutting tools, drilling tools, or machining tools, such as tools for machining tool steel, case-hardened steel and high-speed steel, welding alloys, cast iron and others.', 'SUMMARY\n \nThis summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'In one aspect, embodiments of the present disclosure relate to methods of sintering a binderless cBN body that includes providing a boron nitride particle mixture into a pressure chamber, the boron nitride particle mixture having a first type of boron nitride particles and boron nitride filler particles, and the boron nitride filler particles having a different size and/or type than the first type of boron nitride particles, and sintering the boron nitride particle mixture in the pressure chamber to form the cBN body, where the sintering includes generating a pressure in the pressure chamber of less than 7.7 GPa and heating the boron nitride particle mixture to a temperature ranging from about 1900° C. to about 2300° C., wherein the cBN body has a density of at least 97 percent.', 'In another aspect, embodiments of the present disclosure relate to a method of making a cBN body that includes providing a boron nitride particle mixture into a pressure chamber, generating a pressure in the pressure chamber ranging from about 7 GPa to less than 7.7 GPa, and heating the pressure chamber to a temperature ranging from about 1900° C. to about 2300° C., wherein the cBN body has at least 98 percent composition cBN.', 'In yet another aspect, embodiments of the present disclosure relate to sintered binderless cBN bodies having a plurality of bonded together cBN grains, a density of at least 99 percent, and a Vickers hardness of greater than 38 GPa, wherein cBN forms at least 98 percent composition of the sintered binderless cBN body.', 'Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.', 'BRIEF DESCRIPTION OF DRAWINGS\n \nThe accompanying drawings, together with the specification, illustrate example embodiments of the disclosed subject matter, and, together with the description, serve to explain principles of the disclosed subject matter.', 'FIG.', '1\n is a graph of the theoretical densities of binderless cBN bodies sintered from boron nitride particle mixtures according to embodiments of the present disclosure and from a conventional boron nitride particle mixture.', 'FIG.', '2\n shows an x-ray diffraction spectrum of sintered binderless cBN bodies sintered from a boron nitride particle mixture according to embodiments of the present disclosure under different temperatures.\n \nFIG.', '3\n shows a table of the compositions of the sintered binderless cBN bodies of \nFIG.', '2\n.', 'FIG.', '4\n shows an x-ray diffraction spectrum for comparative samples of sintered binderless cBN bodies.\n \nFIG.', '5\n shows an x-ray diffraction spectrum for comparative samples of sintered binderless cBN bodies.\n \nFIG.', '6\n shows a tool having a sintered binderless cBN material according to embodiments of the present disclosure.\n \nFIG.', '7\n shows a cutting element having a sintered binderless cBN material according to embodiments of the present disclosure.', 'DETAILED DESCRIPTION', 'In the following detailed description, only certain example embodiments of the disclosed subject matter are shown and described, by way of illustration.', 'As those skilled in the art would recognize, the disclosed subject matter may be embodied in many different forms and should not be construed as being limited to the embodiments set forth herein.', 'Like reference numerals designate like elements throughout the specification.', 'According to embodiments of the present disclosure, sintered binderless cubic boron nitride (cBN) bodies having high density and high hardness may be formed by sintering boron nitride particles under relatively low pressure conditions by using boron nitride starting material compositions discussed herein.', 'The resulting sintered binderless cBN bodies substantially include bonded together grains of cBN and may include minimal amounts of residual materials or impurities (e.g., forming less than 3 percent, less than 1 percent, or less than 0.5 percent of the sintered body composition).', 'For example, sintered binderless cBN bodies according to embodiments disclosed herein may have at least 97 percent composition of cBN, e.g., including greater than 98 percent composition cBN and greater than 99 percent composition cBN, such as 99.8 percent composition cBN, which is present as bonded together and interconnected grains of cBN.', 'As used herein, the term “particle” refers to the powder starting material employed prior to sintering, while the term “grain” refers to discernible super-abrasive regions subsequent to sintering.', 'To sinter a binderless cBN body according to embodiments disclosed herein, a boron nitride particle mixture (which also may be referred to as the starting material) may be placed in a protective container, which in turn, may be placed in a working chamber of a suitable high pressure, high temperature press apparatus.', 'The container and its contents may then be subjected to elevated pressure and temperature conditions to sinter the binderless cBN body.', 'Sintered binderless cBN bodies may be prepared using the same equipment generally used for the formation of polycrystalline cubic boron nitride.', 'For example, binderless cBN bodies according to embodiments of the present disclosure may be prepared using any suitable press (e.g., a high-pressure high-temperature (HPHT) press), such as a cubic press, a belt press, a toroid press, or a multi-anvil press, and other know presses.', 'While presses known for sintering materials at high temperatures and high pressures may have a variety of shapes, sizes and configurations of components, presses generally include a “pressure chamber” for holding the starting material to be sintered, where starting material loaded into the pressure chamber may be subjected to increased pressures and temperatures for sintering.', 'Pressure chambers may include one or more components, e.g., components that are movable relative to one another, sealing components, and components having concentric or overlapping walls, to name a few, and may have different sizes and shapes.', 'As used herein, a pressure chamber may include one or more configurations of a container that is capable of holding starting material while allowing heat and pressure to be transferred to the starting material.', 'A pressure chamber may be formed as a non-removable portion of a press, or a pressure chamber may be a removable portion, where the pressure chamber may be removed from and loaded into a press.', 'Presses have previously been used to sinter polycrystalline cubic boron nitride bodies from a starting material mixture of cBN particles and metal binder particles at temperatures and pressures of about 1200-1500° C. and 4-7 GPa, respectively, and to sinter binderless cBN bodies (from a starting material mixture without a metal binder) at temperatures and pressures of greater than 1900° C. and greater than 7.7 GPa, respectively.', 'However, according to embodiments disclosed herein, presses may be used to sinter binderless cBN bodies at pressures less than 7.7 GPa and temperatures ranging from about 1900° C. to 2300° C., while also providing sintered binderless cBN bodies having comparable or greater densities and/or hardness to the densities and hardness of previous cBN bodies sintered at higher pressures.', 'For example, according to embodiments of the present disclosure, a method of making a binderless cBN body may include providing a boron nitride particle mixture into a pressure chamber, generating a pressure in the pressure chamber of less than 7.7 GPa (e.g., ranging from about 6.8 GPa to less than 7.7 GPa, such as about 7 GPa), and heating the pressure chamber to a temperature ranging from about 1900° C. to about 2300° C. to sinter the boron nitride particle mixture into a sintered binderless cBN body having at least 98 percent composition cBN.', 'The remaining composition of the resulting sintered binderless cBN body may include residual materials from sintering and/or impurities, for example, carbides from the equipment used to mix the boron nitride particle mixture and/or oxides formed under the processing conditions.', 'Further, the resulting sintered binderless cBN body may have a density of at least about 97 percent (e.g., greater than 98.0 percent, greater than 98.5 percent, greater than 99.0 percent, or greater than 99.5 percent density) and/or a Vickers hardness of at least about 37 GPa (e.g., greater than 38 GPa or greater than 40 GPa).', 'To form sintered binderless cBN bodies at relatively lower pressures (less than 7.7 GPa) and still result in high density and hardness (e.g., densities of at least about 97 percent and Vickers hardness of at least about 37 GPa), the boron nitride starting material composition may be designed to minimize the volume change resulting from the sintering process.', 'In other words, by designing the boron nitride starting material to undergo less volume change during sintering, lower pressures may be used for the sintering while still resulting in sintered binderless cBN bodies having high density and hardness.', 'Volume change between a starting material and resulting sintered body may occur from phase transformations in the starting material and/or densification of the starting material particles.', 'Densification during the sintering process may result from the shape and/or size of the starting particles changing with the formation of grain boundaries and at the same time, the shape, size and/or amount of pores between the starting particles changing, thereby reducing the relative amount of pore volume to particle volume.', 'Thus, by designing the composition of the boron nitride starting material to have relatively increased density and/or less volume change due to phase transformations, the overall volume change between the starting material and the sintered body may be reduced, and the pressure used for sintering may be lowered.', 'According to embodiments of the present disclosure, a boron nitride particle mixture may be designed to undergo less volume change during sintering by forming the boron nitride particle mixture from a first type of boron nitride particles and boron nitride filler particles, where the boron nitride filler particles have a different size and/or type than the first type of boron nitride particles.', 'For example, a first type of boron nitride particles may include cBN particles having a selected particle size range and/or selected average particle size, and the boron nitride filler particles may include hexagonal boron nitride (“hBN”) particles and/or cBN particles having a different particle size (different particle size range and/or average particle size) from the first type of boron nitride particles.', 'In some embodiments, a first type of boron nitride particles may include a single cut of coarse cBN particles having a particle size ranging from about 12 to 22 microns under a normal distribution, and the boron nitride filler may include fine cBN particles having an average particle size less than the first type of boron nitride particles, such as an average particle size of about 2 microns or less.', 'Optionally, the boron nitride particle mixture may further include a third cut of cBN particles having an average particle size different from the coarse cubic boron nitride particles and the fine cubic boron nitride particles.', 'Embodiments of the present disclosure may include a boron nitride particle mixture having cBN particles with a multi-modal particle size distribution, including for example, a bi-modal particle size distribution (i.e., particles with two average sizes) or a tri-modal particle size distribution (i.e., particles with three average sizes).', 'For example, a boron nitride particle mixture of cBN particles having a bi-modal particle size distribution may include cBN particles having an average particle size within a range of about 12 to 22 microns and cBN particles having an average particle size within a range of about 0.1 to 12 microns.', 'Some embodiments may include use of a boron nitride particle mixture having cBN particles with a close packed tri-modal distribution, such as a first cut of cBN particles having an average particle size ranging from 12 to 22 microns, a second cut of cBN particles having an average particle size ranging from 2 to 4 microns, and a third cut of cBN particles having an average particle size ranging from 0.1 to 1 micron.', 'Boron nitride particle mixtures having cBN particles with a multi-modal particle size distribution may include two or more cuts of cBN particles with different particle sizes, where a majority (e.g., greater than 50 percent) of the composition of the multi-modal cBN particles is a coarse cut of cBN particles having an average particle size ranging from 12 to 22 microns.', 'For example, in embodiments having a tri-modal distribution of cBN particles, the tri-modal cBN particle mixture may include between 70 and 90 percent composition (e.g., about 85 percent composition) of coarse cut cBN particles having an average particle size ranging from 12 to 22 microns, between 5 and 15 percent composition (e.g., about 7 percent composition) of a second cut cBN particles having an average particle size ranging from 2 to 4 microns, and between 5 and 15 percent composition (e.g., about 8 percent composition) of a third cut cBN particles having an average particle size ranging from 0.1 to 1 micron.', 'In some embodiments, tri-modal cBN particle mixtures may include a majority composition of coarse cut cBN particles and a substantially equal amount by composition of two cuts of cBN particles having different average particle sizes.', 'In some embodiments, tri-modal cBN particle mixtures may include a majority composition of coarse cut cBN particles and unequal amounts by composition of two cuts of cBN particles having different average particle sizes (e.g., where a second cut with a relatively larger average particle size forms a greater percent composition than a third cut with a relatively smaller average particle size, or where a second cut with a relatively smaller average particle size forms a greater percent composition than a third cut with a relatively larger average particle size).', 'Mixing cBN particles having different particle sizes to form a boron nitride particle mixture may allow for closer packing between the particles in the boron nitride starting material.', 'Further, mixing cBN particles having larger differences in particle size, e.g., mixing coarse cBN particles and fine cBN particles, may allow for closer packing of the starting material than mixing cBN particles having smaller differences in particle size, e.g., cBN particles with a bi-modal particle size distribution with a difference in average particle size between the two particle sizes ranging from less than 50 percent difference, less than 25 percent difference, or less than 15 percent difference.', 'In some embodiments, hBN particles may be used as boron nitride filler, either alone or in combination with other boron nitride filler material.', 'For example, in some embodiments, a first type of boron nitride particles may include cBN particles, and hBN particles, alone, may form the boron nitride filler.', 'In some embodiments, a first type of boron nitride particles may include cBN particles having a first average particle size, and the boron nitride filler may include hBN particles and cBN particles having a second average particle size, smaller than the first average particle size.', 'HBN particles may act as a lubricator in a boron nitride particle mixture, which may help with particle packing and improve green density.', 'HBN particles in a boron nitride particle mixture may have an average particle size less than or equal to an average particle size of a cBN particle constituent of the boron nitride particle mixture.', 'In some embodiments, hBN particles may have a particle size of less than 5 microns, e.g., ranging from greater than 0 to about 2 microns.', 'A boron nitride particle mixture may include at least about 50 percent by weight of a first type of boron nitride particles, e.g., cBN particles ranging in size from about 12 to 22 microns, and less than 50 percent by weight of a boron nitride filler material.', 'For example, a boron nitride particle mixture may include between 75 and 90 percent by weight (e.g., about 80 percent to about 85 percent by weight) of coarse cBN particles and between 10 and 20 percent by weight (e.g., about 15 percent by weight) fine cBN particles and/or between 5 and 20 percent by weight (e.g., about 15 percent by weight) hBN particles.', 'In some embodiments, a boron nitride particle mixture may include 50 percent by weight or more of cBN particles and less than 50 percent by weight of hBN particles.', 'Because hBN particles undergo a large volume change during sintering due to phase transformation from hBN to cBN, in some embodiments, hBN may form less than 20 percent by weight (e.g., 15 percent by weight or less, 10 percent by weight or less, or about 5 percent by weight) of a boron nitride particle mixture.', 'Using boron nitride particle mixtures disclosed herein as the starting material for forming sintered binderless cBN bodies may reduce the volume change between the volume of the starting material and the volume of the sintered binderless cBN body resulting from the sintering process.', 'According to embodiments of the present disclosure, the composition of a boron nitride particle mixture may be designed to form the boron nitride starting material of a sintered binderless cBN body, such that a change in volume from the boron nitride particle mixture volume to the sintered binderless cBN body volume is less than 45 percent, less than 40 percent (e.g., about 35 percent), and in some embodiments, less than 35 percent.', 'A boron nitride particle mixture according to embodiments of the present disclosure may be sintered into a binderless cBN body by pouring the boron nitride particle mixture into a pressure chamber of a press and generating a pressure in the pressure chamber of less than 7.7 GPa, while heating the boron nitride particle mixture to a temperature ranging from about 1900° C. to about 2300° C.', 'For example, boron nitride particle mixtures according to embodiments of the present disclosure may be sintered at pressures of between 6.8 and 7 GPa, between 7 and 7.2 GPa, or between 7.2 and 7.6 GPa to form binderless cBN bodies.', 'Binderless cBN bodies sintered from boron nitride particle mixtures disclosed herein may be sintered at pressures less than 7.7 GPa and temperatures between about 1900° C. and 2300° C. while still having a density of at least 97 percent, at least 98 percent, or at least 99 percent.', 'The density of the sintered binderless cBN bodies may be increased (e.g., to have a density of greater than 99 percent) by using a boron nitride particle mixture, as disclosed herein, as the starting material for the sintered binderless cBN bodies.', 'For example, using multi-modal cBN particles as the starting boron nitride particle mixture may allow for improved particle packing in the starting material, which may allow for reduced volume change during the sintering process, and thereby allow for a high density resulting from a relatively lower sintering pressure.', 'Using a mixture of cBN particles and less than 50 percent by weight of hBN particles as the starting boron nitride particle mixture may have reduced volume change during the sintering process from phase transformation between hBN to cBN (when compared to sintering a cBN body entirely from hBN starting material), and thereby allow for lower sintering pressures to be used when sintering a high density binderless cBN body.', 'Methods of sintering a binderless cBN body may include powder packing a boron nitride particle mixture within a pressure chamber prior to subjecting the boron nitride particle mixture to elevated pressures and temperatures.', 'For example, in some embodiments, a boron nitride particle mixture starting material may be loaded into a pressure chamber of a press, and the pressure chamber holding the boron nitride particle mixture may be vibrated to powder pack the boron nitride particle mixture.', 'After vibrating, the boron nitride particle mixture may be subjected to elevated pressures and temperatures for sintering the powder packed boron nitride particle mixture into a sintered binderless cBN body.', 'In some embodiments, a method of sintering a binderless cBN body may include cold isostatic pressing a boron nitride particle mixture prior to subjecting the boron nitride particle mixture to elevated pressures and temperatures.', 'For example, in some embodiments, a boron nitride particle mixture starting material may be loaded into and sealed within a flexible mold, and pressure (e.g., hydraulic pressure) may be applied around the sealed flexible mold to provide substantially uniform compaction of the boron nitride particle mixture and relatively uniform density within the compacted body.', 'Optionally, in some embodiments, the boron nitride particle mixture may be powder packed prior to cold isostatic pressing.', 'The compacted body of the boron nitride particle mixture may then be loaded into a pressure chamber of a press and subjected to elevated pressures and temperatures for sintering the compacted boron nitride particle mixture into a sintered binderless cBN body.', 'In some embodiments, a boron nitride particle mixture may be loaded into a high pressure press and subjected to pressures ranging from 1 to 7 GPa to pack the boron nitride particle mixture and improve the green density prior to sintering.', 'After being subjected to pressures ranging from 1 to 7 GPa, the packed boron nitride particle mixture may then be sintered to form a sintered binderless cBN body.', 'Sintered binderless cBN bodies formed from boron nitride particle mixtures according to embodiments of the present disclosure may have high densities of at least 98 percent, including greater than 98.5 percent, greater than 99 percent, and greater than 99.5 percent, depending on, for example, the composition of the boron nitride particle mixture and the sintering temperature and pressure.\n \nFIG.', '1\n shows an example of the theoretical densities of binderless cBN bodies sintered from different boron nitride particle mixtures at 7 GPa and different temperatures.', 'The tested boron nitride particle mixtures include a conventional single cut cBN particle mixture, shown as boron nitride particle mixture A, and boron nitride particle mixtures according to embodiments of the present disclosure, shown as boron nitride particle mixtures B and C. Boron nitride particle mixture A includes a single cut of cBN particles having a normal distribution, where the cBN particles have a particle size ranging from 12 to 22 microns.', 'According to an embodiment, boron nitride particle mixture B includes a mixture with 85 percent by weight of cBN particles with a particle size ranging from 12 to 22 microns and 15 percent by weight of cBN particles with a particle size ranging from greater than 0 to 2 microns.', 'According to an embodiment, boron nitride particle mixture C includes a mixture with 85 percent by weight of the boron nitride particle mixture B and 15 percent by weight of hBN particles.', 'As such, boron nitride particle mixture C may include a mixture with about 72 percent by weight of cBN particles with a particle size ranging from 12 to 22 microns, about 13 percent by weight of cBN particles with a particle size ranging from greater than 0 to 2 microns, and about 15 percent by weight of hBN particles.', 'As shown in \nFIG.', '1\n, boron nitride particle mixture A was unable to result in a high density (with a theoretical density of at least 98 percent) binderless cBN body when sintered at 7 GPa and temperatures under 2250° C. Instead,', 'boron nitride particle mixture A resulted in a high density of about 99.2 percent when sintered at 7 GPa and under temperatures of about 2370° C.', 'In contrast, particle mixtures according to embodiments of the present disclosure and shown in \nFIG.', '1\n, boron nitride particle mixture B and boron nitride particle mixture C, were able to result in high density (with a theoretical density of at least 98 percent) binderless cBN bodies when sintered at 7 GPa and temperatures ranging between 1900° C. and 2300°', 'C.', 'For example, when sintered at 7 GPa and under temperatures ranging from about 2140° C. to 2250° C., boron nitride particle mixture B resulted in a binderless cBN bodies having high densities ranging between about 99.5 percent and about 99.7 percent.', 'When sintered at 7 GPa and about 1950° C., boron nitride particle mixture C resulted in a binderless cBN body having a high density of about 98.6 percent.', 'When sintered at 7 GPa and under temperatures ranging from about 2070° C. to about 2270° C., boron nitride particle mixture C resulted in binderless cBN bodies having high densities ranging from greater than 99.2 percent to about 99.7 percent.', 'FIG.', '1\n shows selected examples of boron nitride particle mixtures according to embodiments of the present disclosure sintered under 7 GPa and temperatures ranging between 1900° C. and 2300°', 'C.', 'However, other boron nitride particle mixtures according to embodiments of the present disclosure may be sintered under similar conditions (e.g., pressures of less than 7.7 GPa, less than 7.5 GPa, or less than 7.2 GPa, such as between 6.9 GPa and 7.1 GPa, and temperatures ranging between about 1900° C. and about 2300° C.) to also result in high density binderless cBN bodies.', 'Further, sintered binderless cBN bodies formed from boron nitride particle mixtures according to embodiments of the present disclosure may have a Vickers hardness of greater than 30 GPa, greater than 35 GPa, and greater than 38 GPa.', 'As discussed herein, using boron nitride particle mixtures according to embodiments of the present disclosure to form sintered binderless cBN bodies may allow for sintering at relatively lower pressures (and optionally in combination with lower temperatures) when compared with previously used boron nitride starting material.', 'Sintered binderless cBN bodies formed according to embodiments disclosed herein may further have improved material properties, notwithstanding the lower sintering pressure used to form the binderless cBN bodies, due in part to the composition of the starting material and its packing efficiency.', 'For example, reverse phase transformation from cBN to hBN in cBN starting material may be avoided by using starting material and sintering methods according to embodiments of the present disclosure, which may result in sintered binderless cBN bodies having improved hardness (due to reduced presence of hBN in the sintered binderless cBN bodies).', 'FIG.', '2\n shows x-ray diffraction results of sintered binderless cBN bodies sintered from a boron nitride particle mixture according to embodiments of the present disclosure sintered under different temperatures and under a pressure of 7 GPa.', 'The boron nitride particle mixture included a mixture of cBN particles having a particle size ranging between 12 and 22 microns, cBN particles having a particle size ranging from greater than 0 microns to about 2 microns, and hBN particles. \nFIG.', '3\n shows the composition of the sintered binderless cBN bodies resulting from sintering the boron nitride particle mixture at different temperatures, as calculated from the x-ray diffraction measurements.', 'When sintered at 1950° C., the resulting sintered binderless cBN body has about 98.5 percent of its composition cBN, 1.2 percent hBN, and 0.35 percent residual materials.', 'When sintered at 2075° C., the resulting sintered binderless cBN body has about 99 percent of its composition cBN, 0.41 percent hBN, and 0.63 percent residual materials.', 'When sintered at 2175° C., the resulting sintered binderless cBN body has about 99.8 percent of its composition cBN, 0.02 percent hBN, and 0.20 percent residual materials.\n \nFIGS.', '4 and 5\n show x ray diffraction measurements taken for additional examples of sintered binderless cBN bodies sintered from a single coarse cut cBN particle mixture having cBN particles with an average particle size ranging from 12 to 22 microns and a single fine cut cBN particle mixture having cBN particles with an average particle size ranging from greater than 0 to 2 microns under different temperatures.', 'According to one or more embodiments, the results shown in \nFIG.', '4\n include the x-ray diffraction patterns for 1) a sintered binderless cBN body sintered from a single fine cut cBN particle mixture (Mixture A) having fine cBN particles with an average particle size ranging between greater than 0 and 2 microns and 2) a sintered binderless cBN body sintered from a single coarse cut cBN particle mixture (Mixture B) having coarse cBN particles with an average particle size ranging from 12 to 22 microns, where Mixtures A and B were each sintered at 2075° C.', 'The results shown in \nFIG.', '5\n include the x-ray diffraction patterns for Mixtures A and B each sintered at 2370° C.\n \nAs shown in \nFIGS.', '4 and 5\n, peaks in the x-ray diffraction patterns at the angular position 2θ of around 28 to 29 represent presence of hBN.', 'Accordingly, \nFIGS.', '4 and 5\n show that fine cut cBN particles may be densified well and sintered to form binderless cBN bodies having trace amounts of (or no amount of) hBN, whereas when coarse cut cBN particles are densified and sintered to form binderless cBN bodies, hBN is present.', 'Further, as shown in \nFIGS. 4 and 5\n, the intensity of the peak at the angular position 2θ of around 28 to 29 resulting from the binderless cBN body sintered from Mixture B at 2075° C. is greater than the intensity of the peak at the angular position 2θ of around 28 to 29 resulting from the binderless cBN body sintered from Mixture B at 2370° C., thereby indicating that the concentration of the hBN phase in the sintered binderless cBN body sintered from Mixture B at 2075° C. may be greater than the concentration of the hBN phase in the sintered binderless cBN body sintered from Mixture B at 2370° C.', 'According to embodiments of the present disclosure, sintered binderless cBN bodies formed according to methods disclosed herein may have less than 1.5 percent composition hBN, less than 1 percent composition hBN, or less than 0.5 percent composition hBN.', 'For example, according to embodiments of the present disclosure, sintered binderless cBN bodies sintered from a boron nitride particle mixture having a first type of cBN particles (e.g., cBN particles with a particle size between 12 and 22 microns) and less than 50 percent by weight of a boron nitride filler material (e.g., boron nitride particles of a different size and/or type than the first type of cBN particles) under sintering conditions with pressures of ranging between about 6.9 GPa and 7.6 GPa (e.g., about 7 GPa, 7.1 GPa, or 7.2 GPa) and temperatures of about 2000° C. and 2200° C. may have a composition including between 0 and 0.5 percent composition hBN and greater than 99 percent composition cBN.', 'Sintered binderless cBN bodies formed according to methods of the present disclosure may be substantially entirely made of cBN and have both high density and high hardness.', 'For example, in some embodiments, sintered binderless cBN bodies formed according to methods of the present disclosure may include a plurality of bonded together cBN grains, wherein cBN forms at least 98 percent composition of the sintered binderless cBN body, and have a density of at least 99 percent and a Vickers hardness of greater than 38 GPa.', 'In some embodiments, sintered binderless cBN bodies formed according to methods of the present disclosure may have less than 1 percent composition hBN.', 'Further, binderless cBN bodies sintered according to embodiments of the present disclosure may have relatively larger sizes when compared with binderless cBN bodies sintered at pressures of 7.7 GPa or more.', 'For example, in some embodiments, a sintered binderless cBN body may have at least one dimension (e.g., dimensions in an x, y, and/or z direction along an x-y-z-coordinate system) extending a distance of at least 5 mm, at least 10 mm, at least 20 mm or more.', 'In some embodiments, sintered binderless cBN bodies sintered at pressures of less than 7.7 GPa (e.g., in some embodiments, using a sintering pressure of about 7 GPa) may have a volume of at least 300 mm\n3\n, at least 500 mm\n3\n, at least 700 mm\n3\n, or at least 1000 mm\n3\n.', 'As discussed herein, sintered binderless cBN bodies according to embodiments of the present disclosure may be formed to have a density of at least 98 percent using sintering pressures of less than 7.7 GPa.', 'Using relatively lower sintering pressures may further allow for forming sintered binderless cBN bodies to have a relatively larger size when compared with binderless cBN bodies sintered at sintering pressure of about 7.7 GPa or more in addition to having densities of 98 percent or more.', 'Binderless cBN bodies sintered according to embodiments of the present disclosure may be used for cutting or machining tools, and may be sintered to have a shape and size according to the end application.', 'FIG.', '6\n shows an example of a tool with which a sintered binderless cBN body according to embodiments of the present disclosure may be used.', 'The tool is a friction stir welding (FSW) tool \n600\n, which may mechanically join two metallic materials \n602\n, \n604\n, by plastically deforming and mixing the materials being joined at sub-melting temperatures.', 'The FSW tool \n600\n includes a spindle \n630\n, a shoulder \n620\n, and a pin \n610\n extending from the shoulder \n620\n.', 'The pin \n610\n penetrates and “stirs” the materials to be joined.', 'Depending on the depth of penetration, the shoulder \n620\n may also contact and “stir” the materials to be joined.', 'In an embodiment, the FSW tool \n600\n drives the spindle \n630\n to rotate the pin \n610\n about an axis \n640\n.', 'As the pin \n610\n rotates, the pin is moved to contact the materials \n602\n, \n604\n to be joined, e.g., along a joint or interface between the materials \n602\n, \n604\n, or if the materials \n602\n, \n604\n are overlapping, the pin \n610\n may be moved to contact the upper layer of overlapping material and plunged a depth below the interface between the overlapping materials.', 'Frictional heat is generated at the contact area between the rotating pin and the materials \n602\n, \n604\n to be joined.', 'The friction-generated heat heats the materials \n602\n, \n604\n to temperatures high enough to soften and make malleable the materials \n602\n, \n604\n, but less than the melting temperature of the materials \n602\n, \n604\n.', 'As the materials \n602\n, \n604\n soften from the frictional heat, the rotating pin \n610\n may plunge a depth into the materials \n602\n, \n604\n, while the rotating motion of the pin \n610\n mixes the softened materials \n602\n, \n604\n together.', 'The rotating pin \n610\n may extend a depth into the materials \n602\n, \n604\n such that the shoulder \n620\n also contacts and generates frictional heat along the surfaces of the materials \n602\n, \n604\n.', 'As the FSW tool \n600\n travels along the interface between the materials \n602\n, \n604\n, a weld of commingled materials \n602\n, \n604\n is formed.', 'After mixing or stirring the materials \n602\n, \n604\n to join them together, the pin \n610\n may be removed (e.g., the pin may be gradually removed or removed using a sacrificial material along the exiting area of the pin to reduce dimpling).', 'The pin \n610\n may be made of sintered binderless cBN formed according to embodiments of the present disclosure, which may provide the pin with improved wear resistance, while also maintaining strength during increased temperatures resulting from generating the frictional heat during friction stirring operations.', 'Sintered binderless cBN bodies according to embodiments of the present disclosure may also be used to form cutting elements.', 'For example, as shown in \nFIG.', '7\n, a sintered binderless cBN body according to embodiments of the present disclosure may be bonded onto a substrate \n710\n, such as a tungsten carbide or other metallic carbide substrate, to form a cutting layer \n720\n of a cutting element \n700\n.', 'The sintered binderless cBN body may be bonded (e.g., welded or brazed) to the substrate \n710\n after the sintered binderless cBN body has been sintered.', 'Sintered binderless cBN bodies according to embodiments of the present disclosure may be used in other machining and cutting applications, and may be used to form cutting elements or machining components that contact and cut or wear a workpiece.', 'In some machining and/or cutting applications, sintered binderless cBN bodies according to embodiments of the present disclosure may be used to form wear resistant elements or surfaces of a machining or cutting tool, where the wear resistant surface may protect certain areas of the tool from wear during the machining and/or cutting applications.', 'While the present disclosure has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the disclosure as described herein.', 'In addition, aspects of particularly described embodiments may be combined with other embodiments without departing from the scope of the disclosure.'] | ['1.', 'A method of sintering a binderless cubic boron nitride body, comprising:\nproviding a boron nitride particle mixture into a pressure chamber, the boron nitride particle mixture comprising a first type of boron nitride particles and boron nitride filler particles, the first type of boron nitride particles comprising a cubic boron nitride particle mixture having a multi modal particle size distribution, the boron nitride filler particles comprising hexagonal boron nitride particles; and\nsintering the boron nitride particle mixture in the pressure chamber to form the binderless cubic boron nitride body, the sintering comprising: generating a pressure in the pressure chamber of less than 7.7 GPa; and heating the boron nitride particle mixture to a temperature ranging from 1900° C. to 2300° C.,\nwherein the binderless cubic boron nitride body has a density of at least 97 percent.', '2.', 'The method of claim 1, wherein the cubic boron nitride particle mixture comprises coarse cubic boron nitride particles having a particle size ranging from 12 to 22 microns.', '3.', 'The method of claim 1, wherein the cubic boron nitride particle mixture comprises fine cubic boron nitride particles having an average particle size less than the first type of boron nitride particles.', '4.', 'The method of claim 3, wherein the fine cubic boron nitride particles have a particle size of 2 microns or less.', '5.', 'The method of claim 3, wherein the fine cubic boron nitride particles form between 10 to 20 weight percent of the boron nitride particle mixture.', '6.', 'The method of claim 1, wherein the hexagonal boron nitride particles form between 5 to 20 weight percent of the boron nitride particle mixture.', '7.', 'The method of claim 1, further comprising vibrating the boron nitride particle mixture in the pressure chamber prior to sintering.\n\n\n\n\n\n\n8.', 'The method of claim 1, further comprising cold isostatic pressing the boron nitride particle mixture prior to sintering.\n\n\n\n\n\n\n9.', 'The method of claim 1, wherein the boron nitride filler particles form less than 50 percent by weight of the boron nitride particle mixture.', '10.', 'The method of claim 1, wherein the cubic binderless boron nitride body has a Vickers hardness of greater than 30 GPa.', '11.', 'The method of claim 1, wherein the cubic binderless boron nitride body has less than 1 percent composition hexagonal boron nitride.', '12.', 'A method of making a binderless cubic boron nitride body, comprising:\nproviding a boron nitride particle mixture into a pressure chamber, the boron particle mixture comprising hexagonal boron nitride particles and a cubic boron nitride particle mixture having a multi modal particle size distribution;\ngenerating a pressure in the pressure chamber ranging from 7 GPa to less than 7.7 GPa; and\nheating the pressure chamber to a temperature ranging from 1900° C. to 2300° C.,\nwherein the binderless cubic boron nitride body has at least 98 percent composition cubic boron nitride.', '13.', 'The method of claim 12, wherein the binderless cubic boron nitride body has a Vickers hardness of greater than 38 GPa.', '14.', 'The method of claim 12, wherein a change in volume from the boron nitride particle mixture volume in the pressure chamber to the binderless sintered cubic boron nitride body volume is less than 25 percent.', '15.', 'The method of claim 14, further comprising cold isostatic pressing the boron nitride particle mixture prior to generating the pressure and heating.'] | ['FIG.', '1 is a graph of the theoretical densities of binderless cBN bodies sintered from boron nitride particle mixtures according to embodiments of the present disclosure and from a conventional boron nitride particle mixture.; FIG.', '2 shows an x-ray diffraction spectrum of sintered binderless cBN bodies sintered from a boron nitride particle mixture according to embodiments of the present disclosure under different temperatures.; FIG.', '3 shows a table of the compositions of the sintered binderless cBN bodies of FIG.', '2.; FIG.', '4 shows an x-ray diffraction spectrum for comparative samples of sintered binderless cBN bodies.; FIG.', '5 shows an x-ray diffraction spectrum for comparative samples of sintered binderless cBN bodies.; FIG.', '6 shows a tool having a sintered binderless cBN material according to embodiments of the present disclosure.;', 'FIG. 7 shows a cutting element having a sintered binderless cBN material according to embodiments of the present disclosure.; FIG.', '1 shows an example of the theoretical densities of binderless cBN bodies sintered from different boron nitride particle mixtures at 7 GPa and different temperatures.', 'The tested boron nitride particle mixtures include a conventional single cut cBN particle mixture, shown as boron nitride particle mixture A, and boron nitride particle mixtures according to embodiments of the present disclosure, shown as boron nitride particle mixtures B and C. Boron nitride particle mixture A includes a single cut of cBN particles having a normal distribution, where the cBN particles have a particle size ranging from 12 to 22 microns.', 'According to an embodiment, boron nitride particle mixture B includes a mixture with 85 percent by weight of cBN particles with a particle size ranging from 12 to 22 microns and 15 percent by weight of cBN particles with a particle size ranging from greater than 0 to 2 microns.', 'According to an embodiment, boron nitride particle mixture C includes a mixture with 85 percent by weight of the boron nitride particle mixture B and 15 percent by weight of hBN particles.', 'As such, boron nitride particle mixture C may include a mixture with about 72 percent by weight of cBN particles with a particle size ranging from 12 to 22 microns, about 13 percent by weight of cBN particles with a particle size ranging from greater than 0 to 2 microns, and about 15 percent by weight of hBN particles.', '; FIG.', '1 shows selected examples of boron nitride particle mixtures according to embodiments of the present disclosure sintered under 7 GPa and temperatures ranging between 1900° C. and 2300°', 'C. However, other boron nitride particle mixtures according to embodiments of the present disclosure may be sintered under similar conditions (e.g., pressures of less than 7.7 GPa, less than 7.5 GPa, or less than 7.2 GPa, such as between 6.9 GPa and 7.1 GPa, and temperatures ranging between about 1900° C. and about 2300° C.) to also result in high density binderless cBN bodies.; FIG.', '2 shows x-ray diffraction results of sintered binderless cBN bodies sintered from a boron nitride particle mixture according to embodiments of the present disclosure sintered under different temperatures and under a pressure of 7 GPa.', 'The boron nitride particle mixture included a mixture of cBN particles having a particle size ranging between 12 and 22 microns, cBN particles having a particle size ranging from greater than 0 microns to about 2 microns, and hBN particles.', 'FIG.', '3 shows the composition of the sintered binderless cBN bodies resulting from sintering the boron nitride particle mixture at different temperatures, as calculated from the x-ray diffraction measurements.', 'When sintered at 1950° C., the resulting sintered binderless cBN body has about 98.5 percent of its composition cBN, 1.2 percent hBN, and 0.35 percent residual materials.', 'When sintered at 2075° C., the resulting sintered binderless cBN body has about 99 percent of its composition cBN, 0.41 percent hBN, and 0.63 percent residual materials.', 'When sintered at 2175° C., the resulting sintered binderless cBN body has about 99.8 percent of its composition cBN, 0.02 percent hBN, and 0.20 percent residual materials.; FIGS. 4 and 5 show x ray diffraction measurements taken for additional examples of sintered binderless cBN bodies sintered from a single coarse cut cBN particle mixture having cBN particles with an average particle size ranging from 12 to 22 microns and a single fine cut cBN particle mixture having cBN particles with an average particle size ranging from greater than 0 to 2 microns under different temperatures.', 'According to one or more embodiments, the results shown in FIG.', '4 include the x-ray diffraction patterns for 1) a sintered binderless cBN body sintered from a single fine cut cBN particle mixture (Mixture A) having fine cBN particles with an average particle size ranging between greater than 0 and 2 microns and 2) a sintered binderless cBN body sintered from a single coarse cut cBN particle mixture (Mixture B) having coarse cBN particles with an average particle size ranging from 12 to 22 microns, where Mixtures A and B were each sintered at 2075° C.', 'The results shown in FIG.', '5 include the x-ray diffraction patterns for Mixtures A and B each sintered at 2370° C.; FIG.', '6 shows an example of a tool with which a sintered binderless cBN body according to embodiments of the present disclosure may be used.', 'The tool is a friction stir welding (FSW) tool 600, which may mechanically join two metallic materials 602, 604, by plastically deforming and mixing the materials being joined at sub-melting temperatures.', 'The FSW tool 600 includes a spindle 630, a shoulder 620, and a pin 610 extending from the shoulder 620.', 'The pin 610 penetrates and “stirs” the materials to be joined.', 'Depending on the depth of penetration, the shoulder 620 may also contact and “stir” the materials to be joined.'] |
|
US11072983 | Systems and methods for holding wireline device against well | Nov 11, 2019 | Joseph Varkey, Maria Grisanti, Paul Wanjau, David Kim, William Brian Underhill | SCHLUMBERGER TECHNOLOGY CORPORATION | Office Action issued in U.S. Appl. No. 16/587,098, dated Dec. 24, 2020 (17 pages). | 3233170; February 1966; Rogers; 4438810; March 27, 1984; Wilkinson; 4515010; May 7, 1985; Weido; 4953136; August 28, 1990; Kamata et al.; 5259452; November 9, 1993; Wittrisch; 6006855; December 28, 1999; Howlett; 6026911; February 22, 2000; Angle; 7187620; March 6, 2007; Nutt et al.; 7721809; May 25, 2010; Minto; 7894297; February 22, 2011; Nutt et al.; 9170149; October 27, 2015; Hartog et al.; 9217320; December 22, 2015; Odashima et al.; 20140191762; July 10, 2014; Chen et al.; 20160215579; July 28, 2016; Van Der Ende; 20170285208; October 5, 2017; Castillo; 20180179840; June 28, 2018; Varkey et al.; 20200110235; April 9, 2020; Maida | Foreign Citations not found. | ['A system includes a cable and a toolstring.', 'The toolstring may couple to the cable to enable the toolstring to be placed in a wellbore.', 'The toolstring includes a sensor that can collect measurements relating to the wellbore.', 'An electromagnetic or anchoring device may selectively hold the toolstring or the cable against a surface of the wellbore.'] | ['Description\n\n\n\n\n\n\nBACKGROUND\n \nThis disclosure relates to systems and methods to hold a downhole device (e.g., a cable or toolstring) against a wellbore wall, which may improve a signal to noise ratio of wellbore measurements.', 'This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below.', 'This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure.', 'Accordingly, these statements are to be read in this light, and not as admissions of any kind.', 'To locate and extract resources from a well, a wellbore may be drilled into a geological formation.', 'Some wellbores may change direction at some point downhole.', 'The change in direction may be at an angle as high as ninety degrees with respect to the surface, causing the wellbore to become horizontal.', 'Downhole toolstrings and sensors are placed into the wellbore to identify properties of the downhole environment.', 'In vertical portions of the wellbore, the downhole toolstrings and sensors may descend into the wellbore using only the force of gravity.', 'However, the downhole toolstrings and sensors may descend into angled portions of the well through the use of additional forces other than gravity.', 'As the wellbore approaches a more horizontal angle, the additional forces play a greater role in propelling the downhole toolstrings and sensors deeper into the wellbore.', 'Once the downhole toolstrings and sensors reach the desired location within the wellbore, the sensors are used to gather data about the geological formation.', 'However, this movement of the toolstrings and sensors may worsen the signal to noise ratio, which could lead to less accurate measurements.', 'SUMMARY\n \nA summary of certain embodiments disclosed herein is set forth below.', 'It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.', 'Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.', 'In one example, a system includes a cable, a toolstring, and a device.', 'The toolstring may couple to the cable to enable the toolstring to be placed in a wellbore.', 'Further, the toolstring includes sensors configured to collect data of a geological formation.', 'The device may selectively hold the toolstring against a surface of the wellbore.', 'In another example, a cable system includes a cable core that includes fiber optic cables, multiple strength members outside of the cable core, and multiple magnetic strength members outside of the cable core.', 'The multiple magnetic strength members may selectively carry current, and the multiple magnetic strength members may become magnetic or activate an electromagnet electrically coupled to the multiple magnetic strength members when the multiple magnetic strength members carry current.', 'In yet another example, a method for improving the signal to noise ratio, includes lowering a cable and a toolstring into a wellbore.', 'The method includes extending at least one arm of a tractor device coupled to the toolstring, and the at least one arm includes a wheel.', 'The method includes engaging the wheel of the tractor device against a surface of the wellbore, and engaging the wheel of the tractor device propels the toolstring and the cable into the wellbore.', 'The method includes retracting the at least one arm of the tractor device, and retracting the at least one arm disengages the wheel from the surface of the wellbore.', 'The method includes attaching the toolstring to the surface of the wellbore using a device coupled to the toolstring.', 'Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure.', 'Further features may also be incorporated in these various aspects as well.', 'These refinements and additional features may exist individually or in any combination.', 'For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination.', 'The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nVarious aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:\n \nFIG.', '1\n is a schematic diagram of a wireline system that includes a toolstring to detect properties of a wellbore or geological formation adjacent to the toolstring, in accordance with an aspect of the present disclosure;\n \nFIGS.', '2A and 2B\n are cross sections of different embodiments of a cable that can be magnetized, in accordance with an aspect of the present disclosure;\n \nFIG.', '3A\n is a side view of an embodiment of a toolstring with the arms of a tractor device extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '3B\n is a side view of the toolstring of \nFIG.', '3A\n in a wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '3C\n is a side view of the toolstring of \nFIG.', '3A\n with the cable magnetized and the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;\n \nFIG.', '3D\n is a side view of the toolstring of \nFIG.', '3C\n in a wellbore and with the cable magnetized and held to the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '4\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '5A\n is a side view of an embodiment of a toolstring including a timer-activated magnetic device with the arms of the tractor device extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '5B\n is a side view of the toolstring of \nFIG.', '5A\n in a wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '5C\n is a side view of the toolstring of \nFIG.', '5A\n with the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;\n \nFIG.', '5D\n is a side view of the toolstring of \nFIG.', '5C\n in a wellbore and with the selectively magnetic device holding the toolstring to the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '5E\n is a side view of the toolstring of \nFIG.', '5D\n, with an additional toolstring mounted on the cable, in accordance with an aspect of the present disclosure;\n \nFIG.', '6\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure;\n \nFIGS.', '7A-7B\n are cross sections of different embodiments of the cable with a magnetic device coupled to the cable, in accordance with an aspect of the present disclosure;\n \nFIG.', '8A\n is a side view of an embodiment of the magnetic device, in accordance with an aspect of the present disclosure;\n \nFIG.', '8B\n is a side view of multiple magnetic devices of \nFIG.', '8A\n in a wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '8C\n is a side view of the magnetic devices of \nFIG.', '8B\n attached to the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '9A\n is a side view of an embodiment of the toolstring including an anchoring device and a tractor device and the arms of the tractor device are extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '9B\n is a side view of the toolstring of \nFIG.', '9A\n and the side-arm of the anchoring device extended, in accordance with an aspect of the present disclosure;\n \nFIG.', '9C\n is a side view of multiple toolstring of \nFIG.', '9B\n with the arms of the tractor devices retracted and the side-arms of the anchoring devices extended and holding the toolstrings against the casing of the wellbore, in accordance with an aspect of the present disclosure;\n \nFIG.', '10\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using an anchoring device, in accordance with an aspect of the present disclosure;\n \nFIG.', '11A\n is a side view of the toolstring of \nFIG.', '9A\n where the anchoring device is activated by a timer device, in accordance with an aspect of the present disclosure;\n \nFIG.', '11B\n is a side view of the toolstring of \nFIG.', '11B\n in a wellbore and with the arms of the tractor device extended, in accordance with an aspect of the present disclosure; and\n \nFIG.', '12\n is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure.', 'DETAILED DESCRIPTION', 'One or more specific embodiments of the present disclosure will be described below.', 'These described embodiments are only examples of the presently disclosed techniques.', 'Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification.', "It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another.", 'Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.', 'When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements.', 'The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.', 'Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.', 'The present disclosure relates to devices that improve the signal to noise ratio of sensors in a wellbore.', 'Toolstrings containing sensors may be placed into the wellbore to gather information about the geological formation.', 'In some portions of the wellbore, the tool may require forces in addition to gravity to descend farther into the well.', 'Once the tool has reached the desired location in the wellbore, the sensors may gather data about the geological formation.', 'When the sensors are gathering data, movement of the sensors may worsen the signal to noise ratio.', 'Therefore, it is desirable to keep the sensors as steady as is possible when the sensors are gathering data.', 'Accordingly, embodiments of this disclosure relate to a system and method for propelling the toolstring farther into the wellbore and for holding the toolstring in a steady position once the toolstring has reached the desired location.', 'That is, some embodiments include a tractor device that includes extendable arms.', 'The arms include drive wheels that may engage the surface of the casing of the wellbore and propel the toolstring farther into the wellbore.', 'Some embodiments include a device that may hold the toolstring steady at the desired location in the wellbore.', 'The device may include components within a cable that can be selectively magnetized.', 'When the components are activated and the components becomes magnetized, the cable may attach to the casing of the wellbore.', 'Attaching the cable to the casing of the wellbore may hold the toolstring steady in place.', 'Alternatively, the device may include components within the toolstring that can be selectively magnetized.', 'When the components are activated and the components become magnetized, the toolstring may attach and hold steady against the casing of the wellbore.', 'Alternatively, the device may include components that mechanically hold the toolstring against the casing of the wellbore.', 'The components may include an arm that braces the toolstring against the casing of the wellbore.', 'Further, the device may include multiple devices spread out along the cable.', 'With this in mind, \nFIG.', '1\n illustrates a well-logging system \n10\n that may employ the systems and methods of this disclosure.', 'The well-logging system \n10\n may be used to convey a toolstring \n12\n through a geological formation \n14\n via a wellbore \n16\n.', 'Further, the wellbore \n16\n may not continue straight down into the geological formation \n14\n, and the wellbore \n16\n may contain a turn \n13\n.', 'The wellbore \n16\n may continue past the turn into the geological formation \n14\n at an angle as high as ninety degrees.', 'In the example of \nFIG.', '1\n, the toolstring \n12\n is conveyed on a cable \n18\n via a logging winch system (e.g., vehicle) \n20\n.', 'Although the logging winch system \n20\n is schematically shown in \nFIG.', '1\n as a mobile logging winch system carried by a truck, the logging winch system \n20\n may be substantially fixed (e.g., a long-term installation that is substantially permanent or modular).', 'Any suitable cable \n18\n for well logging may be used.', 'The cable \n18\n may be spooled and unspooled on a drum \n22\n and an auxiliary power source \n24\n may provide energy to the logging winch system \n20\n, the cable \n18\n, and/or the toolstring \n12\n.', 'Moreover, while the toolstring \n12\n is described as a wireline toolstring, it should be appreciated that any suitable conveyance may be used.', 'For example, the toolstring \n12\n may instead be conveyed as a logging-while-drilling (LWD) tool as part of a bottom hole assembly (BHA) of a drill string, conveyed on a slickline or via coiled tubing, and so forth.', 'For the purposes of this disclosure, the toolstring \n12\n may include any suitable measurement tool that uses a sensor to obtain measurements of properties of the geological formation \n14\n.', 'The toolstring \n12\n may use any suitable sensors to obtain any suitable measurement, including resistivity measurements, electromagnetic measurements, radiation-based (e.g., neutron, gamma-ray, or x-ray) measurements, acoustic measurements, and so forth.', 'In general, the toolstring \n12\n may obtain better measurements, having a higher signal-to-noise ration, when the toolstring \n12\n is pressed against the wellbore \n16\n wall.', 'In some cases, the toolstring \n12\n may use fiber optic sensors that obtain wellbore measurements that are greatly improved when the toolstring \n12\n is pressed against the wellbore \n16\n wall.', 'Furthermore, when the cable \n18\n includes fiber optic cables, the signal that is transported over the fiber optic cables may be improved when the cable is generally held taut (rather than, for example, including many turns or kinks that could degrade the signal traveling over the fiber optic cable).', 'The toolstring \n12\n may emit energy into the geological formation \n14\n, which may enable measurements to be obtained by the toolstring \n12\n as data \n26\n relating to the wellbore \n16\n and/or the geological formation \n14\n.', 'When collecting the data \n26\n, it is desirable to keep the toolstring \n12\n as steady as possible in order to improve the signal to noise ratio.', 'Improving the signal to noise ratio allows for more accurate readings.', 'The data \n26\n may be sent to a data processing system \n28\n.', 'For example, the data processing system \n28\n may include a processor \n30\n, which may execute instructions stored in memory \n32\n and/or storage \n34\n.', 'As such, the memory \n32\n and/or the storage \n34\n of the data processing system \n28\n may be any suitable article of manufacture that can store the instructions.', 'The memory \n32\n and/or the storage \n34\n may be read-only memory (ROM), random-access memory (RAM), flash memory, an optical storage medium, or a hard disk drive, to name a few examples.', 'A display \n36\n, which may be any suitable electronic display, may display the images generated by the processor \n30\n.', 'The data processing system \n28\n may be a local component of the logging winch system \n20\n (e.g., within the toolstring \n12\n), a remote device that analyzes data from other logging winch systems \n20\n, a device located proximate to the drilling operation, or any combination thereof.', 'In some embodiments, the data processing system \n28\n may be a mobile computing device (e.g., tablet, smart phone, or laptop) or a server remote from the logging winch system \n20\n.', 'FIG.', '2A\n depicts an embodiment of a cross-section of a cable \n18\nA.', 'The present embodiment of the cable \n18\nA allows the cable \n18\nA to magnetically attach to the casing \n40\n of the wellbore \n16\n.', 'In doing so, the cable \n18\nA holds the toolstring \n12\n in substantially the same place.', 'In \nFIG.', '2A\n, the cable \n18\nA is designed to function as an electromagnet.', 'The cable \n18\nA includes three different sections, a cable core \n70\n, strength members \n74\n, and magnetic strength members \n72\n.', 'The cable core \n70\n may include fiber optic cables \n81\n and conductors \n85\n.', 'The fiber optic cables \n81\n may include different configurations.', 'For example, the fiber optic cable \n81\n may include an optical core \n78\n and an insulating coating \n80\n followed by a second insulating coating \n76\n.', 'Alternatively, the second insulating coating \n76\n may be replaced by spacers \n84\n followed by an insulating layer \n82\n.', 'While the present embodiment includes three optical cores \n78\n per fiber optic cable \n81\n, it should be appreciated that each fiber optic cable \n81\n may include any suitable number of optical cores, including 1, 2, 3, 4, 5, or 6, or more.', 'The conductors \n85\n include conducting elements \n88\n surrounded by an insulating material \n86\n.', 'Further, the cable core \n70\n may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'The magnetic strength members \n72\n include the strength member \n74\n followed by a layer of insulated strength members/conductors \n75\n (e.g., using bimetallic materials) followed by a layer of durable polymeric electrical insulation \n73\n.', 'In the present embodiment, the magnetic strength members \n72\n are disposed farther from the cable core \n70\n than the strength members \n74\n; however, it should be appreciated that the magnetic strength members \n72\n may be disposed closer to the cable core \n70\n than strength members \n74\n.', 'Additionally or alternatively, the magnetic strength members \n72\n may be disposed in a mixed configuration with the strength member \n74\n, with some magnetic strength members \n72\n farther from the cable core \n70\n and some closer to the cable core \n70\n than the strength members \n74\n.', 'Each of the strength members \n74\n or a portion of the strength members \n74\n in the armor matrix can be magnetic strength members \n72\n.', 'The quantity, material, size and lay angles of the magnetic strength members \n72\n combined with the electrical current applied can be altered to create an electromagnet of sufficient strength to hold the cable \n18\nA in place against the casing \n40\n of the wellbore \n16\n.', 'Surface and downhole electronics may be configured to turn the magnetic strength members \n72\n on and off.', 'In the “Off” mode, return current is carried by the strength members \n74\n.', 'In the “On” position, current is returned on the magnetic strength members \n72\n and cause the magnetic strength member \n72\n to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', 'A hybrid conductor is a cable that contains multiple strands wrapped around one another, and the strands may be composed of multiple types of metals (e.g., steel, bimetallic, etc.).', 'FIG.', '2B\n depicts a cross-section of an alternative embodiment of the cable \n18\n.', 'A cable \n18\nB is designed to function as an electromagnet, and the cable \n18\nB includes a cable core \n90\n, strength members \n92\n, and magnetic strength members \n94\n.', 'The strength members \n92\n may be magnetic strength members \n94\n.', 'The cable core \n90\n includes fiber optic cables \n81\n, conductors \n85\n, and wires \n98\n.', 'The fiber optic cables \n81\n include the optical cores \n78\n followed by the insulating coating \n80\n.', 'The conductors \n85\n include conducting elements \n88\n surrounded by an insulating material \n86\n.', 'The cable core \n90\n may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'All the strength members \n92\n or a portion of the strength members \n92\n may be replaced with magnetic strength members \n94\n (e.g. bi-metallic) in order to balance the cable \n18\nB safe working load and magnetic anchoring force.', 'The material, quantity, size and lay angles of magnetic strength members \n94\n and the electrical current applied may be configured to create an electromagnet of sufficient strength to hold the cable \n18\nB in place against the casing \n40\n of the wellbore \n16\n.', 'Strength member \n92\n and magnetic strength members \n94\n may be held in place by a filler material \n96\n.', 'The filler material may include insulating elements.', 'Surface and downhole electronics are configured to turn the electromagnet on and off.', 'In the “Off” mode, return current is carried by conductors in the cable core \n90\n.', 'In the “On” position, current is returned on the magnetic strength members \n94\n causing the magnetic strength members \n94\n to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', 'FIG.', '3A\n is a side view of an embodiment of a toolstring \n12\nA attached to the cable \n18\n.', 'The cable \n18\n may be either embodiment depicted in \nFIGS.', '2A and 2B\n.', 'In the present embodiment, the toolstring \n12\nA includes a tractor device \n122\n.', 'The tractor device \n122\n includes arms \n124\n, and each arm \n124\n includes a drive wheel \n126\n.', 'The tractor device \n122\n may include any suitable number of arms \n124\n, including 1, 2, 3, 4, 5, 6, or more.', 'In operation, the cable \n18\n and the toolstring \n12\nA are lowered into the wellbore \n16\n on the cable \n18\n, initially by gravity.', 'The tractor device \n122\n attached to the toolstring \n12\nA is used to continue propelling the toolstring \n12\nA into the hole of the wellbore \n16\n in substantially horizontal (i.e., greater than sixty degrees with respect to the surface of the ground) portions of the wellbore \n16\n.', 'As depicted in \nFIG.', '3B\n, the tractor device \n122\n uses drive wheels \n126\n on arms \n124\n that extend from the toolstring \n12\nA to propel the toolstring \n12\nA down the casing \n40\n of the wellbore \n16\n.', 'FIGS.', '3C and 3D\n are side views of the toolstring \n12\nA with the arms \n124\n of the tractor device \n122\n retracted and the cable \n18\n in the “On” position.', 'Once the cable \n18\n and toolstring \n12\nA are in the desired location, the arms \n124\n on the tractor device \n122\n are withdrawn and the cable \n18\n is turned to the “On” position.', 'The return current is switched to the magnetic strength members \n72\n or \n94\n.', 'Applying electrical current to the magnetic strength members \n72\n or \n94\n allows the cable \n18\n to function as an electromagnet.', 'The strength of the electromagnet may be adjusted by changing amount of current applied or by adjusting the material, quantity, diameters and lay angles of the insulated strength member/conductors.', 'Further, the magnetic strength members \n72\n and \n94\n may be included on a portion of the cable \n18\n.', 'For example, the magnetic strength members \n72\n and \n94\n may be included on a portion of the cable \n18\n near the toolstring \n12\n.\n \nFIG.', '4\n illustrates a flowchart of a method \n130\n for improving the signal to noise ratio.', 'The method \n130\n includes lowering (block \n132\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n130\n includes extending (block \n134\n) the arms \n124\n of the tractor device \n122\n.', 'The method \n130\n includes engaging (block \n136\n) the drive wheels \n126\n of the tractor device \n122\n.', 'The drive wheels \n126\n may be engaged against a surface of the wellbore \n16\n, thereby propelling the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n130\n includes retracting (block \n138\n)', 'the arms \n124\n of the tractor device \n122\n.', 'The method \n130\n includes applying (block \n140\n) current to the magnetic strength members \n72\n or \n94\n of the cable \n18\n.', 'As previously discussed, applying current to the magnetic strength members \n72\n or \n94\n allows the cable \n18\n to function as an electromagnet.', 'The cable \n18\n may then be pulled taught to keep the cable \n18\n steady while the fiber optic cables transmit data.', 'The cable \n18\n being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', 'FIG.', '5A\n is a side view of an embodiment of a toolstring \n12\nB including a timer-activated magnetic device \n170\n with the arms \n164\n of the tractor device \n162\n extended.', 'The timer-activated magnetic device \n170\n is powered by a battery \n174\n and the timer-activated device \n170\n is located in the toolstring \n12', 'B. Before running the toolstring \n12\nB and cable \n18\n into the wellbore \n16\n, the timer \n172\n is set to activate after allowing sufficient time for the cable \n18\n to run into the wellbore \n16\n to the desired location.', 'The cable \n18\n and the toolstring \n12\n are lowered into the wellbore \n16\n on the cable \n18\n, initially by gravity.', 'A tractor device \n162\n attached to the toolstring \n12\n is used to continue running the toolstring \n12\n into the wellbore \n16\n in substantially horizontal portions of the wellbore \n16\n.', 'The current returned through the armor can be used to store energy in the battery \n174\n and extend the magnetic anchoring period.', 'As depicted in \nFIG.', '5B\n, the tractor device \n162\n uses drive wheels \n166\n on arms \n164\n that extend from the toolstring \n12\nB to propel the toolstring \n12\nB down the casing \n40\n of the wellbore \n16\n.\n \nFIGS.', '5C and 5D\n are side views of the toolstring \n12\nB with the arms \n164\n of the tractor device \n162\n retracted.', 'Once the timer \n172\n reaches the end of its time, the timer \n172\n activates a switch \n176\n of the timer-activated magnetic device \n170\n (which will allow time for the toolstring \n12\nB to arrive at the desired downhole location).', 'Activating the switch \n176\n supplies power from the battery \n174\n to the electromagnet \n178\n.', 'Activating the switch \n176\n also causes the drive wheels \n166\n of the tractor device \n162\n to retract into the toolstring \n12\nB.', 'The electromagnet \n178\n holds the toolstring \n12\nB in place against the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n can then be tightened to hold it taut against the casing \n40\n of the wellbore \n16\n, allowing the fiber optics of the cable \n18\n to transmit a strong and consistent signal from downhole formations.', 'FIG.', '5E\n is a side view of the toolstring \n12\nB of \nFIG.', '5D\n, with a second timer-activated magnetic device \n170\n mounted on the cable \n18\n.', 'Multiple timer-activated magnetic devices \n170\n may be located at any suitable location along the length of the cable \n18\n.', 'FIG.', '6\n illustrates a flowchart of a method \n400\n for improving the signal to noise ratio.', 'The method \n400\n includes setting (block \n402\n) the timer \n172\n of the timer-activated magnetic device \n170\n.', 'The method \n400\n includes lowering (block \n404\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n400\n includes extending (block \n406\n) the arms \n164\n of the tractor device \n162\n.', 'The method \n400\n includes engaging (block \n408\n) the drive wheels \n166\n of the tractor device \n162\n.', 'The drive wheels \n166\n may engage a surface of the wellbore \n16\n, thereby driving the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n400\n includes activating (block \n410\n) the switch \n176\n of the timer-activated magnetic device \n170\n.', 'The method \n400\n includes retracting (block \n412\n) the arms \n164\n of the tractor device \n162\n.', 'The method \n400\n includes supplying (block \n414\n) power to the electromagnet \n178\n.', 'In the present embodiment, the power is supplied by a battery \n174\n, but the power may be supplied from other structure, including the cable \n18\n.', 'Supplying power to the electromagnet \n178\n causes the electromagnet \n178\n to attach to the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n may then be pulled taught to keep the cable \n18\n steady while the fiber optic cables transmit data.', 'The cable \n18\n being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', 'FIG.', '7A\n is a cross section of an embodiment of a cable \n18\nC with a magnetic device \n210\nA coupled to the cable \n18\nC.', 'The magnetic device \n210\nA is installed as needed along the cable \n18\nC and is powered by insulated magnetic strength members \n220\n.', 'Insulated magnetic strength members \n220\n include insulation \n222\n (e.g., durable polymetric electrical insulation).', 'A number of strength members \n224\n are replaced by insulated magnetic strength members \n220\n.', 'Insulated magnetic strength members \n220\n can be made out of bimetallic material or any suitable magnetic material.', 'A separate insulated magnetic strength member \n220\n may be used for each magnetic device \n210\nA so that each magnetic device \n210\nA may be operated independently.', 'The magnetic device \n210\nA is installed over the cable \n18\nC in two halves that come together and are held together by a magnetic device casing \n234\n to form a cylinder.', 'The cable \n18\nC includes a cable core \n236\n, strength members \n224\n, and insulated magnetic strength members \n220\n.', 'The cable core \n236\n may include fiber optic cables \n81\n and conductors \n85\n.', 'The fiber optic cables \n81\n may include an optical core \n78\n and an insulating coating \n80\n followed by a second insulating coating \n226\n and an outer insulating layer \n240\n.', 'One side of the cylinder contains an electromagnet \n230\n.', 'The electromagnet \n230\n is a semi-circular-profile iron bar wrapped tightly in insulated copper wire.', 'Non-conductive spacers \n232\n hold the electromagnet \n230\n in place within the gap between the magnetic device casing \n234\n and the cable \n18\nC. One end of an insulated conductive wire \n228\n is attached to the insulated magnetic strength member \n220\n, and the other end is attached to the electromagnet \n230\n.', 'Sufficient slack is allowed in the insulated conductive wires \n228\n to enable the connections to insulated magnetic strength members \n220\n that tend to rotate under longitudinal stress.', 'When current is applied to the insulated magnetic strength members \n220\n, the electromagnet \n230\n is activated and attaches the magnetic device \n210\nA to the casing \n40\n of the wellbore \n16\n.', 'FIG.', '7B\n is a cross section of an embodiment of a cable \n18\nD with a magnetic device \n210\nB coupled to the cable \n18\nD. The cable \n18\nD includes the cable core \n90\n, insulated magnetic strength members \n270\n, strength members \n280\n, and a filler material \n272\n (e.g., an insulating material).', 'The magnetic device \n210\nB is installed along the cable \n18\nD and powered by insulated magnetic strength members \n270\n.', 'A number of strength members \n280\n (e.g., standard armor wire) are replaced by the insulated magnetic strength members \n270\n.', 'The insulated magnetic strength members \n270\n may be made out of bimetallic material or any suitable magnetic material to increase the force of attraction between magnetic device \n210\nB and casing \n40\n of the wellbore \n16\n.', 'The magnetic device \n210\nB is installed over the cable \n18\nD in two halves that come together to form a cylinder.', 'One side contains an electromagnet \n276\n.', 'Spacers \n278\n hold the electromagnet \n276\n in place on the cable \n18\nD. When current is applied to the insulated magnetic strength members \n270\n, the electromagnet \n276\n is activated and attaches the magnetic device \n210\nB to the casing \n40\n of the wellbore \n16\n.', 'FIGS.', '8A and 8B\n are a side view of the magnetic device \n210\n.', 'The magnetic device \n210\n may include either the magnetic device \n210\nA or \n210\nB.', 'As shown in \nFIG.', '8B\n, the cable \n18\n may include multiple magnetic devices \n210\n.', 'The magnetic devices \n210\n may be spread along the cable \n18\n at any distance as is desired.', 'FIG.', '8C\n is a side view of the magnetic devices \n210\n attached to the casing \n40\n of the wellbore \n16\n.', 'Once the magnetic device \n210\n has advanced to the desired location in the well, current is applied as described above to activate the electromagnet \n230\n or \n276\n.', 'The magnetic device \n210\n attaches magnetically to the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n is pulled taut and any other magnetic devices \n210\n are also activated to hold the cable \n18\n against the casing \n40\n of the wellbore \n16\n.', 'The cable \n18\n can then be tightened to hold it taut against the casing \n40\n of the wellbore \n16\n, thereby allowing the fiber optics of the cable to receive a strong and consistent signal from downhole formations.', 'Pressing the cable \n18\n against the casing \n40\n of the wellbore \n16\n may also press the toolstring \n12\n against the casing \n40\n.', 'FIG.', '9A\n is a side view of an embodiment of a toolstring \n12\nC including an anchoring device \n310\n and a tractor device \n290\n and the arms \n292\n of the tractor device \n290\n are extended.', 'The present embodiment includes two toolstrings \n12\nC, and only one of the toolstrings includes the tractor device \n290\n.', 'The cable \n18\n and the toolstring \n12\nC are lowered into the wellbore \n16\n, initially by gravity.', 'The tractor device \n290\n of the toolstring \n12\nC is used to continue running the toolstring \n12\nC into the wellbore \n16\n in substantially horizontal portions of the well.', 'Once the toolstring \n12\nC is at the desired location, the drive wheels \n294\n of the tractor device \n290\n retract.', 'FIG.', '9B\n is a side view of the toolstring \n12\nC with the anchoring device \n310\n activated.', 'FIG.', '9C\n is a side view of two toolstrings \n12\nC, both with the anchoring device \n310\n activated.', 'The anchoring devices \n310\n in the toolstring \n12\nC are activated by telemetry signals sent through the cable \n18\n from the surface.', 'The telemetry signals cause a switch \n318\n to either engage or disengage.', 'The telemetry signals cause the switch \n318\n to engage once the toolstring \n12\nC has reached the desired location in the wellbore \n16\n.', 'However, while the switch \n318\n is engaged or disengaged by telemetry signals in the present embodiment, it should be noted that the switch \n318\n may be engaged or disengaged by a program designed to engage the switch \n318\n after a sufficient amount of time has passed.', 'The anchoring devices \n310\n have a single side-arm \n312\n that deploys in direction \n314\n to anchor the toolstrings \n12\nC and the cable \n18\n to the casing \n40\n of the wellbore \n16\n when the switch \n318\n is engaged.', 'The side-arm \n312\n of the anchoring device \n310\n swings outward about a hinge \n320\n in the direction \n314\n to wedge the toolstring \n12\nC in place against the casing \n40\n of the wellbore.', 'In the present embodiment, the anchoring device \n310\n is powered by a battery \n316\n; however, it should be appreciated that the anchoring device \n310\n may also be powered by power supplied through the cable \n18\n.', 'FIG.', '10\n illustrates a flowchart of a method \n430\n for improving the signal to noise ratio.', 'The method \n430\n includes lowering (block \n432\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n430\n includes extending (block \n434\n) the arms \n292\n of the tractor device \n290\n.', 'The method \n430\n includes engaging (block \n436\n) the drive wheels \n294\n of the tractor device \n290\n.', 'The drive wheels \n294\n may be engaged against a surface of the wellbore \n16\n, thereby driving the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n430\n includes retracting (block \n438\n) the arms \n292\n of the tractor device \n290\n.', 'Then, the method \n430\n includes detecting (block \n440\n) the position of the toolstring \n12\n using telemetry signals.', 'The method \n430\n includes extending (block \n442\n) the side-arm \n312\n of the anchoring device \n310\n.', 'Extending the side-arm \n312\n wedges the toolstring \n12\n against the casing \n40\n of the wellbore \n16\n.\n \nFIG.', '11A\n is a side view of the toolstring \n12\nC of \nFIG.', '9A\n where the anchoring device \n310\n is activated by a timer device \n322\n. \nFIG.', '11B\n is a side view of the toolstring \n12\nD of \nFIG.', '11A\n in the wellbore \n16\n.', 'The toolstring \n12\nD uses a timer-activated, battery-powered anchoring device \n310\n on the toolstring \n12\nD with a single side-arm \n312\n that deploys to anchor the toolstring \n12\nD in place against the casing \n40\n of the wellbore \n16\n.', 'Before running into the wellbore \n16\n, the timer device \n322\n is set to activate after allowing sufficient time for the cable \n18\n to run into the wellbore \n16\n to the desired location.', 'The cable \n18\n and the toolstring \n12\nD are lowered into the wellbore \n16\n on a cable \n18\n, initially by gravity.', 'A tractor device \n290\n attached to the toolstring \n12\nD is used to continue running the toolstring \n12\nD into the wellbore \n16\n in substantially horizontal portions of the wellbore \n16\n.', 'Once the toolstring \n12\nD is in place in the desired location, the timer device \n322\n activates the switch \n318\n.', 'Activating the switch \n318\n causes the drive wheels \n294\n of the tractor device \n290\n to retract and the anchoring device \n310\n to activate.', 'The side-arm \n312\n of the anchoring device \n310\n swings outward to wedge the toolstring \n12\nD in place against the casing \n40\n of the wellbore \n16\n.', 'FIG.', '12\n illustrates a flowchart of a method \n460\n for improving the signal to noise ratio.', 'The method \n460\n includes setting (block \n462\n) the timer device \n322\n of the anchoring device \n310\n.', 'The method \n460\n includes lowering (block \n464\n) the cable \n18\n and the toolstring \n12\n into the wellbore \n16\n, initially by gravity.', 'The method \n460\n includes extending (block \n466\n) the arms \n292\n of the tractor device \n290\n.', 'The method \n460\n includes engaging (block \n468\n) the drive wheels \n294\n of the tractor device \n290\n.', 'The drive wheels \n294\n may be engaged against a surface of the wellbore \n16\n, thereby driving the toolstring \n12\n deeper into the wellbore \n16\n.', 'The method \n460\n includes activating (block \n470\n) the switch \n318\n of the timer-activated anchoring device \n310\n.', 'The method \n460\n includes retracting (block \n472\n) the arms \n292\n of the tractor device \n290\n.', 'The method \n460\n includes extending (block \n474\n) the side-arm \n312\n of the anchoring device \n310\n.', 'Extending the side-arm \n312\n wedges the toolstring \n12\n against the casing \n40\n of the wellbore \n16\n.', 'With the foregoing in mind, embodiments presented herein provide devices that are capable of improving the signal to noise ratio of measurements.', 'First, a device may aid in propelling a toolstring to the desired location within the wellbore.', 'Once the toolstring has reached the desired location, another device may be utilized to hold the toolstring steady and in place.', 'Keeping the toolstring steady enables sensors to make more accurate measurements by improving the signal to noise ratio of measurements (e.g., by pressing the toolstring against the wellbore wall and/or by maintaining a taut cable that can transmit fiber optic signals with fewer turns or kinks).', 'The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms.', 'It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.'] | ['1.', 'A cable system comprising:\na cable core comprising a fiber optic cable;\na plurality of strength members outside the cable core; and\na plurality of magnetic strength members outside the cable core, wherein the plurality of magnetic strength members are configured to selectively carry current, and wherein the plurality of magnetic strength members are configured to become magnetic or activate an electromagnet electrically coupled to the plurality of magnetic strength members when the plurality of magnetic strength members carry current.', '2.', 'The cable system of claim 1, wherein the plurality of magnetic strength members carrying current enables the cable system, when placed into a cased wellbore, to attract to a casing of the wellbore and reduce an attenuation of a signal carried by the fiber optic cable by reducing turns or kinks in the cable.', '3.', 'The cable system of claim 1, wherein the plurality of magnetic strength members are insulated.', '4.', 'The cable system of claim 1, the electromagnet is held in place by spacers.', '5.', 'The cable system of claim 1, wherein the plurality of magnetic strength members are disposed farther from the cable core than the plurality of strength members.', '6.', 'The cable system of claim 1, wherein the plurality of strength members are disposed farther from the cable core than the plurality of magnetic strength members.', '7.', 'The cable system of claim 1, wherein the plurality of magnetic strength members are disposed in a mixed configuration with the plurality of strength members, where some magnetic strength members are disposed farther from the cable core and some magnetic strength members are disposed closer to the cable core than the plurality of strength members.', '8.', 'The cable system of claim 1, further comprising a filler material disposed between the plurality of strength members and the plurality of magnetic strength members, where the filler material holds the plurality of strength members and the plurality of magnetic strength members in place.', '9.', 'The cable system of claim 1, wherein the cable system is coupled to a toolstring including a tractor device.', '10.', 'A cable system comprising:\na cable core comprising a fiber optic cable, the fiber optic cable comprising an optical core and an insulating coating;\na plurality of strength members outside the cable core;\na plurality of magnetic strength members outside the cable core; and\nan electromagnet in electrical communication with the plurality of magnetic strength members;\nwherein the plurality of magnetic strength members are configured to selectively carry current, and the plurality of magnetic strength members are configured to become magnetic or activate the electromagnet when the plurality of magnetic strength members carry current.', '11.', 'The cable system of claim 10, further comprising an additional insulating coating disposed over the insulating coating.\n\n\n\n\n\n\n12.', 'The cable system of claim 10, wherein the plurality of magnetic strength members are insulated.', '13.', 'The cable system of claim 10, the electromagnet is held in place by spacers.', '14.', 'The cable system of claim 10, wherein the plurality of magnetic strength members are disposed farther from the cable core than the plurality of strength members.', '15.', 'The cable system of claim 10, wherein the plurality of strength members are disposed farther from the cable core than the plurality of magnetic strength members.', '16.', 'The cable system of claim 10, wherein the plurality of magnetic strength members are disposed in a mixed configuration with the plurality of strength members, where some magnetic strength members are disposed farther from the cable core and some magnetic strength members are disposed closer to the cable core than the plurality of strength members.', '17.', 'The cable system of claim 10, further comprising a filler material disposed between the plurality of strength members and the plurality of magnetic strength members, where the filler material holds the plurality of strength members and the plurality of magnetic strength members in place.', '18.', 'The cable system of claim 10, wherein the cable system is coupled to a toolstring including a tractor device.'] | ['FIG.', '1 is a schematic diagram of a wireline system that includes a toolstring to detect properties of a wellbore or geological formation adjacent to the toolstring, in accordance with an aspect of the present disclosure;; FIGS.', '2A and 2B are cross sections of different embodiments of a cable that can be magnetized, in accordance with an aspect of the present disclosure;; FIG.', '3A is a side view of an embodiment of a toolstring with the arms of a tractor device extended, in accordance with an aspect of the present disclosure;; FIG.', '3B is a side view of the toolstring of FIG.', '3A in a wellbore, in accordance with an aspect of the present disclosure;; FIG.', '3C is a side view of the toolstring of FIG.', '3A with the cable magnetized and the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;; FIG.', '3D is a side view of the toolstring of FIG.', '3C in a wellbore and with the cable magnetized and held to the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG. 4 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '5A is a side view of an embodiment of a toolstring including a timer-activated magnetic device with the arms of the tractor device extended, in accordance with an aspect of the present disclosure;; FIG.', '5B is a side view of the toolstring of FIG.', '5A in a wellbore, in accordance with an aspect of the present disclosure;; FIG.', '5C is a side view of the toolstring of FIG.', '5A with the arms of the tractor device retracted, in accordance with an aspect of the present disclosure;; FIG.', '5D is a side view of the toolstring of FIG.', '5C in a wellbore and with the selectively magnetic device holding the toolstring to the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '5E is a side view of the toolstring of FIG.', '5D, with an additional toolstring mounted on the cable, in accordance with an aspect of the present disclosure;; FIG.', '6 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure;; FIGS.', '7A-7B are cross sections of different embodiments of the cable with a magnetic device coupled to the cable, in accordance with an aspect of the present disclosure;; FIG.', '8A is a side view of an embodiment of the magnetic device, in accordance with an aspect of the present disclosure;; FIG.', '8B is a side view of multiple magnetic devices of FIG.', '8A in a wellbore, in accordance with an aspect of the present disclosure;; FIG.', '8C is a side view of the magnetic devices of FIG.', '8B attached to the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '9A is a side view of an embodiment of the toolstring including an anchoring device and a tractor device and the arms of the tractor device are extended, in accordance with an aspect of the present disclosure;; FIG.', '9B is a side view of the toolstring of FIG.', '9A and the side-arm of the anchoring device extended, in accordance with an aspect of the present disclosure;; FIG.', '9C is a side view of multiple toolstring of FIG.', '9B with the arms of the tractor devices retracted and the side-arms of the anchoring devices extended and holding the toolstrings against the casing of the wellbore, in accordance with an aspect of the present disclosure;; FIG.', '10 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using an anchoring device, in accordance with an aspect of the present disclosure;; FIG.', '11A is a side view of the toolstring of FIG.', '9A where the anchoring device is activated by a timer device, in accordance with an aspect of the present disclosure;; FIG.', '11B is a side view of the toolstring of FIG.', '11B in a wellbore and with the arms of the tractor device extended, in accordance with an aspect of the present disclosure; and; FIG.', '12 is a flow chart for a method for lowering the toolstring and holding the cable against the casing of the wellbore using a timer device, in accordance with an aspect of the present disclosure.', '; FIG.', '2A depicts an embodiment of a cross-section of a cable 18A.', 'The present embodiment of the cable 18A allows the cable 18A to magnetically attach to the casing 40 of the wellbore 16.', 'In doing so, the cable 18A holds the toolstring 12 in substantially the same place.', 'In FIG.', '2A, the cable 18A is designed to function as an electromagnet.', 'The cable 18A includes three different sections, a cable core 70, strength members 74, and magnetic strength members 72.', 'The cable core 70 may include fiber optic cables 81 and conductors 85.', 'The fiber optic cables 81 may include different configurations.', 'For example, the fiber optic cable 81 may include an optical core 78 and an insulating coating 80 followed by a second insulating coating 76.', 'Alternatively, the second insulating coating 76 may be replaced by spacers 84 followed by an insulating layer 82.', 'While the present embodiment includes three optical cores 78 per fiber optic cable 81, it should be appreciated that each fiber optic cable 81 may include any suitable number of optical cores, including 1, 2, 3, 4, 5, or 6, or more.', 'The conductors 85 include conducting elements 88 surrounded by an insulating material 86.', 'Further, the cable core 70 may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'The magnetic strength members 72 include the strength member 74 followed by a layer of insulated strength members/conductors 75 (e.g., using bimetallic materials) followed by a layer of durable polymeric electrical insulation 73.', 'In the present embodiment, the magnetic strength members 72 are disposed farther from the cable core 70 than the strength members 74; however, it should be appreciated that the magnetic strength members 72 may be disposed closer to the cable core 70 than strength members 74.', 'Additionally or alternatively, the magnetic strength members 72 may be disposed in a mixed configuration with the strength member 74, with some magnetic strength members 72 farther from the cable core 70 and some closer to the cable core 70 than the strength members 74.', 'Each of the strength members 74 or a portion of the strength members 74 in the armor matrix can be magnetic strength members 72.', 'The quantity, material, size and lay angles of the magnetic strength members 72 combined with the electrical current applied can be altered to create an electromagnet of sufficient strength to hold the cable 18A in place against the casing 40 of the wellbore 16.', 'Surface and downhole electronics may be configured to turn the magnetic strength members 72 on and off.', 'In the “Off” mode, return current is carried by the strength members 74.', 'In the “On” position, current is returned on the magnetic strength members 72 and cause the magnetic strength member 72 to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', 'A hybrid conductor is a cable that contains multiple strands wrapped around one another, and the strands may be composed of multiple types of metals (e.g., steel, bimetallic, etc.).', '; FIG.', '2B depicts a cross-section of an alternative embodiment of the cable 18.', 'A cable 18B is designed to function as an electromagnet, and the cable 18B includes a cable core 90, strength members 92, and magnetic strength members 94.', 'The strength members 92 may be magnetic strength members 94.', 'The cable core 90 includes fiber optic cables 81, conductors 85, and wires 98.', 'The fiber optic cables 81 include the optical cores 78 followed by the insulating coating 80.', 'The conductors 85 include conducting elements 88 surrounded by an insulating material 86.', 'The cable core 90 may be any configuration used for an electro-optical cable (e.g., Coaxial, Triad, Quad, or Hepta).', 'All the strength members 92 or a portion of the strength members 92 may be replaced with magnetic strength members 94 (e.g. bi-metallic) in order to balance the cable 18B safe working load and magnetic anchoring force.', 'The material, quantity, size and lay angles of magnetic strength members 94 and the electrical current applied may be configured to create an electromagnet of sufficient strength to hold the cable 18B in place against the casing 40 of the wellbore 16.', 'Strength member 92 and magnetic strength members 94 may be held in place by a filler material 96.', 'The filler material may include insulating elements.', 'Surface and downhole electronics are configured to turn the electromagnet on and off.', 'In the “Off” mode, return current is carried by conductors in the cable core 90.', 'In the “On” position, current is returned on the magnetic strength members 94 causing the magnetic strength members 94 to function as an electromagnet.', 'In multiple-conductor cable cores, one or more conductors can be replaced with hybrid conductors.', ';', 'FIG.', '3A is a side view of an embodiment of a toolstring 12A attached to the cable 18.', 'The cable 18 may be either embodiment depicted in FIGS.', '2A and 2B. In the present embodiment, the toolstring 12A includes a tractor device 122.', 'The tractor device 122 includes arms 124, and each arm 124 includes a drive wheel 126.', 'The tractor device 122 may include any suitable number of arms 124, including 1, 2, 3, 4, 5, 6, or more.', 'In operation, the cable 18 and the toolstring 12A are lowered into the wellbore 16 on the cable 18, initially by gravity.', 'The tractor device 122 attached to the toolstring 12A is used to continue propelling the toolstring 12A into the hole of the wellbore 16 in substantially horizontal (i.e., greater than sixty degrees with respect to the surface of the ground) portions of the wellbore 16.', 'As depicted in FIG.', '3B, the tractor device 122 uses drive wheels 126 on arms 124 that extend from the toolstring 12A to propel the toolstring 12A down the casing 40 of the wellbore 16.; FIGS.', '3C and 3D are side views of the toolstring 12A with the arms 124 of the tractor device 122 retracted and the cable 18 in the “On” position.', 'Once the cable 18 and toolstring 12A are in the desired location, the arms 124 on the tractor device 122 are withdrawn and the cable 18 is turned to the “On” position.', 'The return current is switched to the magnetic strength members 72 or 94.', 'Applying electrical current to the magnetic strength members 72 or 94 allows the cable 18 to function as an electromagnet.', 'The strength of the electromagnet may be adjusted by changing amount of current applied or by adjusting the material, quantity, diameters and lay angles of the insulated strength member/conductors.', 'Further, the magnetic strength members 72 and 94 may be included on a portion of the cable 18.', 'For example, the magnetic strength members 72 and 94 may be included on a portion of the cable 18 near the toolstring 12.; FIG.', '4 illustrates a flowchart of a method 130 for improving the signal to noise ratio.', 'The method 130 includes lowering (block 132) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 130 includes extending (block 134) the arms 124 of the tractor device 122.', 'The method 130 includes engaging (block 136) the drive wheels 126 of the tractor device 122.', 'The drive wheels 126 may be engaged against a surface of the wellbore 16, thereby propelling the toolstring 12 deeper into the wellbore 16.', 'The method 130 includes retracting (block 138) the arms 124 of the tractor device 122.', 'The method 130 includes applying (block 140) current to the magnetic strength members 72 or 94 of the cable 18.', 'As previously discussed, applying current to the magnetic strength members 72 or 94 allows the cable 18 to function as an electromagnet.', 'The cable 18 may then be pulled taught to keep the cable 18 steady while the fiber optic cables transmit data.', 'The cable 18 being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', '; FIG.', '5A is a side view of an embodiment of a toolstring 12B including a timer-activated magnetic device 170 with the arms 164 of the tractor device 162 extended.', 'The timer-activated magnetic device 170 is powered by a battery 174 and the timer-activated device 170 is located in the toolstring 12B. Before running the toolstring 12B and cable 18 into the wellbore 16, the timer 172 is set to activate after allowing sufficient time for the cable 18 to run into the wellbore 16 to the desired location.', 'The cable 18 and the toolstring 12 are lowered into the wellbore 16 on the cable 18, initially by gravity.', 'A tractor device 162 attached to the toolstring 12 is used to continue running the toolstring 12 into the wellbore 16 in substantially horizontal portions of the wellbore 16.', 'The current returned through the armor can be used to store energy in the battery 174 and extend the magnetic anchoring period.', 'As depicted in FIG.', '5B, the tractor device 162 uses drive wheels 166 on arms 164 that extend from the toolstring 12B to propel the toolstring 12B down the casing 40 of the wellbore 16.; FIGS.', '5C and 5D are side views of the toolstring 12B with the arms 164 of the tractor device 162 retracted.', 'Once the timer 172 reaches the end of its time, the timer 172 activates a switch 176 of the timer-activated magnetic device 170 (which will allow time for the toolstring 12B to arrive at the desired downhole location).', 'Activating the switch 176 supplies power from the battery 174 to the electromagnet 178.', 'Activating the switch 176 also causes the drive wheels 166 of the tractor device 162 to retract into the toolstring', '12B.', 'The electromagnet 178 holds the toolstring 12B in place against the casing 40 of the wellbore 16.', 'The cable 18 can then be tightened to hold it taut against the casing 40 of the wellbore 16, allowing the fiber optics of the cable 18 to transmit a strong and consistent signal from downhole formations.', 'FIG.', '5E is a side view of the toolstring 12B of FIG.', '5D, with a second timer-activated magnetic device 170 mounted on the cable 18.', 'Multiple timer-activated magnetic devices 170 may be located at any suitable location along the length of the cable 18.; FIG.', '6 illustrates a flowchart of a method 400 for improving the signal to noise ratio.', 'The method 400 includes setting (block 402) the timer 172 of the timer-activated magnetic device 170.', 'The method 400 includes lowering (block 404) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 400 includes extending (block 406) the arms 164 of the tractor device 162.', 'The method 400 includes engaging (block 408) the drive wheels 166 of the tractor device 162.', 'The drive wheels 166 may engage a surface of the wellbore 16, thereby driving the toolstring 12 deeper into the wellbore 16.', 'The method 400 includes activating (block 410) the switch 176 of the timer-activated magnetic device 170.', 'The method 400 includes retracting (block 412) the arms 164 of the tractor device 162.', 'The method 400 includes supplying (block 414) power to the electromagnet 178.', 'In the present embodiment, the power is supplied by a battery 174, but the power may be supplied from other structure, including the cable 18.', 'Supplying power to the electromagnet 178 causes the electromagnet 178 to attach to the casing 40 of the wellbore 16.', 'The cable 18 may then be pulled taught to keep the cable 18 steady while the fiber optic cables transmit data.', 'The cable 18 being kept steady reduces the signal to noise ratio of the data transmitted through the fiber optic cables.', ';', 'FIG.', '7A is a cross section of an embodiment of a cable 18C with a magnetic device 210A coupled to the cable 18C.', 'The magnetic device 210A is installed as needed along the cable 18C and is powered by insulated magnetic strength members 220.', 'Insulated magnetic strength members 220 include insulation 222 (e.g., durable polymetric electrical insulation).', 'A number of strength members 224 are replaced by insulated magnetic strength members 220.', 'Insulated magnetic strength members 220 can be made out of bimetallic material or any suitable magnetic material.', 'A separate insulated magnetic strength member 220 may be used for each magnetic device 210A so that each magnetic device 210A may be operated independently.', 'The magnetic device 210A is installed over the cable 18C in two halves that come together and are held together by a magnetic device casing 234 to form a cylinder.', 'The cable 18C includes a cable core 236, strength members 224, and insulated magnetic strength members 220.', 'The cable core 236 may include fiber optic cables 81 and conductors 85.', 'The fiber optic cables 81 may include an optical core 78 and an insulating coating 80 followed by a second insulating coating 226 and an outer insulating layer 240.', 'One side of the cylinder contains an electromagnet 230.', 'The electromagnet 230 is a semi-circular-profile iron bar wrapped tightly in insulated copper wire.', 'Non-conductive spacers 232 hold the electromagnet 230 in place within the gap between the magnetic device casing 234 and the cable 18C. One end of an insulated conductive wire 228 is attached to the insulated magnetic strength member 220, and the other end is attached to the electromagnet 230.', 'Sufficient slack is allowed in the insulated conductive wires 228 to enable the connections to insulated magnetic strength members 220 that tend to rotate under longitudinal stress.', 'When current is applied to the insulated magnetic strength members 220, the electromagnet 230 is activated and attaches the magnetic device 210A to the casing 40 of the wellbore 16.; FIG.', '7B is a cross section of an embodiment of a cable 18D with a magnetic device 210B coupled to the cable 18D.', 'The cable 18D includes the cable core 90, insulated magnetic strength members 270, strength members 280, and a filler material 272 (e.g., an insulating material).', 'The magnetic device 210B is installed along the cable 18D and powered by insulated magnetic strength members 270.', 'A number of strength members 280 (e.g., standard armor wire) are replaced by the insulated magnetic strength members 270.', 'The insulated magnetic strength members 270 may be made out of bimetallic material or any suitable magnetic material to increase the force of attraction between magnetic device 210B and casing 40 of the wellbore 16.', 'The magnetic device 210B is installed over the cable 18D in two halves that come together to form a cylinder.', 'One side contains an electromagnet 276.', 'Spacers 278 hold the electromagnet 276 in place on the cable 18D.', 'When current is applied to the insulated magnetic strength members 270, the electromagnet 276 is activated and attaches the magnetic device 210B to the casing 40 of the wellbore 16.; FIGS.', '8A and 8B are a side view of the magnetic device 210.', 'The magnetic device 210 may include either the magnetic device 210A or 210B. As shown in FIG.', '8B, the cable 18 may include multiple magnetic devices 210.', 'The magnetic devices 210 may be spread along the cable 18 at any distance as is desired.', 'FIG.', '8C is a side view of the magnetic devices 210 attached to the casing 40 of the wellbore 16.', 'Once the magnetic device 210 has advanced to the desired location in the well, current is applied as described above to activate the electromagnet 230 or 276.', 'The magnetic device 210 attaches magnetically to the casing 40 of the wellbore 16.', 'The cable 18 is pulled taut and any other magnetic devices 210 are also activated to hold the cable 18 against the casing 40 of the wellbore 16.', 'The cable 18 can then be tightened to hold it taut against the casing 40 of the wellbore 16, thereby allowing the fiber optics of the cable to receive a strong and consistent signal from downhole formations.', 'Pressing the cable 18 against the casing 40 of the wellbore 16 may also press the toolstring 12 against the casing 40.; FIG.', '9A is a side view of an embodiment of a toolstring 12C including an anchoring device 310 and a tractor device 290 and the arms 292 of the tractor device 290 are extended.', 'The present embodiment includes two toolstrings 12C, and only one of the toolstrings includes the tractor device 290.', 'The cable 18 and the toolstring 12C are lowered into the wellbore 16, initially by gravity.', 'The tractor device 290 of the toolstring 12C is used to continue running the toolstring 12C into the wellbore 16 in substantially horizontal portions of the well.', 'Once the toolstring 12C is at the desired location, the drive wheels 294 of the tractor device 290 retract.; FIG.', '9B is a side view of the toolstring 12C with the anchoring device 310 activated.', 'FIG.', '9C is a side view of two toolstrings 12C, both with the anchoring device 310 activated.', 'The anchoring devices 310 in the toolstring 12C are activated by telemetry signals sent through the cable 18 from the surface.', 'The telemetry signals cause a switch 318 to either engage or disengage.', 'The telemetry signals cause the switch 318 to engage once the toolstring 12C has reached the desired location in the wellbore 16.', 'However, while the switch 318 is engaged or disengaged by telemetry signals in the present embodiment, it should be noted that the switch 318 may be engaged or disengaged by a program designed to engage the switch 318 after a sufficient amount of time has passed.', 'The anchoring devices 310 have a single side-arm 312 that deploys in direction 314 to anchor the toolstrings 12C and the cable 18 to the casing 40 of the wellbore 16 when the switch 318 is engaged.', 'The side-arm 312 of the anchoring device 310 swings outward about a hinge 320 in the direction 314 to wedge the toolstring 12C in place against the casing 40 of the wellbore.', 'In the present embodiment, the anchoring device 310 is powered by a battery 316; however, it should be appreciated that the anchoring device 310 may also be powered by power supplied through the cable 18.; FIG.', '10 illustrates a flowchart of a method 430 for improving the signal to noise ratio.', 'The method 430 includes lowering (block 432) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 430 includes extending (block 434) the arms 292 of the tractor device 290.', 'The method 430 includes engaging (block 436) the drive wheels 294 of the tractor device 290.', 'The drive wheels 294 may be engaged against a surface of the wellbore 16, thereby driving the toolstring 12 deeper into the wellbore 16.', 'The method 430 includes retracting (block 438) the arms 292 of the tractor device 290.', 'Then, the method 430 includes detecting (block 440) the position of the toolstring 12 using telemetry signals.', 'The method 430 includes extending (block 442) the side-arm 312 of the anchoring device 310.', 'Extending the side-arm 312 wedges the toolstring 12 against the casing 40 of the wellbore 16.; FIG.', '11A is a side view of the toolstring 12C of FIG.', '9A where the anchoring device 310 is activated by a timer device 322.', 'FIG.', '11B is a side view of the toolstring 12D of FIG.', '11A in the wellbore 16.', 'The toolstring 12D uses a timer-activated, battery-powered anchoring device 310 on the toolstring 12D with a single side-arm 312 that deploys to anchor the toolstring 12D in place against the casing 40 of the wellbore 16.', 'Before running into the wellbore 16, the timer device 322 is set to activate after allowing sufficient time for the cable 18 to run into the wellbore 16 to the desired location.', 'The cable 18 and the toolstring 12D are lowered into the wellbore 16 on a cable 18, initially by gravity.', 'A tractor device 290 attached to the toolstring 12D is used to continue running the toolstring 12D into the wellbore 16 in substantially horizontal portions of the wellbore 16.', 'Once the toolstring 12D is in place in the desired location, the timer device 322 activates the switch 318.', 'Activating the switch 318 causes the drive wheels 294 of the tractor device 290 to retract and the anchoring device 310 to activate.', 'The side-arm 312 of the anchoring device 310 swings outward to wedge the toolstring 12D in place against the casing 40 of the wellbore 16.; FIG.', '12 illustrates a flowchart of a method 460 for improving the signal to noise ratio.', 'The method 460 includes setting (block 462) the timer device 322 of the anchoring device 310.', 'The method 460 includes lowering (block 464) the cable 18 and the toolstring 12 into the wellbore 16, initially by gravity.', 'The method 460 includes extending (block 466) the arms 292 of the tractor device 290.', 'The method 460 includes engaging (block 468) the drive wheels 294 of the tractor device 290.', 'The drive wheels 294 may be engaged against a surface of the wellbore 16, thereby driving the toolstring 12 deeper into the wellbore 16.', 'The method 460 includes activating (block 470) the switch 318 of the timer-activated anchoring device 310.', 'The method 460 includes retracting (block 472) the arms 292 of the tractor device 290.', 'The method 460 includes extending (block 474) the side-arm 312 of the anchoring device 310.', 'Extending the side-arm 312 wedges the toolstring 12 against the casing 40 of the wellbore 16.'] |
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US11066903 | Apparatus and methods for well intervention | Jan 27, 2020 | Thomas MacDougall, Mark Milkovisch, Todor Sheiretov | SCHLUMBERGER TECHNOLOGY CORPORATION | NPL References not found. | 1901513; March 1933; Harris; 3173501; March 1965; Moore; 4509593; April 9, 1985; Traver et al.; 4932483; June 12, 1990; Rear; 5309988; May 10, 1994; Shy et al.; 6745836; June 8, 2004; Taylor et al.; 6986394; January 17, 2006; Marsh; 7367397; May 6, 2008; Clemens et al.; 8210251; July 3, 2012; Lynde et al.; 9133671; September 15, 2015; Kellner; 20110120726; May 26, 2011; Murray; 20110146975; June 23, 2011; O'Malley; 20110192222; August 11, 2011; Vetter; 20140174726; June 26, 2014; Harrigan et al.; 20160069146; March 10, 2016; Livescu et al.; 20160123112; May 5, 2016; Purkis; 20160177669; June 23, 2016; Avant; 20170058644; March 2, 2017; Andreychuk; 20170130557; May 11, 2017; Pratt; 20170167227; June 15, 2017; Lee et al.; 20170370189; December 28, 2017; MacDougall et al. | 2002095180; November 2002; WO | ['A downhole tool string for conveying within a wellbore, including an engagement device for engaging a downhole feature located within the wellbore, a first actuator for applying a substantially non-vibrating force to the engagement device while the engagement device is engaged with the downhole feature, and a second actuator for applying a vibrating force to the engagement device while the engagement device is engaged with the downhole feature.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATIONS', 'This application is a divisional application and claims the benefit of and priority to U.S. patent application Ser.', 'No. 15/191,575, titled “Apparatus and Methods for Well Intervention,” filed Jun. 24, 2016, the entirety of which is incorporated herein by reference for all purposes.\n \nBACKGROUND OF THE DISCLOSURE\n \nIntervention operations in completed wells may entail actuation of various fluid valves, such as formation isolation valves, installed within the wellbore.', 'For example, the valves may be installed during completion operations and then generally remain closed to prevent fluid transfer between the wellbore and the formation while still permitting the passage, through the valves, of tubing, tools, and/or tools other equipment.', 'For subsequent operations, the valves may be remotely opened remotely by applying a sequence of pressure pulses.', 'If the opening mechanism of one of the valves becomes stuck, such that the applied pressure pulses are insufficient to actuate the valve, a downhole tool may be conveyed into the wellbore and utilized to mechanically open the valve.', 'However, sand or other contaminants may even prevent such mechanical actuation of the valve.', 'Accordingly, wellsite operators may apply increasing mechanical forces to the stuck valve in attempting to unstick the valve.', 'However, the increased forces may further exacerbate the situation, perhaps resulting in further jamming or seizing the valve, and potentially damaging the valve.', 'Accordingly, a cleanup operation may be conducted prior to attempting to actuate the valves.', 'The cleanup operation may utilize coiled tubing with a milling tool fitted with a brush bit and a debris collection tool to clean out residual fracturing sand and/or other debris that may otherwise cause the valves to stick.', 'However, the cost, equipment footprint at the wellsite, and operational time associated with coiled tubing operations can make this option less than optimal.', 'SUMMARY OF THE DISCLOSURE', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.', 'The present disclosure introduces an apparatus that includes a downhole tool string for conveying within a wellbore.', 'The downhole tool string includes an engagement device operable to engage a downhole feature located within the wellbore, a first actuator operable to apply a substantially non-vibrating force to the engagement device while the engagement device is engaged with the downhole feature, and a second actuator operable to apply a vibrating force to the engagement device while the engagement device is engaged with the downhole feature.', 'The present disclosure also introduces a method that includes operating a first actuator to impart a substantially non-vibrating force to a downhole feature located within a wellbore, and operating a second actuator to impart a vibrating force to the downhole feature.', 'The present disclosure also introduces a method that includes positioning a downhole tool string relative to a downhole feature within a wellbore.', 'The downhole tool string is in communication with surface equipment disposed at a wellsite surface from which the wellbore extends, and the downhole tool string and/or the surface equipment individually or collectively include a controller comprising a processor and a memory storing computer program code.', 'The method also includes engaging the downhole feature with an engagement device of the downhole tool string, and operating the controller to control an actuator of the downhole tool string to impart movements to the engagement device and the downhole feature in first and second directions.', 'The movements are of different distances to achieve a net repositioning of the downhole feature in the first or second direction.', 'These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein.', 'At least some aspects of the present disclosure may be achieved via means recited in the attached claims.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The present disclosure is best understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '2\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '3\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'FIG.', '4\n is a sectional view of a portion of the apparatuses shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure.', 'FIG.', '5\n is a sectional view of the apparatus shown in \nFIG.', '4\n in a different stage of operation.\n \nFIG.', '6\n is a schematic view of a portion of an example implementation of the apparatus shown in \nFIG.', '3\n according to one or more aspects of the present disclosure.', 'FIG.', '7\n is a schematic view of a portion of an example implementation of the apparatus shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure.', 'FIG.', '8\n is a schematic view of a portion of an example implementation of the apparatus shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure.', 'FIG.', '9\n is a schematic view of a portion of an example implementation of the apparatus shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure.', 'FIG.', '10\n is a schematic axial view of the apparatus shown in \nFIG.', '9\n according to one or more aspects of the present disclosure.', 'FIG.', '11\n is a schematic view of a portion of an example implementation of the apparatuses shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure.', 'FIG.', '12\n is a schematic axial view of the apparatus shown in \nFIG.', '11\n according to one or more aspects of the present disclosure.', 'FIG.', '13\n is a schematic view of a portion of an example implementation of the apparatuses shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure.', 'FIG.', '14\n is a schematic axial view of the apparatus shown in \nFIG.', '13\n according to one or more aspects of the present disclosure.', 'FIGS.', '15-19\n are graphs related to one or more aspects of the present disclosure.\n \nFIG.', '20\n is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the present disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the present disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'Moreover, the formation of a first feature over or on a second feature in the description that follows, may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.\n \nFIG.', '1\n is a schematic view of at least a portion of a wellsite system \n100\n according to one or more aspects of the present disclosure.', 'The wellsite system \n100\n may comprise a tool string \n110\n suspended within a wellbore \n120\n that extends from a wellsite surface \n105\n into one or more subterranean formations \n130\n.', 'The wellbore \n120\n is depicted as being a cased-hole implementation comprising a casing \n124\n secured by cement \n122\n.', 'However, one or more aspects of the present disclosure are also applicable to and/or readily adaptable for utilizing in open-hole implementations lacking the casing \n124\n and cement \n122\n.', 'Also, the tool string \n110\n is depicted located within a horizontal portion \n121\n of the wellbore \n120\n.', 'However, it is to be understood that the tool string \n110\n within the scope of the present disclosure may be utilized in vertical, diagonal, and otherwise deviated portions of the wellbore \n120\n.', 'The tool string \n110\n may be suspended within the wellbore \n120\n via a conveyance means \n171\n operably coupled with a tensioning device \n170\n and/or other surface equipment \n175\n disposed at the wellsite surface \n105\n, including a power and control system \n172\n.', 'The tensioning device \n170\n may be operable to apply an adjustable tensile force to the tool string \n110\n via the conveyance means \n171\n.', 'The tensioning device \n170\n may be, comprise, or form at least a portion of a crane, a winch, a drawworks, a top drive, and/or another lifting device coupled to the tool string \n110\n by the conveyance means \n171\n.', 'The conveyance means \n171\n may be or comprise a wireline, a slickline, an e-line, coiled tubing, drill pipe, production tubing, and/or other conveyance means, and may comprise and/or be operable in conjunction with means for communication between the tool string \n110\n, the tensioning device \n170\n, and/or one or more other portions of the surface equipment \n175\n, including the power and control system \n172\n.', 'The conveyance means \n171\n may comprise a multi-conductor wireline, comprising electrical and/or optical conductors extending between the tool string \n110\n and the surface equipment \n175\n.', 'The power and control system \n172\n may include a source of electrical power \n176\n, a memory device \n177\n, and a controller \n178\n operable to process signals or information, and send the processed signals or information to the tool string \n110\n.', 'The controller \n178\n may also be operable to receive commands from a human operator.', 'The tool string \n110\n may comprise an uphole or upper portion \n140\n, a downhole or lower portion \n160\n, and an intermediate portion \n150\n coupled between the upper portion \n140\n and the lower portion \n160\n.', 'The portions \n140\n, \n150\n, \n160\n of the tool string \n110\n may each be or comprise one or more downhole tools, modules, and/or other apparatus operable in wireline, while-drilling, coiled tubing, completion, production, and/or other implementations.', 'Each portion \n140\n, \n150\n, \n160\n of the tool string \n110\n may comprise at least one corresponding electrical and/or optical conductor \n145\n, \n155\n, \n165\n in communication with at least one component of the surface equipment \n175\n.', 'Each of the conductors \n145\n, \n155\n, \n165\n may comprise a plurality of individual conductors, such as may facilitate communication between one or more of the tool string portions \n140\n, \n150\n, \n160\n and one or more component of the surface equipment \n175\n, such as the power and control system \n172\n.', 'Thus, the conductors \n145\n, \n155\n, \n165\n may connect with and/or form a portion of the conveyance means \n171\n, and may include various electrical and/or optical connectors or interfaces along such path.', 'Furthermore, the conductors \n145\n, \n155\n, \n165\n may facilitate communication between two or more of the tool string portions \n140\n, \n150\n, \n160\n.', 'Each portion \n140\n, \n160\n, \n150\n may comprise one or more electrical and/or optical connectors (not shown), such as may be operable to electrically and/or optically connect the conductors \n145\n, \n155\n, \n165\n extending therebetween.', 'For example, the conveyance means \n171\n and the conductors \n145\n, \n155\n, \n165\n may be operable to transmit and/or receive electrical power, data, and/or control signals between the power and control system \n172\n and one or more of the portions \n140\n, \n150\n, \n160\n.', 'Each portion \n140\n, \n150\n, \n160\n of the tool string \n110\n may be or comprise one or more downhole tools, subs, modules, and/or other apparatuses operable in wireline, while-drilling, coiled tubing, completion, production, and/or other operations.', 'Although the tool string \n110\n is shown comprising three portions \n140\n, \n150\n, \n160\n, it is to be understood that the tool string \n110\n may comprise additional portions.', 'For example, the portions \n140\n, \n150\n, \n160\n may each be or comprise one or more of a cable head, a telemetry tool, a directional tool, an acoustic tool, a density tool, an electromagnetic (EM) tool, a formation evaluation tool, a gravity tool, a formation logging tool, a magnetic resonance tool, a formation measurement tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a surveying tool, a release tool, a mechanical interface tool, an anchor tool, a perforating tool, a cutting tool, a linear actuator, a rotary actuator, a downhole tractor, a jarring tool, an impact or impulse tool, a vibrating or shaking tool, a fishing tool, a valve key or engagement tool, and a plug setting tool.', 'One or more of the portions \n140\n, \n150\n, \n160\n may be or comprise inclination sensors and/or other position sensors, such as one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for utilization in determining the orientation of the tool string \n110\n relative to the wellbore \n120\n.', 'Furthermore, one or more of the portions \n140\n, \n150\n, \n160\n may be or comprise a correlation tool, such as a casing collar locator (CCL) operable to detect ends of casing collars by sensing a magnetic irregularity caused by a relatively high mass of an end of a collar of the casing \n124\n.', 'The correlation tool may also or instead be or comprise a gamma ray (GR) tool that may be utilized for depth correlation.', 'The CCL and/or GR tools may transmit signals in real-time to the wellsite surface equipment \n175\n, such as the power and control system \n172\n, via the conveyance means \n171\n.', 'The CCL and/or GR signals may be utilized to determine the position of the tool string \n110\n or portions thereof, such as with respect to known casing collar numbers and/or positions within the wellbore \n120\n.', 'Therefore, the CCL and/or GR tools may be utilized to detect and/or log the location of the tool string \n110\n within the wellbore \n120\n, such as during deployment within the wellbore \n120\n or other downhole operations.', 'FIG.', '2\n is a schematic view of an example implementation of the tool string \n110\n shown in \nFIG.', '1\n according to one or more aspects of the present disclosure, designated in \nFIG.', '2\n by numeral \n200\n.', 'The tool string \n200\n is shown disposed within the substantially horizontal portion \n121\n of the wellbore \n120\n and connected with the surface equipment \n175\n via the conveyance means \n171\n.', 'However, it is to be understood that the tool string \n200\n may also be utilized within a substantially vertical or otherwise deviated portion of the wellbore \n120\n.', 'The following description refers to \nFIGS.', '1 and 2\n, collectively.', 'The tool string \n200\n comprises a plurality of modules communicatively connected with each other and the wellsite equipment \n175\n via an electrical and/or optical conductor system \n208\n extending through the modules of the tool string \n200\n.', 'Although not shown, it is to be understood that the tool string \n200\n may comprise one or more bores extending longitudinally through the various components of the tool string \n200\n to accommodate the conductor system \n208\n.', 'The tool string \n200\n may comprise a cable head \n210\n operable to connect the conveyance means \n171\n with the tool string \n200\n.', 'The tool string \n200\n may further comprise a control module \n212\n downhole from the cable head \n210\n.', 'The control module \n212\n may comprise a controller \n214\n communicatively coupled with one or more portions and/or components of the tool string \n200\n via the conductor system \n208\n, and with the power and control system \n172\n via the conveyance means \n171\n.', 'The controllers \n178\n, \n214\n may be independently or cooperatively operable to control operations of one or more portions and/or components of the tool string \n200\n.', 'For example, the controllers \n178\n, \n214\n may be operable to receive and process signals obtained from various sensors of the tool string \n200\n, store the processed signals, operate one or more portions and/or components of the tool string \n200\n based on the processed signals, and/or communicate the processed signals to the power and control system \n172\n or another component of the surface equipment \n175\n.', 'The controller \n214\n may be operable to receive control commands from the power and control system \n172\n for controlling one or more portions and/or components of the tool string \n200\n.', 'The control module \n212\n may also comprise the correlation and telemetry tools, such as may facilitate positioning of the tool string \n200\n along the wellbore \n120\n and communication with the surface equipment \n175\n.', 'The tool string \n200\n may further comprise one or more actuator modules \n220\n, \n222\n, an engagement device \n224\n, and a power module \n216\n operable to provide power to operate the actuator modules \n220\n, \n222\n, the engagement device \n224\n, and/or one or more other modules and/or portions of the tool string \n200\n.', 'The actuator modules \n220\n, \n222\n may be operable to generate and/or apply corresponding forces to an operatable or movable member \n234\n of a downhole apparatus \n230\n installed within the wellbore \n120\n, via the engagement device \n224\n, to move or otherwise operate the downhole apparatus \n230\n.', 'The engagement device \n224\n may comprise engagement members \n226\n operable to connect, interface, or otherwise engage with a downhole feature \n232\n of the movable member \n234\n of the downhole apparatus \n230\n.', 'The movable member \n234\n may be operatively connected with a fluid control or obstructing member \n236\n of the downhole apparatus \n230\n, and configured to operate the fluid obstructing member \n236\n when mechanically moved or actuated.', 'For example, the downhole apparatus \n230\n may be a fluid valve assembly, such as an isolation valve, a flow control valve, a safety valve, a flapper valve, a ball valve, a gas-lift valve, a plug, or a packer, and the movable member \n234\n may be or comprise a sliding sleeve, a mandrel, or a bracket, configured to mechanically shift or operate the fluid obstructing member \n236\n of the downhole apparatus \n230\n.', 'The downhole feature \n232\n located on the movable member \n234\n may be or comprise one or more grooves, notches, shoulders, or another profile of the movable member \n234\n.', 'The engagement device \n224\n may be or comprise a setting tool or a shifting tool comprising one or more of the engagement members \n226\n, which may be operable to extend outwardly from and retract into the engagement device \n224\n to engage with and disengage from the downhole feature \n232\n of the downhole apparatus \n230\n.', 'The engagement members \n226\n may be operatively connected with and actuated by one or more actuators \n225\n operable to extend and retract the engagement members \n226\n.', 'The actuators \n225\n may be or comprise, for example, hydraulic rams, hydraulic motors, linear electric motors, and rotary electric motors.', 'Accordingly, when the tool string \n200\n is conveyed along the wellbore \n120\n such that the engagement members \n226\n are adjacent the downhole features \n232\n of the downhole apparatus \n230\n that is stuck or intended to be actuated, the engagement device \n224\n may be operated to extend the engagement members \n226\n to engage with the downhole feature \n232\n to connect the engagement device \n224\n with the movable member \n234\n.', 'The engagement members \n226\n may include keys, grooves, or another profile operable to connect, interface, or otherwise engage with the corresponding downhole feature \n232\n.', 'The engagement device \n224\n may further comprise a fishing tool or another tool operable to connect, interface, or otherwise engage with the downhole apparatus \n230\n.', 'Accordingly, the actuator modules \n220\n, \n222\n may be operable to impart the corresponding forces to the downhole apparatus \n230\n via the engagement device \n224\n, when engaged with the downhole feature \n232\n of the downhole apparatus \n230\n, to actuate, move, operate, or dislodge the downhole apparatus \n230\n.', 'Although the engagement members \n226\n are described as being operable to both extend and retract, it is to be understood that the engagement members \n226\n may be or comprise “one-shot” engagement members, operable to extend, but not retract.', 'To disengage such engagement members from the downhole feature \n232\n, the engagement members may be broken or snapped off.', 'The actuator module \n220\n may be operable to axially move at least a portion of the tool string \n200\n, including the actuator module \n222\n and the engagement device \n224\n, along a longitudinal axis \n123\n of the wellbore \n120\n.', 'To facilitate such movement, the actuator module \n220\n may be operable to generate or apply a substantially non-vibrating axial force to the actuator module \n222\n and engagement device \n224\n to move or operate the downhole apparatus \n230\n while the engagement member \n226\n is engaged with the downhole feature \n232\n.', 'The actuator module \n220\n may apply the substantially non-vibrating axial force to the downhole apparatus \n230\n in the form of compression, such as when the actuator module \n220\n increases or moves in the downhole direction against the downhole apparatus \n230\n.', 'The actuator module \n220\n may also or instead apply the substantially non-vibrating axial force to the downhole apparatus \n230\n in the form of tension, such as when the actuator module \n220\n decreases in length or moves in the uphole direction away from the downhole apparatus \n230\n.', 'In an example implementation, the actuator module \n220\n may be a downhole tractor comprising a plurality of tractor drives \n218\n movable outwardly against the sidewall \n126\n to grip the sidewall \n126\n.', 'The tractor drives \n218\n may rotate while in contact with the sidewall \n126\n to move the downhole tractor and, thus, the tool string \n200\n in an intended uphole or downhole direction along the wellbore \n120\n to apply the substantially non-vibrating axial force to the downhole apparatus \n230\n engaged with the engagement device \n224\n.', 'The tractor drives \n218\n may be operatively connected with and actuated by one or more actuators \n219\n operable to extend and rotate the tractor drives \n218\n.', 'The actuators \n219\n may be or comprise, for example, hydraulic rams, hydraulic motors, linear electric motors, and/or rotary electric motors.', 'Accordingly, when the engagement members \n226\n are engaged with the movable member \n234\n of the downhole apparatus \n230\n, the tractor drives \n218\n of the actuator module \n220\n may be operated to move the engagement device \n224\n axially in the uphole or downhole direction to operate or move the downhole apparatus \n230\n as intended.', 'Other types of downhole tractors may also be utilized within the scope of the present disclosure.', 'For example, a downhole tractor utilizing an inchworm principle with two or more sections alternatingly gripping the sidewall \n126\n and resetting may also be utilized to move the tool string \n200\n in an intended direction along the wellbore \n120\n.', 'The actuator module \n222\n may be employed within the tool string \n200\n to perform or assist in the performance of well intervention operations or other downhole operations.', 'The actuator module \n222\n may be coupled between the actuator module \n220\n and the engagement device \n224\n, such as may permit the actuator module \n222\n to augment, supplement, or modify the substantially non-vibrating axial force generated by the actuator module \n220\n and applied to the downhole apparatus \n230\n via the engagement device \n224\n.', 'The actuator module \n222\n may be operable to generate or apply a force to the engagement device in the form of frequency-controlled impulse loads, such as a fluctuating, reciprocating, oscillating, or otherwise vibrating force.', 'Accordingly, the actuator module \n222\n may be operable to apply the vibrating force to the engagement device \n224\n and, thus, the downhole apparatus \n230\n, to move or operate the movable member \n234\n of the downhole apparatus \n230\n.', 'One or more actuators \n223\n of the actuator module \n222\n may generate the vibrating force.', 'The actuators \n223\n may be or comprise hydraulic rams, hydraulic motors, electric motors (linear and/or rotary), and/or other types of actuators.', 'The vibrating force may be an axially vibrating force directed substantially parallel to the longitudinal axis \n123\n of the wellbore \n120\n.', 'The vibrating force may instead or also be a radially vibrating force directed in a radial direction substantially perpendicular to the wellbore axis \n123\n.', 'The vibrating force may instead or also be a rotationally vibrating force directed rotationally around the wellbore axis \n123\n.', 'The actuator module \n222\n may be coupled between the actuator module \n220\n and the engagement device \n224\n.', 'Thus, the actuator module \n220\n may be operable to apply the substantially non-vibrating axial force to the actuator module \n222\n, such that the actuator module \n222\n may be operable to apply a combination of the substantially non-vibrating and vibrating forces to the engagement device \n224\n.', 'During operations, the actuator module \n220\n may be operated before the actuator module \n222\n to operate or move the downhole apparatus \n230\n.', 'If the actuator module \n220\n by itself is unable to or does not operate to move the downhole apparatus, the actuator module \n222\n may be operated in conjunction with the actuator module \n220\n.', 'While operating both actuator modules \n220\n, \n222\n, the substantially non-vibrating force generated by the actuator module \n220\n and the vibrating force generated by the actuator module \n222\n may be simultaneously imparted to the downhole apparatus \n230\n, via the engagement device \n224\n, to collectively move the movable member \n234\n (and, thus, downhole feature \n232\n) between intended positions.', 'Such movement may be to actuate, move, operate, or dislodge the downhole apparatus \n230\n.', 'The power module \n216\n may be operable to provide power to operate the actuator modules \n220\n, \n222\n, the engagement device \n224\n, and/or one or more other modules and/or portions of the tool string \n200\n.', 'For example, the power module \n216\n may be or comprise a hydraulic power pack, which may be operable to supply hydraulic power to the actuator modules \n220\n, \n222\n and the engagement device \n224\n.', 'The hydraulic power pack may provide a pressurized fluid to the one or more actuators \n219\n of the actuator module \n220\n to extend and rotate the drives \n218\n, such as may facilitate movement of the actuator module \n220\n along the wellbore \n120\n.', 'The hydraulic power pack may further provide the pressurized fluid to the one or more actuators \n223\n of the actuator module \n222\n to generate the vibrating force.', 'The hydraulic power pack may also provide the pressurized fluid to the one or more actuators \n225\n of the engagement device \n224\n to outwardly extend the engagement members \n226\n against the downhole feature \n232\n of the downhole apparatus \n230\n.', 'The power module \n216\n may also or instead be or comprise an electrical power source, such as a battery.', 'In such implementations, the battery may provide electrical power to the actuators \n219\n, \n223\n, \n225\n to operate the actuator modules \n220\n, \n222\n and the engagement device \n224\n as described above.', 'The power module \n216\n may also be omitted from the tool string \n200\n, such as in implementations in which hydraulic and/or electrical power may be provided from the wellsite surface \n105\n via the conveyance means \n171\n.', 'FIG.', '3\n is a schematic view of an example implementation of the tool string \n110\n shown in \nFIG.', '1\n according to one or more aspects of the present disclosure, and designated in \nFIG.', '3\n by reference number \n201\n.', 'The tool string \n201\n comprises one or more similar features of the tool string \n200\n shown in \nFIG.', '2\n, including where indicated by like reference numbers, except as described below.', 'Similarly as in \nFIG.', '2\n, the tool string \n201\n is shown disposed within the substantially horizontal portion \n121\n of the wellbore \n120\n and connected with the surface equipment \n175\n via the conveyance means \n171\n.', 'However, it is to be understood that the tool string \n201\n may also be utilized within a substantially vertical or otherwise deviated portion of the wellbore \n120\n.', 'The following description refers to \nFIGS.', '1, 2, and 3\n, collectively.', 'The substantially non-vibrating force applied to the engagement device \n224\n may be generated by means other than the actuator module \n220\n of the tool string \n200\n.', 'For example, instead of or in addition to the actuator module \n220\n, the tool string \n201\n may comprise an actuator module \n260\n operable to anchor the tool string \n201\n against the sidewall \n126\n of the casing \n124\n, and an actuator module \n270\n operable to impart the substantially non-vibrating force to the engagement device \n224\n.', 'The actuator module \n260\n may comprise gripping members \n262\n located on opposing sides of the actuator module \n260\n.', 'The gripping members \n262\n may be operable to extend outwardly against the sidewall \n126\n to grip the casing \n124\n to lock or maintain at least a portion of the tool string \n201\n in a fixed position within the wellbore \n120\n.', 'The actuator module \n260\n may comprise one or more actuators \n264\n operable to extend and retract the gripping members \n262\n into and from engagement with the sidewall \n126\n.', 'The actuator \n264\n may be implemented as a hydraulic ram or motor, an electric actuator or motor, and/or other actuators.', 'The actuator module \n270\n may be or comprise a linear actuator, such as a ram or stroker tool.', 'The actuator module \n270\n may comprise a static portion \n272\n connected with a movable portion \n274\n via an intermediate shaft \n276\n.', 'The movable portion \n274\n may be operable to move axially with or about the shaft \n276\n substantially parallel to the wellbore axis \n123\n to impart the substantially non-vibrating axial force to the engagement device \n224\n.', 'The actuator module \n270\n may comprise one or more actuators \n278\n operable to actuate the axial movement of the movable portion \n274\n.', 'For example, the actuator \n278\n may be a hydraulic pump operable to pressurize hydraulic fluid to power the actuator module \n270\n.', 'The actuator \n264\n may also be implemented as an electric linear actuator or motor operable to impart movement to the shaft \n276\n and/or the movable portion \n274\n.', 'Accordingly, when the engagement members \n226\n are engaged with the movable member \n234\n of the downhole apparatus \n230\n, the gripping members \n262\n of the actuator module \n260\n may be operated to lock the static portion \n272\n of the actuator module \n270\n in position, and then the actuator module \n260\n may be operated to move the movable portion \n274\n and the engagement device \n224\n axially in the uphole or downhole direction to operate or move the downhole apparatus \n230\n as intended.', 'Similarly to as described above with respect to the tool string \n200\n, the power module \n216\n may be operable to provide power to operate the actuator modules \n260\n, \n270\n, \n222\n, the engagement device \n224\n, and/or one or more other modules and/or portions of the tool string \n201\n.', 'For example, when implemented as a hydraulic power pack, the power module \n216\n may be operable to supply hydraulic power to the actuators \n264\n, \n278\n, \n223\n, \n225\n to operate the actuator modules \n260\n, \n270\n, \n222\n and the engagement device \n224\n, as described above.', 'When implemented as an electrical power source, the power module \n216\n may be operable to supply electrical power to the actuators \n264\n, \n278\n, \n223\n, \n225\n to operate the actuator modules \n260\n, \n270\n, \n222\n and the engagement device \n224\n, as described above.', 'The power module \n216\n may also be omitted from the tool string \n201\n, such as in implementations in which hydraulic or electrical power may be provided from the wellsite surface \n105\n via the conveyance means \n171\n.', 'FIGS.', '4 and 5\n are schematic views of at least a portion of an example implementation of the downhole apparatus \n230\n and the engagement device \n224\n shown in \nFIGS.', '2 and 3\n and at different stages of operation.', 'The following description refers to \nFIGS.', '1-5\n, collectively.', 'FIGS.', '4 and 5\n show the downhole apparatus \n230\n implemented as a downhole valve assembly \n240\n disposed within a downhole tubular assembly \n242\n and operable to shut off or otherwise limit fluid flow through the tubulars \n242\n.', 'The valve assembly \n240\n comprises a movable sleeve \n244\n operatively connected with a ball member \n246\n via a bracket \n248\n pivotally connected with the ball member \n246\n.', 'The ball member \n246\n is maintained in position by packing members \n250\n of the downhole valve assembly \n240\n.', 'The movable sleeve \n244\n includes a downhole feature \n252\n comprising a groove and a protrusion receiving, accommodating, or otherwise engaging with the engagement members \n226\n of the engagement device \n224\n.', 'The ball member \n246\n comprises a bore \n258\n or fluid pathway extending therethrough, and may be operated or rotated to selectively permit, prevent, or otherwise limit fluid flow through the valve assembly \n240\n via operation or movement of the movable sleeve \n244\n.', 'FIG.', '4\n shows the movable sleeve \n244\n in a first or initial position and the ball member \n246\n in a closed-flow position, while \nFIG.', '5\n shows the movable sleeve \n244\n in a second or final position and the ball member \n246\n in an open-flow position.', 'Accordingly, to operate the valve assembly \n240\n to the open-flow position, the engagement device \n224\n may be moved in the downhole direction from the initial position to the final position, and to operate the valve assembly \n240\n to the closed-flow position, the engagement device \n224\n may be moved in the uphole direction from the final position to the initial position.', 'As further shown in \nFIGS. 4 and 5\n, the engagement device \n224\n or another portion of the tool string \n110\n may include an accelerometer \n257\n, which may be operable to generate a signal or information indicative of acceleration, shock, and/or forces imparted to the engagement device \n224\n.', 'The signal generated by the accelerometer \n257\n may be communicated to the controllers \n178\n, \n214\n and utilized to monitor the acceleration, mechanical shock, and/or forces imparted to the movable sleeve \n244\n by the actuator modules \n220\n, \n270\n, \n222\n during operations.', 'The accelerometer \n257\n may comprise a one, two, or three-axis accelerometer operable to measure axial and/or lateral acceleration and deceleration of the engagement device \n224\n.', 'Implementations within the scope of the present disclosure may also comprise multiple instances of the accelerometer \n257\n, including implementations in which each accelerometer \n257\n may detect a different range of acceleration.', 'The accelerometer \n257\n may be mounted to a wall or housing of the engagement device \n224\n.', 'The engagement device \n224\n or another portion of the tool string \n110\n may also include a load cell \n259\n, which may be operable to generate a signal or information indicative of the forces imparted to the engagement device \n224\n.', 'The signal generated by the load cell \n259\n may be communicated to the controllers \n178\n, \n214\n and utilized to monitor the force imparted to the movable sleeve \n244\n by the actuator modules \n220\n, \n222\n, \n260\n during operations.', 'Implementations within the scope of the present disclosure may also comprise multiple instances of the load cell \n259\n, such as may be operable to measure axial forces, radial forces, and/or rotational forces or torque imparted to the movable sleeve \n244\n.', 'The load cell \n259\n may be or comprise a Wheatstone bridge strain gauge.', 'The load cell \n259\n may be mounted to the wall or housing of the engagement device \n224\n.', 'During certain downhole applications of the wellsite system \n100\n, increasing the substantially non-vibrating axial force applied by the tensioning device \n170\n or the actuator modules \n220\n, \n270\n may not be sufficient to actuate, move, operate, or dislodge the downhole apparatus \n230\n or may be detrimental to the downhole apparatus \n230\n or the tool string \n200\n, \n201\n.', 'For example, material buildup or contaminants, such as rock particles, sand, proppants, or other debris, may seize portions of the downhole apparatus \n230\n, such as the movable member \n234\n, wherein applying an increasing amount of the substantially non-vibrating axial force to the downhole apparatus \n230\n may cause material fatigue or damage to portions of the downhole apparatus \n230\n or the tool string \n200\n, \n201\n.', 'For example, debris may become lodged between the movable sleeve \n244\n and the tubing assembly \n242\n, between the ball member \n246\n and the packing members \n250\n, and/or between other movable portions of the valve assembly \n240\n to increase frictional forces between such movable portions.', 'Simply increasing the substantially non-vibrating axial force applied to the movable sleeve \n244\n via the engagement device \n224\n may exacerbate the problem by further jamming or seizing the movable sleeve \n244\n against the tubing assembly \n242\n and/or seizing the ball member \n246\n against the packing members \n250\n.', 'Increasing the substantially non-vibrating axial force may also damage portions of the valve assembly \n240\n, such as the bracket \n248\n connecting the ball member \n246\n and the movable sleeve \n244\n.', 'By applying the axially, radially, and/or rotationally vibrating forces in conjunction with the substantially non-vibrating axial force, the debris and/or material buildup may be loosened, broken up, or dispersed away from the movable sleeve \n244\n, the ball member \n246\n, and/or other movable members of the valve assembly \n240\n to free the movable sleeve \n244\n, the ball member \n246\n, and/or other movable members of the valve assembly \n240\n, permitting the substantially non-vibrating axial force to operate or move the valve assembly \n240\n.', 'The vibrating force may further assist in overcoming static friction of the movable members, such as caused by the material buildup.', 'Accordingly, the combination of the substantially non-vibrating axial force and vibrating force may permit use of a relatively low or substantially lower non-vibrating axial force to operate the valve assembly \n240\n compared to the magnitude of the non-vibrating axial force utilized when no vibrating force is applied.', 'Accordingly, use of lower non-vibrating axial force in conjunction with the vibrating force may decrease the chances of damaging or seizing the valve assembly \n240\n.\n \nFIG.', '6\n is a schematic view of a portion of an example implementation of the actuator module \n270\n of the tool string \n201\n shown in \nFIG.', '3\n, designated in \nFIG.', '6\n by numeral \n300\n, and operable to generate or apply the substantially non-vibrating axial force according to one or more aspects of the present disclosure.', 'The actuator module \n300\n comprises one or more similar features of the actuator module \n270\n, including where indicated by like reference numbers, except as described below.', 'The following description refers to \nFIGS.', '3 and 6\n, collectively.', 'The actuator module \n300\n may comprise the static portion \n272\n connected to the movable portion \n274\n via the intermediate shaft \n276\n.', 'The movable portion \n274\n may be operable to move axially, as indicated by arrows \n301\n, \n302\n, about the shaft \n276\n and a cylinder \n304\n connected with the shaft \n276\n to impart the substantially non-vibrating force to the engagement device \n224\n.', 'The actuator module \n300\n is further shown comprising the actuator \n278\n operable to cause the axial movement of the movable portion \n274\n.', 'The actuator \n278\n is shown implemented as an assembly comprising an electrical motor \n306\n connected with and operable to rotate a hydraulic pump \n308\n via a drive shaft \n309\n to pressurize hydraulic fluid.', 'When powered by electrical power received from the power module \n216\n or the wellsite surface \n105\n, the motor \n306\n may actuate the pump \n308\n to pressurize and discharge the hydraulic fluid through a fluid directional control valve \n310\n.', 'To move the movable portion \n274\n away from the static portion \n272\n, as indicated by the arrow \n301\n, the valve \n310\n may direct the hydraulic fluid into a rear volume \n312\n of the movable portion \n274\n via a fluid conduit \n314\n and evacuate the hydraulic fluid from a front volume \n316\n of the movable portion \n274\n via a fluid conduit \n318\n.', 'To move the movable portion \n274\n toward the static portion \n272\n, as indicated by the arrow \n302\n, the valve \n310\n may direct the hydraulic fluid into the front volume \n316\n of the movable portion \n274\n via a fluid conduit \n318\n and evacuate the hydraulic fluid from the rear volume \n312\n of the movable portion \n274\n via the fluid conduit \n314\n.', 'The actuator module \n300\n may further comprise one or more rotary sensors \n307\n operable to generate a signal or information indicative of rotational position, rotational speed, and/or operating frequency of the motor \n306\n.', 'For example, the rotary sensor \n307\n may be operable to convert angular position or motion of the drive shaft \n309\n or another rotating portion of the motor \n306\n to an electrical signal indicative of pumping speed of the pump \n308\n and, thus, the axial velocity and/or position of the movable portion \n274\n of the actuator module \n300\n.', 'The rotary sensor \n307\n may be mounted in association with an external portion of the drive shaft \n309\n or other rotating members of the motor \n306\n.', 'The rotary sensor \n307\n may also or instead be mounted in association with the pump \n308\n to monitor rotational position and/or rotational speed of the pump \n308\n.', 'Although not shown in \nFIG.', '2\n, the actuator module \n220\n may also comprise one or more rotary sensors \n307\n mounted in association with the actuator \n219\n, such as may permit the monitoring of the operating speed of the actuator \n219\n and, thus, the position and/or velocity of the actuator module \n220\n along the wellbore \n120\n.', 'The rotary sensor \n307\n may be or comprise an encoder, a rotary potentiometer, a synchro, a resolver, and/or an RVDT, among other examples.', 'The actuator module \n300\n may also include motor power and/or control components, such as a variable speed or frequency drive (VFD) (not shown), which may be utilized to facilitate control of the motor \n306\n by the controllers \n178\n, \n214\n.', 'The VFD may be connected with or otherwise in communication with the motor \n306\n and the controllers \n178\n, \n214\n via electrical communication means.', 'The VFD may receive control signals from the controllers \n178\n, \n214\n and output corresponding electrical power to the motor \n306\n to control the speed and the torque output of the motor \n306\n and, thus, control the pumping speed and fluid flow rate of the pump \n308\n, as well as the maximum pressure generated by the pump \n308\n.', 'Although the VFD may be located within the actuator module \n300\n, the VFD may be located or disposed at a distance from the motor \n306\n.', 'For example, the VFD may be located within the power module \n216\n and/or the power and control system \n172\n.', 'The actuator module \n300\n may further comprise one or more linear sensors \n311\n operable to generate a signal or information indicative of the axial position and/or velocity of the movable portion \n274\n, such as to monitor the position and/or velocity of the engagement device \n224\n with respect to the static portion \n272\n.', 'The sensor \n311\n may be disposed in association with the movable portion \n274\n in a manner permitting sensing of the position and/or velocity of the movable portion \n274\n.', 'For example, the sensor \n311\n may be disposed through the piston \n304\n to monitor relative position and/or velocity of a magnet or another marker \n313\n carried with the piston \n304\n.', 'The sensor \n311\n may be or comprise a linear encoder, a linear potentiometer, a capacitive sensor, an inductive sensor, a magnetic sensor, a linear variable-differential transformer (LVDT), a proximity sensor, a Hall effect sensor, and/or a reed switch, among other examples.', 'The rotary and/or linear sensors \n307\n, \n311\n may facilitate monitoring or recording by the controllers \n178\n, \n214\n the speed and/or position of the movable member \n234\n of the downhole apparatus \n230\n, such as to monitor the speed at which the downhole apparatus is being operated or whether the downhole apparatus \n230\n has been fully opened or closed.', 'Accordingly, the actuator modules \n220\n, \n270\n may be operated in real-time based on feedback or information generated by the rotary and linear sensors \n307\n, \n311\n.', 'Instead of or in addition to utilizing the actuator module \n220\n shown in \nFIG.', '2\n or the actuator module \n270\n shown in \nFIG.', '3\n, the substantially non-vibrating axial force applied to the engagement device \n224\n may be generated or applied from the wellsite surface \n105\n by the tensioning device \n170\n via the conveyance means \n171\n.', 'However, when utilizing a wireline, a slickline, an e-line, the tool string \n200\n, \n201\n may be limited to applying a tensile force in the uphole direction, as opposed to coiled tubing, drill pipe, and production tubing, which may be utilized to also apply a compressive force in the downhole direction.', 'Accordingly, the when forces generated by the tensioning means are not sufficient to operate the downhole apparatus \n230\n or perform other operations, the actuator module \n222\n may be activated to introduce the vibrating force, such as may aid to operate or move the downhole apparatus \n230\n or perform other operations.', 'FIGS.', '7-14\n are schematic views of a portion of example implementations of the actuator module \n222\n of the tool strings \n200\n, \n201\n shown in \nFIGS.', '2 and 3\n according to one or more aspects of the present disclosure.', 'FIGS.', '7-14\n show one or more similar features of the actuator module \n222\n shown in \nFIGS.', '2 and 3\n, including where indicated by like reference numbers, except as described below.', 'The following description refers to \nFIGS.', '2, 3, and 7-14\n, collectively.', 'FIG.', '7\n shows a portion of an example implementation of the actuator module \n222\n, designated in \nFIG.', '7\n by numeral \n320\n, operable to generate or apply the axially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module \n320\n may comprise the actuator \n223\n, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a rotor \n321\n via a shaft \n322\n, such as may facilitate rotation of the rotor \n321\n about an axis of rotation \n319\n.', 'The rotor \n321\n may comprise a profile comprising alternating recesses or slots \n323\n and shoulders or protrusions \n324\n.', 'The rotor \n321\n may be aligned against a stator or contact member \n325\n such that the alternating slots \n323\n and protrusions \n324\n engage corresponding alternating slots \n326\n and protrusions \n327\n of the contact member \n325\n.', 'The contact member \n325\n may be connected with a body, chassis, or housing \n328\n of the actuator module \n320\n via a biasing member \n329\n.', 'During operations of the actuator module \n320\n, as the actuator \n223\n is rotating the rotor \n321\n, the alternating slots \n323\n and protrusions \n324\n of the rotor \n321\n may be operable to engage the corresponding alternating slots \n326\n and protrusions \n327\n of the contact member \n325\n to axially move the contact member \n325\n away from the actuator \n223\n, as indicated by the arrow \n301\n, and permit the biasing member \n329\n to move the contact member \n325\n toward the actuator \n223\n, as indicated by arrow \n302\n, resulting in the contact member \n325\n moving in a vibrating manner.', 'The vibrating (i.e., inertial) forces imparted to the contact member \n325\n may be transmitted to the housing \n328\n of the actuator module \n320\n via the biasing member \n329\n.', 'Also, the axis of rotation \n319\n may substantially coincide with or extend parallel to the axis \n123\n of the wellbore \n120\n, such that the axially vibrating force may be directed along or parallel to the axis \n123\n of the wellbore \n120\n.', 'The axially vibrating force may then be transferred to the engagement device \n224\n connected with the actuator module \n320\n.', 'In an example implementation of the actuator module \n320\n, the stator \n321\n and the contact member \n325\n may be or comprise complementary face type or crown gears and the alternating slots \n323\n, \n326\n and protrusions \n324\n, \n327\n may be or comprise teeth that are smooth and rounded to assist in slippage.', 'The gear profiles, number of gears, and the spring constant of the biasing member \n329\n may be adjusted to control the vibrating force.', 'FIG.', '8\n shows a portion of an example implementation of the actuator module \n222\n, designated in \nFIG.', '8\n by numeral \n330\n, operable to generate or apply the axially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module \n330\n may comprise the actuator \n223\n, such as a piezoelectric actuator, comprising a piezoelectric element \n332\n, such as a quartz crystal, operable to vibrate axially when an alternating electrical field is applied.', 'One side of the piezoelectric element \n332\n may be fixedly connected with a body, chassis, or housing \n334\n of the actuator module \n330\n via a base \n336\n and an opposing side of the piezoelectric element \n332\n may be connected with a ballast member \n337\n comprising a predetermined mass.', 'During operations, when the electric field is applied to a selected face of the piezoelectric element \n332\n, a mechanical distortion of the piezoelectric element \n332\n occurs along an axis \n331\n generating a force to move the ballast member \n337\n along the axis \n331\n.', 'When the electric field is alternated or continuously turned on and off, the piezoelectric element \n332\n alternatingly extends and retracts to generate an alternating or vibrating force against the ballast member \n337\n to alternatingly extend and retract or vibrate the ballast member \n337\n along the axis \n331\n, as indicates by arrows \n301\n, \n302\n.', 'The vibrating (i.e., inertial) forces imparted to ballast member \n337\n may be transmitted to the housing \n334\n via the piezoelectric element \n332\n and then to the engagement device \n224\n connected with the actuator module \n330\n.', 'The axis \n331\n may substantially coincide with or extend parallel to the axis \n123\n of the wellbore \n120\n, such that the vibrating force may be directed axially along or parallel to the axis \n123\n of the wellbore \n120\n.', 'The axis \n331\n may extend perpendicularly to the axis \n123\n of the wellbore \n120\n, such that the vibrating force may be directed radially with respect to the axis \n123\n of the wellbore \n120\n.', 'The frequency of the vibrating force generated by the actuator module \n330\n may be adjusted by controlling the frequency at which the voltage is applied to the piezoelectric element \n332\n.', 'FIGS.', '9 and 10\n show top and axial views of a portion of an example implementation of the actuator module \n222\n, designated in \nFIGS.', '9 and 10\n by numeral \n340\n, operable to generate or apply the rotationally vibrating force according to one or more aspects of the present disclosure.', 'The actuator module \n340\n may comprise the actuator \n223\n, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a gear or rotor \n341\n via a shaft \n342\n, such as may facilitate rotation of the rotor \n341\n about an axis of rotation \n346\n.', 'The rotor \n341\n may have a profile comprising a plurality of alternating teeth, protrusions, or shoulders \n343\n and recesses or slots \n344\n, such as may be operable to alternatingly engage and disengage one or more contact members \n345\n to move and release the contact member \n345\n along a vector perpendicular to and offset from the axis of rotation \n346\n, as indicated by arrow \n347\n.', 'The contact member \n325\n may be connected with a body, chassis, or housing \n348\n of the actuator module \n320\n via a biasing member \n349\n.', 'During operations of the actuator module \n340\n, as the actuator \n223\n is rotating the rotor \n341\n, the shoulders \n343\n and the slots \n345\n may be operable to alternatingly push the contact member \n345\n toward the housing \n348\n of the actuator module \n340\n, compressing the biasing member \n349\n, and release the contact member \n345\n, permitting the biasing member \n349\n to return the contact member \n345\n to its natural position.', 'The vibrating (i.e., inertial) force imparted to the contact member \n345\n may be imparted to the housing \n348\n via the biasing member \n349\n along the vector perpendicular to and offset from the axis of rotation \n346\n or otherwise around the axis of rotation \n346\n, as indicated by the arrow \n347\n.', 'The axis of rotation \n346\n may substantially coincide with or extend parallel to the axis \n123\n of the wellbore \n120\n, such that the rotationally vibrating force may be directed around the axis \n123\n or tangentially with respect to the axis \n123\n.\n \nFIGS.', '11 and 12\n show side and axial views of a portion of an example implementation of the actuator module \n222\n, designated in \nFIGS.', '11 and 12\n by numeral \n350\n, operable to generate or apply the radially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module \n350\n may comprise the actuator \n223\n, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a gear or rotor \n351\n via a shaft \n352\n, such as may facilitate rotation of the rotor \n351\n about an axis of rotation \n356\n.', 'The rotor \n351\n may have a profile comprising a plurality of alternating teeth, protrusions, or shoulders \n353\n and recesses or slots \n354\n, such as may be operable to alternatingly engage and disengage a plurality of contact members \n355\n to move the contact members \n355\n along corresponding vectors extending radially or perpendicularly with respect to the axis of rotation \n356\n, as indicated by arrows \n357\n.', 'The contact members \n355\n may be connected with a body, chassis, or housing \n358\n of the actuator module \n350\n via corresponding biasing members \n359\n.', 'During operations of the actuator module \n350\n, as the actuator \n223\n is rotating the rotor \n351\n, the shoulders \n353\n and the slots \n355\n may be operable to alternatingly push the contact members \n355\n toward the housing \n358\n of the actuator module \n350\n, compressing the biasing members \n359\n, and release the contact members \n355\n, permitting the biasing members \n359\n to return the contact members \n355\n to their natural positions.', 'The contacting members \n355\n and the shoulders \n353\n of the stator \n351\n may be configured such that each of the contact members \n355\n is movable radially at different times and in different radial directions with respect to the axis of rotation \n356\n during each vibration iteration or cycle as the stator \n351\n is rotated, as indicated by the arrows \n357\n.', 'The vibrating (i.e., inertial) force imparted to the contact members \n355\n may be imparted to the housing \n358\n via corresponding biasing members \n359\n, as indicated by the arrows \n357\n.', 'The axis of rotation \n356\n may substantially coincide with or extend parallel to the axis \n123\n of the wellbore \n120\n, such that the radially vibrating force may be directed in a plurality of radial directions with respect to the axis \n123\n of the wellbore \n120\n.\n \nFIGS.', '13 and 14\n show side and axial views of a portion of an example implementation of the actuator module \n222\n, designated in \nFIGS.', '13 and 14\n by numeral \n360\n, operable to generate or apply the radially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module \n360\n may comprise the actuator \n223\n, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a rotor \n361\n via a shaft \n362\n, such as may facilitate rotation of the rotor \n361\n about an axis of rotation \n366\n.', 'The actuator \n223\n may be fixedly connected with a body, chassis, or housing \n368\n of the actuator module \n360\n.', 'The rotor \n351\n may be asymmetrical, comprise an asymmetrical mass distribution, or may be connected with the shaft \n362\n at a point that is not the center of mass of the rotor \n361\n.', 'Accordingly, when rotated by the actuator \n223\n, a centrifugal or rotating inertial force may be generated along a radial direction away from the axis of rotation \n366\n, as indicated by an arrow \n367\n.', 'The radial force may be directed through a center of mass \n363\n of the rotor \n361\n.', 'Accordingly, the inertial force may continuously change direction as the center of mass \n363\n of the rotor \n361\n changes direction with the rotating rotor \n361\n.', 'The continuously changing inertial force may be transmitted to the actuator \n223\n, causing the actuator \n223\n to vibrate radially \n223\n with respect to the axis of rotation \n366\n.', 'The radially vibrating force may then be transmitted to the housing \n368\n and the engagement device \n224\n connected with the actuator module \n330\n.', 'The axis of rotation \n366\n may substantially coincide with or extend parallel to the axis \n123\n of the wellbore \n120\n, such that the radially vibrating force may be directed radially with respect to the axis \n123\n of the wellbore \n120\n.', 'The speed of the actuators \n223\n of the actuator modules \n320\n, \n340\n, \n350\n, \n360\n may be adjusted to control frequencies of the corresponding axial, rotational, and radial vibrations, which may be proportional to the rotational speed of the actuator \n223\n.', 'Accordingly, each of the actuator modules \n320\n, \n340\n, \n350\n, \n360\n may further comprise one or more rotary sensors \n307\n operable to generate a signal or information indicative of rotational position, rotational speed, and/or operating frequency of the actuator \n223\n.', 'Both the rotary sensor \n307\n and the actuator \n223\n may be in communication with one or more of the controllers \n178\n, \n214\n, such as may permit the one or more of the controllers \n178\n, \n214\n to control the rotational speed of the actuator \n223\n.', 'The actuators \n223\n of the actuator modules \n320\n, \n330\n, \n340\n, \n350\n, \n360\n may be operated to produce the vibrating forces at a relatively low frequency of about one hertz and up to a relatively high frequency of about 500 hertz or more.', 'Although the actuator modules \n320\n, \n330\n, \n340\n, \n350\n, \n360\n are shown as separate devices, it is to be understood that two or more of the actuator modules \n320\n, \n330\n, \n340\n, \n350\n, \n360\n may be incorporated as part of the actuator module \n222\n shown in \nFIGS.', '2 and 3\n within the scope of the present disclosure.', 'Accordingly, the actuator module \n222\n may be operable to generate or apply two or more of the axially, rotationally, and radially vibrating forces to the engagement device \n224\n and the downhole apparatus \n230\n.', 'Furthermore, although the actuator module \n222\n is shown in \nFIGS.', '2 and 3\n as separate devices from the actuator modules \n220\n, \n270\n, it is to be understood that the actuator module \n222\n and the actuator modules \n220\n, \n270\n may be incorporated into a single module within the scope of the present disclosure.', 'Accordingly, combined actuator module may be operable to generate or apply the substantially non-vibrating axial force and one or more of the axially, rotationally, and radially vibrating forces to the engagement device \n224\n and the downhole apparatus \n230\n.', 'In addition to controlling the frequency of the vibrating forces, magnitude and direction of the substantially non-vibrating axial force and vibrating forces may also be controlled.', 'FIGS.', '15-17\n are graphs showing example axial force profiles or curves representing the substantially non-vibrating axial force and the axially vibrating force generated by the actuator modules \n220\n, \n270\n, \n222\n shown in \nFIGS.', '2 and 3\n during operations.', 'The graphs depict magnitude of the axial forces along the vertical axes, with respect to time, shown along the horizontal axes.', 'The horizontal axes indicate a point at which the axial force is zero, such that curves or portions of the curves located on opposing sides of the horizontal axes indicate axial forces applied in opposing directions.', 'Graph \n370\n shows a curve \n371\n representing the substantially non-vibrating axial force generated or applied by the actuator module \n220\n, \n270\n in one direction (i.e., uphole or downhole) and a curve \n372\n representing the axially vibrating force generated or applied by the actuator module \n222\n in opposing directions (i.e., uphole and downhole).', 'The graph further shows a curve \n373\n representing a cumulative axial force applied to the engagement device \n224\n, comprising both the substantially non-vibrating axial force \n371\n and the axially vibrating force \n372\n.', 'As the magnitude of the substantially non-vibrating axial force \n371\n is substantially greater that the magnitude of the axially vibrating force \n372\n, the cumulative axial force \n373\n is shown continuously fluctuating on one side of the horizontal axis, indicating that the cumulative axial force \n373\n is applied to the downhole apparatus \n230\n in one direction (i.e., uphole or downhole) during operations.', 'Graph \n375\n shows a curve \n376\n representing the substantially non-vibrating axial force generated or applied by the actuator module \n220\n, \n270\n in one direction and a curve \n377\n representing the axially vibrating force generated or applied by the actuator module \n222\n in opposing directions.', 'The graph further shows a curve \n378\n representing a cumulative axial force applied to the engagement device \n224\n, comprising both the substantially non-vibrating axial force \n376\n and the axially vibrating force \n377\n.', 'Although the axially vibrating force \n377\n is substantially larger than the axially vibrating force \n372\n shown in graph \n370\n, the magnitude of the substantially non-vibrating axial force \n376\n is still greater that the magnitude of the axially vibrating force \n377\n.', 'Accordingly, the cumulative axial force \n378\n is shown continuously fluctuating on one side of the horizontal axis, indicating that the cumulative axial force \n378\n is applied to the downhole apparatus \n230\n in one direction during operations.', 'Graph \n380\n shows a curve \n381\n representing the substantially non-vibrating axial force generated or applied by the actuator module \n220\n, \n270\n in one direction and a curve \n382\n representing the axially vibrating force generated or applied by the actuator module \n222\n in opposing directions.', 'The graph further shows a curve \n383\n representing a cumulative axial force applied to the engagement device \n224\n, comprising both the substantially non-vibrating axial force \n381\n and the axially vibrating force \n382\n.', 'Unlike the vibrating forces \n372\n, \n377\n shown in graphs \n370\n, \n375\n, the magnitude of the axially vibrating force \n382\n is substantially greater that the magnitude of the non-vibrating axial force \n381\n.', 'Accordingly, the cumulative axial force \n383\n extends on both sides of the horizontal axis, indicating that the cumulative axial force \n383\n is continuously fluctuating in opposing axial directions (i.e., uphole and downhole) to apply the vibrating force to the downhole apparatus \n230\n in the opposing axial directions along the axis \n123\n.', 'Magnitude and direction of the rotationally and radially vibrating forces may also be controlled.', 'FIG.', '18\n is a graph \n384\n showing example rotationally and radially vibrating force profiles or curves generated by the actuator module \n222\n shown in \nFIGS.', '2 and 3\n during operations.', 'The graph \n384\n shows the magnitude of the vibrating forces along a vertical axis, with respect to time, shown along a horizontal axis.', 'The horizontal axis indicates a point at which the magnitude of the vibrating force is zero, such that curves or portions of the curves located on opposing sides of the horizontal axis indicate forces in opposing directions.', 'The rotationally and radially vibrating forces may continuously vary or fluctuate in a single direction during operations, as shown by curve \n385\n.', 'For example, the radially vibrating force may be applied laterally in a single direction with respect to the wellbore axis \n123\n and the rotationally vibrating force may be applied in a single direction (i.e., clockwise or counter-clockwise) with respect to the wellbore axis \n123\n.', 'The rotationally and radially vibrating forces may continuously vary or fluctuate in opposing directions during operations, as shown by curve \n386\n.', 'For example, the radially vibrating force may be applied laterally in opposing directions with respect to the wellbore axis \n123\n and the rotationally vibrating force may be applied in opposing directions (i.e., clockwise and counter-clockwise) with respect to the wellbore axis \n123\n.', 'The magnitude of the vibrating forces shown in \nFIGS.', '15-18\n may be controlled by various means.', 'For example, controlling the rotating speed of the actuator \n223\n may control the force at which the rotors \n321\n, \n341\n, \n351\n, \n361\n push or impact the contact members \n325\n, \n345\n, \n355\n to vary the inertial forces imparted to the contact members \n325\n, \n345\n, \n355\n.', 'Varying the mass of the contact members \n325\n, \n345\n, \n355\n, the rotor \n361\n, and the ballast member \n337\n may also vary the inertial forces imparted to the contact members \n325\n, \n345\n, \n355\n, the rotor \n361\n, and the ballast member \n337\n.', 'Varying the spring constant or stiffness of the biasing members \n329\n, \n349\n, \n359\n may vary the amount of the inertial forces transmitted from the contact members \n325\n, \n345\n, \n355\n to the corresponding housings \n328\n, \n348\n, \n358\n.', 'As described above, the continuously changing inertial forces imparted to portions of the actuator modules \n320\n, \n330\n, \n340\n, \n350\n, \n360\n may be transmitted to the corresponding housings \n328\n, \n334\n, \n348\n, \n358\n, \n368\n and to the engagement device \n222\n as vibrating forces.', 'Accordingly, the magnitudes of the vibrating forces may be controlled by adjusting the magnitudes of the inertial forces.', 'Although the substantially non-vibrating axial force is described above as being generated or applied by the actuator modules \n220\n, \n270\n in a single direction, the actuator modules \n220\n, \n270\n may also generate or apply the substantially non-vibrating axial force alternatingly in opposing directions to the engagement device \n224\n.', 'Such alternating axial force may be utilized in conjunction with or without the vibrating force generated or applied by the actuator module \n222\n.', 'FIG.', '19\n is a graph \n388\n showing an example profile or curve \n390\n indicative of an axial movement of the engagement member \n226\n or another portion of the engagement device \n224\n and, thus, movement of the movable member \n234\n of the downhole apparatus \n230\n, while being actuated by the actuator modules \n220\n, \n270\n.', 'The engagement device \n224\n, the downhole apparatus \n230\n, and the actuator modules \n220\n, \n270\n are shown in \nFIGS.', '2 and 3\n.', 'Accordingly, the following description refers to \nFIGS.', '2, 3, and 19\n, collectively.', 'The vertical axis of the graph \n388\n indicates axial position of the engagement member \n226\n and the movable member \n234\n connected with the engagement member \n226\n along the wellbore \n120\n and the horizontal axis \n391\n indicates time.', 'The horizontal \n391\n axis also indicates a first or starting position of the downhole feature \n232\n or another portion of the movable member \n234\n when initially engaged by the engagement members \n226\n, while a horizontal line \n392\n indicates a second or final position of the downhole feature \n232\n or another portion of the movable member \n234\n.', 'The distance between the first and second positions \n391\n, \n392\n of the movable member \n234\n may be a distance sufficient to actuate or operate the downhole apparatus \n230\n.', 'As the curve \n390\n indicates, the actuator modules \n220\n, \n270\n may be operated to move the engagement device \n224\n and the engaged movable member \n234\n of the downhole apparatus \n230\n axially from the first position \n391\n to the second position \n392\n while also alternating the direction of movement of the movable member \n234\n in opposing axial directions.', 'For example, the actuator modules \n220\n, \n270\n may be operated to impart a force alternating in opposing axial directions (i.e., uphole and downhole) to the engagement device \n224\n to operate or move the downhole apparatus \n230\n alternatingly in opposing axial directions while the engagement members \n226\n are engaged with the downhole feature \n232\n.', 'Some of the alternating movements may be of different distances to achieve a net repositioning of the movable member \n234\n and the downhole feature \n232\n in one of the opposing axial directions (i.e., uphole or downhole) from the first position \n391\n to the second position \n392\n.', 'For example, each successive movement in a first axial direction (i.e., uphole or downhole) may move the movable member \n234\n and the downhole feature \n232\n closer to the second position \n392\n than resulted from a previous movement in the first axial direction, while successive movements in a second axial direction, opposite the first axial direction, may comprise substantially the same distance.', 'The net repositioning of the movable member \n234\n and the downhole feature \n232\n may be an average movement of the alternating opposing axial movements of the movable member \n234\n and the downhole feature \n232\n.', 'The average movement is indicated by curve \n389\n.', 'During example operations, the actuator modules \n220\n, \n270\n may be operated to move the downhole feature \n232\n and the movable member \n234\n from the first position \n391\n to a third position \n393\n located between the first and second positions \n391\n, \n392\n and then from the third position \n393\n to a fourth position \n394\n located between the first and third positions \n391\n, \n393\n.', 'Thereafter, the downhole feature \n232\n and the movable member \n234\n may be moved from the fourth position \n394\n to a fifth position \n395\n located between the second and third positions \n392\n, \n393\n, then from the fifth position \n395\n to a sixth position \n396\n located between the fourth and fifth positions \n394\n, \n395\n, and then from the sixth position \n396\n to the second position \n392\n.', 'During example operations, the actuator modules \n220\n, \n270\n may be operated to move the downhole feature \n232\n and the movable member \n234\n from the sixth position \n396\n to a seventh position \n397\n located between the second and fifth positions \n392\n, \n395\n, then from the seventh position \n397\n to an eighth \n398\n position located between the sixth and seventh positions \n396\n, \n397\n, and then from the eighth position \n398\n to the second position \n392\n.', 'The frequency and the distance of each opposing movement may be adjustable by controlling the actuator modules \n220\n, \n270\n.', 'For example, the actuator modules \n220\n, \n270\n may be operable to alternate the movements between the opposing axial directions at a relatively low frequency of less than one hertz and up to a relatively high frequency of about 300 hertz or more.', 'The actuator modules \n220\n, \n270\n may be operable to move the engagement members \n226\n and the movable member \n234\n between about 0.025 millimeters (mm) (0.001 inch) and about 6.35 mm (0.25 inch) or more during each opposing movement.', 'The speed, position, and/or distance traveled by the engagement members \n226\n and the downhole feature \n232\n may be monitored by the rotary sensor \n307\n associated with the actuator \n219\n of the actuator module \n220\n and the linear sensor \n311\n of the actuator module \n270\n, as described above.', 'Accordingly, the actuator modules \n220\n, \n270\n may be operated in real-time based on feedback or information generated by the rotary and linear sensors \n307\n, \n311\n.', 'The actuator modules \n220\n, \n270\n may also be operable to move the engagement members \n226\n and the movable member \n234\n based on friction forces or resistance to movement of the movable member \n234\n.', 'For example, if the resistance to movement of the movable member \n234\n is within a first (i.e., low) predetermined threshold range, the actuator modules \n220\n, \n270\n may move the engagement members \n226\n and the movable member \n234\n from the first to the second position without alternating the direction of movement of the engagement members \n226\n and the movable member \n234\n.', 'If the resistance to movement of the movable member \n234\n is within a second (i.e., medium) predetermined threshold range, the actuator modules \n220\n, \n270\n may move the engagement members \n226\n and the movable member \n234\n from the first to the second position while alternating the direction of movement of the engagement members \n226\n and the movable member \n234\n, as described above.', 'However, if the resistance to movement of the movable member \n234\n is within a third (i.e., high) predetermined threshold range, the actuator modules \n220\n, \n270\n may alternate the direction of movement of the engagement members \n226\n and the movable member \n234\n without achieving the net repositioning of the engagement members \n226\n and the movable member \n234\n until the movable member \n234\n frees up or otherwise produces less resistance to movement, at which point the actuator modules \n220\n, \n270\n may resume the net repositioning of the engagement members \n226\n and the movable member \n234\n.', 'A portion of the curves \n390\n, \n393\n showing the actuator modules \n220\n, \n270\n alternating the direction of movement of the engagement members \n226\n and the movable member \n234\n without achieving the net repositioning of the engagement members \n226\n and the movable member \n234\n is indicated by numeral \n399\n.', 'Accordingly, the actuator modules \n220\n, \n270\n may be operated in real-time based on feedback or information generated by the accelerometers \n257\n and/or the load cells \n259\n.', 'Various portions of the apparatus described above and shown in \nFIGS.', '1-14\n, may collectively form and/or be controlled by a control system, such as may be operable to monitor and/or control at least some operations of the wellsite system \n100\n, including the tool string \n200\n, \n201\n.', 'FIG.', '20\n is a schematic view of at least a portion of an example implementation of such a control system \n400\n according to one or more aspects of the present disclosure.', 'The following description refers to one or more of \nFIGS.', '1-20\n.', 'The control system \n400\n may comprise a controller \n410\n, which may be in communication with various portions of the wellsite system \n100\n, including the tensioning device \n170\n, the actuators \n219\n, \n223\n, \n225\n, \n264\n, \n278\n, the accelerometers \n257\n, the load cells \n259\n, the linear sensors \n311\n, the rotary sensors \n307\n, the valves \n310\n, and/or other actuators and sensors of the tool string \n200\n, \n201\n.', 'For clarity, these and other components in communication with the controller \n410\n will be collectively referred to hereinafter as “actuator and sensor equipment.”', 'The controller \n410\n may be operable to receive coded instructions \n432\n from the human operators and signals generated by the accelerometers \n257\n, the load cells \n259\n, the linear sensors \n311\n, and the rotary sensors \n307\n, process the coded instructions \n432\n and the signals, and communicate control signals to the actuators \n219\n, \n223\n, \n225\n, \n264\n, \n278\n, the valves \n310\n, and/or the tensioning device \n170\n to execute the coded instructions \n432\n to implement at least a portion of one or more example methods and/or processes described herein, and/or to implement at least a portion of one or more of the example systems described herein.', 'The controller \n410\n may be or comprise one or more of the controllers \n178\n, \n214\n described above.', 'The controller \n410\n may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers) personal digital assistant (PDA) devices, smartphones, internet appliances, and/or other types of computing devices.', 'The controller \n410\n may comprise a processor \n412\n, such as a general-purpose programmable processor.', 'The processor \n412\n may comprise a local memory \n414\n, and may execute coded instructions \n432\n present in the local memory \n414\n and/or another memory device.', 'The processor \n412\n may execute, among other things, the machine-readable coded instructions \n432\n and/or other instructions and/or programs to implement the example methods and/or processes described herein.', 'The programs stored in the local memory \n414\n may include program instructions or computer program code that, when executed by an associated processor, facilitate the wellsite system \n100\n, the tool string \n200\n, \n201\n, the actuator modules \n220\n, \n222\n, \n260\n, \n270\n, and/or the engagement device \n224\n to perform the example methods and/or processes described herein.', 'The processor \n412\n may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples.', 'Of course, other processors from other families are also appropriate.', 'The processor \n412\n may be in communication with a main memory \n417\n, such as may include a volatile memory \n418\n and a non-volatile memory \n420\n, perhaps via a bus \n422\n and/or other communication means.', 'The volatile memory \n418\n may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices.', 'The non-volatile memory \n420\n may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices.', 'One or more memory controllers (not shown) may control access to the volatile memory \n418\n and/or non-volatile memory \n420\n.', 'The controller \n410\n may also comprise an interface circuit \n424\n.', 'The interface circuit \n424\n may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others.', 'The interface circuit \n424\n may also comprise a graphics driver card.', 'The interface circuit \n424\n may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.).', 'One or more of the actuator and sensor equipment may be connected with the controller \n410\n via the interface circuit \n424\n, such as may facilitate communication between the actuator and sensor equipment and the controller \n410\n.', 'One or more input devices \n426\n may also be connected to the interface circuit \n424\n.', 'The input devices \n426\n may permit the wellsite operators to enter the coded instructions \n432\n, including control commands, operational set-points, and/or other data for use by the processor \n412\n.', 'The operational set-points may include, as non-limiting examples, frequency of the vibrations generated by the actuator module \n222\n, frequency of the alternating opposing axial movements imparted by the actuator modules \n220\n, \n270\n, magnitude of the vibrating force generated by the actuator module \n222\n, magnitude of the substantially non-vibrating axial force generated by the actuator module \n220\n, \n270\n, distance of each alternating opposing axial movement imparted by the actuator modules \n220\n, \n270\n, and the force magnitude thresholds to be applied to the downhole apparatus \n230\n by the actuator modules \n220\n, \n222\n, \n270\n, such as to control movement or operation of the downhole apparatus \n230\n or other member located within the wellbore \n120\n.', 'The input devices \n426\n may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples.', 'One or more output devices \n428\n may also be connected to the interface circuit \n424\n.', 'The output devices \n428\n may be, comprise, or be implemented by display devices (e.g., a liquid crystal display (LCD), a light-emitting diode (LED) display, or cathode ray tube (CRT) display), printers, and/or speakers, among other examples.', 'The controller \n410\n may also communicate with one or more mass storage devices \n430\n and/or a removable storage medium \n434\n, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.', 'The coded instructions \n432\n may be stored in the mass storage device \n430\n, the main memory \n417\n, the local memory \n414\n, and/or the removable storage medium \n434\n.', 'Thus, the controller \n410\n may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor \n412\n.', 'In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor \n412\n.', 'The coded instructions \n432\n may include program instructions or computer program code that, when executed by the processor \n412\n, may cause the wellsite system \n100\n, the tool string \n200\n, \n201\n, the actuator modules \n220\n, \n222\n, \n260\n, \n270\n and the engagement device \n224\n to perform methods, processes, and/or routines described herein.', 'For example, the controller \n410\n may receive, process, and record the operational set-points entered by the human operator and the signals generated by the sensors \n257\n, \n259\n, \n307\n, \n311\n.', 'Based on the received operational set-points and the signals generated by the sensors \n257\n, \n259\n, \n307\n, \n311\n, the controller \n410\n may send signals or information to the various actuators \n219\n, \n223\n, \n225\n, \n264\n, \n278\n, valves \n310\n, and/or the tensioning device \n170\n to automatically perform and/or undergo one or more operations or routines described herein or otherwise within the scope of the present disclosure.', 'For example, the controller \n410\n may be operable to cause the actuator modules \n220\n, \n222\n, \n270\n to generate or apply the substantially non-vibrating and vibrating forces to the downhole device \n230\n, as described above in association with graphs \n15\n-\n19\n.', 'In view of the entirety of the present disclosure, including the claims and the figures, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising a downhole tool string for conveying within a wellbore, wherein the downhole tool string comprises: an engagement device operable to engage a downhole feature located within the wellbore; a first actuator operable to apply a substantially non-vibrating force to the engagement device while the engagement device is engaged with the downhole feature; and a second actuator operable to apply a vibrating force to the engagement device while the engagement device is engaged with the downhole feature.', 'The first actuator may comprise a hydraulic ram and/or a downhole tractor.', 'A valve installed in the wellbore may comprise the downhole feature.', 'The substantially non-vibrating force and the vibrating force may be cooperatively for transitioning the valve between open and closed positions.', 'The valve may comprise a sliding sleeve comprising the downhole feature.', 'The first actuator may apply the substantially non-vibrating force to the second actuator, such that the second actuator may apply a combination of the substantially non-vibrating and vibrating forces to the engagement device.', 'The first and second actuators may be simultaneously operable to apply the substantially non-vibrating and vibrating forces to the downhole feature, via the engagement device, to move the downhole feature within the wellbore.', 'The substantially non-vibrating force may be an uphole or downhole axial force to impart respective uphole or downhole movement of the downhole feature while the vibrating force simultaneously imparts vibration to the downhole feature.', 'The substantially non-vibrating force may be an axial force that changes between uphole and downhole directions to alternatingly impart uphole and downhole movements to the downhole feature, and the uphole and downhole movements may be of different distances to achieve a net uphole or downhole repositioning of the downhole feature.', 'The axial force may change between uphole and downhole directions at a frequency of less than one hertz.', 'The vibrating force may be an axially vibrating force, a radially vibrating force, and/or a rotationally vibrating force.', 'The second actuator may comprise a rotor comprising alternating slots and protrusions, a rotary actuator operable to rotate the rotor, and a contact member operable to contact the rotor.', 'The alternating slots and protrusions of the rotor may be operable to move the contact member in an oscillating manner as the rotor rotates to generate the vibrating force.', 'The contact member may be connected with a housing of the vibratory actuator via a biasing member operable to transfer the vibrating force to the housing of the vibratory actuator.', 'The apparatus may further comprise a controller comprising a processor and a memory storing computer program code, wherein the controller may be operable to control the first and second actuators to apply the substantially non-vibrating and vibrating forces.', 'The downhole tool string may comprise the controller.', 'The apparatus may further comprise surface equipment disposed at a wellsite surface from which the wellsite extends, wherein the downhole tool string may be in electrical or optical communication with the surface equipment, and wherein the surface equipment may comprise at least a portion of the controller.', 'The downhole tool string may further comprise a sensor operable to generate information indicative of a position of the downhole feature within the wellbore, and the controller may be operable to record the information.', 'The downhole tool string may further comprise a sensor operable to generate information indicative of at least one of the substantially non-vibrating and vibrating forces, and the controller may be operable to record the information.', 'The downhole tool string may further comprise an anchor device operable to maintain at least a portion of the downhole tool string in a predetermined position within the wellbore.', 'The present disclosure also introduces a method comprising: operating a first actuator to impart a substantially non-vibrating force to a downhole feature located within a wellbore; and operating a second actuator to impart a vibrating force to the downhole feature.', 'The first actuator may comprise a hydraulic ram and/or a downhole tractor.', 'The method may further comprise conveying a downhole tool string within the wellbore, wherein the downhole tool string comprises the first and second actuators.', 'The method may further comprise operating an anchor device to maintain at least a portion of the downhole tool string in a predetermined position within the wellbore.', 'The method may further comprise: engaging an engagement device with the downhole feature; and imparting the substantially non-vibrating and vibrating forces to the downhole feature via the engagement device.', 'The first actuator may impart the substantially non-vibrating force to the second actuator, such that the second actuator may impart a combination of the substantially non-vibrating and vibrating forces to the engagement device.', 'The first and second actuators may simultaneously impart the substantially non-vibrating and vibrating forces to the downhole feature, via the engagement device, to move the downhole feature within the wellbore.', 'A valve installed in the wellbore may comprise the downhole feature.', 'The method may further comprise transitioning the valve between open and closed positions with the substantially non-vibrating force and the vibrating force.', 'The valve may comprise a sliding sleeve comprising the downhole feature.', 'The substantially non-vibrating force may be an uphole or downhole axial force imparting respective uphole or downhole movement of the downhole feature while the vibrating force simultaneously imparts vibration to the downhole feature.', 'The substantially non-vibrating force may be an axial force that changes between uphole and downhole directions to alternatingly impart uphole and downhole movements to the downhole feature, and the uphole and downhole movements may be of different distances to achieve a net uphole or downhole repositioning of the downhole feature.', 'The axial force may change between uphole and downhole directions at a frequency of less than one hertz.', 'The vibrating force may be an axially vibrating force, a radially vibrating force, and/or a rotationally vibrating force.', 'The second actuator may comprise: a rotor comprising alternating slots and protrusions; a rotary actuator operable to rotate the rotor; and a contact member operable to contact the rotor.', 'The alternating slots and protrusions of the rotor may move the contact member in an oscillating manner as the rotor rotates to generate the vibrating force.', 'The contact member may be connected with a housing of the vibratory actuator via a biasing member, and the biasing member may transfer the vibrating force to the housing of the vibratory actuator.', 'The method may further comprise operating a controller comprising a processor and a memory storing computer program code to control the first and second actuators to impart the substantially non-vibrating and vibrating forces.', 'The method may further comprise conveying a downhole tool string within the wellbore, wherein the downhole tool string comprises the controller.', 'The method may further comprise operating surface equipment disposed at a wellsite surface from which the wellsite extends to electrically or optically communicate with the first and second actuators, wherein the surface equipment may comprise at least a portion of the controller.', 'The method may further comprise: operating a sensor to generate information indicative of a position of the downhole feature within the wellbore; and operating the controller to record the information.', 'The method may further comprise: operating a sensor to generate information indicative of at least one of the substantially non-vibrating and vibrating forces; and operating the controller to record the information.', 'The present disclosure also introduces a method comprising: positioning a downhole tool string relative to a downhole feature within a wellbore, wherein the downhole tool string is in communication with surface equipment disposed at a wellsite surface from which the wellbore extends, and wherein the downhole tool string and/or the surface equipment individually or collectively comprise a controller comprising a processor and a memory storing computer program code; engaging the downhole feature with an engagement device of the downhole tool string; and operating the controller to control an actuator of the downhole tool string to impart movements to the engagement device and the downhole feature in first and second directions, wherein the movements are of different distances to achieve a net repositioning of the downhole feature in the first or second direction.', 'The first and second directions may be axially opposite directions.', 'The movements may change between the first and second directions at a frequency of less than one hertz.', 'The movements may change between the first and second directions at a frequency of greater than fifty hertz.', 'The actuator may be a first actuator operable to impart a substantially non-vibrating force to the engagement device, and operating the controller may further comprise controlling a second actuator of the downhole tool string to impart a vibrating force to the engagement device simultaneously with the substantially non-vibrating force.\n \nOperating the controller to impart the movements may be based on information generated by a position sensor of the downhole tool string operable to generate information indicative of a position of the downhole feature.', 'Operating the controller to impart the movements may also or instead be based on information generated by a force sensor of the downhole tool string operable to generate information indicative of a force applied by the actuator to impart the movements.', 'The downhole feature may be in a first position when initially engaged by the engagement device, the net repositioning of the downhole feature may be in the first direction to a second position, and each successive one of the movements in the first direction may move the downhole feature closer to the second position than resulted from the previous movements in the first direction.', 'The movements in the second direction may each be of substantially the same distance.', 'A valve installed in the wellbore may comprise the downhole feature.', 'The valve may comprise a sliding sleeve comprising the downhole feature.', 'The method may further comprise operating the controller to control an anchor device of the downhole tool string to positionally fix at least a portion of the downhole tool string within the wellbore.', 'The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure.', 'A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.', 'The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure.', 'It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.'] | ['1.', 'A method comprising:\nconveying a powered downhole tool string within a wellbore, wherein the down hole tool string comprises a first actuator and a second actuator; operating the first actuator to impart a substantially non-vibrating force to a down hole feature located within the wellbore; operating the second actuator to impart a vibrating force to the downhole feature, and operating a controller to control one or both of the first and second actuators of the downhole tool string to impart movements to the downhole feature in first and second directions, wherein the movements are of different distances to achieve a net repositioning of the down hole feature in the first or second direction.', '2.', 'The method of claim 1, further comprising operating an anchor device to maintain at least a portion of the downhole tool string in a predetermined position within the wellbore.', '3.', 'The method of claim 1, further comprising:\nengaging an engagement device with the downhole feature; and\nimparting the substantially non-vibrating and vibrating forces to the downhole feature via the engagement device.', '4.', 'The method of claim 1, wherein a valve installed in the wellbore comprises the downhole feature, and wherein the method further comprises transitioning the valve between open and closed positions with the substantially non-vibrating force and the vibrating force.', '5.', 'The method of claim 1, wherein the substantially non-vibrating force is an axial force, and wherein the vibrating force is at least one of an axially vibrating force, a radially vibrating force, and/or a rotationally vibrating force.', '6.', 'The method of claim 1, further comprising operating the controller comprising a processor and a memory storing computer program code to control the first and second actuators to impart the substantially non-vibrating and vibrating forces.', '7.', 'The method of claim 1, further comprising operating the controller to adjust a magnitude and frequency of the vibrating force.', '8.', 'The method of claim 1, wherein the vibrating force is continuous and repeatable.', '9.', 'The method of claim 1, wherein the substantially non-vibrating force is a rotational force or a torque, and wherein the vibrating force is at least one of an axially vibrating force, a radially vibrating force, and/or a rotationally vibrating force.\n\n\n\n\n\n\n10.', 'A method comprising:\npositioning a powered downhole tool string relative to a downhole feature of a movable member within a wellbore, wherein the downhole tool string is in communication with surface equipment disposed at a wellsite surface from which the wellbore extends, and wherein the downhole tool string and/or the surface equipment individually or collectively comprise a controller comprising a processor and a memory storing computer program code; engaging the downhole feature with an engagement device of the downhole tool string; and operating the controller to control an actuator of the downhole tool string to impart movements to the engagement device and the downhole feature in first and second directions, wherein the movements are of different distances to achieve a net repositioning of the downhole feature in the first or second direction in response to resistance to movement of the movable member falling within a second predetermined threshold range that is between a first predetermined threshold range and a third predetermined threshold range, wherein the actuator is controlled differently in response to the resistance to movement falling within the first predetermined threshold range or the third predetermined threshold range.\n\n\n\n\n\n\n11.', 'The method of claim 10, wherein the actuator is a first actuator operable to impart a substantially non-vibrating force to the engagement device, and wherein operating the controller further comprises controlling a second actuator of the downhole tool string to impart a vibrating force to the engagement device simultaneously with the substantially non-vibrating force.\n\n\n\n\n\n\n12.', 'The method of claim 10, wherein operating the controller to impart the movements is based on information generated by at least one of:\na position sensor of the downhole tool string operable to generate information indicative of a position of the downhole feature; and/or\na force sensor of the downhole tool string operable to generate information indicative of a force applied by the actuator to impart the movements.', '13.', 'The method of claim 10, wherein the downhole feature is in a first position when initially engaged by the engagement device, wherein the net repositioning of the downhole feature is in the first direction to a second position, and wherein each successive one of the movements in the first direction moves the downhole feature closer to the second position than resulted from the previous movements in the first direction.', '14.', 'The method of claim 10, wherein the controller automatically adjusts the non-vibrating and vibrating forces based on sensor feedback to apply forces to the downhole feature.'] | ['FIG.', '1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '2 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '3 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG.', '4 is a sectional view of a portion of the apparatuses shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure.', '; FIG.', '5 is a sectional view of the apparatus shown in FIG.', '4 in a different stage of operation.;', 'FIG. 6 is a schematic view of a portion of an example implementation of the apparatus shown in FIG.', '3 according to one or more aspects of the present disclosure.', '; FIG. 7 is a schematic view of a portion of an example implementation of the apparatus shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure.', '; FIG. 8 is a schematic view of a portion of an example implementation of the apparatus shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure.', '; FIG.', '9 is a schematic view of a portion of an example implementation of the apparatus shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure.', '; FIG.', '10 is a schematic axial view of the apparatus shown in FIG.', '9 according to one or more aspects of the present disclosure.', '; FIG.', '11 is a schematic view of a portion of an example implementation of the apparatuses shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure.', '; FIG.', '12 is a schematic axial view of the apparatus shown in FIG.', '11 according to one or more aspects of the present disclosure.', '; FIG. 13 is a schematic view of a portion of an example implementation of the apparatuses shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure.', '; FIG.', '14 is a schematic axial view of the apparatus shown in FIG.', '13 according to one or more aspects of the present disclosure.', '; FIGS.', '15-19 are graphs related to one or more aspects of the present disclosure.;', 'FIG.', '20 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.', '; FIG. 1 is a schematic view of at least a portion of a wellsite system 100 according to one or more aspects of the present disclosure.', 'The wellsite system 100 may comprise a tool string 110 suspended within a wellbore 120 that extends from a wellsite surface 105 into one or more subterranean formations 130.', 'The wellbore 120 is depicted as being a cased-hole implementation comprising a casing 124 secured by cement 122.', 'However, one or more aspects of the present disclosure are also applicable to and/or readily adaptable for utilizing in open-hole implementations lacking the casing 124 and cement 122.', 'Also, the tool string 110 is depicted located within a horizontal portion 121 of the wellbore 120.', 'However, it is to be understood that the tool string 110 within the scope of the present disclosure may be utilized in vertical, diagonal, and otherwise deviated portions of the wellbore 120.; FIG.', '2 is a schematic view of an example implementation of the tool string 110 shown in FIG.', '1 according to one or more aspects of the present disclosure, designated in FIG.', '2 by numeral 200.', 'The tool string 200 is shown disposed within the substantially horizontal portion 121 of the wellbore 120 and connected with the surface equipment 175 via the conveyance means 171.', 'However, it is to be understood that the tool string 200 may also be utilized within a substantially vertical or otherwise deviated portion of the wellbore 120.', 'The following description refers to FIGS.', '1 and 2, collectively.;', 'FIG. 3 is a schematic view of an example implementation of the tool string 110 shown in FIG.', '1 according to one or more aspects of the present disclosure, and designated in FIG.', '3 by reference number 201.', 'The tool string 201 comprises one or more similar features of the tool string 200 shown in FIG.', '2, including where indicated by like reference numbers, except as described below.', 'Similarly as in FIG.', '2, the tool string 201 is shown disposed within the substantially horizontal portion 121 of the wellbore 120 and connected with the surface equipment 175 via the conveyance means 171.', 'However, it is to be understood that the tool string 201 may also be utilized within a substantially vertical or otherwise deviated portion of the wellbore 120.', 'The following description refers to FIGS.', '1, 2, and 3, collectively.;', 'FIGS. 4 and 5 are schematic views of at least a portion of an example implementation of the downhole apparatus 230 and the engagement device 224 shown in FIGS.', '2 and 3 and at different stages of operation.', 'The following description refers to FIGS.', '1-5, collectively.; FIGS. 4 and 5 show the downhole apparatus 230 implemented as a downhole valve assembly 240 disposed within a downhole tubular assembly 242 and operable to shut off or otherwise limit fluid flow through the tubulars 242.', 'The valve assembly 240 comprises a movable sleeve 244 operatively connected with a ball member 246 via a bracket 248 pivotally connected with the ball member 246.', 'The ball member 246 is maintained in position by packing members 250 of the downhole valve assembly 240.', 'The movable sleeve 244 includes a downhole feature 252 comprising a groove and a protrusion receiving, accommodating, or otherwise engaging with the engagement members 226 of the engagement device 224.', 'The ball member 246 comprises a bore 258 or fluid pathway extending therethrough, and may be operated or rotated to selectively permit, prevent, or otherwise limit fluid flow through the valve assembly 240 via operation or movement of the movable sleeve 244.', 'FIG.', '4 shows the movable sleeve 244 in a first or initial position and the ball member 246 in a closed-flow position, while FIG.', '5 shows the movable sleeve 244 in a second or final position and the ball member 246 in an open-flow position.', 'Accordingly, to operate the valve assembly 240 to the open-flow position, the engagement device 224 may be moved in the downhole direction from the initial position to the final position, and to operate the valve assembly 240 to the closed-flow position, the engagement device 224 may be moved in the uphole direction from the final position to the initial position.; FIG.', '6 is a schematic view of a portion of an example implementation of the actuator module 270 of the tool string 201 shown in FIG.', '3, designated in FIG.', '6 by numeral 300, and operable to generate or apply the substantially non-vibrating axial force according to one or more aspects of the present disclosure.', 'The actuator module 300 comprises one or more similar features of the actuator module 270, including where indicated by like reference numbers, except as described below.', 'The following description refers to FIGS.', '3 and 6, collectively.;', 'FIGS.', '7-14 are schematic views of a portion of example implementations of the actuator module 222 of the tool strings 200, 201 shown in FIGS.', '2 and 3 according to one or more aspects of the present disclosure.', 'FIGS.', '7-14 show one or more similar features of the actuator module 222 shown in FIGS.', '2 and 3, including where indicated by like reference numbers, except as described below.', 'The following description refers to FIGS.', '2, 3, and 7-14, collectively.;', 'FIG. 7 shows a portion of an example implementation of the actuator module 222, designated in FIG.', '7 by numeral 320, operable to generate or apply the axially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module 320 may comprise the actuator 223, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a rotor 321 via a shaft 322, such as may facilitate rotation of the rotor 321 about an axis of rotation 319.', 'The rotor 321 may comprise a profile comprising alternating recesses or slots 323 and shoulders or protrusions 324.', 'The rotor 321 may be aligned against a stator or contact member 325 such that the alternating slots 323 and protrusions 324 engage corresponding alternating slots 326 and protrusions 327 of the contact member 325.', 'The contact member 325 may be connected with a body, chassis, or housing 328 of the actuator module 320 via a biasing member 329.', 'During operations of the actuator module 320, as the actuator 223 is rotating the rotor 321, the alternating slots 323 and protrusions 324 of the rotor 321 may be operable to engage the corresponding alternating slots 326 and protrusions 327 of the contact member 325 to axially move the contact member 325 away from the actuator 223, as indicated by the arrow 301, and permit the biasing member 329 to move the contact member 325 toward the actuator 223, as indicated by arrow 302, resulting in the contact member 325 moving in a vibrating manner.', 'The vibrating (i.e., inertial) forces imparted to the contact member 325 may be transmitted to the housing 328 of the actuator module 320 via the biasing member 329.', 'Also, the axis of rotation 319 may substantially coincide with or extend parallel to the axis 123 of the wellbore 120, such that the axially vibrating force may be directed along or parallel to the axis 123 of the wellbore 120.', 'The axially vibrating force may then be transferred to the engagement device 224 connected with the actuator module 320.; FIG.', '8 shows a portion of an example implementation of the actuator module 222, designated in FIG.', '8 by numeral 330, operable to generate or apply the axially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module 330 may comprise the actuator 223, such as a piezoelectric actuator, comprising a piezoelectric element 332, such as a quartz crystal, operable to vibrate axially when an alternating electrical field is applied.', 'One side of the piezoelectric element 332 may be fixedly connected with a body, chassis, or housing 334 of the actuator module 330 via a base 336 and an opposing side of the piezoelectric element 332 may be connected with a ballast member 337 comprising a predetermined mass.', 'During operations, when the electric field is applied to a selected face of the piezoelectric element 332, a mechanical distortion of the piezoelectric element 332 occurs along an axis 331 generating a force to move the ballast member 337 along the axis 331.', 'When the electric field is alternated or continuously turned on and off, the piezoelectric element 332 alternatingly extends and retracts to generate an alternating or vibrating force against the ballast member 337 to alternatingly extend and retract or vibrate the ballast member 337 along the axis 331, as indicates by arrows 301, 302.', 'The vibrating (i.e., inertial) forces imparted to ballast member 337 may be transmitted to the housing 334 via the piezoelectric element 332 and then to the engagement device 224 connected with the actuator module 330.', 'The axis 331 may substantially coincide with or extend parallel to the axis 123 of the wellbore 120, such that the vibrating force may be directed axially along or parallel to the axis 123 of the wellbore 120.', 'The axis 331 may extend perpendicularly to the axis 123 of the wellbore 120, such that the vibrating force may be directed radially with respect to the axis 123 of the wellbore 120.', 'The frequency of the vibrating force generated by the actuator module 330 may be adjusted by controlling the frequency at which the voltage is applied to the piezoelectric element 332.; FIGS. 9 and 10 show top and axial views of a portion of an example implementation of the actuator module 222, designated in FIGS.', '9 and 10 by numeral 340, operable to generate or apply the rotationally vibrating force according to one or more aspects of the present disclosure.', 'The actuator module 340 may comprise the actuator 223, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a gear or rotor 341 via a shaft 342, such as may facilitate rotation of the rotor 341 about an axis of rotation 346.', 'The rotor 341 may have a profile comprising a plurality of alternating teeth, protrusions, or shoulders 343 and recesses or slots 344, such as may be operable to alternatingly engage and disengage one or more contact members 345 to move and release the contact member 345 along a vector perpendicular to and offset from the axis of rotation 346, as indicated by arrow 347.', 'The contact member 325 may be connected with a body, chassis, or housing 348 of the actuator module 320 via a biasing member 349.', 'During operations of the actuator module 340, as the actuator 223 is rotating the rotor 341, the shoulders 343 and the slots 345 may be operable to alternatingly push the contact member 345 toward the housing 348 of the actuator module 340, compressing the biasing member 349, and release the contact member 345, permitting the biasing member 349 to return the contact member 345 to its natural position.', 'The vibrating (i.e., inertial) force imparted to the contact member 345 may be imparted to the housing 348 via the biasing member 349 along the vector perpendicular to and offset from the axis of rotation 346 or otherwise around the axis of rotation 346, as indicated by the arrow 347.', 'The axis of rotation 346 may substantially coincide with or extend parallel to the axis 123 of the wellbore 120, such that the rotationally vibrating force may be directed around the axis 123 or tangentially with respect to the axis 123.; FIGS.', '11 and 12 show side and axial views of a portion of an example implementation of the actuator module 222, designated in FIGS.', '11 and 12 by numeral 350, operable to generate or apply the radially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module 350 may comprise the actuator 223, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a gear or rotor 351 via a shaft 352, such as may facilitate rotation of the rotor 351 about an axis of rotation 356.', 'The rotor 351 may have a profile comprising a plurality of alternating teeth, protrusions, or shoulders 353 and recesses or slots 354, such as may be operable to alternatingly engage and disengage a plurality of contact members 355 to move the contact members 355 along corresponding vectors extending radially or perpendicularly with respect to the axis of rotation 356, as indicated by arrows 357.', 'The contact members 355 may be connected with a body, chassis, or housing 358 of the actuator module 350 via corresponding biasing members 359.', 'During operations of the actuator module 350, as the actuator 223 is rotating the rotor 351, the shoulders 353 and the slots 355 may be operable to alternatingly push the contact members 355 toward the housing 358 of the actuator module 350, compressing the biasing members 359, and release the contact members 355, permitting the biasing members 359 to return the contact members 355 to their natural positions.', 'The contacting members 355 and the shoulders 353 of the stator 351 may be configured such that each of the contact members 355 is movable radially at different times and in different radial directions with respect to the axis of rotation 356 during each vibration iteration or cycle as the stator 351 is rotated, as indicated by the arrows 357.', 'The vibrating (i.e., inertial) force imparted to the contact members 355 may be imparted to the housing 358 via corresponding biasing members 359, as indicated by the arrows 357.', 'The axis of rotation 356 may substantially coincide with or extend parallel to the axis 123 of the wellbore 120, such that the radially vibrating force may be directed in a plurality of radial directions with respect to the axis 123 of the wellbore 120.; FIGS. 13 and 14 show side and axial views of a portion of an example implementation of the actuator module 222, designated in FIGS.', '13 and 14 by numeral 360, operable to generate or apply the radially vibrating force according to one or more aspects of the present disclosure.', 'The actuator module 360 may comprise the actuator 223, such as a hydraulic or electrical rotary actuator or motor, operatively connected with a rotor 361 via a shaft 362, such as may facilitate rotation of the rotor 361 about an axis of rotation 366.', 'The actuator 223 may be fixedly connected with a body, chassis, or housing 368 of the actuator module 360.', 'The rotor 351 may be asymmetrical, comprise an asymmetrical mass distribution, or may be connected with the shaft 362 at a point that is not the center of mass of the rotor 361.', 'Accordingly, when rotated by the actuator 223, a centrifugal or rotating inertial force may be generated along a radial direction away from the axis of rotation 366, as indicated by an arrow 367.', 'The radial force may be directed through a center of mass 363 of the rotor 361.', 'Accordingly, the inertial force may continuously change direction as the center of mass 363 of the rotor 361 changes direction with the rotating rotor 361.', 'The continuously changing inertial force may be transmitted to the actuator 223, causing the actuator 223 to vibrate radially 223 with respect to the axis of rotation 366.', 'The radially vibrating force may then be transmitted to the housing 368 and the engagement device 224 connected with the actuator module 330.', 'The axis of rotation 366 may substantially coincide with or extend parallel to the axis 123 of the wellbore 120, such that the radially vibrating force may be directed radially with respect to the axis 123 of the wellbore 120.'] |
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US11066928 | Downhole data transmission and surface synchronization | Jun 18, 2018 | Nirina David Raveloson, Alex David Close, Nikhil Kotian, William James Robert Thomson, Prince Mathew Samuel | SCHLUMBERGER TECHNOLOGY CORPORATION | International Search Report and Written Opinion issued in International Patent application PCT/2018/037975 dated Sep. 21, 2018, 9 pages.; Extended European Search Report under Rule 62 EPC in European Patent Application No. 18821217.9, dated Jun. 14, 2021, 6 pages. | 3991611; November 16, 1976; Marshall, III et al.; 7348893; March 25, 2008; Huang et al.; 7657672; February 2, 2010; Kampmann et al.; 7843959; November 30, 2010; Kampmann et al.; 8000350; August 16, 2011; Riedel et al.; 8044821; October 25, 2011; Mehta; 20070057811; March 15, 2007; Mehta; 20070189119; August 16, 2007; Klotz; 20140085098; March 27, 2014; Stolpman et al.; 20140129148; May 8, 2014; Harmer et al.; 20150078625; March 19, 2015; Yu et al.; 20180119546; May 3, 2018; Soos | 0349465; January 1990; EP; 2016200766; December 2016; WO | ['A telemetry method transmits data from a downhole location to a surface location.', 'During transmission an event is detected that makes it desirable to change a transmitted data stream.', 'A downhole processor processes the detected event in combination with a predefined event database and downhole measurement data using a frame building algorithm to compute a digital data stream.', 'Synchronization markers are added to the data stream to obtain a synchronized data stream in which the synchronization markers identify the detected event.', 'The synchronized data stream is transmitted to the surface location using a downhole telemetry tool and received at the surface location to obtain a decoded data stream.', 'A surface processor processes the synchronization markers to identify the detected event and further processes the detected event in combination with a predefined event database and the decoded data stream using the frame building algorithm to obtain the downhole measurements.'] | ['Description\n\n\n\n\n\n\nCROSS REFERENCE TO RELATED APPLICATIONS', 'This application claims the benefit of and priority to U.S. Provisional Application No. 62/522,740, filed on Jun. 21, 2017, the entirety of which is incorporated herein by reference.', 'BACKGROUND\n \nOil and gas well drilling operations commonly employ a number of measurement while drilling (MWD) and logging while drilling (LWD) techniques to gather information about the borehole and the formation through which it is drilled.', 'MWD and LWD techniques may be used, for example, to obtain information about the well (e.g., information about the size, shape, and direction thereof) and the surrounding formation (e.g., the acoustic velocity, density, and resistivity thereof).', 'Transmission of data (e.g., MWD and LWD data) from a downhole tool to the surface is a difficult process common to many drilling operations.', 'Various telemetry techniques may be employed, for example, including mud pulse telemetry, electromagnetic telemetry, and acoustic telemetry.', 'Owing in part to the inherently noisy communication channel, downhole telemetry operations tend be error prone and slow (having a very limited bandwidth).', 'In view of these difficulties, conventional telemetry operations commonly transmit preconfigured sequences of data.', 'Modern drilling tools generate a large quantity of sensor data that can overload the telemetry channel.', 'Selecting the appropriate information to transmit may involve evaluating complex relationships and dependencies between the various data sets, the drilling conditions, and the subterranean formations.', 'SUMMARY\n \nEmbodiments of the present application include a telemetry method for transmitting data from a downhole location to a surface location.', 'An event is detected that makes it desirable to change a transmitted data stream while drilling.', 'A downhole processor processes the detected event in combination with a predefined event database and downhole measurement data using a frame building algorithm to compute a digital data stream.', 'Synchronization markers are added to the data stream to obtain a synchronized data stream in which the synchronization markers identify the detected event.', 'The synchronized data stream is transmitted to the surface location using a downhole telemetry tool and received at the surface location to obtain a decoded data stream.', 'A surface processor processes the synchronization markers to identify the detected event and further processes the detected event in combination with a predefined event database and the decoded data stream using the frame building algorithm to obtain the downhole measurements.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS\n \nFor a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:\n \nFIG.', '1\n depicts a drilling rig on which the disclosed system and method embodiments may be utilized.\n \nFIG.', '2\n depicts a flow chart of one disclosed telemetry method embodiment for transmitting data from a downhole location to a surface location.\n \nFIG.', '3\n depicts another disclosed telemetry method embodiment.\n \nFIG.', '4\n depicts a telemetry method embodiment similar to the embodiment depicted on \nFIG.', '2\n.', 'FIG.', '5\n depicts a telemetry method embodiment similar to the embodiment depicted on \nFIG.', '5\n.', 'FIG.', '6\n depicts a flow chart of one example method used to modify a data stream.\n \nFIG.', '7\n depicts one example frame builder tree for executing the method of \nFIG.', '6\n.', 'DETAILED DESCRIPTION\n \nEmbodiments of the present application relate generally to telemetry methods in downhole drilling operations and more particularly to a method for synchronizing downhole and surface operations during a telemetry operation.', 'Some embodiments of the present application provide for more reliable transmission of downhole data to the surface.', 'Embodiments of the present application enable the transmitted data stream and content to be automatically modified on the fly (while drilling) in response to a detected downhole event.\n \nFIG.', '1\n depicts an example offshore drilling assembly, generally denoted \n10\n, suitable for employing the disclosed system and method embodiments.', 'In \nFIG.', '1\n a semisubmersible drilling platform \n12\n is positioned over an oil or gas formation disposed below the sea floor \n16\n.', 'A subsea conduit \n18\n extends from deck \n20\n of platform \n12\n to a wellhead installation \n22\n.', 'The platform may include a derrick and a hoisting apparatus for raising and lowering the drill string \n30\n, which, as shown, extends into borehole \n40\n and includes drill bit \n32\n, a transmission device \n50\n, and at least one MWD/LWD tool \n60\n.', 'Drill string \n30\n may optionally further include any number of other tools including, for example, other MWD/LWD tools, stabilizers, a rotary steerable tool, and/or a downhole drilling motor.\n \nFIG.', '1\n further depicts downhole and surface control systems \n100\n and \n150\n.', 'The downhole system \n100\n is deployed in the drill string, for example, in proximity to the transmission device \n50\n and the MWD/LWD tool \n60\n.', 'The downhole system \n100\n may include substantially any suitable downhole controller, for example, including a programmable processor (such as a microprocessor or a microcontroller) and electronic memory.', 'The downhole controller may also include processor-readable or computer-readable program code embodying logic, including instructions for controlling the function of the transmission device \n50\n.', 'The surface control system \n150\n may be deployed, for example, on the drilling rig and may include substantially any suitable processing device, such as a personal computer.', 'It will be understood that the disclosed embodiments are explicitly not limited to any particular downhole and surface systems.', 'With continued reference to \nFIG.', '1\n, the transmission device \n50\n may include substantially any suitable downhole telemetry device.', 'For example, the telemetry device \n50\n may include an electromechanical pulser or a mud siren suitable for mud pulse telemetry, an electromagnetic wave generator suitable for electromagnetic telemetry, or an acoustic generator suitable for acoustic telemetry, or the like.', 'Those of ordinary skill will readily appreciate that in mud pulse telemetry operations, data is transmitted to the surface via pressure waves and/or pulses in the drilling fluid.', 'In electromagnetic telemetry operations, data is transmitted to the surface via a low frequency electromagnetic wave that propagates through the earth formations.', 'In acoustic telemetry operations, data is transmitted to the surface via an acoustic signal that propagates through the drill string.', 'The disclosed embodiments are not limited in these regards and any suitable telemetry system may be used.', 'The MWD/LWD tool \n60\n may include any downhole logging while drilling sensor, for example, including a natural gamma ray sensor, a neutron sensor, a density sensor, a resistivity sensor, a formation pressure sensor, an annular pressure sensor, an ultrasonic sensor, an audio-frequency acoustic sensor, and the like.', 'Such sensors are used to make a wide range of downhole logging measurements.', 'The tool \n60\n may alternatively and/or additionally include various directional sensors such as accelerometers, magnetometers, and/or gyroscopic sensors.', 'The tool \n60\n may further optionally include an energy source, such as a motor, generator, battery, or the like.', 'For example, an LWD tool configured for azimuthal gamma measurements may include a gamma radiation source (such a device is commonly referred to as a density measurement tool).', 'Likewise, LWD tools configured for azimuthal resistivity and acoustic velocity measurements may include one or more electromagnetic wave generators and acoustic transmitters, respectively.', 'The disclosed embodiments are not limited in any of these regards.', 'It will be understood by those of ordinary skill in the art that the deployment illustrated on \nFIG.', '1\n is an example.', 'It will be further understood that the disclosed embodiments are not limited to use with a semisubmersible platform \n12\n as illustrated on \nFIG.', '1\n.', 'The disclosed embodiments are equally well suited for use with any kind of subterranean drilling operation, either offshore or onshore.', 'In disclosed embodiments, the downhole and surface systems \n100\n and \n150\n run a common algorithm; the downhole system \n100\n generating a continuous stream of digitized data for transmission to the surface (via transmission device \n50\n) and the surface system \n150\n generating a hypothetical stream of data having a substantially identical structure to the digitized stream generated by the downhole system \n100\n.', 'The common algorithm is referred to herein as a frame building algorithm.', 'Running the frame building algorithm with identical initial conditions at both the downhole and surface systems \n100\n and \n150\n enables the surface system \n150\n to anticipate the digitized data stream received from the downhole system \n100\n and the transmission device \n50\n.', 'The data stream may include synchronization information (such as extra bits) to enable the surface system \n150\n to identify a data portion of the stream (e.g., the transmitted measurement data) even in the event of synchronization corruption.\n \nFIG.', '2\n depicts a flow chart of one depicted telemetry method embodiment \n200\n for transmitting data from a downhole location such as a drill string to a surface location.', 'In the depicted embodiment, the downhole and surface systems \n100\n and \n150\n are configured to run a frame building algorithm as described above using identical initial conditions \n202\n.', 'The initial conditions may be established (e.g., programmed in the downhole system memory) before the initiation of a drilling job (e.g., when the drilling system is at the surface).', 'The downhole system \n100\n runs the frame building algorithm at \n212\n based on the pre-established initial conditions \n202\n.', 'Downhole measurements (e.g., measurements made by MWD/LWD tool \n60\n) are acquired at \n214\n and combined with synchronization markers \n216\n to generate a real-time (while drilling) data stream at \n218\n.', 'The generated data stream is then transmitted to the surface at \n220\n.', 'The surface system \n150\n runs the frame building algorithm at \n252\n based on the pre-established initial conditions \n202\n.', 'The transmitted data stream is received at \n254\n and resynchronized at \n256\n to identify and extract the downhole measurements at \n258\n.', 'During a drilling operation it may be necessary to modify the transmitted data stream.', 'For example, a sensor failure may necessitate a change in the transmitted data content.', 'Likewise, it may be desirable to change the transmitted data content due to various formation specific events or drilling specific events.', 'For example, additional measurements may be acquired upon penetrating a predetermined formation or due to changing drilling conditions such as the onset of stick slip, vibrations, or other dynamic drilling conditions.', 'Additionally, measurement frequency may increase or decrease with changes in drilling speed.', 'A change in telemetry data rate (bit rate) may also necessitate a modification to the transmitted data stream.', 'The disclosed embodiments are, of course, not limited to these particular events.', 'Identification of one more conditions requiring data stream modification may be accommodated, for example as depicted on \nFIG.', '3\n which depicts a flow chart of another embodiment \n300\n.', 'As in \nFIG.', '2\n, the downhole and surface systems \n100\n and \n150\n are configured to run a frame building algorithm.', 'The initial conditions \n302\n include an events database \n304\n including a number of possible events that would make it desirable to make a data stream modification (e.g., events that would require a data stream modification).', 'Embodiment \n300\n is similar to embodiment \n200\n in that the downhole system \n100\n runs the frame building algorithm at \n312\n based on the pre-established initial conditions \n302\n.', 'Downhole measurements (e.g., measurements made by MWD/LWD tool \n60\n) are acquired at \n314\n and combined with synchronization markers \n316\n to generate a real-time (while drilling) data stream at \n318\n.', 'One or more events requiring data stream modification may be detected at \n320\n.', 'As described above, such events may include, for example, penetration of a predetermined formation or formations, changing drilling conditions, or a downlinked request from the surface system \n150\n.', 'Event detection at \n320\n triggers a change in the initial conditions based upon conditions established in the event database.', 'Upon detecting the event(s) at \n320\n, the downhole system \n100\n re-runs the frame building algorithm at \n322\n based on the new initial conditions (from the events database).', 'Synchronization markers \n326\n may be added to update the real-time data stream at \n328\n.', 'The updated data stream may then be transmitted to the surface system at \n330\n.', 'With continued reference to \nFIG.', '3\n, the surface system \n150\n runs the frame building algorithm at \n352\n based on the pre-established initial conditions \n302\n.', 'The transmitted data stream is received at \n354\n and evaluated at \n356\n to identify the synchronization markers added at \n326\n to identify the new initial conditions (from the event data base \n304\n).', 'The surface system \n150\n then re-runs the frame building algorithm at \n360\n based on the new initial conditions to extract the downhole measurements at \n362\n.\n \nFIG.', '4\n depicts a flow chart of an embodiment \n400\n similar to embodiment \n200\n.', 'Sensor data is acquired while drilling at \n402\n by downhole system \n100\n and processed using a frame building algorithm at \n404\n to generate a raw data stream at \n406\n.', 'The raw data stream is processed using a synchronization encoder to generate a synchronized data stream (e.g., a digitized data stream including synchronization bits) at \n408\n using predetermined encoder parameters \n415\n.', 'The synchronized data stream is transmitted to the surface at \n410\n using a downhole telemetry system (e.g., transmission device \n50\n).', 'As is known to those of ordinary skill in the art, such transmission may result in data loss or attenuation due to environmental disturbances such as noise, attenuation, cross talk, etc. depicted schematically at \n420\n.', 'The transmitted signal is received at \n432\n at the surface system \n150\n and processed via a data synchronization decoder at \n434\n using encoder parameters \n415\n (the same parameters used to synchronize the data stream in the downhole system) to obtain an input (received) data stream at \n436\n.', 'The input data stream is then processed at \n438\n using the frame building algorithm to obtain the reconstructed downhole measurements at \n440\n.', 'The example embodiment depicted on \nFIG.', '4\n illustrates how the downhole system \n100\n may generate the digitized data stream including synchronization markers/bits and how the surface system \n150\n may then rebuild the original data structure to extract the measurements.', 'The method adds timing and context information to the data (via the synchronization bits) such that the surface system \n150\n can deduce the nature of the transmitted data even when information is missing or distorted (e.g., due to environmental factors depicted at \n420\n).', 'The synchronization information may include, for example, two components that are repeated at a predefined period known to both the downhole \n100\n and surface \n150\n systems; (i) synchronization information and (ii) optional data stream context information.', 'As is known to those of ordinary skill in the art, the communications channel \n420\n can introduce data stream errors (e.g., due to noise and/or signal attenuation).', 'These errors may in turn cause desynchronization and subsequent data loss.', 'Repeating the synchronization bits (the synchronization information) at a known period enables the surface system \n150\n periodically validate the synchronization of the received data stream.', 'It will be understood that the choice of synchronization bits (or the bit pattern) may be selected based on the characteristics of the telemetry methodology.', 'For example, the synchronization bits may be selected to maximize the Hamming distance between synchronization patterns and to provide a suitable balance of the telemetry symbol choice to maximize the success rate of data recovery.', 'It will be further understood that synchronization encoding (including synchronization bits in the data stream as described herein) tends to degrade the data transmission efficiency (by adding extra bits to the data in the bit stream).', 'In some embodiments, the synchronization bits and the synchronization period may be further optimized so as to balance stability and transmission overhead requirements.', 'The optional data stream context information is intended to uniquely identify the data order in the data stream generated by the frame building algorithm.', 'The context information may further indicate changes to the data stream, for example, due to an event that requires a change in the data stream (e.g., an event that makes it desirable to make a change in the data stream).', 'The context information may also be repeated periodically in the data stream to ensure successful detection.', 'FIG.', '5\n depicts a flow chart of an embodiment \n500\n similar to embodiment \n300\n.', 'Sensor data is acquired while drilling at \n502\n by downhole system \n100\n and processed using a frame building algorithm at \n504\n to generate a raw data stream at \n506\n.', 'The raw data stream is processed using a synchronization encoder to generate a synchronized data stream (e.g., a digitized data stream including synchronization bits) at \n508\n using predetermined encoder parameters \n515\n.', 'Downhole sensors and/or a processor configured to determine the drilling state and/or the rig state may be used at \n510\n to detect one or more events requiring data stream modification at \n512\n (e.g., as described above).', 'A suitable drilling state processor is disclosed in U.S. Patent Publication 2014/0129148 (which is herein incorporated by reference in its entirety).', 'Upon detecting the event(s) at \n512\n, new initial conditions from an events database \n525\n may be input into the frame building algorithm and the synchronization encoder such that data received at \n502\n is processed with the new initial conditions to obtain a synchronized data stream.', 'This data stream may then be transmitted to the surface at \n514\n using the downhole telemetry system.', 'As is known to those of ordinary skill in the art, such transmission may result in data loss or attenuation due to environmental disturbances such as noise, attenuation, cross talk, etc. depicted schematically at \n520\n.', 'The transmitted signal is received at \n532\n at the surface system \n150\n and processed via a data synchronization decoder at \n534\n using encoder parameters \n515\n and the new initial conditions from the events database \n525\n (the same parameters used to synchronize the data stream in the downhole system) to obtain an input (received) data stream at \n536\n.', 'The input data stream is then processed at \n538\n using the frame building algorithm to obtain the reconstructed downhole measurements at \n540\n.', 'With continued reference to \nFIGS.', '2-5\n, the frame building algorithm may be programmed with substantially any suitable initial conditions (which may also be referred to as input parameters).', 'The initial conditions may include, for example, the make-up of the bottom hole assembly (BHA), including the number and order of tools and sensors deployed in the BHA.', 'The initial conditions may further include the telemetry bit rate (transmission rate) as well as the rate (or range of rates) of penetration of drilling.', 'The rate of penetration may be predefined, computed downhole, or received from the surface via downlink.', 'The initial conditions may also include a listing (or set) of priority measurements (e.g., mission critical measurements) to be transmitted by the BHA to the surface at a predetermined or computed vertical resolution.', 'It will be understood that the nature of the priority measurements (e.g., mission critical measurements) or the architecture of the BHA may impose restrictions (constraints) on the format of the digital data stream generated by the frame building algorithm.', 'These restrictions may include, for example, but are not limited to the following constraints: (i) certain measurements may be dependent on other measurements such that inclusion of one in the data stream necessitates inclusion of the other(s); (ii) certain measurements may be incompatible with other measurements such that inclusion of one necessitates exclusion of the other(s); (iii) a certain sequence may be desired (or required) between various measurements; and (iv) various minimum or maximum spacing may be desired (or required) between various measurements.', 'In conventional drilling operations the above described constraints are resolved by a drilling operator at the surface and therefore cannot be implemented automatically downhole.', 'In contrast to conventional drilling operations, certain disclosed embodiments provide a method for automatically resolving the constraints using a downhole processor.', 'The above described constraints may be represented as rules, for example, (i) add, (ii) delete, (iii) reshuffle, and (iv) check rules.', 'The add and delete rules ensure that the above described measurement dependencies are met, for example, by adding or deleting measurements to or from the measurement sequence.', 'These rules are intended to enforce the first and second constraints listed above.', 'The reshuffle rule is intended to enforce the third and fourth constraints by reshuffling the measurement sequence to create a certain sequence and/or to meet any constraints that dictate specific spacing between measurements.', 'The check rule is intended to ensure that the reshuffle rule has not broken the add or delete rule.', 'FIG.', '6\n depicts a flow chart of one example of a method \n600\n used to modify a data stream, for example, upon identifying a predetermined trigger event.', 'Method \n600\n may thus be used to update the frame building algorithm based upon new initial conditions in the event database.', 'The new input conditions are received at \n602\n, for example, in the form of an initial list of downhole measurements to be transmitted to the surface.', 'These measurements may be processed downhole using a dependency algorithm \n604\n, for example, including the above described add and delete rules to determine a final list of measurements for transmission to the surface.', 'The final list of measurements may then be further processed downhole using a sequencing algorithm \n606\n, for example, including the above described reshuffle and check rules to establish the order and spacing between the measurements and to determine the frame structure at \n608\n.', 'It will be understood that method \n600\n may further be depicted as an example frame builder tree.', 'FIG.', '7\n depicts one such example frame builder tree \n700\n.', 'Tree \n700\n may begin with an initial check \n710\n (C\n1\n) to ensure that the correct initial conditions are received and used to determine the appropriate frame structure.', 'After the initial check, the frame builder tree \n700\n may be executed from left to right.', 'The depicted embodiment continues with an add/subtract sequence \n720\n, which may be thought of as being analogous to the dependency algorithm \n604\n described above with respect to \nFIG.', '6\n.', 'The depicted add/subtract sequence \n720\n includes an add/subtract routine \n730\n for each measurement tool in the bottom hole assembly (or correspondingly for each measurement).', 'For example, the leftmost (first) add/subtract routine \n720\n includes add rule A\n1\n followed by subtract rules S\n1\n, S\n2\n, and S\n3\n.', 'The second and third add/subtract routines include corresponding add rules A\n2\n and A\n3\n, each of which is also followed by subtract rules S\n1\n, S\n2\n, and S\n3\n.', 'Tree \n700\n may then continue with check rules C\n1\n and C\n2\n and reshuffle rules R\n1\n, R\n2\n, R\n3\n, R\n4\n, and R\n5\n, which are intended to establish the order and spacing between the measurements.', 'The check rules and reshuffle rules may thus be understood to be analogous to sequencing algorithm \n606\n described above with respect to \nFIG.', '6\n.', 'Although a system and method for downhole data transmission and surface synchronization has been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.'] | ['1.', 'A telemetry method for transmitting data from a downhole location to a surface location, the method comprising:\n(a) detecting a downhole event that requires change to a transmitted data stream;\n(b) causing a downhole processor to process the downhole event detected in (a) in combination with a predefined event database and downhole measurement data using a frame building algorithm to compute a digital data stream;\n(c) adding synchronization markers to the data stream computed in (b) to obtain a synchronized data stream, the synchronization markers identifying the downhole event detected in (a);\n(d) transmitting the synchronized data stream to the surface location using a downhole telemetry tool;\n(e) receiving the synchronized data stream at the surface location and processing the received synchronized data stream with a decoder to obtain a decoded data stream;\n(f) causing a surface processor to process the synchronization markers to identify the downhole event detected in (a); and\n(g) causing the surface processor to process the event detected in (a) in combination with the predefined event database and the decoded data stream using the frame building algorithm processed in (b) to obtain the downhole measurements.', '2.', 'The method of claim 1, wherein the event detected in (a) comprises at least one of the following: (i) receiving a command from the surface location, (ii) penetration of a predetermined formation or formations while drilling, (iii) changing drilling conditions, or (iv) a change in telemetry data rate.', '3.', 'The method of claim 1, wherein (b) further comprises:\n(i) receiving new input conditions from the predefined event database based on the event detected in (a);\n(ii) processing the new input conditions using a dependency checking algorithm to determine a final list of downhole measurements to be transmitted in (d); and\n(iii) processing the final list of measurements using a sequencing algorithm to compute a frame structure for the digital data stream.', '4.', 'The method of claim 3, wherein the dependency checking algorithm employs add rules and subtract rules, wherein the add rules add downhole measurements to the final list of downhole measurements and the subtract rules subtract downhole measurements from the final list of downhole measurements.', '5.', 'The method of claim 3, wherein the sequencing algorithm employs reshuffle rules that reorder the downhole measurements to achieve a predetermined spacing and order of the downhole measurements in the final list of downhole measurements.', '6.', 'The method of claim 1, wherein the downhole telemetry tool comprises a mud pulse telemetry tool, an electromagnetic telemetry tool, or an acoustic telemetry tool.', '7.', 'The method of claim 1, wherein (f) further comprises causing the surface processor to process the synchronization markers in combination with the predefined event database to identify the downhole event detected in (a).', '8.', 'The method of claim 1, wherein adding synchronization markers includes using one or more encoder parameters, and wherein processing the received synchronized data stream with the decoder includes using a data synchronization decoder and the one or more encoder parameters.', '9.', 'A telemetry method for transmitting data from a downhole location to a surface location, the method comprising:\n(a) acquiring downhole measurements while drilling a subterranean well;\n(b) causing a downhole processor to process the downhole measurements using a frame building algorithm to compute a digital data stream for transmission to the surface;\n(c) detecting a downhole event that requires a change to the digital data stream;\n(d) causing the downhole processor to process the downhole event detected in (c) in combination with a predefined event database to modify the frame building algorithm;\n(e) causing the downhole processor to process the downhole measurements using the frame building algorithm modified in (d) to compute a modified digital data stream;\n(f) adding synchronization markers to the modified data stream computed in (e) to obtain a synchronized data stream, the synchronization markers identifying the downhole event detected in (c);\n(g) transmitting the synchronized data stream to the surface location using a downhole telemetry tool;\n(h) receiving the synchronized data stream at the surface location and processing the received synchronized data stream with a decoder to obtain a decoded data stream;\n(i) causing a surface processor to process the synchronization markers to identify the downhole event detected in (c);\n(j) causing the surface processor to process the event detected in (c) in combination with the predefined event database to modify the frame building algorithm; and\n(k) causing the surface processor to process the decoded data stream using the frame building algorithm modified in (j) to obtain the downhole measurements.', '10.', 'The method of claim 9, wherein the event detected in (c) comprises at least one of the following: (i) receiving a command from the surface location, (ii) penetration of a predetermined formation or formations while drilling, (iii) changing drilling conditions, or (iv) a change in telemetry data rate.', '11.', 'The method of claim 9, wherein (d) further comprises:\n(i) receiving new input conditions from the predefined event database based on the event detected in (c);\n(ii) processing the new input conditions using a dependency checking algorithm to determine a final list of downhole measurements to be transmitted in (g); and\n(iii) processing the final list of measurements using a sequencing algorithm to compute a frame structure for the digital data stream.', '12.', 'The method of claim 11, wherein the dependency checking algorithm employs add rules and subtract rules, wherein the add rules add downhole measurements to the final list of downhole measurements and the subtract rules subtract downhole measurements from the final list of downhole measurements.', '13.', 'The method of claim 11, wherein the sequencing algorithm employs reshuffle rules that reorder the downhole measurements to achieve a predetermined spacing and order of the downhole measurements in the final list of downhole measurements.', '14.', 'The method of claim 9, wherein the downhole telemetry tool comprises a mud pulse telemetry tool, an electromagnetic telemetry tool, or an acoustic telemetry tool.', '15.', 'The method of claim 9, wherein (i) further comprises causing the surface processor to process the synchronization markers in combination with the predefined event database to identify the downhole event detected in (c).'] | ['FIG.', '1 depicts a drilling rig on which the disclosed system and method embodiments may be utilized.; FIG.', '2 depicts a flow chart of one disclosed telemetry method embodiment for transmitting data from a downhole location to a surface location.; FIG.', '3 depicts another disclosed telemetry method embodiment.; FIG.', '4 depicts a telemetry method embodiment similar to the embodiment depicted on FIG.', '2.; FIG.', '5 depicts a telemetry method embodiment similar to the embodiment depicted on FIG.', '5.; FIG.', '6 depicts a flow chart of one example method used to modify a data stream.; FIG.', '7 depicts one example frame builder tree for executing the method of FIG.', '6.; FIG. 1 depicts an example offshore drilling assembly, generally denoted 10, suitable for employing the disclosed system and method embodiments.', 'In FIG.', '1 a semisubmersible drilling platform 12 is positioned over an oil or gas formation disposed below the sea floor 16.', 'A subsea conduit 18 extends from deck 20 of platform 12 to a wellhead installation 22.', 'The platform may include a derrick and a hoisting apparatus for raising and lowering the drill string 30, which, as shown, extends into borehole 40 and includes drill bit 32, a transmission device 50, and at least one MWD/LWD tool 60.', 'Drill string 30 may optionally further include any number of other tools including, for example, other MWD/LWD tools, stabilizers, a rotary steerable tool, and/or a downhole drilling motor.; FIG.', '1 further depicts downhole and surface control systems 100 and 150.', 'The downhole system 100 is deployed in the drill string, for example, in proximity to the transmission device 50 and the MWD/LWD tool 60.', 'The downhole system 100 may include substantially any suitable downhole controller, for example, including a programmable processor (such as a microprocessor or a microcontroller) and electronic memory.', 'The downhole controller may also include processor-readable or computer-readable program code embodying logic, including instructions for controlling the function of the transmission device 50.', 'The surface control system 150 may be deployed, for example, on the drilling rig and may include substantially any suitable processing device, such as a personal computer.', 'It will be understood that the disclosed embodiments are explicitly not limited to any particular downhole and surface systems.; FIG.', '2 depicts a flow chart of one depicted telemetry method embodiment 200 for transmitting data from a downhole location such as a drill string to a surface location.', 'In the depicted embodiment, the downhole and surface systems 100 and 150 are configured to run a frame building algorithm as described above using identical initial conditions 202.', 'The initial conditions may be established (e.g., programmed in the downhole system memory) before the initiation of a drilling job (e.g., when the drilling system is at the surface).', 'The downhole system 100 runs the frame building algorithm at 212 based on the pre-established initial conditions 202.', 'Downhole measurements (e.g., measurements made by MWD/LWD tool 60) are acquired at 214 and combined with synchronization markers 216 to generate a real-time (while drilling) data stream at 218.', 'The generated data stream is then transmitted to the surface at 220.', 'The surface system 150 runs the frame building algorithm at 252 based on the pre-established initial conditions 202.', 'The transmitted data stream is received at 254 and resynchronized at 256 to identify and extract the downhole measurements at 258.; FIG.', '4 depicts a flow chart of an embodiment 400 similar to embodiment 200.', 'Sensor data is acquired while drilling at 402 by downhole system 100 and processed using a frame building algorithm at 404 to generate a raw data stream at 406.', 'The raw data stream is processed using a synchronization encoder to generate a synchronized data stream (e.g., a digitized data stream including synchronization bits) at 408 using predetermined encoder parameters 415.', 'The synchronized data stream is transmitted to the surface at 410 using a downhole telemetry system (e.g., transmission device 50).', 'As is known to those of ordinary skill in the art, such transmission may result in data loss or attenuation due to environmental disturbances such as noise, attenuation, cross talk, etc. depicted schematically at 420.', 'The transmitted signal is received at 432 at the surface system 150 and processed via a data synchronization decoder at 434 using encoder parameters 415 (the same parameters used to synchronize the data stream in the downhole system) to obtain an input (received) data stream at 436.', 'The input data stream is then processed at 438 using the frame building algorithm to obtain the reconstructed downhole measurements at 440.; FIG.', '5 depicts a flow chart of an embodiment 500 similar to embodiment 300.', 'Sensor data is acquired while drilling at 502 by downhole system 100 and processed using a frame building algorithm at 504 to generate a raw data stream at 506.', 'The raw data stream is processed using a synchronization encoder to generate a synchronized data stream (e.g., a digitized data stream including synchronization bits) at 508 using predetermined encoder parameters 515.', 'Downhole sensors and/or a processor configured to determine the drilling state and/or the rig state may be used at 510 to detect one or more events requiring data stream modification at 512 (e.g., as described above).', 'A suitable drilling state processor is disclosed in U.S. Patent Publication 2014/0129148 (which is herein incorporated by reference in its entirety).', '; FIG.', '6 depicts a flow chart of one example of a method 600 used to modify a data stream, for example, upon identifying a predetermined trigger event.', 'Method 600 may thus be used to update the frame building algorithm based upon new initial conditions in the event database.', 'The new input conditions are received at 602, for example, in the form of an initial list of downhole measurements to be transmitted to the surface.', 'These measurements may be processed downhole using a dependency algorithm 604, for example, including the above described add and delete rules to determine a final list of measurements for transmission to the surface.', 'The final list of measurements may then be further processed downhole using a sequencing algorithm 606, for example, including the above described reshuffle and check rules to establish the order and spacing between the measurements and to determine the frame structure at 608.'] |
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US11067369 | RF attenuating switch for use with explosives and method of using the same | Jun 28, 2016 | Kenneth Randall Goodman | SCHLUMBERGER TECHNOLOGY CORPORATION | (JRC Jet Research Center ⋅ Pioneer of the Oilwell Shaped Charge [online], jetresearch.com [retrieved on [Aug. 2008], Retrieved from the Internet: <URL: https://www.jetresearch.com/content/dam/jrc/Documents/Brochures/jrc0011.pdf> (Year: 2008). | 4261263; April 14, 1981; Coultas; 4378738; April 5, 1983; Proctor; 5503077; April 2, 1996; Motley; 7116542; October 3, 2006; Lerche et al.; 7347278; March 25, 2008; Lerche; 7975612; July 12, 2011; Teowee; 8091477; January 10, 2012; Brooks; 8230946; July 31, 2012; Crawford; 8365825; February 5, 2013; Yarbro; 8601948; December 10, 2013; Spring; 9064650; June 23, 2015; Keppler; 20040108114; June 10, 2004; Lerche; 20050178282; August 18, 2005; Brooks; 20060249045; November 9, 2006; Goodman; 20120247769; October 4, 2012; Schacherer; 20140131035; May 15, 2014; Entchev; 20150096752; April 9, 2015; Burgos | 2352261; January 2001; GB; WO-2013173404; November 2013; WO | ['A radio frequency attenuating switch including a switch having a first input for connection to an electrical power supply and first and second output leads for connecting a device such as a detonator.', 'One or more RF mitigation devices are connected within one or more of the output leads.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCES TO RELATED APPLICATIONS', 'This application claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application No. 62/269,367, filed Dec. 18, 2015, which is incorporated herein by reference in its entirety as if fully set forth herein.', 'BACKGROUND\n \nThis section provides background information to facilitate a better understanding of the various aspects of the disclosure.', 'It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.', 'Explosives are used in many types of applications, such as hydrocarbon well applications, seismic applications, military armament, and mining applications.', 'In seismic applications, explosives are discharged at the earth surface to create shock waves into the earth subsurface so that data regarding the characteristics of the subsurface may be measured by various sensors.', 'In the hydrocarbon well context, a common type of explosive that is used includes shaped charges in perforating guns.', 'The shaped charges, when detonated, create perforating jets to extend perforations through any surrounding casing or liner and into the surrounding formation to allow communication of fluids between the formation and the wellbore.', 'Also, in a well, other tools may also contain explosives.', 'For example, pyrotechnics can be used to set packers or to activate other tools.', 'SUMMARY\n \nA radio frequency (RF) attenuating switch includes a RF mitigation device connected in an input lead, a printed circuit board, and/or an output lead of a switch.', 'In some embodiments at least two RF mitigation devices are included within the switch to provide redundant safety protection.', 'An explosive assembly in accordance to one or more aspects of the disclosure includes a switch having first and second input leads and first and second output leads, a detonator connected to the first and second output leads, a controller connected through the first input lead to the detonator when the switch is in a closed state and a radio frequency mitigation device operationally connected between the controller and the detonator.', 'A method includes deploying a perforating gun into a wellbore, the perforating gun having a firing head electrically connecting an electrical power source through a first switch to a first detonator connected to a first plurality of explosive charges and electrically connecting a second switch to second detonator connected to a second plurality of explosive charges, and a radio frequency mitigation device operationally connected between the electrical power source and the first detonator, and detonating the first plurality of explosive charges in response to closing the first switch thereby connecting an electrical power supply to the first detonator.', 'This summary is provided to introduce a selection of concepts that are further described below in the detailed description.', 'This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subj ect matter.', 'BRIEF DESCRIPTION OF THE DRAWINGS', 'The disclosure is best understood from the following detailed description when read with the accompanying figures.', 'It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale.', 'In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.', 'FIG.', '1\n is a schematic diagram of a RF attenuating switch in accordance to one or more aspects of the disclosure incorporated in an explosive assembly.\n \nFIG.', '2\n is a schematic diagram of a RF attenuating switch in accordance to one or more aspects of the disclosure configured as a module with a connected detonator.', 'FIGS.', '3 to 5\n are schematic diagrams illustrating additional non-limiting examples of RF attenuating switches in accordance to one or more aspects of the disclosure incorporated in an explosive assembly.\n \nFIG.', '6\n illustrates a wellbore tool assembly incorporating RF attenuating switches in accordance to one or more aspects of the disclosure.\n \nFIG.', '7\n illustrates a wellbore in which an explosive assembly is deployed and incorporates a RF attenuating switch in accordance to one or more aspects of the disclosure is deployed.', 'DETAILED DESCRIPTION', 'It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.', 'Specific examples of components and arrangements are described below to simplify the disclosure.', 'These are, of course, merely examples and are not intended to be limiting.', 'In addition, the disclosure may repeat reference numerals and/or letters in the various examples.', 'This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.', 'As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements.', 'Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements.', 'Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element are may be utilized to more clearly describe some elements.', 'Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.', 'FIGS.', '1-5\n are non-limiting schematic diagrams illustrating radio frequency (RF) attenuating switches \n10\n (i.e., switch circuits) configured for utilization in explosive assemblies generally denoted by the numeral \n5\n.', 'With reference to \nFIG.', '1\n, the RF attenuating switch \n10\n is electrically connected to a detonator \n12\n to detonate an explosive charge \n9\n.', 'The RF attenuating switch \n10\n includes a first input lead \n16\n and a second input lead \n18\n connected to a control unit \n20\n in \nFIG.', '1\n which provides power and controls closure of switches \n22\n.', 'Control unit \n20\n may include one or more power sources that can be located locally and/or remote from the RF attenuating switch \n10\n.', 'One or more switches \n22\n are connected between the control unit \n20\n and the detonator \n12\n.', 'Switches \n22\n control the power supplied to the detonator \n12\n across output leads \n24\n and \n26\n.', 'In accordance to some embodiments switches \n22\n are field effect transistors which are generally effective as power control devices but are ineffective barriers to RF power as capacitance from drain to source effectively short the device at high RF frequencies.', 'The switches \n22\n are in a default open, or safe, state.', 'Multiple RF attenuating switches \n10\n may be connected as illustrated for example in \nFIG.', '1\n.', 'The length of the leads or the effective antenna length of the switch \n10\n and can significantly vary depending on the operation or use case of the device.', 'For example, in the use of a switch \n10\n that has not been connected with a detonator the leads may only be a few inches or less and therefore there is a limited risk of radio frequency power reception or pickup.', 'As the effective antenna length of the switch increases the risk of unwanted power reception increases.', 'For example, a switch \n10\n may have an effective antenna length of a few inches but when connected in an explosive assembly the effective antenna length of the switch circuit may increase to tens or hundreds of feet increasing the risk of unwanted power reception.', 'The exposure to various RF frequencies and RF transmitter power is increasing as new transmission and radar towers are erected on land and offshore traffic and RF sources increase.', 'The exposure to unwanted power sources also various based on use cases.', 'For example, at a work site the RF power sources (e.g., radios and towers) can be identified and exposure may be limited by precautions such as increasing the distance from the sources and limiting effective antenna length.', 'The exposure to RF sources may increase and be less controllable when transporting an explosive assembly over a roadway.', 'The RF attenuating switch \n10\n isolates the detonator \n12\n from the control unit \n20\n and it does not have a single point of failure that will allow power to the detonator.', 'The RF attenuating switch \n10\n includes the wiring to the control unit and the wiring to the detonator \n12\n.', 'In accordance to one or more embodiments, the RF attenuating switch provides one or more methods of RF protection, e.g., greater than about 10 volt/meter, stray voltage protection for example of about 25 volts or greater, and inadvertent application of power protection, e.g., the lesser of the rating of the control power system or about 600 volts.', 'The detonator may also be an RF-safe device that is connected to the RF attenuating switch \n10\n in use.', 'RF attenuating, or mitigation, devices generally designated by the numeral \n32\n (\nFIG.', '1\n) are placed in the input \n16\n, \n18\n and or output leads \n24\n, \n26\n to provide double fault protection against shorts that occur across the switches \n22\n for example via RF and pinched wires.', 'The RF mitigation devices \n32\n may be connected to a lead on a printed circuit board, illustrated by the box \n7\n, and or on conductor portions (e.g., wires) external to the switch circuit board.', 'In accordance to some embodiments, RF mitigation devices may include shielding \n32\n-\n1\n on the wires.', 'In the illustrated circuits at least two RF mitigation devices \n32\n are connected in a lead between the input \n18\n and output \n24\n and at least one RF mitigation device \n32\n is placed in the lead, i.e., circuit, between input \n16\n and output \n26\n.', 'The RF mitigation device \n32\n may be positioned in the input lead (signal) to the switch \n10\n and/or in an output lead to the detonator \n12\n.', 'The RF mitigation devices \n32\n may include various devices such as and without limitation spark gaps \n36\n, RF chokes \n40\n, shielding \n32\n-\n1\n and shunt capacitors \n30\n.', 'It should be recognized that a RF mitigation device may not be included in one of the leads and to provide redundancy two or more RF mitigation devices may be included in the one lead that includes RF mitigation.', 'A single RF mitigation device may filter more than one signal.\n \nFIG.', '2\n is a schematic diagram illustrating a radio frequency (RF) attenuating switch \n10\n in accordance to one or more embodiments.', 'In this illustrated example the RF attenuating switch \n10\n is configured as a module with a detonator \n12\n, e.g., a printed circuit board and a detonator, and disposed for example in a housing \n34\n.', 'In the module state prior to being connected with an explosive assembly the length of the leads or the effective antenna length can be short, for example less than a foot long, and thus the risk of RF pickup is limited.', 'However, when the module is connected in an explosive assembly for example for transport or use the effective antenna length will increase.', 'For example, the switch in \nFIG.', '2\n may be connected within a tool, such as illustrated in \nFIG.', '6\n, including connecting the control line \n52\n wiring to the inputs \n16\n and/or \n18\n thereby increasing the length of the leads of the switch.', 'For example, connecting the switch into a tool may increase the effective antenna length from a few inches, e.g. four inches, to tens of feet (e.g., 10, 20, 30, 40 or more feet) thereby increasing the risk of RF power pickup.', 'As illustrated in the various figures, the RF mitigation devices may be connected in the wiring in various locations in the tool.', 'In the non-limiting example of \nFIG.', '2\n the RF mitigation devices \n32\n are spark gaps \n36\n (i.e., spark gap circuits).', 'One spark gap \n36\n is connected in series with the output lead \n24\n and the other spark gap \n36\n is connected in series with the output lead \n26\n.', 'The spark gaps \n36\n provide a high voltage stand-off, i.e., act as a low capacitance switch, until gas in the spark gap circuit becomes ionized and the voltage drop across the spark gap drops.', 'The spark gap circuit raises the threshold that needs to be reached before RF exposure and/or stray voltage triggers the detonator \n12\n.', 'Because the spark gap circuit is an open circuit, the spark gap cannot be used to send a trickle current to test the circuit.', 'A resistor \n38\n is connected in parallel with each of the spark gaps \n36\n to facilitate testing.', 'In this example, the switch also includes shunt capacitors \n30\n to redirect the frequency noise and voltage to ground.', 'With reference to \nFIG.', '2\n the RF attenuating switch \n10\n provides RF barriers and power barriers to mitigate stray power as well as lead shorts.', 'The RF attenuating switch \n10\n in \nFIG.', '2\n includes the two spark gaps \n36\n, input leads \n16\n and \n18\n to the switch and output leads \n24\n, \n26\n extending from the switch for example to the detonator \n12\n.', 'If input lead \n18\n and output lead \n24\n, external to the switch, are shorted power protection is provided by the two switches \n22\n and RF protection by the spark gap in the output lead \n26\n.', 'If input lead \n18\n and output lead \n26\n or input lead \n16\n to output lead \n24\n are shorted then the detonator is bypassed.', 'If input lead \n16\n to output lead \n26\n is shorted then protection is provided at the spark gap \n36\n in the output lead \n24\n.', 'FIG.', '3\n illustrates a non-limiting example of a RF attenuating switch \n10\n connected in an explosive assembly \n5\n.', 'In this example, spark gaps \n36\n connected in series with each of the output leads \n24\n, \n26\n for example on the circuit board \n7\n.', 'A RF mitigation device \n32\n in the form of a RF choke \n40\n is connected in one of the input leads, e.g. input \n18\n, and another RF mitigation \n32\n in the form of a RF choke \n40\n is located in one of the output leads, e.g. output \n26\n.', 'In this example the RF chokes \n40\n are located in the wiring external to the printed circuit board.', 'RF attenuation may be improved by utilizing RF chokes \n40\n on an input and an output lead or leads as opposed to one RF choke on the input or the output.', 'With reference to \nFIG.', '6\n an RF mitigation device \n32\n is shown connected to the wiring in the firing head \n44\n.', 'RF mitigation devices \n32\n may be included in other locations, such as sub or tool (e.g., casing collar locator), remote from the switch.', 'In \nFIG.', '4\n the illustrated RF attenuating switch \n10\n is illustrated utilizing RF mitigation devices \n32\n in the form of RF chokes \n40\n, for example ferrite beads or other inductors.', 'The RF chokes may be incorporated as inductors placed for example on the wire leads or pins of switch \n10\n circuit.', 'The RF chokes have an impedance to block the stray high frequency signals.', 'In \nFIG.', '5\n the RF attenuating switch \n10\n utilizes both spark gap \n36\n circuits and RF chokes \n40\n as the RF mitigation devices \n32\n.\n \nFIG.', '6\n illustrates an explosive assembly \n5\n configured in a wellbore device or tool \n42\n, e.g. a perforating gun, and utilizing RF attenuating switches \n10\n connected to detonators \n12\n in accordance to one or more embodiments of the disclosure.', 'The RF attenuating switch \n10\n is disposed in and operationally connected with a carrier \n43\n (e.g. loading tube and/or housing).', 'Connecting the RF attenuating switch \n10\n in the carrier \n43\n may include connecting the input leads to wiring in the carrier thereby increasing the effective antenna length of the RF attenuating switch \n10\n for example from a few inches or a few feet to tens of feet or more.', 'The carrier \n43\n with the RF attenuating switch and detonator \n12\n may be transported over the roadway.', 'In some instances carrier \n42\n may be transported over the roadways with the RF attenuating switch \n10\n, detonators \n12\n, and explosive charges \n9\n installed.', 'The illustrated wellbore tool \n42\n is arranged as a perforating gun having a firing head \n44\n connected to individually controlled gun sections \n46\n each comprising a plurality of shaped explosive charges \n9\n.', 'The gun sections \n46\n, e.g., explosive devices, can be individually controlled by the associated RF attenuating switches \n10\n, see for example \nFIGS.', '1-5\n.', 'In accordance to embodiments, the explosive assembly \n5\n is a selectable firing system \n48\n.', 'A series of RF attenuating switches \n10\n (addressable or non-addressable switches) are connected to detonators \n12\n.', 'Each RF attenuating switch \n10\n and detonator \n12\n are connected via a detonation cord \n50\n to associated explosive charges \n9\n of a gun section \n46\n.', 'For example in \nFIGS.', '6 and 7\n the top gun section \n46\n is connected to the RF attenuating switch \n10\n that is positioned between the two gun sections and the bottom gun section \n46\n is connected to the bottom RF attenuating switch \n10\n, wherein the firing head is the top of the wellbore tool.', 'Digital communications can be used to operationally test, arm and fire the RF attenuating switches \n10\n.', 'The switch may be tested when the tool is assembled and prepared for transport, at a well site, and or when connected to a control line and suspended for example in the wellbore.', 'Each RF attenuating switch \n10\n may or may not have a unique address to individually identify the associated explosive device (e.g., gun section).', 'All circuits, gun wiring, and connections can be tested at the surface prior to running into the wellbore.', 'While running in hole, the testing can be done with a perforation acquisition system.', 'Electrical power and control signals may be communicated from the surface of a wellbore to the gun assembly via a control line \n52\n (e.g., wireline) which includes or is an extension of the inputs \n16\n, \n18\n (\nFIGS.', '1-5\n).', 'The firing head may include one or more operational devices \n54\n such as and without limitation telemetry systems and sensor systems such as accelerometers, inclinometers, magnetometers, pressure, temperature and depth correlation sensors.', 'In accordance to one or more embodiments, the firing head \n44\n is operationally connected to the explosive charges \n9\n of the tool sections \n46\n through an arming switch \n56\n which may be a part of the firing head.', 'FIG.', '7\n illustrates a wellbore tool \n42\n utilizing a RF attenuating switch \n10\n deployed in a well system \n58\n.', 'The wellbore tool \n42\n is deployed in a wellbore \n60\n on a conveyance, which is a wireline \n52\n, i.e. control line, in the illustrated example.', 'The control line \n52\n connects the control unit \n20\n and in the illustrated example a processor \n28\n located at the surface \n64\n to input leads of the RF attenuating switch \n10\n disposed in the wellbore tool \n42\n.', 'When the wellbore tool \n42\n is connected with the control line and suspended from the surface rig \n70\n the effective antenna length of the switch may be in the hundreds of feet increasing the RF pickup of the systems as compared to the switch alone.', 'The wellbore tool \n42\n may incorporate a firing system \n48\n utilizing RF attenuating switches \n10\n.', 'The RF attenuating switches \n10\n have no single faults.', 'In accordance to one or more embodiments, the RF attenuating switches \n10\n provide one or more methods of RF protection, e.g., greater than about 10 volt/meters, stray voltage protection for example of about 25 volts or greater, and inadvertent application of power protection, e.g., the lesser of the rating of the control power system or about 600 volts.', 'In accordance to some embodiments, electrostatic discharge for example of about 15 kV or greater are provided.', 'In accordance to some embodiments RF protection of about 10 volt/meters or greater is provided.', 'Once located in the desired location in the wellbore the individual gun sections \n46\n may be activated via the associated RF attenuating switch \n10\n to detonate the associated explosive charges \n9\n and create perforations \n66\n in the surrounding formation \n68\n.', 'The activating comprises operating the respective RF attenuating switches \n10\n to a closed position to connect the electrical control unit \n20\n to the detonator \n12\n thereby detonating the detonator \n12\n and the connected explosive charges \n9\n.', 'In accordance to embodiments, activating includes communicating a command via telemetry to close the RF attenuating switch.', 'The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure.', 'Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein.', 'Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the disclosure.', 'The scope of the invention should be determined only by the language of the claims that follow.', 'The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group.', 'The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.'] | ['1.', 'A method, comprising:\ndeploying a perforating gun into a wellbore, the perforating gun comprising a firing head electrically connecting an electrical power source through a first RF attenuating switch to a first detonator connected to a first plurality of explosive charges and electrically connecting a second RF attenuating switch to a second detonator connected to a second plurality of explosive charges, wherein each RF attenuating switch comprises: a first input lead connected to the electrical power source; a second input lead connected to the electrical power source; a first output lead connected to the detonator; a second output lead connected to the detonator; and a first RF mitigation device connected to a first output lead of the RF attenuating switch; a second RF mitigation device connected to a second output lead of the RF attenuating switch, wherein the first and second RF mitigation device comprises a spark gap connected in series with the first and second output leads; a first and second resistor connected in parallel with each of the spark gaps; and\ndetonating the first plurality of explosive charges in response to closing the first RF attenuating switch thereby connecting an electrical power supply to the first detonator.', '2.', 'The method of claim 1, wherein the RF mitigation device is connected to a printed circuit board (PCB) of the first RF attenuating switch.', '3.', 'The method of claim 1, wherein one or more RF mitigation devices in addition to the first and second RF mitigation devices are connected to or surrounding at least one of the input leads or one of the output leads, the one or more RF mitigation devices comprising one or more of a spark gap, a capacitor, a RF choke or shielding.', '4.', 'The method of claim 1, wherein the RF mitigation device comprises a first RF mitigation device connected to or surrounding the first output lead from the RF attenuating switch and a second RF mitigation device connected to or surrounding the second output lead of the RF attenuating switch.', '5.', 'The method of claim 1, wherein the RF mitigation device is connected to or surrounding a first output lead of the RF attenuating switch; and, wherein the perforating gun further comprises:\na second RF mitigation device connected to or surrounding a second output lead of the RF attenuating switch; and\na third RF mitigation device connected to or surrounding an input lead to the RF attenuating switch.', '6.', 'The method of claim 5, wherein the RF attenuating switch further comprises: at least one switch connected to the second output lead.', '7.', 'The method of claim 1, wherein the RF mitigation device surrounds the first input lead to the RF attenuating switch; and, wherein the perforating gun further comprises:\na second RF mitigation device surrounding a first output lead of the RF attenuating switch; and\na third RF mitigation device surrounding a second output lead of the RF attenuating switch.', '8.', 'The method of claim 7, wherein the RF attenuating switch further comprises: at least one switch connected to the second output lead.', '9.', 'The method of claim 1, wherein the RF mitigation device is connected to a first output lead of the RF attenuating switch; and, wherein the perforating gun further comprises:\na second RF mitigation device connected to a second output lead of the RF attenuating switch, wherein the first and second RF mitigation device comprises a spark gap connected in series with the first and second output leads;\na third RF mitigation device surrounding the first output lead of the RF attenuating switch; and\na fourth RF mitigation device surrounding the second output lead of the RF attenuating switch.\n\n\n\n\n\n\n10.', 'The method of claim 1, wherein the perforating gun further comprises:\na third RF mitigation device surrounding the first input lead of the RF attenuating switch; and\na fourth RF mitigation device surrounding the second output lead of the RF attenuating switch.', '11.', 'The method of claim 1, wherein the RF attenuating switch further comprises:\na shunt capacitor connected to at least one of the first or second output lead.'] | ['FIG.', '1 is a schematic diagram of a RF attenuating switch in accordance to one or more aspects of the disclosure incorporated in an explosive assembly.; FIG.', '2 is a schematic diagram of a RF attenuating switch in accordance to one or more aspects of the disclosure configured as a module with a connected detonator.; FIGS.', '3 to 5 are schematic diagrams illustrating additional non-limiting examples of RF attenuating switches in accordance to one or more aspects of the disclosure incorporated in an explosive assembly.; FIG.', '6 illustrates a wellbore tool assembly incorporating RF attenuating switches in accordance to one or more aspects of the disclosure.', '; FIG.', '7 illustrates a wellbore in which an explosive assembly is deployed and incorporates a RF attenuating switch in accordance to one or more aspects of the disclosure is deployed.; FIGS.', '1-5 are non-limiting schematic diagrams illustrating radio frequency (RF) attenuating switches 10 (i.e., switch circuits) configured for utilization in explosive assemblies generally denoted by the numeral 5.', 'With reference to FIG.', '1, the RF attenuating switch 10 is electrically connected to a detonator 12 to detonate an explosive charge 9.', 'The RF attenuating switch 10 includes a first input lead 16 and a second input lead 18 connected to a control unit 20 in FIG.', '1 which provides power and controls closure of switches 22.', 'Control unit 20 may include one or more power sources that can be located locally and/or remote from the RF attenuating switch 10.', 'One or more switches 22 are connected between the control unit 20 and the detonator 12.', 'Switches 22 control the power supplied to the detonator 12 across output leads 24 and 26.', 'In accordance to some embodiments switches 22 are field effect transistors which are generally effective as power control devices but are ineffective barriers to RF power as capacitance from drain to source effectively short the device at high RF frequencies.', 'The switches 22 are in a default open, or safe, state.', 'Multiple RF attenuating switches 10 may be connected as illustrated for example in FIG.', '1.; FIG. 2 is a schematic diagram illustrating a radio frequency (RF) attenuating switch 10 in accordance to one or more embodiments.', 'In this illustrated example the RF attenuating switch 10 is configured as a module with a detonator 12, e.g., a printed circuit board and a detonator, and disposed for example in a housing 34.', 'In the module state prior to being connected with an explosive assembly the length of the leads or the effective antenna length can be short, for example less than a foot long, and thus the risk of RF pickup is limited.', 'However, when the module is connected in an explosive assembly for example for transport or use the effective antenna length will increase.', 'For example, the switch in FIG.', '2 may be connected within a tool, such as illustrated in FIG.', '6, including connecting the control line 52 wiring to the inputs 16 and/or 18 thereby increasing the length of the leads of the switch.', 'For example, connecting the switch into a tool may increase the effective antenna length from a few inches, e.g. four inches, to tens of feet (e.g., 10, 20, 30, 40 or more feet) thereby increasing the risk of RF power pickup.', 'As illustrated in the various figures, the RF mitigation devices may be connected in the wiring in various locations in the tool.', '; FIG.', '3 illustrates a non-limiting example of a RF attenuating switch 10 connected in an explosive assembly 5.', 'In this example, spark gaps 36 connected in series with each of the output leads 24, 26 for example on the circuit board 7.', 'A RF mitigation device 32 in the form of a RF choke 40 is connected in one of the input leads, e.g. input 18, and another RF mitigation 32 in the form of a RF choke 40 is located in one of the output leads, e.g. output 26.', 'In this example the RF chokes 40 are located in the wiring external to the printed circuit board.', 'RF attenuation may be improved by utilizing RF chokes 40 on an input and an output lead or leads as opposed to one RF choke on the input or the output.', 'With reference to FIG.', '6 an RF mitigation device 32 is shown connected to the wiring in the firing head 44.', 'RF mitigation devices 32 may be included in other locations, such as sub or tool (e.g., casing collar locator), remote from the switch.; FIG.', '6 illustrates an explosive assembly 5 configured in a wellbore device or tool 42, e.g. a perforating gun, and utilizing RF attenuating switches 10 connected to detonators 12 in accordance to one or more embodiments of the disclosure.', 'The RF attenuating switch 10 is disposed in and operationally connected with a carrier 43 (e.g. loading tube and/or housing).', 'Connecting the RF attenuating switch 10 in the carrier 43 may include connecting the input leads to wiring in the carrier thereby increasing the effective antenna length of the RF attenuating switch 10 for example from a few inches or a few feet to tens of feet or more.', 'The carrier 43 with the RF attenuating switch and detonator 12 may be transported over the roadway.', 'In some instances carrier 42 may be transported over the roadways with the RF attenuating switch 10, detonators 12, and explosive charges 9 installed.; FIG. 7 illustrates a wellbore tool 42 utilizing a RF attenuating switch 10 deployed in a well system 58.', 'The wellbore tool 42 is deployed in a wellbore 60 on a conveyance, which is a wireline 52, i.e. control line, in the illustrated example.', 'The control line 52 connects the control unit 20 and in the illustrated example a processor 28 located at the surface 64 to input leads of the RF attenuating switch 10 disposed in the wellbore tool 42.', 'When the wellbore tool 42 is connected with the control line and suspended from the surface rig 70 the effective antenna length of the switch may be in the hundreds of feet increasing the RF pickup of the systems as compared to the switch alone.'] |
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US11066905 | Oilfield reservoir saturation and permeability modeling | Jun 24, 2016 | Sylvain Wlodarczyk, Keith Pinto, Olivier Marche, Akshat Gupta | Schlumberger Technology Corporation | Skalinski et al. (“Defining and Predicting Rock Types in Carbonates—Preliminary Results from an Integrated Approach using Core and Log Data from the Tengiz Field”, Petrophysics, vol. 47, No. 1 (Feb. 2006); p. 37-52) (Year: 2006).; Harrison et al. (“Saturation Height Methods and Their Impact on Volumetric Hydrocarbon in Place Estimates”, Society of Petroleum Engineers, 2001, pp. 1-12) (Year: 2001).; Edward D. Pittman (“Estimating Pore Throat Size in Sandstones from Routine Core-Analysis Data”, AAPG Bulltein, V. 76 , 1992, p. 191-198) (Year: 1992).; Thomeer et al. (“Introduction of a Pore Geometrical Factor Defined by the Capillary Pressure Curve”, Society of Petroleum Engineers, 1960, pp. 73-77) (Year: 1960).; Francesconi et al. 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Society of Petroleum Engineers of AIME, Journal of Petroleum Technology, pp. 2498-2504.; International Preliminary Report on Patentability for International Patent Application No. PCT/US2016/026311 dated Oct. 19, 2017.; International Search Report and Written Opinion for No. PCT/US2016/026311 dated Jul. 28, 2016.; Extended Search Report for European Patent Application No. 16777232.6 dated Dec. 6, 2018.; Office Action for U.S. Appl. No. 15/564,723 dated Feb. 24, 2020.; International Preliminary Report on Patentability for International Patent Application No. PCT/US2016/034939 dated Dec. 14, 2017.; International Search Report and Written Opinion for No. PCT/US2016/034939 dated Sep. 21, 2016.; Search Report for French Patent Application No. 1554944 dated May 2, 2016.; Extended Search Report for European Patent Application No. 16804196.0 dated Feb. 18, 2019.; Office Action for U.S. Appl. No. 15/577,326 dated Dec. 12, 2019, 26 pages.; Notice of Allowace for U.S. Appl. No. 15/577,326 dated Jun. 1, 2020, 12 pages. | 4211106; July 8, 1980; Swanson; 4628468; December 9, 1986; Thompson; 4783751; November 8, 1988; Ehrlich; 5251286; October 5, 1993; Wiener; 5493226; February 20, 1996; Honarpour; 5698772; December 16, 1997; Deruyter; 5828981; October 27, 1998; Callender; 6226390; May 1, 2001; Deruyter; 6516080; February 4, 2003; Nur; 6941804; September 13, 2005; Hasem; 7490028; February 10, 2009; Sayers; 7707013; April 27, 2010; Valdez; 8645070; February 4, 2014; Hanson et al.; 8676556; March 18, 2014; Deffenbaugh; 9952351; April 24, 2018; Kuznetsov; 10495774; December 3, 2019; Kleinberg; 20060047432; March 2, 2006; Egermann et al.; 20060116828; June 1, 2006; Chen; 20070143025; June 21, 2007; Valdez; 20070143026; June 21, 2007; Valdez; 20090228249; September 10, 2009; Green; 20110004447; January 6, 2011; Hurley; 20120109603; May 3, 2012; Li; 20120130639; May 24, 2012; Hanson; 20120275658; November 1, 2012; Hurley; 20130103319; April 25, 2013; Buiting; 20130297272; November 7, 2013; Sung; 20140048694; February 20, 2014; Pomerantz; 20140136116; May 15, 2014; Banian; 20140136117; May 15, 2014; Banian; 20140257702; September 11, 2014; Al-Ibrahim; 20140343909; November 20, 2014; Guerillot; 20140350860; November 27, 2014; Mezghani; 20160187532; June 30, 2016; Hurley; 20170053046; February 23, 2017; Forsyth; 20180163533; June 14, 2018; Wlodarczyk | 98/40763; September 1998; WO; 2007/076044; July 2007; WO; 2014/143166; September 2014; WO; 2015/021088; February 2015; WO | ['A method for modelling saturation in a reservoir, comprising: obtaining capillary pressure data representing capillary pressure in the reservoir; obtaining permeability data representing permeability in the reservoir; determining a number of pore throats represented by the capillary pressure data; creating hyperbolic tangents based on the capillary pressure data equal in number to the number of pore throats; combining hyperbolic tangents to create a curve to fit the capillary pressure data and to define hyperbolic tangent parameters; combining at least one of the hyperbolic tangent parameters with the permeability data to define a saturation height function; modelling a saturation in the reservoir using the saturation height function; and displaying the saturation model based on the saturation height function.', 'The determination of the number of pore throats may comprise creating an initial capillary pressure curve using a predetermined number of multiple linked hyperbolic tangents, determining a first derivative of the capillary pressure curve, and determining a number of local minima in the capillary pressure curve.'] | ['Description\n\n\n\n\n\n\nCROSS-REFERENCE TO RELATED APPLICATION', 'The present document is based on and claims priority to FR Non-Provisional Application Serial No.: 1556146, filed Jun. 30, 2015, which is incorporated herein by reference in its entirety.', 'BACKGROUND', 'In order to create accurate oilfield reservoir models, a saturation of water and hydrocarbon may be predicted at a given point in the oilfield reservoir.', 'Saturation data may be available at the well scale, where it can be accurately derived from petrophysical well log data using various industry workflows and standards.', 'However, it may be desirable to calculate saturation at the reservoir scale, where few reservoir properties are known.', 'In such cases, a saturation model may be obtained using a saturation height function.', 'However, saturation models may rely on saturation height functions for single pore throat systems, or if multiple pore throats modeling is possible, on unstable models that are dependent on the number of data points used and the selection of the best fit intervals.', 'In addition, there are no automatic ways to determine the number of pore throats that can be set and over which intervals.', 'SUMMARY\n \nEmbodiments of the disclosure may provide a computing system, non-transitory computer-readable medium, and method for modeling saturation in a reservoir.', 'For example, the method includes obtaining capillary pressure data representing capillary pressure in the reservoir and obtaining permeability data representing permeability in the reservoir.', 'The method may further include determining a number of pore throats represented by the capillary pressure data, creating hyperbolic tangents based on the capillary pressure data equal in number to the number of pore throats, and combining hyperbolic tangents to create a curve to fit the capillary pressure data and to define hyperbolic tangent parameters.', 'The method may further include combining at least one of the hyperbolic tangent parameters with the permeability data to define a saturation height function, modeling a saturation in the reservoir using the saturation height function; and displaying the saturation model based on the saturation height function.', 'The determining of the number of pore throats may include creating an initial capillary pressure curve to identify the number of pore throats represented by the capillary pressure data.', 'In another embodiment, the determining of the number of pore throats may include creating the initial capillary pressure curve using a predetermined number of multiple linked hyperbolic tangents; determining a first derivative of the capillary pressure curve; and determining a number of local minima in the capillary pressure curve.', 'The number of pore throats represented by the capillary pressure data may correspond to the number of local minima.', 'In another embodiment, the predetermined number of hyperbolic tangents is equal or greater to the number of pore throats to be identified in the capillary pressure data.', 'In another embodiment, the at least one hyperbolic tangent parameter has a linear relationship with the logarithm of the obtained permeability data.', 'In another embodiment, each of the respective hyperbolic tangents is created for a unique one of the respective pore throats, such that no two of the hyperbolic tangents are created for the same one of the pore throats.', 'In another embodiment, the hyperbolic tangents are defined by the following equation:', 'f\n(\nP,a\nn\n,w\nn\n,t\nn\n)=\na\n1\n+a\nN\n+Σ\nN\nn=1\n(\na\nn+1\n−a\nn\n)·tan \nh\n(\nw\nn\n·(\nP−t\nn\n))', 'with constraints: \n \nw\nn\n>0,∀\nn∈\n[1\n,N\n]\nn,N∈\n \n \na\nn+1\n 0,∀\nn\n∈[1\n,N\n]\nn,N∈\n \n \na\nn+1\n<a\nn\n,∀n\n∈[1\n,N\n−1]\nn,N∈\n \n where P is the logarithmic transform of the normalized capillary pressure and N is the number of hyperbolic tangents set for the model.', 'In one embodiment, the number of hyperbolic tangents of the model in Equation 2 is predetermined and corresponds to the number of pore throats.', 'In other embodiments, the number of pore throats is automatically detected and the number of hyperbolic tangents is selected to correspond to the number of pore throats.', 'For example, \nFIG.', '6\n illustrates capillary pressure data from a 3-pore throat system, accordingly, Equations 1-2 would be set to N=3.', 'In one embodiment, the scaling factors (a\nn+1\n-a\nn\n) of each hyperbolic tangent in the set N are linked together so that the sum of the hyperbolic tangents are bounded between 2a1 and 2aN. The linking may force the partition of the hyperbolic tangents among various pore throats.', 'For example, forcing one hyperbolic tangent per pore throat instead of one hyperbolic tangent over 3 pore throat and two other hyperbolic tangents with no contribution.', 'That is, as illustrated in \nFIG.', '8\n, each hyperbolic tangent may be limited to one pore throat.', 'In one embodiment, the constraints present in Equation 2 are configured to limit the hyperbolic tangents to realistic capillary pressure curves and improves the stability of the model.', 'For example, the hyperbolic tangents may be sorted by the number of pore throats in the system, with the “first” hyperbolic tangent starting on the left.', 'Each pore throat and the corresponding combined hyperbolic tangent may be set as monotonous decreasing functions.', 'For example, \nFIGS.', '3, 4, and 5\n illustrate a model of hyperbolic tangents in a capillary pressure and water saturation system according to an embodiment. \nFIG.', '3\n illustrates a single hyperbolic tangent \n310\n in a capillary pressure and water saturation system created using Equation 2 above with the constraints therein.', 'The x-axis represents the capillary pressure and the y-axis represents the water-saturation.', 'FIG.', '4\n illustrates two hyperbolic tangents \n320\n and \n330\n created using Equation 2 above with the constraints therein.', 'As illustrated in \nFIG.', '4\n, a third hyperbolic tangent \n340\n is the sum of hyperbolic tangents \n320\n and \n330\n and represents a dual pore throat system.\n \nFIG.', '5\n illustrates two hyperbolic tangents \n350\n and \n360\n created without the constraints in Equation 2 above, and a third hyperbolic tangent \n370\n which is the sum of hyperbolic tangents \n350\n and \n360\n.', 'As illustrated in \nFIG.', '5\n, the third hyperbolic tangent \n370\n may not represent a realistic capillary pressure curve because the underlying unconstrained hyperbolic tangents \n350\n and \n360\n go in different directions.', 'A hyperbolic tangent may also not represent a realistic capillary pressure curve if it results in a non-monotonous decreasing function.', 'In one embodiment, a non-linear optimization routine is used to find the best-fit parameters.', 'For example, a non-linear optimization routine configured to handle linear inequalities constraints, such as sequential quadratic programing, may be used to find the best-fit parameters.', 'FIGS.', '6, 7, and 8\n illustrate a capillary pressure model according to embodiments of this disclosure.', 'FIG.', '6\n illustrates capillary pressure data from a multi-pore throat system.', 'FIG.', '7\n illustrates a best-fit curve \n410\n over the capillary pressure data.', 'As illustrated in \nFIG.', '7\n, the best fit curve \n410\n is the sum of three hyperbolic tangents \n420\n, \n430\n, and \n440\n.', 'FIG.', '8\n illustrates the three hyperbolic tangents \n420\n, \n430\n, and \n440\n shifted show which hyperbolic tangent corresponds to with pore throat.', 'As illustrated in \nFIGS.', '6-8\n, a capillary pressure model incorporating Equations 1 and 2 shows a good fit to the measured capillary pressure data wells, and a number of hyperbolic tangents N can be set to fit the number of pore throats in the system.', 'In some embodiments, a good fit is determined by the amount of error in Equation 1: the least error on Equation 1 signifying the best fit, whereas a higher error value indicates a lower quality of the fit.', 'As described above, the number of pore throats may determine the number of hyperbolic tangents N used to create a capillary pressure model. \nFIG.', '9\n illustrates a flowchart of a method for detecting the number of pore throats for a set of capillary pressure data.', 'As illustrated in \nFIG.', '9\n, a method \n600\n may begin with creating a capillary pressure curve in operation \n610\n.', 'Method \n600\n may then continue with determining a first derivative of the capillary pressure curve in operation \n620\n and determining the number of local minima in operation \n630\n.', 'In one embodiment, the number of pore throat corresponds to the number of local minima in operation \n640\n.\n \nFIG.', '10\n illustrates a capillary pressure curve.', 'As illustrated in \nFIG.', '10\n, in operation \n610\n, an initial capillary pressure curve \n700\n is created by linking two hyperbolic tangents \n710\n and \n720\n using Equation 2 to fit the obtained capillary pressure data as similarly described above with respect to \nFIGS.', '2-8\n.', 'In operation \n620\n, the first derivative of the capillary pressure curve is determined.', 'For example, the capillary pressure curve \n700\n may be created using Equation 2: \n \nf\n(\nP,a\nn\n,w\nn\n,t\nn\n)=\na\n1\n+a\nN\n+Σ\nN\nn=1\n(\na\nn+1\n−a\nn\n)·tan \nh\n(\nw\nn\n·(\nP−t\nn\n))', 'Equation 2 \n wherein N is initially chosen to equal 2 to represent a suspected two pore throat system.', 'FIG.', '11\n illustrates a first derivative of a capillary pressure curve.', 'As illustrated in \nFIG.', '11\n, the first derivative \n800\n of the capillary pressure curve \n700\n may be computed using the following equation:\n \n \n \n \n \n \n \n \n \ndf\n \ndP\n \n \n=\n \n \n \n∑\n \n \nn\n \n=\n \n1\n \n \nN\n \n \n\u2062\n \n \n \n(\n \n \n \na\n \n \nn\n \n+\n \n1\n \n \n \n-\n \nan\n \n \n)\n \n \n·\n \n \nw\n \nn\n \n \n·\n \n \n(\n \n \n1\n \n-\n \n \n \ntanh\n \n\u2061\n \n \n(\n \n \n \nw\n \nn\n \n \n·\n \n \n(\n \n \nP\n \n-\n \n \nt\n \nn\n \n \n \n)\n \n \n \n)\n \n \n \n·\n \n \ntanh\n \n\u2061\n \n \n(\n \n \n \nw\n \nn\n \n \n·\n \n \n(\n \n \nP\n \n-\n \n \nt\n \nn\n \n \n \n)\n \n \n \n)\n \n \n \n \n \n \n \n \n \n \n \n \nEquation\n \n\u2062\n \n \n \n \n\u2062\n \n5\n \n \n \n \n \n \n \n \nIn operation \n630\n, the number of local minima is determined.', 'As illustrated in \nFIG.', '11\n, the first derivative \n800\n has two local minima \n801\n and \n802\n.', 'In one embodiment, the local minimum is the lowest value of a function inside a given interval.', 'In another embodiment, the local minima can be found by taking the value where the second derivative crosses the zero line to be positive.', 'In operation \n640\n, the number of pore throats is determined.', 'In one embodiment, the number of local minima identifies the number of pore throats in the capillary pressure system.', 'As illustrated in \nFIG.', '11\n, the first derivative \n800\n has two local minima \n801\n and \n802\n.', 'Accordingly, in \nFIG.', '11\n, the capillary pressure data used to create the initial capillary pressure curve \n700\n data has identified two pore throats.', 'A capillary pressure curve may now be created with confirmation', 'that N=2 using Equation 2.\n \nIn some embodiments, the number of hyperbolic tangents used to create the initial capillary pressure curve can be varied, so long as the number is greater or equal to the number of pre throats to be identified.', 'For example, \nFIGS.', '12-14\n illustrate capillary curves created with 3 hyperbolic tangents for capillary pressure data with different number of pore throats.\n \nFIG.', '12\n illustrates a capillary curve for a 3 pore throat system.', 'As illustrated in \nFIG.', '12\n, an initial capillary pressure curve \n700\n is created by linking three hyperbolic tangents \n710\n, \n720\n, and \n730\n using Equation 2 to fit obtained capillary pressure data for a system with 3 pore throats.', 'A first derivative \n800\n has 3 local minima \n801\n, \n802\n, and \n803\n identifying 3 pore throats for that set of obtained capillary pressure data.', 'Accordingly, N would equal 3.\n \nFIG.', '13\n illustrates a capillary curve for a 2 pore throat system.', 'As illustrated in \nFIG.', '13\n, an initial capillary pressure curve \n700\n is created by linking three hyperbolic tangents \n710\n, \n720\n, and \n730\n using Equation 2 to fit obtained capillary pressure data for a system with 2 pore throats.', 'A first derivative \n800\n has 2 local minima \n801\n and \n802\n identifying 2 pore throats for that set of obtained capillary pressure data.', 'Accordingly, N would equal 2.\n \nFIG.', '14\n illustrates a capillary curve for a 1 pore throat system.', 'As illustrated in \nFIG.', '14\n, an initial capillary pressure curve \n700\n is created by linking three hyperbolic tangents \n710\n, \n720\n, and \n730\n using Equation 2 to fit obtained capillary pressure data for a system with 1 pore throat.', 'A first derivative \n800\n has 1 local minima \n801\n identifying 1 pore throat for that set of obtained capillary pressure data.', 'Accordingly, N would equal 1.\n \nFIGS.', '10 and 15\n illustrate a transition area “A” between 2 pore throats in a capillary curve.', 'As illustrated in \nFIGS.', '10 and 15\n, a line \n900\n represents a limit between the two hyperbolic tangents \n710\n and \n720\n used to create the capillary curve \n700\n.', 'Line \n901\n represents the maximum positive curvature (acceleration) and line \n902\n represents the maximum negative curvature (deceleration).', 'According to one embodiment, the limit between two pore throats lies between the positions of two consecutive local minima of the derivative.', 'Accordingly, in one embodiment the limit position of different pore throats can be detected by analysis of Equation 2.', 'In one embodiment, between the interval of pressure delimited by two consecutive local minima of Equation 5, the limit position can be found by: finding the pressure of the maximum curvature of the capillary pressure, finding the pressure of the maximum negative curvature of the capillary pressure, computing the pressure limit by computing the geometric mean of the minimum and maximum curvature pressure, and estimating the saturation limit using Equation 2 with the pressure limit as the input.', 'For example, a pseudo-curvature may be computed using Equation 6 below\n \n \n \n \n \n \n \n \ncurvature\n \n=\n \n \n \n \n \nf\n \n\u2061\n \n \n(\n \n \nP\n \n+\n \nx\n \n \n)\n \n \n \n-\n \n \nf\n \n\u2061\n \n \n(\n \nP\n \n)\n \n \n \n \n \n \nf\n \n\u2061\n \n \n(\n \nP\n \n)\n \n \n \n-\n \n \nf\n \n\u2061\n \n \n(\n \n \nP\n \n-\n \nx\n \n \n)\n \n \n \n \n \n-\n \n1\n \n \n \n \n \n \nEquation\n \n\u2062\n \n \n \n \n\u2062\n \n6\n \n \n \n \n \n \n \n Where P is the logarithmic transform of the normalized capillary pressure.', 'While Equation 6 is used in one embodiment to compute the curvature of a capillary pressure curve at the limit between pore throats, the disclosure is not thus limited, and other curvature computations may be used.', 'In one embodiment, a saturation height function is created by combining the capillary pressure model of Equations 1 and 2 together with equations incorporating other reservoir physical properties.', 'For example, a capillary pressure curve may be created using Equations 1 and 2 to fit measured capillary pressure data while simultaneously using two other equations to incorporate permeability data to create a saturation height function.', 'In one embodiment, the unknown parameters of Equations 1 and 2 have a linear relationship with the logarithm of the measured permeability for the reservoir.', 'Accordingly, in some embodiments, the unknown parameters of Equations 1 and 2 can be used predict a saturation height function in terms of permeability and capillary pressure.', 'FIGS.', '16 and 17\n illustrate relationships between capillary pressure, permeability, and the unknown parameter tn, according to an embodiment.', 'In particular, \nFIG.', '16\n illustrates various capillary pressure curves according to different values of a permeability K. Similarly, \nFIG.', '17\n illustrates various models of a hyperbolic tangent created using Equations 1 and 2 according to various values of the unknown parameter tn.', 'As illustrated in \nFIGS.', '16 and 17\n, there is a strong linear relationship between the logarithm of the permeability and the unknown parameter tn.', 'For example, the linear relationship between the logarithm of the permeability and the unknown parameter tn can be defined as the following equation: \n \nt\nn\n=k\nn\n·log(\nK\n)', '+\nk\nn+1\n\u2003\u2003Equation 3 \n where K represents the measured permeability.', 'In some embodiments, a strong linear relationship is represented by a higher value of R2, a linear correlation coefficient between log(K) and the parameters of Equation 3.', 'In one embodiment, Equation 3 can be used to define a fourth equation for a saturation height function integrating permeability information.', 'For example, Equation 3 may be substituted into Equation 1 to create the following equation: \n \nf\n(\nP,K,a\nn\n,w\nn\n,k\nn\n)=\na\n1\n+a\nN\n+Σ\nN\nn=1\n(\na\nn+1\n−a\nn\n)·tan \nh\n(\nw\nn\n(\nP−k\nn\n·log(\nK\n)+\nk\nn+1\n))', 'Equation 4 \n \nAccordingly, in one embodiment, Equation 4 represents a saturation height function model simultaneously using capillary pressure data and core permeability measurements.', 'In one embodiment, saturation data for an oilfield reservoir is modeled using the saturation height function of Equation 4 to predict a saturation of water and hydrocarbon at a given point in an oilfield reservoir.', 'In one embodiment, a saturation data model can be created using reservoir properties such as permeability, porosity, height above free water level, and the saturation height function of Equation 4.', 'In some embodiments, porosity, permeability, and rock type data is obtained from seismic and well data.', 'For example, a reservoir model may be defined by Sw=Fn (z, K), where Sw represents the saturation of water and hydrocarbon at a point in the reservoir, (z) is the height above free water level, and (K) is permeability.', 'Each such equation may be limited to a specific rock type.', 'In some embodiments, the methods of the present disclosure may be executed by a computing system.', 'FIG.', '18\n illustrates an example of such a computing system \n500\n, in accordance with some embodiments.', 'The computing system \n500\n may include a computer or computer system \n501\nA, which may be an individual computer system \n501\nA or an arrangement of distributed computer systems.', 'The computer system \n501\nA includes one or more analysis modules \n502\n that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein.', 'To perform these various tasks, the analysis module \n502\n executes independently, or in coordination with, one or more processors \n504\n, which is (or are) connected to one or more storage media \n506\n.', 'The processor(s) \n504\n is (or are) also connected to a network interface \n507\n to allow the computer system \n501\nA to communicate over a data network \n509\n with one or more additional computer systems and/or computing systems, such as \n501\nB, \n501\nC, and/or \n501\nD (note that computer systems \n501\nB, \n501\nC and/or \n501\nD may or may not share the same architecture as computer system \n501\nA, and may be located in different physical locations, e.g., computer systems \n501\nA and \n501\nB may be located in a processing facility, while in communication with one or more computer systems such as \n501\nC and/or \n501\nD that are located in one or more data centers, and/or located in varying countries on different continents).', 'A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.', 'The storage media \n506\n may be implemented as one or more computer-readable or machine-readable storage media.', 'Note that while in the example embodiment of \nFIG.', '18\n storage media \n506\n is depicted as within computer system \n501\nA, in some embodiments, storage media \n506\n may be distributed within and/or across multiple internal and/or external enclosures of computing system \n501\nA and/or additional computing systems.', 'Storage media \n506\n may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLUERAY® disks, or other types of optical storage, or other types of storage devices.', 'Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes.', 'Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture).', 'An article or article of manufacture may refer to any manufactured single component or multiple components.', 'The storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.', 'In some embodiments, computing system \n500\n contains one or more modeling module(s) \n508\n.', 'In the example of computing system \n500\n, computer system \n501\nA includes the modeling module \n508\n.', 'In some embodiments, a single modeling module may be used to perform at least some aspects of one or more embodiments of the methods disclosed herein.', 'In alternate embodiments, a plurality of modeling modules may be used to perform at least some aspects of methods herein.', 'It should be appreciated that computing system \n500\n is one example of a computing system, and that computing system \n500\n may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of \nFIG.', '18\n, and/or computing system \n500\n may have a different configuration or arrangement of the components depicted in \nFIG.', '18\n.', 'The various components shown in \nFIG.', '18\n may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.', 'Further, aspects of the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices.', 'These modules, combinations of these modules, and/or their combination with general hardware are included within the scope of protection of the invention.', 'Geologic interpretations, models, and/or other interpretation aids may be refined in an iterative fashion; this concept is applicable to the methods discussed herein.', 'This may include use of feedback loops executed on an algorithmic basis, such as at a computing device (e.g., computing system \n500\n, \nFIG.', '18\n), and/or through manual control by a user who may make determinations regarding whether a given step, action, template, model, or set of curves has become sufficiently accurate for the evaluation of the subsurface three-dimensional geologic formation under consideration.', 'The present disclosure has been described with reference to the embodiments.', 'Although a few embodiments have been shown and described, it will be appreciated by those skilled in the art that changes may be made in these embodiments without departing from the principles and spirit of preceding detailed description.', 'It is intended that the present disclosure be construed as including such modifications and alterations insofar as they come within the scope of the appended claims or the equivalents thereof.'] | ['1.', 'A method for modeling saturation in a reservoir, comprising:\nobtaining capillary pressure data representing capillary pressure in the reservoir;\nobtaining permeability data representing permeability in the reservoir;\ndetermining a number of pore throats represented by the capillary pressure data;\ncreating a number of hyperbolic tangents based on the capillary pressure data, wherein the number of hyperbolic tangents that are created is equal to the number of pore throats;\ncombining the hyperbolic tangents to create a model capillary pressure curve to fit the capillary pressure data and to define hyperbolic tangent parameters;\ncombining at least one of the hyperbolic tangent parameters with the permeability data to define a saturation height function;\nmodeling a saturation in the reservoir using the saturation height function; and\ndisplaying the saturation model based on the saturation height function,\nwherein identifying the number of pore throats that are represented in the model comprises: determining a first derivative of the model capillary pressure curve; and determining a number of local minima in the model capillary pressure curve, wherein the number of pore throats represented by the capillary pressure data corresponds to the number of local minima.', '2.', 'The method of claim 1, wherein the number of hyperbolic tangents is equal to or greater than the number of pore throats identified in the model capillary pressure curve.', '3.', 'The method of claim 1, wherein the at least one hyperbolic tangent parameter has a linear relationship with the logarithm of the obtained permeability data.', '4.', 'The method of claim 1, wherein each of the respective hyperbolic tangents is created for a unique one of the respective pore throats, such that no two of the hyperbolic tangents are created for the same one of the pore throats.', '5.', 'The method of claim 1, wherein combining of the hyperbolic tangents to create the model capillary pressure curve to fit the capillary pressure data and to define the hyperbolic tangent parameters comprises using a non-linear least-square process.', '6.', 'A non-transitory computer-readable medium storing instructions that, when executed by one or more processors of a computing system, cause the computing system to perform operations to cause the computing system to perform the method of claim 1.\n\n\n\n\n\n\n7.', 'The non-transitory computer-readable medium of claim 6, wherein the number of hyperbolic tangents is equal to or greater than the number of pore throats identified in the model capillary pressure curve.', '8.', 'The non-transitory computer-readable medium of claim 6, wherein each of the respective hyperbolic tangents is created for a unique one of the respective pore throats, such that no two of the hyperbolic tangents are created for the same one of the pore throats.', '9.', 'A computing system, comprising:\none or more processors; and\na memory system comprising one or more non-transitory computer-readable media storing instructions that, when executed by one or more processors of a computing system, cause the computing system to perform operations, the operations comprising: obtaining capillary pressure data representing capillary pressure in a reservoir; obtaining permeability data representing permeability in the reservoir; determining a number of pore throats represented by the capillary pressure data; creating a number of hyperbolic tangents based on the capillary pressure data, wherein the number of hyperbolic tangents that are created is equal to the number of pore throats; combining the hyperbolic tangents to create a model capillary pressure curve to fit the capillary pressure data and to define hyperbolic tangent parameters; combining at least one of the hyperbolic tangent parameters with the permeability data to define a saturation height function; modeling a saturation in the reservoir using the saturation height function; and displaying the saturation model based on the saturation height function,\nwherein the determining the number of pore throats that are represented in the model capillary pressure curve comprises:\ndetermining a first derivative of the model capillary pressure curve; and\ndetermining a number of local minima in the model capillary pressure curve, wherein the number of pore throat represented by the model capillary pressure data corresponds to the number of local minima.\n\n\n\n\n\n\n10.', 'The computer system of claim 9, wherein the number of hyperbolic tangents is equal to or greater than the number of pore throats identified in the model capillary pressure curve.', '11.', 'The method of claim 1, further comprising confirming or adjusting the number of pore throats by identifying a number of pore throats that are represented by the model of the capillary pressure.', '12.', 'The method of claim 1, further comprising determining a limit between two of the pore throats, wherein determining the limit comprises:\nidentifying an interval between two consecutive local minima of a first derivative of the model capillary curve;\nfinding a maximum positive curvature of the model capillary curve in the interval;\nfinding a pressure of a maximum negative curvature of the model capillary curve in the interval; and\ncomputing the limit by selecting a point between the maximum positive curvature and the maximum negative curvature.', '13.', 'The non-transitory computer-readable medium of claim 6, wherein the operations further comprise confirming or adjusting the number of pore throats by identifying a number of pore throats that are represented by the model of the capillary pressure.', '14.', 'The computer system of claim 9, wherein the operations further comprise confirming or adjusting the number of pore throats by identifying a number of pore throats that are represented by the model of the capillary pressure.', '15.', 'The computer system of claim 9, wherein the operations further comprise determining a limit between two of the pore throats, wherein determining the limit comprises:\nidentifying an interval between two consecutive local minima of a first derivative of the initial capillary curve;\nfinding a maximum positive curvature of capillary pressure in the interval;\nfinding a pressure of a maximum negative curvature of capillary pressure in the interval;\ncomputing a limit position between two of the hyperbolic tangents by selecting a point between the maximum positive curvature and the maximum negative curvature.'] | ['FIG. 1 illustrates an example of a system that includes various management components to manage various aspects of a geologic environment according to an embodiment.; FIG.', '2 illustrates a flowchart of a method for modeling saturation in a reservoir according to an embodiment.; FIG.', '3 illustrates a model of hyperbolic tangents in a capillary pressure and water saturation system according to an embodiment.; FIG.', '4 illustrates a model of hyperbolic tangents in a capillary pressure and water saturation system according to an embodiment.; FIG.', '5 illustrates a model of hyperbolic tangents in a capillary pressure and water saturation system according to an embodiment.; FIG.', '6 illustrates capillary pressure data from a multi-pore throat system according to an embodiment.; FIG.', '7 illustrates a curve fit to capillary pressure data according to an embodiment.; FIG.', '8 illustrates hyperbolic tangents corresponding to pore throats according to an embodiment.; FIG.', '9 illustrates a flowchart of a method for detecting the number of pore throats corresponding to a set of capillary pressure data according to an embodiment;; FIG.', '10 illustrates a capillary pressure curve according to an embodiment;; FIG.', '11 illustrates a first derivative of a capillary pressure curve according to an embodiment;; FIG.', '12 illustrates a capillary curve for a 3 pore throat system.; FIG.', '13 illustrates a capillary curve for a 2 pore throat system.; FIG.', '14 illustrates a capillary curve for a 1 pore throat system.; FIG.', '15 illustrates a transition area between pore throats in a capillary curve according to an embodiment.; FIG.', '16 illustrates capillary pressure curves and permeability values according to an embodiment.; FIG.', '17 illustrates hyperbolic tangents and unknown parameter values according to an embodiment.; FIG.', '18 illustrates a schematic view of a computing system according to an embodiment.; FIG.', '1 illustrates an example of a system 100 that includes various management components 110 to manage various aspects of a geologic environment 150 (e.g., an environment that includes a sedimentary basin, a reservoir 151, one or more faults 153-1, one or more geobodies 153-2, etc.).', 'For example, the management components 110 may allow for direct or indirect management of sensing, drilling, injecting, extracting, etc., with respect to the geologic environment 150.', 'In turn, further information about the geologic environment 150 may become available as feedback 160 (e.g., optionally as input to one or more of the management components 110).; FIG.', '1 also shows an example of a framework 170 that includes a model simulation layer 180 along with a framework services layer 190, a framework core layer 195 and a modules layer 175.', 'The framework 170 may include the commercially available OCEAN® framework where the model simulation layer 180 is the commercially available PETREL® model-centric software package that hosts OCEAN® framework applications.', 'In an example embodiment, the PETREL® software may be considered a data-driven application.', 'The PETREL® software can include a framework for model building and visualization.; FIG. 1 also shows the geologic environment 150 as optionally including equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159.', 'For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures.', 'As an example, a well may be drilled for a reservoir that is laterally extensive.', 'In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop a laterally extensive reservoir (e.g., via fracturing, injecting, extracting, etc.).', 'As an example, the equipment 157 and/or 158 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.; FIG.', '2 illustrates a flowchart of a method 200 for modeling saturation in a reservoir.', 'As illustrated in FIG.', '2, the method 200 may begin with obtaining petrophysical data in operation 210.', 'For example, in operation 210, petrophysical data from the reservoir may be collected or received.', 'The petrophysical data may include capillary pressure data and permeability data.', 'In some embodiments, the petrophysical data may also include porosity, height above free water level, and rock type data.; FIG.', '5 illustrates two hyperbolic tangents 350 and 360 created without the constraints in Equation 2 above, and a third hyperbolic tangent 370 which is the sum of hyperbolic tangents 350 and 360.', 'As illustrated in FIG.', '5, the third hyperbolic tangent 370 may not represent a realistic capillary pressure curve because the underlying unconstrained hyperbolic tangents 350 and 360 go in different directions.', 'A hyperbolic tangent may also not represent a realistic capillary pressure curve if it results in a non-monotonous decreasing function.; FIGS. 6, 7, and 8 illustrate a capillary pressure model according to embodiments of this disclosure.', 'FIG.', '6 illustrates capillary pressure data from a multi-pore throat system.', 'FIG.', '7 illustrates a best-fit curve 410 over the capillary pressure data.', 'As illustrated in FIG. 7, the best fit curve 410 is the sum of three hyperbolic tangents 420, 430, and 440.', 'FIG.', '8 illustrates the three hyperbolic tangents 420, 430, and 440 shifted show which hyperbolic tangent corresponds to with pore throat.;', 'FIG. 10 illustrates a capillary pressure curve.', 'As illustrated in FIG.', '10, in operation 610, an initial capillary pressure curve 700 is created by linking two hyperbolic tangents 710 and 720 using Equation 2 to fit the obtained capillary pressure data as similarly described above with respect to FIGS.', '2-8.; FIG.', '11 illustrates a first derivative of a capillary pressure curve.', 'As illustrated in FIG.', '11, the first derivative 800 of the capillary pressure curve 700 may be computed using the following equation:; FIG.', '12 illustrates a capillary curve for a 3 pore throat system.', 'As illustrated in FIG.', '12, an initial capillary pressure curve 700 is created by linking three hyperbolic tangents 710, 720, and 730 using Equation 2 to fit obtained capillary pressure data for a system with 3 pore throats.', 'A first derivative 800 has 3 local minima 801, 802, and 803 identifying 3 pore throats for that set of obtained capillary pressure data.', 'Accordingly, N would equal 3.; FIG.', '13 illustrates a capillary curve for a 2 pore throat system.', 'As illustrated in FIG.', '13, an initial capillary pressure curve 700 is created by linking three hyperbolic tangents 710, 720, and 730 using Equation 2 to fit obtained capillary pressure data for a system with 2 pore throats.', 'A first derivative 800 has 2 local minima 801 and 802 identifying 2 pore throats for that set of obtained capillary pressure data.', 'Accordingly, N would equal 2.; FIG.', '14 illustrates a capillary curve for a 1 pore throat system.', 'As illustrated in FIG.', '14, an initial capillary pressure curve 700 is created by linking three hyperbolic tangents 710, 720, and 730 using Equation 2 to fit obtained capillary pressure data for a system with 1 pore throat.', 'A first derivative 800 has 1 local minima 801 identifying 1 pore throat for that set of obtained capillary pressure data.', 'Accordingly, N would equal 1.; FIGS.', '10 and 15 illustrate a transition area “A” between 2 pore throats in a capillary curve.', 'As illustrated in FIGS.', '10 and 15, a line 900 represents a limit between the two hyperbolic tangents 710 and 720 used to create the capillary curve 700.', 'Line 901 represents the maximum positive curvature (acceleration) and line 902 represents the maximum negative curvature (deceleration).;', 'FIGS.', '16 and 17 illustrate relationships between capillary pressure, permeability, and the unknown parameter tn, according to an embodiment.', 'In particular, FIG.', '16 illustrates various capillary pressure curves according to different values of a permeability K. Similarly, FIG.', '17 illustrates various models of a hyperbolic tangent created using Equations 1 and 2 according to various values of the unknown parameter tn.', 'As illustrated in FIGS.', '16 and 17, there is a strong linear relationship between the logarithm of the permeability and the unknown parameter tn.', 'For example, the linear relationship between the logarithm of the permeability and the unknown parameter tn can be defined as the following equation: tn=kn·log(K)+kn+1\u2003\u2003Equation 3 where K represents the measured permeability.'] |