Method and system for autonomous drilling instruction set

Abstract

Systems and techniques to utilize processing circuitry to determine at least one modification to be made to an operation of a downhole tool, select a first Instruction Set Architecture (ISA) downlink command corresponding to a first instruction to implement only one first command action at the downhole tool to effect at least a portion of the modification to be made to the operation of the downhole tool, and transmit the a first ISA downlink command as a control signal to control at least a portion of the downhole tool as the one command action.

Description

BACKGROUND

[0001] The present disclosure relates to systems and methods for sending transmissions downhole and back to the surface during autonomous drilling.

[0002] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and / or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it may be understood that these statements are to be read in this light, and not as admissions of prior art.

[0003] Drilling operations have, over time, have moved away from human-operator led drilling methods and towards autonomous drilling methods. Critical to this transition is the advancement of robust communication techniques. Human-operator led drilling uses Instruction Set Architecture (ISA) to send commands downhole which correspond to (trigger) particular actions undertaken by a component in response to reception of the commands. These ISA are simple for human operators to be able to decipher and utilize. Autonomous drilling techniques use machines to remotely transmit and receive data, and are capable of deciphering far more complex ISAs. Thus the present disclosure teaches methods to modify existing ISA to allow for a greater number of more precise commands to maximize efficiency in autonomous drilling. This maximization of efficiency leads to savings in time and therefore cost savings. In embodiments, the present disclosure additionally teaches a similar modification of ISAs to send commands back up from the tool to the surface.SUMMARY

[0004] A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.

[0005] During drilling operations, commands are communicated from the surface to downhole to trigger operations and / or actions by downhole equipment. Likewise, information, such as drilling mud pressure, weight on bit, directional measurements, sensor readings, etc. from the downhole equipment (e.g., downhole tools) are sent to the surface. Conventional methods of drilling have largely been largely taken over by autonomous drilling, resulting in various benefits. For example, productivity can be increased, as operators are able to manage many machines remotely. Additionally, autonomous drilling also can provide cost savings, since it requires fewer crews and fewer trips to rig sites. Finally, accuracy can be increased, as autonomous drilling can react more rapidly to changing downhole conditions relative to human guided drilling operations.

[0006] It is desirable to have increases in communication capabilities as transitioning to autonomous drilling continues. In human-led drilling, communication involves human operators providing commands to downhole equipment. Accordingly, so as not to overwhelm the operator, a relatively reduced set of commands and the corresponding actions that are triggered in the downhole equipment may be utilized. In contrast, autonomous drilling can allow for greater numbers of commands to be provided to downhole equipment. This corresponds to an increase in the number of triggering actions available to be undertaken by the downhole equipment. In some embodiments, while packet size (e.g., a number of bits in a command) is increased for an autonomous drilling Instruction Set Architecture (ISA) relative to an operator directed drilling ISA, an accompanying increase in the resolution of triggered actions corresponding to the commands in the downhole equipment results in overall fewer commands being transmitted to effect desired actions. The present disclosure teaches a method and system to increase the available actions that can be triggered by an ISA to reduce the overall number of commands issued to generate a desired outcome in controlling the operation of downhole equipment. This can allow for overall time savings in control of downhole equipment and, correspondingly, increasing efficiency in downhole operations.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:

[0008] FIG. 1 depicts an example wellsite system for measuring borehole data using various downhole tools and surface tools, in accordance with embodiments of the present disclosure;

[0009] FIG. 2 depicts a well control system configured to control the wellsite system of FIG. 1, in accordance with embodiments of the present disclosure; and

[0010] FIG. 3 is a flow diagram of downhole communications using a modified Instruction Set Architecture (ISA) for autonomous drilling, in accordance with embodiments of the present disclosure.DETAILED DESCRIPTION

[0011] Certain embodiments commensurate in scope with the present disclosure are summarized below. These embodiments are not intended to limit the scope of the disclosure, but rather these embodiments are intended only to provide a brief summary of certain disclosed embodiments. Indeed, the present disclosure may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

[0012] As used herein, the term “coupled” or “coupled to” may indicate establishing either a direct or indirect connection (e.g., where the connection may not include or include intermediate or intervening components between those coupled) and is not limited to either unless expressly referenced as such. The term “set” may refer to one or more items. Wherever possible, like or identical reference numerals are used in the figures to identify common or the same elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale for purposes of clarification.

[0013] As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,”“coupled,”“connect,”“connection,”“connected,”“in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”

[0014] Furthermore, when introducing elements of various embodiments of the present disclosure, the articles “a,”“an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment,”“an embodiment,” or “some embodiments” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, the phrase A “based on” B is intended to mean that A is at least partially based on B. Moreover, unless expressly stated otherwise, the term “or” is intended to be inclusive (e.g., logical OR) and not exclusive (e.g., logical XOR). In other words, the phrase A “or” B is intended to mean A, B, or both A and B.

[0015] Finally, the techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function] . . . ” or “step for [perform]ing [a function] . . . ”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

[0016] Drilling methods have become increasingly autonomous over the past several years. Tasks that used to require human intervention now can performed by computing systems. Autonomous drilling is one example of drilling tasks that can be automated. Autonomous drilling is employed to steer and control drilling operations remotely, enhance drilling performance, and enable more precise well placement. This reduction in human intervention enhances efficiency.

[0017] Autonomous drilling operations are performed in view of communication of sensed parameters during drilling and geosteering commands to the drilling tool based on those sensed parameters to effect particular drilling operations. For example, steering of a drill bit of a tool can be accomplished based on steering inputs that can include, for example, setting of a toolface angle (TF) and a steering ratio (SR). The TF refers to an amount of orientation of a face (e.g., a cutting face) of a drill bit, which operates to indicate and / or define the direction drilling will steer towards. The SR refers to an amount of directional change that will occur for a drilling tool, e.g., how rapidly a drilling direction will be altered. TF is typically provided in degrees while SR is typically a value between 0 and 1 and can be represented as a percentage (e.g., from 0%-100%). The SR and TF can be controlled by adjusting drilling parameters, for example, a rotary speed of the drill string, flow rate of drilling fluid (i.e., mud), a weight on bit (WOB) value, etc. in view of the SR or TF value that is transmitted as part of a steering input. Determination of the steering inputs can be performed, for example, based upon sensed data, for example, from downhole sensors, which can be used to determine subsequent commands to be transmitted to a drilling tool to implement a drilling plan (i.e., to adjust the well path to correspond to a drilling plan).

[0018] Present techniques described herein provide for reducing the amount of time in implementing drilling operations, thus increasing efficiency and reducing costs. This can be achieved through the transmission of fewer overall numbers of downlink commands per well. Through the use high precision commands as part of an autonomous drilling Instruction Set Architecture (ISA) that utilizes additional commands in place of an operator directed drilling ISA (which instead utilizes multiple less precision commands to control drilling operations), time can be saved during drilling operations. Computerized autonomous drilling allows for use of an autonomous drilling ISA, which can be generated and calibrated for use by autonomous systems rather than human operators. This can include an end-to-end workflow that operates to improve both downlink and uplink communications and can be specifically tailored for autonomous drilling systems, relative to a manually driven (i.e., human directed) system for drilling, for example, directional drilling (DD). Additionally, embodiments include managing high number of steering commands per ISA and can include the organization of steering commands in multi-level pages hierarchy instead of a single level. These enhancements allow for increased efficiency, control, and overall performance in the drilling process.

[0019] FIG. 1 illustrates a drilling system 10 that may employ the systems and methods of this disclosure. The drilling system 10 may be used to drill a borehole 12 into a geological region 14. In the drilling system 10, a drilling rig 18 may rotate a drill string 20 within the borehole 12. As the drill string 20 is rotated, a drilling fluid pump 22 may be used to pump drilling fluid, which may be referred to as “mud” or “drilling mud,” downward through the center of the drill string 20, and back up around the drill string 20, as shown by reference arrows 24. At the surface, return drilling fluid may be filtered and conveyed back to a mud pit 26 for reuse. The drilling fluid may travel down to the bottom of the drill string 20 known as the bottom-hole assembly (BHA) 28. The drilling fluid may be used to rotate, cool, and / or lubricate a drill bit 30 that may be a part of the BHA 28. The fluid may exit the drill string 20 through the drill bit 30 and carry drill cuttings away from the bottom of the borehole 12 back to the surface.

[0020] The BHA 28 may include the drill bit 30 along with various downhole tools, such as one or more logging tools 32. The BHA 28 may thus convey the one or more logging tools 32 through the geological region 14 via the borehole 12. As described in greater detail herein, the one or more logging tools 32 may be any suitable downhole tool that emits electromagnetic waves within the borehole 12 (e.g., a downhole environment). The downhole tools, which may include the one or more logging tools 32, may collect a variety of information relating to the geological region 14 and the state of drilling in the borehole 12. For instance, the downhole tools may be logging-while drilling (LWD) tools that measure physical properties of the geological region 14, such as density, porosity, resistivity, lithology, and so forth. Likewise, the downhole tools may be measurement-while-drilling (MWD) tools that measure certain drilling parameters, such as the temperature, pressure, orientation of the drill bit 30, mapping-while-drilling tools, and so forth. The downhole tools can be used to facilitate drilling operations, for example, directional drilling operations.

[0021] The one or more logging tools 32 may receive energy from an electrical energy device or an electrical energy storage device, such as an auxiliary power source 34 or another electrical energy source to power the tool. In some embodiments, the one or more logging tools 32 may include a power source within the one or more logging tools 32, such as a battery system or a capacitor, to store sufficient electrical energy to emit and / or receive electromagnetic waves.

[0022] Communications 36, such as control signals, may be transmitted from a data processing system 38 (processing system 38) to the one or more logging tools 32, and communications 36, such as data signals related to the results / measurements of the one or more logging tools 32, may be returned to the data processing system 38 from the one or more logging tools 32. The data processing system 38 may be any electronic data processing system that can be used to carry out the systems and methods of this disclosure. For example, the data processing system 38 may include one or more processors 40, which may execute instructions stored in memory 42 and / or storage 44. The memory 42 and / or the storage 44 of the data processing system 38 may be any suitable article of manufacture that can store the instructions. In certain embodiments, the one or more processors 40 may include a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, a digital signal processor (DSP), or another control or computing device. In certain embodiments, the one or more processors 40 may include machine learning (ML) and / or artificial intelligence (AI) based processors able to implement a trained ML model.

[0023] In certain embodiments, the memory 42 and storage 44 is implemented as one or more non-transitory computer-readable or machine-readable storage media. In certain embodiments, the memory 42 may include one or more different forms of memory, including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories. The storage 44 may include solid state drives, magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices. Note that the computer-executable instructions and associated data of the analysis module(s) may be provided on one computer-readable or machine-readable storage medium of the memory 42 or the storage 44, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media are considered to be part of an article (or article of manufacture), which may refer to any manufactured single component or multiple components. In certain embodiments, the storage 44 may be located either in the machine running the machine-readable instructions or may be located at a remote site from which machine-readable instructions may be downloaded over a network for execution.

[0024] As illustrated, the data processing system 38 may optionally also include a display 46, which may be any suitable electronic display and which may display images generated by the processor 40. The data processing system 38 may be a local component of the drilling system 10 (i.e., at the surface), within the one or more logging tools 32 (i.e., downhole), a device located proximate to the drilling operation, and / or a remote data processing device located away from the drilling system 10 to process downhole measurements in real time or sometime after the data has been collected. In some embodiments, the data processing system 38 may be a portable computing device (e.g., tablet, smart phone, or laptop) or a server remote from the drilling system 10. In some embodiments, the one or more logging tools 32 may store and process collected data in the BHA 28 or send the data to the surface for processing via communications 36 described above, including any suitable telemetry (e.g., electrical signals pulsed through the geological region 14 or mud pulse telemetry using the drilling fluid).

[0025] It should be noted that, although the discussion above relates to a drilling system, other downhole equipment or systems may employ the systems and methods of this disclosure. For example, a downhole tool with an acoustic tool conveyed by slickline, coiled tubing, wireline, or other delivery systems, may utilize the disclosed systems and methods.

[0026] Operation of drilling system 10 may be controlled by a processor of the data processing system 38. For example, FIG. 2 illustrates a block diagram of the data processing system 38 that is communicatively coupled to the one or more logging tools 32. In the illustrated embodiment, a logging tool 32 includes a processor 50, memory 52, an electromagnetic (EM) acquisition system 54, and storage 56. In some embodiments, the processor 50 may be ASIC (application specific integrated circuit), field programmable gate array (FPGA), a micro control unit (MCU), a digital signal processor (DSP), and the like. In general, the drilling system 10 communicates with the data processing system 38 via a data cable, telemeter or other suitable techniques. For example, the drilling system 10 may communicate EM measurements obtained by an EM sensor (or meter) as part of the EM acquisition system 54. In turn, a processor of the surface control system may determine certain parameters (e.g., porosity, water saturation, permeability, velocities, resistivity, and so forth) based on the EM measurements. In such embodiments, the EM acquisition system 54 may include an emission source (e.g., an antenna) to acquire, obtain, or otherwise measure EM measurements.

[0027] In certain embodiments, the data processing system 38 may include one or more analysis modules (e.g., a program of computer-executable instructions and associated data) that may be configured to perform various functions of the embodiments described herein. In certain embodiments, to perform these various functions, the one or more analysis modules may be executed on one or more processors 40 of the processing system 38, which may be connected to memory 42 and storage 44 in which the one or more analysis modules may be stored.

[0028] In certain embodiments, the computer-executable instructions of the one or more analysis modules, when executed by the one or more processors 40, may cause the one or more processors 40 to generate to perform autonomous drilling operations which can include, for example, control of drilling operations, such as directional drilling operations, in conjunction with a drilling plan based upon measured data.

[0029] FIG. 3 is a flow diagram of processes performed in drilling operation 200 to send communications 36 of FIG. 1 downhole, in accordance with an embodiment of the present disclosure. In block 202, a determination is made on what drilling goals are to be achieved. This can include implementation of a drilling plan to achieve drilling of a well along a desired drilling path. In embodiments, and as shown in FIG. 1, these goals may involve, for example, results / measurements of the one or more logging tools 32 as feedback that can be analyzed to determine what control signals are to be generated and transmitted to the downhole tool to execute drilling operations as part of the drilling plan.

[0030] Thus, for example, in block 202, the commands to be transmitted downhole can be control signals for control of an autonomous drilling operation to drill a well in conjunction with a drilling plan. Block 202 can include review of sensed parameters during drilling as well as determination of geosteering commands to be transmitted to the drilling tool based on those sensed parameters to effect particular drilling operations. As noted above, those geosteering commands can include, for example, steering inputs that can include setting of TF and SR so as to control the direction drilling will steer towards and how rapidly a drilling direction will be altered. Determination of the steering inputs can be performed, for example, based upon sensed data, for example, from downhole sensors, which can be used to determine subsequent commands to be transmitted to a drilling tool (e.g., logging tool 32) to implement a drilling plan (i.e., to adjust the well path to correspond to a drilling plan).

[0031] Moving to block 204, and based on the determination made in block 202, commands are sent downhole using an ISA to the logging tool 32 via the processing system 38 illustrated in FIG. 2. Block 206 illustrates the logging tool 32 actually performing the command sent to it via the ISA. After this drilling is performed, block 208 includes the logging tool 32 sending data back to the surface with any parameters measured during the activities in block 206. Finally, block 210 describes sending updated commands using the ISA to the logging tool 32 via the data processing system 38.

[0032] In certain embodiments, a simple Instruction Set Architecture (ISA) to enable humans to read and convey the information described in FIG. 3 is provided. This can be referred to as an operator directed drilling ISA. In some embodiments, the ISA can include two parts. The first part is referred to as downlink commands, which each include a unique number corresponding to a desired instruction to be sent to the downhole tool from the data processing system 38. The second part is referred to as instructions, which each correspond to a desired actions for the tool to execute on receiving a specific command. For example, the table below depicts command #1-1, wherein the command is associated with the instructions “Set tool face (TF) angle to 0 degrees and steering ration (SR) to 25%,” respectively.TABLE 1Operator Directed Drilling ISAPage 0 Manual (Build and Turn)Command ActionCommand #Steering Mode 0: Build and Turn1-0 Go to Page 0 with MTF neutral setting:TF = 0 degrees, SR = 0%1-1 Set TF = 0 degrees, SR = 25%1-2 Set TF = 0 degrees, SR = 50%1-3 Set TF = 0 degrees, SR = 75%1-4 Set TF = 0 degrees, SR = 100%1-5 Set TF = 18 degrees, SR = 75%1-6 Set TF = 18 degrees, SR = 100%1-7 Set TF = 36 degrees, SR = 50%1-8 Set TF = 36 degrees, SR = 100%1-9 Set TF = 45 degrees, SR = 25%1-10Set TF = 54 degrees, SR = 75%1-11Set TF = 72 degrees, SR = 50%1-12Set TF = 72 degrees, SR = 100%1-13Set TF = 90 degrees, SR = 25%1-14Set TF = 90 degrees, SR = 75%1-15Set TF = 90 degrees, SR = 100%1-16Set TF = 108 degrees, SR = 50%1-17Set TF = 108 degrees, SR = 100%1-18Set TF = 126 degrees, SR = 75%1-19Set TF = 135 degrees, SR = 25%1-20Set TF = 144 degrees, SR = 50%1-21Set TF = 144 degrees, SR = 100%1-22Set TF = 162 degrees, SR = 75%1-23Set TF = 180 degrees, SR = 25%1-24Set TF = 180 degrees, SR = 50%1-25Set TF = 180 degrees, SR = 75%1-26Set TF = 180 degrees, SR = 100%1-27Set TF = 198 degrees, SR = 75%1-28Set TF = 216 degrees, SR = 50%1-29Set TF = 216 degrees, SR = 100%1-30Set TF = 225 degrees, SR = 25%1-31Set TF = 234 degrees, SR = 75%2-0 Set TF = 252 degrees, SR = 50%2-1 Set TF = 252 degrees, SR = 100%2-2 Set TF = 270 degrees, SR = 25%2-3 Set TF = 270 degrees, SR = 75%2-4 Set TF = 270 degrees, SR = 100%2-5 Set TF = 288 degrees, SR = 50%2-6 Set TF = 288 degrees, SR = 100%2-7 Set TF = 306 degrees, SR = 75%2-8 Set TF = 315 degrees, SR = 25%2-9 Set TF = 324 degrees, SR = 50%2-10Set TF = 324 degrees, SR = 100%2-11Set TF = 342 degrees, SR = 75%2-12Set TF = 342 degrees, SR = 100%2-13Increase SR by 10%2-14Decrease SR by 10%2-15Increase TF by 12 degrees2-16Decrease TF by 12 degrees2-17Use Gravity Mode2-18Use Magnetic Mode2-192-202-212-22Downlink Bit Period: 18 s2-23Downlink Bit Period: 36 s

[0033] In this manner, the operator directed drilling ISA includes downlink commands that correspond to instructions having multiple command actions for the downhole tool associated therewith (e.g., both a TF and a SR command). That is, the downlink commands are coupled to particular parameter values (e.g., multiple command actions). This type of ISA is intended to be simple for use by a human. This type of ISA has some drawbacks, however. For example, the total number of ISA commands may be limited so that a human can easily find and transmit a particular downlink command. However, by implementing a relatively few downlink commands as part of the ISA, the corresponding instructions for each downlink command is similarly reduced to the number of downlink commands available. This has the effect of reducing the complexity of the ISA, however, the resulting control signals and corresponding actions are similarly limited to those provided in the instructions.

[0034] For example, a desired change in operation of the downhole tool may be desired by an operator, e.g., a particular steering input. However, there may not be a corresponding downlink command that corresponds to the desired steering input in the available ISA. This can lead an operator to choose a best available downlink command to affect a desired change in the operation of the drilling tool. However, because the ISA is relatively limited in size, that command may only allow for gross changes in operating parameters of the drilling tool and not the particular steering input desired. Thus, one or more additional downlink commands will be provided by the operator to continue to modify the operation of the downhole tool until a result that best approximates a result corresponding to the desired steering input can be achieved using the available downlink commands. These additional downlink commands and their corresponding instructions as performed by the downhole tool result in more time to achieve (or approximate) a desired result relative to an amount of time a precise instruction and its corresponding downlink command would use to achieve the result.

[0035] Thus, in some embodiments, a different ISA than the operator directed drilling ISA described above may be employed. For example, as drilling has become more autonomous, use of an ISA with greater size and / or complexity becomes feasible to provide a greater amount of instructions available to be selected and transmitted downhole. This ISA can be termed an autonomous drilling ISA. Using an autonomous drilling ISA can increase the resolution of parameter values (e.g., instructions) that can be transmitted to the downhole tool and reduce the total number of commands utilized to achieve a desired result, since more precise instructions can be defined with corresponding downlink commands as part of an ISA utilized in conjunction with autonomous drilling (e.g., an autonomous drilling ISA).

[0036] An example of an ISA used in autonomous drilling as an autonomous drilling ISA as illustrated in the table below.TABLE 2Autonomous Drilling ISACommand #Command Action1-0 Set TF=01-1 Set TF=11.251-2 Set TF=22.51-3 Set TF=33.751-4 Set TF=451-5 Set TF=56.251-6 Set TF=67.51-7 Set TF=78.751-8 Set TF=901-9 Set TF=101.251-10Set TF=112.51-11Set TF=123.751-12Set TF=1351-13Set TF=146.251-14Set TF=157.51-15Set TF=168.751-16Set TF=1801-17Set TF=191.251-18Set TF=202.51-19Set TF=213.751-20Set TF=2251-21Set TF=236.251-22Set TF=247.51-23Set TF=258.751-24Set TF=2701-25Set TF=281.251-26Set TF=292.51-27Set TF=303.751-28Set TF=3151-29Set TF=326.251-30Set TF=337.51-31Set TF=348.752-0 Set SR=4.348%2-1 Set SR=8.696%2-2 Set SR=13.043%2-3 Set SR=17.391%2-4 Set SR=21.739%2-5 Set SR=26.087%2-6 Set SR=30.435%2-7 Set SR=34.783%2-8 Set SR=39.130%2-9 Set SR=43.478%2-10Set SR=47.826%2-11Set SR=52.174%2-12Set SR=56.522%2-13Set SR=60.870%2-14Set SR=65.217%2-15Set SR=69.565%2-16Set SR=73.913%2-17Set SR=78.261%2-18Set SR=82.609%2-19Set SR=86.957%2-20Set SR=91.304%2-21Set SR=95.652%2-22Set SR=100.000%2-23Go to Page 1.12-24Go to Page 1.22-25Go to Page 1.32-26Go to Page 1.42-27Go to Page 1.52-28Go to Page 1.62-29Go to Page 1.72-30Go to Page 2.12-31Go to Index Page

[0037] As illustrated, the downlink commands are decoupled from parameter values, in contrast with the operator directed drilling ISA described above. Thus, for example, command 1-2 in the operator directed drilling ISA described in Table 1 results in an instruction that includes a particular parameter value (e.g., multiple command actions, here set TF=0 degrees and SR=25%). In contrast, command 1-2 in the autonomous drilling ISA described in Table 2 results in an instruction that controls only one command action (e.g., set TF=22.5 degrees). By decoupling the downlink commands from the parameter values (i.e., multiple control actions to be performed by the drilling tool), higher precision control of the downhole tool can be achieved.

[0038] The efficiency gained by this decoupling can be illustrated by the following example. If the downhole tool is set to follow TF of 72 degrees and SR of 50%, and a desired control action is to set TF to 45 degrees and keep the SR to 50%, using the operator directed drilling ISA of Table 1 requires the engineer to find the downlink closest command link to provide an instruction that best approximates the desired control actions, since no downlink command and corresponding instruction provides for TF of 72 degrees and SR of 50% (i.e., the desired values do not exist in the operator directed drilling ISA). As illustrated by Table 1, the closest command is command 1-9, which sets the TF to 45 degrees and the SR to 25%. The disadvantage to using operator directed drilling ISA, however, is that the engineer will have to subsequently send two further commands to increase SR by 10% (i.e., send command 2-13 twice). Although the final result sets the TF to 45 degrees, the SR % will only be set to 45%. Using the operator directed drilling ISA, this is the closest to the desired SR that can be achieved, even after using three total commands. Each of these three commands takes time to execute and slows down the overall drilling process, thus resulting in inefficiencies.

[0039] If instead of the ISA of Table 1 (the operator directed drilling ISA), the ISA of Table 2 (the autonomous drilling ISA) is utilized, the data processing system 38, and more particularly computer-executable instructions when executed by the one or more processors 40, may perform autonomous drilling operations with greater precision and in less time than the example above. For example, the data processing system 40 executing a program as a directional drilling advisor that operates to transmit drilling command actions to a downhole tool can send a single downlink command 1-4 to set the TF to 45 degrees. No additional downlink command need be sent to adjust the SR, since no corresponding control action to modify SR is required. This results in up to a three time reducing in the time to implement the control action using the autonomous drilling ISA. This example highlights that higher precision command actions that can be undertaken via use of expanded downlink commands and instructions of the operator directed drilling ISA.

[0040] In another embodiment, the autonomous drilling ISA is organized to maximize the number of commands sent downhole. For example, command pages can be maximized by allocating separate pages for separate parameters. Table 2 would therefore represent a page incorporating commands for TF and SR, but subsequent pages may be dedicated to other parameters, such as Inclination Hold (IH), Hold Inclination and Azimuth (HIA), and Auto curve (AC). Additionally, this can be expanded to allow for pages for additional commands per section type such as: Vertical, Curve, Tangent, and Horizontal.

[0041] In another embodiment, the autonomous drilling ISA may be able to accommodate more bits representing commands with no issues. For example, it is possible to add an additional bit to the autonomous drilling ISA relative to an operator directed drilling ISA, for example, so that a downlink command is represented by 7 bits instead of 6, resulting in a doubling of commands per page from 64 to 128 commands per page. Traditional ISA systems will not be able to accommodate this change as human operators would be overburdened with this increase. The present system, being autonomous, can accommodate more precise values using a fewer number of commands to reach a desired drilling state with this expansion of downlink commands available.

[0042] In another embodiment, the number of downlink commands may be increased in the autonomous drilling ISA by using an index page, for example, for multiple chapters of steering commands pages. This structure is referred to as two level page hierarchy instead of just a single level. For example, in the proposed ISA of Table 1, all available pages are accessible via a single command such as commands 2-23 till 2-30. However, to expand on the number of available commands in the ISA, it is possible to use additional levels of page hierarchy via command 2-31. This command will direct the tool to at least one alternate page (i.e. an index page) where all commands correspond to page ranges. This can allow for access, for example, to 512 pages each with 64 commands.

[0043] The following example illustrates the difference in steering commands in 1 versus 2 level page hierarchy models. In single level pages of 1 level hierarchy, assume there are 8 navigation commands out of 64. This means there are 56 steering commands per page, and there will be a total of 448 steering commands in the entire ISA (56*8 pages=448). Using two level pages, however, and assuming 9 navigation commands (e.g. 8 shortcut pages+1 command to access the special page of page ranges), this means there are 55 steering commands per page and 28,160 total steering commands in the ISA. (55*512 pages=28160). While access of the separate levels can require, for example. two downlink commands to change page ranges, the gain from increasing the maximum number of available steering commands can still be beneficial.

[0044] Additionally, autonomous drilling ISA may be used to send uplink commands using the same process as downlink commands, by utilizing telemetry available to transmit information to the surface. For example, an equivalent to multiple pages for uplinks can be provided, which allows for higher precision for specific data fields in the information being sent to the surface, e.g. actual steering ratio being executed by the downhole tool as different than the desired steering ratio that is being sent from surface to downhole. This allows for enhanced tool control, which leads to improved drilling quality and higher rate of penetration (ROP) due to fewer control commands being sent overall. Furthermore, as uplink commands may be transmitted without any separate “Go-to page” command being sent from tool to the surface, an acknowledgement packet to both confirm the receipt of the command and surface / cloud software switch to corresponding uplink page can instead be transmitted.

[0045] The autonomous drilling ISA is more scalable and flexible than an operator directed drilling ISA. Use of the autonomous drilling ISA is not limited to select commands that are easy to be memorized by an operator. Instead, increased control actions (e.g., altering a toolface angle of a downhole tool, altering a steering ratio of the downhole tool, etc.) can be performed via implementation of the data processing system 38.

[0046] The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the disclosure to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrated and described may be re-arranged, and / or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principals of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosure and various embodiments with various modifications as are suited to the particular use contemplated.

Examples

Embodiment Construction

[0011]Certain embodiments commensurate in scope with the present disclosure are summarized below. These embodiments are not intended to limit the scope of the disclosure, but rather these embodiments are intended only to provide a brief summary of certain disclosed embodiments. Indeed, the present disclosure may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

[0012]As used herein, the term “coupled” or “coupled to” may indicate establishing either a direct or indirect connection (e.g., where the connection may not include or include intermediate or intervening components between those coupled) and is not limited to either unless expressly referenced as such. The term “set” may refer to one or more items. Wherever possible, like or identical reference numerals are used in the figures to identify common or the same elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown ...

BACKGROUND

[0001] The present disclosure relates to systems and methods for sending transmissions downhole and back to the surface during autonomous drilling.

[0002] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and / or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it may be understood that these statements are to be read in this light, and not as admissions of prior art.

[0003] Drilling operations have, over time, have moved away from human-operator led drilling methods and towards autonomous drilling methods. Critical to this transition is the advancement of robust communication techniques. Human-operator led drilling uses Instruction Set Architecture (ISA) to send commands downhole which correspond to (trigger) particular actions undertaken by a component in response to reception of the commands. These ISA are simple for human operators to be able to decipher and utilize. Autonomous drilling techniques use machines to remotely transmit and receive data, and are capable of deciphering far more complex ISAs. Thus the present disclosure teaches methods to modify existing ISA to allow for a greater number of more precise commands to maximize efficiency in autonomous drilling. This maximization of efficiency leads to savings in time and therefore cost savings. In embodiments, the present disclosure additionally teaches a similar modification of ISAs to send commands back up from the tool to the surface.SUMMARY

[0004] A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.

[0005] During drilling operations, commands are communicated from the surface to downhole to trigger operations and / or actions by downhole equipment. Likewise, information, such as drilling mud pressure, weight on bit, directional measurements, sensor readings, etc. from the downhole equipment (e.g., downhole tools) are sent to the surface. Conventional methods of drilling have largely been largely taken over by autonomous drilling, resulting in various benefits. For example, productivity can be increased, as operators are able to manage many machines remotely. Additionally, autonomous drilling also can provide cost savings, since it requires fewer crews and fewer trips to rig sites. Finally, accuracy can be increased, as autonomous drilling can react more rapidly to changing downhole conditions relative to human guided drilling operations.

[0006] It is desirable to have increases in communication capabilities as transitioning to autonomous drilling continues. In human-led drilling, communication involves human operators providing commands to downhole equipment. Accordingly, so as not to overwhelm the operator, a relatively reduced set of commands and the corresponding actions that are triggered in the downhole equipment may be utilized. In contrast, autonomous drilling can allow for greater numbers of commands to be provided to downhole equipment. This corresponds to an increase in the number of triggering actions available to be undertaken by the downhole equipment. In some embodiments, while packet size (e.g., a number of bits in a command) is increased for an autonomous drilling Instruction Set Architecture (ISA) relative to an operator directed drilling ISA, an accompanying increase in the resolution of triggered actions corresponding to the commands in the downhole equipment results in overall fewer commands being transmitted to effect desired actions. The present disclosure teaches a method and system to increase the available actions that can be triggered by an ISA to reduce the overall number of commands issued to generate a desired outcome in controlling the operation of downhole equipment. This can allow for overall time savings in control of downhole equipment and, correspondingly, increasing efficiency in downhole operations.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:

[0008] FIG. 1 depicts an example wellsite system for measuring borehole data using various downhole tools and surface tools, in accordance with embodiments of the present disclosure;

[0009] FIG. 2 depicts a well control system configured to control the wellsite system of FIG. 1, in accordance with embodiments of the present disclosure; and

[0010] FIG. 3 is a flow diagram of downhole communications using a modified Instruction Set Architecture (ISA) for autonomous drilling, in accordance with embodiments of the present disclosure.DETAILED DESCRIPTION

[0011] Certain embodiments commensurate in scope with the present disclosure are summarized below. These embodiments are not intended to limit the scope of the disclosure, but rather these embodiments are intended only to provide a brief summary of certain disclosed embodiments. Indeed, the present disclosure may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

[0012] As used herein, the term “coupled” or “coupled to” may indicate establishing either a direct or indirect connection (e.g., where the connection may not include or include intermediate or intervening components between those coupled) and is not limited to either unless expressly referenced as such. The term “set” may refer to one or more items. Wherever possible, like or identical reference numerals are used in the figures to identify common or the same elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale for purposes of clarification.

[0013] As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,”“coupled,”“connect,”“connection,”“connected,”“in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”

[0014] Furthermore, when introducing elements of various embodiments of the present disclosure, the articles “a,”“an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment,”“an embodiment,” or “some embodiments” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, the phrase A “based on” B is intended to mean that A is at least partially based on B. Moreover, unless expressly stated otherwise, the term “or” is intended to be inclusive (e.g., logical OR) and not exclusive (e.g., logical XOR). In other words, the phrase A “or” B is intended to mean A, B, or both A and B.

[0015] Finally, the techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function] . . . ” or “step for [perform]ing [a function] . . . ”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

[0016] Drilling methods have become increasingly autonomous over the past several years. Tasks that used to require human intervention now can performed by computing systems. Autonomous drilling is one example of drilling tasks that can be automated. Autonomous drilling is employed to steer and control drilling operations remotely, enhance drilling performance, and enable more precise well placement. This reduction in human intervention enhances efficiency.

[0017] Autonomous drilling operations are performed in view of communication of sensed parameters during drilling and geosteering commands to the drilling tool based on those sensed parameters to effect particular drilling operations. For example, steering of a drill bit of a tool can be accomplished based on steering inputs that can include, for example, setting of a toolface angle (TF) and a steering ratio (SR). The TF refers to an amount of orientation of a face (e.g., a cutting face) of a drill bit, which operates to indicate and / or define the direction drilling will steer towards. The SR refers to an amount of directional change that will occur for a drilling tool, e.g., how rapidly a drilling direction will be altered. TF is typically provided in degrees while SR is typically a value between 0 and 1 and can be represented as a percentage (e.g., from 0%-100%). The SR and TF can be controlled by adjusting drilling parameters, for example, a rotary speed of the drill string, flow rate of drilling fluid (i.e., mud), a weight on bit (WOB) value, etc. in view of the SR or TF value that is transmitted as part of a steering input. Determination of the steering inputs can be performed, for example, based upon sensed data, for example, from downhole sensors, which can be used to determine subsequent commands to be transmitted to a drilling tool to implement a drilling plan (i.e., to adjust the well path to correspond to a drilling plan).

[0018] Present techniques described herein provide for reducing the amount of time in implementing drilling operations, thus increasing efficiency and reducing costs. This can be achieved through the transmission of fewer overall numbers of downlink commands per well. Through the use high precision commands as part of an autonomous drilling Instruction Set Architecture (ISA) that utilizes additional commands in place of an operator directed drilling ISA (which instead utilizes multiple less precision commands to control drilling operations), time can be saved during drilling operations. Computerized autonomous drilling allows for use of an autonomous drilling ISA, which can be generated and calibrated for use by autonomous systems rather than human operators. This can include an end-to-end workflow that operates to improve both downlink and uplink communications and can be specifically tailored for autonomous drilling systems, relative to a manually driven (i.e., human directed) system for drilling, for example, directional drilling (DD). Additionally, embodiments include managing high number of steering commands per ISA and can include the organization of steering commands in multi-level pages hierarchy instead of a single level. These enhancements allow for increased efficiency, control, and overall performance in the drilling process.

[0019] FIG. 1 illustrates a drilling system 10 that may employ the systems and methods of this disclosure. The drilling system 10 may be used to drill a borehole 12 into a geological region 14. In the drilling system 10, a drilling rig 18 may rotate a drill string 20 within the borehole 12. As the drill string 20 is rotated, a drilling fluid pump 22 may be used to pump drilling fluid, which may be referred to as “mud” or “drilling mud,” downward through the center of the drill string 20, and back up around the drill string 20, as shown by reference arrows 24. At the surface, return drilling fluid may be filtered and conveyed back to a mud pit 26 for reuse. The drilling fluid may travel down to the bottom of the drill string 20 known as the bottom-hole assembly (BHA) 28. The drilling fluid may be used to rotate, cool, and / or lubricate a drill bit 30 that may be a part of the BHA 28. The fluid may exit the drill string 20 through the drill bit 30 and carry drill cuttings away from the bottom of the borehole 12 back to the surface.

[0020] The BHA 28 may include the drill bit 30 along with various downhole tools, such as one or more logging tools 32. The BHA 28 may thus convey the one or more logging tools 32 through the geological region 14 via the borehole 12. As described in greater detail herein, the one or more logging tools 32 may be any suitable downhole tool that emits electromagnetic waves within the borehole 12 (e.g., a downhole environment). The downhole tools, which may include the one or more logging tools 32, may collect a variety of information relating to the geological region 14 and the state of drilling in the borehole 12. For instance, the downhole tools may be logging-while drilling (LWD) tools that measure physical properties of the geological region 14, such as density, porosity, resistivity, lithology, and so forth. Likewise, the downhole tools may be measurement-while-drilling (MWD) tools that measure certain drilling parameters, such as the temperature, pressure, orientation of the drill bit 30, mapping-while-drilling tools, and so forth. The downhole tools can be used to facilitate drilling operations, for example, directional drilling operations.

[0021] The one or more logging tools 32 may receive energy from an electrical energy device or an electrical energy storage device, such as an auxiliary power source 34 or another electrical energy source to power the tool. In some embodiments, the one or more logging tools 32 may include a power source within the one or more logging tools 32, such as a battery system or a capacitor, to store sufficient electrical energy to emit and / or receive electromagnetic waves.

[0022] Communications 36, such as control signals, may be transmitted from a data processing system 38 (processing system 38) to the one or more logging tools 32, and communications 36, such as data signals related to the results / measurements of the one or more logging tools 32, may be returned to the data processing system 38 from the one or more logging tools 32. The data processing system 38 may be any electronic data processing system that can be used to carry out the systems and methods of this disclosure. For example, the data processing system 38 may include one or more processors 40, which may execute instructions stored in memory 42 and / or storage 44. The memory 42 and / or the storage 44 of the data processing system 38 may be any suitable article of manufacture that can store the instructions. In certain embodiments, the one or more processors 40 may include a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, a digital signal processor (DSP), or another control or computing device. In certain embodiments, the one or more processors 40 may include machine learning (ML) and / or artificial intelligence (AI) based processors able to implement a trained ML model.

[0023] In certain embodiments, the memory 42 and storage 44 is implemented as one or more non-transitory computer-readable or machine-readable storage media. In certain embodiments, the memory 42 may include one or more different forms of memory, including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories. The storage 44 may include solid state drives, magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices. Note that the computer-executable instructions and associated data of the analysis module(s) may be provided on one computer-readable or machine-readable storage medium of the memory 42 or the storage 44, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media are considered to be part of an article (or article of manufacture), which may refer to any manufactured single component or multiple components. In certain embodiments, the storage 44 may be located either in the machine running the machine-readable instructions or may be located at a remote site from which machine-readable instructions may be downloaded over a network for execution.

[0024] As illustrated, the data processing system 38 may optionally also include a display 46, which may be any suitable electronic display and which may display images generated by the processor 40. The data processing system 38 may be a local component of the drilling system 10 (i.e., at the surface), within the one or more logging tools 32 (i.e., downhole), a device located proximate to the drilling operation, and / or a remote data processing device located away from the drilling system 10 to process downhole measurements in real time or sometime after the data has been collected. In some embodiments, the data processing system 38 may be a portable computing device (e.g., tablet, smart phone, or laptop) or a server remote from the drilling system 10. In some embodiments, the one or more logging tools 32 may store and process collected data in the BHA 28 or send the data to the surface for processing via communications 36 described above, including any suitable telemetry (e.g., electrical signals pulsed through the geological region 14 or mud pulse telemetry using the drilling fluid).

[0025] It should be noted that, although the discussion above relates to a drilling system, other downhole equipment or systems may employ the systems and methods of this disclosure. For example, a downhole tool with an acoustic tool conveyed by slickline, coiled tubing, wireline, or other delivery systems, may utilize the disclosed systems and methods.

[0026] Operation of drilling system 10 may be controlled by a processor of the data processing system 38. For example, FIG. 2 illustrates a block diagram of the data processing system 38 that is communicatively coupled to the one or more logging tools 32. In the illustrated embodiment, a logging tool 32 includes a processor 50, memory 52, an electromagnetic (EM) acquisition system 54, and storage 56. In some embodiments, the processor 50 may be ASIC (application specific integrated circuit), field programmable gate array (FPGA), a micro control unit (MCU), a digital signal processor (DSP), and the like. In general, the drilling system 10 communicates with the data processing system 38 via a data cable, telemeter or other suitable techniques. For example, the drilling system 10 may communicate EM measurements obtained by an EM sensor (or meter) as part of the EM acquisition system 54. In turn, a processor of the surface control system may determine certain parameters (e.g., porosity, water saturation, permeability, velocities, resistivity, and so forth) based on the EM measurements. In such embodiments, the EM acquisition system 54 may include an emission source (e.g., an antenna) to acquire, obtain, or otherwise measure EM measurements.

[0027] In certain embodiments, the data processing system 38 may include one or more analysis modules (e.g., a program of computer-executable instructions and associated data) that may be configured to perform various functions of the embodiments described herein. In certain embodiments, to perform these various functions, the one or more analysis modules may be executed on one or more processors 40 of the processing system 38, which may be connected to memory 42 and storage 44 in which the one or more analysis modules may be stored.

[0028] In certain embodiments, the computer-executable instructions of the one or more analysis modules, when executed by the one or more processors 40, may cause the one or more processors 40 to generate to perform autonomous drilling operations which can include, for example, control of drilling operations, such as directional drilling operations, in conjunction with a drilling plan based upon measured data.

[0029] FIG. 3 is a flow diagram of processes performed in drilling operation 200 to send communications 36 of FIG. 1 downhole, in accordance with an embodiment of the present disclosure. In block 202, a determination is made on what drilling goals are to be achieved. This can include implementation of a drilling plan to achieve drilling of a well along a desired drilling path. In embodiments, and as shown in FIG. 1, these goals may involve, for example, results / measurements of the one or more logging tools 32 as feedback that can be analyzed to determine what control signals are to be generated and transmitted to the downhole tool to execute drilling operations as part of the drilling plan.

[0030] Thus, for example, in block 202, the commands to be transmitted downhole can be control signals for control of an autonomous drilling operation to drill a well in conjunction with a drilling plan. Block 202 can include review of sensed parameters during drilling as well as determination of geosteering commands to be transmitted to the drilling tool based on those sensed parameters to effect particular drilling operations. As noted above, those geosteering commands can include, for example, steering inputs that can include setting of TF and SR so as to control the direction drilling will steer towards and how rapidly a drilling direction will be altered. Determination of the steering inputs can be performed, for example, based upon sensed data, for example, from downhole sensors, which can be used to determine subsequent commands to be transmitted to a drilling tool (e.g., logging tool 32) to implement a drilling plan (i.e., to adjust the well path to correspond to a drilling plan).

[0031] Moving to block 204, and based on the determination made in block 202, commands are sent downhole using an ISA to the logging tool 32 via the processing system 38 illustrated in FIG. 2. Block 206 illustrates the logging tool 32 actually performing the command sent to it via the ISA. After this drilling is performed, block 208 includes the logging tool 32 sending data back to the surface with any parameters measured during the activities in block 206. Finally, block 210 describes sending updated commands using the ISA to the logging tool 32 via the data processing system 38.

[0032] In certain embodiments, a simple Instruction Set Architecture (ISA) to enable humans to read and convey the information described in FIG. 3 is provided. This can be referred to as an operator directed drilling ISA. In some embodiments, the ISA can include two parts. The first part is referred to as downlink commands, which each include a unique number corresponding to a desired instruction to be sent to the downhole tool from the data processing system 38. The second part is referred to as instructions, which each correspond to a desired actions for the tool to execute on receiving a specific command. For example, the table below depicts command #1-1, wherein the command is associated with the instructions “Set tool face (TF) angle to 0 degrees and steering ration (SR) to 25%,” respectively.TABLE 1Operator Directed Drilling ISAPage 0 Manual (Build and Turn)Command ActionCommand #Steering Mode 0: Build and Turn1-0 Go to Page 0 with MTF neutral setting:TF = 0 degrees, SR = 0%1-1 Set TF = 0 degrees, SR = 25%1-2 Set TF = 0 degrees, SR = 50%1-3 Set TF = 0 degrees, SR = 75%1-4 Set TF = 0 degrees, SR = 100%1-5 Set TF = 18 degrees, SR = 75%1-6 Set TF = 18 degrees, SR = 100%1-7 Set TF = 36 degrees, SR = 50%1-8 Set TF = 36 degrees, SR = 100%1-9 Set TF = 45 degrees, SR = 25%1-10Set TF = 54 degrees, SR = 75%1-11Set TF = 72 degrees, SR = 50%1-12Set TF = 72 degrees, SR = 100%1-13Set TF = 90 degrees, SR = 25%1-14Set TF = 90 degrees, SR = 75%1-15Set TF = 90 degrees, SR = 100%1-16Set TF = 108 degrees, SR = 50%1-17Set TF = 108 degrees, SR = 100%1-18Set TF = 126 degrees, SR = 75%1-19Set TF = 135 degrees, SR = 25%1-20Set TF = 144 degrees, SR = 50%1-21Set TF = 144 degrees, SR = 100%1-22Set TF = 162 degrees, SR = 75%1-23Set TF = 180 degrees, SR = 25%1-24Set TF = 180 degrees, SR = 50%1-25Set TF = 180 degrees, SR = 75%1-26Set TF = 180 degrees, SR = 100%1-27Set TF = 198 degrees, SR = 75%1-28Set TF = 216 degrees, SR = 50%1-29Set TF = 216 degrees, SR = 100%1-30Set TF = 225 degrees, SR = 25%1-31Set TF = 234 degrees, SR = 75%2-0 Set TF = 252 degrees, SR = 50%2-1 Set TF = 252 degrees, SR = 100%2-2 Set TF = 270 degrees, SR = 25%2-3 Set TF = 270 degrees, SR = 75%2-4 Set TF = 270 degrees, SR = 100%2-5 Set TF = 288 degrees, SR = 50%2-6 Set TF = 288 degrees, SR = 100%2-7 Set TF = 306 degrees, SR = 75%2-8 Set TF = 315 degrees, SR = 25%2-9 Set TF = 324 degrees, SR = 50%2-10Set TF = 324 degrees, SR = 100%2-11Set TF = 342 degrees, SR = 75%2-12Set TF = 342 degrees, SR = 100%2-13Increase SR by 10%2-14Decrease SR by 10%2-15Increase TF by 12 degrees2-16Decrease TF by 12 degrees2-17Use Gravity Mode2-18Use Magnetic Mode2-192-202-212-22Downlink Bit Period: 18 s2-23Downlink Bit Period: 36 s

[0033] In this manner, the operator directed drilling ISA includes downlink commands that correspond to instructions having multiple command actions for the downhole tool associated therewith (e.g., both a TF and a SR command). That is, the downlink commands are coupled to particular parameter values (e.g., multiple command actions). This type of ISA is intended to be simple for use by a human. This type of ISA has some drawbacks, however. For example, the total number of ISA commands may be limited so that a human can easily find and transmit a particular downlink command. However, by implementing a relatively few downlink commands as part of the ISA, the corresponding instructions for each downlink command is similarly reduced to the number of downlink commands available. This has the effect of reducing the complexity of the ISA, however, the resulting control signals and corresponding actions are similarly limited to those provided in the instructions.

[0034] For example, a desired change in operation of the downhole tool may be desired by an operator, e.g., a particular steering input. However, there may not be a corresponding downlink command that corresponds to the desired steering input in the available ISA. This can lead an operator to choose a best available downlink command to affect a desired change in the operation of the drilling tool. However, because the ISA is relatively limited in size, that command may only allow for gross changes in operating parameters of the drilling tool and not the particular steering input desired. Thus, one or more additional downlink commands will be provided by the operator to continue to modify the operation of the downhole tool until a result that best approximates a result corresponding to the desired steering input can be achieved using the available downlink commands. These additional downlink commands and their corresponding instructions as performed by the downhole tool result in more time to achieve (or approximate) a desired result relative to an amount of time a precise instruction and its corresponding downlink command would use to achieve the result.

[0035] Thus, in some embodiments, a different ISA than the operator directed drilling ISA described above may be employed. For example, as drilling has become more autonomous, use of an ISA with greater size and / or complexity becomes feasible to provide a greater amount of instructions available to be selected and transmitted downhole. This ISA can be termed an autonomous drilling ISA. Using an autonomous drilling ISA can increase the resolution of parameter values (e.g., instructions) that can be transmitted to the downhole tool and reduce the total number of commands utilized to achieve a desired result, since more precise instructions can be defined with corresponding downlink commands as part of an ISA utilized in conjunction with autonomous drilling (e.g., an autonomous drilling ISA).

[0036] An example of an ISA used in autonomous drilling as an autonomous drilling ISA as illustrated in the table below.TABLE 2Autonomous Drilling ISACommand #Command Action1-0 Set TF=01-1 Set TF=11.251-2 Set TF=22.51-3 Set TF=33.751-4 Set TF=451-5 Set TF=56.251-6 Set TF=67.51-7 Set TF=78.751-8 Set TF=901-9 Set TF=101.251-10Set TF=112.51-11Set TF=123.751-12Set TF=1351-13Set TF=146.251-14Set TF=157.51-15Set TF=168.751-16Set TF=1801-17Set TF=191.251-18Set TF=202.51-19Set TF=213.751-20Set TF=2251-21Set TF=236.251-22Set TF=247.51-23Set TF=258.751-24Set TF=2701-25Set TF=281.251-26Set TF=292.51-27Set TF=303.751-28Set TF=3151-29Set TF=326.251-30Set TF=337.51-31Set TF=348.752-0 Set SR=4.348%2-1 Set SR=8.696%2-2 Set SR=13.043%2-3 Set SR=17.391%2-4 Set SR=21.739%2-5 Set SR=26.087%2-6 Set SR=30.435%2-7 Set SR=34.783%2-8 Set SR=39.130%2-9 Set SR=43.478%2-10Set SR=47.826%2-11Set SR=52.174%2-12Set SR=56.522%2-13Set SR=60.870%2-14Set SR=65.217%2-15Set SR=69.565%2-16Set SR=73.913%2-17Set SR=78.261%2-18Set SR=82.609%2-19Set SR=86.957%2-20Set SR=91.304%2-21Set SR=95.652%2-22Set SR=100.000%2-23Go to Page 1.12-24Go to Page 1.22-25Go to Page 1.32-26Go to Page 1.42-27Go to Page 1.52-28Go to Page 1.62-29Go to Page 1.72-30Go to Page 2.12-31Go to Index Page

[0037] As illustrated, the downlink commands are decoupled from parameter values, in contrast with the operator directed drilling ISA described above. Thus, for example, command 1-2 in the operator directed drilling ISA described in Table 1 results in an instruction that includes a particular parameter value (e.g., multiple command actions, here set TF=0 degrees and SR=25%). In contrast, command 1-2 in the autonomous drilling ISA described in Table 2 results in an instruction that controls only one command action (e.g., set TF=22.5 degrees). By decoupling the downlink commands from the parameter values (i.e., multiple control actions to be performed by the drilling tool), higher precision control of the downhole tool can be achieved.

[0038] The efficiency gained by this decoupling can be illustrated by the following example. If the downhole tool is set to follow TF of 72 degrees and SR of 50%, and a desired control action is to set TF to 45 degrees and keep the SR to 50%, using the operator directed drilling ISA of Table 1 requires the engineer to find the downlink closest command link to provide an instruction that best approximates the desired control actions, since no downlink command and corresponding instruction provides for TF of 72 degrees and SR of 50% (i.e., the desired values do not exist in the operator directed drilling ISA). As illustrated by Table 1, the closest command is command 1-9, which sets the TF to 45 degrees and the SR to 25%. The disadvantage to using operator directed drilling ISA, however, is that the engineer will have to subsequently send two further commands to increase SR by 10% (i.e., send command 2-13 twice). Although the final result sets the TF to 45 degrees, the SR % will only be set to 45%. Using the operator directed drilling ISA, this is the closest to the desired SR that can be achieved, even after using three total commands. Each of these three commands takes time to execute and slows down the overall drilling process, thus resulting in inefficiencies.

[0039] If instead of the ISA of Table 1 (the operator directed drilling ISA), the ISA of Table 2 (the autonomous drilling ISA) is utilized, the data processing system 38, and more particularly computer-executable instructions when executed by the one or more processors 40, may perform autonomous drilling operations with greater precision and in less time than the example above. For example, the data processing system 40 executing a program as a directional drilling advisor that operates to transmit drilling command actions to a downhole tool can send a single downlink command 1-4 to set the TF to 45 degrees. No additional downlink command need be sent to adjust the SR, since no corresponding control action to modify SR is required. This results in up to a three time reducing in the time to implement the control action using the autonomous drilling ISA. This example highlights that higher precision command actions that can be undertaken via use of expanded downlink commands and instructions of the operator directed drilling ISA.

[0040] In another embodiment, the autonomous drilling ISA is organized to maximize the number of commands sent downhole. For example, command pages can be maximized by allocating separate pages for separate parameters. Table 2 would therefore represent a page incorporating commands for TF and SR, but subsequent pages may be dedicated to other parameters, such as Inclination Hold (IH), Hold Inclination and Azimuth (HIA), and Auto curve (AC). Additionally, this can be expanded to allow for pages for additional commands per section type such as: Vertical, Curve, Tangent, and Horizontal.

[0041] In another embodiment, the autonomous drilling ISA may be able to accommodate more bits representing commands with no issues. For example, it is possible to add an additional bit to the autonomous drilling ISA relative to an operator directed drilling ISA, for example, so that a downlink command is represented by 7 bits instead of 6, resulting in a doubling of commands per page from 64 to 128 commands per page. Traditional ISA systems will not be able to accommodate this change as human operators would be overburdened with this increase. The present system, being autonomous, can accommodate more precise values using a fewer number of commands to reach a desired drilling state with this expansion of downlink commands available.

[0042] In another embodiment, the number of downlink commands may be increased in the autonomous drilling ISA by using an index page, for example, for multiple chapters of steering commands pages. This structure is referred to as two level page hierarchy instead of just a single level. For example, in the proposed ISA of Table 1, all available pages are accessible via a single command such as commands 2-23 till 2-30. However, to expand on the number of available commands in the ISA, it is possible to use additional levels of page hierarchy via command 2-31. This command will direct the tool to at least one alternate page (i.e. an index page) where all commands correspond to page ranges. This can allow for access, for example, to 512 pages each with 64 commands.

[0043] The following example illustrates the difference in steering commands in 1 versus 2 level page hierarchy models. In single level pages of 1 level hierarchy, assume there are 8 navigation commands out of 64. This means there are 56 steering commands per page, and there will be a total of 448 steering commands in the entire ISA (56*8 pages=448). Using two level pages, however, and assuming 9 navigation commands (e.g. 8 shortcut pages+1 command to access the special page of page ranges), this means there are 55 steering commands per page and 28,160 total steering commands in the ISA. (55*512 pages=28160). While access of the separate levels can require, for example. two downlink commands to change page ranges, the gain from increasing the maximum number of available steering commands can still be beneficial.

[0044] Additionally, autonomous drilling ISA may be used to send uplink commands using the same process as downlink commands, by utilizing telemetry available to transmit information to the surface. For example, an equivalent to multiple pages for uplinks can be provided, which allows for higher precision for specific data fields in the information being sent to the surface, e.g. actual steering ratio being executed by the downhole tool as different than the desired steering ratio that is being sent from surface to downhole. This allows for enhanced tool control, which leads to improved drilling quality and higher rate of penetration (ROP) due to fewer control commands being sent overall. Furthermore, as uplink commands may be transmitted without any separate “Go-to page” command being sent from tool to the surface, an acknowledgement packet to both confirm the receipt of the command and surface / cloud software switch to corresponding uplink page can instead be transmitted.

[0045] The autonomous drilling ISA is more scalable and flexible than an operator directed drilling ISA. Use of the autonomous drilling ISA is not limited to select commands that are easy to be memorized by an operator. Instead, increased control actions (e.g., altering a toolface angle of a downhole tool, altering a steering ratio of the downhole tool, etc.) can be performed via implementation of the data processing system 38.

[0046] The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the disclosure to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrated and described may be re-arranged, and / or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principals of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosure and various embodiments with various modifications as are suited to the particular use contemplated.

Examples

Embodiment Construction

[0011]Certain embodiments commensurate in scope with the present disclosure are summarized below. These embodiments are not intended to limit the scope of the disclosure, but rather these embodiments are intended only to provide a brief summary of certain disclosed embodiments. Indeed, the present disclosure may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

[0012]As used herein, the term “coupled” or “coupled to” may indicate establishing either a direct or indirect connection (e.g., where the connection may not include or include intermediate or intervening components between those coupled) and is not limited to either unless expressly referenced as such. The term “set” may refer to one or more items. Wherever possible, like or identical reference numerals are used in the figures to identify common or the same elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown ...

Claims

1. A tangible, non-transitory, computer-readable medium comprising instructions that, when executed by processing circuitry, are configured to cause the processing circuitry to:determine at least one modification to be made to an operation of a downhole tool;select a first Instruction Set Architecture (ISA) downlink command corresponding to a first instruction to implement only one first command action at the downhole tool to effect at least a portion of the modification to be made to the operation of the downhole tool; andtransmit the first ISA downlink command as a control signal to control at least a portion of the downhole tool as the first command action.

2. The tangible, non-transitory, computer-readable medium of claim 1, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to receive at least one sensed operational parameter of the downhole tool.

3. The tangible, non-transitory, computer-readable medium of claim 2, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to utilize the sensed operational parameter of the downhole tool in selecting the first ISA downlink command.

4. The tangible, non-transitory, computer-readable medium of claim 3, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to receive at least one second sensed operational parameter of the downhole tool.

5. The tangible, non-transitory, computer-readable medium of claim 4, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to utilize the second sensed operational parameter of the downhole tool to:determine at least one second modification to be made to the operation of the downhole tool;select a second ISA downlink command corresponding to a second instruction to implement only one second command action at the downhole tool to effect at least a portion of the second modification to be made to the operation of the downhole tool; andtransmit the second ISA downlink command as a second control signal to control the at least a portion of the downhole tool as the second command action.

6. The tangible, non-transitory, computer-readable medium of claim 1, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to select the first ISA downlink command from a plurality of chapters of ISA downlink commands.

7. The tangible, non-transitory, computer-readable medium of claim 1, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to select the first ISA downlink command as corresponding to the first instruction to alter a steering input of the downhole tool.

8. The tangible, non-transitory, computer-readable medium of claim 7, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to select the first ISA downlink command as implementing a first tool face angle as the first command action.

9. The tangible, non-transitory, computer-readable medium of claim 7, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to select the first ISA downlink command as implementing a first steering ratio as the first command action.

10. The tangible, non-transitory, computer-readable medium of claim 1, wherein the instructions, when executed by the processing circuitry, further cause the processing circuitry to select a second ISA downlink command corresponding to a second instruction to implement only one second command action at the downhole tool to effect at least a second portion of the modification to be made to the operation of the downhole tool.

11. A method, comprising:determining, via data processing system, at least one modification to be made to an operation of a downhole tool;selecting, via the data processing system, a first Instruction Set Architecture (ISA) downlink command corresponding to a first instruction to implement only one first command action at the downhole tool to effect at least a portion of the modification to be made to the operation of the downhole tool; andtransmitting, via the data processing system, the first ISA downlink command as a control signal to control at least a portion of the downhole tool as the one first command action.

12. The method of claim 11, further comprising receiving at least one sensed operational parameter of the downhole tool and utilizing the sensed operational parameter of the downhole tool in selecting the first ISA downlink command.

13. The method of claim 12, further comprising receiving at least one second sensed operational parameter of the downhole tool.

14. The method of claim 13, further comprising utilizing the second sensed operational parameter of the downhole tool to:determine at least one second modification to be made to the operation of the downhole tool;select a second ISA downlink command corresponding to a second instruction to implement only one second command action at the downhole tool to effect at least a portion of the second modification to be made to the operation of the downhole tool; andtransmit the second ISA downlink command as a second control signal to control the at least a portion of the downhole tool as the second command action.

15. The method of claim 11, further comprising selecting the first ISA downlink command from a plurality of chapters of ISA downlink commands.

16. The method of claim 11, further comprising selecting the first ISA downlink command as corresponding to the first instruction to alter a steering input of the downhole tool.

17. The method of claim 16, further comprising selecting the first ISA downlink command as implementing a first tool face angle as the command action or a first steering ratio as the command action.

18. The method of claim 11, further comprising selecting a second ISA downlink command corresponding to a second instruction to implement only one second command action at the downhole tool to effect at least a second portion of the modification to be made to the operation of the downhole tool.

19. A system, comprising:processing circuitry configured to:determine at least one modification to be made to an operation of a downhole tool;select a first Instruction Set Architecture (ISA) downlink command corresponding to a first instruction to implement only one first command action at the downhole tool to effect at least a portion of the modification to be made to the operation of the downhole tool; andtransmit the a first ISA downlink command as a control signal to control at least a portion of the downhole tool as the first command action.

20. The system of claim 19, wherein the processing circuitry is further configured to select a second ISA downlink command corresponding to a second instruction to implement only one second command action at the downhole tool to effect at least a second portion of the modification to be made to the operation of the downhole tool.

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