A method may include dividing a wellplan into one or more section using a section detection algorithm, receiving a depth measurement of a drill bit or a bottom hole assembly located in a wellbore, utilizing the section detection algorithm and the depth measurement to identify a section of the wellplan from the one or more sections of the wellplan, and identifying a target based at least in part on the identified section. The method may further include determining one or more steering commands based at least in part on the target and a control algorithm and steering the bottom hole assembly to the target using the one or more steering commands.

CROSS-REFERENCED TO RELATED APPLICATIONS

The present application is a non-provisional of U.S. Patent Application No. 63/340,556, filed on May 11, 2022, the entire disclosure of which is incorporated herein by reference.

BACKGROUND

The oil and gas industry may use wellbores as fluid conduits to access subterranean deposits of various fluids and minerals which may include hydrocarbons. There may be a direct correlation between the productivity of a wellbore and the interfacial surface area through which the wellbore intersects a target subterranean formation. For this reason, it may be economically desirable to increase the length of a drilled section within a target subterranean formation by means of extending a horizontal, slant-hole, or deviated wellbore through the target subterranean formation. Additionally, horizontal, slant-hole, and deviated drilling techniques may be utilized in operational contexts where the surface location is laterally offset from the target subterranean formation such that the target subterranean formation may not be accessible by vertical drilling alone.

Due to leasing restrictions associated with developing a subterranean asset it may be important to pre-plan and adhere to a specific wellbore trajectory in order to maximize the extended length of the wellbore through the target subterranean formation. Additionally, constructing a smooth wellbore profile may be a priority if further operations may be utilized to complete and produce the well. Unintentional departures from the planned wellbore trajectory, which may include “bit walking,” may result in hole deviations. In non-limiting terms, hole deviations may be caused by geological heterogeneity, property variations in geological layers, formation dip angles, geological folding and faulting, drill-bit type, bit hydraulics, improper hole cleaning, drill string characteristics, high ROP, and human error. Unplanned hole deviations may result in “wellbore tortuosity,” which may in the very least create problems with future well operations including the placement and utilization of casing, completion tools, logs, and/or production and artificial lift equipment.

DETAILED DESCRIPTION

This disclosure details methods and systems for automating the steering control for vertical-curve-lateral (VCL) drilling. With use of multi-purpose smart drilling tools which may achieve high-DLS curves as well as straight sections with tight tolerances, single-trip VCL drilling applications have gained great importance. As discussed below, the method may utilize a reference wellplan where the wellplan is divided into vertical, tangent, curve, and lateral sections based on a section detection algorithm based on predetermined criteria. The section detection algorithm may operate in real-time during drilling operations to detect and categorize a current section of a wellbore based at least in part on a reference wellplan and bit depth. In some examples, the section detection algorithm may be either a partially- or a fully automated algorithm. As described herein, real-time may be generally understood to relate to a system, apparatus, or method in which a set of input data is processed and available for use when new survey information is acquired. In some examples, once the new survey information is acquired the data may be processed and available for use within 100 milliseconds (“ms”) to 1 second. Once the current section of the wellbore is detected and categorized, a control algorithm may establish the control parameters according to an objective which may be defined according to the current section and/or transition point. In some examples, the control algorithm may be either a partially- or a fully automated algorithm. In some examples, the control algorithm may automatically set the next target and adjust the control constraints on position, attitude, walk rate, build rate, and/or curvature. Given the target and the objective, the constraints and the suitable control algorithm may be selected and run to provide steering recommendations. As discussed below, suitable control algorithms may include model-based control algorithms and model-free control algorithms. The steering recommendations may be used to direct a drill bit in order to extend a drill string through a subterranean formation in accordance with a wellplan.

FIG.1illustrates an example of drilling system100. As illustrated, wellbore102may extend from a wellhead104into a subterranean formation106from a surface108. Generally, wellbore102may include horizontal, vertical, slanted, curved, and other types of wellbore geometries and orientations. Wellbore102may be cased or uncased. In examples, wellbore102may include a metallic member. By way of example, the metallic member may be a casing, liner, tubing, or other elongated steel tubular disposed in wellbore102.

As illustrated, wellbore102may extend through subterranean formation106. As illustrated inFIG.1, wellbore102may extend generally vertically into the subterranean formation106, however, wellbore102may extend at an angle through subterranean formation106, such as horizontal and slanted wellbores. For example, althoughFIG.1illustrates a vertical or low inclination angle well, high inclination angle or horizontal placement of the well and equipment may be possible. It should further be noted that whileFIG.1generally depicts land-based operations, those skilled in the art may recognize that the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.

As illustrated, a drilling platform110may support a derrick112having a traveling block114for raising and lowering drill string116. Drill string116may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art. A kelly118may support drill string116as it may be lowered through a rotary table120. A drill bit122may be attached to the distal end of drill string116and may be driven either by a downhole motor, a rotary steerable system (“RSS”), and/or via rotation of drill string116from surface108. Without limitation, drill bit122may include, roller cone bits, PDC bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As drill bit122rotates, it may create and extend wellbore102that penetrates various subterranean formations106. A pump124may circulate drilling fluid through a feed pipe126through kelly118, downhole through interior of drill string116, through orifices in drill bit122, back to surface108via annulus128surrounding drill string116, and into a retention pit132.

With continued reference toFIG.1, drill string116may begin at wellhead104and may traverse wellbore102. Drill bit122may be attached to a distal end of drill string116and may be driven, for example, either by a downhole motor and/or via rotation of drill string116from surface108. In a non-limiting example, the weight of drill string116and bottom hole assembly may be controlled and measured while drill bit122is disposed within wellbore102. In further examples, drill bit122may or may not be in contact with the bottom of wellbore102. Drill bit122may be allowed to contact the bottom of wellbore102with varying amounts of weight applied to drill bit122. The weight of drill string116may be measured at the surface of wellbore102and may be referred to as the “hook load.” The difference in the hook load when drill bit122is suspended just above the bottom of wellbore102and the hook load when drill bit122is in contact with the bottom of wellbore102may be referred to as the weight-on-bit (“WOB”). Both the hook load and the weight-on-bit may be considered drilling parameters. In some examples the hook load may be measured by a hoisting system or a hook load sensor. In some examples, the hook load is measured at the surface by a sensor disposed at the surface of drilling system100. Drill bit122may be a part of bottom hole assembly130at the distal end of drill string116. In some examples, bottom hole assembly130may further include tools for directional drilling applications. In other examples, directional drilling tools may be disposed anywhere along the drill string assembly. In further examples, directional drilling tools may be disposed within the wellbore using wireline, electric line, or slick line. As will be appreciated by those of ordinary skill in the art, bottom hole assembly130may include directional drilling tools including but not limited to a measurement-while drilling (MWD) and/or logging-while drilling (LWD) system, magnetometers, accelerometers, agitators, bent subs, orienting subs, mud motors, rotary steerable systems (RSS), jars, vibration reduction tools, roller reamers, pad pushers, non-magnetic drilling collars, whipstocks, push-the-bit systems, point-the-bit systems, directional steering heads and other directional drilling tools. Directional drilling tools may be disposed anywhere along the drill string assembly including at the portion distal to the drilling right which may be known as the Bottom hole assembly130may comprise any number of tools, transmitters, and/or receivers to perform downhole measurement operations. In some scenarios, these downhole measurements produce drilling parameters which may be used to guide the drilling operation. For example, as illustrated inFIG.1, bottom hole assembly130may include a measurement assembly134. It should be noted that measurement assembly134may make up at least a part of bottom hole assembly130. Without limitation, any number of different measurement assemblies, communication assemblies, battery assemblies, and/or the like may form bottom hole assembly130with measurement assembly134. Additionally, measurement assembly134may form bottom hole assembly130itself. In examples, measurement assembly134may comprise at least one sensor136, which may be disposed at the surface of measurement assembly134. It should be noted that whileFIG.1illustrates a single sensor136, there may be any number of sensors disposed on or within measurement assembly134. Without limitation, sensors may be referred to as a transceiver. Further, it should be noted that there may be any number of sensors disposed along bottom hole assembly130at any degree from each other. In examples, sensors136may also include backing materials and matching layers. It should be noted that sensors136and assemblies housing sensors136may be removable and replaceable, for example, in the event of damage or failure.

Without limitation, bottom hole assembly130may be connected to and/or controlled by information handling system131, which may be disposed on surface108. Without limitation, information handling system131may be disposed down hole in bottom hole assembly130. Processing of information recorded may occur down hole and/or on surface108. Processing occurring downhole may be transmitted to surface108to be recorded, observed, and/or further analyzed. Additionally, information recorded on information handling system131that may be disposed down hole may be stored until bottom hole assembly130may be brought to surface108. In examples, information handling system131may communicate with bottom hole assembly130through a communication line (not illustrated) disposed in (or on) drill string116. In examples, wireless communication may be used to transmit information back and forth between information handling system131and bottom hole assembly130. Information handling system131may transmit information to bottom hole assembly130and may receive as well as process information recorded by bottom hole assembly130. In examples, a downhole information handling system (not illustrated) may include, without limitation, a microprocessor or other suitable circuitry, for estimating, receiving, and processing signals from bottom hole assembly130. Downhole information handling system (not illustrated) may further include additional components, such as memory, input/output devices, interfaces, and the like. In examples, while not illustrated, bottom hole assembly130may include one or more additional components, such as analog-to-digital converter, filter, and amplifier, among others, which may be used to process the measurements of bottom hole assembly130before they may be transmitted to surface108. Alternatively, raw measurements from bottom hole assembly130may be transmitted to surface108.

Any suitable technique may be used for transmitting signals from bottom hole assembly130to surface108, including, but not limited to, wired pipe telemetry, mud-pulse telemetry, acoustic telemetry, and electromagnetic telemetry. While not illustrated, bottom hole assembly130may include a telemetry subassembly that may transmit telemetry data to surface108. At surface108, pressure sensors (not shown) may convert the pressure signal into electrical signals for a digitizer (not illustrated). The digitizer may supply a digital form of the telemetry signals to information handling system131via a communication link140, which may be a wired or wireless link. The telemetry data may be analyzed and processed by information handling system131.

As illustrated, communication link140(which may be wired or wireless, for example) may be provided that may transmit data from bottom hole assembly130to an information handling system131at surface108. Information handling system131may include a personal computer141, an output device142(e.g., a video display), an input device144(e.g., keyboard, mouse, etc.), and/or non-transitory computer-readable media146(e.g., optical disks, magnetic disks) that may store code representative of the methods described herein. In addition to, or in place of processing at surface108, processing may occur downhole, at an offsite location, or any combination thereof. In some examples, and as described in further detail below, the processing of information handling system131may be performed using one or more computers which may further be located in one or more locations. In a non-limiting example, the processing of information handling system131may be performed using a network of computers. As discussed below, information handling system131may be utilized in the navigation of the steering equipment of drilling system100in accordance with a pre-planned wellbore trajectory or wellplan.

Information handling system131may include any instrumentality or aggregate of instrumentalities operable to compute, estimate, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system131may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. Information handling system131may include random access memory (RAM), one or more processing resources such as a central processing unit134(CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system131may include one or more disk drives146, output devices142, such as a video display, and one or more network ports for communication with external devices as well as an input device144(e.g., keyboard, mouse, etc.). Information handling system131may also include one or more buses operable to transmit communications between the various hardware components.

Alternatively, systems and methods of the present disclosure may be implemented, at least in part, with non-transitory computer-readable media. Non-transitory computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Non-transitory computer-readable media may include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.

FIG.2illustrates an example information handling system131which may be employed to perform various steps, methods, and techniques disclosed herein. Persons of ordinary skill in the art will readily appreciate that other system examples are possible. As illustrated, information handling system131includes a processing unit (CPU or processor)202and a system bus204that couples various system components including system memory206such as read only memory (ROM)208and random-access memory (RAM)210to processor202. Processors disclosed herein may all be forms of this processor202. Information handling system131may include a cache212of high-speed memory connected directly with, in close proximity to, or integrated as part of processor202. Information handling system131copies data from memory206and/or storage device214to cache212for quick access by processor202. In this way, cache212provides a performance boost that avoids processor202delays while waiting for data. These and other modules may control or be configured to control processor202to perform various operations or actions. Other system memory206may be available for use as well. Memory206may include multiple different types of memory with different performance characteristics. It may be appreciated that the disclosure may operate on information handling system131with more than one processor202or on a group or cluster of computing devices networked together to provide greater processing capability. Processor202may include any general-purpose processor and a hardware module or software module, such as first module216, second module218, and third module220stored in storage device214, configured to control processor202as well as a special-purpose processor where software instructions are incorporated into processor202. Processor202may be a self-contained computing system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor may be symmetric or asymmetric. Processor202may include multiple processors, such as a system having multiple, physically separate processors in different sockets, or a system having multiple processor cores on a single physical chip. Similarly, processor202may include multiple distributed processors located in multiple separate computing devices but working together such as via a communications network. Multiple processors or processor cores may share resources such as memory206or cache212or may operate using independent resources. Processor202may include one or more state machines, an application specific integrated circuit (ASIC), or a programmable gate array (PGA) including a field PGA (FPGA).

Each individual component discussed above may be coupled to system bus204, which may connect each and every individual component to each other. System bus204may be any of several types of bus structures including a memory bus or memory controller, a peripheral bus, and a local bus using any of a variety of bus architectures. A basic input/output (BIOS) stored in ROM208or the like, may provide the basic routine that helps to transfer information between elements within information handling system131, such as during start-up. Information handling system131further includes storage devices214or computer-readable storage media such as a hard disk drive, a magnetic disk drive, an optical disk drive, tape drive, solid-state drive, RAM drive, removable storage devices, a redundant array of inexpensive disks (RAID), hybrid storage device, or the like. Storage device214may include software modules216,218, and220for controlling processor202. Information handling system131may include other hardware or software modules. Storage device214is connected to the system bus204by a drive interface. The drives and the associated computer-readable storage devices provide nonvolatile storage of computer-readable instructions, data structures, program modules and other data for information handling system131. In one aspect, a hardware module that performs a particular function includes the software component stored in a tangible computer-readable storage device in connection with the necessary hardware components, such as processor202, system bus204, and so forth, to carry out a particular function. In another aspect, the system may use a processor and computer-readable storage device to store instructions which, when executed by the processor, cause the processor to perform operations, a method or other specific actions. The basic components and appropriate variations may be modified depending on the type of device, such as whether information handling system131is a small, handheld computing device, a desktop computer, or a computer server. When processor202executes instructions to perform “operations”, processor202may perform the operations directly and/or facilitate, direct, or cooperate with another device or component to perform the operations.

As illustrated, information handling system131employs storage device214, which may be a hard disk or other types of computer-readable storage devices which may store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, digital versatile disks (DVDs), cartridges, random access memories (RAMs)210, read only memory (ROM)208, a cable containing a bit stream and the like, may also be used in the exemplary operating environment. Tangible computer-readable storage media, computer-readable storage devices, or computer-readable memory devices, expressly exclude media such as transitory waves, energy, carrier signals, electromagnetic waves, and signals per se.

To enable user interaction with information handling system131, an input device222represents any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech and so forth. An output device224may also be one or more of a number of output mechanisms known to those of skill in the art. In some instances, multimodal systems enable a user to provide multiple types of input to communicate with information handling system131. Communications interface226generally governs and manages the user input and system output. There is no restriction on operating on any particular hardware arrangement and therefore the basic hardware depicted may easily be substituted for improved hardware or firmware arrangements as they are developed.

As illustrated, each individual component describe above is depicted and disclosed as individual functional blocks. The functions these blocks represent may be provided through the use of either shared or dedicated hardware, including, but not limited to, hardware capable of executing software and hardware, such as a processor202, that is purpose-built to operate as an equivalent to software executing on a general-purpose processor. For example, the functions of one or more processors presented inFIG.2may be provided by a single shared processor or multiple processors. (Use of the term “processor” should not be construed to refer exclusively to hardware capable of executing software.) Illustrative examples may include microprocessor and/or digital signal processor (DSP) hardware, read-only memory (ROM)208for storing software performing the operations described below, and random-access memory (RAM)210for storing results. Very large-scale integration (VLSI) hardware examples, as well as custom VLSI circuitry in combination with a general-purpose DSP circuit, may also be provided.

FIG.3illustrates an example information handling system131having a chipset architecture that may be used in executing the described method and generating and displaying a graphical user interface (GUI). Information handling system131is an example of computer hardware, software, and firmware that may be used to implement the disclosed technology. Information handling system131may include a processor202, representative of any number of physically and/or logically distinct resources capable of executing software, firmware, and hardware configured to perform identified computations. Processor202may communicate with a chipset300that may control input to and output from processor202. In this example, chipset300outputs information to output device224, such as a display, and may read and write information to storage device214, which may include, for example, magnetic media, and solid-state media. Chipset300may also read data from and write data to RAM210. A bridge302for interfacing with a variety of user interface components304may be provided for interfacing with chipset300. Such user interface components304may include a keyboard, a microphone, touch detection and processing circuitry, a pointing device, such as a mouse, and so on. In general, inputs to information handling system131may come from any of a variety of sources, machine generated and/or human generated.

Chipset300may also interface with one or more communication interfaces226that may have different physical interfaces. Such communication interfaces may include interfaces for wired and wireless local area networks, for broadband wireless networks, as well as personal area networks. Some applications of the methods for generating, displaying, and using the GUI disclosed herein may include receiving ordered datasets over the physical interface or be generated by the machine itself by processor202analyzing data stored in storage device214or RAM210. Further, information handling system131receive inputs from a user via user interface components304and execute appropriate functions, such as browsing functions by interpreting these inputs using processor202.

During drilling operations, information handling system131may process different types of the real-time data originated from varied sampling rates and various sources, such as diagnostics data, sensor measurements, operations data, and/or the like. These measurements from wellbore102, BHA130, measurement assembly134, and sensor136may allow for information handling system131to perform real-time health assessment of the drilling operation. Drilling tools and equipment may further comprise a variety of sensors which may be able to provide real-time measurements and data relevant to steering the drilling equipment in order to construct a wellbore in adherence to a well plan. In some examples this drilling equipment may include drilling rigs, top drives, drilling tubulars, mud motors, gyroscopes, accelerometers, magnetometers, bent housing subs, directional steering heads, rotary steerable systems (“RSS”), whipstocks, push-the-bit systems, point-the-bit systems, and other directional drilling tools. In the context of drilling operations, “real-time,” may be construed as monitoring, gathering, assessing, and/or utilizing data contemporaneously with the execution of the drilling operation. In further examples, real-time may be understood to relate to a system, apparatus, or method in which a set of input data is processed and available for use when new survey information is acquired. For example, once the new survey information is acquired the data may be processed and available for use within 100 milliseconds (“ms”) to 1 second. Real-time operations may further comprise modifying the initial design or execution of the planned operation in order to modify the trajectory of a drilling operation. In some examples, the modifications to the drilling operation may occur through automated or semi-automated processes. In further examples, an automated drilling process may include conducting or performing one or more portions of a drilling operation without the use of human intervention. In some examples, the usage of algorithms may replace the requirement for human intervention in the decision-making process. In other examples, the section of a wellbore that a drill bit (e.g., drill bit122inFIG.1) is located in may be identified according to a section detection algorithm without the requirement for human intervention. In further examples, the section detection algorithm may be partially or fully automated. Additionally, a control algorithm may be used to identify operational parameters which may be used to construct a wellbore according to a wellplan. In some examples, the control algorithm may be partially or fully automated such that the operational parameters may be at least partially determined without human intervention. For example, an automated drilling process may include relaying or downlinking a set of operational commands (control commands) to an RSS in order to modify a drilling operation to achieve a certain objective. In other examples, operational commands (control commands) may be automatically relayed to the top drive. In other examples, the operational commands (control commands) may be relayed to the rig personnel for review prior to implementation. In some examples, drilling objectives may be incorporated into the drilling operation through minimization of a cost function, which will be discussed in further detail below.

FIG.4illustrates an example of one arrangement of resources in a computing network400that may employ the processes and techniques described herein, although many others are of course possible. As noted above, an information handling system131, as part of their function, may utilize data, which includes files, directories, metadata (e.g., access control list (ACLS) creation/edit dates associated with the data, etc.), and other data objects. The data on the information handling system131is typically a primary copy (e.g., a production copy). During a copy, backup, archive or other storage operation, information handling system131may send a copy of some data objects (or some components thereof) to a secondary storage computing device404by utilizing one or more data agents402.

A data agent402may be a desktop application, website application, or any software-based application that is run on information handling system131. As illustrated, information handling system131may be disposed at any rig site (e.g., referring toFIG.1) or repair and manufacturing center. The data agent may communicate with a secondary storage computing device404using communication protocol408in a wired or wireless system. The communication protocol408may function and operate as an input to a website application. In the website application, field data related to pre- and post-operations, generated DTCs, notes, and the like may be uploaded. Additionally, information handling system131may utilize communication protocol408to access processed measurements, operations with similar DTCs, troubleshooting findings, historical run data, and/or the like. This information is accessed from secondary storage computing device404by data agent402, which is loaded on information handling system131.

Secondary storage computing device404may operate and function to create secondary copies of primary data objects (or some components thereof) in various cloud storage sites406A-N. Additionally, secondary storage computing device404may run determinative algorithms, such as the section detection algorithm or the control algorithm, on data uploaded from one or more information handling systems131, discussed further below. Communications between the secondary storage computing devices404and cloud storage sites406A-N may utilize REST protocols (Representational state transfer interfaces) that satisfy basic C/R/U/D semantics (Create/Read/Update/Delete semantics), or other hypertext transfer protocol (“HTTP”)-based or file-transfer protocol (“FTP”)-based protocols (e.g., Simple Object Access Protocol).

In conjunction with creating secondary copies in cloud storage sites406A-N, the secondary storage computing device404may also perform local content indexing and/or local object-level, sub-object-level or block-level deduplication when performing storage operations involving various cloud storage sites406A-N. Cloud storage sites406A-N may further record and maintain DTC code logs for each downhole operation or run, map DTC codes, store repair and maintenance data, store operational data, and/or provide outputs from determinative algorithms that are located in cloud storage sites406A-N. In a non-limiting example, this type of network may be utilized as a platform to store, backup, analyze, import, and preform extract, transform and load (“ETL”) processes to the data gathered during a drilling operation.

FIG.5illustrates workflow500for autonomous vertical-curve-lateral (“VCL”) drilling. Workflow500may be performed utilizing one or more information handling systems131in a computing network400(i.e., referring toFIG.5). Workflow500may be used to divide a wellplan into vertical, tangent, curve, and lateral sections based at least in part on predetermined criteria. The inputs to workflow500, such as the reference wellplan, bit depth, and high-level objective may be identified in block502. In some examples, the bit depth may be determined from a depth measurement. In further examples, the depth measurement may be determined from the cumulative length of the drill pipe and drilling tools disposed within the well. In some examples, the depth may additionally be determined by incorporating inputs such as the string weight and block height or top drive height. In further examples, the string weight may be determined from the hook load, which may further be determined from the hook load sensors. In some examples, the reference wellplan (e.g., “wellplan”) may include associated pairs of intended (e.g., planned) dog-leg severity (“DLS”) and inclination values which may vary according to vertical depth. In further examples, the predetermined criteria may include grouping the ranges for the associated pairs of intended (e.g., planned) DLS and inclination values and labelling the groupings with a categorical descriptor. The categorical descriptor may be associated with a section of a wellbore. In some examples, a “high level objective,” may be a function of the categorical descriptor or the objectives in a given section of the wellbore. For example, each section of a wellplan may be categorized as one of a vertical, tangent, curve, and/or lateral section according to the aforementioned, pre-defined ranges for DLS and inclination. These categories may further tie to the high-level objective as identified in block502. In some examples, the boundaries utilized to group the ranges, which define a particular section, may vary from well to well. The boundaries utilized to group the ranges and delineate the categories for the wellbore sections (e.g., the current section if drill bit122is located in a defined wellbore section) may be furthered described as depicted inFIG.6.

FIG.6illustrates how a section detected in block504ofFIG.5may be determined using workflow600. Workflow600may begin with block602where inputs such as the wellplan and the bit depth are identified or specified. The inputs may be the wellplan from block502inFIG.5and the current depth of drill bit122(e.g., referring toFIG.1). Using the inputs from block602, a DLS and an inclination angle may be identified in block604. For example, the wellplan may include tabular data columns for DLS values and associated inclination values as a function of depth such that any given depth, a DLS and inclination value may be identified or interpolated. The identification of the dog leg severity and the inclination angle in block604may be compared to a pre-determined criteria in block606to identify whether the current bit depth is associated with a vertical section, a tangent section, a curve section, and/or a lateral section in comparison to the wellplan. For the given example, the vertical threshold may be 3 degrees, the lateral threshold may be 80 degrees, and the dog-leg severity threshold (“DLS threshold”) may be 0.1 degrees per 100 feet (0.1 degrees per 30.5 meters). While the foregoing thresholds may provide for example thresholds which may be applied to a given well, the threshold values should not be construed as to limit the possible threshold values to the values provided in this specific example. As such, alternative thresholds may be utilized. For example, the value selected for the vertical threshold may be value between about 0 and about 3 degrees, the value selected for the lateral threshold may be a value between about 80 and about 95 degrees, and the value selected for the dog-leg severity threshold (“DLS threshold”) may be a value between about 0 degrees per 100 feet and about 0.5 degrees per 100 ft (0.5 degrees per 30.5 meters). As previously described, various ranges for DLS and inclination may be grouped or categorized in accordance with a wellbore section as depicted in block606. The categorized wellbore sections in block606may be an output in block504of workflow500(e.g., referring toFIG.5) The wellbore section detection algorithm as depicted inFIG.6and described in the foregoing may be executed utilizing one or more information handling systems (e.g., information handling system131inFIG.1) in a computing network (e.g., computing network400inFIG.4). In some examples, section detection may be determined utilizing position-based criteria in lieu of DLS and inclination as described in the forgoing. For example, sections may be identified by comparing the true vertical depth (“TVD”) of the drill bit122(e.g., referring toFIG.1) with the predetermined wellplan where various TVD ranges are associated with different wellbore sections. In some examples, the section detection algorithm may be run separately for inclination and azimuth which may allow for build sections to be determined independently of turn sections. In such examples, changes in inclination may affect the build rate which may further be associated with a build section. Likewise, changes in azimuth may affect the turn rate which may be further associated with a turn section.

In block504, the section detection algorithm may be utilized to detect the current section based on the inputs of block502. In some examples, this may be referred to as a section detection algorithm. In further examples, the section detection algorithm may be utilized to detect the current section in real-time during drilling operations. The current section may refer to the section in which the drill bit122(e.g., referring toFIG.1) may be located. In some examples, a target may be selected in block506according to the identified section from block504. In some examples, the selected target may be a physical location in 3-dimensional space to which drill bit122(e.g., referring toFIG.1) is intended to progress. For example, the end point location of a current section as detailed in a wellplan may be used as a target. In other examples, the target may be a location along a trajectory as detailed in a wellplan which falls within the current section. In additional examples, the target may be a location along a trajectory as detailed in a wellplan which is located in a subsequent section. The target may include a location, attitude, build rate, walk rate, curvature, or combinations thereof. In some examples, the target selected in block506may be a specified azimuth, inclination, or attitude which may further be selected in accordance with a geosteering objective. In some examples, a drilling objective may be selected in block506according to the identified section from block504. Utilizing drilling objectives may increase the performance of a system. For example, a drilling objective may be formulated to minimize tortuosity, borehole length, downlink commands, time spent drilling, final offset from the target, vibrations, and maximize ROP, and combinations thereof. Once a target is selected in block506, the constraints and/or operational parameters for the control algorithm may be established in block508such that they meet the objective identified in block506. For example, the constraints and/or operational parameters of block508may be used to direct and/or steer bottom hole assembly130(e.g., referring toFIG.1) towards the target identified in block506. In other examples, the operational parameters of block508may be used to formulate a control problem which describes objectives and/or dynamics according to functions of state and control variables. In further examples, constraints may be the lower and upper bounds on the state and control variables. The constraints may be used to establish the boundaries for the problem, however, once a solution for the problem is determined, the optimal state and control variables are obtained. The identified optimal state and control variables may thereafter be utilized to steer bottom hole assembly130(e.g., referring toFIG.1) or drill bit122(e.g., referring toFIG.1).

Control algorithms for automated drilling may utilize specified parameters to achieve desired performance. In some examples, control algorithms may be used interchangeably with control methods. In some examples, automated drilling may include the determination of operational parameters where at least a portion of the process is performed on information handling system131(e.g., referring toFIG.1) without the intervention of a human. In some examples, model-free control algorithms such as proportional-integral-derivative (“PID”) control algorithms may require gain tables which vary according to the required level of aggressiveness. In some examples, suitable control algorithms may include model-based controls, such as, but not limited to, linear-quadratic regulator (LQR), model predictive controller (MPC), linear-quadratic-Gaussian (LQG) control, adaptive control, sliding mode control, min-max control, and model-free control algorithms, such as, but not limited to proportional-integral-derivative (PID), fuzzy control, and combinations thereof. In some examples the required level of aggressiveness may vary according to the detected section and the specific scenario. For example, sections of a well that are intended to be relatively straight, and which may not include large changes in inclination or azimuth may utilize less aggressive gain tables. For sections which include more curvature, the control aggressiveness may depend on whether the drilling operation is ahead or behind the wellplan. For example, in some situations the bottom hole assembly of a drill string may not generate adequate build rates or curvature relative to the required wellplan. In such a case, the well that is generated may be considered to be “behind,” relative to the expectations as set forth in the wellplan. In such examples, the wellbore may not build curvature as quickly as required by the wellplan and more aggressive gain tables may be utilized. In other examples, sections of the well which may include large changes or variations in inclination or azimuth may have less aggressive gain tables if the wellbore is adequately achieving the required curvature build with respect to the wellplan. Additional control algorithms may utilize model-based methods, such as a linear-quadratic regulators (“LQR”), model predictive control (MPC), adaptive control, sliding control, minimum/maximum control, and combinations thereof. LQR may be a form of a feedback regulator where a dynamic system is operated at a minimum cost. LQR and MPC may be similar control methodologies, for example, utilizing LQR repeatedly with a receding horizon may be a form of MPC. Additionally, while MPC may use constraints, as discussed below, LQR does not utilize constraints. In some examples, MPC may utilize an objective-based cost function in conjunction with constraints for the system states. In some examples, the objective which, helps define the cost function and the constraints, may be a function of attitude (e.g., azimuth and inclination), curvature, and/or position. In some examples, the selection of the parameters for a given section may be automated. In further examples, the automated selection of parameters for a given section may be performed on information handling system131(e.g., referring toFIG.1) and may not require human intervention to perform parameter selection. As such, a human user may not be required to provide or otherwise input the parameters to continue drilling through a given section or to continue drilling while transitioning from one section to another. Rather, information handling system131(e.g., referring toFIG.1) may be used to determine the drilling commands and parameters used to drill through a given section or to drill through transitions from one section to another.

An example of using optimization-based control in adherence with the foregoing description may be defined in the form as detailed below. For a given control problem, the functions of f(x), gi(x), and hi(x) may need to be well defined.

minf⁢(x)subject⁢togi⁢(x)=ci⁢for⁢i=1,…,nhj⁢(x)≥dj⁢for⁢j=1,…,m(1)
where x is the problem variable which may comprise of attitude (i.e., inclination and azimuth), curvature, position, and/or control command (toolface and steering ratio). Additionally, f(x) is the objective function of the problem, which is formulized such that the minimization of this value would result in the optimal performance of the system. The objective function may be based on tortuosity, borehole length, limited change in downlink commands, time spent drilling, final offset from target, or a weighted combination thereof. The variable gi(x) may represent the equality constraints and it may be used to describe system model and/or waypoint or target constraints in terms of attitude, curvature and/or position where n is the number of equality constraints. Further, the variable hi(x) may represent the inequality constraints where m is the number of inequality constraints. Inequality constraints may be used to put upper and lower bounds on the attitude, curvature, tortuosity, and/or position.

For the wellplan, different objectives and constraints for the vertical section, curve section, and lateral sections (e.g., referring to block606) may be represented by different formulations of f, g, and h. The proposed method proposes to formulate these functions and solve the corresponding optimization problem best suitable for the given section, given as follows:

In some examples, the foregoing optimization problem may be used in accordance with a variety of combinations of scenarios and objectives. For example, some scenarios may include solving the optimization problem when the actual well trajectory is ahead of or behind the wellplan with respect to the achieved attitude or well position. In further examples, the drilling equipment and/or bottom hole assembly130(e.g., referring toFIG.1) may not achieve sufficient tool yield such that the actual well trajectory is behind the wellplan. In further examples, the tool yield may be tied to the build rate or the turn rate, and each of build rate and turn rate may be solved for separately. Build rate and turn rate will be further described below. While any of the foregoing may be solved for separately, they may additional be solved for in any combination.

Referring back toFIG.5, as noted above, the control algorithm then sets the control parameters for the current section and/or transition point in block508. In some examples, the control algorithm may automatically set the next target and adjust the control constraints on position, attitude, build rate, walk rate, curvature, or combinations thereof. Given the target and objective, and the constraints, the suitable control algorithm is selected and run to provide steering recommendations. In block510, the control algorithm may be run on information handling system131, which may produce steering commands in block512, which may be transmitted to bottom hole assembly130in block514. As each target is hit, workflow500may be performed continuously.

TheFIGS.7A-7Dmay depict some of the features of blocks508-512(e.g., referring toFIG.5) of workflow500. For example, in block508, inequality constraints such as an upper and/or a lower bound may be identified. The output of block508(e.g., referring toFIG.5) may be used to determine steering commands in block510which may either modify or maintain the trajectory of the well in order to intersect an intended target. In some examples the steering commands may be determined in order to achieve a specific build rate (“BR”), walk rate (“WR”), or attitude. As further described below,FIGS.7A-7Dare graphs that may depict how inequality constraints, such as upper and lower bound constraints, are used to bound a reference value, prospective result, or wellplan value. For example, when the drilled well is behind the wellplan, the boundaries may be larger which may allow for more aggressive control. In general, the requirement for more aggressive control may be associated with the utilization of larger boundaries. Likewise, the requirement for less aggressive controls may be associated with the utilization of more narrow boundaries. In some examples, the required level of control may be determined separately for the azimuth and the inclination. In other examples, the level of control for the azimuth and the inclination may be weighted in the cost function to achieve different objectives. For example, increasing the weighting of azimuthal control may provide more azimuthal control while decreasing the weighting of azimuthal control may provide less azimuthal control. In further examples the required level of control for the azimuth may create boundaries for the walk rate (“WR”) while the required level of control for the inclination may create boundaries for the build rate (“BR”). The level of aggressiveness in the controls may be associated with whether the drilled well path is ahead of or behind the wellplan. For example, the requirement for more aggressive control may be associated with scenarios where the drilled well path is behind the wellplan. Alternatively, the requirement for less aggressive control may be associated with scenarios where the drilled well path is on target with, or ahead of the wellplan. In some examples, it may be empirically identified that bottom hole assembly130(e.g., referring toFIG.1) may not be able to achieve the build rates required by the wellplan in a curved section. As such larger boundaries may be utilized to get the well path aligned with the wellplan. In other examples, the wellbore may deviate from the intended wellpath, or fall behind the wellplan in the vertical, tangent, or lateral sections which may require more aggressive control and larger boundaries. In some examples, utilizing less aggressive controls by providing more narrow boundaries may result in a smoother wellbore trajectory with less aggressive curvature.

FIG.7AandFIG.7Bmay both depict boundaries utilized for the build rate of a wellbore section.FIG.7Amay comprise a graph700which further depicts an upper bound for build rate702, a lower bound for build rate704, and a wellplan build rate706.FIG.7Bmay comprise a graph710, which further depicts an upper bound for build rate712, a lower bound for build rate714, and a wellplan build rate716. As depicted, the wellbore section may be a curved section, however in practice it could be any section. The build rate ranges forFIG.7Amay depict a narrower range of build rates than what is depicted inFIG.7B. For example, the difference between the upper bound for build rate702and the lower bound for build rate704in graph700may be less than the difference between the upper bound for build rate712and the lower bound for build rate714in graph710. As such, graph710ofFIG.7Bmay have a more aggressive control requirement than graph700ofFIG.7A.FIG.7CandFIG.7Dmay both depict boundaries utilized for the walk rate of a wellbore section.FIG.7Cmay comprise a graph720which further depicts an upper bound for walk rate722, a lower bound for walk rate724, and a wellplan walk rate726.FIG.7Bmay comprise a graph730, which further depicts an upper bound for walk rate732, a lower bound for walk rate734, and a wellplan walk rate736. The walk rate ranges forFIG.7Cmay depict a broader range of walk rates than what is depicted inFIG.7D. For example, the difference between the upper bound for build rate722and the lower bound for build rate724in graph720may be greater than the difference between the upper bound for build rate732and the lower bound for build rate734in graph730. As such,FIG.7Dmay have a less aggressive control requirement thanFIG.7C.

The proposed methods and systems are an improvement over prior technology in that the methods and systems described above provide automated detection of vertical section, tangent section, curved sections, or lateral sections of a wellbore in real-time. Additionally, methods are improvements over the current technology in that the methods use an information handling system rather than human intervention or input to determine and adjust parameters and objectives based on the current section. The information handling system may be further used to determine and adjust the parameters and objectives when transitioning between sections without requiring manual or human input. In current implementations, human intervention is required to select targets, objectives, and/or control algorithms and methodologies. For example, human intervention may be required when the drill bit and/or bottom hole assembly are transitioning from one section to another section. Automating these processes may allow for consistency in the drilling process among different wells.

The systems and methods may include any of the various features disclosed herein, including one or more of the following statements. The systems and methods may include any of the various features disclosed herein, including one or more of the following statements.

Statement 1: A method may comprise dividing a wellplan into one or more sections using a section detection algorithm, receiving a depth measurement of a drill bit or a bottom hole assembly located in a wellbore, utilizing the section detection algorithm and the depth measurement to identify a section of the wellplan from the one or more sections of the wellplan, and identifying a target based at least in part on the identified section. The method may further comprise determining one or more steering commands based at least in part on the target and a control algorithm and steering the bottom hole assembly to the target using the one or more steering commands.

Statement 2: The method of statement 1, further comprising identifying one or more constraints based at least in part on the identified section and determining the one or more steering commands based at least in part on the one or more constraints.

Statement 3: The method of any of the preceding statements, wherein the target is located within a same section of the wellplan from where the drill bit or the bottom hole assembly is located.

Statement 4: The method of any of the preceding statements, wherein the target is located within a different section of the wellplan from where the drill bit or the bottom hole assembly is located.

Statement 5: The method of any of the preceding statements, wherein identifying the section of the wellplan further comprises identifying at least one section selected from the group consisting of a vertical section, a tangent section, a curve section, and a lateral section.

Statement 6: The method of any of the preceding statements, wherein dividing the wellplan into one or more sections further comprises dividing the wellplan according to a vertical threshold, a lateral threshold, and a dog-leg severity threshold.

Statement 7: The method of statement 6, wherein the vertical threshold is about 0 degrees to about 3 degrees, the lateral threshold is about 80 degrees to about 95 degrees, and the dog-leg severity threshold is about 0 degrees per 100 feet to about 0.5 degrees per 100 feet.

Statement 8: The method of any of the preceding statements, wherein the target comprises at least one target selected from the group consisting of a location, an attitude, a curvature, a build rate, a walk rate, or a combination thereof.

Statement 9: The method of any of the preceding statements, wherein the control algorithm further comprises a model-based control or a model-free control.

Statement 10: The method of statement 9, wherein the model-based control comprises at least one model-based control selected from the group consisting of linear quadratic regulators, model predictive control, and combinations thereof.

Statement 11: The method of statement 9, wherein the model-free control is a proportional-integral-derivative.

Statement 12: A system may comprise a bottom hole assembly comprising at least one sensor configured to take at least one measurement and an information handling system. The information handling system may be configured to divide a wellplan into one or more sections based at least in part on a section detection algorithm and one or more thresholds, receive a depth measurement, wherein the depth measurement corresponds to a location of a drill bit or a bottom hole assembly, and utilize the section detection algorithm and the depth measurement to identify a section of the wellplan from the one or more sections of the wellplan. The information handling system may further be configured to identify a target based at least in part on the identified section of the wellplan, determine one or more steering commands based at least in part on the target and a control algorithm, and relay the one or more steering commands to the bottom hole assembly.

Statement 13: The system of statement 12, wherein the information handling system is further configured to identify one or more constraints based at least in part on the identified section and determine the one or more steering commands based at least in part on the one or more constraints.

Statement 14: The system of any of the preceding statements, 12-13, wherein the one or more sections of the wellplan include at least one section selected from the group consisting of a vertical section, a tangent section, a curve section, and a lateral section.

Statement 15: The system of any of the preceding statements, 12-14, wherein the one or more thresholds include at least one of a vertical threshold, a lateral threshold, and a dog-leg severity threshold, and wherein the vertical threshold is about 0 to about 3 degrees, the lateral threshold is about 80 degrees to about 95 degrees, and the dog-leg severity threshold is about 0 degrees per 100 feet to about 0.5 degrees per 100 feet.

Statement 16: The system of any of the preceding statements, 12-15, wherein the target comprises at least one target selected from the group consisting of a location, an attitude, a curvature, a build rate, a walk rate, or a combination thereof.

Statement 17: The system of any of the preceding statements, 12-16, wherein the control algorithm further comprises a model-based control algorithm.

Statement 18: The system of statement 17, wherein the model-based control algorithm comprises at least one model-based control algorithm selected from the group consisting of linear quadratic regulators, model predictive control, and combinations thereof.

Statement 19: The system of any of the preceding statements, 12-18, wherein the control algorithm is a model-free control algorithm.

Statement 20: The system of any of the preceding statements, 12-19, wherein the model-free control is a proportional-integral-derivative.

Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations may be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims. The preceding description provides various examples of the systems and methods of use disclosed herein which may contain different method steps and alternative combinations of components. It should be understood that, although individual examples may be discussed herein, the present disclosure covers all combinations of the disclosed examples, including, without limitation, the different component combinations, method step combinations, and properties of the system. It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.