Automatic control of trajectory of downhole drilling

Abstract

Methods and systems are provided for automatically controlling a drilling trajectory during directional drilling of a build portion or curve or bend of a wellbore.

Description

[0001] Cross-references to related applications

[0002] This disclosure claims priority to U.S. Provisional Application No. 63 / 497,824, filed April 24, 2023, entitled “AUTOMATED CONTROL OF TRAJECTORY OF DOWNHOLE DRILLING,” the entire contents of which are incorporated herein by reference. Technical Field

[0003] The disclosed embodiments generally relate to automated methods and systems for directional control during downhole directional drilling operations. Background Technology

[0004] Directional drilling is used to control the trajectory of a wellbore, causing it to deviate from the vertical direction. For example, directional drilling is commonly used to drill S-shaped wells, deviated wells, and horizontal wells. These wellbores include one or more construction sections or curves or bends, where the trajectory follows a generally curved path.

[0005] Directional drilling systems can employ Rotary Steering Systems (RSS) to control the trajectory of the wellbore being drilled. RSS uses a downhole steering mechanism controlled by the drilling operator. The operator sends commands to the downhole steering mechanism using surface equipment, and the mechanism responds to these commands to steer the drill in the desired direction. The steering mechanisms used in RSS generally fall into two main categories: "push-the-bit" or "point-the-bit." Push-the-bit steering mechanisms typically use pads on the outside of the tool, which press against the wellbore to cause a change in direction. Point-the-bit steering mechanisms change the direction of the bit relative to the rest of the tool by bending the spindle that passes through it. Point-the-bit steering mechanisms typically employ some form of non-rotating housing or reference housing to generate this deflection within the spindle.

[0006] In current drilling practices, the trajectory of the wellbore construction section is controlled by automated drilling methods. These methods use measurements of the target inclination and azimuth angles of the wellbore being drilled, as well as the inclination and azimuth angles of the actual trajectory of the wellbore, in the closed-loop control of the drilling system's RSS (Responsive System). The measurements of the inclination and azimuth angles of the actual wellbore trajectory can be derived from downhole sensors such as accelerometers, magnetometers, and gyroscopes.

[0007] In some cases, noise in the azimuth measurements used in the closed-loop control of the RSS during drilling of the construction section can be high, and this noise can affect performance. For example, skipping or unstable azimuth measurements used in such closed-loop control can lead to unstable tool faces (i.e., drilling direction) or unstable SR parameters (i.e., the time the steering mechanism will spend maintaining the desired tool face), which can result in lower drilling efficiency, a less smooth well path, and in some cases, cause drilling operations to perceive that the RSS closed-loop control is not working.

[0008] Furthermore, during the drilling of the build-up section, the closed-loop control of the RSS typically utilizes a large number of RSS downlinks, which transmit Gravity Tool Face (GTF) data representing the variable target orientation within the build-up section of the wellbore. GTF data indicates the angular deviation of the circumference of some components of the downhole tool relative to the high side (HS) of the tool collar (or borehole). These numerous GTF downlinks can limit the drilling rate and also contribute to human error. Summary of the Invention

[0009] In one embodiment, a method and system are provided for automatically controlling the trajectory of a build-up section, bend, or curve of a wellbore drilled by a drilling system employing a Rotary Rotary Steering System (RSS). The target inclination and target azimuth of the RSS are determined for the build-up section, bend, or curve during drilling. The target inclination and a measurement of the inclination of the wellbore being drilled are used in the closed-loop control of the RSS inclination. Simultaneously with the closed-loop inclination control, the target azimuth is used for the open-loop azimuth control of the RSS azimuth. The target inclination and target azimuth of the RSS can be determined from toolface parameters, such as parameters specifying the downlink to the RSS gravity toolface (GTF) or magnetic toolface (MTF).

[0010] In one embodiment, a method and system are provided for automatically controlling the trajectory of a construction section, bend, or curve of a wellbore drilled by a drilling system employing an RSS (Real-Side Controller). The RSS is configured to receive toolface parameters representing the MTF (Mean Factor Forecasting) for drilling the construction section, bend, or curve of the wellbore. The MTF parameters are used to determine the target inclination and target azimuth of the wellbore during drilling. The target inclination and target azimuth, together with measurements of the azimuth and inclination of the wellbore being drilled, are used for closed-loop control of the azimuth and inclination of the drilling system's RSS during drilling the construction section, bend, or curve of the wellbore.

[0011] In embodiments, the control pattern described herein can be repeated, wherein the toolface parameters are progressively adjusted over time during drilling. This progressive adjustment can represent a variable target orientation in the curve of the construction portion or bend in the wellbore, such that the trajectory of the drilling and the resulting wellbore follows or approximates a planned or otherwise desired bend path.

[0012] The disclosed embodiments can provide various technical advantages. For example, the disclosed embodiments provide real-time closed-loop control of the drilling tool face. Therefore, the disclosed method can improve drilling efficiency.

[0013] The present invention is provided to introduce some concepts that will be further described in the following specific embodiments. The present invention is not intended to identify key or essential features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter. Attached Figure Description

[0014] This disclosure is further described in the following detailed description by way of non-limiting examples and with reference to the various figures mentioned, wherein the same reference numerals denote similar parts in several views of the figures, and wherein:

[0015] Figure 1 An example drilling rig on which the disclosed embodiments can be utilized is depicted;

[0016] Figure 2 Depicting Figure 1 The lower BHA section of the drill string is shown.

[0017] Figure 3 A schematic diagram depicting the attitude and steering parameters in the global coordinate reference system is provided.

[0018] Figure 4 A schematic diagram of the gravity tool facet and the magnetic tool facet in the global reference frame is depicted;

[0019] Figure 5 This is a control block diagram for implementing the automatic control method according to the first aspect of this disclosure;

[0020] Figure 6 This is a control block diagram for implementing the automatic control method according to the second aspect of this disclosure;

[0021] Figure 7 This is a schematic diagram of a computer processing system. Detailed Implementation

[0022] The details shown herein are merely illustrative and are presented for the purpose of discussing embodiments of the subject matter disclosure in a way that is believed to be most useful and readily understood. In this regard, no attempt is made to show structural details in more detail than necessary for a basic understanding of the disclosure, and the description, taken in conjunction with the accompanying drawings, makes it apparent to those skilled in the art how the various forms of the disclosure will manifest in practice. Furthermore, the same reference numerals and names in the various drawings indicate the same elements.

[0023] Figure 1A drilling rig 10 suitable for use with various methods and system embodiments disclosed herein is depicted. A semi-submersible drilling platform 12 is positioned above an oil or gas formation (not shown) located below the seabed 16. A subsea guide 18 extends from the deck 20 of the platform 12 to the wellhead equipment 22. The platform may include a derrick and lifting equipment for raising and lowering the drill string 30, as shown, which extends into the borehole 40 and includes a bottom hole assembly (BHA) 50. The BHA 50 includes a drill bit 32, a steering tool 60 (also known as a directional drilling tool), and one or more downhole navigation sensors 70, such as a measurement-while-drilling sensor including a triaxial accelerometer and / or a triaxial magnetometer. The BHA 50 may also include substantially any other suitable downhole tool, such as a downhole drilling motor, a downhole telemetry system, a reaming tool, etc. The disclosed embodiments are not limited to such other tools.

[0024] It should be understood that the BHA can include virtually any suitable steering tool 60, for example, including rotary steerable tools. Various rotary steerable tool configurations are known in the art, including various steering mechanisms for controlling the drilling direction. For example, many existing rotary steerable tools include a substantially non-rotating housing that incorporates cutting blades that engage with the borehole wall. The engagement of the cutting blades with the borehole wall can be controlled to change the attitude of the drill bit during drilling, thereby pointing or pushing the drill bit in the desired direction during drilling. A rotary shaft deployed within the housing transmits rotational power and axial drilling pressure to the drill bit during drilling. Accelerometer and magnetometer assemblies can be deployed within the housing and therefore do not rotate or rotate slowly relative to the borehole wall.

[0025] In one embodiment, the BHA 50 may employ a rotary cocoa steering system, such as a PowerDrive rotary cocoa steering system available from the SLB, which rotates fully with the drill string (i.e., the housing rotates with the drill string). The PowerDriveXceed uses an internal steering mechanism that does not require contact with the borehole wall and allows the tool body to rotate fully with the drill string. The PowerDrive X5, X6, and PowerDrive Orbit rotary cocoa steering systems utilize mud-actuated blades (or pads) that contact the borehole wall. As the system rotates in the borehole, the extension of the blades (or pads) is rapidly and continuously adjusted. The PowerDrive Archer utilizes a lower steering section that connects to the upper section at an articulated swivel. The swivel is actively tilted via a piston to change the angle of the lower section relative to the upper section and maintain the desired drilling direction as the bottomhole drill assembly rotates in the borehole. The accelerometer and magnetometer assemblies may rotate with the drill string, or alternatively, be deployed in an internal rolling stabilization housing such that they remain substantially stationary (in the bias phase) or rotate slowly relative to the borehole (in the neutral phase). To drill to the desired curvature, the bias and neutral phases are alternated during drilling at a predetermined ratio (referred to as the steering ratio). Again, the disclosed embodiments are not limited to use with any particular steering tool configuration.

[0026] The downhole sensor 70 may comprise virtually any suitable sensor arrangement for performing downhole navigation measurements (drill hole inclination, drill hole azimuth, and / or tool face measurements). Such sensors may include, for example, accelerometers, magnetometers, gyroscopes, etc. Such sensor arrangements are well known in the art and will not be described in further detail. The disclosed embodiments are not limited to the use of any particular sensor embodiment or configuration. For example, methods for performing real-time drilling measurements of drill hole inclination and drill hole azimuth are disclosed in commonly assigned U.S. Patent Nos. US9273547B2 and US9982525B2. In the depicted embodiment, sensor 70 is shown deployed within steering tool 60. This depiction is merely for convenience, as sensor 70 may be deployed elsewhere in the BHA.

[0027] Those skilled in the art will understand that Figure 1 The deployment shown is merely an example. It will be further understood that the disclosed embodiments are not limited to those described above. Figure 1 The semi-submersible platform 12 shown is used in conjunction with this. The disclosed embodiments are equally applicable to any type of underground drilling operation, whether offshore or onshore.

[0028] Figure 2 The lower BHA section of the drill string 30 is depicted, which includes the drill bit 32 and the steering tool 60. (See above regarding...) Figure 1As described, the steering tool may include a navigation sensor 70, which includes a three-axis (triaxial) accelerometer and a magnetometer navigation sensor. Suitable accelerometers and magnetometers can be selected from virtually any suitable commercially available device known in the art. Figure 2 Also included are schematic diagrams of triaxial accelerometer and magnetometer sensor groups. Triaxial means that each sensor group comprises three mutually perpendicular sensors, with the accelerometers designated Ax, Ay, and Az, and the magnetometers designated Bx, By, and Bz. By convention, a right-handed system is specified, where the z-axis accelerometers and magnetometers (Az and Bz) are substantially parallel to the borehole orientation as indicated (although the disclosed embodiments are not limited to this convention). Therefore, each of the accelerometer and magnetometer groups can be considered to define a plane (x-axis and y-axis) and a pole (the z-axis along the axis of the BHA).

[0029] Figure 3 A diagram depicting the attitude of the BHA at upper survey station 82 and lower survey station 84 in the global coordinate reference system is shown. The attitude of the BHA defines the orientation of the BHA axes (axis 86 at upper survey station 82 and axis 88 at lower survey station 84) in three-dimensional space. In wellbore exploration applications, wellbore attitude represents the direction of the BHA axes in the global coordinate reference system (and is generally understood to be approximately equal to the direction of drill bit propagation). Attitude can be represented by a unit vector, the direction of which is typically defined by the borehole inclination and borehole azimuth. Figure 2 In the middle, the wellbore dip angles at upper exploration station 82 and lower exploration station 84 are determined by Inc. up and Inc low This indicates that the wellbore azimuth is determined by Azi. up and Azi low The angle β represents the overall angular change of the borehole between the first and second measuring stations 82 and 84.

[0030] Figure 4 Another schematic diagram depicts the attitude and tool face in the global coordinate reference system at point 84 of the second lower survey station. The Earth's magnetic and gravitational fields are depicted at points 91 and 92. Drilling inclination Inc. low This indicates the deviation of axis 88 from the vertical direction, while the drilling azimuth angle Azi... lowThis represents the deviation of the projection of axis 88 onto the horizontal plane from magnetic north. Gravity tool facet (GTF) is the angular deviation of the circumference of some component of a downhole tool relative to the high side (HS) of the tool collar (or borehole). In this disclosure, gravity tool facet (GTF) represents the angular deviation between the direction of the drill bit's azimuth and the high side direction (e.g., in slippery drilling operations, gravity tool facet represents the angular deviation between the curved scribe line and the high side direction). Magnetic tool facet (MTF) is similar to GTF, but uses magnetic north as the reference direction. Specifically, MTF is the angular deviation of the drill bit's azimuth in the horizontal plane from magnetic north.

[0031] It should be understood that the disclosed embodiments are not limited to those intended to limit the scope of the invention. Figure 2 , Figure 3 and Figure 4 The above-described conventions for borehole coordinates are described herein. It will be further understood that these conventions can affect the form of certain mathematical equations followed in this disclosure. Those skilled in the art will be able to readily utilize other conventions and derive equivalent mathematical equations.

[0032] In current drilling practice, the trajectory of the constructed sections, curves, or bends of the wellbore is controlled by an automated drilling method. This method uses measurements of the target inclination and azimuth of the wellbore being drilled, as well as the inclination and azimuth of the actual trajectory of the wellbore, in the closed-loop control of the drilling system's RSS (Real-Side System). The target inclination and azimuth are determined by a downlink-to-RSS programmed GTF (Getting To-Factory). The measurements of the inclination and azimuth of the actual trajectory of the wellbore are derived from sensor data obtained from downhole sensors such as accelerometers, magnetometers, and gyroscopes.

[0033] In some instances, noise in the azimuth measurements used in the closed-loop control of the RSS can be high when drilling through sections, curves, or bends, and this noise can impact performance. For example, skipping or unstable azimuth measurements used in such closed-loop control can result in an unstable tool face (i.e., drilling direction) or unstable SR parameters (i.e., the time the RSS will spend maintaining the desired tool face), which can lead to lower drilling efficiency, a less smooth well path, and in some cases, cause drilling operations to perceive that the RSS's closed-loop control is not working.

[0034] In a first aspect of this disclosure, an improved control mode or process is provided for automatically controlling the drilling trajectory during directional drilling. This control mode is referred to herein as "AutoCurve_IC". In embodiments, the AutoCurve_IC control mode can be activated (either manually activated by instructions from the drilling operator or automatically activated by instructions from a processor or other programmable controller) when directional drilling is drilling a portion of the wellbore or a curve or bend.

[0035] In this embodiment, the AutoCurve_IC control mode can be configured to use the target inclination angle of the wellbore being drilled and the measured inclination angle of the wellbore being drilled for closed-loop control of the inclination angle of the drilling system's RSS, while simultaneously performing open-loop control of the azimuth angle of the drilling system's RSS. In the open-loop control of the drilling system's RSS azimuth angle, the AutoCurve_IC control mode can be configured to set the azimuth angle of the drilling system's RSS based on the target azimuth angle, but will not dynamically adjust the azimuth angle of the drilling system's RSS based on measurements of the azimuth angle of the actual trajectory of the wellbore being drilled. The target inclination angle and target azimuth angle can be determined from the downlink toolface to the RSS (e.g., GTF or MTF toolface). The measured inclination angle of the actual trajectory of the wellbore during drilling can be derived from sensor data obtained from downhole sensors (e.g., accelerometers, magnetometers, and gyroscopes).

[0036] In this embodiment, the AutoCurve_IC control mode can be configured as a preset when the RSS is programmed for use in the wellbore. It can also be configured to be turned on and off via commands transmitted to the RSS (e.g., commands from an MPDL map). This configuration can be triggered or invoked if the drilling operation temporarily experiences unstable azimuth measurements, such as entering a mixed zone when drilling north or south.

[0037] In an embodiment, the AutoCurve_IC control mode can be configured to be automatically triggered or invoked based on an assessment of predetermined conditions, such as changes in magnetometer and tilt values ​​falling within a set range, or changes in continuous tilt and azimuth values ​​exceeding a set limit, without surface intervention.

[0038] In other embodiments, the AutoCurve_IC control mode can be configured to be automatically triggered or invoked when azimuth fluctuations are detected or when a period of time is detected, or before the lateral portion of the landing wellbore and / or the borehole.

[0039] Figure 5A control block diagram of the AutoCurve_IC control mode is shown. The inputs to the first block 501 include tool face parameters (such as parameters specifying the GTF or MTF used for drilling operations) and optionally, SR parameters specifying the time the RSS will spend maintaining the desired tool face. The outputs of block 501 are the desired target inclination and target azimuth. The target azimuth is provided to the steering control system (block 503A), which performs open-loop control of the RSS azimuth based on the target azimuth. In an embodiment, the open-loop control of block 503A can be configured to set the RSS azimuth based on the target azimuth, but not to dynamically adjust the drilling system's RSS azimuth based on measurements of the azimuth of the actual trajectory of the wellbore being drilled. The target inclination is provided to the steering control system (block 503B), which performs closed-loop control of the RSS inclination based on the target inclination. In an embodiment, the closed-loop control of block 503B can be configured to control the drilling direction using a target inclination angle determined from sensor data during drilling and a measured toolface inclination angle, such that the measured toolface inclination angle tracks the target inclination angle. The target inclination angle and target azimuth angle can be determined from the toolface downlink to the RSS. The measured azimuth and inclination angles of the actual wellbore trajectory during drilling can be derived from sensor data obtained from downhole sensors (e.g., accelerometers, magnetometers, and gyroscopes).

[0040] In an embodiment, the AutoCurve_IC control mode can be repeated to progressively adjust tool face parameters (e.g., parameters specifying GTF or MTF) over time during drilling. This progressive adjustment can represent a variable target orientation in the build-up portion or curvature of the wellbore, such that the drilling and resulting wellbore trajectory follows or approximates a planned or otherwise desired curvature path.

[0041] In a second aspect of this disclosure, another improved control mode or process is provided for automatically controlling the drilling trajectory during directional drilling. This control mode is referred to herein as "AutoCurve_MTF". In an embodiment, the AutoCurve_MTF control mode can be activated (either manually activated by instructions from the drilling operator or automatically activated by instructions from a processor or other programmable controller) when directional drilling is drilling a construction portion, curve, or bend in the wellbore.

[0042] In this embodiment, the AutoCurve_MTF control mode can be configured to receive toolface parameters representing the MTF (Mean Transmission Factor) for the construction portion, curve, or bend of the wellbore. The MTF parameters are used to determine the target inclination and target azimuth of the wellbore during drilling. The target inclination and target azimuth, along with measurements of the azimuth and inclination of the wellbore being drilled, are used in closed-loop control of the azimuth and inclination of the drilling system's RSS (Responding Sag). In closed-loop control, the AutoCurve_MTF control mode can be configured to dynamically adjust the azimuth and inclination of the drilling system's RSS based on measurements of the azimuth and inclination of the actual trajectory of the wellbore being drilled. The target inclination and target azimuth can be determined from the downlink MTF toolface to the RSS. Measurements of the azimuth and inclination of the actual trajectory of the wellbore during drilling can be derived from sensor data obtained from downhole sensors such as accelerometers, magnetometers, and gyroscopes.

[0043] In this embodiment, the AutoCurve_MTF control mode can be configured as a preset when the RSS is programmed for use in the wellbore. It can also be configured to be turned on and off via commands sent to the RSS (e.g., commands from an MPDL map).

[0044] In an embodiment, the AutoCurve_MTF control mode can be configured to be automatically triggered or invoked based on predetermined conditions without surface intervention.

[0045] Note that the MTF toolface is currently used in manual mode to build the well, and when there is an angle in the well, such as approximately five (5) degrees of inclination. Drilling operations are typically downlinked to GTF mode to build the remainder of sections or curves or bends.

[0046] The AutoCurve_MTF control mode is advantageous for drilling out sections of the wellbore, such as curves or bends, because it allows for drilling out bends with fewer downlinks. This can increase the drilling rate, reduce human error, and lower the drilling cost of the wellbore.

[0047] Figure 6A control block diagram of the AutoCurve_MTF control mode is shown. The inputs to the first block 601 include MTF toolface parameters (i.e., parameters specifying the MTF used for drilling operations) and optionally SR parameters specifying the time the RSS will spend holding the desired toolface. The outputs of block 601 are the desired target inclination and target azimuth. The target inclination and target azimuth are provided to the steering control system (block 603), which performs closed-loop control of the RSS's inclination and azimuth based on the target inclination and target azimuth. In an embodiment, the closed-loop control of block 603 can be configured to dynamically adjust the azimuth and inclination of the drilling system's RSS to control the drilling direction, such that the measured inclination and measured azimuth derived from sensor data track the target azimuth and target inclination. The target inclination and target azimuth can be determined from the MTF toolface downlink to the RSS. The azimuth and dip angles of the actual trajectory of the wellbore during drilling can be derived from sensor data obtained by downhole sensors such as accelerometers, magnetometers, and gyroscopes.

[0048] In an embodiment, the AutoCurve_MTF control mode can be repeated, in which the MTF toolface parameters are gradually adjusted over time during drilling. This gradual adjustment can represent a variable target orientation in the build-up portion or curvature of the wellbore, such that the trajectory of the drilling and the resulting wellbore follows or approximates a planned or otherwise desired curvature path.

[0049] The embodiments described herein are configured for downhole implementation via one or more controllers deployed downhole (e.g., in a directional drilling tool). Suitable controllers may include, for example, programmable processors, such as microprocessors or microcontrollers, and processor-readable or computer-readable program code embodying logic. For example, a suitable processor may be used to execute the method embodiments described above. Suitable controllers may also optionally include other controllable components, such as sensors (e.g., depth sensors), data storage devices, power supplies, timers, etc. The controller may also be configured to communicate electronically with attitude sensors (e.g., to receive continuous dip and azimuth measurements). Suitable controllers may also optionally communicate with other instruments in the drill string, such as telemetry systems communicating with the surface. Suitable controllers may further optionally include volatile or non-volatile memory or data storage devices.

[0050] The disclosed embodiments may also include a downhole steering tool having a downhole steering tool body, a steering mechanism for controlling the direction of drilling a subsurface wellbore, and sensors for measuring the wellbore's attitude (i.e., dip and azimuth) during drilling. The steering tool may also include a downhole controller comprising one or more modules embodying a cascaded closed-loop system that processes parameter data and attitude measurements received from the sensors to control the drilling direction as described herein.

[0051] Figure 7 An example device 2500 with a processor 2502 and a memory 2504 is shown, which can be configured to implement various embodiments of the processes and systems discussed herein. For example, various steps or operations of the processes or systems described herein can be embodied by computer program instructions (software) that execute on the device 2500. The memory 2504 may also host one or more databases and may include one or more forms of volatile data storage media (such as random access memory (RAM)) and / or one or more forms of non-volatile storage media (such as read-only memory (ROM), flash memory, etc.).

[0052] Device 2500 is an example of a computing device or a programmable device, and is not intended to impose any limitations on the scope of use or functionality of device 2500 and / or its possible architecture. For example, device 2500 may include one or more computing devices, programmable logic controllers (PLCs), etc.

[0053] Furthermore, device 2500 should not be construed as having any dependency on one or more of the components shown in device 2500. For example, device 2500 may include one or more computers, such as laptop computers, desktop computers, mainframe computers, etc., or any combination or accumulation thereof.

[0054] Device 2500 may also include bus 2508, which is configured to allow various components and devices, such as processor 2502, memory 2504 and local data storage device 2510, and other components, to communicate with each other.

[0055] Bus 2508 may include any one or more of several types of bus architectures, including memory bus or memory controller, peripheral bus, accelerated graphics port, and processor or local bus using any of the various bus architectures. Bus 2508 may also include wired and / or wireless buses.

[0056] Local data storage device 2510 may include fixed media (e.g., RAM, ROM, fixed hard disk drive, etc.) and removable media (e.g., flash drive, removable hard disk drive, optical disk, magnetic disk, etc.). One or more input / output (I / O) devices 2512 may also communicate via user interface (UI) controller 2514, which may be connected to the I / O devices 2512 directly or via bus 2508.

[0057] In one possible embodiment, network interface 2516 can communicate externally to device 2500 via a connected network. Media drive / interface 2518 can accept removable physical media 2520, such as flash drives, optical discs, removable hard disk drives, software products, etc. In one possible embodiment, logic, computational instructions, and / or software programs including elements of module 2506 can reside on removable media 2520 readable by media drive / interface 2518.

[0058] In one possible embodiment, input / output device 2512 may allow a user (such as a human annotator) to input commands and information into device 2500, and may also allow information to be presented to the user and / or other components or devices. Examples of one or more input devices 2512 include, for example, sensors, keyboards, cursor control devices (e.g., mice), microphones, scanners, and any other input devices known in the art. Examples of output devices include display devices (e.g., monitors or projectors), speakers, printers, network interface cards, etc.

[0059] This document describes various processes and systems of the present disclosure in the general context of software or program modules, or it may describe techniques and modules implemented in pure computing hardware. Software typically includes routines, programs, objects, components, data structures, etc., that perform specific tasks or implement specific abstract data types. Implementations of these modules and techniques may be stored on or transmitted through some form of tangible computer-readable medium. A computer-readable medium can be any available data storage medium that is tangible and accessible by a computing device. Therefore, a computer-readable medium can include a computer storage medium. "Computer storage medium" means tangible medium and includes volatile and non-volatile, removable and non-removable tangible media implemented for storing information such as computer-readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technologies, CD-ROM, Digital Universal Disc (DVD) or other optical storage, magnetic tape cassettes, magnetic tape, disk storage or other magnetic storage devices, or any other tangible medium that can be used to store desired information and is accessible by a computer.

[0060] Some of the methods and processes described above can be executed by a processor. The term "processor" should not be construed as limiting the embodiments disclosed herein to any particular type of device or system. A processor may include a computer system. A computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, general-purpose computer, special-purpose machine, virtual machine, software container, or device) for performing any of the methods and processes described above.

[0061] Computer systems may also include memory, such as semiconductor memory devices (e.g., RAM, ROM, PROM, EEPROM, or flash programmable RAM), magnetic memory devices (e.g., magnetic disks or fixed disks), optical memory devices (e.g., CD-ROMs), PC cards (e.g., PCMCIA cards), or other memory devices.

[0062] Alternatively or additionally, the processor may include discrete electronic components coupled to a printed circuit board, an integrated circuit (e.g., an application-specific integrated circuit (ASIC)), and / or a programmable logic device (e.g., a field-programmable gate array (FPGA)). Any of the methods and processes described above can be implemented using such logic devices.

[0063] Some of the methods and processes described above can be implemented as computer program logic for use with a computer processor. This computer program logic can be embodied in various forms, including source code or computer-executable form. Source code can include a series of computer program instructions in various programming languages ​​(e.g., object code, assembly language, or high-level languages ​​such as C, C++, or JAVA). Such computer instructions can be stored in a non-transitory computer-readable medium (e.g., memory) and executed by a computer processor. The computer instructions can be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink-wrapping software), pre-loaded onto a computer system (e.g., on a system ROM or hard disk), or distributed from a server via a communication network (e.g., the Internet).

[0064] Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily understand that many modifications can be made to the exemplary embodiments without substantially departing from the invention. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined by the following claims. In the claims, the device plus function clause is intended to cover structures described herein as performing said functions, and includes not only structural equivalents but also equivalent structures. Thus, although nails and screws may not be structural equivalents because nails have a cylindrical surface for securing wooden parts together, while screws have a helical surface, nails and screws can be equivalent structures in the context of fastening wooden parts. The applicant expressly disclaims any limitation imposed on any of the claims herein by invoking 35 USC §112, paragraph 6, unless the term “means for…” and the associated function are expressly used in the claims.

Claims

1. A method for automatically closed-loop control of a drilling trajectory during directional drilling performed by a drilling system employing a rotary steerable system (RSS), the method comprising: When constructing sections, bends, or curves in the wellbore, determine the target dip angle and target azimuth angle of the RSS; When drilling the construction section, bend, or curve of the wellbore, the measured values ​​of the target inclination angle and the inclination angle of the wellbore being drilled are used in the closed-loop control of the inclination angle of the RSS. and While performing closed-loop control on the inclination angle of the RSS, when drilling the construction part, bend, or curve of the wellbore, the target azimuth angle is used to perform open-loop control on the azimuth angle of the RSS.

2. The method according to claim 1, wherein: When drilling the construction section, bend, or curve of the wellbore, the open-loop control of the RSS azimuth angle does not dynamically adjust the RSS azimuth angle based on the measured azimuth angle of the actual trajectory of the wellbore being drilled.

3. The method according to claim 1, wherein: The target dip angle and target azimuth angle are determined from downlink or received toolface parameters when drilling the construction section, bend, or curve of the wellbore.

4. The method according to claim 3, wherein: The toolface parameters specify the gravity toolface (GTF) used for drilling the construction portion, bend, or curve of the wellbore, or The tool face parameter specifies the magnetic tool face (MTF) used for drilling the construction portion, bend, or curve of the wellbore.

5. The method according to claim 3, further comprising: The operation of the method is repeated, wherein the tool face parameters are gradually adjusted over time during the drilling process, wherein the gradual adjustment represents a variable target orientation in the construction portion or curvature of the wellbore, such that the drilling trajectory and the resulting wellbore follow or approximate a planned or otherwise desired curvature path.

6. A control system for automatically controlling a drilling trajectory during directional drilling performed by a drilling system employing a rotary steerable system (RSS), the control system comprising: At least one module, the at least one module being configured to perform the method according to claim 1, to control the RSS during the construction of a section or curvature in the wellbore.

7. The control system according to claim 6, wherein: The at least one module is embodied by a downhole processor or controller.

8. A directional drilling system, comprising: A bottom hole drilling assembly, the bottom hole drilling assembly including a rotary steerable system (RSS) and a drill bit; and At least one module, the at least one module being configured to perform the method according to claim 1, to control the RSS during the construction of a section or curvature in the wellbore.

9. The directional drilling system according to claim 8, wherein: The at least one module is embodied by a downhole processor or controller.

10. A method for automatically closed-loop control of a drilling trajectory during directional drilling performed by a drilling system employing a rotary steerable system (RSS), the method comprising: Receive tool face parameters representing the magnetic tool face (MTF) used for the construction portion, curve, or bend of the wellbore; The toolface parameters representing the MTF are used to determine the target dip and target azimuth of the wellbore when drilling the construction section, curve, or bend of the wellbore; and When drilling the construction section, bend, or curve of the wellbore, the target inclination angle and the target azimuth angle, as well as the measured values ​​of the azimuth and inclination angle of the wellbore being drilled, are used in the closed-loop control of the azimuth and inclination angle of the RSS.

11. The method of claim 10, wherein: Closed-loop control of the azimuth and inclination of the RSS during the construction, bend, or curve of the wellbore is achieved by dynamically adjusting the azimuth and inclination of the RSS based on the corresponding measurements of the actual trajectory of the wellbore being drilled.

12. The method according to claim 10, wherein: The tool face parameters representing the MTF are received or downlinked when drilling the construction section, bend, or curve of the wellbore.

13. The method of claim 10, further comprising: The operation of the method is repeated, wherein during the drilling, the tool face parameters representing the MTF change over time are progressively adjusted, wherein the progressive adjustment represents a variable target orientation in the construction portion or curvature of the wellbore, such that the trajectory of the drilling and the resulting wellbore follows or approximates a planned or otherwise desired curvature path.

14. A control system for automatically controlling a drilling trajectory during directional drilling performed by a drilling system employing a rotary steerable system (RSS), the control system comprising: At least one module, the at least one module being configured to perform the method of claim 10 to control the RSS during the construction of a section or curvature in the wellbore.

15. The control system according to claim 14, wherein: The at least one module is embodied by a downhole processor or controller.

16. A directional drilling system, comprising: A bottom hole drilling assembly, the bottom hole drilling assembly including a rotary steerable system (RSS) and a drill bit; and At least one module, the at least one module being configured to perform the method of claim 10 to control the RSS during the construction of a section or curvature in the wellbore.

17. The directional drilling system according to claim 16, wherein: The at least one module is embodied by a downhole processor or controller.

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