Automatic control of trajectory of downhole drilling

Abstract

Methods and systems are provided for automatic closed-loop control of a drilling trajectory during directional drilling that automatically adjusts at least one parameter during directional drilling to automatically control drilling direction when drilling a whipstock that transitions the wellbore from a vertical portion to a curvilinear or tangential portion. In an embodiment, closed-loop control may be configured to automatically adjust a steering ratio (SR) parameter that controls the time the steering tool will spend on holding a desired magnetic tool face.

Description

[0001] Cross-references to related applications

[0002] This disclosure claims priority to U.S. Provisional Application No. 63 / 497,831, 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 methods and systems for directional control during downhole directional drilling operations. Background Technology

[0004] The use of directional drilling methods is becoming increasingly common in drilling subsurface wells. One challenge of directional drilling methods is their tendency to drill in directions deviating from the set point. These tendencies can be influenced by a number of factors and can change unexpectedly during drilling operations. Factors that can affect this directional tendency can include, for example, the nature of the subsurface formation, the configuration of the bottom hole assembly (BHA), bit wear, bit / stabilizer travel, unplanned contact points (e.g., due to BHA compression and buckling), stabilizer-formation interactions, the steering mechanism used by the drilling tools, and various drilling parameters.

[0005] Steering mechanisms used in directional drilling methods have a tool face, which is part of a deflection tool or a steerable motor system. This tool face is oriented in a specific direction to produce the desired deflection during drilling. In current directional drilling methods, a magnetic tool face is used to represent the tool face orientation when the wellbore being drilled has an inclination angle less than a predetermined threshold (e.g., less than 8°), and a gravity tool face is used to represent the tool face orientation when the wellbore being drilled has an inclination angle greater than the predetermined threshold (e.g., greater than 8°). The magnetic tool face is the tool face orientation, measured as the angle between the tool reference axis and magnetic north in the horizontal plane. The gravity tool face is the tool face orientation, measured as the angle between the tool reference axis and gravity in the vertical plane.

[0006] Directional drilling methods typically transition from the vertical portion of the wellbore to the curved or tangential portion. This transition is often referred to as kickoff. In current directional drilling methods, kickoff is usually achieved manually by the driller using a downlink magnetic toolface and steering ratio (SR) parameters. The magnetic toolface represents the drilling direction, and the SR parameters indicate the time the steering mechanism will spend maintaining the desired magnetic toolface and then drilling forward; these parameters are adjusted as needed. Once there is no magnetic interference, the driller manually switches from using a magnetic toolface to using a gravity toolface and continues drilling with the gravity toolface and SR parameters as needed. Sometimes, this manual transition from a magnetic toolface to a gravity toolface can lead to anomalies in dip and azimuth smoothness, as well as inconsistent wellbore dogleg severity during kickoff. Summary of the Invention

[0007] This summary is provided to introduce some concepts that will be further described in the following detailed description. This summary is not intended to identify key features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter.

[0008] A method and system are provided for automatic closed-loop control of the drilling trajectory during directional drilling, which automatically adjusts at least one parameter during directional drilling to automatically control the drilling direction when drilling out a build-up section that transitions the wellbore from a vertical section to a curved or tangential section.

[0009] In this embodiment, closed-loop control can be configured to automatically adjust the steering ratio (SR) parameter, which controls the time the steering tool will spend maintaining the desired magnetic tool face. The SR parameter determines the dogleg severity (DLS) of the tool response during drilling.

[0010] In an embodiment, closed-loop control can be configured to be based on a target dogleg severity (target_DLS) and an estimated dogleg severity calculated from the tool response ( The steering ratio (SR) parameter is automatically adjusted based on the difference or error between the parameters.

[0011] In an embodiment, closed-loop control can be configured to be based on a target build rate parameter (target_BR) and an estimated build rate parameter calculated from the tool response ( The difference or error between the two parameters is used to adjust the steering ratio (SR) parameter.

[0012] In an embodiment, closed-loop control may be configured to adjust the steering ratio (SR) parameter based on at least one of the following: i) the difference or error between the target tilt angle and the measured tilt angle of the steering tool, and ii) the difference or error between the target build rate calculated from the measured tilt angle of the steering tool and the current build rate.

[0013] In one embodiment, the steering ratio (SR) parameter can be adjusted based on multiple inputs selected from a group including desired magnetic toolface, target dogleg severity, target build rate, drilling rate (ROP), and drilling status parameters. In another embodiment, at least one of the inputs can be provided by a user or from a machine downlink that monitors and automatically sends the inputs.

[0014] In an embodiment, closed-loop control can be configured to terminate the automatic adjustment of the steering ratio (SR) parameter or switch to another control mode when the tilt angle of the steering tool exceeds a predetermined threshold.

[0015] In an embodiment, the closed-loop control may be further configured to automatically adjust the magnetic tool face of the steering tool if the magnitude of the difference between the desired magnetic tool face and the azimuth angle of the steering tool exceeds a predetermined threshold at a predetermined tilt angle of the steering tool.

[0016] In an embodiment, the adjustment of the steering ratio (SR) parameter can be based on the ramp or nudge of multiple magnetic tool faces at estimated or traversed measurement depths during drilling.

[0017] In an embodiment, the adjustment of at least one parameter can be manually activated by instructions from the drilling operator, or automatically activated by instructions from the processor or other programmable controller during directional drilling.

[0018] In an embodiment, the adjustment of at least one parameter can be performed by a downhole processor or controller.

[0019] The disclosed embodiments offer various technical advantages. For example, the disclosed embodiments provide real-time closed-loop control of the drilling tool face. Therefore, the disclosed method can provide improved well layout and reduced wellbore curvature. Furthermore, by providing closed-loop control, the disclosed method tends to improve drilling efficiency and consistency.

[0020] This summary is provided to introduce some concepts that will be further described in the following detailed description. This summary 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

[0021] 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:

[0022] Figure 1 An example drilling rig on which the disclosed embodiments can be utilized is depicted;

[0023] Figure 2 Depicting Figure 1 The lower BHA section of the drill string is shown.

[0024] Figure 3 A schematic diagram depicting the attitude and steering parameters in the global coordinate reference system is provided.

[0025] Figure 4 A schematic diagram of the gravity tool facet and the magnetic tool facet in the global reference frame is depicted;

[0026] Figure 5 The block diagram of the closed-loop control algorithm disclosed herein is used to implement an automatic control method for drilling directional drilling in a wellbore.

[0027] Figure 6 This is a schematic diagram illustrating the inputs and outputs of the automatic control method of this disclosure;

[0028] Figure 7A and Figure 7B The flowchart below illustrates the control algorithm for an automatic control method for drilling a wellbore, based on this disclosure.

[0029] Figure 8 This is a schematic diagram of a proportional-integral (PI) controller according to the present disclosure, which is configured to process MTF targets to control drilling during wellbore build-up; and

[0030] Figure 9 This is a schematic diagram of a computer processing system. Detailed Implementation

[0031] 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.

[0032] 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.

[0033] It should be understood that the BHA can include virtually any suitable steering tool 60, such as a deflector or a rotary steering system. Various rotary steering tool configurations are known in the art, including various steering mechanisms for controlling the drilling direction.

[0034] For example, in one embodiment, the BHA 50 may include a deflector tool comprising a substantially non-rotating housing with blades engaging the wellbore wall. The engagement of the blades with the wellbore wall can be controlled to change the drill bit's attitude during drilling, thereby pointing or pushing the drill bit in a desired direction during drilling. A rotary shaft deployed within the housing transmits rotational power and axial drilling pressure to the drill bit during drilling. An accelerometer assembly and a magnetometer assembly may be deployed within the housing and therefore do not rotate or rotate slowly relative to the wellbore wall.

[0035] In another embodiment, the BHA 50 may include a rotary steerable system, such as the PowerDrive rotary steerable system available from 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 wellbore wall and allows the tool body to rotate fully with the drill string. The PowerDrive X5, X6, and POWERDRIVE ORBIT® rotary steerable systems utilize mud-actuated blades (or pads) that contact the wellbore wall. As the system rotates in the wellbore, the extension of the blades (or pads) is rapidly and continuously adjusted. The POWERDRIVE ARCHER® utilizes a lower steering section that engages with 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 wellbore. The accelerometer and magnetometer assemblies can rotate with the drill string, or alternatively, they can be deployed in an internally roll-stabilized housing such that they remain substantially stationary (in the bias phase) or rotate slowly relative to the wellbore (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.

[0036] The downhole sensor 70 may comprise virtually any suitable sensor arrangement for performing downhole navigation measurements (wellbore inclination, wellbore azimuth, and / or toolface 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 wellbore inclination and wellbore 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.

[0037] 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.

[0038] 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 1 As 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 wellbore 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).

[0039] Figure 3 A diagram depicting the attitude of the first and second upper and lower exploration stations 82 and 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 exploration station 82 and axis 88 at lower exploration 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 wellbore dip angle and the wellbore azimuth angle. 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 wellbore between the first and second measuring stations 82 and 84.

[0040] Figure 4 Another schematic diagram depicts the attitude and tool face in the global coordinate reference system at point 84 of the second lower exploration station. The Earth's magnetic and gravitational fields are depicted at points 91 and 92. Borehole dip angle Inc. low This represents the deviation of axis 88 from the vertical direction, while the wellbore 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 wellbore). In this disclosure, gravity tool facet (GTF) represents the angular deviation between the direction of the drill bit's directional movement 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 directional movement in the horizontal plane from magnetic north.

[0041] 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.

[0042] In current practice, directional drilling methods employ manual operation to achieve the build-up transition from the vertical portion of the wellbore to the curved or tangential portion. This manual operation can lead to anomalies in dip and azimuth smoothness, as well as inconsistent dogleg severity during build-up.

[0043] This disclosure describes a control mode or process for automatically closed-loop control of the drilling trajectory during directional drilling. This control mode is referred to herein as "automatic directional drilling." The automatic directional drilling control mode can be configured to automatically control the drilling direction during directional drilling, which transitions the wellbore from a vertical section to a curved or tangential section.

[0044] In the embodiment, the automatic tilting control mode can be achieved through, for example... Figure 5 The closed-loop control algorithm shown is used to implement this. Controller block 501 is configured to base its algorithm on the target dogleg severity (target_DLS) and the estimated dogleg severity calculated from the tool response. The difference or error between the target build rate parameter (target_BR) and the estimated build rate parameter calculated from the tool response will automatically adjust the steering ratio (SR) parameter. Dogleg severity is a measure of the variation in wellbore orientation over a defined length, typically measured in degrees per 100 feet. The SR parameter controls the time the steering tool (box 503) will spend maintaining the desired magnetic tool face (labeled "MTF"). Alternatively, controller box 501 can be configured to base the target build rate parameter (target_BR) on the estimated build rate parameter (target_BR) calculated from the tool response. The difference or error between the parameters automatically adjusts the steering ratio (SR) parameter. The build-up rate is a measure of the rate of change of dip angle relative to the depth in the wellbore.

[0045] In this embodiment, the inputs to the control algorithm include the desired magnetic toolface (i.e., the target azimuth, denoted as "MTF"), the target dogleg severity (target_DLS) (or the target build rate (target_BR)), the rate of drilling (ROP), and drilling status parameters. The inputs can be provided by a user (e.g., a user with a supervisory role) or from a machine downlink to controller block 501 and / or steering tool 503, which is supervised and automatically sends the inputs. Depending on the telemetry rate, controller block 501 can be located on the surface or downhole. The rate of drilling (ROP) and drilling status can be downlinked, measured, or estimated. The desired magnetic toolface (MTF) is the target azimuth (angle). Steering tool 503 controls the drilling direction such that it tracks the desired magnetic toolface (MTF) over a time period controlled by SR parameters. The desired magnetic toolface (MTF) may need to be set as a ramp of multiple MTFs, rather than just a single setpoint. In this case, the MTF setpoint fine movement can be performed internally by the steering tool 503 during drilling using the estimated or passed measurement depth. Figure 6 The inputs and outputs of the automatic tilting control algorithm are shown.

[0046] Estimator box 505 calculates the actual or estimated dogleg severity from the tool response. (or actual or estimated construction date) In an embodiment, the estimator block 505 can use the rate of drilling (ROP) to calculate... Alternatively, the total angle change and threshold (US10995552) can be used to calculate... And the maximum theoretical DLS (e.g., 10 degrees / 100 feet) is used to calculate and transfer the estimated MD. For example, if 0.5 degrees corresponds to 5 feet drilled using theoretical DLS, then the actual or estimated MD is obtained. There are other methods to calculate this by estimating the location of the propagation through the ground. . (or This can be used as part of a closed-loop control algorithm. The target_DLS (or target_BR) can be used in conjunction with... (or The SR parameters are compared and manipulated accordingly. Furthermore, BR and / or turning rate (TR) can be derived and used in controller block 501. Controller block 501 can be a linear controller (e.g., a proportional controller) or a nonlinear controller, including neural network-based controllers.

[0047] In other embodiments, the automatic tilting control mode can be achieved through, for example... Figure 7A and 7B The control algorithm shown in the flowchart is used to implement this.

[0048] In box 701, the target MTF (i.e., MTF requirement), target dip, target azimuth, ROP, and possibly other drilling parameters are provided as inputs. One or more of these inputs can be transmitted from the monitoring machine or downlink, or obtained from the local electronic storage device set in the storage tool.

[0049] In block 703, the attitude (tilt angle INC in degrees and azimuth angle AZI in degrees) of the steering tool (e.g., RSS) is calculated from measurements performed by sensors integrated into the steering tool, as is well known to those skilled in the art.

[0050] In box 705, the current build rate (i.e., actual BR) of the steering tool can be calculated from the steering tool's attitude (e.g., camber INC in degrees) calculated in 703. For example, the current build rate (i.e., actual BR) can be calculated from the difference between the steering tool's camber INC (in degrees) measured by a sensor at the current time (the current measurement time) and the steering tool's camber INC (in degrees) measured by the same sensor at a previous time (the measurement time before the current measurement time). In another example, the current build rate (i.e., actual BR) can be calculated from the difference between the camber INC (in degrees) measured by two sensors at a given measurement time, where the distance between the two sensors is known.

[0051] In block 707, the control operation checks whether the tilt angle (INC) of the steering tool calculated in 703 is less than or equal to a predetermined tilt angle value (predetermined _INC_1). If yes, the control operation continues to blocks 709 and 711. If no, the control operation continues to block 713. In an embodiment, the predetermined tilt angle value (predetermined _INC_1) may be 8 degrees. Another threshold may be used (e.g., a threshold in the range of 2 to 5 degrees). The threshold may be obtained from a supervisory machine transmission or downlink, or from a local electronic storage device storing the tool settings.

[0052] In block 709, the steering ratio SR is calculated as a function of: i) the difference between the target camber angle of 701 and the INC of the steering tool calculated in 703, and ii) the difference between the target build rate (target_BR) and the current build rate (actual_BR) of 705. In an embodiment, the target build rate (target_BR) may be based on the target dogleg severity (target_DLS) and / or another input parameter.

[0053] In box 711, the target _MTF of box 701 is used to control the steering tool within a time period corresponding to the steering ratio SR calculated as in 709. Within this box, the steering tool controls the drilling direction such that it tracks the desired magnetic tool face (MTF) within the time period controlled by the steering ratio SR of 709. The operation can return to box 701 to repeat the control operation shown in the figure.

[0054] In block 713, the control operation checks whether the magnitude of the difference between the target MTF at 701 and the azimuth angle of the steering tool calculated at 703 is less than a predetermined amount. If not, the control operation proceeds to block 715. If not, the control operation proceeds to block 717. In an embodiment, the predetermined amount may be 20 degrees. Another threshold may be used. The threshold may be obtained from a supervisory machine transmission or downlink, or from a local electronic storage device configured for the storage tool.

[0055] In box 715, the control operation executes a scheme for controlling the azimuth angle of the steering tool.

[0056] Note that the operation controls in boxes 713 and 715 address the accuracy of the steering tool's azimuth angle during descent. Specifically, if the descent azimuth angle falls outside a pre-selected threshold (e.g., 20 degrees) at a pre-selected tilt angle (e.g., 8 degrees), the scheme in box 715 is automatically executed. In an embodiment, this scheme can be configured to adjust the steering tool's target_MTF to control the steering tool's azimuth angle and account for any deviations or errors in the tool face, such as those that might be encountered if tool face offset exists. See below for reference. Figure 8 An example of this scheme is described. The operation can return to box 701 to repeat the control operation shown in the figure.

[0057] In block 717, the control operation checks whether the tilt angle (INC) of the steering tool calculated in 703 is greater than or equal to a predetermined tilt angle value (predetermined _INC_2). If not, the control operation continues to blocks 719 and 721. If yes, the control operation continues to block 723. In an embodiment, the predetermined tilt angle value (predetermined _INC_2) can be 10 degrees. Another threshold (e.g., a threshold in the range of 5 to 10 degrees) can be used. The threshold can be obtained from a supervisory machine transmission or downlink, or from a local electronic storage device storing the tool settings.

[0058] In block 719, the steering ratio SR is calculated as a function of: i) the difference between the target camber angle of 701 and the INC of the steering tool calculated in 703, and ii) the difference between the target build rate (target_BR) and the current build rate (actual_BR) of 705. In an embodiment, the target build rate (target_BR) may be based on the target dogleg severity (target_DLS) and / or another input parameter.

[0059] In box 721, the target _MTF of box 701 is used to control the steering tool within a time period corresponding to the steering ratio SR calculated as in 719. Within this box, the steering tool controls the drilling direction such that it tracks the desired magnetic tool face (MTF) within the time period controlled by the steering ratio SR of 719. The operation can return to box 701 to repeat the control operation shown in the figure.

[0060] In box 723, the control operation automatically switches to another control mode (such as automatic curve control mode) suitable for drilling the construction, curve or tangential portion of the wellbore, which has already been skewed by the operation of the automatic skew control mode.

[0061] Figure 8 A proportional-integral (PI) controller is described, which can handle the target MTF to control the drilling direction controlled by the steering tool. From Figure 7A and 7B The calculated azimuth angle AZI (box 703) of the steering tool obtained by the method can be combined with the magnetic tool face setpoint value (e.g., the desired magnetic tool face angle) to obtain the tool face error. The tool face error can be subjected to a threshold function and a proportional-integral gain stage to obtain the tool face correction (ΔTF). The tool face correction (ΔTF) can be subjected to a threshold function and combined with the previous tool face correction (TF command (k-1)) to obtain the current tool face correction (TF command (k)). The current tool face correction (TF command (k)) is the new MTF requirement (in degrees) applied to the steering tool. The previous tool face correction (TF command (k-1)) is the previous MTF requirement (in degrees) applied to the steering tool. The proportional gain is represented by parameter P (in degrees / (degree error)). The integral gain is represented by parameter I (in degrees / (degree error)). It should be understood that Figure 8 The described control structure functions similarly to a proportional-integral (P+I) controller, used to change the MTF toolface setpoint value in response to toolface disturbances. The disclosed embodiments are, of course, not limited to any particular type of controller. For example, other controllers, such as proportional controllers, proportional-derivative controllers, or proportional-integral-derivative controllers, can be used. Non-classical controllers, such as model predictive controllers, fuzzy controllers, etc., can also be used.

[0062] During directional drilling, the automatic directional control mode can be activated (either manually via instructions from the drilling operator or automatically via instructions from the processor or other programmable controllers).

[0063] In this embodiment, the automatic tilting control mode can be activated through various mechanisms, such as the PowerV and manual mode pages, or manual commands in the downlink map.

[0064] In one embodiment, when the wellbore dip angle is low (e.g., less than 5 degrees), the automatic directional control mode can be activated.

[0065] In this embodiment, when the automatic tilting control mode is activated, the steering tool can be configured to automatically curve on the multi-page downlink map. The MTF, DLS, and ROP targets can be preset in the tool settings so that they are only used when the automatic tilting control mode is activated. If not preset, these tool settings can be configured to default values ​​and can be adjusted via the downlink on the automatic curve page.

[0066] In this embodiment, once the wellbore inclination exceeds a preset inclination value (e.g., 10 degrees), directional drilling control can switch from automatic build-up control mode to another mode (e.g., automatic curve mode), and subsequent downlinks will be accepted in the other mode. If automatic build-up control mode needs to be deactivated before reaching the inclination set for automatic deactivation, another command can be sent to configure over-control automatic build-up control mode. This will allow the tool to enter other modes, such as HIA, IH, automatic curve, or manual mode.

[0067] In the embodiments, the automatic directional drilling control mode can be activated by various conditions or commands, such as: the drilling operator sending a downlink; using the preset MTF, DLS, and ROP settings in the tool's automatic directional drilling settings, the tool will start the automatic directional drilling control mode in the MTF direction according to the set instructions; the target DLS and ROP can be set or controlled independently.

[0068] In this embodiment, during automatic directional control mode, the tool can be configured to automatically switch to another mode (e.g., automatic curve mode) without requiring action or input from the drilling operator. In this embodiment, this occurs once the inclination angle reaches a predetermined value (e.g., 10 degrees). In follow mode, if any turning is required, the TF settings in the automatic curve page can be used without exiting automatic directional control mode.

[0069] In embodiments, the automatic directional drilling control mode can be deactivated via various conditions or commands. For example, once the dip angle reaches a predetermined value (e.g., 20 degrees), the tool can be configured to automatically terminate the automatic directional drilling control mode and switch to another mode (such as an automatic curve mode with pre-selected automatic curve settings). If a tangential portion is required, the drilling operation can send the command DLS=0 from within the automatic curve page.

[0070] 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.

[0071] 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 a cascaded closed-loop control system (e.g., Figure 5 One or more modules of the cascaded closed-loop system, which process parameter data and attitude measurements received from sensors to control the drilling direction as described herein.

[0072] Figure 9 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.).

[0073] 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.

[0074] 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.

[0075] 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.

[0076] 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.

[0077] 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.

[0078] In one possible implementation, 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 implementation, logic, computational instructions, and / or software programs of the elements including module 2506 can reside on removable media 2520 that can be read by media drive / interface 2518.

[0079] 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.

[0080] 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.

[0081] 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.

[0082] 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.

[0083] 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.

[0084] 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).

[0085] 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 automatic closed loop control of a well trajectory during directional drilling, the method comprising: automatically adjusting at least one parameter during directional drilling to automatically control the drilling direction while drilling a buildout that transitions a wellbore from a vertical section to a curve or tangent section.

2. The method of claim 1, wherein: the at least one parameter includes a steering ratio (SR) parameter that controls the time a steering tool will spend to maintain a desired magnetic tool face.

3. The method of claim 2, wherein: The adjustment is based on a difference or error between a target dogleg severity (Target_DLS) and an estimated dogleg severity (Est_DLS) calculated from the tool response. ) automatically adjusts a steering ratio (SR) parameter based on a difference or error between a target dogleg severity (Target_DLS) and an estimated dogleg severity (Est_DLS) calculated from the tool response.

4. The method of claim 2, wherein: The adjustment is based on a difference or error between a target build rate parameter (target_BR) and an estimated build rate parameter (estimated_BR) calculated from a tool response ) automatically adjusts a slew ratio (SR) parameter.

5. The method of claim 2, wherein: the adjustment automatically adjusts the steering ratio (SR) parameter based on at least one of i) a difference or error between a target inclination of the steering tool and a measured inclination, and ii) a difference or error between a target build rate and a current build rate calculated from a measured inclination of the steering tool.

6. The method of claim 2, wherein: the adjustment is based on a plurality of inputs selected from the group consisting of a desired magnetic tool face, a target dogleg severity, a target build rate, a rate of penetration (ROP), and a drilling state parameter.

7. The method of claim 5, wherein: at least one of the inputs is produced by a user or downlinked from a machine that supervises and automatically sends the input.

8. The method of claim 2, further comprising: terminating the automatic adjustment or switching to another control mode when an inclination of the steering tool exceeds a predetermined threshold.

9. The method of claim 2, further comprising: automatically adjusting a magnetic tool face of the steering tool if a magnitude of a difference between the desired magnetic tool face and an azimuth of the steering tool at a predetermined inclination angle of the steering tool exceeds a predetermined threshold.

10. The method of claim 2, wherein: the adjustment is based on a ramp or magnetic tool face setpoint jog of a plurality of magnetic tool faces using an estimated or elapsed measured depth during drilling.

11. The method of claim 1, wherein: the adjustment is performed by a downhole processor or controller.

12. The method of claim 1, wherein: the adjustment is activated manually by an instruction from a drilling operator or automatically by an instruction from a processor or other programmed controller during directional drilling.

13. A control system for automatic closed loop control of a well trajectory during directional drilling, the control system comprising: at least one module configured to automatically adjust at least one parameter during directional drilling to automatically control the drilling direction while drilling a buildout that transitions a wellbore from a vertical section to a curve or tangent section.

14. The control system of claim 13, wherein: the at least one parameter includes a steering ratio (SR) parameter that controls the time a steering tool will spend to maintain a desired magnetic tool face.

15. The control system of claim 14, wherein: At least one module is configured to automatically adjust a steering ratio (SR) parameter based on a difference or error between a target dogleg severity (Target_DLS) and an estimated dogleg severity (Est_DLS) calculated from tool response. ) between a target dogleg severity (Target_DLS) and an estimated dogleg severity (Est_DLS) calculated from tool response.

16. The control system of claim 14, wherein: At least one module is configured to automatically adjust a slew ratio (SR) parameter based on a difference or error between a target build rate parameter (target_BR) and an estimated build rate parameter (estimated_BR) calculated from a tool response. ) 17. The control system of claim 14, wherein: the at least one module is configured to automatically adjust a steering ratio (SR) parameter based on at least one of i) a difference or error between a target inclination of the steering tool and a measured inclination, and ii) a difference or error between a target build rate and a current build rate calculated from the measured inclination of the steering tool.

18. The control system of claim 15, wherein: the at least one module is configured to automatically adjust a steering ratio (SR) parameter based on a plurality of inputs selected from the group consisting of: a desired magnetic tool face, a target dogleg severity, a target build rate, a rate of penetration (ROP), and a drilling state parameter.

19. The control system of claim 18, wherein: at least one of the inputs is generated by a user or downlinked from a machine supervising and automatically sending the input.

20. The control system of claim 14, wherein: the at least one module is configured to automatically terminate the automatic adjustment of the steering ratio (SR) parameter or switch to another control mode when the inclination of the steering tool exceeds a predetermined threshold.

21. The control system of claim 14, wherein: the at least one module is configured to automatically adjust a magnetic tool face of the steering tool if a magnitude of a difference between the desired magnetic tool face and an azimuth angle of the steering tool at a predetermined angle of inclination of the steering tool exceeds a predetermined threshold.

22. The control system of claim 14, wherein: the at least one module is configured to automatically adjust a steering ratio (SR) parameter based on a slope of a plurality of magnetic tool faces or a magnetic tool face setpoint jog using an estimated or logged measured depth during drilling.

23. The control system of claim 13, wherein: operation of the at least one module is manually activated by an instruction from a drilling operator or automatically activated by an instruction from a processor or other programmed controller during directional drilling.

24. The control system of claim 13, wherein: the at least one module comprises a downhole processor or controller.

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