Modular downhole directional drilling control unit

Abstract

The control unit may obtain a drilling plan. A control unit may receive state information from a measurement while drilling (MWD) unit in data communication with the control unit. A control unit may determine at least one actuation timing of a biasing element based on the status information and the drilling plan. The control unit may actuate at least one biasing element of the directional steering tool based on the actuation timing.

Description

Cross-reference to related applications

[0001] This application claims priority to U.S. Provisional Patent Application No. 63 / 581,992, filed on September 12, 2023, which is incorporated herein by reference in its entirety. Background Technology

[0002] For drilling wellbores, directional drilling allows for the creation of non-linear or linear wellbores that traverse different formations. A directional drilling unit includes sensors and measuring tools that are redundant with those included in other downhole tools. Summary of the Invention

[0003] In some aspects, the technology described herein relates to a method for controlling a downhole tool, the method comprising: at a control unit: obtaining a drilling plan; receiving status information from a measurement while drilling (MWD) unit that communicates data with the control unit; determining at least one actuation timing of a bias element based on the status information and the drilling plan; and actuating at least one bias element of a directional steering tool based on the actuation timing.

[0004] In some aspects, the technology described herein relates to an apparatus for controlling a downhole tool, the apparatus comprising: a processor; a communication device communicating with the processor; and a hardware storage device storing instructions that, when executed by the processor, cause the control unit to: obtain a drilling plan; receive status information via the communication device from an MWD unit that communicates data with the control unit; determine at least one actuation timing of a biasing element based on the status information and the drilling plan; and actuate at least one biasing element of a directional steering tool based on the actuation timing.

[0005] In some aspects, the technology described herein relates to a system for guiding a bottom hole assembly, the system comprising: a MWD unit; a directional steering tool including at least one biasing element; and a control unit that communicates data with the MWD unit and at least one actuation mechanism of the at least one biasing element of the directional steering tool, wherein the control unit comprises: a processor; a communication device communicating with the processor; and a hardware storage device storing instructions that, when executed by the processor, cause the control unit to: obtain a drilling plan; receive status information from the MWD unit communicating with the control unit via the communication device; determine at least one actuation timing of the at least one biasing element based on the status information and the drilling plan; and actuate the at least one biasing element of the directional steering tool based on the actuation timing.

[0006] This summary is provided to introduce a series of concepts further described below in the 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.

[0007] Further features and aspects of the embodiments of this disclosure will be set forth in the following description and will be apparent in part from the description, or may be learned by practice of such embodiments. The features and aspects of such embodiments can be implemented and obtained by means of the instruments and combinations specifically pointed out in the appended claims. These and other features will become clearer from the following description and the appended claims, or may be learned by practice of such embodiments as set forth below. Attached Figure Description

[0008] To describe how the above and other features of this disclosure are obtained, a more specific description will be presented by reference to the specific embodiments of this disclosure shown in the accompanying drawings. For better understanding, the same elements have been denoted by the same reference numerals throughout the drawings. Although some of the drawings may be schematic or enlarged representations of concepts, the non-schematic drawings should be considered to be drawn to scale for some embodiments of this disclosure, while they are not drawn to scale for other embodiments contemplated herein. It should be understood that the drawings depict some exemplary embodiments, which will be described and explained in more specific and detailed manner by means of the drawings, in which: Figure 1 Drilling systems and downhole environments according to some embodiments of this disclosure are shown; Figure 2 This is a side view of a downhole environment according to some embodiments of this disclosure, wherein the BHA and drill string guide the drill bit to form a curve of the wellbore; Figure 3 This is a system diagram showing the communication between the control unit and the sensors and biasing elements of the orientation and guidance tool of the MWD unit according to some embodiments of this disclosure; Figure 4 The flowchart illustrates an embodiment of a method for controlling downhole tools at a control unit, according to some embodiments of this disclosure; Figure 5 This is a system diagram illustrating communication between a control unit and sensors of the MWD unit, one or more tool face sensors of the orientation guide tool, and biasing elements of the orientation guide tool, according to some embodiments of this disclosure; and Figure 6 The flowchart illustrates another embodiment of a method for controlling downhole tools based on status information collected by the MWD unit and the directional guidance tool, according to some embodiments of this disclosure. Detailed Implementation

[0009] Embodiments of this disclosure generally relate to apparatus, systems, and methods for controlling downhole tools in a downhole environment. Embodiments of this disclosure generally relate to apparatus, systems, and methods for directional drilling. In some embodiments, the systems and methods according to this disclosure allow for the selective cutting, drilling, milling, reaming, degradation, or other removal of material to guide the drill bit in the downhole environment. In some embodiments, the systems and methods of this disclosure allow for the removal of material from the formation in a lateral direction during wellbore drilling. In some embodiments, the systems and methods according to this disclosure allow for the removal of material from the formation based at least in part on information received from one or more sensors in the bottomhole assembly. It should be understood that while this disclosure will describe systems and methods for directional drilling wellbore, it should be understood that this disclosure is applicable to any downhole apparatus having actuable structures on a lateral surface during or after wellbore formation.

[0010] In some implementations, the drilled wellbore or planned wellbore path includes turns or curves. In some implementations, communication with the directional drilling components is slower, while sensors in the downhole environment allow real-time information to be provided to the directional drilling components. In some implementations, a control unit or control unit receives information from a measurement-while-drilling (MWD) unit, a logging-while-drilling (LOD) unit, other devices with sensors, or independent sensors, and provides instructions to the directional drilling rig to guide the drill string.

[0011] Figure 1 An implementation scheme for the drilling system and downhole environment is shown. Figure 1 An example of a drilling system 100 for drilling through formation 101 to form a wellbore 102 is shown. The drilling system 100 includes a drilling rig 103 for rotating a drilling assembly 104 that extends downward into the wellbore 102. The drilling assembly 104 may include a drill string 105 and a bottom hole assembly (BHA) 106 attached to the downhole end of the drill string 105. When the drilling system 100 is used for drilling through formation, a drill bit 110 may be included at the downhole end of the BHA 106.

[0012] The drill string 105 may include several joints of the drill pipe 108 connected end-to-end via a tool joint 109. The drill string 105 transmits drilling fluid through a central bore and can transmit rotational power from the drilling rig 103 to the BHA 106. In some embodiments, the drill string 105 may also include additional components such as subs, short drill pipes, etc. The drill pipe 108 provides hydraulic channels through which drilling fluid 111 is pumped from the surface. The drilling fluid 111 is discharged through nozzles, orifices, or other orifices of selected size in the drill bit 110 to cool the drill bit 110 and its cutting structures, and to lift drill cuttings out of the wellbore 102 during drilling and to prevent the wellbore 102 from collapsing. The drilling fluid 111 carries drill cuttings solids (including fine drill cuttings, drill cuttings, and other rock cuttings) from the wellbore 102 to the surface. Drill cuttings solids may include components from formation 101, components of drilling assembly 104 itself, components of other components (e.g., plugs, lost tools / parts, etc.), or combinations thereof.

[0013] BHA 106 may include drill bit 110 or other components. An exemplary BHA 106 may include additional or other components (e.g., connected between drill string 105 and / or drill bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, downhole reamers, directional steering tools, casing shoes, hydraulic disconnect joints, slappers, damping tools, other components, or combinations of the foregoing.

[0014] Generally, drilling system 100 may include other drilling components and accessories, such as specialized valves (e.g., kerb plugs, blowout preventers, safety valves, centrifuges, vibrating screens, and rheometers). Additional components included in drilling system 100 may be considered part of the surface system (e.g., part of drilling rig 103, drilling assembly 104, drill string 105, or BHA 106, depending on their location and / or purpose within drilling system 100).

[0015] Drill bit 110 in BHA 106 can be any type of drill bit suitable for degrading downhole materials. For example, drill bit 110 can be a drill bit suitable for drilling formation 101. Exemplary types of drill bits used for drilling formations are fixed-cutting or scraper bits, roller cone bits, impregnated bits, or core bits. In other embodiments, drill bit 110 can be a milling shoe for removing metal, composite materials, elastomers, other downhole materials, or combinations thereof. For example, drill bit 110 can be used with a directional drilling tool to mill into casing 107 fitted onto wellbore 102. Drill bit 110 can also be a flat-end milling shoe for milling away tools, plugs, cement, other materials, or combinations thereof within wellbore 102. Cuttings or other drill cuttings generated by using the milling shoe can be lifted to the surface via drilling fluid 111 or allowed to fall downhole. During operations, conditions of the equipment of drilling system 100, formation 101, wellbore 102, drilling fluid 111, or other parts of the well site may change.

[0016] In some embodiments, BHA 106 includes one or more biasing units that allow an operator to guide the drill bit 110 relative to the formation 101 as the drilling assembly 104 rotates within the wellbore 102. For example, Figure 2 This is a side view of the implementation scheme of the downhole environment, in which BHA 206 and drill string 205 guide drill bit 210 to form the curve of wellbore 202.

[0017] In some embodiments, as the BHA 206 and / or drill string 205 follow a curve, a portion of the BHA 206 and / or drill string 205 contacts the radially inner surface 212 of the wellbore 202. In some embodiments, when the BHA 206 and drill string 205 bore into and touch the formation 201 on the wellbore surface, the BHA 206 and drill string 205 are damaged by the formation 201. In some embodiments, when the BHA 206 and drill string 205 contact the formation 201 on the wellbore surface, the BHA 206 and drill string 205 experience resistance in the longitudinal and / or rotational directions, thereby imposing additional stress on the drilling system and its components. Precise control of the guidance of the BHA 206 and drill bit 210 by the directional steering tool 214 allows the drilling system to limit and / or prevent damage to the BHA 206 and drill string 205 in the nonlinear wellbore 202.

[0018] In some embodiments, the directional steering tool 214 is a discrete steering tool coupled to the drill bit 210. In some embodiments, the directional steering tool 214 is a drill bit with an integrated biasing element or steering element. For example, the directional steering tool 214 includes at least one actuable biasing element 216 configured to be radially outwardly actuated from the rotational axes of the BHA 206 and the drill string 205. As the BHA 206 and the drill string 205 rotate, the actuable biasing element 216 is actuated between a closed position and an open position to selectively apply lateral forces to the wellbore wall. The drill bit 210 is pushed in the opposite lateral direction to guide the orientation of the drill bit 210 and the wellbore 202.

[0019] In some embodiments, the MWD unit 218 allows the measurement of various operating conditions, environmental conditions, fluid measurements, or other status information related to the performance and / or condition of the downhole tool and the downhole environment in which the downhole tool operates. In some embodiments, the MWD unit 218 measures and / or records the orientation information of the downhole tool. In some examples, the MWD unit 218 includes an accelerometer and / or a magnetometer to measure the dip and azimuth of the wellbore at the measurement location. In some embodiments, the MWD unit 218 includes an inclinometer gyroscope that allows the acquisition of orientation and / or movement information, such as dip, azimuth, velocity, and other values. In some embodiments, the MWD unit 218 records the orientation measurement results. In some embodiments, the MWD unit 218 transmits the measurement results to a system and / or operator at the surface.

[0020] In some implementations, the MWD unit 218 measures and / or records drilling mechanics information. In some implementations, the drilling mechanics information includes drill string rotation speed; variations in rotation speed (vibration); drill string vibration amplitude, frequency, and patterns; downhole temperature; bit torque; weight on bit; mud flow rate; other drilling mechanics information; and combinations thereof. In some implementations, the MWD unit 218 records the drilling mechanics information. In some implementations, the MWD unit 218 transmits the drilling mechanics information to a surface system and / or operator.

[0021] In some embodiments, MWD unit 218 measures and / or records formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other formation properties. In some embodiments, MWD unit 218 records formation information. In some embodiments, MWD unit 218 transmits formation information to a system and / or operator at the ground.

[0022] Control unit 220 communicates with MWD unit 218 and directional guidance tool 214. Control unit 220 receives status information (including one or more of direction information, drilling mechanics information, and formation information) from MWD unit 218. In some embodiments, control unit 220 receives status information from MWD unit 218 in real time. In some embodiments, control unit 220 receives status information from MWD unit 218 at predetermined time intervals. In some embodiments, control unit 220 communicates bidirectionally with MWD unit 218. In some embodiments, control unit 220 receives status information on demand in response to status requests transmitted from control unit 220 to MWD unit 218.

[0023] Figure 3 This is a system diagram of an embodiment in which the control unit 320 communicates with the sensors of the MWD unit 318 and the biasing element 316 of the orientation and guidance tool 314. In some embodiments, the MWD unit 318 includes multiple sensors 322 for measuring state information. In some examples, the sensors 322 include accelerometers configured to measure orientation information. In some examples, the sensors 322 include magnetometers configured to measure orientation information. In some embodiments, the MWD unit 318 includes other sensors configured to measure orientation information. In some embodiments, the sensors 322 include force gauges, strain gauges, or other devices configured to measure drill pressure or torque on the drill bit, or other drilling mechanics information. In some embodiments, the sensors 322 include temperature sensors, pressure sensors, gamma-ray sensors, or other devices configured to measure formation information.

[0024] Control unit 320 receives status information collected by sensor 322 from MWD unit 318, and control unit 320 actuates or transmits actuation commands to one or more actuation mechanisms of directional tool 314. In some embodiments, control unit actuates or causes actuation of fluid valve 324 of directional tool 314. In some embodiments, control unit 320 actuates or causes actuation of a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of fluid valve 324 allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move bias element 316 of directional tool 314. In a particular example, opening fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0025] In some embodiments, the control unit 320 actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0026] In some implementations, the control unit 320 actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0027] Control unit 320 includes processor 326 configured to determine the actuation timing of at least one biasing element of the orientation guide tool. In some embodiments, processor 326 is or includes a central processing unit (CPU). In some embodiments, processor 326 is or includes a graphics processing unit (GPU). In some embodiments, processor 326 is or includes an application-specific integrated circuit (ASIC). For example, processor 326 communicates with hardware storage device 328 storing instructions that, when executed by processor 326, cause control unit 320 to perform at least a portion of any of the methods described herein. In some embodiments, processor 326 also communicates with communication device 330, which allows or enables communication between control unit 320 and MWD unit 318. In some embodiments, communication device 330 is a wired communication device that communicates with MWD unit 318 via wired communication. In some embodiments, communication device 330 is a wireless communication device that communicates with MWD unit 318 via wireless communication. In some implementations, the control unit 320 has a predefined connection protocol and wiring connected to a mechanical connector that is coupled to a complementary connector on the MWD unit 318 to enable data connection between the two.

[0028] In some implementations, hardware storage device 328 is a non-transitory storage device, including any of RAM, ROM, EEPROM, CD-ROM or other optical disc storage devices (such as CD, DVD, etc.), magnetic disk storage devices or other magnetic storage devices, or any other medium that can be used to store desired program code in the form of computer-executable instructions or data structures and is accessible by a general-purpose or special-purpose computer.

[0029] In some embodiments, a power source 334 (e.g., a battery cell or power generation unit, such as a turbine) is located between the control unit 320 and the MWD unit 318. In some embodiments, the power source 334 provides power to both the control unit 320 and the MWD unit 318. In some embodiments, power for the control unit 320 is drawn directly from the MWD unit 318. In some embodiments, the power source 334 is integrated with the control unit 320.

[0030] Figure 4 This is a flowchart illustrating an embodiment of method 436 for controlling downhole tools at a control unit. In some embodiments, method 436 includes obtaining a drilling plan at 438. In some embodiments, the drilling plan is obtained from a local hardware storage device (such as information about...) located within the control unit. Figure 3 The information is obtained from the described hardware storage device. In some examples, the drilling plan is transmitted to and / or loaded onto the local hardware storage device at the surface location before the control unit is run downhole.

[0031] In some implementations, obtaining a drilling plan includes receiving or accessing the drilling plan using a communication device. In some examples, the drilling plan is transmitted from the MWD unit or directional drilling tool to a control unit via wired or wireless communication using a communication device. In some examples, the drilling plan is transmitted via wired or wireless communication from a source located on or near the surface (such as a surface control facility of the drilling system, such as regarding...) Figure 1 The drilling plan is transmitted to the control unit. In some embodiments, the drilling plan is transmitted to the control unit via mud pulse telemetry. For example, modulating mud pulses (e.g., flow rate, mud pressure) transmits instructions to downhole tools. In some embodiments, obtaining the drilling plan includes a combination of the above-described techniques, such as communicating from the surface to select one of a plurality of drilling plans stored locally on the hardware storage device of the control unit. In at least one example, the control unit stores a plurality of drilling plans on its local hardware storage device and uses mud pulse telemetry to transmit instructions to the control unit or other downhole tools to modify, select, or implement a first drilling plan among the plurality of drilling plans.

[0032] In some embodiments, the drilling plan includes target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes multiple target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes length values. In some embodiments, the drilling plan includes the radius of at least one turn within the wellbore.

[0033] In some embodiments, method 436 further includes receiving status information from at least the MWD unit at 440. In some embodiments, the status information includes any of orientation information, drilling mechanics information, environmental information, and other status information related to the current, historical, or predicted status of the BHA, drill string, drilling assemblies, or drilling system. In some embodiments, the status information includes orientation information for downhole tools. In some examples, the MWD unit includes an accelerometer and / or a magnetometer to measure the dip and azimuth of the wellbore at the measurement location. In some embodiments, the MWD unit 218 includes an inclinometer gyroscope that allows the acquisition of orientation and / or movement information, such as dip, azimuth, velocity, and other values. In some examples, the MWD unit measures gravity direction. In some embodiments, the MWD unit records the orientation measurement results. In some embodiments, the MWD unit transmits the measurement results to a system and / or operator at the surface.

[0034] In some implementations, the status information includes drilling mechanics information. In some implementations, drilling mechanics information includes drill string rotation speed; variations in rotation speed (vibration); drill string vibration amplitude, frequency, and pattern; downhole temperature; bit torque; weight on bit; mud flow rate; other drilling mechanics information; and combinations thereof. In some implementations, the MWD unit records the drilling mechanics information. In some implementations, the MWD unit transmits the drilling mechanics information to the surface system and / or operator.

[0035] In some implementations, the state information includes formation information such as density, porosity, resistivity, magnetic resonance, formation pressure, or other formation properties. In some implementations, the MWD unit records the formation information. In some implementations, the MWD unit transmits the formation information to a system and / or operator at the surface.

[0036] In some implementations, the status information includes a guidance request. In some examples, the MWD unit transmits a guidance request to the control unit based on directional information, drilling mechanics information, or formation information collected by the MWD unit. In some implementations, the MWD unit measures the deflection in the direction of the BHA, and the MWD unit calculates and / or provides a guidance request to counteract the deflection. In some examples, the MWD unit has a hold azimuth, hold dip, or hold direction command that causes the MWD unit to provide a guidance request based on any deviation relative to the target azimuth, target dip, or target direction.

[0037] In some embodiments, method 436 further includes determining an actuation timing at 442. An actuation timing refers to the moment when the biasing element of the directional tool moves to achieve the desired change in drill bit orientation. For example, as the drill bit and directional tool rotate, the control unit actuates the biasing element of the directional tool to push the drill bit in the desired direction opposite to the biasing element. The control unit uses the rotational speed (and any optional variations in rotational speed) to determine when to actuate the biasing element to push the drill bit in the desired direction.

[0038] In some implementations, the control unit compares a drilling plan, including a target inclination angle, a target azimuth angle, a target direction, a target turning radius, or a combination thereof, with status information received from at least the MWD unit to determine the timing of actuation.

[0039] In some implementations, the actuation timing includes the actuation duration. For example, the longer the actuation duration of the bias element, the longer the time the drill bit takes to remove material in the opposite direction. Therefore, variations in the actuation duration alter the amount of formation material removed by the drill bit and change the shape of the wellbore.

[0040] In some implementations, the actuation timing includes the actuation amplitude. For example, a larger actuation amplitude of the bias element results in a greater force exerted on the wellbore wall, causing the drill bit to press against the wellbore wall in the opposite direction. Therefore, changes in the actuation amplitude alter the rate at which the drill bit removes formation material and change the shape of the wellbore.

[0041] In some examples, the actuation duration and / or amplitude are determined at least in part based on state information, such as drilling mechanics information. In some embodiments, a smaller actuation duration and / or amplitude reduces drill bit resistance, thus limiting or preventing stick-slip in the drill string. In some embodiments, the actuation duration and / or amplitude vary based on state information, such as formation information. In some embodiments, measured formation variations indicate that the rate of formation material removal differs for a given duration and / or amplitude. In some examples, entry into softer formations (as indicated by state information) results in the control unit determining a shorter duration and / or smaller amplitude of actuation timing required to execute the drilling plan.

[0042] In some implementations, method 436 further includes actuating at 444 at at least one biasing element based on the actuation timing. (As per at least...) Figure 3The actuation of at least one biasing element of the directional steering tool includes one or more actuation mechanisms for the directional steering tool or transmits actuation commands thereto. In some embodiments, a control unit actuates or causes a fluid valve of the directional steering tool to be actuated. In some embodiments, a control unit actuates or causes a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of the fluid valve allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move the biasing element of the directional steering tool. In a particular example, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0043] In some embodiments, the control unit actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0044] In some implementations, the control unit actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0045] Figure 5 This is a system diagram of an embodiment in which the control unit 520 communicates with sensors 522 of the MWD unit 518, one or more tool face sensors 546 of the directional guidance tool 514 (or drill bit), and biasing elements 516 of the directional guidance tool 514. In some embodiments, the MWD unit 518 includes multiple sensors 522 for measuring state information. In some examples, sensors 522 include accelerometers configured to measure orientation information. In some examples, sensors 522 include magnetometers configured to measure orientation information. In some embodiments, sensors 522 include gyroscopes. In some embodiments, the MWD unit 518 includes other sensors 522 configured to measure orientation information. In some embodiments, sensors 522 include force gauges, strain gauges, or other devices configured to measure drill pressure or torque on the drill bit, or other drilling mechanics information. In some embodiments, sensors 522 include temperature sensors, pressure sensors, gamma-ray sensors, or other devices configured to measure formation information.

[0046] In some embodiments, the directional guidance tool 514 further includes one or more toolface sensors 546 for measuring one or more characteristics of the BHA, drill string, drilling assembly, formation, or combinations thereof. For example, the directional guidance tool 514 has toolface sensors 546 that measure or calculate the magnetic toolface and provide it to the control unit 520. In some embodiments, the directional guidance tool 514 has toolface sensors 546 that measure one or more of the azimuth angle, inclination angle, and rotational speed of the toolface. In some embodiments, the directional guidance tool 514 transmits or makes available to the control unit 520 the status information measured by the toolface sensors 546.

[0047] Control unit 520 receives status information from MWD unit 518 (collected by MWD sensor 522) and status information from directional tool 514 (collected by tool face sensor 546), and control unit 520 actuates one or more actuation mechanisms of directional tool 514 or transmits actuation commands to it. In some embodiments, control unit 520 actuates or causes actuation of fluid valve 524 of directional tool 514. In some embodiments, control unit 520 actuates or causes actuation of a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of the fluid valve allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move the biasing element of the directional tool. In a particular example, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0048] In some embodiments, the control unit 520 actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0049] In some implementations, the control unit 520 actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0050] Control unit 520 includes processor 526 configured to determine the actuation timing of at least one biasing element 516 of orientation guide tool 514. In some embodiments, processor 526 is or includes a central processing unit (CPU). In some embodiments, processor 526 is or includes a graphics processing unit (GPU). In some embodiments, processor 526 is or includes an application-specific integrated circuit (ASIC). For example, processor 526 communicates with hardware storage device 528 storing instructions that, when executed by processor 526, cause control unit 520 to perform at least a portion of any of the methods described herein. In some embodiments, processor 526 communicates with communication device 530, which allows or enables communication between control unit 520 and MWD unit 518. In some embodiments, communication device 530 is a wired communication device that communicates with MWD unit 518 via wired communication. In some embodiments, communication device 530 is a wireless communication device that communicates with MWD unit 518 via wireless communication. In some implementations, the control unit 520 has a predefined connection protocol and wiring connected to a mechanical connector that is coupled to a complementary connector on the longitudinal end of the MWD unit 518 to enable data connection between the two.

[0051] In some implementations, hardware storage device 528 is a non-transitory storage device, including any of RAM, ROM, EEPROM, CD-ROM or other optical disc storage devices (such as CD, DVD, etc.), magnetic disk storage devices or other magnetic storage devices, or any other medium that can be used to store desired program code in the form of computer-executable instructions or data structures and is accessible by a general-purpose or special-purpose computer.

[0052] In some embodiments, a power source 534 (e.g., a battery cell or power generation unit, such as a turbine) is located between the control unit 520 and the MWD unit 518. In some embodiments, the power source provides power to both the control unit 520 and the MWD unit 518. In some embodiments, power for the control unit 520 is drawn directly from the MWD unit 518. In some embodiments, the power source 534 is integrated with the control unit 520.

[0053] Figure 6This is a flowchart illustrating another embodiment of method 636 for controlling downhole tools based on status information collected by the MWD unit and directional guidance tools. In some embodiments, method 636 includes obtaining a drilling plan at 638. In some embodiments, the drilling plan is obtained from a local hardware storage device (such as the hardware storage device described with respect to 5) located locally within the control unit. In some examples, the drilling plan is transferred to and / or loaded onto the local hardware storage device at the surface location before the control unit is lowered downhole.

[0054] In some implementations, obtaining a drilling plan includes receiving or accessing the drilling plan using a communication device. In some examples, the drilling plan is transmitted from the MWD unit or directional drilling tool to a control unit via wired or wireless communication using a communication device. In some examples, the drilling plan is transmitted via wired or wireless communication from a source located on or near the surface (such as a surface control facility of the drilling system, such as regarding...) Figure 1 The drilling plan is transmitted to the control unit. In some embodiments, the drilling plan is transmitted to the control unit via mud pulse telemetry. For example, modulating mud pulses (e.g., flow rate, mud pressure) transmits instructions to downhole tools. In some embodiments, obtaining the drilling plan includes a combination of the above-described techniques, such as communicating from the surface to select one of a plurality of drilling plans stored locally on the hardware storage device of the control unit. In at least one example, the control unit stores a plurality of drilling plans on its local hardware storage device and uses mud pulse telemetry to transmit instructions to the control unit or other downhole tools to modify, select, or implement a first drilling plan among the plurality of drilling plans.

[0055] In some embodiments, the drilling plan includes target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes multiple target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes length values. In some embodiments, the drilling plan includes the radius of at least one turn within the wellbore.

[0056] In some implementations, method 636 further includes receiving status information, such as information about the MWD unit and the orientation guidance tool, at 640. Figure 5The status information includes, in some embodiments, orientation information, drilling mechanics information, environmental information, and any other status information relating to the current, historical, or predicted status of the BHA, drill string, drilling assemblies, or drilling system. In some embodiments, the status information includes orientation / information of the downhole tool and / or tool face. In some examples, the MWD unit and / or directional guidance tool includes accelerometers and / or magnetometers to measure the dip and azimuth of the wellbore at the measurement location. In some embodiments, the MWD unit includes an inclinometer gyroscope that allows the acquisition of orientation and / or movement information, such as dip, azimuth, velocity, and other values. In some examples, the MWD unit and / or directional guidance tool measures gravity direction. In some embodiments, the MWD unit and / or directional guidance tool records the orientation measurement results. In some embodiments, the MWD unit and / or directional guidance tool transmits the measurement results to the system and / or operator at the surface.

[0057] In some implementations, the status information includes drilling mechanics information. In some implementations, drilling mechanics information includes drill string rotation speed; variations in rotation speed (vibration); drill string vibration amplitude, frequency, and pattern; downhole temperature; bit torque; weight on bit; mud flow rate; other drilling mechanics information; and combinations thereof. In some implementations, the MWD unit and / or directional steering tool records the drilling mechanics information. In some implementations, the MWD unit and / or directional steering tool transmits the drilling mechanics information to a surface system and / or operator.

[0058] In some implementations, the state information includes formation information such as density, porosity, resistivity, magnetic resonance, formation pressure, or other formation properties. In some implementations, the MWD unit and / or directional guidance tool records the formation information. In some implementations, the MWD unit and / or directional guidance tool transmits the formation information to a system and / or operator at the ground.

[0059] In some implementations, the status information includes a guidance request. In some examples, the MWD unit transmits a guidance request to the control unit based on directional information, drilling mechanics information, or formation information collected by the MWD unit. In some implementations, the MWD unit measures the deflection in the direction of the BHA, and the MWD unit calculates and / or provides a guidance request to counteract the deflection. In some examples, the MWD unit has a hold azimuth, hold dip, or hold direction command that causes the MWD unit to provide a guidance request based on any deviation relative to the target azimuth, target dip, or target direction.

[0060] In some embodiments, method 636 further includes determining an actuation timing at 642. An actuation timing refers to the moment when the biasing element of the directional tool moves to achieve the desired change in drill bit orientation. For example, as the drill bit and directional tool rotate, the control unit actuates the biasing element of the directional tool to push the drill bit in the desired direction opposite to the biasing element. The control unit uses the rotational speed (and any optional variations in rotational speed) to determine when to actuate the biasing element to push the drill bit in the desired direction.

[0061] In some implementations, the control unit compares a drilling plan, including a target inclination angle, target azimuth angle, target direction, target turning radius, or a combination thereof, with status information received from at least the MWD and directional steering tools to determine the timing of actuation.

[0062] In some implementations, the actuation timing includes the actuation duration. For example, the longer the actuation duration of the bias element, the longer the time the drill bit takes to remove material in the opposite direction. Therefore, variations in the actuation duration alter the amount of formation material removed by the drill bit and change the shape of the wellbore.

[0063] In some implementations, the actuation timing includes the actuation amplitude. For example, a larger actuation amplitude of the bias element results in a greater force exerted on the wellbore wall, causing the drill bit to press against the wellbore wall in the opposite direction. Therefore, changes in the actuation amplitude alter the rate at which the drill bit removes formation material and change the shape of the wellbore.

[0064] In some examples, the actuation duration and / or amplitude are determined at least in part based on state information, such as drilling mechanics information. In some embodiments, a smaller actuation duration and / or amplitude reduces drill bit resistance, thus limiting or preventing stick-slip in the drill string. In some embodiments, the actuation duration and / or amplitude vary based on state information, such as formation information. In some embodiments, measured formation variations indicate that the rate of formation material removal differs for a given duration and / or amplitude. In some examples, entry into softer formations (as indicated by state information) results in the control unit determining a shorter duration and / or smaller amplitude of actuation timing required to execute the drilling plan.

[0065] In some implementations, method 636 further includes actuating at 644 at at least one biasing element based on the actuation timing. (As per at least...) Figure 5The actuation of at least one biasing element of the directional steering tool includes one or more actuation mechanisms for the directional steering tool or transmits actuation commands thereto. In some embodiments, a control unit actuates or causes a fluid valve of the directional steering tool to be actuated. In some embodiments, a control unit actuates or causes a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of the fluid valve allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move the biasing element of the directional steering tool. In a particular example, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0066] In some embodiments, the control unit actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0067] In some implementations, the control unit actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0068] This disclosure generally relates to apparatus, systems, and methods for controlling downhole tools in a downhole environment. In some embodiments, a control unit in the BHA receives status information from a MWD unit and determines the timing for actuating at least one biasing element of the directional tool.

[0069] In some implementations, the MWD unit allows the measurement of various operating conditions, environmental conditions, fluid measurements, or other status information related to the performance and / or condition of the downhole tool and the downhole environment in which the downhole tool operates. In some implementations, the MWD unit measures and / or records the orientation information of the downhole tool. In some examples, the MWD unit includes accelerometers and / or magnetometers to measure the dip and azimuth of the wellbore at the measurement location. In some implementations, the MWD unit includes an inclinometer gyroscope that allows the acquisition of orientation and / or movement information, such as dip, azimuth, velocity, and other values. In some implementations, the MWD unit records the orientation measurement results. In some implementations, the MWD unit transmits the measurement results to a system and / or operator at the surface.

[0070] In some implementations, the MWD unit measures and / or records drilling mechanics information. In some implementations, the drilling mechanics information includes drill string rotation speed; variations in rotation speed (vibration); drill string vibration amplitude, frequency, and patterns; downhole temperature; bit torque; weight on bit; mud flow rate; other drilling mechanics information; and combinations thereof. In some implementations, the MWD unit records the drilling mechanics information. In some implementations, the MWD unit transmits the drilling mechanics information to a surface system and / or operator.

[0071] In some implementations, the MWD unit measures and / or records formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other formation properties. In some implementations, the MWD unit records formation information. In some implementations, the MWD unit transmits the formation information to a system and / or operator at the surface.

[0072] The control unit communicates data with the MWD unit and the directional guidance tool. The control unit receives status information (including one or more of direction information, drilling mechanics information, and formation information) from the MWD unit. In some embodiments, the control unit receives status information from the MWD unit in real time. In some embodiments, the control unit receives status information from the MWD unit at predetermined time intervals. In some embodiments, the control unit receives status information on demand in response to status requests transmitted from the control unit to the MWD unit.

[0073] In some embodiments, the MWD unit includes multiple sensors for measuring state information. In some examples, the sensors include accelerometers configured to measure orientation information. In some examples, the sensors include magnetometers configured to measure orientation information. In some embodiments, the sensors include gyroscopes. In some embodiments, the MWD unit includes other sensors configured to measure orientation information. In some embodiments, the sensors include force gauges, strain gauges, or other devices configured to measure drill pressure or torque on the drill bit, or other drilling mechanics information. In some embodiments, the sensors include temperature sensors, pressure sensors, gamma-ray sensors, or other devices configured to measure formation information.

[0074] The control unit receives status information collected by sensors from the MWD unit, and actuates or transmits actuation commands to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes actuation of a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of the fluid valve allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move the biasing element of the directional steering tool. In a particular example, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0075] In some embodiments, the control unit actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0076] In some implementations, the control unit actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0077] The control unit includes a processor configured to determine the actuation timing of at least one biasing element of the orientation guide tool. In some embodiments, the processor is or includes a central processing unit (CPU). In some embodiments, the processor is or includes a graphics processing unit (GPU). In some embodiments, the processor is or includes an application-specific integrated circuit (ASIC). For example, the processor communicates data with a hardware storage device storing instructions that, when executed by the processor, cause the control unit to perform at least a portion of any of the methods described herein. In some embodiments, the processor also communicates data with a communication device that allows or enables communication between the control unit and the MWD unit. In some embodiments, the communication device is a wired communication device that communicates with the MWD unit via wired communication. In some embodiments, the communication device is a wireless communication device that communicates with the MWD unit via wireless communication. In some embodiments, the control unit has a predefined connection protocol and wiring connected to a mechanical connector that engages with a complementary connector on the longitudinal end of the MWD unit to establish a connection between the two.

[0078] In some implementations, the hardware storage device is a non-transitory storage device, including any of RAM, ROM, EEPROM, CD-ROM or other optical disc storage devices (such as CD, DVD, etc.), magnetic disk storage devices or other magnetic storage devices, or any other medium that can be used to store desired program code in the form of computer-executable instructions or data structures and is accessible by a general-purpose or special-purpose computer.

[0079] In some implementations, the power source (e.g., a battery cell or generator unit, such as a turbine) is located between the control unit and the MWD unit. In some implementations, the power source supplies power to both the control unit and the MWD unit. In some implementations, power is drawn directly from the MWD unit. In some implementations, the power source is integrated with the control unit.

[0080] In some implementations, the method of controlling downhole tools at the control unit includes obtaining a drilling plan. In some implementations, the drilling plan is obtained from a local hardware storage device (such as the hardware storage device described herein) located locally within the control unit. In some examples, the drilling plan is transferred to and / or loaded onto the local hardware storage device at the surface location before the control unit is lowered downhole.

[0081] In some embodiments, obtaining a drilling plan includes receiving or accessing the drilling plan using a communication device. In some examples, the drilling plan is transmitted from the MWD unit or directional drilling tool to the control unit via wired or wireless communication using a communication device. In some examples, the drilling plan is transmitted from a source located on or near the surface (such as a surface control facility of the drilling system, as described herein) to the control unit via wired or wireless communication using a communication device. In some embodiments, the drilling plan is transmitted to the control unit via mud pulse telemetry. For example, modulating mud pulses (e.g., flow rate, mud pressure) transmits instructions to downhole tools. In some embodiments, obtaining a drilling plan includes a combination of the above techniques, such as communicating from the surface to select one of a plurality of drilling plans stored locally on the hardware storage device of the control unit. In at least one example, the control unit stores a plurality of drilling plans on its local hardware storage device and uses mud pulse telemetry to transmit instructions to the control unit or other downhole tools to modify, select, or implement a first drilling plan among the plurality of drilling plans.

[0082] In some embodiments, the drilling plan includes target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes multiple target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes length values. In some embodiments, the drilling plan includes the radius of at least one turn within the wellbore.

[0083] In some embodiments, the method further includes receiving status information from at least the MWD unit. In some embodiments, the method further includes receiving status information from at least the MWD unit and a directional guidance tool. In some embodiments, the status information includes any of orientation information, drilling mechanics information, environmental information, and other status information related to the current, historical, or predicted status of the BHA, drill string, drilling assemblies, or drilling system. In some embodiments, the status information includes orientation information of the downhole tool. In some examples, the MWD unit includes an accelerometer and / or a magnetometer to measure the dip and azimuth of the wellbore at the measurement location. In some embodiments, the MWD unit includes an inclinometer gyroscope that allows the acquisition of orientation and / or movement information, such as dip, azimuth, velocity, and other values. In some examples, the MWD unit measures gravity direction. In some embodiments, the MWD unit records the orientation measurement results. In some embodiments, the MWD unit transmits the measurement results to a system and / or operator at the surface.

[0084] In some implementations, the status information includes drilling mechanics information. In some implementations, drilling mechanics information includes drill string rotation speed; variations in rotation speed (vibration); drill string vibration amplitude, frequency, and pattern; downhole temperature; bit torque; weight on bit; mud flow rate; other drilling mechanics information; and combinations thereof. In some implementations, the MWD unit records the drilling mechanics information. In some implementations, the MWD unit transmits the drilling mechanics information to the surface system and / or operator.

[0085] In some implementations, the state information includes formation information such as density, porosity, resistivity, magnetic resonance, formation pressure, or other formation properties. In some implementations, the MWD unit records the formation information. In some implementations, the MWD unit transmits the formation information to a system and / or operator at the surface.

[0086] In some implementations, the status information includes a guidance request. In some examples, the MWD unit transmits a guidance request to the control unit based on directional information, drilling mechanics information, or formation information collected by the MWD unit. In some implementations, the MWD unit measures the deflection in the direction of the BHA, and the MWD unit calculates and / or provides a guidance request to counteract the deflection. In some examples, the MWD unit has a hold azimuth, hold dip, or hold direction command that causes the MWD unit to provide a guidance request based on any deviation relative to the target azimuth, target dip, or target direction.

[0087] In some embodiments, the method further includes determining an actuation timing. An actuation timing refers to the moment when the biasing element of the directional tool moves to achieve the desired change in drill bit orientation. For example, as the drill bit and directional tool rotate, the control unit actuates the biasing element of the directional tool to push the drill bit in the desired direction opposite to the biasing element. The control unit uses the rotational speed (and any optional variations in rotational speed) to determine when to actuate the biasing element to push the drill bit in the desired direction.

[0088] In some implementations, the control unit compares a drilling plan, including a target inclination angle, a target azimuth angle, a target direction, a target turning radius, or a combination thereof, with status information received from at least the MWD unit to determine the timing of actuation.

[0089] In some implementations, the actuation timing includes the actuation duration. For example, the longer the actuation duration of the bias element, the longer the time the drill bit takes to remove material in the opposite direction. Therefore, variations in the actuation duration alter the amount of formation material removed by the drill bit and change the shape of the wellbore.

[0090] In some implementations, the actuation timing includes the actuation amplitude. For example, a larger actuation amplitude of the bias element results in a greater force exerted on the wellbore wall, causing the drill bit to press against the wellbore wall in the opposite direction. Therefore, changes in the actuation amplitude alter the rate at which the drill bit removes formation material and change the shape of the wellbore.

[0091] In some examples, the actuation duration and / or amplitude are determined at least in part based on state information, such as drilling mechanics information. In some embodiments, a smaller actuation duration and / or amplitude reduces drill bit resistance, thus limiting or preventing stick-slip in the drill string. In some embodiments, the actuation duration and / or amplitude vary based on state information, such as formation information. In some embodiments, measured formation variations indicate that the rate of formation material removal differs for a given duration and / or amplitude. In some examples, entry into softer formations (as indicated by state information) results in the control unit determining a shorter duration and / or smaller amplitude of actuation timing required to execute the drilling plan.

[0092] In some embodiments, the method further includes actuating at least one biasing element based on actuation timing. As described herein, actuating at least one biasing element of a directional steering tool includes actuating one or more actuation mechanisms of the directional steering tool or transmitting actuation commands thereto. In some embodiments, a control unit actuates or causes actuation of a fluid valve of the directional steering tool. In some embodiments, a control unit actuates or causes actuation of a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of the fluid valve allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move the biasing element of the directional steering tool. In a particular example, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0093] In some embodiments, the control unit actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0094] In some implementations, the control unit actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0095] In some embodiments, the control unit receives status information from MWD unit sensors and orientation tool sensors. In some embodiments, the MWD unit includes multiple sensors for measuring status information. In some examples, the sensors include accelerometers configured to measure orientation information. In some examples, the sensors include magnetometers configured to measure orientation information. In some embodiments, the MWD unit includes an inclinometer that allows the acquisition of orientation and / or movement information, such as inclination, azimuth, velocity, and other values. In some embodiments, the MWD unit includes other sensors configured to measure orientation information. In some embodiments, the sensors include force gauges, strain gauges, or other devices configured to measure drill pressure or torque on the drill bit, or other drilling mechanics information. In some embodiments, the sensors include temperature sensors, pressure sensors, gamma-ray sensors, or other devices configured to measure formation information.

[0096] In some embodiments, the directional guidance tool further includes one or more toolface sensors that measure one or more characteristics of the BHA, drill string, drilling assembly, formation, or combinations thereof. For example, the directional guidance tool has toolface sensors that measure or calculate the magnetic toolface and provide it to a control unit. In some embodiments, the directional guidance tool has toolface sensors that measure one or more of the azimuth angle, inclination angle, and rotational speed of the toolface. In some embodiments, the directional guidance tool transmits or makes available to the control unit the status information measured by the toolface sensors.

[0097] The control unit receives status information from the MWD unit (collected by the MWD sensors) and status information from the directional steering tool (collected by the tool face sensors), and actuates or transmits actuation commands to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes actuation of a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of the fluid valve allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move the biasing element of the directional steering tool. In a particular example, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0098] In some embodiments, the control unit actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0099] In some implementations, the control unit actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0100] The control unit includes a processor configured to determine the actuation timing of at least one biasing element of the orientation guide tool. In some embodiments, the processor is or includes a CPU. In some embodiments, the processor is or includes a GPU. In some embodiments, the processor is or includes an ASIC. For example, the processor communicates data with a hardware storage device storing instructions that, when executed by the processor, cause the control unit to perform at least a portion of any of the methods described herein. In some embodiments, the processor also communicates data with a communication device that allows or enables communication between the control unit and the MWD unit. In some embodiments, the communication device is a wired communication device that communicates with the MWD unit via wired communication. In some embodiments, the communication device is a wireless communication device that communicates with the MWD unit via wireless communication. In some embodiments, the control unit has a predefined connection protocol and wiring connected to a mechanical connector that engages with a complementary connector on the longitudinal end of the MWD unit to establish a connection between the two.

[0101] In some implementations, the hardware storage device is a non-transitory storage device, including any of RAM, ROM, EEPROM, CD-ROM or other optical disc storage devices (such as CD, DVD, etc.), magnetic disk storage devices or other magnetic storage devices, or any other medium that can be used to store desired program code in the form of computer-executable instructions or data structures and is accessible by a general-purpose or special-purpose computer.

[0102] In some implementations, the power source (e.g., a battery cell or generator unit, such as a turbine) is located between the control unit and the MWD unit. In some implementations, the power source supplies power to both the control unit and the MWD unit. In some implementations, power is drawn directly from the MWD unit. In some implementations, the power source is integrated with the control unit.

[0103] In some implementations, methods for controlling downhole tools based on status information collected by the MWD unit and directional guidance tools include obtaining a drilling plan. In some implementations, the drilling plan is obtained from a local hardware storage device (such as the hardware storage device described herein) located locally within the control unit. In some examples, the drilling plan is transmitted to and / or loaded onto the local hardware storage device at the surface location before the control unit is lowered downhole.

[0104] In some embodiments, obtaining a drilling plan includes receiving or accessing the drilling plan using a communication device. In some examples, the drilling plan is transmitted from the MWD unit or directional drilling tool to the control unit via wired or wireless communication using a communication device. In some examples, the drilling plan is transmitted from a source located on or near the surface (such as a surface control facility of the drilling system, as described herein) to the control unit via wired or wireless communication using a communication device. In some embodiments, the drilling plan is transmitted to the control unit via mud pulse telemetry. For example, modulating mud pulses (e.g., flow rate, mud pressure) transmits instructions to downhole tools. In some embodiments, obtaining a drilling plan includes a combination of the above techniques, such as communicating from the surface to select one of a plurality of drilling plans stored locally on the hardware storage device of the control unit. In at least one example, the control unit stores a plurality of drilling plans on its local hardware storage device and uses mud pulse telemetry to transmit instructions to the control unit or other downhole tools to modify, select, or implement a first drilling plan among the plurality of drilling plans.

[0105] In some embodiments, the drilling plan includes target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes multiple target azimuth and inclination values ​​for the planned wellbore. In some embodiments, the drilling plan includes length values. In some embodiments, the drilling plan includes the radius of at least one turn within the wellbore.

[0106] In some embodiments, the method further includes receiving status information from a MWD unit and directional guidance tool, such as those described herein. In some embodiments, the status information includes any of the following: orientation information, drilling mechanics information, environmental information, and other status information relating to the current, historical, or predicted status of the BHA, drill string, drilling assemblies, or drilling system. In some embodiments, the status information includes orientation / information of the downhole tool and / or tool face. In some examples, the MWD unit and / or directional guidance tool includes accelerometers and / or magnetometers to measure the dip and azimuth of the wellbore at the measurement location. In some embodiments, the MWD unit includes an inclinometer gyroscope that allows the acquisition of orientation and / or movement information, such as dip, azimuth, velocity, and other values. In some examples, the MWD unit and / or directional guidance tool measures gravity direction. In some embodiments, the MWD unit and / or directional guidance tool records the orientation measurement results. In some embodiments, the MWD unit and / or directional guidance tool transmits the measurement results to a system and / or operator at the surface.

[0107] In some implementations, the status information includes drilling mechanics information. In some implementations, drilling mechanics information includes drill string rotation speed; variations in rotation speed (vibration); drill string vibration amplitude, frequency, and pattern; downhole temperature; bit torque; weight on bit; mud flow rate; other drilling mechanics information; and combinations thereof. In some implementations, the MWD unit and / or directional steering tool records the drilling mechanics information. In some implementations, the MWD unit and / or directional steering tool transmits the drilling mechanics information to a surface system and / or operator.

[0108] In some implementations, the state information includes formation information such as density, porosity, resistivity, magnetic resonance, formation pressure, or other formation properties. In some implementations, the MWD unit and / or directional guidance tool records the formation information. In some implementations, the MWD unit and / or directional guidance tool transmits the formation information to a system and / or operator at the ground.

[0109] In some implementations, the status information includes a guidance request. In some examples, the MWD unit transmits a guidance request to the control unit based on directional information, drilling mechanics information, or formation information collected by the MWD unit. In some implementations, the MWD unit measures the deflection in the direction of the BHA, and the MWD unit calculates and / or provides a guidance request to counteract the deflection. In some examples, the MWD unit has a hold azimuth, hold dip, or hold direction command that causes the MWD unit to provide a guidance request based on any deviation relative to the target azimuth, target dip, or target direction.

[0110] In some embodiments, the method further includes determining an actuation timing. An actuation timing refers to the moment when the biasing element of the directional tool moves to achieve the desired change in drill bit orientation. For example, as the drill bit and directional tool rotate, the control unit actuates the biasing element of the directional tool to push the drill bit in the desired direction opposite to the biasing element. The control unit uses the rotational speed (and any optional variations in rotational speed) to determine when to actuate the biasing element to push the drill bit in the desired direction.

[0111] In some implementations, the control unit compares a drilling plan, including a target inclination angle, target azimuth angle, target direction, target turning radius, or a combination thereof, with status information received from at least the MWD and directional steering tools to determine the timing of actuation.

[0112] In some implementations, the actuation timing includes the actuation duration. For example, the longer the actuation duration of the bias element, the longer the time the drill bit takes to remove material in the opposite direction. Therefore, variations in the actuation duration alter the amount of formation material removed by the drill bit and change the shape of the wellbore.

[0113] In some implementations, the actuation timing includes the actuation amplitude. For example, a larger actuation amplitude of the bias element results in a greater force exerted on the wellbore wall, causing the drill bit to press against the wellbore wall in the opposite direction. Therefore, changes in the actuation amplitude alter the rate at which the drill bit removes formation material and change the shape of the wellbore.

[0114] In some examples, the actuation duration and / or amplitude are determined at least in part based on state information, such as drilling mechanics information. In some embodiments, a smaller actuation duration and / or amplitude reduces drill bit resistance, thus limiting or preventing stick-slip in the drill string. In some embodiments, the actuation duration and / or amplitude vary based on state information, such as formation information. In some embodiments, measured formation variations indicate that the rate of formation material removal differs for a given duration and / or amplitude. In some examples, entry into softer formations (as indicated by state information) results in the control unit determining a shorter duration and / or smaller amplitude of actuation timing required to execute the drilling plan.

[0115] In some embodiments, the method further includes actuating at least one biasing element based on actuation timing. As described herein, actuating at least one biasing element of a directional steering tool includes actuating one or more actuation mechanisms of the directional steering tool or transmitting actuation commands thereto. In some embodiments, a control unit actuates or causes actuation of a fluid valve of the directional steering tool. In some embodiments, a control unit actuates or causes actuation of a motor connected to a diamond (or other hard or superhard material) rotary valve, one or more solenoid valves, or one or more bistable actuator control valves. In some embodiments, movement of the fluid valve allows fluid (such as hydraulic fluid or mud) to flow through it and applies hydraulic pressure to move the biasing element of the directional steering tool. In a particular example, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, opening the fluid valve allows hydraulic fluid to apply hydraulic pressure to a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0116] In some embodiments, the control unit actuates or causes actuation of the electric motor of the directional tool. In a particular example, the electric motor moves a movable guide pad, thereby applying force to the wellbore wall. In some embodiments, the electric motor moves a movable guide pad containing cutting elements to remove material from the wellbore wall.

[0117] In some implementations, the control unit actuates or causes actuation of the brakes of the directional tool. In a particular example, the control unit changes the rotation or rotational speed of at least a portion of the directional tool, and / or moves a movable guide pad, thereby applying force to the wellbore wall and / or removing material from the wellbore wall.

[0118] It should be understood that references to "one embodiment" or "implementation" in this disclosure are not intended to exclude the existence of other embodiments that also incorporate the described features. For example, any element described with respect to an embodiment herein may be combined with any element of any other embodiment described herein, provided that such features are not described as mutually exclusive. As will be understood by one of ordinary skill in the art as covered by embodiments of this disclosure, the numbers, percentages, ratios, or other values ​​stated herein are intended to include such values, as well as other values ​​that are "about," "approximately," or "about" said values. Therefore, the values ​​should be interpreted broadly enough to cover values ​​that are at least close enough to the stated value to perform the desired function or achieve the desired result. The values ​​include at least the variations expected in a suitable manufacturing or production process and may include values ​​within 5%, 1%, 0.1%, or 0.01% of the stated value.

[0119] As used herein, the terms “approximately,” “about,” and “substantially” mean a quantity that is close to or within standard manufacturing or process tolerances or that still performs the desired function or achieves the desired result. For example, the terms “approximately,” “about,” and “substantially” can refer to a quantity that is less than 5%, less than 1%, less than 0.1%, and less than 0.01% of the quantity. Furthermore, it should be understood that any direction or frame of reference in the foregoing description is only relative direction or movement. For example, any reference to “up” and “down,” or “above” or “below”, describes only the relative position or movement of the relevant element.

[0120] In view of this disclosure, those skilled in the art will recognize that equivalent constructions do not depart from the spirit and scope of this disclosure, and that various changes, substitutions, and modifications can be made to the embodiments disclosed herein without departing from the spirit and scope of this disclosure. Equivalent constructions (including the functional "device plus function" clause) are intended to cover structures described herein as performing said function, including structural equivalents operating in the same manner and equivalent structures providing the same function. The applicant's explicit intent is not to invoke device plus function or other functional requirements in any claim, except for those claims where the phrase "device for..." appears with the associated function. Every addition, deletion, and modification to the embodiments falling within the meaning and scope of the claims will be included in the claims. Therefore, the embodiments are considered illustrative rather than restrictive, and the scope of this disclosure is indicated by the appended claims rather than by the foregoing description.

Claims

1. A method for controlling downhole tools, the method comprising: At the control unit: Obtain drilling plans; Status information is received from the measurement while drilling (MWD) unit that communicates data with the control unit; At least one actuation timing for the bias element is determined based on the status information and the drilling plan; as well as At least one biasing element of the orientation and guidance tool is actuated based on the actuation timing.

2. The method according to claim 1, wherein the state information includes azimuth information.

3. The method according to claim 1, wherein the state information includes tilt angle information.

4. The method according to claim 1, wherein the state information includes rotational speed.

5. The method according to claim 1, wherein the status information includes a guidance request.

6. The method according to claim 1, wherein the state information includes formation information.

7. The method of claim 1, wherein the drilling plan is obtained from the MWD unit.

8. The method of claim 1, wherein the drilling plan is obtained at least in part via mud pulse telemetry.

9. The method of claim 1, wherein the drilling plan is selected from a plurality of drilling plans stored on a hardware storage device of the control unit.

10. The method of claim 1, wherein the drilling plan includes a target azimuth and dip angle.

11. The method of claim 1, wherein actuating the at least one biasing element comprises actuating a valve to allow fluid to flow through the valve to move the biasing element.

12. The method of claim 1, wherein actuating the at least one biasing element comprises actuating an electric motor to move the biasing element.

13. The method of claim 1, wherein actuating the at least one biasing element comprises actuating a brake on the directional guide tool.

14. The method of claim 1, wherein determining the actuation timing includes determining the actuation duration.

15. The method of claim 1, wherein determining the actuation timing includes determining the actuation amplitude.

16. A control unit for controlling downhole tools, the control unit comprising: processor; A communication device that communicates with the processor; and a hardware storage device, on which instructions are stored, which, when executed by the processor, cause the control unit to: Obtain drilling plans; Status information is received from the MWD unit, which communicates with the control unit, via the communication device; At least one actuation timing for the bias element is determined based on the status information and the drilling plan; as well as At least one biasing element of the orientation and guidance tool is actuated based on the actuation timing.

17. The control unit of claim 16, wherein the drilling plan is one of a plurality of drilling plans stored on the hardware storage device.

18. The control unit of claim 16, wherein the instructions further cause the control unit to receive at least a portion of the status information from the tool face sensor of the orientation guide tool.

19. A system for guiding a bottom hole drill string assembly, the system comprising: MWD unit, the MWD unit being configured to collect state information from at least one of an accelerometer, a magnetometer, and a gyroscope; A directional guiding tool, the directional guiding tool including at least one biasing element; as well as A control unit, which communicates data with at least one actuation mechanism of the at least one biasing element of the MWD unit and the orientation guide tool, wherein the control unit includes: processor; A communication device for communicating with the processor; and A hardware storage device storing instructions that, when executed by the processor, cause the control unit to: Obtain drilling plans; The status information is received from the MWD unit, which communicates with the control unit, via the communication device; Based on the status information and the drilling plan, at least one actuation timing of the at least one biasing element is determined; and The at least one biasing element of the orientation guide tool is actuated based on the actuation timing.

20. The system of claim 19, further comprising a power source that provides power to at least one of the control unit and the MWD unit.

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