WO2025059000A1

WO2025059000A1 - Modular downhole directional drilling control unit

Info

Publication number: WO2025059000A1
Application number: PCT/US2024/045911
Authority: WO
Inventors: Edward Richards; Sameer Bhoite; Steven G. Villareal; Geoffrey Charles Downton
Original assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Current assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Priority date: 2023-09-12
Filing date: 2024-09-10
Publication date: 2025-03-20
Anticipated expiration: 2026-03-12

Abstract

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

Description

MODULAR DOWNHOLE DIRECTIONAL DRILLING CONTROL UNIT

CROSS REFERENCE TO RELATED APPLICATIONS

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

BACKGROUND

[0002] For drilling of a borehole, directional drilling allows creation of a non-linear borehole or a linear borehole through varying earth formations. Directional drilling units contain sensors and measurement tools that are redundant with sensors and measurement tools included in other downhole tools.

SUMMARY

[0003] In some aspects, the techniques described herein relate to a method of controlling a downhole tool, the method including: at a control unit: obtaining a drill plan; receiving status information from a measurement while drilling (MWD) unit in data communication with the control unit; determining, based on the status information and the drill plan, at least one actuation timing of a biasing element; and actuating at least one biasing element of a directional steering tool based on the actuation timing.

[0004] In some aspects, the techniques described herein relate to a device for controlling a downhole tool, the device including: a processor; a communication device in communication with the processor; and a hardware storage device having instructions stored thereon that, when executed by the processor, cause the control unit to: obtain a drill plan; receive status information from an MWD unit in data communication with the control unit via the communication device; determine, based on the status information and the drill plan, at least one actuation timing of a biasing element; and actuate at least one biasing element of a directional steering tool based on the actuation timing.

[0005] In some aspects, the techniques described herein relate to a system for steering a bottomhole assembly, the system including: an MWD unit; a directional steering tool including at least one biasing element; and a control unit in data communication 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 includes: a processor; a communication device in communication with the processor; and a hardware storage device having instructions stored thereon that, when executed by the processor, cause the control unit to: obtain a drill plan; receive status information from the MWD unit in data communication with the control unit via the communication device; determine, based on the status information and the drill plan, at least one actuation timing of the at least one biasing element; 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 selection of concepts that are 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 be used as an aid in limiting the scope of the claimed subject matter.

[0007] Additional features and aspects of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments. The features and aspects of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims or may be learned by the practice of such embodiments as set forth hereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, non-schematic drawings should be considered as being to scale for some embodiments of the present disclosure, but not to scale for other embodiments contemplated herein. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which: [0009] FIG. 1 illustrates a drilling system and downhole environment, according to some embodiments of the present disclosure;

[0010] FIG. 2 is a side view of a downhole environment in which a BHA and drill string steer the bit to create a curve of a borehole, according to some embodiments of the present disclosure;

[0011] FIG. 3 is a system diagram of a control unit in communication with the sensors of the MWD unit and the biasing elements of the directional steering tool, according to some embodiments of the present disclosure;

[0012] FIG. 4 is a flowchart illustrating an embodiment of a method of controlling a downhole tool at a control unit, according to some embodiments of the present disclosure;

[0013] FIG. 5 is a system diagram of a control unit in communication with the sensors of the MWD unit, one or more toolface sensors of the directional steering tool, and the biasing elements of the directional steering tool, according to some embodiments of the present disclosure; and [0014] FIG. 6 is a flowchart illustrating another embodiment of a method of controlling a downhole tool based on status information collected by an MWD unit and a directional steering tool, according to some embodiments of the present disclosure.

DETAILED DESCRIPTION

[0015] Embodiments of the present disclosure generally relate to devices, systems, and methods for controlling a downhole tool in a downhole environment. Embodiments of the present disclosure generally relate to devices, systems, and methods for directional drilling. In some embodiments, systems and methods according to the present disclosure allow for the selective cutting, drilling, milling, reaming, degrading, or otherwise removing material to steer a drill bit in a downhole environment. In some embodiments, systems and methods according to the present disclosure allow for the removal of material from formation in a lateral direction during drilling of the borehole. In some embodiments, systems and methods according to the present disclosure allow for the removal of material from the formation based at least partially on information received from one or more sensors in the bottomhole assembly. It should be understood that while the present disclosure will describe the systems and methods for directional drilling of a wellbore, it should be understood that the present disclosure is applicable to any downhole device with actuatable structures on a lateral surface during or after the creation of a borehole. [0016] In some embodiments, a borehole or a planned path of a borehole being drilled includes a turn or curve. In some embodiments, communication to the directional drilling components is slow, while sensors in the downhole environment allow for real-time information to be provided to the directional drilling components. In some embodiments, a control device or control unit receives information from a measurement while drilling unit, logging while drilling unit, other devices with sensors, or standalone sensors and provides instructions to a directional drilling device to steer the drill string.

[0017] FIG. 1 illustrates an embodiment of a drilling system and downhole environment. FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling assembly 104 which extends downward into the wellbore 102. The drilling assembly 104 may include a drill string 105 and a bottomhole assembly (BHA) 106 attached to the downhole end of the drill string 105. Where the drilling system 100 is used for drilling formation, a drill bit 110 can be included at the downhole end of the BHA 106.

[0018] The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and can transmit rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid 111 is pumped from the surface. The drilling fluid 111 discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, for lifting cuttings out of the wellbore 102 as it is being drilled, and for preventing the collapse of the wellbore 102. The drilling fluid 111 carries drill solids including drill fines, drill cuttings, and other swarf from the wellbore 102 to the surface. The drill solids can include components from the earth formation 101, the drilling assembly 104 itself, from other man-made components (e.g., plugs, lost tools/components, etc.), or combinations thereof.

[0019] The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and/or the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurementwhile-drilling (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, underreamers, directional steering tools, section mills, hydraulic disconnects, jars, vibration dampening tools, other components, or combinations of the foregoing.

[0020] In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, safety valves, centrifuges, shaker tables, and rheometers). Additional components included in the drilling system 100 may be considered a part of the surface system (e.g., drill rig 103, drilling assembly 104, drill string 105, or a part of the BHA 106, depending on their locations and/or use in the drilling system 100).

[0021] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, impregnated bits, or coring bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface by the drilling fluid 111 or may be allowed to fall downhole. The conditions of the equipment of the drilling system 100, the formation 101, the wellbore 102, the drilling fluid 111, or other part of the wellsite can change during operations.

[0022] In some embodiments, the BHA 106 includes one or more biasing units that allow an operator to steer the bit 110 relative to the earth formation 101 as the drilling assembly 104 rotates in the wellbore 102. For example, FIG. 2 is a side view of an embodiment of a downhole environment in which a BHA 206 and drill string 205 steer the bit 210 to create a curve of a borehole 202.

[0023] In some embodiments, a portion of the BHA 206 and/or drill string 205 contacts a radially inward surface 212 of the borehole 202 as the BHA 206 and drill string 205 follow the curve. In some embodiments, when the BHA 206 and drill string 205 contact the formation 201 of the borehole surface, the BHA 206 and drill string 205 experience damage from the formation 201. In some embodiments, when the BHA 206 and drill string 205 contact the formation 201 of the borehole surface, the BHA 206 and drill string 205 experience drag, in the longitudinal direction and/or the rotational direction, placing additional strain on the drilling system and components thereof. Precise control of steering the BHA 206 and the bit 210 with a directional steering tool 214 allows the drilling system to limit and/or prevent damage to the BHA 206 and drill string 205 in non-linear boreholes 202.

[0024] In some embodiments, a directional steering tool 214 is a discrete steering tool that is coupled to a drill bit 210. In some embodiments, the directional steering tool 214 is the drill bit with an integrated biasing element or steering element. For example, a directional steering tool 214 includes at least one actuatable biasing element 216 configured to actuate radially outward from a rotational axis of the BHA 206 and drill string 205. As the BHA 206 and drill string 205 rotate, the actuatable biasing element 216 is actuated between a closed position and an open position to selectively apply a lateral force to the borehole wall. The drill bit 210 is urged in an opposing lateral direction to steer the drill bit 210 and the direction of the borehole 202.

[0025] In some embodiments, an MWD unit 218 allows for measurements of a plurality of operating conditions, environmental conditions, fluid measurements, or other status information regarding the performance and/or condition of the downhole tool and the downhole environment in which the downhole tool is operating. In some embodiments, the MWD unit 218 measures and/or records directional information of the downhole tool. In some examples, the MWD unit 218 includes accelerometers and/or magnetometers to measure the inclination and azimuth of the borehole at the measured location. In some embodiments, the MWD unit 218 includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some embodiments, the MWD unit 218 records the directional measurements. In some embodiments, the MWD unit 218 transmits the measurements to a system and/or operator at the surface.

[0026] In some embodiments, the MWD unit 218 measures and/or records drilling mechanics information. In some embodiments, the drilling mechanics information includes a rotational speed of the drill string; variation (vibration) in the rotational speed; amplitude, frequency, and mode of vibrations of the drill string; downhole temperature; torque on bit; weight on bit; mud flow volume; other drilling mechanics information; and combinations thereof. In some embodiments, the MWD unit 218 records the drilling mechanics information. In some embodiments, the MWD unit 218 transmits the drilling mechanics information to a system and/or operator at the surface.

[0027] In some embodiments, the MWD unit 218 measures and/or records formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other properties of the formation. In some embodiments, the MWD unit 218 records the formation information. In some embodiments, the MWD unit 218 transmits the formation information to a system and/or operator at the surface.

[0028] A control unit 220 is in data communication with the MWD unit 218 and the directional steering tool 214. The control unit 220 receives status information (including one or more of directional information, drilling mechanics information, and formation information) from the MWD unit 218. In some embodiments, the control unit 220 receives the status information in realtime from the MWD unit 218. In some embodiments, the control unit receives the status information at predetermined intervals from the MWD unit 218. In some embodiments, the control unit 220 is in two-way communication with the MWD unit 218. In some embodiments, the control unit 220 receives the status information on-demand in response to status requests transmitted to the MWD unit 218 from the control unit 220.

[0029] FIG. 3 is a system diagram of an embodiment of a control unit 320 in communication with the sensors of the MWD unit 318 and the biasing elements 316 of the directional steering tool 314. In some embodiments, the MWD unit 318 includes a plurality of sensors 322 that allow the measurement of the status information. In some examples, the sensors 322 include accelerometers configured to measure directional information. In some examples, the sensors 322 include magnetometers configured to measure directional information. In some embodiments, the MWD unit 318 includes other sensors configured to measure directional information. In some embodiments, the sensors 322 include force meters, strain gauges, or other devices configured to measure a weight on bit or torque on 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.

[0030] The control unit 320 receives the status information from the MWD unit 318 collected by the sensors 322, and the control unit 320 actuates or transmits actuation instructions to one or more actuation mechanisms of the directional steering tool 314. In some embodiments, the control unit actuates or causes the actuation of a fluid valve 324 of the directional steering tool 314. In some embodiments, the control unit 320 actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve 324 allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element 316 of the directional steering tool 314. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0031] In some embodiments, the control unit 320 actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall.

[0032] In some embodiments, the control unit 320 actuates or causes the actuation of a brake of the directional steering tool. In a particular example, the control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0033] The control unit 320 includes a processor 326 configured to determine an actuation timing of at least one biasing element of the directional steering tool. In some embodiments the processor 326 is or includes a central processing unit (CPU). In some embodiments, the processor 326 is or includes a graphical processing unit (GPU). In some embodiments, the processor 326 is or includes an application specific integrated circuit (ASIC). For example, the processor 326 is in data communication with a hardware storage device 328 having instructions stored thereon that, when executed by the processor 326, cause the control unit 320 to perform at least a part of any method described herein. In some embodiments, the processor 326 is further in data communication with a communication device 330 that allows or enables communication between the control unit 320 and the MWD unit 318. The communication device 330 is, in some embodiments, a wired communication device that communicates with the MWD unit 318 through wired communication. The communication device 330 is, in some embodiments, a wireless communication device that communicates with the MWD unit 318 through wireless communication. In some embodiments, the control unit 320 has predefined connection protocols and wiring to a mechanical connector that couples to a complementary connector on the MWD unit 318 to enable data connection therebetween.

[0034] In some embodiments, the hardware storage device(s) 328 is a non-transient storage device including any of RAM, ROM, EEPROM, CD-ROM or other optical disk storage (such as CDs, DVDs, etc.), magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store desired program code means in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer.

[0035] In some embodiments, a power source 334 (e.g., a battery unit or a power generation unit such as a turbine) is positioned between the control unit 320 and the MWD unit 318. In some embodiments, the power source 334 provides electrical 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.

[0036] FIG. 4 is a flowchart illustrating an embodiment of a method 436 of controlling a downhole tool at a control unit. In some embodiments, the method 436 includes obtaining a drill plan at 438. In some embodiments, the drill plan is obtained from a local hardware storage device positioned locally within the control unit, such as the hardware storage device described in relation to FIG. 3. In some examples, the drill plan is transmitted to and/or loaded onto the local hardware storage device at a surface location prior to the control unit being tripped downhole.

[0037] In some embodiments, obtaining the drill plan includes receiving or accessing the drill plan with the communication device. In some examples, the drill plan is transmitted from the MWD unit or the directional steering tool to the control unit via a wired or wireless communication with the communication device. In some examples, the drill plan is transmitted from a source at or near the surface (such as a control facility at the surface of the drilling system, such as described in relation to FIG. 1) to the control unit via a wired or wireless communication with the communication device. In some embodiments, the drill plan is transmitted to the control unit by mud pulse telemetry. For example, mud pulses (e.g., flow rate, mud pressure) is modulated to transmit instructions to a downhole tool. In some embodiments, obtaining the drill plan includes a combination of the above-described techniques, such as a communication from the surface to select one of a plurality of drill plans stored locally on a hardware storage device of the control unit. In at least one example, the control unit has a plurality of drill plans stored on a local hardware storage device thereof, and mud pulse telemetry is used to communicate instructions to the control unit or other downhole tool to change, select, or implement a first drill plan of the plurality of drill plans.

[0038] In some embodiments, the drill plan includes a target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a plurality of target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a length value. In some embodiments, the drill plan includes a radius of at least one turn in the borehole.

[0039] In some embodiments, the method 436 further includes receiving status information from at least the MWD unit at 440. In some embodiments, the status information includes any of directional information, drilling mechanics information, environmental information, and other status information that relates to the current, historic, or predicted status of the BHA, the drill string, the drilling assembly, or the drilling system. In some embodiments, the status information includes directional information of the downhole tool. In some examples, the MWD unit includes accelerometers and/or magnetometers to measure the inclination and azimuth of the borehole at the measured location. In some embodiments, the MWD unit 218 includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some examples, the MWD unit measures a gravitational direction. In some embodiments, the MWD unit records the directional measurements. In some embodiments, the MWD unit transmits the measurements to a system and/or operator at the surface.

[0040] In some embodiments, the status information includes drilling mechanics information. In some embodiments, the drilling mechanics information includes a rotational speed of the drill string; variation (vibration) in the rotational speed; amplitude, frequency, and mode of vibrations of the drill string; downhole temperature; torque on bit; weight on bit; mud flow volume; other drilling mechanics information; and combinations thereof. In some embodiments, the MWD unit records the drilling mechanics information. In some embodiments, the MWD unit transmits the drilling mechanics information to a system and/or operator at the surface.

[0041] In some embodiments, the status information includes formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other properties of the formation. In some embodiments, the MWD unit records the formation information. In some embodiments, the MWD unit transmits the formation information to a system and/or operator at the surface.

[0042] In some embodiments, the status information includes a steering request. In some examples, the MWD unit transmits to the control unit a steering request based on the directional information, drilling mechanics information, or formation information collected by the MWD unit. In some embodiments, the MWD unit measures a deflection in the direction of the BHA, and the MWD unit calculates and/or provides a steering request to counteract the deflection. In some examples, the MWD unit has a hold-azimuth, a hold-inclination, or hold-direction command that causes the MWD unit to provide steering requests based on any deviation from the target azimuth, target inclination, or target direction.

[0043] The method 436 further includes, in some embodiments, determining an actuation timing at 442. The actuation timing is the timing at which a biasing element of the directional steering tool moves to effectuate a desired change in direction of the drill bit. For example, as the drill bit and directional steering tool rotate, the control unit actuates a biasing element of the directional steering tool to urge the drill bit in a desired direction opposite the biasing element. The control unit uses the rotational speed (and, optionally, any measured variation in the rotational speed) to determine when the biasing element(s) is actuated to push the drill bit in the desired direction.

[0044] In some embodiments, the control unit compares a drill plan including a target inclination, a target azimuth, target direction, target turn radius, or combinations thereof to the status information received from at least the MWD unit to determine the actuation timing.

[0045] In some embodiments, the actuation timing includes an actuation duration. For example, a longer actuation duration of the biasing element provides a longer duration of removal time for the bit in the opposite direction. Changes in the actuation duration can, therefore, alter an amount of removal of formation material by the bit and change a shape of the borehole.

[0046] In some embodiments, the actuation timing includes an actuation amplitude. For example, a larger amplitude of the actuation of the biasing element provides a greater magnitude force against the borehole wall to press the bit against the borehole wall in the opposite direction. Changes in the actuation amplitude can, therefore, alter the rate of removal of formation material by the bit and change the shape of the borehole.

[0047] In some examples, the actuation duration and/or amplitude is determined based at least partially on status information such as drilling mechanics information. In some embodiments, a lesser actuation duration and/or amplitude reduces drag on the bit, which can limit or prevent stickslip mechanics in the drill string. In some embodiments, the actuation duration and/or amplitude changes based on status information such as formation information. In some embodiments, measured changes in the formation indicate different removal rates of formation material for a given duration and/or amplitude. In some examples, crossing into a softer formation (as indicated by the status information) causes the control unit to determine a shorter duration and/or lesser amplitude of the actuation timing is needed to execute the drill plan. [0048] In some embodiments, the method 436 further includes actuating at least one biasing element based on the actuation timing at 444. As described in relation to at least FIG. 3, actuating at least one biasing element of the directional steering tool includes actuating or transmitting actuation instructions to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element of the directional steering tool. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0049] In some embodiments, the control unit actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall.

[0050] In some embodiments, the control unit actuates or causes the actuation of a brake of the directional steering tool. In a particular example, a control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0051] FIG. 5 is a system diagram of an embodiment of a control unit 520 in communication with the sensors 522 of the MWD unit 518, one or more toolface sensors 546 of the directional steering tool 514 (or bit), and the biasing elements 516 of the directional steering tool 514. In some embodiments, the MWD unit 518 includes a plurality of sensors 522 that allow the measurement of the status information. In some examples, the sensors 522 include accelerometers configured to measure directional information. In some examples, the sensors 522 include magnetometers configured to measure directional information. In some embodiments, the sensors 522 include a gyroscope. In some embodiments, the MWD unit 518 includes other sensors 522 configured to measure directional information. In some embodiments, the sensors 522 include force meters, strain gauges, or other devices configured to measure a weight on bit or torque on bit or other drilling mechanics information. In some embodiments, the sensors 522 include temperature sensors, pressure sensors, gamma ray sensors, or other devices configured to measure formation information.

[0052] In some embodiments, the directional steering tool 514 further includes one or more toolface sensors 546 that measure one or more properties of the BHA, the drill string, the drilling assembly, the formation, or combinations thereof. For example, the directional steering tool 514 has toolface sensors 546 therein that measure or calculate the magnetic toolface and provide the magnetic toolface to the control unit 520. In some embodiments, the directional steering tool 514 has toolface sensors 546 that measure one or more of the azimuth of the toolface, the inclination of the toolface, and the rotational speed of the toolface. The directional steering tool 514, in some embodiments, transmits or makes available to the control unit 520 the status information measured by the toolface sensors 546.

[0053] The control unit 520 receives the status information from the MWD unit 518 collected by the MWD sensors 522 and from the directional steering tool 514 collected by the toolface sensors 546, and the control unit 520 actuates or transmits actuation instructions to one or more actuation mechanisms of the directional steering tool 514. In some embodiments, the control unit 520 actuates or causes the actuation of a fluid valve 524 of the directional steering tool 514. In some embodiments, the control unit 520 actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element of the directional steering tool. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0054] In some embodiments, the control unit 520 actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall. [0055] In some embodiments, the control unit 520 actuates or causes the actuation of a brake of the directional steering tool. In a particular example, a control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0056] The control unit 520 includes a processor 526 configured to determine an actuation timing of at least one biasing element 516 of the directional steering tool 514. In some embodiments the processor 526 is or includes a central processing unit (CPU). In some embodiments, the processor 526 is or includes a graphical processing unit (GPU). In some embodiments, the processor 526 is or includes an application specific integrated circuit (ASIC). For example, the processor 526 is in data communication with a hardware storage device 528 having instructions stored thereon that, when executed by the processor 526, cause the control unit 520 to perform at least a part of any method described herein. In some embodiments, the processor 526 is in data communication with a communication device 530 that allows or enables communication between the control unit 520 and the MWD unit 518. The communication device 530 is, in some embodiments, a wired communication device that communicates with the MWD unit 518 through wired communication. The communication device 530 is, in some embodiments, a wireless communication device that communicates with the MWD unit 518 through wireless communication. In some embodiments, the control unit 520 has predefined connection protocols and wiring to a mechanical connector that couples to a complementary connector on a longitudinal end of the MWD unit 518 to enable data connection therebetween.

[0057] In some embodiments, the hardware storage device(s) 528 is a non-transient storage device including any of RAM, ROM, EEPROM, CD-ROM or other optical disk storage (such as CDs, DVDs, etc.), magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store desired program code means in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer.

[0058] In some embodiments, a power source 534 (e.g., a battery unit or a power generation unit such as a turbine) is positioned 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. [0059] FIG. 6 is a flowchart illustrating another embodiment of a method 636 of controlling a downhole tool based on status information collected by an MWD unit and a directional steering tool. In some embodiments, the method 636 includes obtaining a drill plan at 638. In some embodiments, the drill plan is obtained from a local hardware storage device positioned locally within the control unit, such as the hardware storage device described in relation to FIG. 5. In some examples, the drill plan is transmitted to and/or loaded onto the local hardware storage device at a surface location prior to the control unit being tripped downhole.

[0060] In some embodiments, obtaining the drill plan includes receiving or accessing the drill plan with the communication device. In some examples, the drill plan is transmitted from the MWD unit or the directional steering tool to the control unit via a wired or wireless communication with the communication device. In some examples, the drill plan is transmitted from a source at or near the surface (such as a control facility at the surface of the drilling system, such as described in relation to FIG. 1) to the control unit via a wired or wireless communication with the communication device. In some embodiments, the drill plan is transmitted to the control unit by mud pulse telemetry. For example, mud pulses (e.g., flow rate, mud pressure) is modulated to transmit instructions to a downhole tool. In some embodiments, obtaining the drill plan includes a combination of the above-described techniques, such as a communication from the surface to select one of a plurality of drill plans stored locally on a hardware storage device of the control unit. In at least one example, the control unit has a plurality of drill plans stored on a local hardware storage device thereof, and mud pulse telemetry is used to communicate instructions to the control unit or other downhole tool to change, select, or implement a first drill plan of the plurality of drill plans.

[0061] In some embodiments, the drill plan includes a target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a plurality of target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a length value. In some embodiments, the drill plan includes a radius of at least one turn in the borehole. [0062] In some embodiments, the method 636 further includes receiving status information from the MWD unit and the directional steering tool at 640 such as described at least in relation to FIG. 5. In some embodiments, the status information includes any of directional information, drilling mechanics information, environmental information, and other status information that relates to the current, historic, or predicted status of the BHA, the drill string, the drilling assembly, or the drilling system. In some embodiments, the status information includes directional information of the downhole tool and/or toolface. In some examples, the MWD unit and/or directional steering tool includes accelerometers and/or magnetometers to measure the inclination and azimuth of the borehole at the measured location. In some embodiments, the MWD unit includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some examples, the MWD unit and/or directional steering tool measures a gravitational direction. In some embodiments, the MWD unit and/or directional steering tool records the directional measurements. In some embodiments, the MWD unit and/or directional steering tool transmits the measurements to a system and/or operator at the surface.

[0063] In some embodiments, the status information includes drilling mechanics information. In some embodiments, the drilling mechanics information includes a rotational speed of the drill string; variation (vibration) in the rotational speed; amplitude, frequency, and mode of vibrations of the drill string; downhole temperature; torque on bit; weight on bit; mud flow volume; other drilling mechanics information; and combinations thereof. In some embodiments, the MWD unit and/or directional steering tool records the drilling mechanics information. In some embodiments, the MWD unit and/or directional steering tool transmits the drilling mechanics information to a system and/or operator at the surface.

[0064] In some embodiments, the status information includes formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other properties of the formation. In some embodiments, the MWD unit and/or directional steering tool records the formation information. In some embodiments, the MWD unit and/or directional steering tool transmits the formation information to a system and/or operator at the surface.

[0065] In some embodiments, the status information includes a steering request. In some examples, the MWD unit transmits to the control unit a steering request based on the directional information, drilling mechanics information, or formation information collected by the MWD unit. In some embodiments, the MWD unit measures a deflection in the direction of the BHA, and the MWD unit calculates and/or provides a steering request to counteract the deflection. In some examples, the MWD unit has a hold-azimuth, a hold-inclination, or hold-direction command that causes the MWD unit to provide steering requests based on any deviation from the target azimuth, target inclination, or target direction. [0066] The method 636 further includes, in some embodiments, determining an actuation timing at 642. The actuation timing is the timing at which a biasing element of the directional steering tool moves to effectuate a desired change in direction of the drill bit. For example, as the drill bit and directional steering tool rotate, the control unit actuates a biasing element of the directional steering tool to urge the drill bit in a desired direction opposite the biasing element. The control unit uses the rotational speed (and, optionally, any measured variation in the rotational speed) to determine when the biasing element(s) is actuated to push the drill bit in the desired direction.

[0067] In some embodiments, the control unit compares a drill plan including a target inclination, a target azimuth, target direction, target turn radius, or combinations thereof to the status information received from at least the MWD and the directional steering tool to determine the actuation timing.

[0068] In some embodiments, the actuation timing includes an actuation duration. For example, a longer actuation duration of the biasing element provides a longer duration of removal time for the bit in the opposite direction. Changes in the actuation duration can, therefore, alter an amount of removal of formation material by the bit and change a shape of the borehole.

[0069] In some embodiments, the actuation timing includes an actuation amplitude. For example, a larger amplitude of the actuation of the biasing element provides a greater magnitude force against the borehole wall to press the bit against the borehole wall in the opposite direction. Changes in the actuation amplitude can, therefore, alter the rate of removal of formation material by the bit and change the shape of the borehole.

[0070] In some examples, the actuation duration and/or amplitude is determined based at least partially on status information such as drilling mechanics information. In some embodiments, a lesser actuation duration and/or amplitude reduces drag on the bit, which can limit or prevent stickslip mechanics in the drill string. In some embodiments, the actuation duration and/or amplitude changes based on status information such as formation information. In some embodiments, measured changes in the formation indicate different removal rates of formation material for a given duration and/or amplitude. In some examples, crossing into a softer formation (as indicated by the status information) causes the control unit to determine a shorter duration and/or lesser amplitude of the actuation timing is needed to execute the drill plan.

[0071] In some embodiments, the method 636 further includes actuating at least one biasing element based on the actuation timing at 644. As described in relation to at least FIG. 5, actuating at least one biasing element of the directional steering tool includes actuating or transmitting actuation instructions to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element of the directional steering tool. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0072] In some embodiments, the control unit actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall.

[0073] In some embodiments, the control unit actuates or causes the actuation of a brake of the directional steering tool. In a particular example, a control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0074] The present disclosure relates generally to devices, systems, and methods for controlling a downhole tool in a downhole environment. In some embodiments, a control unit in a BHA receives status information from an MWD unit and determines actuation timing(s) to actuate at least one biasing element of a directional steering tool.

[0075] In some embodiments, an MWD unit allows for measurements of a plurality of operating conditions, environmental conditions, fluid measurements, or other status information regarding the performance and/or condition of the downhole tool and the downhole environment in which the downhole tool is operating. In some embodiments, the MWD unit measures and/or records directional information of the downhole tool. In some examples, the MWD unit includes accelerometers and/or magnetometers to measure the inclination and azimuth of the borehole at the measured location. In some embodiments, the MWD unit includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some embodiments, the MWD unit records the directional measurements. In some embodiments, the MWD unit transmits the measurements to a system and/or operator at the surface.

[0076] In some embodiments, the MWD unit measures and/or records drilling mechanics information. In some embodiments, the drilling mechanics information includes a rotational speed of the drill string; variation (vibration) in the rotational speed; amplitude, frequency, and mode of vibrations of the drill string; downhole temperature; torque on bit; weight on bit; mud flow volume; other drilling mechanics information; and combinations thereof. In some embodiments, the MWD unit records the drilling mechanics information. In some embodiments, the MWD unit transmits the drilling mechanics information to a system and/or operator at the surface.

[0077] In some embodiments, the MWD unit measures and/or records formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other properties of the formation. In some embodiments, the MWD unit records the formation information. In some embodiments, the MWD unit transmits the formation information to a system and/or operator at the surface.

[0078] A control unit is in data communication with the MWD unit and the directional steering tool. The control unit receives status information (including one or more of directional information, drilling mechanics information, and formation information) from the MWD unit. In some embodiments, the control unit receives the status information in real-time from the MWD unit. In some embodiments, the control unit receives the status information at predetermined intervals from the MWD unit. In some embodiments, the control unit receives the status information on-demand in response to status requests transmitted to the MWD unit from the control unit.

[0079] In some embodiments, the MWD unit includes a plurality of sensors that allow the measurement of the status information. In some examples, the sensors include accelerometers configured to measure directional information. In some examples, the sensors include magnetometers configured to measure directional information. In some embodiments, the sensors include gyroscopes. In some embodiments, the MWD unit includes other sensors configured to measure directional information. In some embodiments, the sensors include force meters, strain gauges, or other devices configured to measure a weight on bit or torque on 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.

[0080] The control unit receives the status information from the MWD unit collected by the sensors, and the control unit actuates or transmits actuation instructions to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element of the directional steering tool. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0081] In some embodiments, the control unit actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall.

[0082] In some embodiments, the control unit actuates or causes the actuation of a brake of the directional steering tool. In a particular example, a control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0083] The control unit includes a processor configured to determine an actuation timing of at least one biasing element of the directional steering tool. In some embodiments the processor is or includes a central processing unit (CPU). In some embodiments, the processor is or includes a graphical processing unit (GPU). In some embodiments, the processor is or includes an application specific integrated circuit (ASIC). For example, the processor is in data communication with a hardware storage device having instructions stored thereon that, when executed by the processor, cause the control unit to perform at least a part of any method described herein. In some embodiments, the processor is further in data communication with a communication device that allows or enables communication between the control unit and the MWD unit. The communication device is, in some embodiments, a wired communication device that communicates with the MWD unit through wired communication. The communication device is, in some embodiments, a wireless communication device that communicates with the MWD unit through wireless communication. In some embodiments, the control unit has predefined connection protocols and wiring to a mechanical connector that couples to a complementary connector on a longitudinal end of the MWD unit to enable connection therebetween.

[0084] In some embodiments, the hardware storage device(s) is a non-transient storage device including any of RAM, ROM, EEPROM, CD-ROM or other optical disk storage (such as CDs, DVDs, etc.), magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store desired program code means in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer.

[0085] In some embodiments, a power source (e.g., a battery unit or a power generation unit such as a turbine) is positioned between the control unit and the MWD unit. In some embodiments, the power source provides power to both the control unit and the MWD unit. In some embodiments, power is drawn directly from the MWD unit. In some embodiments, the power source is integrated with the control unit.

[0086] In some embodiments, a method of controlling a downhole tool at a control unit includes obtaining a drill plan. In some embodiments, the drill plan is obtained from a local hardware storage device positioned locally within the control unit, such as the hardware storage device described herein. In some examples, the drill plan is transmitted to and/or loaded onto the local hardware storage device at a surface location prior to the control unit being tripped downhole.

[0087] In some embodiments, obtaining the drill plan includes receiving or accessing the drill plan with the communication device. In some examples, the drill plan is transmitted from the MWD unit or the directional steering tool to the control unit via a wired or wireless communication with the communication device. In some examples, the drill plan is transmitted from a source at or near the surface (such as a control facility at the surface of the drilling system, such as described herein) to the control unit via a wired or wireless communication with the communication device. In some embodiments, the drill plan is transmitted to the control unit by mud pulse telemetry. For example, mud pulses (e.g., flow rate, mud pressure) is modulated to transmit instructions to a downhole tool. In some embodiments, obtaining the drill plan includes a combination of the above-described techniques, such as a communication from the surface to select one of a plurality of drill plans stored locally on a hardware storage device of the control unit. In at least one example, the control unit has a plurality of drill plans stored on a local hardware storage device thereof, and mud pulse telemetry is used to communicate instructions to the control unit or other downhole tool to change, select, or implement a first drill plan of the plurality of drill plans.

[0088] In some embodiments, the drill plan includes a target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a plurality of target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a length value. In some embodiments, the drill plan includes a radius of at least one turn in the borehole.

[0089] 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 from the directional steering tool. In some embodiments, the status information includes any of directional information, drilling mechanics information, environmental information, and other status information that relates to the current, historic, or predicted status of the BHA, the drill string, the drilling assembly, or the drilling system. In some embodiments, the status information includes directional information of the downhole tool. In some examples, the MWD unit includes accelerometers and/or magnetometers to measure the inclination and azimuth of the borehole at the measured location. In some embodiments, the MWD unit includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some examples, the MWD unit measures a gravitational direction. In some embodiments, the MWD unit records the directional measurements. In some embodiments, the MWD unit transmits the measurements to a system and/or operator at the surface.

[0090] In some embodiments, the status information includes drilling mechanics information. In some embodiments, the drilling mechanics information includes a rotational speed of the drill string; variation (vibration) in the rotational speed; amplitude, frequency, and mode of vibrations of the drill string; downhole temperature; torque on bit; weight on bit; mud flow volume; other drilling mechanics information; and combinations thereof. In some embodiments, the MWD unit records the drilling mechanics information. In some embodiments, the MWD unit transmits the drilling mechanics information to a system and/or operator at the surface. [0091] In some embodiments, the status information includes formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other properties of the formation. In some embodiments, the MWD unit records the formation information. In some embodiments, the MWD unit transmits the formation information to a system and/or operator at the surface.

[0092] In some embodiments, the status information includes a steering request. In some examples, the MWD unit transmits to the control unit a steering request based on the directional information, drilling mechanics information, or formation information collected by the MWD unit. In some embodiments, the MWD unit measures a deflection in the direction of the BHA, and the MWD unit calculates and/or provides a steering request to counteract the deflection. In some examples, the MWD unit has a hold-azimuth, a hold-inclination, or hold-direction command that causes the MWD unit to provide steering requests based on any deviation from the target azimuth, target inclination, or target direction.

[0093] The method further includes, in some embodiments, determining an actuation timing. The actuation timing is the timing at which a biasing element of the directional steering tool moves to effectuate a desired change in direction of the drill bit. For example, as the drill bit and directional steering tool rotate, the control unit actuates a biasing element of the directional steering tool to urge the drill bit in a desired direction opposite the biasing element. The control unit uses the rotational speed (and, optionally, any measured variation in the rotational speed) to determine when the biasing element(s) is actuated to push the drill bit in the desired direction.

[0094] In some embodiments, the control unit compares a drill plan including a target inclination, a target azimuth, target direction, target turn radius, or combinations thereof to the status information received from at least the MWD unit to determine the actuation timing.

[0095] In some embodiments, the actuation timing includes an actuation duration. For example, a longer actuation duration of the biasing element provides a longer duration of removal time for the bit in the opposite direction. Changes in the actuation duration can, therefore, alter an amount of removal of formation material by the bit and change a shape of the borehole.

[0096] In some embodiments, the actuation timing includes an actuation amplitude. For example, a larger amplitude of the actuation of the biasing element provides a greater magnitude force against the borehole wall to press the bit against the borehole wall in the opposite direction. Changes in the actuation amplitude can, therefore, alter the rate of removal of formation material by the bit and change the shape of the borehole.

[0097] In some examples, the actuation duration and/or amplitude is determined based at least partially on status information such as drilling mechanics information. In some embodiments, a lesser actuation duration and/or amplitude reduces drag on the bit, which can limit or prevent stickslip mechanics in the drill string. In some embodiments, the actuation duration and/or amplitude changes based on status information such as formation information. In some embodiments, measured changes in the formation indicate different removal rates of formation material for a given duration and/or amplitude. In some examples, crossing into a softer formation (as indicated by the status information) causes the control unit to determine a shorter duration and/or lesser amplitude of the actuation timing is needed to execute the drill plan.

[0098] In some embodiments, the method further includes actuating at least one biasing element based on the actuation timing. As described herein, actuating at least one biasing element of the directional steering tool includes actuating or transmitting actuation instructions to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element of the directional steering tool. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0099] In some embodiments, the control unit actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall.

[0100] In some embodiments, the control unit actuates or causes the actuation of a brake of the directional steering tool. In a particular example, a control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0101] In some embodiments, the control unit receives status information from sensors of the MWD unit and sensors of the directional steering tool. In some embodiments, the MWD unit includes a plurality of sensors that allow the measurement of the status information. In some examples, the sensors include accelerometers configured to measure directional information. In some examples, the sensors include magnetometers configured to measure directional information. In some embodiments, the MWD unit includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some embodiments, the MWD unit includes other sensors configured to measure directional information. In some embodiments, the sensors include force meters, strain gauges, or other devices configured to measure a weight on bit or torque on 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.

[0102] In some embodiments, the directional steering tool further includes one or more toolface sensors that measure one or more properties of the BHA, the drill string, the drilling assembly, the formation, or combinations thereof. For example, the directional steering tool has toolface sensors therein that measure or calculate the magnetic toolface and provide the magnetic toolface to the control unit. In some embodiments, the directional steering tool has toolface sensors that measure one or more of the azimuth of the toolface, the inclination of the toolface, and the rotational speed of the toolface. The directional steering tool, in some embodiments, transmits or makes available to the control unit the status information measured by the toolface sensors.

[0103] The control unit receives the status information from the MWD unit collected by the MWD sensors and from the directional steering tool collected by the toolface sensors, and the control unit actuates or transmits actuation instructions to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element of the directional steering tool. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0104] In some embodiments, the control unit actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall.

[0105] In some embodiments, the control unit actuates or causes the actuation of a brake of the directional steering tool. In a particular example, a control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0106] The control unit includes a processor configured to determine an actuation timing of at least one biasing element of the directional steering 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 is in data communication with a hardware storage device having instructions stored thereon that, when executed by the processor, cause the control unit to perform at least a part of any method described herein. In some embodiments, the processor is further in data communication with a communication device that allows or enables communication between the control unit and the MWD unit. The communication device is, in some embodiments, a wired communication device that communicates with the MWD unit through wired communication. The communication device is, in some embodiments, a wireless communication device that communicates with the MWD unit through wireless communication. In some embodiments, the control unit has predefined connection protocols and wiring to a mechanical connector that couples to a complementary connector on a longitudinal end of the MWD unit to enable connection therebetween.

[0107] In some embodiments, the hardware storage device(s) is a non-transient storage device including any of RAM, ROM, EEPROM, CD-ROM or other optical disk storage (such as CDs, DVDs, etc.), magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store desired program code means in the form of computer-executable instructions or data structures and which can be accessed by a general purpose or special purpose computer. [0108] In some embodiments, a power source (e g., a battery unit or a power generation unit such as a turbine) is positioned between the control unit and the MWD unit. In some embodiments, the power source provides power to both the control unit and the MWD unit. In some embodiments, power is drawn directly from the MWD unit. In some embodiments, the power source is integrated with the control unit.

[0109] In some embodiments, a method of controlling a downhole tool based on status information collected by an MWD unit and a directional steering tool includes obtaining a drill plan. In some embodiments, the drill plan is obtained from a local hardware storage device positioned locally within the control unit, such as the hardware storage device described herein. In some examples, the drill plan is transmitted to and/or loaded onto the local hardware storage device at a surface location prior to the control unit being tripped downhole.

[0110] In some embodiments, obtaining the drill plan includes receiving or accessing the drill plan with the communication device. In some examples, the drill plan is transmitted from the MWD unit or the directional steering tool to the control unit via a wired or wireless communication with the communication device. In some examples, the drill plan is transmitted from a source at or near the surface (such as a control facility at the surface of the drilling system, such as described herein) to the control unit via a wired or wireless communication with the communication device. In some embodiments, the drill plan is transmitted to the control unit by mud pulse telemetry. For example, mud pulses (e.g., flow rate, mud pressure) is modulated to transmit instructions to a downhole tool. In some embodiments, obtaining the drill plan includes a combination of the above-described techniques, such as a communication from the surface to select one of a plurality of drill plans stored locally on a hardware storage device of the control unit. In at least one example, the control unit has a plurality of drill plans stored on a local hardware storage device thereof, and mud pulse telemetry is used to communicate instructions to the control unit or other downhole tool to change, select, or implement a first drill plan of the plurality of drill plans.

[0U1] In some embodiments, the drill plan includes a target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a plurality of target azimuth and inclination values of the planned borehole. In some embodiments, the drill plan includes a length value. In some embodiments, the drill plan includes a radius of at least one turn in the borehole.

[0112] In some embodiments, the method further includes receiving status information from the MWD unit and the directional steering tool such as described herein. In some embodiments, the status information includes any of directional information, drilling mechanics information, environmental information, and other status information that relates to the current, historic, or predicted status of the BHA, the drill string, the drilling assembly, or the drilling system. In some embodiments, the status information includes directional information of the downhole tool and/or toolface. In some examples, the MWD unit and/or directional steering tool includes accelerometers and/or magnetometers to measure the inclination and azimuth of the borehole at the measured location. In some embodiments, the MWD unit includes survey gyroscopes that allow directional and/or movement information, such as inclination, azimuth, velocity, and other values. In some examples, the MWD unit and/or directional steering tool measures a gravitational direction. In some embodiments, the MWD unit and/or directional steering tool records the directional measurements. In some embodiments, the MWD unit and/or directional steering tool transmits the measurements to a system and/or operator at the surface.

[0113] In some embodiments, the status information includes drilling mechanics information. In some embodiments, the drilling mechanics information includes a rotational speed of the drill string; variation (vibration) in the rotational speed; amplitude, frequency, and mode of vibrations of the drill string; downhole temperature; torque on bit; weight on bit; mud flow volume; other drilling mechanics information; and combinations thereof. In some embodiments, the MWD unit and/or directional steering tool records the drilling mechanics information. In some embodiments, the MWD unit and/or directional steering tool transmits the drilling mechanics information to a system and/or operator at the surface.

[0114] In some embodiments, the status information includes formation information, such as density, porosity, resistivity, magnetic resonance, formation pressure, or other properties of the formation. In some embodiments, the MWD unit and/or directional steering tool records the formation information. In some embodiments, the MWD unit and/or directional steering tool transmits the formation information to a system and/or operator at the surface.

[0115] In some embodiments, the status information includes a steering request. In some examples, the MWD unit transmits to the control unit a steering request based on the directional information, drilling mechanics information, or formation information collected by the MWD unit. In some embodiments, the MWD unit measures a deflection in the direction of the BHA, and the MWD unit calculates and/or provides a steering request to counteract the deflection. In some examples, the MWD unit has a hold-azimuth, a hold-inclination, or hold-direction command that causes the MWD unit to provide steering requests based on any deviation from the target azimuth, target inclination, or target direction.

[0116] The method further includes, in some embodiments, determining an actuation timing. The actuation timing is the timing at which a biasing element of the directional steering tool moves to effectuate a desired change in direction of the drill bit. For example, as the drill bit and directional steering tool rotate, the control unit actuates a biasing element of the directional steering tool to urge the drill bit in a desired direction opposite the biasing element. The control unit uses the rotational speed (and, optionally, any measured variation in the rotational speed) to determine when the biasing element(s) is actuated to push the drill bit in the desired direction.

[0117] In some embodiments, the control unit compares a drill plan including a target inclination, a target azimuth, target direction, target turn radius, or combinations thereof to the status information received from at least the MWD and the directional steering tool to determine the actuation timing.

[0118] In some embodiments, the actuation timing includes an actuation duration. For example, a longer actuation duration of the biasing element provides a longer duration of removal time for the bit in the opposite direction. Changes in the actuation duration can, therefore, alter an amount of removal of formation material by the bit and change a shape of the borehole.

[0119] In some embodiments, the actuation timing includes an actuation amplitude. For example, a larger amplitude of the actuation of the biasing element provides a greater magnitude force against the borehole wall to press the bit against the borehole wall in the opposite direction. Changes in the actuation amplitude can, therefore, alter the rate of removal of formation material by the bit and change the shape of the borehole.

[0120] In some examples, the actuation duration and/or amplitude is determined based at least partially on status information such as drilling mechanics information. In some embodiments, a lesser actuation duration and/or amplitude reduces drag on the bit, which can limit or prevent stickslip mechanics in the drill string. In some embodiments, the actuation duration and/or amplitude changes based on status information such as formation information. In some embodiments, measured changes in the formation indicate different removal rates of formation material for a given duration and/or amplitude. In some examples, crossing into a softer formation (as indicated by the status information) causes the control unit to determine a shorter duration and/or lesser amplitude of the actuation timing is needed to execute the drill plan. [0121] In some embodiments, the method further includes actuating at least one biasing element based on the actuation timing. As described herein, actuating at least one biasing element of the directional steering tool includes actuating or transmitting actuation instructions to one or more actuation mechanisms of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a fluid valve of the directional steering tool. In some embodiments, the control unit actuates or causes the actuation of a motor connected to a diamond (or other hard or ultrahard material) rotary valve, a solenoid operated valve or valves, a bistable actuator-controlled valve or valves. In some embodiments, movement of the fluid valve allows a fluid, such as a hydraulic fluid or a mud, to flow therethrough and apply a hydraulic pressure to move a biasing element of the directional steering tool. In a particular example, a fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad, exerting a force on the borehole wall. In some embodiments, the fluid valve opening allows a hydraulic fluid to apply a hydraulic pressure to a movable steering pad containing cutting elements to remove material from a borehole wall.

[0122] In some embodiments, the control unit actuates or causes the actuation of an electric motor of the directional steering tool. In a particular example, an electric motor moves a movable steering pad, exerting a force on the borehole wall. In some embodiments, an electric motor moves a movable steering pad containing cutting elements to remove material from a borehole wall.

[0123] In some embodiments, the control unit actuates or causes the actuation of a brake of the directional steering tool. In a particular example, a control unit alters a rotation or rotational speed of at least a portion of the directional steering tool and/or moves a movable steering pad, exerting a force on the borehole wall and/or removing material from the borehole wall.

[0124] It should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein, to the extent such features are not described as being mutually exclusive. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about”, “substantially”, or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

[0125] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

[0126] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims. The described embodiments are therefore to be considered as illustrative and not restrictive, and the scope of the disclosure is indicated by the appended claims rather than by the foregoing description.

Claims

CLAIMS What is claimed is:

1. A method of controlling a downhole tool, the method comprising: at a control unit: obtaining a drill plan; receiving status information from a measurement while drilling (MWD) unit in data communication with the control unit; determining, based on the status information and the drill plan, at least one actuation timing of a biasing element; and actuating at least one biasing element of a directional steering tool based on the actuation timing.

2. The method of claim 1, wherein the status information includes azimuthal information.

3. The method of claim 1, wherein the status information includes inclination information.

4. The method of claim 1, wherein the status information includes rotational speed.

5. The method of claim 1, wherein the status information includes a steering request.

6. The method of claim 1, wherein the status information includes formation information.

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

8. The method of claim 1, wherein the drill plan is obtained at least partially via mud pulse telemetry.

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

10. The method of claim 1, wherein the drill plan includes a target azimuth and inclination.

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

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

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

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

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

16. A control unit for controlling a downhole tool, the control unit comprising: a processor; a communication device in communication with the processor; and a hardware storage device having instructions stored thereon that, when executed by the processor, cause the control unit to: obtain a drill plan; receive status information from an MWD unit in data communication with the control unit via the communication device; determine, based on the status information and the drill plan, at least one actuation timing of a biasing element; and actuate at least one biasing element of a directional steering tool based on the actuation timing.

17. The control unit of claim 16, wherein the drill plan is one of a plurality of drill 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 a toolface sensor of the directional steering tool.

19. A system for steering a bottomhole assembly, the system comprising: an MWD unit configured to collect status information from at least one of an accelerometer, a magnetometer, and a gyroscope; a directional steering tool including at least one biasing element; and a control unit in data communication 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 includes: a processor; a communication device in communication with the processor; and a hardware storage device having instructions stored thereon that, when executed by the processor, cause the control unit to: obtain a drill plan; receive the status information from the MWD unit in data communication with the control unit via the communication device; determine, based on the status information and the drill plan, at least one actuation timing of the at least one biasing element; and actuate the at least one biasing element of the directional steering tool based on the actuation timing.

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