System and method for controlling downhole behavior

Abstract

A drill bit for use in a downhole environment has an active element movable relative to the drill bit. The drill bit is rotated in the downhole environment and at least one downhole parameter is measured. The at least one downhole parameter is compared to a target parameter value, and the active element is selectively moved relative to the drill bit when the at least one downhole parameter exceeds a threshold of the target parameter value. Movement of the active element changes the proportion of weight on the active element compared to other cutting structures of the drill bit. Changing the proportion of weight can be used to reduce the cutting depth of the cutting structure and reduce or eliminate motor stalling or stick-slip behavior.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to and the benefit of U.S. Patent Application No. 62 / 724,436, filed on August 29, 2019, the entire contents of which are expressly incorporated herein by reference. Background Art

[0003] In underground drilling, a wellbore is bored into the underground formation using a drill bit. The drill bit is attached to the portion of a pipe that returns to the surface. The attached portion of the pipe is connected to other downhole tools, collectively known as the drill string. The portion of the drill string located near the bottom of the wellbore is called the bottom hole assembly (BHA). The BHA typically includes the drill bit, sensors, batteries, telemetry devices, and other devices located near the drill bit. A drilling fluid, sometimes called drilling mud, is provided to the drill bit from the surface through the pipes that form the drill string. The main function of the drilling fluid is to cool the drill bit and move the drill cuttings out of the bottom of the wellbore and upward through the annulus between the drill string and the wellbore wall. Typically, sensors are placed on the BHA or drill bit to measure downhole drilling parameters or other parameters. The sensors measure downhole parameters related to the behavior of the drill bit in the downhole environment. Summary of the invention

[0004] In some embodiments, a system for drilling a wellbore includes a bottom hole assembly including a cutting tool having a body. A movable element is connected to the body and is movable relative to the body at least partially in a longitudinal direction of the cutting tool. An actuator is coupled to the movable element and configured to move the movable element. At least one sensor is configured to measure at least one downhole parameter, and a processor communicates with the at least one sensor and the actuator to move the movable element based on a difference between the at least one downhole parameter and a target parameter.

[0005] In some embodiments, a system for drilling a wellbore includes a drill bit having a longitudinal axis, the drill bit being rotatable about the longitudinal axis. An active element is located in or on the drill bit and relative to the drill bit along the longitudinal axis. The system also includes an actuator that applies a force to the active element to move the active element; and at least one sensor that measures at least one downhole parameter. A processor of the system communicates with the at least one sensor and the actuator to move the active element to an extended state when the at least one downhole parameter exceeds an actuation threshold, and to move the active element to a retracted state when the at least one downhole parameter is within a deactivation threshold.

[0006] In some embodiments, a method of controlling a drill bit in a downhole environment includes lowering the drill bit into a downhole environment, wherein the drill bit has an active element movable relative to a longitudinal axis of the drill bit. The method also includes applying torque to the drill bit in the downhole environment, measuring at least one downhole parameter, and comparing the at least one downhole parameter to a target parameter value. When the at least one downhole parameter exceeds a threshold of the target parameter value, the active element moves relative to the drill bit. Moving the active element may apply a force to a formation or other workpiece cut by the drill bit.

[0007] This summary is provided to introduce some concepts that are further described 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 to help limit the scope of the claimed subject matter. Additional features and aspects of the embodiments of the present disclosure will be set forth herein, and in part will be apparent from the description, or may be learned by practicing the embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] In order to describe the manner in which the above-referenced features and other features of the present disclosure may be obtained, a more particular description will be given with reference to specific embodiments thereof illustrated in the accompanying drawings. For better understanding, in the various drawings, like elements have been denoted by like reference numerals. Although some of the drawings may be schematic or enlarged representations of concepts, at least some of the drawings may be drawn to scale. 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 drawings, in which:

[0009] Figure 1 is a schematic side view of a drilling system according to at least one embodiment of the present disclosure;

[0010] Figure 2 is a cross-sectional view of a downhole motor according to at least one embodiment of the present disclosure;

[0011] Figure 3 is a cross-sectional view of a drill bit according to at least one embodiment of the present disclosure;

[0012] Figure 4 is a cross-sectional view of another drill bit according to at least one embodiment of the present disclosure;

[0013] Figure 5-1 is a side view of a cutting element having a first depth of cut according to at least one embodiment of the present disclosure;

[0014] Figure 5-2 is a diagram showing a second cutting depth according to at least one embodiment of the present disclosure Figure 5-1 a side view of a cutting element;

[0015] Figure 5-3is a diagram showing a third cutting depth according to at least one embodiment of the present disclosure Figure 5-1 a side view of a cutting element;

[0016] Figure 6 is a flow chart illustrating a method of controlling a drill bit in a downhole environment according to at least one embodiment of the present disclosure;

[0017] Figure 7 is a flow chart illustrating another method of controlling a drill bit in a downhole environment according to at least one embodiment of the present disclosure;

[0018] Figure 8 is a flow chart illustrating yet another method of controlling a drill bit in a downhole environment according to at least one embodiment of the present disclosure;

[0019] Figure 9-1 is a side cross-sectional view of a drill bit having active elements in a downhole environment according to at least one embodiment of the present disclosure;

[0020] Figure 9-2 is a side cross-sectional view of the drill bit of FIG. 9 with an actuated active element in a downhole environment in accordance with at least one embodiment of the present disclosure;

[0021] Fig.10 is a graph showing the rotational speed of a drill bit versus actuation of a movable element according to at least one embodiment of the present disclosure; and

[0022] Fig.11 is a graph illustrating force applied by a moving element relative to displacement of the moving element according to at least one embodiment of the present disclosure. DETAILED DESCRIPTION

[0023] The present disclosure generally relates to devices, systems and methods for measuring downhole parameters. Other aspects of the present disclosure relate to moving active elements to adjust the behavior of a downhole tool based at least in part on the downhole parameters. More specifically, aspects of the present disclosure relate to dynamically using at least one active element positioned in a downhole cutting tool to apply forces to a formation and change the downhole performance of the downhole cutting tool.

[0024] Figure 1 An example of a drilling system 100 for drilling a formation 101 to form a wellbore 102 is shown. The drilling system 100 includes a drilling rig 103 for extending a drilling tool assembly 104 downwardly into the wellbore 102. The drilling tool assembly 104 includes a drill string 105 and a bottom hole assembly ("BHA") 106 attached to the downhole end of the drill string 105. A cutting tool such as an underreamer, a mill, or a drill bit 110 may be attached to the BHA 106 or included as part of the BHA 106. In the illustrated embodiment, the drill bit 110 is included at the downhole end of the BHA 106.

[0025] The drill string 105 may include multiple joints of drill pipe 108 connected end-to-end by tool joints 109. The drill string 105 transmits drilling fluid through a central hole and transmits rotational power from the drilling rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as short joints, short joints, etc. The drill pipe 108 provides a hydraulic passage through which the drilling fluid is pumped from the surface. The drilling fluid is discharged through a nozzle, jet or other orifice of a selected size in the drill bit 110 to cool the drill bit 110 and the cutting structure thereon and to lift drill cuttings out of the wellbore 102 while drilling.

[0026] The BHA 106 may include a drill bit 110 or other components. An exemplary BHA 106 may include additional or other components (e.g., coupled between the drill string 105 and the drill bit 110). Examples of other BHA components include drill collars, stabilizers, measurement while drilling (“MWD”) tools, logging while drilling (“LWD”) tools, downhole motors, reamers, face mills, hydraulic disconnects, jars, vibrators or damping tools, other components, or combinations thereof.

[0027] Typically, the drilling system 100 may include other drilling components and accessories, such as specialized valves (e.g., Kelly plugs, blowout preventers, and safety valves). Depending on the location of the components in the drilling system 100, the other components included in the drilling system 100 may be considered part of the drilling tool assembly 104, the drill string 105, or the BHA 106.

[0028] The drilling system 100 optionally includes one or more downhole motors 111 that rotate the drill bit 110. In addition to or in place of a surface rotary system (e.g., a top drive or rotary table in the drilling rig 103), a downhole motor 111 may be included. The downhole motor 111 may include a turbodrill, a progressive displacement motor (PDM), other mud motors driven by drilling fluid, an electric motor, or other motors located downhole at the surface. The downhole motor 111 is capable of providing torque to the drill bit 110 so as to rotate the drill bit to facilitate the removal of material from the formation 101. For example, a PDM mud motor is driven by the fluid pressure of the drilling fluid pumped downhole through the drill string 105, which is pushed through a series of chambers in the PDM mud motor to rotate the rotor of the PDM mud motor. The rotation of the rotor converts the pressure of the downhole flow and the drilling fluid into a torque that rotates the drive shaft. The drive shaft is connected to the drill bit 110 and rotates the drill bit. The turbodrill operates by causing the fluid to flow through a series of turbines and rotating the rotors in the turbines. The turbine rotor is attached to a shaft which in turn rotates the drill bit relative to the drill string.

[0029] The drill bit 110 in the BHA 106 can be any type of drill bit suitable for degrading downhole materials. For example, the drill bit 110 can be a drill bit suitable for drilling into the formation 101. Example types of drill bits used to drill into the formation are fixed cutter or traction drill bits, roller cone drill bits, or a hybrid of fixed and roller cone drill bits. In other embodiments, the drill bit 110 can be a mill used to remove metals, composites, elastomers, other materials, or combinations thereof downhole. For example, the drill bit 110 can be used with a whipstock to grind the casing 107 lining the wellbore 102. The drill bit 110 can also be a chip removal mill used to grind away tools, plugs, cement, other materials, or combinations thereof within the wellbore 102. Chips or other debris formed using a mill may be lifted to the surface or may fall into the wellbore.

[0030] In some embodiments, the drill bit 110 includes a movable element that is movable longitudinally relative to the drill bit to apply force to the formation and remove or change the proportion of the weight on bit (WOB) carried by the cutting structure of the drill bit 110. For example, assuming a constant WOB, moving the movable element axially downward may cause the movable element to bear a higher proportion of the weight and cause a reduced proportion of the weight to be distributed to the blades, cones, cutting elements on the blades or cones, or other cutting structures. Reducing the absolute value or the proportion of the weight on the cutting structure can reduce the engagement of the cutting elements with the formation (e.g., by reducing the depth of cut), thereby allowing the cutting elements (and therefore the drill bit 110) to rotate with less resistance from the formation. The weight on the cutting structure can be reported or regarded as a nominal value (e.g., 10,000 pounds force (44.5 kN)), or the weight on the cutting structure can be a relative number proportional to the WOB. For example, in some examples, prior to actuation of one or more active elements, the weight on the cutting structure may be between 80% and 100% of the WOB, and during actuation of one or more active elements, the weight on the cutting structure may be between 40% and 90% of the WOB.

[0031] Reducing weight on the cutting structure allows the depth of cut to be reduced and the drill bit to rotate more consistently or freely. Reduced rotational resistance can reduce or prevent adverse downhole dynamics, such as stick-slip or motor stalling. The active element can be moved relative to the drill bit by hydraulic pressure, pneumatic pressure, magnetic force, mechanical force, one or more electric motors, or by another actuation mechanism. The active element moves in response to a triggering event. For example, a triggering event may occur when one or more sensors provide information about a downhole parameter that one or more processors compare to a target parameter value or threshold. When a downhole parameter deviates from a target parameter value, exceeds or falls below an actuation threshold, or is otherwise used, a triggering event may occur and the processor may actuate the active element.

[0032] Stick-slip refers to the erratic movement of the drill bit 110 as the drill bit 110 rotates relative to the formation 101. Engagement of the cutting elements or other parts of the drill bit 110 with the formation 101, which thereby resists the rotation of the drill bit 110, slowing the rotation of the drill bit 110, is referred to as "sticking". Since torque may still be applied to the downhole system, sticking may result in a buildup of torque energy. At least some of the accumulated energy may be released quickly when the drill bit 110 generates and releases enough torsional energy in the BHA 106, drill pipe 108, or other parts of the drill string 105 to "slip" (which may include completely breaking away from the formation 101 or simply starting to remove material at a greater rate). The resulting slipping behavior may produce very high rotational speeds of the BHA 106 and drill bit 110, which may damage components of the BHA 106 or drill bit 110 and reduce the rate of penetration (ROP) of the drilling system 100 or the service life of the drill bit 110 or BHA 106.

[0033] Motor stall may occur when the rotational speed of the downhole motor 111 decreases and the motor stops rotating despite continuous fluid flow. Motor stall may be due to low differential pressure across the motor, resulting in insufficient torque produced by the motor and potentially causing damage to the downhole motor 111. Motor stall may also be the result of high differential pressure across the downhole motor 111. In some cases, motor stall may also damage the downhole motor 111 or create pressure waves in the drilling fluid column, which may damage the downhole motor 111 or other downhole components. Damage to the downhole motor 111 may include ruptured seals or damage to the stator or rotor, which makes the motor inefficient or unable to produce torque in response to fluid flow.

[0034] Figure 2 2 is a side cross-sectional view of an embodiment of a downhole motor 211 having a stator 213 and a rotor 215. The downhole motor 211 represents a PDM in which a fluid 217 flows through the mud motor 211 by moving a series of cavities 219 in a longitudinal direction. In a progressive displacement cavity motor 211, the outer surface of the rotor 215 is a single helix, while the inner surface of the stator 213 is a double helix. The displacement of the cavities 219 relative to the stator 213 causes the rotor 215 to rotate in an eccentric manner to turn a shaft 221. The shaft 221 can drive a drill bit (e.g., Figure 1 The drill bit 110) is used to remove material in a downhole environment.

[0035] When the drill bit experiences stick-slip behavior, the relative rotational speed rate of the rotor 215 and the stator 213 may decrease (during sticking) and increase (during sliding), resulting in a corresponding increase and decrease in fluid pressure, respectively. Although sudden increases and decreases in speed and pressure may damage the mud motor 211, if the mud motor 211 stalls and fluid pressure can only be established on one side of the mud motor 211, the stator 213 and the rotor 215 may suffer significant damage. The sensors 240-1, 240-2 can be located on either side of the mud motor 211 to measure uphole pressure (e.g., using a first sensor 240-1), downhole pressure (e.g., using a second sensor 240-2), or differential pressure (e.g., by measuring the difference between the pressures experienced by the first sensor 240-1 and the second sensor 240-2).

[0036] Figure 3 310 is a side cross-sectional view of an embodiment of a drill bit 310 according to some embodiments of the present disclosure. The drill bit 310 includes a drill bit body 312 having a longitudinal rotation axis 314 about which the drill bit 310 rotates. The drill bit body 312 has one or more blades 316 protruding therefrom, and a plurality of cutting elements 318 are positioned in and / or fixed to the blades 316. In some embodiments, the blades 316 include a primary blade and a secondary blade. For example, both the primary blade and the secondary blade extend from the radially outer edge of the drill bit 310 toward the longitudinal rotation axis 314, and the primary blade extends closer to the longitudinal rotation axis 314. In other words, the primary blade is longer in the radial direction. In the same or other embodiments, the cutting element 318 may be positioned on one or more rollers, or on both one or more blades 316 and one or more rollers. For example, in addition to or in lieu of one or more blades 316 protruding from the drill bit body 312, the drill bit body 312 may have at least one roller positioned thereon, to which the cutting element 318 is attached.

[0037] The cutting element 318 may include a superhard material. As used herein, the term "superhard" is understood to refer to a material known in the art having a hardness of about 1,500 HV (Vickers hardness (kg / mm 2)) or greater grain hardness. Such superhard materials may include, but are not limited to, diamond, polycrystalline diamond (PCD), hexagonal diamond (Lonsdaleite), cubic boron nitride (cBN), polycrystalline cBN (PcBN), binderless PCD or nano-polycrystalline diamond (NPD), Q-carbon, binderless PcBN, diamond-like carbon, boron oxide, aluminum manganese aluminum boride, metal boride, tungsten carbide, boron nitride carbon and other materials in the boron-nitrogen-carbon-oxygen system (whose hardness values ​​are all higher than 1500HV) and combinations of the above materials. In some embodiments, the superhard material may have a hardness value higher than 3,000HV. In other embodiments, the superhard material may have a hardness value higher than 4,000HV. In other embodiments, the superhard material may have a hardness value greater than 80HRa (Rockwell hardness A).

[0038] The drill bit profile of drill bit 310 includes various regions, including cone 320, nose 322, shoulder 324, and gage 326 regions. Figure 3 3, the area for a single blade 316 is shown, however, when rotated into a single plane, the complete cutting profile of the drill bit 310 includes each cutting element 318 of the drill bit 310. The cutting elements 318 may be positioned on any or each of the cone 320, nose 322, shoulder 324, and gage 326 areas to remove a portion of the earth from the formation (e.g., Figure 1 The cutting elements 318 engage with downhole workpieces (e.g., formations) to fracture, abrade, grind, shear, or otherwise mechanically remove material from the formations. Figure 3 The cutting elements 318 shown in the drawing include shear cutting elements, but other cutting element geometries may be used in place of or in combination with shear cutting elements. For example, a pointed or pointed cutting element such as a conical cutting element, a ridged cutting element, or a bullet nose cutting element may be employed in any or each area of ​​the drill bit profiles described herein.

[0039] With each rotation of the drill bit 310 about the rotation axis 314, the amount of material removed from the formation varies according to one or more downhole parameters. For example, downhole parameters include formation characteristics such as the hardness of the formation, the formation fluid pressure, or the uniformity of the formation that affect the volume and rate of material removal. In addition, downhole parameters include BHA characteristics, which include the rotation rate of the drill bit 310, the weight on bit (WOB) (i.e., the amount of force applied to the formation by the drill bit 310 in the longitudinal direction of the drill bit 310), the geometry and state of the cutting elements 318 and / or blades 316, the placement of the cutting elements 318 in the cutting profile, the drilling fluid flow rate (for flushing the cuttings from the blades 316), and other BHA characteristics. The interaction and combination of various formation characteristics and BHA characteristics can affect the volume and rate of material removal. For example, depending on the hardness of the formation, the exposure height, the WOB, etc., a heavier set of cutting elements (i.e., more cutting elements in the cutting profile) may produce more or less material removal.

[0040] The cutting elements 318 engaging the formation have a depth of cut (DOC), which is related to the amount of the cutting elements 318 that extend into the formation when cutting. The greater the amount of the cutting elements 318 that extend into the formation, the higher the DOC. Therefore, the DOC is a measure of how actively the drill bit 310 removes material from the formation with each rotation. The DOC may be affected by the geometry and material of the cutting elements. For example, a conical cutting element exhibits a different DOC than a shear cutting element. The DOC may be affected by the orientation of the cutting element. A conical cutting element will exhibit a different DOC because the apex of the cutting element is oriented at a different angle (e.g., inclination) relative to the surface of the downhole workpiece. The DOC is also affected by the formation material. For example, a cutting element exhibits a different DOC in formations with different hardness or porosity. The DOC may be further affected by the weight of the cutting structure. Therefore, by reducing the weight of the cutting structure, the DOC can be reduced even if the weight of the drill bit is constant. For example, by actuating the active element 328 of the drill bit 310 , the amount of WOB on the active element 328 may be increased while decreasing the proportion of WOB applied to the cutting element 318 .

[0041] ROP relates to the rate at which the drill bit 310 removes material from the formation and extends the length of the wellbore. Although a greater DOC may correspond to a greater ROP, an increase in DOC may also be associated with a greater amount of torque on the drill bit 310 and may slow the rotational speed of the drill bit 310, resulting in a decrease in ROP. In some cases, a sudden increase in DOC (e.g., due to a change in the formation or a sudden increase in WOB or weight on the cutting structure) may result in a sudden change in the torque of the drill bit 310 or a change in the rotational speed of the drill bit 310. In some cases, a change in torque or rotational speed is detrimental to the performance or service life of the drill bit 310 or cutting element 318. For example, an increase in DOC or torque on the drill bit, a decrease in the rotational speed of the drill bit, or a combination thereof may produce, or be the result of, stick-slip behavior or motor stalling. Changes in formation properties and / or BHA properties may further produce vibrations, vortices, or other adverse effects.

[0042] In some embodiments, a drill bit 310 according to the present disclosure is used to mitigate stick-slip, motor stall, or other undesirable downhole conditions or behaviors. For example, the drill bit 310 has an active element 328. The active element 328 is optionally positioned in the drill bit body 312 and is movable relative to the drill bit body 312. Figure 3 While the movable element 328 is shown extending from the surface of the drill bit and coaxial with the longitudinal rotation axis 314, the movable element 328 may be positioned at other locations and / or in other orientations in the drill bit 310. For example, the movable element 328 may be positioned in the blades 316 or in a flute between the blades 316. In other examples, the movable element 328 may move in an orientation that is angled with respect to the longitudinal rotation axis 314.

[0043] The active element 328 at least partially protrudes from the drill bit 310 to contact the formation. The active element 328 has an extended state and a retracted state, and optionally, when in the extended state and the retracted state, the active drill bit 328 protrudes from the surface of the drill bit 310, although to different degrees. In other embodiments, the active element 328 is recessed in the drill bit body 312 so that when in the retracted state, the active element 328 does not contact the formation. When actuated, the active element 328 is pushed to the extended state. The active element 328 can be actuated to multiple positions between the retracted state and the extended state. When actuated, the active element 328 can apply a force to the formation (this also includes increasing the proportional WOB), thereby changing the weight on the cutting structure, the DOC, or both. The force applied to the formation may reduce, stop or prevent stick-slip behavior, vibration, vortex, motor stall and other adverse effects.

[0044] In some embodiments, the active element 328 is biased toward or toward the face or body of the drill bit 310. For example, a biasing element 330, such as a spring, a compressible fluid, a magnet, or other mechanism that applies force to the active element 328 can be positioned in the drill bit 310 to bias the active element 328 away from the downhole end of the drill bit 310 having the formation and the cutting element 318. In the illustrated embodiment, this includes biasing the active element 328 in an uphole longitudinal direction coaxial with or parallel to the longitudinal axis 314. In other examples, the biasing element 330 can be positioned at other locations in the BHA (e.g., in a drill collar), can bias the active element 328 at an angle relative to the longitudinal axis 314 of the cutting tool, or have other positions or orientations. The active element 328 can be selectively actuated or activated to move the active element 328 relative to the drill bit body 312 (e.g., in a downhole longitudinal direction). Actuation of the active element 328 may cause the active element 328 to protrude from the face, blade, or body of the drill bit 310, or increase the amount by which the active element 328 protrudes from the drill bit 310 if it has already protruded beyond the face, blade, or body of the drill collar 310. By increasing the amount by which the active element 328 protrudes, the active element 328 applies a force (or an increased force) to the formation. The actuator controls the movement of the active element 328.

[0045] In some embodiments, the movable element 328 is moved relative to the drill bit 310 by hydraulic pressure from a hydraulic fluid 332. The actuator of the movable element 328 includes a valve 334 that at least partially controls the hydraulic pressure of the hydraulic fluid 332 from a fluid conduit 336 to a surface of the movable element 328 (or a drive element coupled to the movable element 328). In some embodiments, the hydraulic fluid 332 is a drilling fluid, and the fluid conduit 336 is a conduit from a surface drilling station that provides the drilling fluid to the drill bit 310 and the downhole environment. For example, the fluid conduit 336 may include a portion of a drill string (e.g., Figure 1 In other embodiments, and as with respect to Figure 4 Described in more detail, the hydraulic fluid is a fluid that is isolated from the drilling fluid (eg, a clean fluid).

[0046] In some embodiments, the valve 334 is a digital valve or a switch valve that allows the hydraulic fluid 332 to flow in an open state and prevents the hydraulic fluid 332 from flowing in a closed state. For example, the valve 334 can be moved to an open state and remain open (or moved to a closed state and remain closed) until the movable element 328 moves to the desired position. In other examples, the valve 334 repeatedly moves between the open state and the closed state to actuate the movable element 328 multiple times in succession, thereby moving the movable element to the desired position. In other embodiments, the valve 334 is a proportional valve that allows the valve to be moved to any of a variety of discrete or proportional states between the open state and the closed state. With a proportional valve, the amount of hydraulic fluid 332 that generates the force to move the movable element 328 can be changed (and has a certain ratio of the total flow and the actuation force in the open state), thereby allowing the movable element 328 to have multiple extension states.

[0047] The movement of the active element 328 may be controlled by a central processing unit (CPU) 338 or other processor in data communication with the valve 334 or other actuators (e.g., hydraulic pumps, electric motors, or other devices for moving the active element 328). In some embodiments, the CPU 338 is in data communication with one or more sensors 340 that measure one or more downhole parameters and provide information about the downhole parameters to the CPU 338. The CPU 338 controls the movement and / or position of the active element 328 based at least in part on the information received from the one or more sensors 340.

[0048] In some embodiments, at least one of the sensors 340 is positioned uphole of the drill bit 310. For example, the sensor 340 may be positioned uphole of the drill bit 310 to measure the WOB. In other embodiments, at least one of the sensors 340 is positioned within the drill bit 310. For example, the sensor 340 may be positioned in the drill bit body 312 to measure the rotational speed of the drill bit 310. In yet another embodiment, at least one sensor 340 is positioned downhole of a downhole motor. In yet another embodiment, at least one of the sensors 340 is positioned uphole of a downhole motor. For example, a pair of sensors 340 may be positioned on either longitudinal end of the downhole motor (e.g., on the uphole side and downhole side of the drill bit) to measure the torque of the downhole motor, the pressure differential across the downhole motor, the rotational speed of the downhole motor, or a combination thereof.

[0049] In some embodiments, at least one sensor 340 is a formation sensor. The formation sensor is configured to measure one or more formation characteristics, including formation hardness, formation homogeneity (in the case of a layered formation), formation porosity, formation integrity, formation temperature, formation fluid content, formation fluid pressure, or other characteristics of the formation. In other embodiments, at least one sensor 340 is a drilling system sensor. The drilling system sensor is configured to measure one or more drilling system or BHA characteristics, including rotational speed, torque, vibration, linear speed, temperature, drilling fluid pressure, hydraulic fluid pressure, or other performance of the drilling device. For example, the sensor can be a force sensor, a torque sensor, a pressure sensor, a linear speed sensor, a rotational speed sensor, or other type of sensor to measure movement of the drilling system or forces applied to the drilling system.

[0050] The CPU 338 may further include a hardware storage device 342 having instructions stored thereon or in data communication therewith. The instructions may be in the form of software or firmware code that, when executed by the CPU 338, causes the CPU 338 and / or the drill head 310 to extend or retract the active element 328, or to perform any method or portion of a method described herein. The hardware storage device 342 may include a platen-based storage device, a solid-state storage device, a RAM, or other persistent, non-transmitting type or long-term storage device.

[0051] Reference now Figure 4 In other embodiments, the hydraulic fluid 432 is a clean hydraulic fluid (e.g., not a drilling fluid provided from the surface or exiting through a nozzle of a drill bit). The hydraulic fluid 432 can be used exclusively for pressurization of the active element 428. For example, the fluid conduit 436 pressurizes the reservoir 435, and the valve 434 controls the flow from the fluid conduit 436 to the reservoir 435. In some embodiments, the valve 434 is controlled by a CPU 438, which communicates with one or more sensors 440 and a hardware storage device 442. When the valve 434 is closed, the valve limits and potentially prevents the fluid from the fluid conduit 436 from increasing the pressure on the reservoir 435. When the valve 434 is open, the valve 434 allows the fluid pressure from the fluid conduit 436 to pressurize the reservoir 435 and the hydraulic fluid 432, thereby applying a force to the active element 428.

[0052] In some embodiments, the pump 437 provides pressurization or additional pressurization to the hydraulic fluid 432 from the reservoir 435 toward the active element 428 to move the active element 428 relative to the drill bit body 412. For example, the pump 437 can be a single-acting piston pump, a double-acting piston pump, a rotary pump, a progressive displacement cavity pump, or other fluid pump. In other embodiments, the active element 428 can be moved by one or more electric motors (e.g., servomotors, stepper motors, linear actuators, worm gears, electromagnets, or other electronically controlled devices) to move the active element 428.

[0053] Figure 3 and 4 The sensors 340, 440 can measure or sample the downhole parameters at a sampling rate sufficient to allow the active elements 328, 428 to respond to changes in the downhole parameters. In some embodiments, the active elements 328, 428 respond to changes in the downhole parameters in real time or near real time. In some embodiments, the sampling rate is within a range having a lower limit, an upper limit, or a lower limit and an upper limit, including any one of 10Hz, 20Hz, 50Hz, 100Hz, 250Hz, 500Hz, 1000Hz, 5000Hz, 10000Hz; or any value therebetween. For example, the sampling rate can be greater than 10Hz. In other examples, the sampling rate is less than 10,000Hz. In other examples, the sampling rate is between 10Hz and 10,000Hz. In other examples, the sampling rate is between 20Hz and 5,000Hz, between 50Hz and 1,000Hz, or about 100Hz. In other examples, the sampling rate is less than 10Hz or greater than 10,000Hz.

[0054] Figures 5-1 to 5-3 It shows how the DOC varies with cutting element geometry and WOB (or weight of the cutting structure). Figure 5-1 525-1 . 100 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Figure 5-1Increasing the rake angle 529 reduces the aggressiveness of the cutting element 518-1 and, under the same loading conditions, may also reduce the DOC. For example, a cutting element 518-1 with a rake angle 529 of -10° has a face 531 that is 10° from perpendicular to the formation 501 and, under the same loading conditions, is less aggressive and has a lower DOC than a cutting element 518-1 with a rake angle 529 of -5° such that the face 531 is 5° from perpendicular to the formation 501. Therefore, under the same loading conditions, a cutting element with a lower negative rake angle 529 removes more material from the formation 501 than a cutting element with a higher negative rake angle 529.

[0055] and Figure 5-1 The related discussion assumes that face 531 is planar; however, face 531 can have other shapes. For example, the face of cutting element 531 can be concave at the cutting tip that engages structure 501. In the case where cutting element 531 is concave at the cutting tip, the cutting element can have an effective rake angle that is measured based on the geometry of the face, rather than the axis of the cutting element. Although the cutting element (as measured by the axis) has a negative rake angle, such a cutting element can have a positive effective rake angle. A positive effective rake angle can provide greater positivity and greater cutting depth under the same load conditions.

[0056] Figure 5-2 A cross section of a cutting element support 516 is shown with a first weight positioned on cutting element 525-1. The cutting element support 516 supports a second cutting element 518-2 having a first weight positioned on the cutting element 525-1. Figure 5-1 The first cutting element 518-1 shown has a different cutting element geometry. For example, the second cutting element 518-2 represents a conical, ridged or other pointed cutting element. Figure 5-1 Compared to the shearing first cutting element 518-1, the pointed second cutting element 518-2 can apply more pressure to the formation 501 with the same weight on the cutting element 525-1 due to the greater point load. The increased pressure can result in an increased second DOC 523-2 relative to the first DOC 523-1.

[0057] Figure 5-3 is a side cross-sectional view of first cutting element 518-1 having a second weight on cutting element 525-2. The second weight on cutting element 525-2 is less than the first weight on cutting element 525-1. When first cutting element 518-1 and formation 501 are the same, the reduced second weight on cutting element 525-2 may result in third DOC 523-3 being less than Figure 5-1 The first DOC 523-1 shown in FIG. Figures 5-1 to 5-3 Changing the DOC by changing the geometry of the cutting elements and the weight on the cutting elements (or the weight on the entire cutting structure) is shown, but the DOC may be affected by other factors related to the BHA or drill bit, or controlled by the drill bit operator. Examples include WOB, cutting element rake and side rake, cutting element density, cutting element type, blade density, other drilling system characteristics, formation composition changes, porosity, fluid pressure, temperature, stratification, or other formation or environmental conditions.

[0058] Figure 6 6 is a flow chart showing an example method 644 of controlling a downhole cutting tool in a downhole environment. In the illustrated embodiment, the method 644 includes lowering the cutting tool into the downhole environment at 646. Lowering the cutting tool into the downhole environment at 646 may also include lowering a BHA, a drill string, or one or more downhole tools into the downhole environment. The downhole environment may include a straight, deflected, or oriented wellbore, or a straight, deflected, or oriented portion. The cutting tool inserted into the wellbore may include a movable element movable relative to the cutting tool body. In some embodiments, the movable element is movable at least in a longitudinal direction, and as a result, the amount of the movable element protruding from the face or body of the cutting tool is selectively varied. The method 644 includes rotating the cutting tool at 648. In some embodiments, the drill bit is rotated by a top drive or a rotary table, and the torque for rotating the cutting tool is transmitted from the top drive to the cutting tool through the drill string. In other embodiments, the cutting tool is rotated by a downhole motor (e.g., a mud motor or a turbodrill) driven by a drilling fluid and positioned in a drill string within the downhole environment. Rotating the cutting tool at 648 may also include applying weight to the cutting tool. For example, the drill string and BHA may contribute to the weight being applied to the cutting tool, or a downhole tractor or other component may apply weight to the cutting tool.

[0059] Figure 6 The method 644 also includes controlling the movement of the movable element of the cutting element at 649. Figure 6 In the embodiment of the present invention, controlling the movement of the active element 649 is achieved at least in part by measuring at least one downhole parameter at 650, comparing at least one downhole parameter to a target parameter value at 652, and moving the active element relative to the cutting tool body at 654. In some embodiments, measuring at least one downhole parameter includes using at least one sensor (e.g., Figure 2 Sensor 240-1, 240-2, 240-3 or Figure 3 and 4 340, 440) and a processor (e.g., Figure 3 and 4The downhole parameters may be characteristics of the surrounding formation surrounding the cutting tool. For example, the downhole parameters may include formation characteristics, including formation hardness, formation homogeneity (in the case of layered formations), formation porosity, formation integrity, formation temperature, formation fluid content, formation fluid pressure, or other characteristics of the formation.

[0060] Controlling the movement of the active element at 649 optionally includes periodically, continuously, or iteratively repeating measuring at least a portion of at least one downhole parameter at 650, comparing at least one downhole parameter to a target parameter value at 652, or moving the active element relative to the cutting tool body at 654. For example, after or while moving the active element relative to the drill bit body at 654, the system may again measure at least one downhole parameter, compare the measured at least one downhole parameter to the target parameter value, and then not move the cutting element relative to the tool body (e.g., when there is not a sufficient difference between the measured parameter and the target parameter). In other examples, after comparing at least one downhole parameter to the target parameter value at 652, the system may again measure at least one downhole parameter when it is determined that the active element should not move relative to the cutting tool body.

[0061] The downhole parameter measured at 650 using at least one sensor may also or alternatively be a characteristic of the cutting tool, BHA, or drill string. For example, the downhole parameter may be a rotational speed of the cutting tool or BHA, WOB, ROP, a lateral vibration of the cutting tool, an axial vibration of the cutting tool, other accelerometer readings of the cutting tool or BHA, torque on the cutting tool, torque above the cutting tool, torque on a downhole motor rotor or shaft, DOC of one or more cutting elements, a pressure drop of drilling fluid across the cutting tool or downhole motor, or other characteristics of the cutting tool, BHA, or drill string. In other examples, the downhole parameter includes relative values, such as a rotational speed difference measured between a surface drive system (e.g., a top drive or a rotary table) and the cutting tool / BHA, a rotational speed difference between the cutting tool and a downhole motor drive shaft, or a torque difference between the cutting tool and the surface drive system.

[0062] In some embodiments, comparing at least one downhole parameter to a target parameter value at 652 includes calculating a difference between the at least one downhole parameter and the target parameter. For example, the processor receives a measured downhole parameter from a sensor and compares the value of the measured downhole parameter to the target parameter. The target parameter is optionally a dynamically calculated target value, and comparing the downhole parameter to the target parameter at 652 may include calculating a difference between the two. In some examples, the target parameter is a constant value. For example, a drill operator may set a target rotational speed of the drill bit (e.g., 120 revolutions per minute (RPM)), and some or all deviations from the target result may result in movement of the active element at 654.

[0063] In other examples, the target parameter is dynamically calculated. The target parameter of the dynamic calculation of the example is the rolling average of the rotation speed of the cutting tool. For example, the target parameter can be a 30-second rolling average of the rotation speed of the cutting tool measured. A sudden deviation from the 30-second rolling average (instantaneous or other rolling averages) can result in the movement of the active element at 654.

[0064] In some examples, the relative rotational speed rate of the cutting tool relative to the speed of the torque source (e.g., a top drive, a rotary table, a mud motor, or a turbodrill) can indicate the presence of stick-slip behavior. The target parameter can be the rotational speed rate of the torque source, and the measured downhole parameter can be the rotational speed rate of the cutting tool. If the measured downhole parameter does not exceed the target parameter value, method 644 may include returning to measuring the downhole parameter. In contrast, for example, if the drilling system detects that the parameter exceeds the target parameter value or has a significant difference from the target parameter (e.g., at least 5%, 10%, or 15% deviation between the rotational speed rates of the top drive or mud motor and the cutting tool at 652), the active element can be moved at 654. In another example, if a 10% deviation in the rotational speed rate of the cutting tool from the rotational speed rate of the torque source is detected at 652, the system can trigger a valve (e.g., Figure 3 and Figure 4 The valves 334, 434) are opened or closed proportionally to change the hydraulic pressure to the active element and move the active element by a corresponding amount. By moving the active element, the active element can reduce a portion of the DOC and / or WOB on the cutting structure and allow the drill bit to increase speed. For example, reducing the DOC can reduce the drag of the drill bit and allow the drill bit to more effectively transmit torque and recover speed. The increase in speed can dissipate any torsional energy in the drill string, thereby avoiding the sudden step change in the rate of rotation of the drill bit experienced during the slipping portion of the stick-slip behavior.

[0065] In some embodiments, different combinations of measured downhole parameters and associated target parameters may be used to control the active element at 654. For example, a measured deviation from a first target parameter (e.g., a 10% pressure drop across a downhole motor) combined with a measured deviation from a second target parameter (e.g., a 10% difference in bit rotational speed) results in more aggressive actuation of the active element than a measured 10% deviation from the first target parameter or a measured 10% deviation from the second target parameter.

[0066] At 654, movement of the active element relative to the cutting tool body may include moving the active element away from the cutting tool body or into the cutting tool body. Movement of the active element away from the cutting tool body and toward the formation may apply a force or increase the force applied by the active element to the formation. The force applied by the active element or the increased applied force may increase the portion of the WOB supported by the active element and reduce the portion of the WOB applied to other cutting structures as a whole, as well as the portion applied to individual cutting structures. Movement of the active element into the cutting tool body and away from the formation may remove the applied force or reduce the force applied to the formation. The reduction in the force applied by the active element may reduce the portion of the WOB supported by the active element and increase the portion of the WOB applied to the cutting element and the cutting structure.

[0067] In some embodiments, moving the active element relative to the drill bit body at 654 includes moving a valve between at least one open state and a closed state to change the hydraulic pressure applied to the active element. For example, opening the valve (or further opening the valve) to allow the flow of hydraulic fluid and / or increase the hydraulic pressure of the hydraulic fluid to move the active element away from the cutting tool body and toward the formation. In other examples, closing the valve restricts and potentially prevents the flow of hydraulic fluid, or reduces the hydraulic pressure of the hydraulic fluid used to move the active element into or toward the cutting tool body and away from the formation.

[0068] In other embodiments, moving the active element relative to the cutting tool body at 654 includes actuating a fluid pump to change the hydraulic pressure applied to the active element. For example, the pump can be a single-acting piston pump, a double-acting piston pump, a rotary pump, a progressive displacement cavity pump, or other fluid pump. In other embodiments, the active element can be moved by one or more electric motors, such as a servo motor, a stepper motor, a linear actuator, a worm gear, an electromagnet, or other electronic control device to move the active member. In other embodiments, the active element is moved relative to.

[0069] Figure 7 Another embodiment of a method 744 of controlling a cutting tool in a downhole environment is shown. Although the method 744 is described only in the context of a drill bit, the method is equally applicable to other types of cutting tools.

[0070] In the illustrated embodiment, method 744 includes lowering a drill bit into a downhole environment at 746 and rotating the drill bit relative to the formation at 748. Lowering the drill bit into the downhole environment and rotating the drill bit relative to the formation may be a process that is similar to Figure 6 Similar elements 646 and 648 are similar or identical.

[0071] Figure 7 The method 744 also includes controlling movement of an active element of the drill bit at 749. Controlling movement of the active element includes measuring at least one downhole parameter at 750, calculating a difference between the measured downhole parameter and a target parameter value at 751, comparing the difference to an actuation threshold at 753, and moving the active element relative to the drill bit body at 754. In some embodiments, measuring at least one downhole parameter includes using at least one sensor (e.g., Figure 2-4 The sensors 240-1, 240-2, 240-3, 340 and 440 and the processor (eg Figure 3 and 4 The downhole parameters may be characteristics of the surrounding formations around the drill bit, or characteristics of the drill bit or drill string, such as Figure 6 described.

[0072] In some embodiments, a difference between a measured downhole parameter and a target parameter value is calculated at 751, and the difference is compared to an actuation threshold at 753 to determine whether and when to move the active element at 754. For method 744, a valve and / or an actuation pump may be used to open to apply hydraulic pressure to the active element to move the active element when the measured downhole parameter exceeds or falls below a threshold, or when the difference between the measured downhole parameter and the target parameter exceeds a threshold. In contrast, there may be no response when the measured parameter is within a desired range or when the difference does not exceed a threshold. For example, if the actuation threshold is 10% off from the target parameter, the active element will be actuated when the difference between the measured downhole parameter and the target parameter value is calculated to be greater than 10% of the target parameter value.

[0073] In some embodiments, the target parameter value is a constant or fixed value on which the actuation threshold is based. For example, the target parameter value may be a drill bit rotational speed (e.g., 200 RPM), and the actuation threshold is a percentage deviation relative to the rotational speed (e.g., 10% or 20 RPM of the target parameter), which may create a target range (e.g., 180 to 220 RPM). Thus, a measured drill bit rotational speed outside the desired range (e.g., greater than 220 RPM or less than 180 RPM) may result in a difference between the measured downhole parameter and the target parameter value greater than the actuation threshold of 10%. In other examples, the target parameter value may be a torque on the drill bit. In such an example, where the actuation threshold is 15%, a drill bit torque that is directly measured or indirectly calculated and is 15% higher or 15% lower than the target drill bit torque results in actuation of the active element. The target torque parameter value of the drill bit can be within a range having a lower limit, an upper limit, or a lower limit and an upper limit, including any of the following: 5.0 kilopound-feet (klbf-ft) (6.8 kilonewton-meters (kN-m)), 7.5 klbf-ft ​​(10.2 kN-m), 10.0 klbf-ft ​​(13.6 kN-m), 12.5 klbf-ft ​​(16.9 kN-m), 15.0 klbf-ft ​​(20.3 kN-m ), 17.5 klbf-ft ​​(23.7 kN-m), 20.0 klbf-ft ​​(27.1 kN-m), 22.5 klbf-ft ​​(30.5 kN-m), 25.0 klbf-ft ​​(33.9 kN-m), 30.0 klbf-ft ​​(40.7 kN-m), 35.0 klbf-ft ​​(47.5 kN-m), 40.0 klbf-ft ​​(54.2 kN-m), or any value therebetween. For example, the target torque parameter value on the drill bit may be greater than 5.0 klbf-ft ​​(6.8 kN-m). In other examples, the target torque parameter value on the drill bit may be less than 25.0 klbf-ft ​​(33.9 kN-m) or less than 40.0 klbf-ft ​​(54.2 kN-m). In other examples, the target torque parameter value on the drill bit can be between 5.0 klbf-ft ​​(6.8 kN-m) and 25.0 klbf-ft ​​(kN-m), or between 5.0 klbf-ft ​​(6.8 kN-m) and 40.0 klbf-ft ​​(54.2 kN-m). In other examples, the target torque parameter value on the drill bit can be less than 5.0 klbf-ft ​​(6.8 kN-m) or greater than 40.0 klbf-ft ​​(54.2 kN-m).

[0074] In other embodiments, the target parameter value is determined as a historical value of the downhole parameter. For example, the target parameter value may be a cumulative average, median, or rolling average of the downhole parameter on which the actuation threshold is based. In at least one example, the target parameter value may be a rolling average of 15 seconds, 30 seconds, 60 seconds, 90 seconds, or 120 seconds (or other durations). As an example, the target parameter value may be a pressure difference across a downhole motor, although any suitable parameter value discussed herein may be used. If the actuation threshold is 15% off the target parameter value, the active element may move relative to the drill bit body when the measured pressure difference across the downhole motor deviates from the rolling average of the pressure difference across the downhole motor by an amount greater than 15% of the rolling average. In other examples, the target parameter value may be a 20-second (or other duration) rolling average of the drill bit rotation speed, where the drive threshold is 5%, 10%, 20%, or another percentage of the rolling average. In some examples, the measured value of the downhole parameter is an instantaneous value; however, in other examples, the measured value is an average value (e.g., a rolling average) over a duration that is less than the target parameter rolling average. Therefore, within the present disclosure, the measured value of the downhole parameter includes not only the raw data or measured value, but also the value calculated or derived from the raw data (e.g., an average value, a difference relative to another value, etc.). As an illustration, if the target parameter is a 20-second rolling average, the difference between the measured downhole parameter and the target parameter value can be calculated using the measured downhole parameter that is a 3-second or 5-second rolling average of the instantaneous measurement of the downhole parameter. In at least one example, the active element is actuated when the shorter rolling average of the drill bit rotation speed deviates from the longer rolling average of the drill bit rotation speed, pressure difference, torque, etc. by more than 5%, 10%, 15%, 20% (or some other percentage).

[0075] In at least one example, when drilling through a homogeneous formation at a constant WOB, the torque on the drill bit can be maintained approximately constant while drilling. The expected torque value can be a target parameter, and the measured torque can be a measured downhole parameter. If the torque on the drill bit increases above an actuation threshold (e.g., a specific value or a value based on a difference from that value), or drops below the actuation threshold, the active element may move downhole or in other directions, which will apply force to the formation (supporting a portion of the WOB) and reduce the weight of other components (e.g., the cutting structure), thereby limiting or even preventing the torque of the drill bit (from the formation) from overcoming the torque provided by the downhole motor, which may cause the motor to stall.

[0076] In some embodiments, comparing at least one downhole parameter to a target parameter includes comparing at least one downhole parameter to a plurality of thresholds for the downhole parameter. For example, a first threshold and a second threshold may each be associated with a first amount of movement and / or force of the active element and a second amount of movement and / or force of the active element, respectively. Thus, if the measured or calculated value exceeds the first threshold, the active element may be moved a first amount (or a first amount of force may be applied), but if the measured or calculated value exceeds both the first and second thresholds, the active element may be moved a second amount (or a second amount of force may be applied).

[0077] In some embodiments, the first threshold and the second threshold are nominal values ​​set by the drill operator or by the manufacturer or service provider of the drill. For example, the first threshold may be a rotational speed of 90RPM for the drill bit, and the second threshold may be a rotational speed of 80RPM for the drill bit. In other examples, the first threshold and the second threshold may involve rolling averages calculated over different time periods. For example, the first threshold may be when the 30-second rolling average of the drill bit rotational speed or torque is less than 80% of the torque source rotational speed or torque, and the second threshold may be when the 0.5-second rolling average is less than 60% of the torque source rotational speed or torque. Exceeding the first threshold may prompt the active element to apply less force to the formation, or a shorter actuation duration to allow the drill bit to accelerate and match the torque source, while exceeding the second threshold may indicate a more severe change in downhole behavior and prompt more active intervention in the active element in terms of scope or duration to limit or prevent motor stalling or stick-slip.

[0078] In another example, the measured values ​​or differences in the measured values ​​of multiple different downhole parameters can be used to determine when to actuate the active element. For example, a first threshold value can be associated with the measured torque applied to the drill bit and a second threshold value can be associated with the drill bit rotation speed. The measured torque applied to the drill bit can be within the first threshold value and the measured drill bit rotation speed can be within the second threshold value, but the composite deviation of the measured torque from the target torque value and the deviation of the measured drill bit rotation speed from the target drill bit rotation speed can cause the active element to be actuated.

[0079] In a particular example, a total deviation of 20% from a target parameter value may result in the active element being actuated. Different combinations of measured downhole parameters may result in a total deviation of 20% and an actuated active element. For example, a 10% deviation of a first downhole parameter combined with a 10% deviation of a second downhole parameter may result in the active element being actuated. In another example, a 15% deviation of a first downhole parameter combined with a 5% deviation of a second downhole parameter may result in the active element being actuated. In yet another example, a 20% deviation of a first downhole parameter combined with a 0% deviation of a second downhole parameter may result in the active element being actuated. In another example, a 2% deviation of a first downhole parameter combined with an 18% deviation of a second downhole parameter may result in the active element being actuated. As will be appreciated in view of the disclosure herein, more than two parameters may also be measured and compared to determine the total deviation for triggering actuation of an active element.

[0080] In some embodiments, the active element may be actuated when the total deviation of the measured downhole parameters exceeds an actuation threshold. For example, the active element may be actuated when the total deviation of the measured downhole parameters exceeds a 100% deviation relative to a threshold for each downhole parameter. In at least one example, the torque applied to the drill bit may have a 20% threshold. Additionally, the rotational speed of the downhole motor may have a 10% actuation threshold.

[0081] For example, if the torque measured at the drill bit deviates from the target parameter value by 50% of the actuation threshold (e.g., the measured torque is 10% deviation and the actuation threshold is 20% torque change), and the rotational speed of the downhole motor deviates from the target parameter value by 50% of the actuation threshold (e.g., the measured rotational speed is 5% deviation and the actuation threshold is 10% rotational speed change), then the active element can be actuated when the total deviation is 100% (i.e., torque deviation is 50% + rotational speed deviation is 50%). In other embodiments, the active element can be actuated by simultaneously comparing three or more measured downhole parameters to the target parameter value and / or threshold (e.g., relative rotational speed rate of the drill bit relative to the torque source, torque at the drill bit, pressure drop at the drill bit, formation hardness, change in formation hardness, formation porosity, formation fluid pressure, drilling fluid temperature, or other downhole parameters). In at least some embodiments, the CPU or other processor can use artificial intelligence or machine learning to review historical data from the run and predict when stick-slip behavior or motor stall may occur. For example, multiple data points related to downhole parameters, vibrations, vortices, fluid flow, cuttings transport, etc. can be evaluated and the information from those learnings can establish dynamic thresholds that predict future stick-slip behavior and motor stalls to activate the active element.

[0082] In some embodiments, calculating the difference between the measured downhole parameter and the target parameter and comparing the measured downhole parameter to the threshold value also includes comparing at least one downhole parameter to the target parameter. For example, a 10% deviation of the torque applied to the drill bit relative to the target parameter value of the desired torque may prompt the active element to begin moving, thereby starting to move the active element. In another example, calculating the difference between the measured downhole parameter and the target parameter may include comparing the measured downhole parameter to multiple thresholds. For example, the multiple thresholds may include a 10% deviation of the torque applied to the drill bit and a 50% deviation of the torque applied to the drill bit. If the measured downhole parameter is a 20% deviation of the torque applied to the drill bit relative to the target parameter value, the actuator may cause the movement of the active element to apply the first maximum force that the active element can apply (e.g., 20% of the maximum force). For example, for an active element that can apply 10,000 pounds of force (lbf) (44.5kN), the active element can apply 2,000lbf (8.9kN). However, if the torque applied to the drill bit exceeds a second threshold (e.g., a 50% deviation from the torque target parameter value), the active element may be actuated a different amount (e.g., 100% of the maximum force). Thus, for the active element described above, a full force of 10,000 lbf (44.5 kN) may be applied to the active element to limit or prevent motor stalling or stick-slip.

[0083] Method 744 also includes optionally moving the active element relative to the drill bit body at 754, similar to the method described with respect to Figure 6 Described. Movement of the active element relative to the drill bit body may include moving the active element away from the drill bit body or into the drill bit body. Movement of the active element away from the drill bit body and toward the formation may apply a force or increase the force applied to the formation. The force applied by the active element or the increased applied force may increase the portion of the WOB supported by the active element and reduce the portion of the WOB applied to the cutting element or other portions of the cutting structure. Movement of the active element toward or into the drill bit body and away from the formation may remove the applied force or reduce the force applied to the formation. The reduction in the force applied by the active element may reduce the portion of the WOB supported by the active element and increase the portion of the WOB applied to the cutting structure.

[0084] In some embodiments, moving the active element relative to the drill bit body at 754 includes moving a valve between an open state and a closed state to change the hydraulic pressure applied to the active element. For example, opening the valve allows the flow of hydraulic fluid and / or increases the hydraulic pressure of the hydraulic fluid to move the active element away from the drill bit body and toward the formation. In other examples, closing the valve restricts and / or prevents the flow of hydraulic fluid and / or reduces the hydraulic pressure of the hydraulic fluid to move the active element into the drill bit body and away from the formation.

[0085] In other embodiments, moving the movable element relative to the drill bit body at 754 includes actuating a fluid pump to change the hydraulic pressure applied to the movable element. For example, the pump can be a single-acting piston pump, a double-acting piston pump, a rotary pump, a progressive displacement cavity pump, or other fluid pump. In other embodiments, the movable element can be moved by one or more motors, such as a servo motor, a stepper motor, a linear actuator, a worm gear, an electromagnet, or other electronically controlled device to move the movable element.

[0086] In addition, and as regards Figure 6 As discussed, controlling movement of the active element of the drill bit at 749 may include continuously, iteratively, or repeatedly measuring at least one downhole parameter at 750, calculating a difference between the measured downhole parameter and a target parameter value at 751, comparing the difference to an actuation threshold at 753, and moving the active element at 754. Thus, if the comparison at 753 does not result in movement of the active element at 754, the method 744 may include measuring the downhole parameter 750 again and continuing. Figure 7 Shown and relative to Figure 7 Similarly, if the active element moves at 754, the downhole parameter can be measured again at 750 and the difference calculated at 751. With a sufficient difference determined when comparing at 753, the active element can continue to be maintained in the moved position or active position at 754. In another example, the comparison of the difference to the threshold at 753 can be a comparison to a deactivation threshold, and in the event of a sufficient difference (or not sufficient difference), the movement of the active element relative to the drill bit body can be to retract the active element from the active position at 754.

[0087] Figure 8 844 is a flow chart illustrating another embodiment of a method 844 for controlling a cutting tool in a downhole environment. The cutting tool may include any suitable downhole cutting tool, including a drill bit. Figure 8 In the illustrated embodiment, method 844 includes lowering the drill bit into a downhole environment at 846 and rotating the drill bit relative to the formation at 848. These actions are similar to or the same as those performed relative to the formation. Figure 6 and Figure 7 Describe the corresponding action.

[0088] Figure 8 The method 844 further includes controlling movement of an active element of the drill bit at 849. Controlling movement of the active element includes measuring at least one downhole parameter at 850, calculating a difference between the measured downhole parameter and a target parameter at 851, comparing the difference to an actuation threshold at 853, and moving the active element relative to the drill bit body to apply a force to the formation at 854, similar to the method described with respect to Figure 7In some embodiments, measuring at least one downhole parameter includes using a processor (e.g. Figure 3 , 4 At least one sensor (e.g., Figure 2-4 Sensors 240-1, 240-2, 240-3, 340, 440). Figure 6 and Figure 7 As described, the downhole parameters may be properties of the surrounding formation around the drill bit or properties of the drill bit or drill string.

[0089] In some embodiments, the active element may be moved toward the extended state to apply force to the formation for a fixed duration. For example, moving the active element at 854 includes moving the active element at an actuation rate and / or at an actuation duration. In some embodiments, the actuation rate is fixed, while in other embodiments, the actuation rate varies according to a measured downhole parameter, a deviation from a target parameter, an amount by which a measured downhole parameter exceeds a threshold, or a combination thereof. For example, the actuation rate may be greater when the measured downhole parameter is farther from the target parameter than when the measured downhole parameter is closer to the target parameter. As an example, the rate at which the active element may move toward the extended state is greater when the measured downhole parameter deviates from the target parameter by 50% than when the measured downhole parameter deviates from the target parameter by 20%. In other examples, the rate at which the active element moves toward the extended state is greater when the first measured downhole parameter deviates from the first target parameter by 20% than when the second measured downhole parameter deviates from the second target parameter by 20%. In other examples, the rate at which the active element moves toward the extended state is greater when the first measured downhole parameter exceeds a first threshold than when the second measured downhole parameter exceeds a second threshold that is the same as, less than, or greater than the first threshold.

[0090] In some embodiments, the actuation duration is fixed. For example, each instance of active element actuation may have an actuation duration of 0.05 seconds, 0.1 seconds, 0.25 seconds, 0.5 seconds, 1.0 seconds, 1.5 seconds, 2.0 seconds, 3.0 seconds, 5.0 seconds, 10 seconds, or other lengths of actuation duration, or anything in between. In other embodiments, the actuation duration may vary based on a measured downhole parameter, a deviation from a target parameter, an amount by which a measured downhole parameter exceeds a threshold, or a combination thereof. For example, the duration for which an active element may remain in an extended state or another actuation state is longer when a first measured downhole parameter triggers actuation of the active element than when a second measured downhole parameter triggers actuation of the active element. The time for which an active element remains actuated (e.g., protruding a maximum distance from the drill bit and / or applying a maximum force to the formation) is longer when a pressure drop across the mud motor is measured to exceed a first threshold than when a measured drill bit rotation speed exceeds a second threshold.

[0091] In another example, the duration that the active element remains in the extended state or another actuated state is longer when the measured downhole parameter is farther from the target parameter than when the measured downhole parameter is closer to the target parameter. For example, if the measured pressure drop across the mud motor changes by 80% in 0.5 seconds, the active element can remain actuated for a longer duration than another actuation triggered by a second measured downhole parameter (e.g., a change in formation fluid pressure). This may be because the high pressure drop can be considered to generate an associated pressure wave in the drilling fluid, which is likely to cause damage to the mud motor as it moves in the fluid conduit, and the pressure wave may spend more time in the drilling fluid to stabilize to limit or prevent damage to the mud motor.

[0092] In other embodiments, the active element may be moved to the extended state and force applied (reducing the weight ratio on the other cutting structure) until one or more downhole parameters are measured to be within the deactivation threshold. Figure 8 The method 844 includes comparing the difference to a deactivation threshold at 855 and moving the active element relative to the drill bit body to reduce the force applied by the active element to the formation at 867. After actuation, the active element can be retracted toward a retracted state when the condition triggering actuation or other conditions associated with stick-slip behavior or motor stalling are alleviated.

[0093] In some embodiments, when the difference between the measured downhole parameter and the target parameter value is compared to the deactivation threshold and the difference is less than the deactivation threshold, the active element is maintained in the actuated state and retracted. For example, when the measured downhole parameter exceeds the actuation threshold, the active element may be actuated and maintained in the actuated state until the measured downhole parameter changes and the difference is measured to be within the deactivation threshold.

[0094] In some examples, the activation threshold and the deactivation threshold are the same. For example, if the measured downhole parameter is drill bit rotation speed, the activation threshold may be a 20% change from a rolling average of the drill bit rotation speed. When the measured drill bit rotation speed is less than 80% of the rolling average, the active element will be activated. Figure 8 As shown, even after the active element is moved at 854, method 844 includes continuing to measure the downhole parameter at 850, calculating the difference between the measured downhole parameter and the target parameter value at 851, and comparing the difference to the actuation threshold at 853. If the calculated difference becomes less than the 20% threshold (i.e., the target is greater than 80% of the rolling average), the active element can be moved relative to the drill bit body and fully or partially retracted at 857 to reduce the force applied to the formation. In such an embodiment, the actuation threshold can serve as both an actuation threshold and a deactivation threshold. This operation is also applicable to Figure 6 and 7The method of claim 1, wherein moving the active element relative to the drill bit body at 654, 754 may include extending the active element in response to the measured parameter or calculated difference exceeding the target parameter value or threshold, or retracting the active element in response to the measured parameter or calculated difference no longer exceeding the target parameter or threshold. Additionally, in some embodiments, the active element is actuated when the measured drill bit rotation speed is greater than 120% of the rolling average, and the active element remains in the actuated state until the drill bit rotation speed is less than 120% of the rolling average.

[0095] In other examples, the actuation threshold and the deactivation threshold are different so that the movement of the active element exhibits hysteresis. For example, the measured downhole parameter may be drill bit rotation speed, the actuation threshold may be a 20% change from a rolling average of the drill bit rotation speed, and the deactivation threshold may be a 10% deviation from the rolling average of the drill bit rotation speed. In such an example, when the drill bit rotation speed is measured to be less than 80% of the rolling average or greater than 120% of the rolling average (i.e., differing from the rolling average by at least 20%), the active element is actuated, and the active element remains in the actuated state until the drill bit rotation speed returns to greater than 90% of the rolling average or less than 110% of the rolling average.

[0096] In some embodiments, repeated actuation may cause damage to the active element and / or the hydraulic or other power device that moves the active element over time. Therefore, hysteresis can extend the service life of the active element by actuating the active element until the measured downhole parameter is closer to the target parameter value than the actuation threshold. For example, when the actuation threshold and the deactivation threshold are the same, the measured downhole parameter can remain close to the threshold, resulting in repeated and rapid actuation of the active element. In some embodiments, the method of the present disclosure may also include counting the number of activations within a given period of time. If the number of activations exceeds the activation count threshold, the actuation threshold, the deactivation threshold, the dynamic variable (e.g., the rolling average length or the average length of the measured value) may be adjusted to reduce the number of activations. In another embodiment, if the number of activations exceeds the activation count threshold, the actuator may be placed in sleep mode. For example, the CPU may stop processing measurements for a specific period of time until the tool returns to the ground, or until a signal to wake up from sleep mode is received. The activation count threshold may be any suitable value, but in some embodiments may include more than two activations per minute, more than three activations per minute, more than five activations per minute, more than ten activations per five minutes, or other values, or any value in between.

[0097] In some embodiments, the deactivation threshold may change as a function of the amount of actuation over a period of time or drilling distance. The deactivation threshold may become closer to the target parameter value, which may cause the active element to remain actuated until the measured downhole parameter is closer to the target parameter. In the previous example, where the actuation threshold is a 20% change from the rolling average of the drill bit rotation speed and the deactivation threshold is a 10% deviation from the rolling average of the drill bit rotation speed, the deactivation threshold may change. For example, when the active element is actuated more than, for example, four times in one minute, the deactivation threshold may change from the rolling average of the drill bit rotation speed by 7.5% or 5%. Therefore, the active element will remain actuated for a longer time until the measured drill bit rotation speed is within 7.5% or 5% of the rolling average of the drill bit rotation speed. Restoring the downhole parameter to a value closer to the target parameter can move the downhole parameter further away from the actuation threshold and limit the number of required actuations.

[0098] In addition, the active element can move toward the retracted state at a moving rate that is the same or different from the actuation rate. In some embodiments, the active element is actuated at the actuation rate and moves toward the extended state or other actuation states, and the active element shrinks toward the retracted state at a contraction rate. An actuation rate greater than the retraction rate allows the active element to quickly respond to adverse conditions measured by one or more sensors, while a relatively slow retraction rate allows the drill bit to reengage with the formation without causing the same conditions that promote actuation. For example, in response to a rapid increase in torque on the drill bit, the active element can extend to the extended state in less than 0.1 seconds to quickly react and limit and / or prevent the motor from stalling or sticking. The active element can then be retracted to the retracted position within 2.0 seconds to engage the drill bit and the cutting element of the drill bit with the formation without the cutting element contacting the same surface of the formation and generating another sudden increase in torque on the drill bit.

[0099] Figure 8 The method 844 is at least partially an iterative process and can be used to repeatedly move the active element to increase and decrease the force applied by the active element to the formation or other workpiece. Figure 7 As described, controlling movement of the active element of the drill bit at 849 may include continuously, iteratively, or repeatedly measuring at least one downhole parameter at 850, calculating a difference between the measured downhole parameter and a target parameter value at 851, comparing the difference to an actuation threshold at 853, and moving the active element at 854. The measurement at 850 may be ongoing so that movement of the active element at 854 may result even after other measurements do not trigger movement of the active element.

[0100] Additionally, at 855, when comparing the measured at least one downhole parameter to the deactivation threshold, method 844 may include moving the active element at 857, or alternatively may not move the active element. In either case, method 844 may include returning to controlling movement of the active element of the drill bit at 849 and measuring at least one downhole parameter at 850, and continuing to compare the measured difference to the activation threshold or the deactivation threshold to move the active element accordingly. Again, for simplicity, Figure 8 After comparing the difference to the activation threshold at 855, the method returns to controlling movement of the active element of the drill bit at 849. However, in some embodiments, when the active element has been moved to apply a force (or increased force) to the workpiece at 855, the method may not compare the difference between the measured downhole parameter and the target parameter to the actuation threshold at 853. For example, when a switching valve is used to control movement of the active element and the valve is in a position corresponding to an extended active element applying force to the workpiece, the method 844 may skip actions 853 and 854, and thus directly compare the calculated difference to the deactivation threshold at 855.

[0101] Figure 9-1 9 is a side cross-sectional view of an embodiment of a drill bit 910 having active elements 928 in a downhole environment. The drill bit 910 removes material from the formation 910 (or casing, downhole fish, or other workpiece) as the drill bit 910 rotates relative to the formation / workpiece 901. For a given WOB, a portion of the WOB is applied to a cutting structure, which includes a cutting element 918. The cutting element 918 positioned on the blades 916 of the drill bit 910 engages the formation 901, and the weight on the cutting structure can change the DOC of the cutting element 918 of the drill bit 910.

[0102] At least one sensor 940 positioned in the drill bit 910, BHA, or drill string can measure at least one downhole parameter. The active element 928 can remain in a retracted state (i.e., positioned proximate to and / or within the drill bit body 912) during drilling operations until a downhole parameter measured by the sensor 940 exceeds a threshold, deviates from a target parameter, or otherwise measures a value that triggers actuation, as described herein. In some embodiments, the active element 928 includes a superhard element 956 at the downhole end of the active element 928. For example, the active element 928 may include a pointed cutting element attached to the downhole end. When the active element 928 is in a retracted or deployed state, the pointed cutting element can engage the formation 901 and assist the drill bit in tracking. When the active element 928 contacts the formation 901, the superhard element 956 can increase the operating life and corrosion resistance of the active element 928. Although Figure 9-1The superhard element 956 is shown extending outwardly of the face of the drill bit body 912 in the retracted state, and in other embodiments, the superhard element 956 or other downhole lowermost portion of the active element 928 may be flush with or recessed in the drill bit face in the retracted state.

[0103] Figure 9-2 After actuating the active element 928 Figure 9-2 9. The active element 928 can be moved away from the drill bit body 912 toward the formation 901 to apply force to the formation 901. In some embodiments, the active element 928 moves a distance represented by the stroke 958. The stroke 958 represents the range of movement and the distance from the active element 929 to the retracted position (see Figure 9-1 ) moves to the extended position ( Figure 9-2 ). The stroke 958 can be a range having a lower limit, an upper limit, or a lower and upper limit, including any of the following: 0.1 inches (0.25 centimeters), 0.25 inches (0.63 centimeters), 0.5 inches (1.27 centimeters), 0.75 inches (1.91 centimeters), 1.0 inches (2.54 centimeters), 1.25 inches (3.18 centimeters), 1.5 inches (3.81 centimeters), 1.75 inches (4.45 centimeters), 2.0 inches (5.08 centimeters), or any value therebetween. In some examples, the stroke 958 is greater than 0.1 inches (0.25 cm). In other examples, the stroke 958 is less than 2.0 inches (5.08 centimeters). In other examples, the stroke 958 is between 0.1 inches (0.25 cm) and 2.0 inches (5.08 cm), between 0.25 inches (0.63 cm) and 1.75 inches (4.45 cm), or between 0.5 inches (1.27 inches) and 1.5 inches (3.81 cm). In at least one example, the stroke 958 is approximately 1.0 inches (2.54 cm). In other examples, the stroke 958 is less than 0.1 inches (0.25 mm) or greater than 2.0 inches (5.08 cm).

[0104] In some embodiments, the activated or extended active element 928 is axially offset from the downhole tip of the cutting structure (i.e., the distance from the downhole tip of the active element 928 to the downhole-most point of the cutting element 918 or blade 916) by a displacement distance 964. In some embodiments, the displacement distance 964 is within a range having a lower limit, an upper limit, or a lower limit and an upper limit, including any of the following: 0.1 inches (0.25 cm), 0.25 inches (0.63 cm), 0.5 inches (1.27 cm), 0.75 inches (1.91 cm), 1.0 inches (2.54 cm), 1.25 inches (3.18 cm), 1.5 inches (3.81 cm), 1.75 inches (4.45 cm), 2.0 inches (5.08 cm), 2.5 inches (6.35 cm), 3.0 inches (7.62 cm), 5.0 inches (12.7 cm), or any value therebetween. In some examples, the displacement distance 964 is greater than 0.1 inches (0.25 centimeters). In other examples, the displacement distance 964 is less than 2.0 inches (5.08 centimeters) or less than 5.0 inches (12.7 centimeters). In other examples, the displacement distance 964 is between 0.1 inches (0.25 centimeters) and 5.0 inches (12.7 centimeters). In other examples, the extended displacement 964 is between 0.25 inches (0.63 centimeters) and 3.0 inches (7.62 centimeters), between 0.5 inches (1.27 centimeters) and 2.5 inches (6.35 centimeters), or between 0.5 inches (1.27 centimeters) and 1.75 inches (4.45 centimeters). In at least one example, the extended displacement 964 is approximately 1.0 inches (2.54 centimeters). In other examples, the extended displacement 964 is less than 0.1 inches (0.25 centimeters) or greater than 5.0 inches (12.7 centimeters).

[0105] In some embodiments, the active element 928 is configured to apply a force to the formation within a range having a lower limit, an upper limit, or both, including any of 500 pounds (lbs.) (2.22 kilonewtons (kN)), 1,000 lbs. (4.45 kN), 2,000 lbs. (8.90 kN), 4,000 lbs. (17.8 kN), 6,000 lbs. (26.7 kN), 8,000 lbs. (35.6 kN), 10,000 lbs. (44.5 kN), 15,000 lbs. (66.8 kN), 20,000 lbs. (89.0 kN), 30,000 lbs. (133.5 kN), or any value therebetween. In some examples, the force is greater than 500 lbs. (2.22 kN). In other examples, the force is less than 30,000 lbs. (133.5 kN). In other examples, the force is between 500 lbs. (2.22 kN) and 30,000 lbs. (133.5 kN), between 1,000 lbs. (4.45 kN) and 15,000 lbs. (66.8 kN), or between 2,000 lbs. (8.90 kN) and 20,000 lbs. (89.0 kN). In at least one example, the force is about 10,000 lbs. (44.5 kN). In other examples, the force is less than 500 lbs. (2.22 kN) or greater than 30,000 lbs. (133.5 kN). In at least one example, the force is at least 10%, at least 20%, or at least 30% of the WOB (eg, to reduce the total weight on another cutting structure by at least 10%, at least 20%, or at least 30%, respectively, of the WOB).

[0106] In some embodiments, the active element 928 moves from the retracted state to the actuated state (e.g., the extended state) with an actuation time within a range having an upper limit value, a lower limit value, or an upper limit value and a lower limit value including any of the following: 0.1 seconds, 0.2 seconds, 0.3 seconds, 0.4 seconds, 0.6 seconds, 0.8 seconds, 1.0 seconds, 1.5 seconds, 2.0 seconds, or any value therebetween. In some examples, the actuation time may be greater than 0.1 seconds. In other examples, the actuation time may be less than 2.0 seconds. In other examples, the actuation time may be less than 1.0 seconds. In other examples, the actuation time may be less than 0.5 seconds. In at least one example, the actuation time may be less than 0.1 seconds.

[0107] In some embodiments, the active element 928 moves from the actuated state (e.g., the extended state) to the retracted state with a retraction time within a range having an upper limit value, a lower limit value, or an upper limit value and a lower limit value including any of the following: 0.1 seconds, 0.2 seconds, 0.3 seconds, 0.4 seconds, 0.6 seconds, 0.8 seconds, 1.0 seconds, 1.5 seconds, 2.0 seconds, 4.0 seconds, 6.0 seconds, 8.0 seconds, 10.0 seconds, or any value therebetween. In some examples, the retraction time may be greater than 0.1 seconds. In other examples, the retraction time may be less than 10.0 seconds. In further examples, the retraction time may be less than 5.0 seconds, less than 2.0 seconds, or less than 1.0 seconds. In some embodiments, the retraction time is the same as the actuation time. In other embodiments, the retraction time is less than the actuation time. In other embodiments, the retraction time is greater than the actuation time. For example, the active element 928 may be actuated faster than the active element retracts. A slower retraction may allow the WOB and / or torque on the drill bit 910 to increase more gradually, thereby limiting and / or preventing further stick-slip behavior or motor stalling.

[0108] In order to apply force to the formation without damaging the active element 928 or penetrating the formation 901 too quickly to reduce the WOC on the blades of the drill bit, it may be necessary to distribute the load on the active element 928 to a larger area. In some cases, the area over which the load is distributed on the active element 928 is related to the active element diameter 960. For example, a larger active element diameter 960 (i.e., the diameter or width of the cutting end of the active element 928) can provide a larger area and allow the active element 928 to apply greater force to formations with lower hardness or greater porosity than a small diameter active element 928 (e.g., by reducing point loads). In other examples, a smaller active element diameter 960 and a cutting end of the active element 928 can allow the active element 928 to occupy less of the drill bit 910, thereby giving the drill bit 910 a more aggressive cutting profile and greater ROP. In some embodiments, the active element diameter 960 is related to the drill bit body diameter 962 by a body diameter ratio within a range having a lower limit value, an upper limit value, or a lower limit value and an upper limit value including any of the following: 2%, 4%, 6%, 8%, 10%, 15%, 20%, 25%, 35%, or any value therebetween. In some examples, the body diameter ratio is greater than 2%. In other examples, the body diameter ratio is less than 35%. In other examples, the body diameter ratio is between 2% and 35%, between 4% and 25%, or between 2% and 15%. In specific examples, the body diameter ratio is about 5%, about 10%, or about 12.5%. In other example embodiments, the body diameter ratio is less than 2% or greater than 35%.

[0109] In the same or other embodiments, the active element diameter 960 (or the width of a non-cylindrical active element) is related to the gage diameter 965 of the drill bit 910, and its gage diameter ratio is in a range having a lower limit value, an upper limit value, or a lower limit and an upper limit value including any of the following: 1%, 2%, 5%, 10%, 15%, 20%, 25%, or any value therebetween. In some examples, the gage diameter ratio is greater than 1%. In other examples, the gage diameter ratio is less than 25%. In other examples, the gage diameter ratio is between 1% and 25%, between 2% and 20%, or between 3% and 12%. In specific examples, the gage diameter ratio is about 3%, about 8.5%, or about 10%. In other example embodiments, the gage diameter ratio is less than 1% or greater than 25%.

[0110] Fig.10 is to show that there are Figure 9-1 and 9-2 Graph 1066 of an exemplary use of a cutting tool with an active element having an activation and deactivation hysteresis behavior of the active element. The graph shows the instantaneous rotational speed of the drill bit 1068 measured over time and a first average value, which in the illustrated graph 1066 is a 0.5 second rolling average value 1070. As discussed herein, the rolling average value 1070 can be used in some embodiments as a measured downhole parameter value for controlling activation of one or more active elements on a cutting tool.

[0111] The first average value 1070 can be compared to a second average value, which is a rolling average value for 30 seconds in the graph 1066. When the first average value 1070 drops below the actuation threshold value 1072 based on the second average value at t1 (e.g., exceeds 20% of the difference from the second average value), the valve is opened to actuate the active element. At t2, the valve remains open and the active element is actuated until the first average value 1070 is greater than the deactivation threshold value 1074 (e.g., less than 10% of the difference from the second average value). After closing the valve and deactivating the active element, the rotational speed of the drill bit 1068 begins to decrease again, the first average value 1070 drops below the actuation threshold value 1072 at t3, and the valve is opened again to re-activate the active element until the rotational speed of the drill bit 1068 is again above the deactivation threshold value 1074 at t4 (e.g., less than 10% of the difference from the second average value).

[0112] Repeated and / or rapid actuation of the active element may wear the active element or the area of ​​the drill bit body surrounding the active element, or deplete the downhole power source. During operation in challenging environments or drilling conditions, the active element may be actuated several times per minute. When the active element is actuated beyond the actuation limit within a period of time, such as three times in 30 seconds, four times in one minute, five times in one minute, eight times in 90 seconds, ten times in two minutes, or other number of actuations within a period of time, the active element may enter a sleep mode as described herein. In at least some embodiments, the sleep mode limits the wear of the active element, increases the operating life of the active element, or increases the operating life of the downhole power source.

[0113] When in sleep mode, the active element can remain stationary in a retracted position or an extended position relative to the drill bit body. In some examples, the active element moves to the retracted position when entering sleep mode. In other examples, the active element maintains a constant axial position relative to the drill bit body when entering sleep mode, even if the axial position is not the retracted position. In some embodiments, the sleep mode has a duration of at least one minute. In other embodiments, the sleep mode has a duration of at least three minutes. In other embodiments, the sleep mode has a duration of at least five minutes. In other embodiments, the sleep mode lasts until the tool is pulled to the surface or a wake-up signal is received. The wake-up signal can be sent from the surface or from downhole. For example, the MWD can monitor downhole conditions and determine when to wake up the active element. In some embodiments, the sleep mode also disables the measurement of downhole parameters, while in other embodiments, downhole measurements of one or more downhole parameters can continue during sleep mode. In at least some embodiments, when the downhole tool enters sleep mode, a signal can be sent to the surface, the MWD, or another location to warn the operator or tool of the sleep mode.

[0114] In some embodiments, the relationship between the distance that the active element moves and the force used to move the active element that distance within the formation is nonlinear. Fig.111176 is a graph 1178 showing an example relationship of displacement of an active element relative to the force used to move the active element and obtain the displacement. The initial movement of the active element from the retracted position may apply little or no force to the formation because the active element may not be in contact with the formation, or the formation within the cone of the drill bit may be loosely consolidated and / or unsupported. Therefore, as reflected by the inconsistent force applied during the initial movement of the active element, the formation may crack or break when in contact with the active element as the active element moves toward the actuation position. The active element may continue to move toward the actuation position and apply increasing force as it further penetrates and / or compresses the formation. Curve 1178 shows a typical exponential relationship, in which increasingly larger displacements utilize exponentially increasing forces. In particular, graph 1176 shows a generally flat or linear relationship for the first 0.4 inches (1.02 cm), after which the slope transitions and increases sharply. For example, in graph 1176, approximately 4,000 lbf (17.8 kN) is used to move the active element the first 0.6 inches (1.5 centimeters), or is applied to the formation through the first 0.6 inches (1.5 centimeters) of movement. However, the additional 4,000 lbf (17.8 kN) only moves the active element approximately 0.12 inches (0.3 centimeters). Adding another 4,000 lbf (17.8 kN), or a total of 12,000 lbf (53.4 kN), only moves the active element approximately another 0.06 inches (0.15 centimeters).

[0115] Fig.11 The graph 1176 of FIG. 1176 shows the movement of the active element in different formations; however, the specific graph will vary depending on the geometry of the cutting element, the hardness of the formation, the strength of the formation, the starting position of the active element, etc. For example, a relatively soft formation may allow for greater displacement with less force before the slope transitions to a steeper slope. In at least some embodiments, designing a drill bit or other cutting tool includes determining a transition for the active element of the drill bit and formation combination, and determining a stroke based on the transition. For example, since significantly more force is required to move the active element after the transition, the return stroke may be reduced, and the drill bit may be designed to displace 10%, 20%, 30%, or 40% more than the displacement at the transition.

[0116] In at least one embodiment, a drilling system according to the present disclosure adjusts the weight distribution on the cutting tool to limit stick-slip behavior, motor stalling, or other downhole dynamics of the drilling system. The drilling system includes one or more active elements, such as a center jack, that apply force to the formation to reduce the portion of the WOB on the cutting structure and reduce the DOC. The active element can be actuated in response to measuring or calculating one or more downhole parameters that indicate or predict the presence of stick-slip behavior and / or indicate conditions that may cause the motor to stall or damage the downhole motor.

[0117] Embodiments of the drilling system are described primarily with reference to wellbore drilling operations; however, the drilling systems described herein can be used in applications other than wellbore drilling. In other embodiments, the drilling systems of the present disclosure can be used outside of a wellbore or other downhole environment for exploration or production of natural resources. For example, the drilling systems of the present disclosure can be used in a wellbore for placement of utility pipelines. Therefore, the terms "wellbore," "wellbore," and the like should not be construed to limit the tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

[0118] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the currently disclosed technology. In addition, in order to provide a brief description of these embodiments, all features of the actual embodiments may not be described in the specification. In addition, various examples are provided as illustrations of example methods in which the systems and tools of the present disclosure can be used. For example, examples of certain downhole parameters (e.g., drill bit rotation speed) are provided, which can be measured and compared in certain ways (e.g., comparison with top drive speed or specific activation duration) for activation or deactivation. These examples are illustrative, and in view of the present disclosure, it will be understood by those of ordinary skill in the art that any downhole parameter described herein can be used in combination with any other activation / deactivation method. Therefore, any element described herein with respect to any embodiment can be used in combination with any other embodiment, unless these features are described to the extent that they are mutually exclusive.

[0119] In addition, 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 other embodiments that also include the described features. The numbers, percentages, ratios, or other values ​​described herein are intended to include that value, as well as other values ​​that are "approximately" or "approximately" the described value, as understood by those of ordinary skill in the art included in the embodiments of the present disclosure. Therefore, the values ​​should be interpreted broadly enough to include values ​​that are at least close enough to the described values ​​to perform the desired function or achieve the desired results. The values ​​include at least the variations expected in a suitable manufacturing or production process, and may include values ​​within 5%, within 1%, within 0.1%, or within 0.01% of the described values.

[0120] In view of the present disclosure, those of ordinary skill in the art will recognize that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and modifications may be made to the embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent structures, including functional "means plus function" statements, are intended to cover structures that perform the functions described herein, including structural equivalents that operate in the same manner and equivalent structures that provide the same functions. It is the express intention of the applicant not to invoke means plus function or other functional claims in any claim, except for those claims in which the words "means for..." appear together with the relevant functions. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims will be covered by the claims.

[0121] As used herein, the terms "approximately," "about," and "substantially" refer to an amount that is close to a stated amount, that is within standard manufacturing or process tolerances, or that still performs a desired function or achieves a desired result. For example, the terms "approximately," "about," and "substantially" refer to amounts that are within less than 5%, within less than 1%, within less than 0.1%, and less than 0.01% of a stated amount. In addition, it should be understood that any directions or reference frames in the foregoing description are only relative directions or movements. For example, any reference to "up" and "down," or "above" or "below" merely describes the relative position or movement of the associated elements.

[0122] The present invention may be embodied in other specific forms without departing from the spirit or features of the present invention. The described embodiments should be considered illustrative rather than restrictive. Therefore, the scope of the present disclosure is indicated by the appended claims rather than the preceding description. Changes within the equivalent meaning and scope of the claims should be included within their scope.

Claims

1. A system for drilling a wellbore, the system comprising: Bottom hole assembly, including: a cutting tool having a body, a cutting structure including a plurality of cutting elements, and a longitudinal axis oriented in a longitudinal direction; a movable element connected to the body along the longitudinal axis, the movable element being at least partially movable relative to the body in the longitudinal direction of the cutting tool, the movable element comprising a superhard element; an actuator coupled to the movable element and configured to move the movable element; at least one sensor configured to measure at least one downhole parameter; and At least one processor is in communication with at least one sensor and actuator to move the active element based on a difference between an actuation threshold or a deactivation threshold of at least one downhole parameter and a target parameter, wherein the actuation threshold and the deactivation threshold are different.

2. The system of claim 1, wherein at least one sensor is a rotational speed sensor positioned in a bottom hole assembly to measure a rotational speed of the cutting tool, and wherein, The processor is further configured to calculate a difference between the at least one downhole parameter and a target parameter by comparing the rotational speed of the cutting tool with a historical value of the rotational speed of the cutting tool or with a rotational speed of a torque source of the cutting tool.

3. The system of claim 2, wherein the historical value of the cutting tool rotation speed is a rolling average.

4. The system of claim 1, wherein at least one sensor is a formation sensor configured to measure at least one formation property.

5. The system of claim 1, wherein at least one sensor is a force sensor positioned in the bottom hole assembly and configured to measure weight on bit, wherein: The processor is further configured to calculate a difference between the at least one downhole parameter received from the at least one sensor and the target parameter by comparing the measured weight on bit to the target measured weight on bit.

6. The system of claim 1, at least one sensor being a torque sensor positioned in a bottom hole assembly to measure torque on the cutting tool, wherein: The processor is also configured to calculate a difference between at least one downhole parameter received from the at least one sensor and a target parameter by comparing the torque on the cutting tool to the torque applied by the torque source.

7. The system of claim 1 further comprising a downhole motor providing torque to rotate the cutting tool, the at least one sensor comprising one or more pressure sensors positioned to measure a pressure drop across the downhole motor.

8. The system of claim 1, wherein the movable element has a maximum travel of between 0.25 cm and 3.81 cm.

9. The system according to claim 8, wherein: At maximum travel, the downhole-most end of the movable element is above the well of the downhole-most cutting element of the cutting tool.

10. A system for drilling a wellbore, the system comprising: a drill bit having a longitudinal axis about which the drill bit is rotatable; a movable element located in the drill bit, the movable element being movable relative to the drill bit along a longitudinal axis; an actuator that applies a force to the movable element to move the movable element; at least one sensor configured to measure at least one downhole parameter; and A processor communicates with at least one sensor and an actuator to move the active element toward an extended state when at least one downhole parameter exceeds an actuation threshold and to move the active element toward a retracted state when at least one downhole parameter is within a deactivation threshold, wherein the actuation threshold is different from the deactivation threshold. The system of claim 10 , wherein the deactivation threshold is closer to a target parameter than the actuation threshold.

12. The system of claim 10, wherein the at least one sensor is a first sensor, the at least one downhole parameter is a first downhole parameter, and the actuation threshold is a first actuation threshold, the system further comprising: a second sensor, wherein the processor is configured to actuate the actuator to move the active element a first distance when the first downhole parameter exceeds a first actuation threshold, and the processor is configured to move the active element a second distance when a second downhole parameter from the second sensor exceeds a second actuation threshold.

13. According to the system of claim 10, at least one downhole parameter is a first downhole parameter, and the actuation threshold is a first actuation threshold, the processor is further configured to move the active element a first distance when the first downhole parameter exceeds the first actuation threshold, and the processor is configured to move the active element a second distance when the second downhole parameter exceeds the second actuation threshold.

14. The system of claim 13, the first downhole parameter and the second downhole parameter being the same downhole parameter, and the first actuation threshold and the second actuation threshold being different magnitudes for the same downhole parameter.

15. A method for controlling a drill bit, comprising: lowering a drill bit into a downhole environment, the drill bit having a movable element movable relative to the drill bit along a longitudinal axis of the drill bit; applying torque to the drill bit in a downhole environment; Measure the rotation speed of the drill bit; comparing the rotational speed to a target parameter value; and The movable element is moved relative to the drill bit when the rotational speed exceeds an actuation threshold of the target parameter value and / or is within a deactivation threshold of the target parameter, wherein the actuation threshold is different from the deactivation threshold.

16. The method according to claim 15, wherein: Moving the movable element relative to the drill bit includes controlling a valve between a closed state and at least one open state to apply hydraulic pressure that moves the movable element. The method according to claim 15 , wherein the target parameter value is a rolling average of the rotation speed.

18. The method according to claim 17, wherein: The rolling average is a first rolling average, and the actuation threshold is a first actuation threshold, wherein comparing the rotational speed to the target parameter value comprises: calculating a second rolling average of the rotational speed, the first rolling average and the second rolling average being averaged over different time periods; and The second rolling average is compared to the first actuation threshold or the second actuation threshold.

19. The method according to claim 18, wherein: Moving the movable element relative to the drill bit includes moving the movable element relative to the drill bit when the second rolling average exceeds the first actuation threshold or the second rolling average exceeds the second actuation threshold.

20. The method of claim 15, wherein the drill bit includes a cutting structure separate from the movable element, wherein: A cutting structure separate from the movable element is axially fixed relative to the longitudinal axis of the drill bit.

21. The method according to claim 20, wherein: Moving the movable element relative to the drill bit changes the weight on the cutting structure by at least the greater of 4.45 kN or 10% of the total weight on the drill bit.

22. The method according to any one of claims 15 to 20, wherein: Lowering the drill bit comprises lowering the system according to any one of claims 1 to 14 into a downhole environment.

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