Docket No. IS22.0269 WO PCT SYSTEMS AND METHODS FOR DIRECTIONAL DRILLING BACKGROUND [0001] Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. A variety of drilling methods may be utilized depending partly on the characteristics of the formation through which the wellbore is drilled. [0002] Directional drilling can include steering a drill bit or other downhole tool through a non- linear path. In the course of the path, the drill string can bind on the inner surface of the wellbore. SUMMARY [0003] In some embodiments, a device for directional drilling includes a body, an actuatable steering pad, an actuator, and a cutting element. The body has a rotational axis. The actuator moves the actuatable steering pad radially outward from the body between an open position and a closed position, and the actuatable steering pad has a contact surface. The cutting element is positioned on the actuatable steering pad with a radially outermost portion of the cutting element radially outward of a radially outermost portion of the contact surface in the closed position and radially inward of the radially outermost portion of the contact surface in the open position. [0004] In some embodiments, a method of directional drilling includes rotating a directional steering tool in a downhole environment, wherein the directional steering tool includes at least a first actuatable steering pad and a second actuatable steering pad with cutting elements positioned thereon; applying a lateral force with the first actuatable steering pad in a first radial direction of the directional steering tool to urge the directional steering tool in a second radial direction opposite the first radial direction; and removing material from a borehole wall in the second radial direction with a cutting element positioned in the second actuatable steering pad. [0005] In some embodiments, a device for directional drilling includes a body, an actuatable steering pad, an actuator, and a cutting element. The body has a rotational axis. The actuator is configured to move the actuatable steering pad radially outward from the body through a range of motion between an open position and a closed position, and the actuatable steering pad has a
Docket No. IS22.0269 WO PCT contact surface. The cutting element is positioned on the actuatable steering pad, and the cutting element is deployed radially outside of the contact surface through at least a portion of the range of motion and not deployed in a remaining portion of the range of motion. [0006] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. BRIEF DESCRIPTION OF THE DRAWINGS [0007] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, non-schematic drawings should be considered as being to scale for some embodiments of the present disclosure, but not to scale for other embodiments contemplated herein. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which: [0008] FIG. 1 is a side schematic view of a drilling system, according to some embodiments of the present disclosure; [0009] FIG.2 is a side cross-sectional view of a downhole environment with a curve in a borehole, according to some embodiments of the present disclosure; [0010] FIG. 3 is a transverse cross-sectional view of a directional steering tool in a borehole, according to some embodiments of the present disclosure; [0011] FIG.4 is a transvers cross-sectional view of another directional steering tool in a borehole, according to some embodiments of the present disclosure; [0012] FIG. 5 is a longitudinal cross-sectional view of a directional steering tool in a borehole, according to some embodiments of the present disclosure; [0013] FIG. 6 is a longitudinal cross-sectional view of an actuatable steering pad, according to some embodiments of the present disclosure;
Docket No. IS22.0269 WO PCT [0014] FIG. 7 is a flowchart illustrating a method of directional drilling, according to some embodiments of the present disclosure; [0015] FIG. 8 is a transverse cross-sectional view of a non-circular borehole, according to some embodiments of the present disclosure; [0016] FIG. 9 is a side cross-sectional view of a bottomhole assembly traversing a ledge in a borehole, according to some embodiments of the present disclosure; and [0017] FIG.10-1 through FIG.10-3 illustrate a directional steering tool with an actuatable steering pad in an open position, a deployed position, and a stowed position, according to some embodiments of the present disclosure. DETAILED DESCRIPTION [0018] Embodiments of the present disclosure generally relate to devices, systems, and methods for directional drilling. In some embodiments, systems and methods according to the present disclosure allow for the selective cutting, drilling, milling, reaming, degrading, or otherwise removing material from a radially inward surface of a curve in a borehole. In some embodiments, systems and methods according to the present disclosure allow for the removal of material from a radially inward surface of a curve during drilling of the borehole. In some embodiments, systems and methods according to the present disclosure allow for the removal of material from the radially inward surface after drilling of the borehole. It should be understood that while the present disclosure will describe the systems and methods for directional drilling of a wellbore, it should be understood that the present disclosure is applicable to any downhole device with actuatable structures on a lateral surface during or after the creation of a borehole. [0019] In some embodiments, a borehole or a planned path of a borehole being drilled includes a turn or curve. While a downhole tool or a drill string of various components can bend or turn around a curve with a relatively large radius, it may be desirable to create or navigate a curve with a smaller radius. When the drill string encounters a curve with a relatively small radius, the components of the drill string may contact against a radially inward side of the curve. In some examples, the formation material may wear or damage the components of the drill string. Selectively removing material from the radially inward side of the curve may provide clearance for components of the drill string to pass through the curve with less or no damage. Increasing the radius of the curve may further reduce friction or drag, saving energy at the drill site.
Docket No. IS22.0269 WO PCT [0020] As described herein, the wellsite may be a drill site, a producing wellsite, or a non- producing wellsite, although a drill rig will be described herein. FIG.1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling assembly 104 which extends downward into the wellbore 102. The drilling assembly 104 may include a drill string 105 and a bottomhole assembly (BHA) 106 attached to the downhole end of drill string 105. Where the drilling system 100 is used for drilling formation, a drill bit 110 can be included at the downhole end of the BHA 106. [0021] The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and can transmit rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid 111 is pumped from the surface. The drilling fluid 111 discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, for lifting cuttings out of the wellbore 102 as it is being drilled, and for preventing the collapse of the wellbore 102. The drilling fluid 111 carries drill solids including drill fines, drill cuttings, and other swarf from the wellbore 102 to the surface. The drill solids can include components from the earth formation 101, the drilling assembly 104 itself, from other man-made components (e.g., plugs, lost tools/components, etc.), or combinations thereof. [0022] The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and/or the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement- while-drilling (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, underreamers, directional steering tools, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing. [0023] In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, safety valves, centrifuges, shaker tables, and rheometers). Additional components included in the drilling system 100 may be considered a part of the surface system (e.g., drill rig 103, drilling assembly 104, drill string 105, or a part of the BHA 106, depending on their locations and/or use in the drilling system 100).
Docket No. IS22.0269 WO PCT [0024] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, impregnated bits, or coring bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface by the drilling fluid 111 or may be allowed to fall downhole. The conditions of the equipment of the drilling system 100, the formation 101, the wellbore 102, the drilling fluid 111, or other part of the wellsite can change during operations. [0025] Sensors within the wellsite provide information to make operation decisions for efficiency, safety, and other reasons. For example, a sensor information may be a weight-on-bit (WOB) measurement that provides the controller or computing device with a nominal measured value for the WOB during drilling. The sensor information may be a downhole fluid pressure measurement, such as a nominal pressure value during fluid production of a wellsite. In some examples, the sensor information may be an alert that vibration in the BHA has exceeded a safety threshold and the sensor information may or may not include the nominal shock and/or vibration value (such as a rotational acceleration value) with the alert based on exceeding the preset safety threshold. In some embodiments, vibration in the drill string can limit the efficiency of the drilling, and vibration can be caused by contact between the BHA and/or drill string with the borehole wall. [0026] FIG.2 is a side view of an embodiment of a downhole environment in which a BHA 206 and drill string 205 are passing through a curve of a borehole 202. In some embodiments, portion of the BHA 206 and/or drill string 205 contacts a radially inward surface 212 of the borehole 202 as the BHA 206 and drill string 205 follow the curve. In some embodiments, when the BHA 206 and drill string 205 contact the formation 201 of the borehole surface, the BHA 206 and drill string 205 experience damage from the formation 201. In some embodiments, when the BHA 206 and drill string 205 contact the formation 201 of the borehole surface, the BHA 206 and drill string 205 experience drag, in the longitudinal direction and/or the rotational direction, placing additional strain on the drilling system and components thereof.
Docket No. IS22.0269 WO PCT [0027] In some embodiments, a directional steering tool 214 is a discrete steering tool that is coupled to a drill bit 210. In some embodiments, the directional steering tool 214 is the drill bit with integrated steering element. For example, a directional steering tool 214 includes at least one actuatable steering pad 216 configured to actuate radially outward from a rotational axis of the BHA 206 and drill string 205. As the BHA 206 and drill string 205 rotate, the actuatable steering pad 216 is actuated between a closed position and an open position to selectively apply a lateral force to the borehole wall. The drill bit 210 is urged in an opposing lateral direction to steer the drill bit 210 and the direction of the borehole 202. In some embodiments, a directional steering tool 214 includes one or more cutting elements located on the actuatable steering pad 216 to remove material from the formation 201 of the borehole wall as the directional steering tool 214 rotates relative to the formation 201. [0028] In some embodiments, the cutting element(s) on the actuatable steering pad are positioned and oriented on the surface of the actuatable steering pad to engage with the formation and remove material from the formation when the actuatable steering pad is in a closed position and be located radially within a contact portion of the actuatable steering pad when the actuatable steering pad is in the open position. For example, a surface of the actuatable steering pad changes in orientation relative to a tangential direction in a rotational direction of the directional steering tool. [0029] FIG. 3 is a transverse cross-sectional view of a directional steering tool including three actuatable steering pads 316-1, 316-2, 316-3 positioned proximate an outer surface 318 of a body 320 of the directional steering tool 314. In some embodiments, an actuatable steering pad is connected to the body by a hinge 322 and movable by an actuator 332. In some examples, the hinge 322 includes an axle or other rod about which the actuatable steering pad 316-1 rotates relative to the body 320 and allows a contact surface 324 of the actuatable steering pad 316-1 to change orientation relative to a tangent 326 of the outer surface 328 of the body 320 in a rotational direction 330. In some examples, the hinge 322 includes a flexible or elastically deformable portion that allows a contact surface 324 of the actuatable steering pad 316-1 to change orientation relative to a tangent 326 of the outer surface 328 of the body 320 in a rotational direction 330. In some embodiments, the actuatable steering pad 316-1 is movable between the closed position and the open position by a first actuator 332 and a second actuator (not shown in FIG.3) that extend in the radial direction by different amounts that allow a contact surface 324 of the actuatable
Docket No. IS22.0269 WO PCT steering pad 316-1 to change orientation relative to a tangent 326 of the outer surface 328 of the body 320 in a rotational direction 330. [0030] By changing the orientation of a contact surface 324 of the actuatable steering pad relative to a tangent 326 of the rotation of the body 320, the directional steering device can change the relative order of the cutting element 334 and a radially outermost portion of the contact surface 324 by actuating the actuatable steering pad between the closed position (such as the second actuatable steering pad 316-2) and the open position (such as the first actuatable steering pad 316- 1). The radially outermost portion of the contact surface 324 is the portion of the contact surface 324 closest to and/or contacting the surface of the borehole wall 336. In some embodiments, in the open position, the radially outermost portion of the contact surface 324 is a portion of the contact surface distal to the hinge 322 or other axis of the actuatable steering pad. In some embodiments, when the actuatable steering pad moves inward toward the body 320 and toward the closed position (such as the second actuatable steering pad 316-2), the contact surface 324 of the actuatable steering pad 316-2 moves radially inward more than the cutting element 334 positioned proximate the hinge 322, causing the cutting element 334 to become radially outward of the contact surface 324 of the actuatable steering pad 316-2. In some embodiments, a cutting element 334 is considered deployed when at least a portion of the cutting element 334 is radially outward of the contact surface 324 of the actuatable steering pad 316-2. [0031] In some embodiments, the actuatable steering pad has a range of motion in the radial direction. The range of motion is the total radial movement of a radially outermost portion of the contact surface of the actuatable steering pad in the open position relative to the same portion of the contact surface in the closed position. The cutting element is deployed in at least a portion of the range of motion. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion having in a range having an upper value, a lower value, or upper and lower values including any of 5%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or any values therebetween. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion greater than 25% of the range of motion. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion less than 80% of the range of motion. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion between 25% and 75% of the range of motion. In some embodiments, the
Docket No. IS22.0269 WO PCT cutting element is deployed in the closed position and through approximately 50% of the range of motion. [0032] For example, when an actuatable steering pad is rotationally positioned opposite the steering direction (and applying a lateral force to steer the directional steering device), the actuatable steering pad is in an open position; and when the actuatable steering pad is rotationally positioned in the steering direction (and removing material from the formation of the borehole wall), the actuatable steering pad is in a closed position. When the cutting element is deployed in the closed position and through approximately 50% of the range of motion and the radial speed of actuation is substantially constant, the cutting element will be deployed in 50% of the rotational arc of the directional steering tool and will be not deployed in the remaining 50% of the rotational arc. In at least one embodiment, the cutting element is deployed for 50% of the rotation of the directional steering tool and a contact surface of the actuatable steering pad contacts the formation of the borehole wall for the remaining 50% of the rotational arc. [0033] In some embodiments, the cutting element is deployed for greater than or less than 50% of the range of motion due to or to account for wear of the contact surface of the actuatable steering pad. For example, the actuatable steering pad may include a bearing material configured to resist wear during operation. In some embodiments, the bearing material is or includes an ultrahard material. [0034] In some embodiments, the term "ultrahard" is understood to refer to those materials known in the art to have a grain hardness of about 1,500 HV (Vickers hardness in kg/mm2) or greater. Such ultra-hard materials can include those capable of demonstrating physical stability at temperatures above about 750°C, and for certain applications above about 1,000°C, which are formed from consolidated materials. Such ultrahard materials can include but are not limited to diamond or polycrystalline diamond (PCD) including leached metal catalyst PCD, non-metal catalyst PCD, binderless PCD, nanopolycrystalline diamond (NPD), or hexagonal diamond (Lonsdaleite); cubic boron nitride (cBN); polycrystalline cBN (PcBN); Q-carbon; binderless PcBN; diamond-like carbon; boron suboxide; aluminum manganese boride; metal borides; boron carbon nitride; and other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, oxide, nitride, carbide and boride ceramics and/or cermets, as well as combinations of the above materials. In at least one embodiment, a cutting element may be a monolithic carbonate PCD. For example, the cutting element may consist of a PCD compact
Docket No. IS22.0269 WO PCT without an attached substrate or metal catalyst phase. In some embodiments, the ultrahard material may have a hardness value above 3,000 HV. In other embodiments, the ultrahard material may have a hardness value above 4,000 HV. In yet other embodiments, the ultrahard material may have a hardness value greater than 80 HRa (Rockwell hardness A). [0035] In some embodiments, the rotational axis 338 of the actuatable steering pad is positioned forward in the rotational direction 330 relative to the contact surface 324 of the actuatable steering pad 316-1. For example, the rotational axis 338 of the actuatable steering pad is substantially parallel to the rotational axis 340 of the directional steering tool 314. In other examples, the rotational axis 338 of the actuatable steering pad is less than 45° from the rotational axis 340 of the directional steering tool 314. In some embodiments, the rotational axis 338 of the actuatable steering pad is positioned in the forward rotational direction 330 relative to the contact surface 324 of the actuatable steering pad. For example, the cutting element(s) 334 are positioned in the forward direction ahead of the contact surface 324 in the rotational direction 330. [0036] In some embodiments, the pad surface and/or contact surface 324 of the actuatable steering pad 316-3 has a radius of curvature 342 equal to the radius of curvature 344 of the body outer surface 318. In such an embodiment, the pad surface and/or contact surface 324 and body outer surface 318 may create a substantially continuous surface when the actuatable steering pad is in the closed position. The cutting element(s) 334 may protrude from the substantially continuous surface. In some embodiments, pad surface and/or contact surface 324 has a radius of curvature 342 that is less than the radius of curvature 344 of the body outer surface 318. In such an embodiment, the contact surface 324 (in the open position) contacts the borehole wall 336 between the cutting element(s) 334 and a terminal end 346 of the pad surface without the terminal end 346 contacting the borehole wall 336. The smaller radius of curvature 342 allows the actuatable steering pad 316-3 to be actuated to different positions in the range of motion without the terminal end 346 contacting the borehole wall 336 and experiencing accelerated wear. [0037] FIG. 4 illustrates another embodiment of a directional steering tool 414 according to the present disclosure. In some embodiments, the rotational axis 438 of the actuatable steering pad 416-1, 416-2, 416-3 is positioned rearward relative to the contact surface 424 of the actuatable steering pad. For example, the cutting element(s) 434 are positioned rearward of (e.g., behind) the contact surface 424 in the rotational direction 430. In some embodiments, the cutting elements 434
Docket No. IS22.0269 WO PCT positioned proximate the rotational axis 438 of the actuatable steering pad 416-1, 416-2, 416-3 may transmit force from the wellbore wall 436 more directly to the hinge 422. [0038] FIG.5 illustrates another embodiment of a directional steering tool according to the present disclosure. In some embodiments, the rotational axis 538 of the actuatable steering pad 516-1, 516- 2 is positioned in the downhole longitudinal direction 548 relative to the contact surface 524 of the actuatable steering pad 516-1, 516-2. For example, the cutting element(s) 534 are positioned in the downhole longitudinal direction 548 ahead of the contact surface 524. [0039] In some embodiments, the rotational axis of the actuatable steering pad is positioned in the uphole longitudinal direction relative to the contact surface of the actuatable steering pad. For example, the cutting element(s) are positioned in the uphole direction of the contact surface in the longitudinal direction. [0040] FIG.6 is a side cross-sectional view of an embodiment of an actuatable steering pad 616 with cutting elements 634-1, 634-2. In some embodiments, the cutting elements 634-1, 634-2 are positioned proximate the rotational axis 638 of the actuatable steering pad 616 to allow the cutting elements 634-1, 634-2 to remain at approximately a constant radial height 650 relative to the rotational axis 640 of the directional steering tool, while the tilt of the actuatable steering pad 616 around the rotational axis 638 of the actuatable steering pad 616 allows a contact surface 624 to move more than the cutting elements 634-1, 634-2 in the radial direction. [0041] In some embodiments, the cutting elements 634-1, 634-2 of the actuatable steering pad 616 include any cutting element type, such as shear cutters, bullet cutters, conical cutters, ridged or “axe” cutters, rolling cutters, etc. In some embodiments, the steering pad 616 has one or more first cutting elements 634-1 proximate the rotational axis 638 of the actuatable steering pad 616 and one or more second cutting elements 634-2 distal from the rotational axis 638 of the actuatable steering pad 616 relative to the first cutting elements 634-1. In some embodiments, a partial actuation of the actuatable steering pad 616, such as a 25% actuation relative to the total range of motion of the actuatable steering pad, may allow different cutting elements to engage with the formation of the borehole wall. For example, a partial actuation may selectively allow more aggressive bullet cutting elements of the second cutting elements 634-2 to contact the wall in addition to the shear cutting elements of the first cutting elements 634-1 for additional removal of formation material.
Docket No. IS22.0269 WO PCT [0042] In some embodiments, the cutting elements 634-1, 634-2 are oriented with a longitudinal axis 652 of the cutting element an angle to a radial direction. For example, the cutting elements may have a rake between 5° and 45°. In some embodiments, the rake is between 5° and 25°. In some embodiments, the rake is between 5° and 10°. In some embodiments, the effective rake of the cutting element 634-1, 634-2 changes as the actuatable steering pad 616 moves from the closed position toward the open position. For example, the first cutting element 634-1 may have a rake between 5° and 10° in the closed position, and the second cutting element 634-2 may have a rake between 10° and 15°. When the actuatable steering pad 616 is partially actuated at a 5° angle from the closed position, the second cutting element 634-2 may have a rake between 5° and 10°. For example, when the actuatable steering pad 616 is partially actuated and the second cutting element 634-2 engages the formation, the second cutting element 634-2 has substantially the same rake as the first cutting element 634-1 when the actuatable steering pad 616 is in the closed position. [0043] In some embodiments, the first cutting element 634-1 and second cutting element 634-2 are positioned at the same radial height 650 in the radial direction of the actuatable steering pad 616. In some embodiments, the first cutting element 634-1 and the second cutting element 634-2 are positioned at different radial heights 650 in the radial direction of the actuatable steering pad 616. For example, the second cutting element 634-2 may have a lesser radial height 650 in the radial direction than the first cutting element 634-1 such that the second cutting element 634-2 is not contacting the formation in the closed position. [0044] FIG.7 is a flowchart illustrating an embodiment of a method 754 of directional drilling. In some embodiments, the method includes rotating a directional steering tool in a downhole environment at 756. The directional steering tool includes at least a first actuatable steering pad and a second actuatable steering pad with cutting elements positioned thereon. [0045] The method includes applying a lateral force with the first steering pad in a first radial direction of the directional steering tool to urge the directional steering tool in a second radial direction opposite the first radial direction at 756. The method further includes removing material from a borehole wall in the second radial direction with a cutting element positioned in the second steering pad at 758. In some embodiments, removing material from the borehole wall creates a non-circular borehole. For example, the borehole may be an elliptical borehole in transverse cross- section. In some embodiments, the transverse cross-section of the borehole 802 may be an elongated circle with a semi-circular boundary at the radially inward wall 860 of the curve of the
Docket No. IS22.0269 WO PCT borehole and a semi-circular boundary at the radially outward wall 862 with substantially straight segments 864 connecting the semi-circular boundaries, such as illustrated in FIG. 8. In some embodiments, the transverse cross-section of the borehole may be egg-shaped with a semi-circular boundary at the radially outward wall and a parabolic boundary at the radially inward wall. The timing and amount of actuation of the actuatable steering pad(s) may alter the borehole shape. [0046] In some embodiments, the cutting elements located on the actuatable steering pad(s) of the directional steering tool may be configured to remove material without actuation of the actuatable steering pad(s). For example, the cutting elements of the actuatable steering pad may contact the formation of the borehole wall without actuating the actuatable steering pad(s) when the drill bit encounters a ledge or other change in formation hardness during an otherwise substantially straight section of the borehole. In some embodiments, such as that illustrated in the embodiment of FIG. 9, the BHA 906 is deflected by a first formation 901-1 with a hardness greater than a second formation 901-2. The drill bit 910 preferentially removes material from the second formation 901- 2 and creates a ledge 966 in the first formation 901-1. The ledge 966 may damage components of the rotating BHA 906 and drill string. When the actuatable steering pad 916 of the BHA 906 contacts the ledge 966, the cutting elements 934 of the actuatable steering pad 916 remove material from the ledge 966 to lessen and/or remove the ledge 966 without an actuatable steering pad 916 or other directional steering device applying a transverse force opposite the ledge 966. In some embodiments, a directional steering tool according to the present disclosure passively removes material from the formation to protect the directional steering tool or other components of the BHA and drill string from a ledge of harder material in the formation. [0047] In some embodiments, such as in soft formations where cutting elements have a high removal rate or when steering the BHA and drill string in a large radius curve, it may be desirable to not remove material from the borehole wall with cutting elements located at the radially inward borehole wall. In such an embodiment, a directional steering tool according to the present disclosure may allow the cutting elements on an actuatable steering pad to be stowed within an outer radius of the body outer surface. [0048] FIG. 10-1 is a side view of a directional steering tool 1014 with an embodiment of an actuatable steering pad 1016 according to the present disclosure in an open position. In the open position, the actuatable steering pad 1016 applies a lateral force with a contact surface 1024 of the actuatable steering pad 1016, and the cutting elements 1034 are not deployed. For example, the
Docket No. IS22.0269 WO PCT contact surface 1024 is radially outward of the cutting element(s) 1034 and the outermost surface 1028 of the body 1020 of the directional steering tool 1014. In the open position, the contact surface 1024 of the actuatable steering pad 1016 steers the BHA, while the cutting elements 1034 do not remove material from the formation. [0049] FIG. 10-2 is a side view of the directional steering tool of FIG. 10-1 with an actuatable steering pad 1016 in a deployed position in which at least one cutting element 1034 is configured to contact the borehole wall and/or remove material from the formation. The at least one cutting element is positioned radially outside or outward of the outermost surface 1028 of the body 1020 of the directional steering tool 1014 such that in a curve or at a ledge of the borehole, the cutting elements 1034 contact the formation before the outermost surface 1028 of the body 1020 and/or before the contact surface 1024 of the actuatable steering pad 1016. In the deployed position, the actuatable steering pad 1016 is not substantially steering the BHA, and the cutting element(s) 1034 thereon remove material from the formation. [0050] FIG.10-3 is a side view of the directional steering tool 1014 of FIG.10-1 with an actuatable steering pad 1016 in a stowed position. In some embodiments, the stowed position of the actuatable steering pad 1016 positions at least a portion of the actuatable steering pad inward of the outermost surface 1028 of the body 1020 of the directional steering tool 1014. In some embodiments, the cutting elements 1034 and the contact surface 1024 are radially within an outermost surface 1028 of the directional steering tool 1014. In some embodiments, the entire actuatable steering pad 1016 is radially within the outermost surface 1028 of the directional steering tool 1014. In the stowed position, the actuatable steering pad 1016 and cutting element(s) 1034 thereon neither steer the BHA nor remove material from the formation. INDUSTRIAL APPLICABILITY [0051] Embodiments of the present disclosure generally relate to devices, systems, and methods for directional drilling. In some embodiments, systems and methods according to the present disclosure allow for the selective cutting, drilling, milling, reaming, degrading, or otherwise removing material from a radially inward surface of a curve in a borehole. In some embodiments, systems and methods according to the present disclosure allow for the removal of material from a radially inward surface of a curve during drilling of the borehole. In some embodiments, systems and methods according to the present disclosure allow for the removal of material from the radially
Docket No. IS22.0269 WO PCT inward surface after drilling of the borehole. It should be understood that while the present disclosure will describe the systems and methods for directional drilling of a wellbore, it should be understood that the present disclosure is applicable to any downhole device with actuatable structures on a lateral surface during or after the creation of a borehole. [0052] In some embodiments, a borehole or a planned path of a borehole being drilled includes a turn or curve. While a downhole tool or a drill string of various components can bend or turn around a curve with a relatively large radius, it may be desirable to create or navigate a curve with a smaller radius. When the drill string encounters a curve with a relatively small radius, the components of the drill string may contact against a radially inward side of the curve. In some examples, the formation material may wear or damage the components of the drill string. Selectively removing material from the radially inward side of the curve may provide clearance for components of the drill string to pass through the curve with less or no damage. Increasing the radius of the curve may further reduce friction or drag, saving energy at the drill site. [0053] In some embodiments, a drilling system includes a drill rig used to turn a drilling assembly which extends downward into the wellbore. The drilling assembly may include a drill string and a bottomhole assembly (BHA) attached to the downhole end of drill string. Where the drilling system is used for drilling formation, a drill bit can be included at the downhole end of the BHA. [0054] The drill string may include several joints of drill pipe connected end-to-end through tool joints. The drill string transmits drilling fluid through a central bore and can transmit rotational power from the drill rig to the BHA. In some embodiments, the drill string may further include additional components such as subs, pup joints, etc. The drill pipe provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit for the purposes of cooling the bit and cutting structures thereon, for lifting cuttings out of the wellbore as it is being drilled, and for preventing the collapse of the wellbore. The drilling fluid carries drill solids including drill fines, drill cuttings, and other swarf from the wellbore to the surface. The drill solids can include components from the earth formation, the drilling assembly itself, from other man-made components (e.g., plugs, lost tools/components, etc.), or combinations thereof. [0055] The BHA may include the bit or other components. An example BHA may include additional or other components (e.g., coupled between to the drill string and/or the bit). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling
Docket No. IS22.0269 WO PCT (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, underreamers, directional steering tools, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing. [0056] In general, the drilling system may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, safety valves, centrifuges, shaker tables, and rheometers). Additional components included in the drilling system may be considered a part of the surface system (e.g., drill rig, drilling assembly, drill string, or a part of the BHA, depending on their locations and/or use in the drilling system). [0057] The bit in the BHA may be any type of bit suitable for degrading downhole materials. For instance, the bit may be a drill bit suitable for drilling the earth formation. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, impregnated bits, or coring bits. In other embodiments, the bit may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit may be used with a whipstock to mill into casing lining the wellbore. The bit may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface by the drilling fluid or may be allowed to fall downhole. The conditions of the equipment of the drilling system, the formation, the wellbore, the drilling fluid, or other part of the wellsite can change during operations. [0058] Sensors within the wellsite provide information to make operation decisions for efficiency, safety, and other reasons. For example, a sensor information may be a weight-on-bit (WOB) measurement that provides the controller or computing device with a nominal measured value for the WOB during drilling. The sensor information may be a downhole fluid pressure measurement, such as a nominal pressure value during fluid production of a wellsite. In some examples, the sensor information may be an alert that vibration in the BHA has exceeded a safety threshold and the sensor information may or may not include the nominal shock and/or vibration value (such as a rotational acceleration value) with the alert based on exceeding the preset safety threshold. [0059] In some embodiments, a portion of the BHA and/or drill string contacts a radially inward surface of the borehole as the BHA and drill string follow the curve. In some embodiments, when the BHA and drill string contact the formation of the borehole surface, the BHA and drill string experience damage from the formation. In some embodiments, when the BHA and drill string
Docket No. IS22.0269 WO PCT contact the formation of the borehole surface, the BHA and drill string experience drag, both in the longitudinal direction and the rotational direction, placing additional strain on the drilling system and components thereof. [0060] In some embodiments, a directional steering tool is a discrete steering tool that is coupled to a drill bit. In some embodiments, the directional steering tool is the drill bit with integrated steering element. For example, a directional steering tool includes at least one actuatable steering pad configured to actuate radially outward from a rotational axis of the BHA and drill string. As the BHA and drill string rotate, the actuatable steering pad is actuated between a closed position and an open position to selectively apply a lateral force to the borehole wall. The drill bit is urged in an opposing lateral direction to steer the drill bit and the direction of the borehole. In some embodiments, a directional steering device includes one or more cutting elements located on the actuatable steering pad to remove material from the formation of the borehole wall as the directional steering device rotates relative to the formation. [0061] In some embodiments, the cutting element(s) on the actuatable steering pad are positioned and oriented on the surface of the actuatable steering pad to engage with the formation and remove material from the formation when the actuatable steering pad is in a closed position and be located radially within a contact portion of the actuatable steering pad when the actuatable steering pad is in the open position. For example, a surface of the actuatable steering pad changes in orientation relative to a tangential direction in a rotational direction of the directional steering tool. [0062] In some embodiments, an actuatable steering pad is connected to the body of a directional steering tool by a hinge. In some examples, the hinge includes an axle or other rod about which the actuatable steering pad rotates relative to the body. In some examples, the hinge includes a flexible or elastically deformable portion that allows a contact surface of the actuatable steering pad to change orientation relative to a tangent of the outer surface of the body in a rotational direction. In some embodiments, the actuatable steering pad is movable between the closed position and the open position by a first actuator and a second actuator that extend in the radial direction by different amounts that allow a contact surface of the actuatable steering pad to change orientation relative to a tangent of the outer surface of the body in a rotational direction. [0063] By changing the orientation of a contact surface of the actuatable steering pad relative to a tangent of the rotation of the body, the directional steering device can change the relative order of the cutting element and a radially outermost portion of the contact surface by actuating the
Docket No. IS22.0269 WO PCT actuatable steering pad between the closed position and the open position. The radially outermost portion of the contact surface is the portion of the contact surface closest to and/or contacting the surface of the wellbore wall. In some embodiments, in the open position, the radially outermost portion of the contact surface is a portion of the contact surface distal to the hinge or other axis of the actuatable steering pad. In some embodiments, when the actuatable steering pad moves inward toward the body and toward the closed position, the contact surface of the actuatable steering pad moves radially inward more than the cutting element positioned proximate the hinge, causing the cutting element to become radially outward of the contact surface of the actuatable steering pad. In some embodiments, a cutting element is considered deployed when at least a portion of the cutting element is radially outward of the contact surface of the actuatable steering pad. [0064] In some embodiments, the actuatable steering pad has a range of motion in the radial direction. The range of motion is the total radial movement of a radially outermost portion of the contact surface of the actuatable steering pad in the open position relative to the same portion of the contact surface in the closed position. The cutting element is deployed in at least a portion of the range of motion. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion having in a range having an upper value, a lower value, or upper and lower values including any of 5%, 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or any values therebetween. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion greater than 25% of the range of motion. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion less than 80% of the range of motion. In some embodiments, the cutting element is deployed in the closed position and through a percentage of the range of motion between 25% and 75% of the range of motion. In some embodiments, the cutting element is deployed in the closed position and through approximately 50% of the range of motion. [0065] For example, when an actuatable steering pad is rotationally positioned opposite the steering direction (and applying a lateral force to steer the directional steering device), the actuatable steering pad is in an open position; and when the actuatable steering pad is rotationally positioned in the steering direction (and removing material from the formation of the borehole wall), the actuatable steering pad is in a closed position. When the cutting element is deployed in the closed position and through approximately 50% of the range of motion and the radial speed of
Docket No. IS22.0269 WO PCT actuation is substantially constant, the cutting element will be deployed in 50% of the rotational arc of the directional steering tool and will be not deployed in the remaining 50% of the rotational arc. In at least one embodiment, the cutting element is deployed for 50% of the rotation of the directional steering tool and a contact surface of the actuatable steering pad contacts the formation of the borehole wall for the remaining 50% of the rotational arc. [0066] In some embodiments, the cutting element is deployed for greater than or less than 50% of the range of motion due to or to account for wear of the contact surface of the actuatable steering pad. For example, the actuatable steering pad may include a bearing material configured to resist wear during operation. In some embodiments, the bearing material is or includes an ultrahard material. [0067] In some embodiments, the term "ultrahard" is understood to refer to those materials known in the art to have a grain hardness of about 1,500 HV (Vickers hardness in kg/mm2) or greater. Such ultra-hard materials can include those capable of demonstrating physical stability at temperatures above about 750°C, and for certain applications above about 1,000°C, which are formed from consolidated materials. Such ultrahard materials can include but are not limited to diamond or polycrystalline diamond (PCD) including leached metal catalyst PCD, non-metal catalyst PCD, binderless PCD, nanopolycrystalline diamond (NPD), or hexagonal diamond (Lonsdaleite); cubic boron nitride (cBN); polycrystalline cBN (PcBN); Q-carbon; binderless PcBN; diamond-like carbon; boron suboxide; aluminum manganese boride; metal borides; boron carbon nitride; and other materials in the boron-nitrogen-carbon-oxygen system which have shown hardness values above 1,500 HV, oxide, nitride, carbide and boride ceramics and/or cermets, as well as combinations of the above materials. In at least one embodiment, a cutting element may be a monolithic carbonate PCD. For example, the cutting element may consist of a PCD compact without an attached substrate or metal catalyst phase. In some embodiments, the ultrahard material may have a hardness value above 3,000 HV. In other embodiments, the ultrahard material may have a hardness value above 4,000 HV. In yet other embodiments, the ultrahard material may have a hardness value greater than 80 HRa (Rockwell hardness A). [0068] In some embodiments, the rotational axis of the actuatable steering pad is positioned in the rotational direction relative to the contact surface of the actuatable steering pad. For example, the rotational axis of the actuatable steering pad is substantially parallel to the rotational axis of the directional steering tool. In other examples, the rotational axis of the actuatable steering pad is less
Docket No. IS22.0269 WO PCT than 45° from the rotational axis of the directional steering tool. In some embodiments, the rotational axis of the actuatable steering pad is positioned in the forward rotational direction relative to the contact surface of the actuatable steering pad. For example, the cutting element(s) are positioned in the forward direction ahead of the contact surface in the rotational direction. [0069] In some embodiments, the pad surface of the actuatable steering pad has a radius of curvature equal to the radius of curvature of the body outer surface. In such an embodiment, the pad surface and body outer surface may create a substantially continuous surface when the actuatable steering pad is in the closed position. The cutting element(s) may protrude from the substantially continuous surface. In some embodiments, pad surface and/or contact surface has a radius of curvature that is less than the radius of curvature of the body outer surface. In such an embodiment, the contact surface (in the open position) contacts the borehole wall between the cutting element(s) and a terminal end of the pad surface without the terminal end contacting the borehole wall. The smaller radius of curvature allows the actuatable steering pad to be actuated to different positions in the range of motion without the terminal end contacting the borehole wall and experiencing accelerated wear. [0070] In some embodiments, the rotational axis of the actuatable steering pad is positioned rearward relative to the contact surface of the actuatable steering pad. For example, the cutting element(s) are positioned rearward of (e.g., behind) the contact surface in the rotational direction. [0071] In some embodiments, the rotational axis of the actuatable steering pad is positioned in the downhole longitudinal direction relative to the contact surface of the actuatable steering pad. For example, the cutting element(s) are positioned in the downhole direction ahead of the contact surface in the longitudinal direction. [0072] In some embodiments, the rotational axis of the actuatable steering pad is positioned in the uphole longitudinal direction relative to the contact surface of the actuatable steering pad. For example, the cutting element(s) are positioned in the uphole direction of the contact surface in the longitudinal direction. [0073] In some embodiments, the cutting elements are positioned proximate the rotational axis (e.g., the hinge) of the actuatable steering pad to allow the cutting elements to remain at approximately a constant radius relative to the rotational axis of the directional steering tool, while the tilt of the actuatable steering pad allows a contact surface of the actuatable steering pad to move more than the cutting elements in the radial direction.
Docket No. IS22.0269 WO PCT [0074] In some embodiments, the cutting elements of the actuatable steering pad include any cutting element type, such as shear cutters, bullet cutters, conical cutters, ridged or “axe” cutters, rolling cutters, etc. In some embodiments, the steering pad has a set of first cutting elements proximate the hinge of the actuatable steering pad and a set of second cutting elements distal from the hinge of the actuatable steering pad relative to the first cutting elements. In some embodiments, a partial actuation of the actuatable steering pad, such as a 25% actuation relative to the total range of motion of the actuatable steering pad, may allow different cutting elements to engage with the formation of the borehole wall. For example, a partial actuation may selectively allow more aggressive bullet cutting elements of the second cutting elements to contact the wall in addition to the shear cutting elements of the first cutting elements for additional removal of formation material. [0075] In some embodiments, the cutting elements are oriented with a longitudinal axis of the cutting element at an angle to a radial direction. For example, the cutting elements may have a rake between 5° and 45°. In some embodiments, the rake is between 5° and 25°. In some embodiments, the rake is between 5° and 10°. In some embodiments, the effective rake of the cutting element changes as the actuatable steering pad moves from the closed position toward the open position. For example, the first cutting element may have a rake between 5° and 10° in the closed position, and the second cutting element may have a rake between 10° and 15°. When the actuatable steering pad is partially actuated at a 5° angle from the closed position, the second cutting element may have a rake between 5° and 10°. For example, when the actuatable steering pad is partially actuated and the second cutting element engages the formation, the second cutting element has substantially the same rake as the first cutting element when the actuatable steering pad is in the closed position. [0076] In some embodiments, the first cutting element and second cutting element are positioned at the same radial height in the radial direction of the actuatable steering pad. In some embodiments, the first cutting element and the second cutting element are positioned at different radial heights in the radial direction of the actuatable steering pad. For example, the second cutting element may have a lesser radial height in the radial direction than the first cutting element such that the second cutting element is not contacting the formation in the closed position. [0077] In some embodiments, a method of directional drilling includes rotating a directional steering tool in a downhole environment. The directional steering tool includes at least a first
Docket No. IS22.0269 WO PCT actuatable steering pad and a second actuatable steering pad with cutting elements positioned thereon. [0078] The method includes applying a lateral force with the first steering pad in a first radial direction of the directional steering tool to urge the directional steering tool in a second radial direction opposite the first radial direction. The method further includes removing material from a borehole wall in the second radial direction with a cutting element positioned in the second steering pad. In some embodiments, removing material from the borehole wall creates a non-circular borehole. For example, the borehole may be an elliptical borehole in transverse cross-section. In some embodiments, the transverse cross-section of the borehole may be an elongated circle with a semi- circular boundary at the radially inward wall of the curve of the borehole and a semi-circular boundary at the radially outward wall with substantially straight segments connecting the semi- circular boundaries. In some embodiments, the transverse cross-section of the borehole may be egg-shaped with a semi-circular boundary at the radially outward wall and a parabolic boundary at the radially inward wall. The timing and amount of actuation of the actuatable steering pad(s) may alter the borehole shape. [0079] In some embodiments, the cutting elements located on the actuatable steering pad(s) of the directional steering tool may be configured to remove material without actuation of the actuatable steering pad(s). For example, the cutting elements of the actuatable steering pad may contact the formation of the borehole wall without actuating the actuatable steering pad(s) when the drill bit encounters a ledge or other change in formation hardness during an otherwise substantially straight section of the borehole. In some embodiments, the BHA is deflected by a first formation with a hardness greater than a second formation. The drill bit preferentially removes material from the second formation and creates a ledge in the first formation. The ledge may damage components of the rotating BHA and drill string. When the actuatable steering pad of the BHA contacts the ledge, the cutting elements of the actuatable steering pad remove material from the ledge to lessen and/or remove the ledge without an actuatable steering pad or other directional steering device applying a transverse force opposite the ledge. In some embodiments, a directional steering tool according to the present disclosure passively removes material from the formation to protect the directional steering tool or other components of the BHA and drill string from a ledge of harder material in the formation.
Docket No. IS22.0269 WO PCT [0080] In some embodiments, such as in soft formations where cutting elements have a high removal rate or when steering the BHA and drill string in a large radius curve, it may be desirable to not remove material from the borehole wall with cutting elements located at the radially inward borehole wall. In such an embodiment, a directional steering tool according to the present disclosure may allow the cutting elements on an actuatable steering pad to be stowed within an outer radius of the body outer surface. [0081] In some embodiments, in the open position, the actuatable steering pad applies a lateral force with a contact surface of the actuatable steering pad and the cutting elements are not deployed. For example, the contact surface is radially outward of the cutting element(s) and the outermost surface of the body of the directional steering tool. In the open position, the contact surface of the actuatable steering pad steers the BHA, while the cutting elements do not remove material from the formation. [0082] In some embodiments, an actuatable steering pad in a deployed position has at least one cutting element positioned to contact the borehole wall and/or remove material from the formation. The at least one cutting element is positioned radially outside or outward of the outermost surface of the body of the directional steering tool such that in a curve or at a ledge of the borehole, the cutting elements contact the formation before the outermost surface of the body and/or before the contact surface of the actuatable steering pad. In the deployed position, the actuatable steering pad is not substantially steering the BHA, but the cutting element(s) thereon remove material from the formation. [0083] In some embodiments, the stowed position of the actuatable steering pad positions at least a portion of the actuatable steering pad inward of the outer surface of the body of the directional steering tool. In some embodiments, the cutting elements and the contact surface are radially within an outermost surface of the directional steering tool. In some embodiments, the entire actuatable steering pad is radially within the outermost surface of the directional steering tool. In the stowed position, the actuatable steering pad and cutting element(s) thereon neither steer the BHA nor remove material from the formation. [0084] The present disclosure relates to methods and systems for directional drilling according to any of the following: [0085] In some embodiments, a device for directional drilling includes a body, an actuatable steering pad, an actuator, and a cutting element. The body has a rotational axis. The actuator moves
Docket No. IS22.0269 WO PCT the actuatable steering pad radially outward from the body between an open position and a closed position, and the actuatable steering pad has a contact surface. The cutting element is positioned on the actuatable steering pad with a radially outermost portion of the cutting element radially outward of a radially outermost portion of the contact surface in the closed position and radially inward of the radially outermost portion of the contact surface in the open position. In some embodiments, the body includes a drill bit. In some embodiments, the device includes a hinge, and the actuator is configured to rotate the actuatable steering pad around the hinge. In some embodiments, the hinge is located forward of the cutting element relative to a rotational direction of the body around the rotational axis. In some embodiments, the hinge is located rearward of the cutting element relative to a rotational direction of the body around the rotational axis. In some embodiments, the hinge is located in a downhole longitudinal direction relative to the cutting element. In some embodiments, the hinge is located in an uphole longitudinal direction relative to the cutting element. In some embodiments, the cutting element is a first cutting element and the device further comprises a second cutting element located rearward of the first cutting element relative to a rotational direction of the body around the rotational axis. In some embodiments, the second cutting element has a different rake than the first cutting element. In some embodiments, the second cutting element has a different radial height than the first cutting element. In some embodiments, the second cutting element is a different cutting element type than the first cutting element. In some embodiments, the contact surface has a different radius of curvature from an outer surface of the body. In some embodiments, the actuator is configured to move the actuatable steering pad radially inward to a stowed position wherein the cutting element is radially within an outermost portion of an outer surface of the body. [0086] In some embodiments, a method of directional drilling includes rotating a directional steering tool in a downhole environment, wherein the directional steering tool includes at least a first actuatable steering pad and a second actuatable steering pad with cutting elements positioned thereon; applying a lateral force with the first actuatable steering pad in a first radial direction of the directional steering tool to urge the directional steering tool in a second radial direction opposite the first radial direction; and removing material from a borehole wall in the second radial direction with a cutting element positioned in the second actuatable steering pad. In some embodiments, the second actuatable steering pad is in a closed position when removing material from the borehole wall. In some embodiments, the method further includes creating a non-circular
Docket No. IS22.0269 WO PCT borehole in transverse cross-section. In some embodiments, the non-circular borehole is an elongated circle in transverse cross-section. In some embodiments, the method further includes partially actuating the second actuatable steering pad to deploy a second cutting element. [0087] In some embodiments, a device for directional drilling includes a body, an actuatable steering pad, an actuator, and a cutting element. The body has a rotational axis. The actuator is configured to move the actuatable steering pad radially outward from the body through a range of motion between an open position and a closed position, and the actuatable steering pad has a contact surface. The cutting element is positioned on the actuatable steering pad, and the cutting element is deployed radially outside of the contact surface through at least a portion of the range of motion and not deployed in a remaining portion of the range of motion. [0088] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. Accordingly, the terms “wellsite,” “wellbore,” “borehole,” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment. [0089] Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein, to the extent such features are not described as being mutually exclusive. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about”, “substantially”, or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value. [0090] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or
Docket No. IS22.0269 WO PCT which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. [0091] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims. The described embodiments are therefore to be considered as illustrative and not restrictive, and the scope of the disclosure is indicated by the appended claims rather than by the foregoing description.