Patent Grant
11643883
Generally, wellbores are drilled through hydrocarbon-bearing subsurface formations to obtain hydrocarbons such as oil and gas. Some wellbores include vertical portions, as well as horizontal/lateral portions. Indeed, a wellbore may extend vertically downward from a surface of the drilling operation and transition, via a curved portion (e.g., dogleg portion), to a horizontal portion at a desired depth in the subsurface formation. During drilling operations, a rotary steerable system tool may be implemented in a downhole drilling operation to guide a drilling path of the bottom hole assembly (BHA). The rotary steerable system may veer the BHA from a vertical drilling path to a horizontal drilling path. For some subsurface formations, a curved portion having a high dogleg severity may be desirable. As such, some rotary steerable systems may include a flexible tool such that the rotary steerable system may increase a dogleg severity (i.e., a measure of the change in direction of a wellbore over a defined length) of the curved portion of the wellbore.
Unfortunately, the flexible tool may hinder drilling operations in straight portions of the wellbore (e.g., the vertical portion and/or horizontal portion). In particular, the flexible tool may have decreased torsional stiffness making the BHA less suitable for steering controllability and vibration mitigation, which may lead to an increased risk of stick-slip, whirl, and/or other issues.
These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the method.
Disclosed herein are systems and methods for an adjustably flexible downhole tool. In particular, a bottom hole assembly comprises the adjustably flexible downhole tool, as well as a rotary steerable system for steering the bottom hole assembly (BHA) assembly during drilling operations. As set forth in detail below, the adjustably flexible downhole tool may have at least one adjustable member configured to adjust a stiffness of the adjustably flexible downhole tool as the BHA moves along the wellbore. For example, the adjustably flexible downhole tool may be adjusted to be more flexible for curved portions (e.g., dogleg portions) such that the rotary steerable system may increase a dogleg severity (i.e., a measure of the change in direction of a wellbore over a defined length) of the curved portion of the wellbore. Further, the adjustably flexible downhole tool may be adjusted to be stiffer along straight portions of the wellbore for improved steering controllability, vibration mitigation, and/or other benefits.
A rotary steerable system 130 of the bottom hole assembly 134 may be configured to steer the drill bit 122 through the subterranean formation 106 to form the various portions of the wellbore 102. The bottom hole assembly 134 may further comprise an adjustably flexible downhole tool 150 configured to support the rotary steerable system 130 in steering the drill bit 122. For example, the adjustably flexible downhole tool 150 may be adjusted to be more flexible while drilling the curved portion(s) 156 and may be adjusted to be stiffer while drilling straight portions (e.g., the vertical portion 154, the horizontal portion 158, etc.). Moreover, the rotary steerable system 130 may comprise any number of tools, such as sensors 136, transmitters, and/or receivers to perform downhole measurement operations or to perform real-time health assessment of a rotary steerable system 130 during drilling operations. Further, the rotary steerable system 130 may comprise any number of different measurement assemblies, communication assemblies, battery assemblies, and/or the like. Moreover, the sensors 136 may be connected to information handling system 138. There may be any number of sensors 136 disposed in the BHA 134 or rotary steerable system 130.
Moreover, the rotary steerable system 130 may be connected to and/or controlled by information handling system 138, which may be disposed on surface 108 or downhole in the rotary steerable system 130. A communication link 140 may provide transmission of measurements from the sensors 136 to the information handling system 138, as well as commands from the information handling system 138 to the rotary steerable system 130. The communication link 140 may include, but is not limited to, wired pipe telemetry, mud-pulse telemetry, acoustic telemetry, and electromagnetic telemetry. Further, the information handling system 138 may comprise a personal computer 141, a video display 142, a keyboard 144 or any suitable input device, and/or non-transitory computer-readable media 146 (e.g., optical disks, magnetic disks) that can store code representative of the methods described herein.
The adjustably flexible downhole tool 150 may also comprise an outer sleeve 210 disposed around at least a portion of the length of shaft 202. The outer sleeve 210 may be annular such that the outer sleeve radially encloses the shaft 202. In some embodiments, the outer sleeve 210 may comprise radial slots, gaps, or other spaces such that the outer sleeve 210 only partially encloses the shaft 202. Moreover, as illustrated, an anchored end 224 of the outer sleeve 210 may be connected to the first connector end 204, and the outer sleeve 210 may extend axially from the first connector end 204 in a direction toward the second connector end 206. A free end 226 of the outer sleeve 210, opposite the anchored end 224, may be disposed proximate the second connector end 206. In the illustrated embodiment, the free end 226 is not attached to the second connector end 206. That is, the outer sleeve 210 may be cantilevered from the first connector end 204. Moreover, the outer sleeve 210 may be secured to the first connector end 204 via a threaded connection, welding, fasteners (e.g., screws, pins, etc.), and/or press-fitting a radially inner sleeve surface 212 of the outer sleeve against a radially outer connector surface 230 of the first connector end 204.
The radially inner sleeve surface 212 of the outer sleeve 210 may be radially offset from a radially outer shaft surface 236 of the shaft 202 such that an annulus 220 is formed between the outer sleeve 210 and the shaft 202. At least one adjustable member 240 may be disposed in the annulus 220 defined between the shaft 202 and the outer sleeve 210. As illustrated, the at least one adjustable member 240 comprises an annular piston 214 configured to move axially with respect to outer sleeve 210 and shaft 202. In the illustrated embodiment, the annular piston 214 is disposed in a first position located proximate the first connector end 204. However, the annular piston 214 may be configured to move axially along the shaft 202 from the first position to the second position located proximate the free end 226 of the outer sleeve and/or the second connector end 206. Moving the annular piston 214 from the first position toward the second position may increase bending stiffness and/or torsional stiffness of the adjustably flexible downhole tool.
A radially inner piston surface 270 of the annular piston 214 may be configured to interface with the radially outer shaft surface 236 of the shaft 202, and a radially outer piston surface 272 of the annular piston may be configured to interface with the radially inner sleeve surface 212 of the outer sleeve 210. As such, the annular piston 214 may at least partially restrain radial movement (e.g., deflection/bending) of the shaft 202 with respect to the outer sleeve 210 at a location of the annular piston 214. During drilling operations, the adjustably flexible downhole tool 150 may experience forces in certain locations along the wellbore (e.g., the curved portion 156) that cause the adjustably flexible downhole tool 150 to bend. In particular, as the shaft 202 is connected at both ends (e.g., to the first connector end 204 and the second connector end 206), the shaft 202 may bend due to the forces present along the curved portion 156. Generally, as the outer sleeve 210 is cantilevered from the first connector end 204, the outer sleeve may not support the shaft 202. However, as the annular piston 214 is configured to interface with both the shaft 202 and the outer sleeve 210, the outer sleeve 210 may support the shaft 202 (e.g., to restrain bending) at the location of the annular piston 214.
In the illustrated embodiment, the annular piston 214 is disposed in the first position. As the first position is disposed proximate the first connector end 204, only a portion of the outer sleeve 210 (e.g., between the first connector end 204 and the annular piston 214) is configured to help restrain radial movement (e.g., bending) of the shaft 202. However, as the annular piston 214 moves toward the second connector end 206, more of the length of the outer sleeve 210 may be configured to support more of the length of the shaft 202, which is configured to increase the bending stiffness of the adjustably flexible downhole tool 150. As such, the adjustably flexible downhole tool 150 may be adjusted between a flexible state (e.g., with the annular piston 214 in the first position) and a stiffer state (e.g., with the annular piston 214 in the second position). In some embodiments, the stiffness of the adjustably flexible downhole tool 150 may be variable adjusted. That is, the annular piston 214 may be positioned at any axial position along the shaft 202 between the first position and the second position to provide additional stiffness control for the adjustably flexible downhole tool 150. For example, the adjustably flexible downhole tool 150 may move through a curved portion 156 of the wellbore 102 that has a low dogleg severity. To maintain higher steering controllability and/or vibration mitigation while still increasing the flexibility of the adjustably flexible downhole tool 150 to reduce strain, the annular piston 214 may be moved to a position disposed between the first position and the second position.
An actuator 218 may be configured to drive the adjustable member 240 (e.g., annular piston 214) along the shaft 202 between the first position and the second position. In some embodiments, the actuator 218 may be configured to provide unidirectional movement of the annular piston 214 (e.g., in a direction from the first connector end 204 toward the second connector end 206). However, in some embodiments, the actuator 218 may be configured to provide bidirectional movement of the annular piston 214 along the shaft 202. Further, the actuator 218 may be configured to drive the adjustable member 240 on demand. That is, the actuator 218 may be configured to receive signal, via electrical communication, fluid communication, or any other suitable communication mechanism, and drive the adjustable member 240 in response to receiving the signal. In the illustrated embodiment, the actuator 218 comprises a hydraulic system 238 having at least a control valve 242 and a fluid passageway 244 extending from the central bore 208 to a sealed chamber 246. The sealed chamber 246 may be defined by a portion of the annulus 220 between the first connector end 204 and the annular piston 214. In some embodiments, to help isolate the sealed chamber 246 from the downhole environment, the annular piston 214 may comprise a plurality of seals to form a seal between the annular piston 214 and the shaft 202, as well as between the annular piston 214 and the outer sleeve 210.
Moreover, to move the annular piston 214 in the direction from the first position toward the second position, the control valve 242 may be configured to open the fluid passageway 244 in response to a control signal; thereby, permitting fluid from the central bore 208 to pass through the fluid passageway 244 and enter the sealed chamber 246. As the fluid enters the sealed chamber 246, the pressure in the sealed chamber 246 may increase. In response to the pressure in the sealed chamber 246 exceeding a threshold pressure, the annular piston 214 may move in the direction toward the second connector end 206. Further, the actuator 218 may comprise an electrical motor, or any other suitable actuator or combination of actuators, to move the annular piston 214 between the first position and the second position.
Further, the adjustably flexible downhole tool 150 may also comprise a debris barrier 232 configured to prevent downhole debris from moving into the annulus 220. For example, the debris barrier 232 may comprise a screen to filter out debris moving into the annulus 220. The debris barrier 232 may be secured in the annulus 220 in a location proximate the second connector end 206. In particular, the debris barrier 232 may be disposed between the second position of the annular piston 214 and the second connector end 206 such that the debris barrier 232 does not inhibit movement of the annular piston 214 along the annulus 220 between the first position and the second position. Moreover, the debris barrier 232 may span between the shaft 202 and the outer sleeve 210.
With regard to
Alternatively, the stop mechanism 280 may comprise a wedge disposed proximate the second position. For example, the shaft 202 may comprise a wedge protruding into the annulus 220 from the radially outer shaft surface 236. Alternatively, the diameter of the shaft 202 may gradually increase along the length of the shaft 202 in the direction toward the second connector end 206, starting from the second position, to form the wedge (e.g., tapered surface). The wedge may be configured to restrain axial movement of the annular piston 214 in the direction toward the second connector end 206 and/or secure the annular piston 214 at the second position. Likewise, the outer sleeve 210 may comprise a wedge (e.g., tapered surface) protruding into the annulus 220 from the radially inner sleeve surface 212. In addition, the annular piston 214 may have a tapered portion. In particular, the radially inner piston surface 270 and/or radially outer piston surface 272 may comprise tapered portions. As the annular piston 214 moves into the second position, the tapered portion of radially inner piston surface 270 may engage the wedge of shaft 202 and the tapered portion of radially outer piston surface 272 may engage the wedge of outer sleeve 210. The engagement of both tapered portions may create a more rigid coupling of shaft 202 to outer sleeve 210 through annular piston 214 at the second position. Indeed, removing the radial clearance between shaft 202, annular piston 214, and outer sleeve 210 may make the adjustably flexible downhole tool 150 more laterally stiff and less prone to wear from relative movement of parts in abrasive drilling mud during drilling operations. Further, the rigid coupling of shaft 202 to outer sleeve 210 through annular piston 214 at the second position may increase the torsional stiffness of the adjustably flexible downhole tool 150.
With regard to
Moreover, the annular piston 214 may be moved on demand, in a direction toward the pivot guide 300, to adjust the adjustably flexible downhole tool 150 to be more radially stiff. Indeed, a variable radial stiffness may be achieved based at least in part on the position of annular piston 214 between first position and pivot guide 300. The adjustably flexible downhole tool 150 may be most stiff position with the annular piston 214 disposed directly adjacent pivot guide 300.
In the illustrated embodiment, each ring of the plurality of annular rings 402 is disposed in a first position such that the adjustably flexible downhole tool 150 is in a flexible configuration. In the first position, each annular ring 402 may be spaced apart from adjacent annular rings 402. Indeed, there may be sufficient axial and/or radial clearance between respective interlocking features of adjacent annular rings of the plurality of annular rings 402 that each annular ring may move radially and/or axially with respect to respective adjacent annular rings. As each annular ring may move freely with respect to adjacent annular rings, the plurality of annular rings 402 may not restrain bending of the shaft 202 such that the adjustably flexible downhole tool 150 may be in the flexible configuration.
Referring to
As set forth above, the adjustably flexible downhole tool 150 may comprise the actuator 218. The actuator 218 may be configured to drive each annular ring of the plurality of annular rings 402 axially to move from the respective first positions to the respective second positions. In some embodiments, the actuator 218 may comprise a push ring 426 and an electric motor configured to drive the push ring 426 in an axial direction toward the plurality of annular rings 402. The push ring 426 may be disposed about the shaft 202 at an end of the plurality of annular rings 402. In some embodiments, the push ring 426 is threaded to the shaft 202, the first connector end 204, or the second connector end 206 such that driving the push ring 426 in an axial direction comprises rotating/threading the push ring 426. Indeed, the push ring 426 may move axially as it rotates to produce an axial force on the plurality of annular rings 402. The axial force may drive the plurality of annular rings 402 from the respective first positions to the respective second positions. For example, the push ring 426 may be threaded to the second connector end 206 such that the actuator 218 may driving the push ring 426 in a direction toward the first connector end 204. As such, the push ring 426 may drive the plurality of annular rings 402 in a direction toward the first connector end 204 and compress the annular rings 402 against a shoulder 428 of the first connector end 204 and/or a ring adapter 440 disposed between the shoulder 428 and the annular rings 402. Compressing the plurality of annular rings against the first connector end 204 (e.g., moving each of the annular rings 402 from the respective first position to the respective second position) may reduce or remove axial and/or radial clearance between each of the plurality of annular rings 402; thereby, interfacing adjacent interlocking features 404, 408 of the plurality of annular rings 402. Compressing the plurality of annular rings 402 may not require a large amount of axial force.
Moreover, the adjustably flexible downhole tool 150 may comprise a locking feature 430 configured to axially hold the plurality of annular rings 402 in the second position. The locking feature 430 may comprise threading, an expandable locking ring, a collet, a spring energized lock, or any combination thereof. For example, the push ring 426 may be configured to interface with an exterior annular ring 432 of the plurality of annular rings 402 to drive the plurality of annular rings 402 to the second position. The exterior annular ring 432 may comprise a ring slot 434 configured to house an expandable locking ring 438. Further, the shaft 202 may comprise shaft slot 436 disposed in a location corresponding to the second position of the exterior annular ring 432. As the exterior annular ring 432 moves into the second position, the expandable locking ring 438 may expand into the shaft slot 436 and lock the exterior annular ring 432 in the second position. Locking the exterior annular ring 432 in the second position may axially hold the plurality of annular rings 402 in the second position.
Additionally, the adjustably flexible downhole tool 150 may comprise a torsional locking feature to increase torsional stiffness of the adjustably flexible downhole tool 150. The torsional locking feature may restrain rotational movement of the plurality of annular rings 402 with respect to the shaft 202. In some embodiments, the torsional locking feature may comprise a key and slot configuration (shown in
Further, the adjustably flexible downhole tool 150 may comprise the at least one adjustable member 240. In the illustrated embodiment, the at least one adjustable member 240 comprises the actuating sleeve 500. The actuating sleeve 500 may be coupled to the second connector end 206. Further, the actuating sleeve 500 may be configured to move axially, with respect to the shaft 202, from the first position to the second position to increase bending stiffness and/or torsional stiffness of the adjustably flexible downhole tool 150. As illustrated, in the first position, the actuating sleeve 500 is axially offset from the outer sleeve 210 such that the outer sleeve 210 may not support the shaft 202 in the first position. Therefore, adjustably flexible downhole tool 150 may be in a flexible configured with the actuating sleeve 500 in the first position, such that the rotary steerable system 130 may bend sufficiently to achieve a high dog leg severity through curved portions 156 of the wellbore 102. However, in the second position (shown in
Moreover, the adjustably flexible downhole tool 150 may comprise the actuator 218 to drive the actuating sleeve 500 from the first position to the second position. The actuator 218 may comprise a hydraulic actuator, an electric motor, or some combination thereof. In the illustrated embodiment, the actuator 218 comprises a hydraulic system 238 having an electric motor 502 configured to actuate a piston valve 504 to open a fluid line 506 from the central bore 208 to a sealed chamber 508. The sealed chamber 508 may be defined by a radially inner actuating surface 510 of the actuating sleeve 500 and a second radially outer connector surface 540 of the second connector end 206. Further, opening the fluid line 506 may permit fluid passing through the central bore 208 to flow into the sealed chamber 508, which may increase the pressure in the sealed chamber 508. In some embodiments, a shear pin 526 may be configured to hold the actuating sleeve 500 in the first position. The shear pin 526 may be configured to shear in response to a threshold axial force (e.g., an actuation force) applied to the actuating sleeve 500 such that the actuating sleeve 500 may move from the first position towards the second position to interface with the outer sleeve 210. Once the piston valve 504 opens the fluid line 506, the pressure in the sealed chamber 508 may increase sufficiently to apply the threshold axial force to the actuating sleeve 500 such that the actuating sleeve 500 may move from the first position to the second position.
Referring to
The free end 226 of the outer sleeve 210 may comprise a first interface surface 514 configured to interface with a second interface surface 516 of the actuating sleeve 500. In the illustrated embodiment, the first interface surface 514 and the second interface surface 516 comprise tapered/angular surfaces. However, the first interface surface 514 and the second interface surface 516 may comprise any suitable interface for restraining radial and/or axial movement of the free end 226 of the outer sleeve 210. For example, the first interface surface 514 may comprise at least one protrusion and the second interface surface 516 may comprise at least one recess configured to receive the at least one protrusion.
As set forth above with respect to
In some embodiments, the actuator 218 may comprise the electric motor 502 attached to a hydraulic pump (not shown) that is configured to pump hydraulic oil from a reservoir into the sealed chamber 508. The pressure from the hydraulic oil pumped into the sealed chamber may drive the actuating sleeve 500 to the second position. Further, the pressure in sealed chamber 508 may be controlled with a check valve/relief valve. A pressure transducer may monitor the pressure in sealed chamber 508. In response to the pressure in the sealed chamber 508 falling lower than desired pressure, the electric motor 502 and hydraulic pump may be pump additional hydraulic oil into the sealed chamber 508 to restore the desired pressure to sealed chamber 508. In response to pressure in the sealed chamber 508 exceeding a maximum desire pressure (e.g., due to thermal expansion of the hydraulic oil or from compression of sealed chamber 508 due to mechanical loading), the relief valve may vent a portion of the hydraulic oil back to the reservoir, which may reduce pressure in the sealed chamber 508.
Moreover, the actuator 218 may be configured to drive the actuating sleeve 500 from the second position back to the first position. For example, a solenoid valve (not shown) may open to allow the hydraulic oil in the sealed chamber 508 to vent back to the reservoir. Further, the actuator 218 may comprise a biasing mechanism (not shown). The biasing mechanism may comprise a spring configured to apply a biasing force to the actuating sleeve 500 in a direction toward the first position. As the pressure in the sealed chamber 508 decreases, via the oil being vented, the actuation force on the actuating sleeve 500 from pressure in the sealed chamber may fall below the biasing force from the biasing spring, such that the biasing spring may drive the actuating sleeve 500 from the second position to the first position. As such, the actuator may selectively move the actuating sleeve between the first position and the second position to adjust the bending stiffness and/or torsional stiffness of the adjustably flexible downhole tool 150.
Moreover, as set forth above, the actuator 218 may be configured to drive the actuating sleeve 500 from the second position to the first position. In some embodiments, the electric motor 502 may operate in the reverse direction to move actuating sleeve 500 away from the outer sleeve 210 and back to the first position. As such, the actuator 218 may selectively move the actuating sleeve 500 between the first position and the second position to adjust the bending stiffness and/or torsional stiffness of the adjustably flexible downhole tool 150. Indeed, the actuator 218 may alternate the actuating sleeve 500 between the first position and the second position as the bottom hole assembly 134 moves along the wellbore 102 based at least in part on a portion of the wellbore (e.g., straight portion or curved portion) through which the bottom hole assembly 134 is traveling.
Accordingly, the present disclosure may provide systems for adjusting bending stiffness and/or torsional stiffness of an adjustably flexible downhole tool as the bottom hole assembly moves through a wellbore. The claim may comprise any of the various features disclosed herein, including one or more of the following statements.
Statement 1. A system for an adjustably flexible downhole tool comprises first and second connector ends; a shaft extending between the first and second connector ends, wherein the shaft is configured to bend in response to passing through curved portions of a wellbore; an outer sleeve disposed around at least a portion of the shaft and extending from the first connector end in a direction toward the second connector end; and at least one adjustable member configured to move axially, with respect to the shaft, from a first position to a second position to increase bending stiffness and/or torsional stiffness of the adjustably flexible downhole tool, wherein the at least one adjustable member at least partially restrains bending of the shaft in the second position.
Statement 2. The system of statement 1, wherein the at least one adjustable member is disposed within an annulus formed between a radially outer surface of the shaft and a radially inner surface of the outer sleeve.
Statement 3. The system of statement 1 or statement 2, wherein the first position is disposed proximate the first connector end, and wherein the second position is disposed proximate the second connector end.
Statement 4. The system of any preceding statement, wherein the at least one adjustable member comprises an annular piston, wherein a radially inner piston surface of the annular piston interfaces with a radially outer shaft surface of the shaft and a radially outer piston surface of the annular piston interfaces with a radially inner sleeve surface of the outer sleeve, and wherein the annular piston at least partially restrains radial movement of the shaft with respect to the outer sleeve at a location of the annular piston.
Statement 5. The system of any preceding statement, further comprising a track disposed along a path of the at least one adjustable member from the first position to the second position, wherein the track is configured restrain rotational movement of the at least one adjustable member with respect to the shaft and the outer sleeve.
Statement 6. The system of any preceding statement, further comprising a debris barrier spanning between the shaft and the outer sleeve, wherein the debris barrier is configured to prevent downhole debris from moving into an annulus formed between the shaft and the outer sleeve.
Statement 7. The system of any preceding statement, further comprising a wedge disposed proximate the second position, wherein the wedge is configured to secure the at least one adjustable member at the second position.
Statement 8. The system of any preceding statement, further comprising a pivot guide disposed about the shaft proximate the second connector end, wherein the pivot guide is disposed between the shaft and the outer sleeve, and wherein the pivot guide comprises a spherical bearing, a crowned spline, or other constant velocity joint configured to pivot such that the shaft may radially deflect with respect to the outer sleeve.
Statement 9. The system of any of statements 1, 3, 5, or 6, wherein the at least one adjustable member comprises an actuating sleeve that is axially offset from the outer sleeve in the first position, and wherein the actuating sleeve is configured to interface with the outer sleeve to restrain bending of the shaft in the second position.
Statement 10. The system of statement 1 or statement 3, wherein the at least one adjustable member comprises a plurality of annular rings, wherein each annular ring of the plurality of annular rings is configured to interface with at least one adjacent annular ring, in the second position, to restrain bending of the shaft in the second position.
Statement 11. The system of any preceding statement, further comprising an actuator configured to drive the adjustable member to any position between the first position and the second position, wherein the actuator may be configured to drive the adjustable member forward toward the first position and/or in reverse toward the second position, and wherein the actuator comprises a hydraulic actuator, an electric motor, or some combination thereof.
Statement 12. A system for an adjustably flexible downhole tool comprises first and second connector ends; a shaft extending between the first and second connector ends, wherein the shaft is configured to bend in response to passing through curved portions of a wellbore; and a plurality of annular rings disposed about a radially outer surface of the shaft along a length of the shaft, wherein each annular ring of the plurality of annular rings is configured to move axially, with respect to the shaft, from a first position to a second position, and wherein each annular ring of the plurality of annular rings is configured to interface with at least one adjacent annular ring, in the second position, to at least partially restrain bending of the shaft and increase bending stiffness and/or torsional stiffness of the adjustably flexible downhole tool.
Statement 13. The system of statement 12, wherein each annular ring of the plurality of annular rings comprises a first interlocking feature at a first axial end of the annular ring and a second interlocking feature at a second axial end of the annular ring, wherein the first interlocking feature comprises a protrusion, and wherein the second interlocking feature comprises a recess.
Statement 14. The system of statement 12 or statement 13, further comprising a locking feature configured to axially hold the plurality of annular rings in the second position.
Statement 15. The system of any of statements 12-14, wherein the locking feature comprises threading, an expandable ring, a spring energized lock, collet, or some combination thereof.
Statement 16. The system of any of statements 12-15, further comprising a torsional locking feature configured to restrain rotational movement of the plurality of annular rings with respect to the shaft.
Statement 17. The system of any of statements 12-16, further comprising an actuator configured to drive the plurality of annular rings axially, with respect to the shaft, from the first position to the second position such that the plurality of annular rings are compressed toward each other.
Statement 18. A system for an adjustably flexible downhole tool comprises first and second connector ends; a shaft extending between the first and second connector ends, wherein the shaft is configured to bend in response to passing through curved portions of a wellbore; an outer sleeve disposed around at least a portion of the shaft and extending from the first connector end in a direction toward the second connector end; and an actuating sleeve coupled to the second connector end, wherein the actuating sleeve is configured to move axially, with respect to the shaft, from a first position to a second position, and wherein the actuating sleeve in configured to interface with outer sleeve in the second position to restrain bending of the shaft and increase bending stiffness and/or torsional stiffness of the adjustably flexible downhole tool.
Statement 19. The system of statement 18, further comprising a shear pin configured to hold the actuating sleeve in the first position, wherein the shear pin is configured to shear to release the actuating sleeve in response to an actuation force.
Statement 20. The system of statement 18 or statement 19, further comprising an actuator configured to drive the actuating sleeve from the first position to the second position, wherein the actuator comprises a hydraulic actuator, an electric motor, or some combination thereof.
Therefore, the present embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present embodiments may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, all combinations of each embodiment are contemplated and covered by the disclosure. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure.
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