Downhole Tool Centralizing Pistons

Abstract

The present disclosure is directed to setting pistons designed to centralize downhole tools within a wellbore. In one embodiment, a downhole tool includes a probe extendable to engage a wall of a wellbore and a setting piston extendable towards the wall of the wellbore. A roller is coupled to the setting piston and designed to roll circumferentially along the wall to pivot the downhole tool within the wellbore.

Description

BACKGROUND OF THE DISCLOSURE

The disclosure relates generally to pistons that may be employed in downhole tools to position the downhole tools within a wellbore.

Wellbores (also known as boreholes) are drilled to penetrate subterranean formations for hydrocarbon prospecting and production. During drilling operations, evaluations may be performed on the subterranean formation for various purposes, such as to locate hydrocarbon-producing formations and manage the production of hydrocarbons from these formations. To conduct formation evaluations, the drill string may include one or more drilling tools that test and/or sample the surrounding formation, or the drill string may be removed from the wellbore, and a wireline tool may be deployed into the wellbore to test and/or sample the formation. These drilling tools and wireline tools, as well as other wellbore tools conveyed on coiled tubing, slick line, drillpipe, casing or other conveyers, are also referred to herein as “downhole tools.”

Formation evaluation often requires that fluid from the formation be drawn into the downhole tool for testing and/or sampling. Various fluid communication devices, such as probes, are typically extended from the downhole tool and placed in contact with the wellbore wall to establish fluid communication with the formation surrounding the wellbore and to draw fluid into the downhole tool. The probe may include a packer that establishes a seal with the sidewall of a wellbore. However, the inability to centralize the downhole tool in the wellbore may result in an incomplete seal.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of an embodiment of a wellsite system that may employ downhole tools with centralizing pistons, according to aspects of the present disclosure;

FIG. 2 is a schematic view of another embodiment of a wellsite system that may employ downhole tools with centralizing pistons, according to aspects of the present disclosure;

FIG. 3 is a top cross-sectional view of a downhole tool employing a centralizing piston, according to aspects of the present disclosure;

FIG. 4 is a top cross-sectional view of the downhole tool of FIG. 3 depicting an initial position within the wellbore and a centralized position within the wellbore, according to aspects of the present disclosure;

FIG. 5 is a perspective view of the piston assembly of FIGS. 3 and 4, according to aspects of the present disclosure;

FIG. 6 is a perspective view of another embodiment of a piston assembly, according to aspects of the present disclosure;

FIG. 7 is a schematic view of an embodiment of a downhole tool that may employ the piston assemblies of FIGS. 5 and 6, according to aspects of the present disclosure;

FIG. 8 is a flow chart depicting a method for centralizing a downhole tool in a wellbore, according to aspects of the present disclosure;

FIG. 9 is a top cross-sectional view of another embodiment of a downhole tool employing one or more rollers, according to aspects of the present disclosure; and

FIG. 10 is a schematic view of the downhole tool of FIG. 9.

DETAILED DESCRIPTION

It is to be understood that the present disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting.

The present disclosure is directed to pistons that may be employed to centralize downhole tools within a wellbore. According to certain embodiments, the pistons may include rollers designed to centralize the tool within the wellbore. For example, the rollers may include wheels designed to roll along the circumference of the wellbore wall to centralize the tool along a longitudinal axis of the wellbore. In certain embodiments, the downhole tool may pivot around a probe extended toward an opposite side of the wellbore from the centralizing pistons.

FIGS. 1 and 2 depict examples of wellsite systems that may employ the centralizing piston systems and techniques described herein. FIG. 1 depicts a rig 100 with a downhole tool 102 suspended therefrom and into a wellbore 104 via a drill string 106. The downhole tool 100 has a drill bit 108 at its lower end thereof that is used to advance the downhole tool into the formation and form the wellbore.

The drillstring 106 is rotated by a rotary table 110, energized by means not shown, which engages a kelly 112 at the upper end of the drillstring 106. The drillstring 106 is suspended from a hook 114, attached to a traveling block (also not shown), through the kelly 112 and a rotary swivel 116 that permits rotation of the drillstring 106 relative to the hook 114. The rig 100 is depicted as a land-based platform and derrick assembly used to form the wellbore 104 by rotary drilling.

Drilling fluid or mud 118 is stored in a pit 120 formed at the well site. A pump 122 delivers the drilling fluid 118 to the interior of the drillstring 106 via a port in the swivel 116, inducing the drilling fluid to flow downwardly through the drillstring 106 as indicated by a directional arrow 124. The drilling fluid exits the drillstring 106 via ports in the drill bit 108, and then circulates upwardly through the region between the outside of the drillstring and the wall of the wellbore, called the annulus, as indicated by directional arrows 126. The drilling fluid lubricates the drill bit 108 and carries formation cuttings up to the surface as it is returned to the pit 120 for recirculation.

The downhole tool 102, sometimes referred to as a bottom hole assembly (“BHA”), is preferably positioned near the drill bit 108 and includes various components with capabilities, such as measuring, processing, and storing information, as well as communicating with the surface. A telemetry device (not shown) is also preferably provided for communicating with a surface unit (not shown).

The downhole tool 102 further includes a sampling while drilling (“SWD”) system 128 including a fluid communication module 130 and a sampling module 132. The modules are preferably housed in a drill collar for performing various formation evaluation functions, such as pressure testing and sampling, among others. As shown in FIG. 1, the fluid communication module 130 is preferably positioned adjacent the sampling module 132. Additional devices, such as pumps, gauges, sensor, monitors or other devices usable in downhole sampling and/or testing also may be provided.

The fluid communication module 130 includes a probe 134, which may be positioned in a stabilizer blade or rib 136. The probe 134 includes an inlet for receiving formation fluid and a flowline (not shown) extending into the downhole tool for passing fluids through the tool. The probe 134 is preferably movable between extended and retracted positions for selectively engaging a wall of the wellbore 104 and acquiring fluid samples from the formation F. One or more setting pistons 138 may be provided to assist in positioning the fluid communication device against the wellbore wall. As discussed further below with respect to FIG. 3, the setting pistons 138 may include rollers designed to centralize the downhole tool 102 within the wellbore 104.

FIG. 2 depicts an example of a wireline downhole tool 200 that may employ the systems and techniques described herein. The downhole tool 200 is suspended in a wellbore 202 from the lower end of a multiconductor cable 204 that is spooled on a winch (not shown) at the surface. The cable 204 is communicatively coupled to an electronics and processing system 206. The downhole tool 200 includes an elongated body 208 that includes a formation tester 214 having a selectively extendable probe 216 and backup pistons 218 that are arranged on opposite sides of the elongated body 208. The extendable probe 216 is configured to selectively seal off or isolate selected portions of the wall of the wellbore 202 to fluidly couple to the adjacent formation F and/or to draw fluid samples from the formation F. Additional modules (e.g., 210) that provide additional functionality such as fluid analysis, resistivity measurements, coring, or imaging, among others, also may also be included in the tool 200.

The formation fluid may be expelled through a port (not shown) or it may be sent to one or more fluid sampling modules 226 and 228. In the illustrated example, the electronics and processing system 206 and/or a downhole control system are configured to control the extendable probe assembly 216 and/or the drawing of a fluid sample from the formation F. As discussed further below with respect to FIG. 3, setting pistons 218 may include rollers designed to centralize the downhole tool 102 within the wellbore 104.

FIG. 3 is a top cross-sectional view of a downhole tool 302 employing a centralizing piston assembly 300 in accordance with embodiments of the present disclosure. For example, the downhole tool 302 may be a drilling tool, such as the downhole tool 102 described above with respect to FIG. 1, that employs the centralizing piston assembly 300 for the setting piston 138. Further, the downhole tool 302 may be a wireline tool, such as the downhole tool 200 described above with respect to FIG. 2, that employs the centralizing piston assembly 300 for the setting piston 218. Moreover, the centralizing piston assembly 300 may be employed in other downhole tools, such as tools conveyed downhole on wired drill pipe.

The piston assembly 300 is designed to centralize the downhole tool 302 within the wellbore 304. As shown in FIG. 3, the piston assembly 300 is disposed on the radially opposite side of the downhole tool 302 from a probe assembly 306 so that the piston assembly is radially offset from the probe assembly 306 by approximately 180 degrees. However, in other embodiments, one or more piston assemblies 300 may be disposed at various radial locations around the downhole tool 302.

The probe assembly 306 includes an extension member 308 designed to radially extend from and retract towards the downhole tool 302. Accordingly to certain embodiments, the extension member 308 may be hydraulically or mechanically actuated. A plate 310 is disposed on the end of the extension member 308 to mount a packer 312. According to certain embodiments, the packer 312 may be a rubber gasket, or other rubber-like material, designed to sealingly engage the wall 313 of the wellbore 304. Formation fluid may enter the probe assembly 306 through an inlet 314 in the packer 312, and the formation fluid may be directed into the downhole tool 302 for testing and/or sampling.

The piston assembly 300 is also designed to extend from and retract towards the downhole tool 302. The piston assembly 300 includes a piston 316 that may be actuated to extend radially outward from the downhole tool 302 to engage the opposite side of the wall 313, which in turn may force the packer 312 towards the wall 313. According to certain embodiments, the piston assembly 300 may be designed to promote a good seal between the packer 312 and the wall 313 by forcing packer 312 towards the wall 313. The piston assembly 300 further includes a roller 318 coupled to the piston 316. For example, the roller 318 may be rotatably coupled to the end of the piston 316 by a bearing 320. The bearing 320 may facilitate rotation of the roller 318 and further may seal the interior of the piston 316 from debris and other fluid that may be disposed within the wellbore 304. Further, the bearing 320 may have a rugged construction designed to withstand the setting force of the piston assembly 300, which in certain embodiments may be approximately 5000 lbs.

As shown in FIG. 4, the roller 318 allows the downhole tool 302 to rotate within the wellbore 304 when the piston assembly 300 is deployed. For example, the downhole tool 302 may pivot from an initial position 322 to a centered position 324, as generally shown by the arrow 326. In particular, the roller 318 may rotate along the circumference of the wall 313, as generally shown by the arrow 328, which in turn may pivot the downhole tool 302, as shown by the arrow 326. In certain embodiments, the downhole tool 302 may pivot around the point 329 where the packer 312 contacts the borehole wall 313. As shown by arrow 330, the pivotal movement allows the tool to move away from the initial position 322, which is adjacent to the wellbore wall 313, to the centered position 324, which is generally aligned with the longitudinal axis 332 of the wellbore 304. The centralization provided by the piston assembly 300 may be particularly beneficial in deviated wells where gravity may promote an initial position of the downhole tool 302 within the wellbore that is adjacent to the wall 313, rather than aligned with the wellbore longitudinal axis 332.

FIG. 5 is a perspective view of the piston assembly 300. The roller 318, which is coupled to the piston 316 by the bearing 320, includes a pair of hemispherical wheels 334 designed to rotate as shown by arrow 328. Although the hemispherical wheels 334 are shown as rotating in the counterclockwise direction, the hemispherical wheels 334 may also rotate in the clockwise direction. According to certain embodiments, the roller 318 may be constructed of metal, rubber, or other suitable material. The roller 318 also includes grooves 336 disposed in the outer surfaces of the hemispheres 334 to provide friction between the roller 318 and the wall 313 (FIG. 4). The grooves 336 may be designed to provide an amount of friction between the roller 318 and the rugged borehole wall 313 that is greater than the friction provided by the bearing 320, which facilitates pivoting of the downhole tool within the wellbore. Further, the roller 318 may be designed to have a size sufficient to roll over bumps and other irregularities on the borehole wall. For example, in certain embodiments, the roller 318 may be designed to have a diameter 338 that is greater than or equal to approximately one inch. Further, in certain embodiments, the roller diameter 318 may be greater than the diameter 340 of the piston 316.

As shown in FIG. 5, the roller 318 includes a pair of hemispherical wheels 334 designed to engage the borehole wall. However, in other embodiments, the geometry, size, and/or style of the roller 318 may vary. For example, in other embodiments, the roller 318 may include any number of hemispherical wheels, spherical rollers, or wheels of a tire-like geometry.

FIG. 6 depicts another embodiment of a piston assembly 342 that includes a tire-like wheel 344. The wheel 344 is partially enclosed by a housing 346 and rotatably coupled to the piston 316 by a bearing that may be located within a stirrup section 347 of the housing 346. According to certain embodiments, the wheel 344 may have a tire-like geometry with grooves 348 designed to provide friction between the wheel 344 and the borehole wall. Further, the wheel 344 may have a diameter 350 that may be greater than the diameter 340 of the piston 316.

FIG. 7 depicts another embodiment of a downhole tool 352 that may employ the piston assemblies 300 designed to centralize the downhole tool 352 within the wellbore 354, in a manner similar to that described above with respect to FIGS. 3 to 5. The probe assembly 306 is disposed in a recess 358 within the housing 356 of the downhole tool 356. The probe assembly 306 is designed to extend from the housing 356 so that the packer 312 engages the wall 360 of the wellbore 354. Formation fluid may then enter the probe assembly 306 through the inlet 314, as generally shown by the arrows 362. The piston assemblies 300 may also extend from the housing 356 to engage the wall 360 and force the packer 312 towards an opposite side of the wall 360. As shown in FIG. 7, the piston assemblies 300 are disposed within recesses 364 in the housing 356. However, in other embodiments, the recesses 364 may be omitted.

When the piston assemblies 300 are retracted, the rollers 318, and in particular, the hemispherical wheels 334, may extend beyond the housing 356. Accordingly, the downhole tool 352 may include standoffs 366 that extend radially from the housing 356 to protect the rollers 318 during insertion of the downhole tool 352 into the wellbore 354. The standoffs 366 may be radially aligned with the piston assemblies 300 and may be designed to radially extend from the housing beyond the rollers 318 when the pistons are retracted. According to certain embodiments, the standoffs 366 may be bolted, clamped, or otherwise affixed to the housing 356. Further, the standoffs 366 may be disposed longitudinally on both sides of a roller 318. In other embodiments, the rollers 318 may be designed to fully retract within the housing 356 and the standoffs 366 may be omitted. Further, in certain embodiments, the rollers 318 may be disposed between stabilizer blades 112, which may function as standoffs to protect the rollers 318.

FIG. 8 depicts a method 368 for centralizing a downhole tool within a wellbore. The method may begin by disposing (block 330) a downhole tool within a wellbore. For example, the downhole tool may be lowered into a wellbore via a drillstring or wireline cable, as discussed above with respect to FIGS. 1 and 2. Once the downhole tool is positioned within the wellbore, a probe may be extended toward the wellbore wall. For example, the probe assembly 306 may be hydraulically or mechanically actuated to radially extend from the downhole tool 302, as shown in FIG. 3. Prior to, during, or after extension of the probe, backup pistons also may be extended (block 374) towards the wellbore wall. For example, the piston assembly 300 may be hydraulically or mechanically actuated to radially extend form the downhole tool 302, as shown in FIG. 3. The tool may then be centered (block 376) within the wellbore as rollers on the backup pistons allow the tool to pivot. For example, rollers 318 may roll along the circumference of the wellbore 304 to allow the tool to pivot around the point 329, as discussed above with respect to FIG. 4.

In certain embodiments, the rollers may then be locked (block 378) to inhibit further movement or pivoting of the tool within the wellbore. For example, as shown in FIG. 4, the rollers 318 may be mechanically or hydraulically locked in place to inhibit pivoting of the downhole tool 302. According to certain embodiments, the rollers may be locked using the hydraulic system included within the downhole tool for extending the probe assembly 306 and the piston assembly 300. In other embodiments, the rollers may be locked by actuating a pin, latch, or other mechanical locking device. Moreover, in yet other embodiments, the rollers may be locked by further extending the setting piston such that the roller engages the wall with increased force to inhibit movement of the roller. According to certain embodiments, the locking step may occur after a certain time has passed since deployment of the probe and/or setting piston. Further, in certain embodiments, the locking step may be omitted.

FIGS. 9 and 10 depict another embodiment of a roller that may be employed to position or centralize a downhole tool within a wellbore. The downhole tool 380 is generally similar to the downhole tool 352 described above with respect to FIG. 7, and includes the probe assembly 306 that engages the formation F. However, rather than employing setting pistons, the downhole tool 380 includes rollers 382 disposed around the circumference of the housing 356 of the downhole tool 380. According to certain embodiments, the rollers 382 may have an outer diameter 390 larger than the outer diameter 392 of the housing 356. Further, the outer diameter 390 of the roller 382 may be smaller than the inner diameter 394 of the wellbore 304 to provide a clearance 395 between the roller 382 and the wall 313 when the downhole tool 380 is generally centered along the longitudinal axis of the wellbore.

According to certain embodiments, the housing 356 may include one or more grooves that contain bearings 384 that rotatably couple the rollers 382 to the housing 356. The rollers 382 may rotate with respect to the housing 356, as generally shown by the arrow 386, and may roll along the surface of the wall 313. The rollers 382 may be constructed of metal, rubber, or other suitable material designed to engage the wall 313. The outer surface of the rollers 382 may include grooves 388 designed to provide friction between the rollers 382 and the wall 313.

When the probe assembly 306 is extended towards the wall 313, the rollers 382 may roll along the wall to pivot the downhole tool in the wellbore. The downhole tool may pivot in a manner similar to that described above with respect to FIG. 4. For example, the downhole tool 302 may pivot around the point 329 where the packer 312 contacts the borehole wall 313. The pivotal movement allows the tool to move away from an initial position adjacent to the wellbore wall 313 (e.g., similar to position 324 shown in FIG. 4) to a centered position (shown in FIG. 9) which is generally aligned with the longitudinal axis of the wellbore 304.

As shown in FIG. 10, the downhole tool 382 includes two rollers 382, with one roller 382 disposed on either side of the probe assembly 306. However, in other embodiments, any number of rollers 382 in various positions with respect to the probe assembly 306 may be employed. For example, in certain embodiments, a single roller 382 may be disposed above or below the probe assembly 306.

The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

Claims

1. A downhole tool comprising:

a probe extendable to engage a wall of a wellbore;

a setting piston extendable towards the wall of the wellbore; and

a roller coupled to the setting piston and configured to roll circumferentially along the wall to pivot the downhole tool within the wellbore.

2. The downhole tool of claim 1, wherein the probe comprises a packer to sealingly engage the wall and an inlet to direct formation fluid into the downhole tool.

3. The downhole tool of claim 1, wherein the roller comprises an outer diameter greater than and an outer diameter of the setting piston.

4. The downhole tool of claim 1, wherein the roller comprises a grooved wheel.

5. The downhole tool of claim 1, wherein the roller comprises a plurality of hemispheres coupled to the setting piston by a bearing extending between the plurality of hemispheres.

6. The downhole tool of claim 1, wherein the roller is configured to pivot the downhole tool about a contact point between the probe and the wall.

7. The downhole tool of claim 1, wherein the setting piston is disposed radially opposite from the probe.

8. The downhole tool of claim 1, wherein the roller comprises a single wheel disposed in a housing coupled to an end of the setting piston.

9. The downhole tool of claim 1, wherein the roller is configured to centralize the downhole tool along a longitudinal axis of the wellbore.

10. A method for centralizing a downhole tool comprising:

extending a probe of the downhole tool to engage a wall of a wellbore;

extending a setting piston of the downhole tool such that a roller coupled to the setting piston engages the wall; and

rolling the roller circumferentially along the wall to pivot the downhole tool within the wellbore.

11. The method of claim 10, wherein extending a probe and extending a setting piston occur simultaneously.

12. The method of claim 10, wherein rolling the roller comprises rolling a plurality of hemispheres along the wall.

13. The method of claim 10, wherein extending a probe comprises disposing a packer against the wall.

14. The method of claim 10, comprising locking the roller to inhibit movement of the roller along the wall.

15. A downhole tool comprising:

a probe extendable from a housing of the downhole tool to engage a wall of a wellbore;

a setting piston extendable from the housing at a location radially opposite the probe; and

a roller coupled to the setting piston and configured to roll circumferentially along the wall to pivot the downhole tool within the wellbore.

16. The downhole tool of claim 15 comprising an additional setting piston extendable from the housing at another location radially opposite the probe.

17. The downhole tool of claim 15, wherein the housing comprises a recess that houses the setting piston in a retracted position.

18. The downhole tool of claim 15, comprising one or more standoffs coupled to the housing and radially aligned with the setting piston.

19. The downhole tool of claim 18 wherein the one or more standoffs project from the housing such that the one or more standoffs radially extend beyond the roller when the setting piston is retracted.

20. The downhole tool of claim 15 comprising a pair of standoffs coupled to the housing and each radially aligned with the setting piston.