Patent Grant
12110750
None.
Not applicable.
Not applicable.
Wellbore servicing operations typically utilize a first type of downhole tool for small tubulars and a second type for large tubulars as the downhole tool needs to be anchored to the wellbore tubular during the servicing operation. The downhole tool is typically conveyed into the wellbore through a small wellbore tubular, for example, production tubing. In some scenarios, the downhole tool can anchor to the small wellbore tubular to perform a servicing operation within the wellbore. The downhole tool typically utilizes a first type of anchoring system with wedges to extend a set of slips to grip the small wellbore tubing. The first type of anchoring system for the downhole tool can have limited reach and may not be suitable for large wellbore tubing.
In other scenarios, the downhole tool can exit the small wellbore tubular to anchor inside of a large wellbore tubular, for example, a casing string. The downhole tool typically uses a second type of anchoring system, referred to as a high expansion anchoring system, to extend an anchoring pad out to grip the large wellbore tubing. The high expansion anchoring system of the downhole tool may not generate the gripping force to anchor the downhole tool in small wellbore tubing. A downhole tool with an anchoring system that can anchor in small wellbore tubulars and large wellbore tubulars is desirable.
For a more complete understanding of the present disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.
It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the disclosed systems and methods may be implemented using any number of techniques, whether currently known or not yet in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, but may be modified within the scope of the appended claims along with their full scope of equivalents.
Once an oil or gas well is drilled, a downhole tool can be conveyed into the wellbore via a logging cable to perform wellbore operations such as logging or perforating operations. To conduct these wellbore operations, the downhole tool may need to be centralized, e.g., positioned along the central axis of an oilfield tubular. The centralization of the downhole tool can be accomplished with an anchoring mechanism, e.g., linkages equally spaced around the outside of the downhole tool that extends radially to anchor or grip onto an inner surface of the oilfield tubular.
The anchoring mechanism for the downhole tools can generate an anchoring force to ensure proper wellbore operation. The anchoring mechanism can comprise a set of anchor pads to generate a radial force with a friction component against the inner surface of the oilfield tubular to prevent sliding or movement between the anchor pad and the inner surface of the tubular. The anchoring mechanism can comprise an uphole arm, an anchor pad, and a downhole arm to extended to large diameter oilfield tubular, e.g., casing. In another scenario, the anchoring mechanism can comprise a set of slips and wedge to extend to small diameter tubulars, e.g., production tubing.
To address some of the challenges described above, as well as others, apparatus, systems, and methods for anchoring a downhole tool in large diameter and small diameter oilfield tubulars with a singular anchoring mechanism are described. Various embodiments include an anchoring mechanism configured to be extended by at least one wedge. This anchoring mechanism can anchor the downhole tool to a small diameter tubular. Various embodiments comprise an anchoring mechanism with an extension mechanism to extend the past the outer surface of the wedge to anchor the downhole tool within a large diameter tubular. Various example embodiments that can provide some or all of these advantages will now be described in detail.
Turning now to
The wireline servicing operation can begin with transporting the surface logging facility 4, the downhole tool assembly 2, and various wireline equipment to a remote wellsite. The remote wellsite can on land (as illustrated in
The wireline servicing operation can be performed with a drilling or workover rig 12 comprising a derrick 14 and various wireline equipment 16 for the conveyance of the downhole tool assembly 2 into the wellbore 8. The wellbore 8 may include one or more casing string 18, e.g., pipes threadingly coupled together, and anchored at surface with a wellhead 20. The casing string 18 can be cemented 22 within the wellbore 8. For example, the wellbore 8 can comprise a casing string 18 supported by cement 22 extending into a formation 24. In some embodiments, the wellbore 8 can comprise a portion of the wellbore 8 without a casing string 18.
The wireline servicing operation comprises lowering the downhole tool assembly 2 to a target depth, e.g., the formation 24, anchoring the downhole tool assembly 2 with an anchoring device 34, and activating a service tool 36. The downhole tool assembly 2 comprises a wireline logging head 32 to electrically couple the anchoring device 34 and the service tool 36 to the logging facility 4. The service tool 36 of the downhole tool assembly 2 can be a shifting tool, a perforating gun assembly, a packer assembly, a frac plug assembly, an isolation device, or any other downhole servicing tool. For example, the downhole tool assembly 2 can be lowered into the wellbore 8 to a target depth, e.g., the formation 24, anchored to the casing string 18 via the anchoring device 34, and the service tool 36 can be activated, for example, the perforating gun assembly fired to perforate the casing string 18. The anchoring device 34 within the downhole tool assembly 2 can be actuated from the surface logging facility 4, also referred to as a logging facility, via a processor within the wireline logging head 32. The wireline logging head may include one or more processors, memory, and a data acquisition process executing in memory to control the function of the anchoring device 34 and record periodic datasets indicative of the servicing operation. The periodic datasets can comprise measurement data from one or more sensors, such as accelerometers, and may be stored in memory or transmitted to surface via the logging cable 6. The measurement data can be communicated to the logging facility 4 for storage, processing, and analysis. The logging facility 4 may be provided with electronic equipment 38 and a controller 10, e.g., computer system comprising a processor and non-transitory memory, for various types of signal processing. In some embodiments, the wireline logging head 32 may not include a processor and the logging facility 4 may control the anchoring device 34 via the controller 10.
Turning now to
In some embodiments, the downhole tool assembly 2 can be conveyed through the production tubing, e.g., small oilfield tubular, to a target location within a large oilfield tubular below the exit of the production tubing, e.g., within a casing string location 28. The anchoring device 34 of the downhole tool assembly 2 can be activated to anchor the downhole tool assembly 2 to the inner surface 26 of the casing string 18, e.g., large oilfield tubular, at the target depth. The service tool 36 of the downhole tool assembly 2 can be activated to perform the wellbore operation or a portion of the wellbore operation within the casing string 18.
In some embodiments, the downhole tool assembly 2 can be conveyed through the production tubing and the casing string location 28 to a location within a lower completion 30. The lower completion can comprise a hanger 40 and a completion string 42. The hanger 40 can be a liner hanger, a production packer, a gravel pack packer, a cementing equipment, or any downhole assembly configured to anchor a smaller tubular to a larger tubular. The completion string 42 can comprise a small diameter oilfield tubular (e.g., production tubing, liner, casing, or workover tubing) and/or completion equipment such as a housing, an extension, a sand screen, a completion valve, an ESP pump assembly, an isolation device, or any combination thereof. The downhole tool assembly 2 can be conveyed into the lower completion 30 via the workstring 6 to a target location within the completion string 42. The anchoring device 34 of the downhole tool assembly 2 can be activated to anchor the downhole tool assembly 2 to the inner surface 44 of the completion string 42, e.g., small oilfield tubular, at the target depth. The service tool 36 of the downhole tool assembly 2 can be activated to perform the wellbore operation or a portion of the wellbore operation within the completion string 42.
Turning now to
The anchoring device 200 can include a first arm 270 and an extension mechanism to guide the anchor pad 210 into engagement with an inner surface of a tubular. In some embodiments, the extension mechanism can be a telescopic arm 272. The first arm 270 can be a rigid member rotationally coupled to the first pivot axle 228 of the first hub 212 and the first pivot point 244 of the anchor pad 210. Although the first arm 270 is illustrated as a round rod shape, it is understood that the first arm 270 can have any geometric cross-sectional shape, for example, round, oval, square, rectangular, hexagonal, octagonal, any suitable geometric shape, or combinations thereof. The first arm 270 is configured to transfer an actuation force from the first hub 212 via the first pivot axle 228 to the anchor pad 210 via the first pivot point 244.
In some embodiments, the telescopic arm 272, e.g., the extension mechanism, can comprise an extension arm 276 slidably engaged with a housing 278. The extension arm 276 can be a ridge member with a generally round shape and rotationally coupled to the second pivot point 246 of the anchor pad 210. The housing 278 can be a generally cylinder shape with an outer surface 280, an inner surface 282, and rotationally coupled to the pivot axle 266 of the wedge hub 214. The extension arm 276 can move a linear distance labeled “A” within the housing 278 of the telescopic arm 272. In a first position, also referred to as the run-in position, the linear distance A can be a maximum value and the extension arm 276 is constrained to the interior of the housing 278, e.g., can't exit the housing 278. In some embodiments, the telescopic arm 272 can be placed in tension while in the first position. For example, the telescopic arm 272 can be in tension to retain the anchor pad 210 in a run-in position by pulling the second pivot point 246 with the pivot axle 266 of the wedge hub 214.
Turning now to
The extension mechanism can be configured in an activated or a deactivated mode. In the deactivated mode, the linear distance labeled “A” is greater than zero and the anchor pad is radially extended towards the inner surface of the tubular by the tapered outer surface 260 of the wedge hub 214 and the inner surface 262 of the anchor pad 210. In the activated mode, the linear distance labeled “A” is equal to zero the anchor pad is radially extended towards the inner surface of the tubular by the first pivot point 244 and the second pivot point 246. In some embodiments, the extension mechanism can be in compression in the activated mode. For example, an end face of the extension arm 276 can be in direct contact with the housing 278 when the linear distance “A” is equal to zero and thus, additional force places the extension arm 276 in compression.
In some embodiments, the anchor pad 210 grips the inner surface 44 of the tubular 42 with the extension mechanism deactivated and/or with the distance A greater than zero. For example, the outer surface 232 of the anchor pad 210 can grip the inner surface 44 of the tubular 42 when the extension arm 276 is 50% of the distance A within the housing 278. The size of the tubular 42, e.g., distance of the inner surface 44 to the central axis 230, can determine when the outer surface 232 of the anchor pad 210 grips the inner surface 44 and thus, determine the portion of the distance A the extension arm 276 travels within the housing 278. In one scenario, the inner surface 44 can be closer to the central axis 230 and the extension arm 276 can travel 10% of the distance A when the anchor pad 210 grips the tubular 42. In another scenario, the inner surface 44 can be a greater distance from the central axis 230 and the extension arm 276 can travel 90% of the distance A when the anchor pad 210 grips the tubular 42. Although three percentages are described, it is under stood that the extension arm 276 can travel 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or 100% of the distance A until the anchor pad 210 grips the tubular 42. As illustrated in
In some embodiments, the actuation feature can urge the wedge hub 214 towards the first hub 212. For example, the actuation feature can urge the front face 254 of the wedge hub 214 towards the back face 226 of the first hub 212. In some embodiments, the actuation feature can comprise a first volume of fluid, a pump, and a second volume of fluid. For example, a mandrel within housing can be urged outward from the housing by transferring fluid from the first volume to the second volume by the pump. In some embodiments, the mandrel within the housing can be extended by an electric motor turning a gearing system mechanically coupled to the mandrel. In some embodiments, the mandrel can be a threaded rod that is extended/retracted from the housing by an electric motor. The actuation feature can be controlled to move in a first direction, e.g., to set the anchor mechanism, and move in a second direction, e.g., to release the anchor mechanism, by the controller. In some embodiments, the controller is electrically coupled to the actuation feature to provide voltage and power to the actuation feature.
Turning now to
Although the anchoring device 200 is illustrated as a single set of an anchor pad 210, a first arm 270, and a telescopic arm 272, it is understood that the anchoring device 200 can have 2 sets at 180 degrees, 3 sets at 120 degrees, 4 sets at 90 degrees, or any number of sets.
Turning now to
In some embodiments, the wedge hub 314 can be a generally cylindrical shape with an outer surface 350, a back face 352, a front face 354, and a tapered outer surface 360. The tapered outer surface 360 can have a frustoconical shape or a planar tapered surface. The tapered outer surface 360 of the wedge hub 314 may correspond and slidably engage with the inner surface 262 of the anchor pad 210. In some embodiments, the tapered outer surface 360 and inner surface 262 can both be a frustoconical shape configured for slidable engagement. In some embodiments, the tapered outer surface 360 and inner surface 262 can both be a planar tapered surface configured for slidable engagement.
The anchoring device can include a first arm 270 and an extension mechanism to guide the anchor pad 210 into engagement with an inner surface of a tubular. In some embodiments, the extension mechanism can comprise a sliding axle assembly 366 include a pivot axle 322 within an axle slot 324 located within the wedge hub 314. The axle slot 324 comprises a first end 326, an upper side 334, a lower side 332, and a second end 328. The pivot axle 322 can be configured to move from a linear distance labeled “A” from an initial position abutting the first end face 326 to a second position abutting the second end face 328. The axis of the wedge hub 314 can be coincident with the longitudinal axis 330 of the anchoring device 300. The back face 352 of the wedge hub 314 can be coupled to one or more parts and/or assemblies that are not illustrated. The sliding axle assembly 366, e.g., the extension mechanism, can be in a deactivated mode when the linear distance “A” is greater than zero and in an activated mode when the sliding axle assembly 366 is in a compressive state due to the linear distance “A” being zero.
In some embodiments, the anchoring device 300 can include a first arm 270 and a second arm 320 to guide the anchor pad 210 into engagement with an inner surface of a tubular. As previously described, the first arm 270 can be a rigid member rotationally coupled to the first pivot axle 228 of the first hub 212 and the first pivot point 244 of the anchor pad 210. The first arm 270 is configured to transfer an actuation force from the first hub 212 via the first pivot axle 228 to the anchor pad 210 via the first pivot point 244.
In some embodiments, the second arm 320 can be a rigid member rotationally coupled to a second pivot point 246 and the pivot axle 322. The second arm 320 can be a generally round cross-section shape or any other geometric cross-section. The second arm 320, coupled to the pivot axle 322, can move a linear distance labeled “A” within the axle slot 324 of the wedge hub 314. In a first position, also referred to as the run-in position, the linear distance A can be a maximum value and the second arm 320 can be placed in tension with the translating axle 322 abutting the first end 326. For example, the second arm 320 can be in tension to retain the anchor pad 210 in a run-in position with the axle 322 abutting the first end 326 while a tension force is placed on the wedge hub 314 via the back face 352. The sliding axle assembly 366, e.g., the extension mechanism, can have an activation mode and a deactivation mode. The sliding axle assembly 366 can be in the deactivation mode in response to being placed in the run-in position or the value of the linear distance A being greater than zero.
Turning now to
In some embodiments, the anchor pad 210 grips the inner surface 44 of the tubular 42 before the distance A reaches zero, e.g., in the deactivation mode. For example, the outer surface 232 of the anchor pad 210 can grip the inner surface 44 of the tubular 42 when the translating axle 322 is 50% of the distance A within the axle slot 324. As previously described, it is understood that the translating axle 322 can travel 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or 100% of the distance A until the anchor pad 210 grips the tubular 42. As illustrated in
Turning now to
Although the anchoring device 300 is illustrated as a single set of an anchor pad 210, a first arm 270, and a second arm 320, it is understood that the anchoring device 300 can have 2 sets at 180 degrees, 3 sets at 120 degrees, 4 sets at 90 degrees, or any number of sets.
In some embodiments, the anchoring device 200 can return from the set position, e.g., the second position, to a run-in position, e.g., the first position. For example, referring to
In some embodiments, the anchoring device 200 can return from a position wherein the anchor pad 210 is supported or in contact with the wedge hub 214 to the run-in position. The actuation mechanism can retract the wedge hub 214 to decrease the value of the linear distance “B” to a value of zero, e.g., the initial position or run-in position. The linear value of “A” within the telescoping arm 272 can increase as the linear value of “B” decreases as the anchor pad 210 is moved down the tapered outer surface 260 to the initial position as shown in
In some embodiments, the anchoring device 300 can return from the set position, e.g., the second position, to a run-in position, e.g., the first position. For example, referring to
In some embodiments, the anchoring device 300 can return from a position wherein the anchor pad 210 is supported or in contact with the wedge hub 314 to the run-in position. The actuation mechanism can retract the wedge hub 314 to decrease the value of the linear distance “B” to a value of zero, e.g., the initial position or run-in position. The linear value of “A” within the axle slot 324 can increase as the linear value of “B” decreases as the anchor pad 210 is moved down the tapered outer surface 360 to the initial position as shown in
The downhole tool assembly 2 can be anchored at a first target depth within the wellbore 8 to perform a service and moved to a second location within the wellbore to perform a service. In some embodiments, the downhole tool assembly 2 can be conveyed into a wellbore 8 to a target depth and anchored at that depth. For example, the downhole tool assembly 2 can be conveyed into the wellbore 8, via a workstring 6, to a first target depth, e.g., a casing string location 28, a controller 10 within the logging facility 4 can activate the anchoring device 34, and the downhole tool assembly 2 can be anchored by the anchoring device 34. The anchoring device 34 can extend the anchor pad 210 to a set position as illustrated in
The following are non-limiting, specific embodiments in accordance with the present disclosure:
While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, RJ, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=Rl+k*(Ru−Rl), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.
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