Multi-set packers for subterranean boreholes

Abstract

An embodiment of a packer for a subterranean borehole includes a throughbore, a body, a packing element, and a packer piston. In addition, the packer includes a mandrel inserted into the body along a central axis. The mandrel is configured to axially translate, relative to the central axis, under tension to selectively place the packer piston in fluid communication with the throughbore such that an increase in a pressure in the throughbore is configured to actuate the packer piston to expand the packing element.

Description

MULTI-SET PACKERS FOR SUBTERRANEAN BOREHOLESCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of U.S. provisional patent application serial number 63 / 756,578, filed on February 10, 2025, and entitled “Hydro-Mechanical Multi-Set Packet,” the contents of which are incorporated by reference in their entirety and for all purposes.BACKGROUND

[0002] In a subterranean borehole, such as a borehole used in the production of oil, gas, or other resources, a casing pipe (“casing”) may be installed for a myriad of reasons. For instance, the casing may be used to reinforce the borehole against the fluid pressure of the surrounding formation, to isolate the borehole from fluids within the formation, and to provide a passageway for fluids or equipment. A borehole may include multiple casings, such an outer casing and one or more inner casings nested within the outer casing.

[0003] For a number of reasons, it may be necessary to cut and pull a casing or portion thereof from the borehole. For example, a casing cutting and retrieval operation may be performed to facilitate abandonment of the borehole in preparation for drilling a sidetrack borehole to remove casing that is damaged.SUMMARY

[0004] Some embodiments disclosed are directed to a packer for a subterranean borehole. The packer includes a throughbore, a body, a packing element, and a packer piston. In addition, the packer includes a mandrel inserted into the body along a central axis. The mandrel is configured to axially translate, relative to the central axis, under tension to selectively place the packer piston in fluid communication with the throughbore such that an increase in a pressure in the throughbore is configured to actuate the packer piston to expand the packing element.

[0005] Some embodiments disclosed are directed to a method of operating a packer in a subterranean borehole. The method includes (a) increasing a tension on the packer to place a throughbore of the packer in fluidPATENTAttorney Docket No.: WBRE / 0012PCcommunication with a packer piston of the packer. In addition, the method includes (b) increasing a pressure in the throughbore, while maintaining the tension from (a), to actuate the packer piston and expand a packing element of the packer.

[0006] Some embodiments disclosed are directed to an assembly for cutting and retrieving a casing from a subterranean borehole. The assembly includes a casing cutter including one or more expandable blades, a spear including one or more expandable anchors, and a packer coupled to the spear and the casing cutter. The packer includes a throughbore, a body, a packing element, and a packer piston. In addition, the packer includes a mandrel inserted into the body along a central axis. The mandrel is configured to axially translate, relative to the central axis, under tension to selectively place the packer piston in fluid communication with the throughbore such that an increase in fluid pressure in the throughbore is configured to actuate the packer piston to expand the packing element.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] For a detailed description of various exemplary embodiments, reference will now be made to the accompanying drawings in which:

[0008] FIGs. 1 A-1 F are sequential schematic illustrations of a casing cutting and retrieval operation for a subterranean borehole according to one or more embodiments, which may be combined with other embodiments;

[0009] FIG. 2 is a cross-sectional view of a packer that may be utilized in the casing cutting and retrieval operation of FIGs. 1 A-1 F according to one or more embodiments, which may be combined with other embodiments;

[0010] FIGs. 3A and 3B are enlarged, cross-sectional views of the packer of FIG. 2 showing a mandrel of the packer being transitioned between a retracted position and an extended position, respectively, according to one or more embodiments, which may be combined with other embodiments;

[0011] FIGs. 4A and 4B are enlarged, cross-sectional views of the packer of FIG. 2 showing a plunger of the packer being transitioned between an unlocked and locked position, respectively, with the mandrel in a retracted positionPATENTAttorney Docket No.: WBRE / 0012PCaccording to one or more embodiments, which may be combined with other embodiments;

[0012] FIG. 40 is an enlarged, cross-sectional view of the packer of FIG. 2 showing the plunger in an unlocked position with the mandrel in an extended position according to one or more embodiments, which may be combined with other embodiments;

[0013] FIG. 5 is an enlarged, cross-sectional view of an alternative example of the packer of FIG. 2, including a packer piston that is actuated uphole to expand a packing element according to one or more embodiments, which may be combined with other embodiments; and

[0014] FIG. 6 is a flow diagram of a method according to one or more embodiments, which may be combined with other embodiments.

[0015] In the Drawings, like numbers refer to like elements throughout. As well, terms such as “uphole” and “downhole” may by appreciated by one of skill in the art to refer to a described first element or item and its relative position comparatively to a second or another element or item, such as within a wellbore or along a working tool string. Such relative language is effective regardless of orientation of the tool string or the wellbore, such as vertical, substantially vertical, deviated, substantially horizontal, or horizontal.DETAILED DESCRIPTION

[0016] A casing cutting and retrieval operation for a subterranean wellbore may be performed by using an assembly that includes a casing cutter, a spear, and a packer. The spear may be configured to hold and retrieve the cut casing. The packer may be configured to facilitate fluid circulation around the cut casing. The packer may comprise a mechanical tension-set packer. If the packer is positioned uphole of the spear along the assembly, there is a risk that tension transmitted through the packer to the spear, such as when setting the anchors of the spear, may inadvertently set the packer.

[0017] If the packer is positioned downhole of the spear along the assembly, then the spear cannot be used to assist with setting the packer. Additional equipment, such as additional slips, may be necessary to complete the casing cutting and retrieval operation, rendering the actuation of the packer during thisPATENTAttorney Docket No.: WBRE / 0012PCoperation more complex. Additionally, such an arrangement increases on the assembly the distance between the spear and the casing cutter, which may adversely affect centralization of the casing cutter during cutting operations. Any stability issue that develops during the cutting operations may have detrimental impacts.

[0018] Hydraulically set packers are not typically used for a casing cutting and retrieval operation because the elevated fluid pressures utilized during such operation can inadvertently set the packer. For instance, elevated fluid pressures may trigger or activate expansion of the anchors of the spear or the blades of the casing cutter, so an elevated fluid pressure may also cause a premature or undesired expansion of the packing element of the packer.

[0019] As those of skill in the art may realize, conventional hydraulically-set packers are so-called “single-set” packers. Single-set packers may only be set once during a trip within the borehole. Premature actuation of a single-set hydraulically-actuated packer may require that the actuated packer be tripped back to the surface to allow the packer to be redressed or re-set, resulting in lost rig time and increased operational risk.

[0020] Accordingly, one or more embodiments disclosed related to systems and related methods for performing casing cutting and retrieval operations in a wellbore that enable the entire casing cutting and retrieval process to be completed in a single trip. In one or more embodiments, which may be combined with other embodiments, the systems disclosed may include a hydraulically-set packer featuring a selective locking and unlocking mechanism that prevents unintended activation under high fluid pressure or flow rates while also allowing controlled activation. The controlled activation may occur through lower fluid pressure, reduced fluid flow, such as through a ball drop that blocks fluid flow, mechanical manipulation, such as by “jarring” the drill string, or a combination thereof. In one or more embodiments, which may be combined with other embodiments, the hydraulically-set packer of the systems disclosed may be configured to be set and unset one or more times, such as multiple times, during a single trip within the borehole. The ability to set and unset the packer one or more times may improve flexibility, overall efficiency, and reducePATENTAttorney Docket No.: WBRE / 0012PCrisk for a casing cutting and retrieval operation or any other downhole operation in which the packer is being utilized.

[0021] FIGs. 1A-1F schematically illustrate a casing cutting and retrieval operation for a portion of a subterranean borehole 10 (“borehole” or “wellbore” 10) defined by and extending through a subterranean formation 5. The borehole 10 is depicted as including an outer casing 20 lining a portion of the wall defining the borehole 10. An inner casing 30 is installed within an interior defined in part by the outer casing 20 and the borehole 10.

[0022] In FIG. 1A, a cutting and retrieval assembly 100 is shown positioned in the borehole 10 having run or “tripped” downhole into the borehole 10 as the lead end of a workstring 50. In one or more embodiments, which may be combined with other embodiments, besides the assembly 100, the workstring 50 may comprise a plurality of pipes or other tubulars that are coupled or connected in series, such as through threaded couplings, that extend from a surface entry point to a position downhole. In one or more embodiments, which may be combined with other embodiments, the workstring 50 may at least partially comprise a continuous tether, such as coiled tubing, wireline, slickline, electric line (“E-line”), fiber optic line, or a continuous rod.

[0023] Generally, FIGs. 1A-F shows that the cutting and retrieval assembly 100 includes a casing cutter 110. The casing cutter 110 may include one or more blades 112 configured to sever metal equipment, such as a casing or other tubulars.

[0024] FIGs. 1A-F also show that the cutting and retrieval assembly 100 includes a spear 120 that is positioned adjacent to and uphole of the casing cutter 110. The spear 120 comprises anchors 122, such as slips. In FIGs. 1A-F, the anchors 122 are shown extended into a gripping or frictional contact with the interior surface of the inner casing 30. In one or more embodiments, which may be combined with other embodiments, the anchors 122 may be expanded into initial contact with the inner casing 30 by increasing a pressure or a flow rate of the fluid present or introduced into the wellbore 50, such as fluid shown flowing (arrows 60 in FIG. 1 B and to be described further) through portions ofPATENTAttorney Docket No.: WBRE / 0012PCthe workstring 50 and assembly 100. Thus, the spear 120 may be called a “hydraulically-actuated” spear 120.

[0025] Generally, once the anchors are initially deployed against the interior surface of a casing, tension may be applied to the assembly by jarring or pulling on the workstring uphole. Such an action after the anchors are deployed against the interior surface of the inner casing may drive the anchors into the inner casing itself, securing the assembly and workstring to the inner casing. While the internal structural details of the spear are not shown or described in FIGs. 1A-F or the disclosure with specificity, one may appreciate that spears, such as the spear, and the operation thereof are well known to persons of skill in the art.

[0026] FIGs. 1A-F also shows that the cutting and retrieval assembly 100 includes a packer 130 that is positioned adjacent to and uphole of the spear 120. The packer 130 includes a packing element 132. In one or more embodiments, which may be combined with other embodiments, the packing element may be comprised of an elastomeric material. FIG. 1A illustrates the packer 130 in an unset or non-deployed configuration, where the packing element 132 is an undeployed or retracted state and not in contact with the inner surface of the inner casing 30.

[0027] FIG. 1B depicts a cutting operation of the inner casing 30. Specifically, the anchors 122 of the spear 120 have been engaged with the inner casing 30. In addition, a fluid is circulated (arrows 60) through the cutting and retrieval assembly 100 via the workstring 50. The fluid introduced into and circulating within the wellbore may comprise any suitable liquid or semi-liquid utilized for treating, conditioning, plugging, abandoning, or other wellbore or formation operations, including, but not limited to, brine(s), drilling muds, water, emulsion, acids, alkalines, gels, such as “fragile gels”, and components of the compositions thereof. The fluid use is not limited, that is it may be used to increase pressures within the cutting and retrieval assembly, to flush out one or more fluid pathways defined in the borehole, to lubricate and cool blades of a cutting tool, such as the casing cutter of the assembly, or other functions as needed downhole. Throughout this description, “fluid” is used to genericallyPATENTAttorney Docket No.: WBRE / 0012PCrefer to any suitable fluid(s) or fluid combination(s) that may be flowed within a subterranean wellbore or equipment introduced for various purposes, where the flow of the fluid is represented by arrows to show movement, such as arrows 60. Throughout the various operations described, a fluid may comprise the same fluid throughout or may comprise different fluids at different times or for different functions. Thus, reference to a singular fluid (and its flow via arrows 60) is intended to simplify the description and is not meant to limit the particular fluid(s) or fluid combination(s) that may be used.

[0028] During the cutting operation of FIG. 1B, the fluid flows (see arrows 60) downhole through and out the cutting and retrieval assembly 100 into the inner casing 30, and then uphole through an annulus 38. Annulus 38 is defined between the inner casing 30 and both the cutting and retrieval assembly 100 and the workstring 50.

[0029] As shown in FIGs. 1A and 1B, the blades 112 of the casing cutter 110 are expanded radially outward and engage with the inner casing 30. Specifically, the blades 112 may be expanded into initial contact with the inner casing 30 by increasing a pressure or flow rate of the fluid. The casing cutter 110 may be referred to as a “hydraulically-actuated” casing cutter 112. While the internal structural details of the casing cutter 110 are not shown or described, it should be appreciated that casing cutters, such as the casing cutter 110, and the operation thereof are well-known to persons of skill in the art.

[0030] During the cutting operation, tension is placed on the inner casing 30 via the workstring 50 through the spear 120. Specifically, the tension applied to the workstring 50 may be transferred to the inner casing 30 via the anchors 122 of the spear 120. While the anchors 122 are engaged, the fluid is circulated (arrows 60) through the assembly 100 and back uphole, the casing cutter 110 is rotated such that the extended blades 112 to engage with and cut through the casing 30, and the packer 130 is maintained in an unset configuration so that fluid may continue to flow back uphole unencumbered by the packer 130.

[0031] In one or more embodiments, which may be combined with other embodiments, the casing cutter 110 may be rotated via the workstring 50 byPATENTAttorney Docket No.: WBRE / 0012PCuse of suitable surface equipment, such as a kelly drive, power swivel, rotary table, top drive, or combinations thereof. In one or more of these embodiments, the spear 120 may include or be coupled to one or more bearings (not shown) configured to allow the relative rotation of the casing cutter 110 and workstring 50. While the casing cutter 110 and workstring 50 are being rotated, the spear 120 via its engaged anchors 122, may remain stationary or substantially stationary.

[0032] In one or more embodiments, which may be combined with other embodiments, the casing cutter 110 may be rotated by one or more downhole systems or devices that are coupled to or incorporated into the cutting and retrieval assembly 100 or workstring 50 such that the workstring 50 and other portions of the assembly 100 do not rotate while the casing cutter 100 rotates. Such downhole systems and devices that may support casing cutter rotation may include, for instance, mud motors, a positive displacement motor, turbine motor, rotary steerable system, downhole electric motor, or combinations thereof.

[0033] Reference is now made to FIG. 1 C, where severing of the casing 30 is complete, forming an inner casing 30 into a first or uphole section 32 and a second or downhole section 34. Once the inner casing 30 has been cut, the rotation of the casing cutter 110 and the circulation of the fluid may both be ceased. Halting the rotation and the fluid flow may result in retracting the blades 112 from the inner casing 30. The anchors 122 of the spear 120 may also remain engaged with the uphole section 32.

[0034] FIG. 1 C shows that packing element 132 is deployed and is in sealing contact with uphole section 32. After the inner casing 30 is cut or severed into the uphole section 32 and downhole section 34, the packer 130 may be actuated and the packing element 132 extended radially outward such that the packing element 132 contacts interior surface of the uphole section 32 of the inner casing 30, creating a fluid tight seal. The fluid tight seal prevents fluid from bypassing the packing element 132 and flowing between uphole and downhole sections of the interior of the uphole section 32.PATENTAttorney Docket No.: WBRE / 0012PC

[0035] Referring to FIG. 1 D, while the packing element 132 is in contact with the interior surface of the uphole section 32 of the inner casing 30, the fluid is circulated (arrows 60) through the workstring 50, the cutting and retrieval assembly 100, and annulus 38. The fluid flows into annulus 38 proximate to where severing of casing 30 occurred, which may be termed the cut or divide 36. However, the fluid is prevented from returning to the surface through annulus 38 past where the packing element 132 is deployed. As a result, annulus 32 may be fluidically static. Thus, the fluid is diverted (arrows 60) into an annulus 22 via the cut 36. Annulus 22 is defined between the uphole section 32 of the inner casing 30 and the outer casing 20.

[0036] In one or more embodiments, which may be combined with other embodiments, the outer casing, such as outer casing 20, is omitted. In such embodiments, there is a single casing string for borehole 10. In such embodiments, the fluid is diverted through the cut 36 and into an annulus defined between the uphole section 32 and the inner wall of the borehole 10 (see arrows 60).

[0037] Referring to the instance of FIG. 1 D, the fluid is shown flowing uphole (arrows 60) via the annulus 22, clearing out debris, such as drilling mud solids or particles of drilled rock or cement, from the annulus 22 and from around the location of cut 36. In one or more embodiments, which may be combined with other embodiments, a pressure or a flow rate of the fluid may be maintained such that the packing element 132 is maintained in an expanded state, contacting the uphole section 32. However, the pressure or flow rate of the fluid is insufficient to actuate the blades 112 of the casing cutter 110, preventing them from extending outward from the interior of the casing cutter 110.

[0038] As shown in FIG. 1 E, after the fluid has been circulated through the annulus 22, the packer 130 may be retracted, disengaged, or unset. Specifically, the packing element 132 may be retracted radially away from the inner wall of the uphole section 32, establishing fluid communication between the annulus 38 and the annulus 22. However, the anchors 122 of the spear 120 remain engaged with the upper section 32.PATENTAttorney Docket No.: WBRE / 0012PC

[0039] As shown in FIG. 1 F, the upper section 32 of the inner casing 30 may be retrieved by pulling on the workstring 50. Specifically, the anchors 122 may remain in contact with the inner surface of the uphole section 32. As a result, the anchors 122 may transfer the pulling force from the workstring 50 to the uphole section 32 to allow the uphole section 32 to be tripped to the surface along with the workstring 50.

[0040] Because the packing element 132 remains retracted from the upper section 32 as the workstring 50 is withdrawn to the surface through casing 20, fluid in the annulus 38 between the workstring 50 and the uphole section 32 of the inner casing 30 may migrate past the packer 130, spear 120, and (in part) cutter 110, and into the interior space defined by outer casing 20 while the uphole section 32 is being retrieved. This prevents fluid contained in the uphole section 32 from being pulled out of the borehole while the upuhole casing section is being withdrawn, significantly reducing the weight of the entire system.

[0041] In one or more embodiments, which may be combined with other embodiments, a portion of the uphole section 32 of the inner casing 30 may become jammed during retrieval, such as due to an accumulation of debris in the annulus 22 between the uphole section 32 and the outer casing 20. In such embodiments, the packer 130 may be reset by re-expanding the packing element 132, such that it comes into frictional contact with the uphole section 32. After re-seating the upper section 32 with the packing element 132, fluid may be recirculated downhole via the workstring 50, out of the cutting and retrieval assembly 100, and back uphole through the annulus 22 to clear out the accumulated debris or other obstructions, by conveying such debris uphole with the fluid flow (arrows 60).

[0042] Reference is now made to FIG. 2 which shows a cross-section of a packer 200 according to one or more embodiments, which may be combined with other embodiments. The packer 200 shown in FIG. 2 may be utilized as the packer 130 in the casing cutting and retrieval operation described as part of FIGs. 1 A-1 F. The packer 200 is configured to be set and unset one or more times in a single trip into a borehole. FIG. 2 illustrates the packer 200 in aPATENTAttorney Docket No.: WBRE / 0012PCposition or state for introduction into, withdrawal from, or traversal through a borehole.

[0043] The packer 200 includes a central or longitudinal axis 205 (“axis 205”), a first or uphole end 200a, and a second or downhole end 200b opposite the uphole end 200a along the axis 205. The packer 200 includes a body 210, a mandrel 220, and a plunger 250, all coaxially aligned along the axis 205.

[0044] In addition, the packer 200 includes a packing element 202 that is positioned around, such as circumferentially around, the body 210. The packing element 202 may be analogous to the packing element 132 as provided in FIGs. 1 A-1 F and the associated description. In some instances, the packing element 202 may comprise an elastomeric element that is configured to expand, such as being radially expandable, such that it may sealingly engage against an inner surface of a surrounding tubular, such as casing.

[0045] A packer piston 204 is positioned around, such as circumferentially around, the body 210, adjacent to and uphole of the packing element 202. The packer piston 204 may be retained on the body 210 by a retention sleeve 238. The retention sleeve 238 may be engaged, such as threadedly engaged, with the body 210 and may define a receptacle (see receptacle 239 in FIGs. 3A and 3B) that at least partially receives the packer piston 204 in an axial direction. During operations, the packer piston 204 may be axially actuated to compress and radially expand the packing element 202.

[0046] The body 210 includes a first or uphole end 210a and a second or downhole end 210b opposite the uphole end 210a along the axis 205. In addition, the body 210 defines a throughbore surface 216 that further defines throughbore that is an interior space that extends axially between the ends 210a, 210b. The downhole end 210b is positioned downhole of and is coupled or connected, such as threadedly engaged, with a coupling sub 219. The coupling sub 219 is positioned downhole of and is coupled or connected, such as threadedly engaged, with a retainer housing 245. Retainer housing 245 is positioned downhole of and is coupled or connected, such as threadedly engaged, with a downhole connection sub 214. The connection sub 214 may include a threaded connector 217, such as a pin threaded connector, that isPATENTAttorney Docket No.: WBRE / 0012PCpositioned at the downhole end 200b of the packer 200. The connection sub 214 may be configured to connect the packer 200 to other downhole components, such as the spear 120 and casing cutter 110, as previously shown in FIGs. 1A-1F and described.

[0047] The mandrel 220 includes a first or uphole end 220a and a second or downhole end 220b that is opposite the uphole end 220a along the axis 205. In addition, the mandrel 220 includes a throughbore that is an interior space defined by throughbore surface 226 that extends axially between the ends 220a, 220b.

[0048] The uphole end 220a may be positioned at and may define the uphole end 200a of the packer 200. In addition, the uphole end 220a may include or be coupled to a threaded connector 222, such as a box threaded connector, that is positioned at the uphole ends 220a, 200a. The threaded connector 222 may be configured to connect the packer 200 to other uphole components, such as the workstring 50. The mandrel 220 may be inserted into and through the throughbore that is defined by the throughbore surface 216 of the body 210 such that the uphole end 220a of the mandrel 220 is positioned uphole of the uphole end 210a of body 210, and the downhole end 220b of mandrel 220 is positioned downhole of the downhole end 210b of body 210.

[0049] The downhole end 220b is engaged, such as threadedly engaged, with a torque cap 242. The torque cap 242 is at least partially received into the connection sub 214. In particular, the torque cap 242 may include one or more splines 246 that are engaged with one or more corresponding grooves or splines (not shown for the sake of clarity) defined in the connection sub 214. Thus, the torque cap 242 may said to be engaged with the connection sub 214 via a “splined connection”. During operations, the mandrel 220 may be axially translated within and relative to the body 210, and the torque cap 242 may thus be axially translated within and relative to the connection sub 214. The splined connection between the torque cap 242 and connection sub 214 may facilitate the axial translation of the mandrel 220 and torque cap 242 while still facilitating torque transfer from the mandrel 220 and torque cap 242 to the connection sub 214.PATENTAttorney Docket No.: WBRE / 0012PC

[0050] A biasing assembly 244 is positioned radially between the mandrel 220 and retainer housing 245 and axially between the coupling sub 219 and torque cap 242. In some embodiments, the biasing assembly 244 comprises a stack of Belleville washers; however, other biasing members or assemblies are contemplated, such as one or more coiled springs. During operations, the biasing assembly 244 may provide a bias force to the torque cap 242 and the mandrel 220 axially toward the downhole end 200b of the packer 200. In addition, the biasing assembly 244 may be configured to counter a weight of components that are coupled downhole of the packer 200 to prevent undesired actuation of the mandrel 220 relative to the body 210 during operations. For instance, as previously described for the cutting and retrieval assembly 100 of FIGs. 1A-1F, a spear, such as spear 120, and a casing cutter, such as casing cutter 110, may be coupled to the downhole end 200b of the packer 130 or 200. In one or more embodiments, which may be combined with other embodiments, the biasing assembly 244 may be configured to exert a sufficient biasing force to counteract the weight of these additional components.

[0051] The mandrel 220 may include a pair of opposing shoulders 225, 227 along an outer surface, such as a radially outer surface, thereof. Specifically, the mandrel 220 may include a first or uphole shoulder 225 and a second or downhole shoulder 227 that is axially spaced and positioned downhole of the uphole shoulder 225. The shoulders 225, 227 may be configured as frustoconical shoulders, radially extending shoulders, ora combination thereof. The shoulders 225, 227 may be aligned or positioned within the coupling sub 219. In addition, a retaining ring 229, such as an expandable ring) is positioned within the coupling sub 219 such that the retaining is positioned axially between the shoulders 225, 227. During operations, the retaining ring 229 may engage with the shoulders 225, 227 to limit the axial translation range of the mandrel 220 relative to the body 210. Specifically, translation of the mandrel 220 axially away from the downhole end 200b may be limited by engagement of the retaining ring 229 and the downhole shoulder 227 and translation of the mandrel 220 axially toward the downhole end 200a may be limited by engagement of the retaining ring 229 and the uphole shoulder 225. It shouldPATENTAttorney Docket No.: WBRE / 0012PCbe appreciated that additional or alternative shouldered engagements, such as between the mandrel 220 and body 210 or coupling sub 219 may be utilized to limit an axial translation of the mandrel 220 relative to the body 210 during operations.

[0052] The plunger 250 includes a first or uphole end 250a and a second or downhole end 250b opposite the uphole end 250a along the axis 205. In addition, the plunger 250 may include a flange (or piston head) 259 defined at (or proximate to) the uphole end 250a. Further, the plunger 250 includes a first cylindrical outer surface 254 and a second cylindrical outer surface 256 that is adjacent to the first cylindrical outer surface 254. The first cylindrical outer surface 254 and the second cylindrical outer surface 256 may be positioned axially between the flange 259 and the downhole end 250b. In addition, the first cylindrical outer surface 254 may be generally positioned uphole of the second cylindrical outer surface 256. Further, the first cylindrical outer surface 254 may extend radially outward to a greater outer diameter than the second cylindrical outer surface 256 relative to the common axis 205. A throughbore that is defined by a throughbore surface 252 of the plunger 250 extends axially between the ends 250a, 250b.

[0053] The plunger 250 is coaxially introduced into the throughbore that is an interior space defined by throughbore surface 226 of the mandrel 220. A retaining collar 221 may be engaged, such as threadably engaged, within the throughbore defined by the throughbore surface 226 of the mandrel 220 axially between the uphole end 250a of the plunger 250 and the uphole end 220a of the mandrel 220. In one or more embodiments, the plunger 250 may be retained within the throughbore defined by the throughbore surface 226 of the mandrel 220 via one or more shoulders defined in the throughbore defined by the throughbore surface 226 in addition to (or in lieu of the retaining collar 221. A biasing member 258 may be positioned between the flange 259 of the plunger 250 and a shoulder 215 defined by the throughbore surface 226. The biasing member 258 is configured to apply a force and axially bias the plunger 250 toward the retaining collar 221 and the uphole end 220a of the mandrel 220. The biasing member 258 may comprise one or more coiled springs that extendPATENTAttorney Docket No.: WBRE / 0012PChelically around an outer surface of the plunger 250; however, other biasing members are contemplated.

[0054] The mandrel 220 may define one or more, such as one or a plurality of radially extending apertures or ports that are defined by the recess surfaces 232 of the mandrel 220. These apertures extend radially from the throughbore surface 226 to an outer surface of the mandrel 220. A locking dog 262 may be positioned in each of the one or more apertures defined by the recess surfaces 232. In addition, the locking dogs 262 may be generally engaged, such as frictionally engaged, with the outer surface of the plunger 250. Further, the throughbore defined by the throughbore surface 216 of the body 210 may include one or more radially extending recesses that are defined by one or more recess surface 218 that may be axially alignable with the locking dogs 262 and the recess surface 232 defined by the mandrel 220. For instance, the throughbore defined by the throughbore surface 216 of the body 210 may include a single, annular recess defined by a single recess surface 218 or a plurality of circumferentially spaced recesses defined by a plurality of recess surfaces 218. In either case, the recess(es) defined by recess surface(s) 218 may extend radially outward from the axially adjacent surfaces that are defined by the throughbore surface 216.

[0055] During operations, the mandrel 220 may be axially translated within and relative to the body 210 via tension that may be applied. For instance, tension may be applied to the mandrel 220 via a coupled or connected workstring, such as the workstring 50 shown in FIGs. 1A-1F, via the threaded connector 222. As described in more detail, applying tension that results in the axial translation of the mandrel 220 in the uphole direction, that is away from the downhole end 200b, relative to the body 210 may place the packer piston 204 in fluid communication with the throughbore defined by throughbore surface 226. In addition, during operations, the plunger 250 may be axially translated within the throughbore defined by throughbore surface 226 of the mandrel 220 such that the locking dogs 262 selectively radially expand within annular recesses defined by recess surfaces 218 and the radially extending recesses defined by recess surface(s) 218. In expanding into these radiallyPATENTAttorney Docket No.: WBRE / 0012PCextending recesses, the locking dogs 282 secure the position of the mandrel 220 relative to the body 210, preventing axial movement and thereby preventing actuation of the packer piston 204. Selectively locking the mandrel 220 to the body 210 via actuation of the plunger 250 may allow tension, such as tension applied through the drill string, to be translated to the packer 200 without placing the packer piston 204 in fluid communication with the throughbore defined by throughbore surface 226. When the packer piston 204 is not in fluid communication with the with the throughbore by throughbore surface 226, the risk of an inadvertent or undesired radial expansion of the packing element 202 is mitigated. This facilitates embodiments of a casing cutting and retrieval operation, such as the casing cutting and retrieval operation of FIGs. 1 A-1 F and as described.

[0056] FIGs. 3A and 3B provide a more detailed illustration of the selective fluid communication between the packer piston 204 and throughbore defined by throughbore surface 226 based on an axial translation of the mandrel 220 according to one or more embodiments, which may be combined with other embodiments. Specifically, FIG. 3A shows the mandrel 220 in a first or retracted position, when tension applied to the mandrel 220 is less than a biasing force exerted by the biasing assembly 244 as shown in FIG. 2. As a result, the mandrel 220 may be axially translated downhole and toward the downhole end 200b. As the mandrel 220 is axially retracted within the body 210, the retaining ring 229 is engaged with the uphole shoulder 225 on the outer surface of the mandrel 220.

[0057] Back to FIGs. 3A-3B, the mandrel 220 may include a pair of axially spaced radial seals 228 coupled along its outer surface. The radial seals 228 may comprise any suitable radial sealing member or assembly. For instance, the radial seals 228 may comprise O-rings, seal rings, lip seals, wiper seals, or combinations thereof.

[0058] The mandrel 220 may also define one or more ports 224 that extend through the mandrel 220 from the throughbore surface 226 to an annulus 263, placing each in fluid communication with the other. Annulus or annular space 263 is a radial void may be defined by a throughbore defined by the throughborePATENTAttorney Docket No.: WBRE / 0012PCsurface 216 of the body 210 and the outer surface of the mandrel 220. In one or more embodiments, which may be combined with other embodiments, the mandrel 220 may define a plurality of the ports 224, such as shown in FIGs. 3A and 3B. The plurality of ports 224 may be positioned downhole of the radial seals 228.

[0059] In one or more embodiments, which may be combined with other embodiments, the body 210 may define one or more or a plurality of radial ports 213, such as shown in FIG. 3A. The ports 213 provide fluid communication between the annulus 263 and another annulus or annular space 264. Annulus 264 is defined radially between the outer surface of the body 210 and an inner surface of the packer piston 204 or with the receptacle 239 of the retention sleeve 238. The ports 213 may be circumferentially distributed about the body 210 at an axial position along the axis 205.

[0060] When the mandrel 220 is in the retracted position, such as shown in FIG. 3A, the radial seals 228 may be positioned uphole and downhole of the ports 213. Thus, when the mandrel 220 is retracted axially into the body 210, fluid (arrows 60) flowing through the throughbore defined by throughbore surface 226 may communicate with and fill the annulus 263 via the radial ports 224 however, fluid is prevented from advancing through the ports 213 and into the annulus 264 by the radial seals 228. Thus, the ports 213 and the annulus 264 may be flu idical ly static in this state of operation.

[0061] Conversely, FIG. 3B shows the mandrel 220 in a second or extended position in which the mandrel 220 is axially translated in an uphole direction relative to the body 210 as compared to the first position, such as shown in FIG.3A. The axial translation of the mandrel 220 in the extended position extends the mandrel 220 outward from the body 210 along the axis 205. A tension applied to the mandrel 220, such as through the drillstring, may be greater than the biasing force exerted by the biasing assembly 244 as shown in FIG. 2, such that the mandrel 220 is extended relative to the body 210. In the extended position, such as generally shown in FIG. 3B, the mandrel 220 may be axially translated away from the downhole end 200b so that the retaining ring 229 isPATENTAttorney Docket No.: WBRE / 0012PCengaged with the downhole shoulder 227 on the outer surface of the mandrel 220 (not shown).

[0062] When the mandrel 220 is in the extended position, such as shown in FIG. 3B, the radial seals 228 may be axially shifted or translated uphole from the ports 213, establishing fluid communication between annulus 263 and ports 213. When the mandrel 220 is axially extended from the body 210, the throughbore interior space defined by throughbore surface 226 may be placed in fluid communication with the packer piston 204 via the ports 224, the annulus 263, and the ports 213. This allows fluid flowing (arrows 60) through the throughbore defined by throughbore surface 226 to flow through the ports 224, the annulus 263, the ports 213, and into the annulus 264. The fluid entering the annulus 264 may transmit a force to drive the packer piston 204 in a downhole direction or toward the downhole end 200b. Driving the packer piston 204 downhole radially expands the packing element 202, as previously described. The packer piston 204 may engage the packing element 202 via an actuation ring 235 that is axially positioned therebetween. When the pressure or flow rate of the fluid is reduced, a biasing member 231 , which is positioned axially between the packer piston 204 and a retaining ring 233 mounted to the outer surface of the body 210, may actuate the packer piston 204 in the uphole direction and therefore into the receptacle 239 to permit radial retraction of the packing element 202.

[0063] When the mandrel 220 is in the extended position, such as shown in FIG. 3B, the pressure or flow rate of fluid in communications with the packer 200 may be adjusted to actuate the packing element 202 to selectively set via radially expansion or unset via radially retraction the packing element 202. Conversely, when the mandrel 220 is in the retracted position, such as shown in part in FIG. 3A, fluid communication between the throughbore interior space defined by throughbore surface 226 and the packer piston 204 is prevented or at least restricted such that the packing element 202 may not be activated.

[0064] FIGs. 4A-4C provide a more detailed illustration of the selective actuation of the plunger 250 within the throughbore defined by throughbore surface 226 of the mandrel 220 according to one or more embodiments, whichPATENTAttorney Docket No.: WBRE / 0012PCmay be combined with other embodiments. Specifically, FIG. 4A illustrates the plunger 250 in a first or unlocked position. In the first position, the pressure or flow rate of fluid flowing (arrows 60) through the packer 200 by way of the throughbore defined by throughbore surface 226 of mandrel 220 exerts a pressure on the flange 259 that is less than the biasing force by the biasing member 258. As a result, the biasing member 258 forces the flange 259 in the uphole direction and into engagement or contact with the downhole surface of the retaining collar 221.

[0065] Conversely, FIG. 4B illustrates the plunger 250 in a second or locked position. In the second position, the pressure or flow rate of fluid flowing through the packer 200 by way of the throughbore defined by throughbore surface 226 of mandrel 220 exerts a sufficient pressure on the flange 259 to overcome the biasing force applied by the biasing member 258. As a result, the pressure of the fluid forces the flange 259 in the downhole direction, axially compressing the biasing member 258 against the shoulder 215 defined by throughbore surface 226. The pressure or flow rate of the fluid flowing through the packer 200 may selectively actuate the plunger 250 between the unlocked position, such as shown in FIG. 4A, and the locked position, such as shown in FIG. 4B.

[0066] To prevent fluid lock between the flange 259 and shoulder 215, one or more ports 223 may be defined in the mandrel 220. Fluid lock may prevent free actuation of the plunger 250 during operations.

[0067] FIGs. 4A and 4B also illustrate the mandrel 220 in the retracted position of FIG. 3A as previously described. When the mandrel 220 is in the retracted position, such as shown in FIG. 3A, actuation of the plunger 250 between its corresponding unlocked position, such as shown in FIG. 4A, and locked position, such as shown in FIG. 4B, may selectively radially expand the locking dogs 262 into the recess(es) defined by the recess surface(s) 218 of the body 210. Expanding the locking dogs 262 into the recess(es) 218 axially locks the position of the mandrel 220 to the body 210, as previously described. Conversely, selectively radially contracting the locking dogs 262 releases thePATENTAttorney Docket No.: WBRE / 0012PCmandrel 220 from the body 210 to permit axial movement relative to one another.

[0068] Specifically, when the plunger 250 is in the unlocked position, such as shown in FIG. 4A, and the mandrel 220 is in its corresponding retracted position, such as shown in FIG. 3A, the second cylindrical outer surface 256 may be aligned and engaged with the locking dogs 262. The smaller outer diameter of second cylindrical outer surface 256 may allow the locking dogs 262 to retract and be positioned in a more radially inward location within the apertures defined by the recess surface 232 and away from the recess(es) defined by the recess surface 218 in the body 210.

[0069] However, when the pressure or flow rate of the fluid is increased to transition the plunger 250 from the unlocked position, such as shown in FIG.4A, to the locked position, such as shown in FIG. 4B, first cylindrical outer surface 254 is aligned with and slidingly engaged with the locking dogs 262 so that the locking dogs 262 are positioned in a radially expanded location and into the recess(es) defined by the recess surface(s) 218 of the body 210. In some instances, the locking dogs 262 contact the recess surface(s) 218 of the recess(es) of body 210, halting their radial expansion and providing securing pressure against both the first cylindrical outer surface 254 and the recess surface 218. Thus, when the mandrel 220 is in the retracted position, such as shown in FIG. 3A, actuation of the plunger 250 to the locked position, such as shown in FIG. 4B, may thereby axially lock or fix the mandrel 220 to the body 210 as previously described, so that actuation of the mandrel 220 from the retracted position, such as shown in FIG. 3A, to the extended position, such as shown in FIG. 3B, is prevented.

[0070] When the pressure or flow rate of the fluid is sufficiently reduced to allow the biasing member 258 to axially translate the plunger 250 toward the unlocked position, such as shown in FIG. 4A, the locking dogs 262 may be retracted out of the recess(es) defined by the recess surface(s) 218 and into the apertures defined by the recess surfaces 232 as previously described, forming a void between the recess surface(s) 218 and the outer radial surface of the locking dogs 262. In one or more embodiments, which may be combinedPATENTAttorney Docket No.: WBRE / 0012PCwith other embodiments, the locking dogs 262 may be retracted back into the apertures defined by the recess surface 232 of the mandrel 220 by sliding engagement of chamfers formed on the locking dogs 262 and recess(es) defined by the recess surface(s) 218 , such as during axial translation of the mandrel 220 relative to body 210. In one or more embodiments, which may be combined with other embodiments, the locking dogs 262 may be radially biased inward toward the axis 205, such as via suitable biasing members or compressible fluids. Thus, when the mandrel 220 is in the retracted position, such as shown in FIG. 3A, actuation of the plunger 250 to the unlocked position, such as shown in FIG. 4A, may thereby axially unlock the mandrel 220 from the body 210 as previously described, so that the mandrel 220 may be actuated from the retracted position, such as shown in FIG. 3A, to the extended position, such as shown in FIG. 3B, via tension as previously described.

[0071] FIG. 4C illustrates the position of the plunger 250 and locking dogs 262 when the mandrel 220 is placed in the extended position of FIG. 3B. Specifically, as previously described, when the mandrel 220 is in the extended position, such as shown in part in FIG. 3B, the mandrel 220 is axially translated uphole and extends out from the body 210. In this position, the locking dogs 262 are misaligned with the recess(es) defined by the recess surface(s) 218 in the body 210. As a result, regardless of the pressure or flow rate of the fluid flowing (arrows 60) within the packer 200, the locking dogs 262 are prevented from radially expanding into the recess(es) defined by the recess surface 218 of the body 210. This prevents locking the mandrel 220 to the body 210. When the mandrel 220 and the body 210 are not interlocked, axial translation of the plunger 250 within the mandrel 220 is restricted.

[0072] Referring to FIGs. 3A-3B and 4A-4C, the extended and retracted positions of the mandrel 220 and the unlocked and locked positions of the plunger 250 may be utilized to facilitate and enhance a casing cutting and retrieval operation for a subterranean borehole. Thus, several portions of the operation illustrated in FIGs. 1A-1F and previously described are now provided for when the packer 200 is used in relation to the operation rather than packer 130 as part of the cutting and retrieval assembly 100 and operation thereof. ForPATENTAttorney Docket No.: WBRE / 0012PCthis description, reference will be made to positions of the mandrel 220 and plunger 250 in FIGS. 3A-3B and 4A-4C in relation to various operational steps previously described in relation to FIGs. 1A-1F.

[0073] In one or more embodiments, which may be combined with other embodiments, the mandrel 220 may initially be locked in the retracted position, such as shown in FIG. 3A, by transitioning the plunger 250 to the locked position, such as shown in FIG. 4B. Specifically, the mandrel may be placed in the retracted position by reducing a tension applied to the packer 200, such as via the workstring 50 in FIGs. 1A-1F. The plunger 250 may be transitioned to the locked position, such as shown in FIG. 4B, by increasing a pressure or flow rate of the fluid flowing through the packer 200, particularly through the throughbore defined by throughbore surface 226.

[0074] Locking the mandrel 220 in the retracted position, such as shown in FIG. 3A, may allow an operator to hydraulically actuate other components of the cutting and retrieval assembly 100 without risking an undesired expansion of the packing element 202. Specifically, as previously described, both the casing cutter 110 and spear 120 are hydraulically actuated. Thus, an increase in the pressure or flow rate of the fluid (arrows 60) may deploy the blades 112 of the casing cutter 110 and the anchors 122 of the spear 120. By initially locking the mandrel 220 in the retracted position, such as shown in FIG. 3A, fluid communication between the throughbore interior space defined by throughbore surface 226 and the packer piston 204 is prevented, such as by the radial seals 228. An actuation or expansion of the packing element 202 may be prevented because of any increase in the pressure or flow rate of the fluid to deploy either the blades 112 or the anchors 122. Locking the mandrel 220 in the retracted position, such as shown in FIG. 3A, may allow tension to be applied to the cutting and retrieval assembly 100 when the anchors 122 are deployed, setting or engaging the anchors 122 with the inner casing 30.

[0075] As previously described, tension may be applied to the cutting and retrieval assembly 100 when the blades 112 are rotated to cut the inner casing 30. In addition, fluid may be circulated through the cutting and retrieval assembly 100 to perform a number of functions, as previously described.PATENTAttorney Docket No.: WBRE / 0012PCLocking the mandrel 220 to the body 210 allows this tensioning operation to occur without translating the mandrel 220 relative to the body 210, which avoids placing the packer piston 204 in fluid communication with the throughbore defined by throughbore surface 226. Thus, locking the mandrel 220 to the body 210 may prevent the tension from translating the mandrel 220 and therefore prevent the increased pressure or flow rate of the fluid 60 from expanding the packing element 202.

[0076] After the inner casing 30 is cut, the packer 200 may be set by reducing the pressure or flow rate of fluid flowing through the packer 200 (arrows 60) to transition the plunger 250 from the locked position, such as shown in FIG. 4B, to the unlocked position, such as shown in FIG. 4A. The transition occurs as force against biasing member 258 is relieved. Thereafter, tension may be placed on the mandrel 220 to transition the mandrel 220 from the retracted position, such as shown in FIG. 3A, to the extended position, such as shown in FIG. 3B and4C, placing the packer piston 204 in fluid communication with the throughbore interior space defined by throughbore surface 226 of the mandrel 220. As previously described, the transitioning of the mandrel 220 to the extended position, such as shown in FIG. 3B and 4C, may misalign the locking dogs 262 with the recess(es) defined by the recess surface 218, restricting axial movement of the plunger 250 within the mandrel 220 regardless of the pressure or flow rate of fluid through the mandrel 220. A pressure or flow rate of the fluid may then be increased as desired or necessary to actuate the packer piston 204, where the packing element 202 radially expands without an actuation of the plunger 250.

[0077] Once the packing element 202 is fully expanded, the tension on the mandrel 220 may be decreased to allow transition of the mandrel 220 from the extended position, such as shown in FIGs. 3B and 4C, to the retracted position, such as shown in FIG. 3A. Bias assembly 244 applies the bias force that makes this transition. Once in the retracted position, , such as shown in FIG. 3A, fluid communication between the packer piston 204 and the throughbore defined by throughbore surface 226 is prevented. Any fluid in the annulus 264 and receptacle 239 is isolated and static. Such isolation may maintain the positionPATENTAttorney Docket No.: WBRE / 0012PCof the packer piston 204, locking the packing element 202 in the expanded state regardless of the fluid pressure or the fluid flow rate

[0078] As shown in FIGs. 3A and 3B, a nozzle or vent 237 may be defined in the retention sleeve 238. Vent 237 may be configured to vent the annulus 264 to the surrounding borehole environment. During operations, when the mandrel 220 is in the extended position, such as shown in FIGs. 3B and 4C, the flow of fluid introduced into the annulus 264 via ports 213 defined by body 210 may exit through the vent 237. In some embodiments, the vent 237 may prevent over pressurization or pressurized fluid from becoming trapped in the annulus 264. In some instances, a positive flow of fluid (arrows 60) with the mandrel 220 in the extended positions of FIGs. 3B and 4C, may be necessary to maintain the packing element 202 in the expanded state. In some instances, the vent 237 may also be utilized to pass fluid from the annulus 264 as the packing element 202 is transitioned form an expanded state to an unset or retracted state.

[0079] To unset the packer 200, such as after circulating fluid through the annulus 22, such as shown in FIG. 1D, and prior to pulling the uphole section 32 of the inner casing 30 to the surface, such as shown in FIGs. 1E and 1F, tension may be increased on the cutting and retrieval assembly 100. Increased tension in this instance may transition the mandrel 220 to the extended position, such as shown in FIGs. 3B and 4C, placing the annulus 264 and the packer piston 204 in fluid communication with the throughbore defined by throughbore surface 226. In addition, the pressure or flow rate of the fluid may be reduced in the throughbore defined by throughbore surface 226, allowing biasing member 231 act and transmit force into the packer piston 204, translating the packer piston 204 back into the receptacle 239. Transitioning packer piston 204 back into the receptacle 239 relieves pressure on the packing element 202. As a result of these several actions, the packing element 202 may radially decouple from the uphole section 32 of the inner casing 30, such as shown in FIG. 1 E, deflate, and retreat into the packer 200. In one or more embodiments, which may be combined with other embodiments, tension may be maintained on the mandrel 220 to retain the mandrel 220 in the extended position while thePATENTAttorney Docket No.: WBRE / 0012PCpacking element 202 expands into the uphole section 32 of the inner casing 30. In these scenarios, unsetting the packer 200 may include reducing a pressure or flow rate of the fluid, which may actuate the packer piston 204 and relieve pressure on the packing element 202, as previously described.

[0080] Thereafter, when pulling the uphole section 32 of the inner casing 30 to the surface, such as shown in FIG. 1F, to circulate fluid through the annulus 22 so as to clear out debris, for example, the tension applied to the cutting and retrieval assembly 100 may be increased to place or maintain the mandrel 220 in the extended position, such as shown in FIG. 3B and 40 while the pressure or flow rate of the fluid is increased to radially expand the packing element 202.

[0081] Referring to FIG. 1 D, when fluid is circulated (arrows 60) through the annulus 22 prior to pulling the uphole section 32 of the inner casing 30 to the surface, the general uphole flow of the fluid 60 may impart a pressure on a downhole side or end of the packing element 132, 202. As shown in FIGs. 3A and 3B and as previously described, the packer piston 204 of the packer 200 may translate in the downhole direction, axially compressing the packer element 132, 202 such that the packer element 132, 202 radially expands. During the fluid circulation operation of FIG. 1D and utilizing the packer 200, the increased pressure on the downhole end of the packer 200 may counteract the translation of the packer piston 204. This counter action results in a reduction or elimination of the sealing engagement between the packing element 202 and uphole section 32 of the inner casing 30, such as shown in FIG. 1D.

[0082] Accordingly, embodiments of a packer, such as the packer 200 of FIG. 2, may include a packer piston, as packer piston 204, that is configured to be translated in the uphole direction to expand the packing element, such as packing element 202. The uphole translation of the packer piston may utilize an increase in downhole fluid pressure during a fluid circulation operation, such as shown in FIG. 1D, to further compress and therefore radially expand the packing element.

[0083] Reference is now made to FIG. 5, which shows an embodiment of the packer 300, which has a configuration similar to the packer 200 of FIG. 2,PATENTAttorney Docket No.: WBRE / 0012PCbut that includes a packer piston 304 in place of the packer piston 204, such as shown in FIG. 2 and as previously described. The packer piston 304 of the packer 300 may be configured substantially similar to the packer piston 204 but for the packer piston 304 may be configured to translate in an uphole direction to axially compress and radially expand the packing element 202. Other than the packer piston 304 and related components, the packer 300 of FIG. 5 may otherwise be configured in a substantially similar manner to the packer 200 of FIGs. 2-4C and as previously described. Specifically, the packer 300 may also include the body 210, mandrel 220, and plunger 250, as previously described.

[0084] As shown in FIG. 5, the packer piston 304 may be positioned downhole of the packing element 202. A retention sleeve 338 may be engaged, such as threadedly engaged, with the body 210 or the coupling sub 219, such as shown in FIG. 2. The retention sleeve 338 may define a receptacle 339 that is configured to at least partially axially receive the packer piston 304 when translated in a downhole direction.

[0085] A sleeve 340 is positioned around the body 210 that radially underlies the packer piston 304 and packing element 202. The sleeve 340 may define an annulus 342 radially between the sleeve 340 and an outer surface of the body 210 that is in fluid communication with the one or more ports 213 defined by the body 210. A downhole end 340b of the sleeve 340 may extend axially into the receptacle 339 of the retention sleeve 338. A portion of the receptacle 339 may be define an axial gap 344 between downhole end 340b and a terminal surface 337. Annulus 342 is in fluid communication with the receptacle 339 via the axial gap 344. In one or more embodiments, the axial gap 344 may be defined as a singular annular gap between the downhole end 340b and the terminal surface 337 or may comprise one or more radially extending slots or apertures that are defined by and extend through the sleeve 340. Thus, the term “gap” is intended to broadly cover any suitable opening(s) or port(s) that allows fluid to traverse from the annulus 342 to the receptacle 339 or to otherwise access the packer piston 304 when motivated to flow.

[0086] A retention sleeve 350 may be positioned around the sleeve 340 that underlies the packing element 202 and defines a radially extending shoulderPATENTAttorney Docket No.: WBRE / 0012PC352. A biasing member 331 may be positioned (and captured) between the radially extending shoulder 352 and a shoulder 307 defined on a radially inner surface of the packer piston 304 to axially bias the packer piston 304 axially downhole and into the receptacle 339. As with the biasing member 231 , the biasing member 331 may comprise one or more coiled springs or any other suitable axial biasing member.

[0087] During operations, when the mandrel 220 is in the extended position, such as shown in FIG. 3B and 4C as the radial seals 228 are positioned uphole of the port(s) 213 defined by the body 21 -, fluid may be communicated (arrows 60) from the throughbore defined by throughbore surface 226, through the ports 224, into the annulus 263, to the ports 213, through the annulus 342, through the axial gap 344, and into the receptacle 339. Upon entering the receptacle 339, the fluid may bear against and translate the packer piston 304 in the uphole direction against the bias provided by the biasing member 331. In translating the packer piston 304 against the biasing member 331, radially expands the packing element 202. A vent 347 may be defined in the retention sleeve 338 that is configured permit fluid to be discharged out of the annulus 342 and into the surrounding borehole environment in a similar manner to that described for the vent 237 shown in FIGS. 3A and 3B.

[0088] An actuation ring 335 may be configured to transfer force between the packing element 202 and the packer piston 304. In addition, a stop ring 319 may be coupled to the body 210 uphole of the packing element 202 that defines a shoulder 320. During operations, when the packer piston 304 is translated in the uphole direction, the packing element 202 is compressed against the shoulder 320 that facilitates the radial expansion of the packing element 202.

[0089] Thus, of FIG. 5, When the packer piston 304 for the packer 300 is axially translated in the uphole direction, the packing element 202 is compressed. As a result, during the fluid circulation operation of FIG. 1D, the increased pressure on the downhole end of the packer 200 may not counter the translation of the packer piston 304. Rather, the increased downhole pressure may further increase the pressure applied by the packer piston 304 to thePATENTAttorney Docket No.: WBRE / 0012PCpacking element 202, which may therefore enhance the sealing engagement of the packing element 202 and the uphole section 32 of the inner casing 30, such as shown in FIG. 1D. In one or more embodiments, which may be combined with other embodiments, the packer piston 304 may include one or more exposed outer shoulders 306 (see FIG. 5). Outer shoulders 306 may be configured to convert the increased downhole pressure into an uphole oriented force on the packer piston 304 during such an operation.

[0090] FIG. 6 shows a method according to one or more embodiments, which may be combined with other embodiments. The method 400 may be performed by use of any one or more of the embodiments of the packers described, such as packers 130, 200, 300, as well as any configuration of packer envisioned though the scope of the disclosure provided. In describing the features of an embodiment method or process, such as method 400, continuing reference is made to FIGs. 1 A-5. However, it should be appreciated that embodiments of a method or a process, such as method 400, may be performed by use of one or more packers that are different from the embodiment packers 130, 200, 300, as described in at least some respects.

[0091] Method 400 includes increasing a tension on a packer such that the throughbore of the packer is placed in fluid communication with a packer piston of the packer at block 402. As previously described for the packer 200, the mandrel 220 may be placed under tension, such as communicated through the workstring 50 in FIGs. 1A-1F, to axially shift the mandrel 220 relative to the body 210, placing the throughbore defined by throughbore surface 226 in fluid communication with the packer piston 204 via the ports 224, annulus 263, and ports 213.

[0092] Method 400 also includes increasing pressure in the throughbore while maintaining the increased pressure on the packer such that the packer piston actuates and the packing element of the packer expands at block 404. As previously described for the packer 200, when the mandrel 220 is maintained under tension in the extended position, such as shown in FIGs. 3B, 4C, increasing the fluid pressure in the throughbore defined by throughbore surface 226 may actuate the packer piston 204, which compress the packerPATENTAttorney Docket No.: WBRE / 0012PCpiston 204 and expands the packing element 202. The increased pressure may be communicated to the packer piston 204 via the ports 224, annulus 263, and ports 213.

[0093] In one or more embodiments, which may be combined with other embodiments, the method 400 may also include actuating a plunger , such as the plunger 250), within the throughbore to selectively lock a mandrel to a body of the packer. Locking the mandrel to the body of the packer prevents fluid communication between the throughbore and the packer piston.

[0094] In one or more embodiments, which may be combined with other embodiments, the method 400 may include increasing a fluid pressure in the throughbore to expand one or more blades , such as blades 112, of a casing cutter , such as casing cutter 110, coupled to the packer. In one or more embodiments, which may be combined with other embodiments, the method 400 may include increasing a fluid pressure in the throughbore to expand one or more anchors , such as anchors 122, of a spear , such as spear 120, coupled to the packer.

[0095] In one or more embodiments, which may be combined with other embodiments, the method 400 may include decreasing a tension on the packer. Decreasing tension on the packer may prevent fluid communication between the throughbore and the packer piston while increasing the fluid pressure to expand the blade(s) or the anchor(s). As a result, increasing the pressure of the fluid in the throughbore to expand the blade(s) or the anchor(s) does not actuate the packer piston, preventing the expansion of the packing element.

[0096] As explained previously and reiterated here, the present disclosure includes, without limitation, the following Examples.

[0097] Example 1: A packer for a subterranean borehole, the packer comprising: a throughbore; a body; a packing element; a packer piston; and a mandrel inserted into the body along a central axis, where the mandrel is configured to axially translate, relative to the central axis, under tension to selectively place the packer piston in fluid communication with the throughbore such that an increase in a pressure in the throughbore is configured to actuate the packer piston to expand the packing element.PATENTAttorney Docket No.: WBRE / 0012PC

[0098] Example 2: The packer of any of the Examples, where the throughbore is defined in the mandrel, where the mandrel includes one or more first ports that extend from the throughbore to an annulus defined between the mandrel and the body, where the body includes one or more second ports that communicate the annulus with the packer piston, and where the mandrel is configured to axially translate under tension to selectively place the one or more first ports in fluid communication with the one or more second ports.

[0099] Example s: The packer of any of the Examples, where the mandrel includes a pair of axially spaced radial seals, and where the mandrel is actuatable between: a first position, under a first tension, in which the one or more second ports are aligned axially between the pair of axially spaced radial seals; and a second position, under a second tension that is greater than the first tension, in which the one or more second ports are positioned axially downhole of the pair of axially spaced radial seals.

[0100] Example 4: The packer of any of the Examples, where the packer piston is configured to actuate in a downhole direction to expand the packing element.

[0101] Example s: The packer of any of the Examples, where the packer piston is configured to actuate in an uphole direction to expand the packing element.

[0102] Example 6: The packer of any of the Examples, further comprising a plunger that is inserted into the throughbore, where the plunger is configured to axially translate within the throughbore to selectively lock the mandrel to the body based on a pressure in the throughbore.

[0103] Example 7: The packer of any of the Examples, further comprising one or more locking dogs positioned in one or more apertures extending radially through the mandrel, where the plunger is configured to axially translate based on a fluid pressure in the throughbore to radially expand the one or more locking dogs into one or more recesses defined on the body.

[0104] Example s: The packer of any of the Examples, where the plunger includes a first outer surface and a second outer surface, where the first outer surface has a greater outer diameter than the second outer surface, and wherePATENTAttorney Docket No.: WBRE / 0012PCthe plunger is actuatable between: a first position, under a first pressure in the throughbore, in which the one or more locking dogs are engaged with the second outer surface; and a second position, under a second pressure in the throughbore that is greater than the first pressure, in which the one or more locking dogs are engaged with the first outer surface, where the plunger is axially translated within the throughbore from the first position to the second position, and where the one or more locking dogs are expanded into the one or more recesses defined on the body when the plunger is in the second position.

[0105] Example 9: A method of operating a packer in a subterranean borehole, the method comprising: (a) increasing a tension on the packer to place a throughbore of the packer in fluid communication with a packer piston of the packer; and (b) increasing a pressure in the throughbore, while maintaining the tension from (a), to actuate the packer piston and expand a packing element of the packer.

[0106] Example 10: The method of any of the Examples, where the packer comprises a body and a mandrel inserted into the body along a central axis, and where (a) further comprises axially translating the mandrel relative to the body relative to the central axis.

[0107] Example 11 : The method of any of the Examples, where (a) further comprises communicating one or more first ports defined in the mandrel with one or more second ports defined in the body, where the one or more first ports are in fluid communication with the throughbore, and where the one or more second ports are in fluid communication with the packer piston.

[0108] Example 12: The method of any of the Examples, further comprising: (c) decreasing the tension on the packer after (b) to isolate the one or more first ports from the one or more second ports to maintain a pressure on the packer piston and an expansion of the packing element.

[0109] Example 13: The method of any of the Examples, further comprising: (d) axially shifting a plunger in a first axial direction in the throughbore to expand one or more locking dogs through the mandrel and into the body to prevent axial translation of the mandrel relative to the body, before (a); and (e) axially shifting the plunger in a second axial direction in the throughbore to retract thePATENTAttorney Docket No.: WBRE / 0012PCone or more locking dogs and allow axial translation of the mandrel relative to the body, before (a).

[0110] Example 14: The method of any of the Examples, where (d) further comprises increasing the pressure in the throughbore, and where (e) further comprises decreasing the pressure in the throughbore.

[0111] Example 15: The method of any of the Examples, where (a) comprises axially translating the mandrel in a first axial direction relative to the central axis, and where (b) further comprises axially translating the packer piston in a second axial direction relative to the central axis that is opposite the first axial direction.

[0112] Example 16: The method of any of the Examples, where (a) comprises axially translating the mandrel in a first axial direction relative to the central axis, and where (b) further comprises axially translating the packer piston in the first axial direction relative to the central axis.

[0113] Example 17: An assembly for cutting and retrieving a casing from a subterranean borehole, the assembly comprises: a casing cutter including one or more expandable blades; a spear including one or more expandable anchors; and a packer coupled to the spear and the casing cutter, where the packer comprises: a throughbore; a body; a packing element; a packer piston; and a mandrel inserted into the body along a central axis, where the mandrel is configured to axially translate, relative to the central axis, under tension to selectively place the packer piston in fluid communication with the throughbore such that an increase in fluid pressure in the throughbore is configured to actuate the packer piston to expand the packing element.

[0114] Example 18: The assembly of any of the Examples, where the spear is coupled between the packer and the casing cutter.

[0115] Example 19: The assembly of any of the Examples, where the packer further comprises a plunger that is inserted into the throughbore, where the plunger is configured to axially translate, relative to the central axis, to selectively lock the mandrel to the body based on a pressure in the throughbore.

[0116] Example 20: The assembly of any of the Examples, where the packer further comprises one or more locking dogs positioned in one or morePATENTAttorney Docket No.: WBRE / 0012PCapertures extending radially through the mandrel, where the plunger is configured to axially translate, relative to the central axis, based on a fluid pressure in the throughbore to radially expand the one or more locking dogs into one or more recesses defined on the body to thereby lock the mandrel to the body.

[0117] Embodiments disclosed relate to systems, and related methods, for performing casing cutting and retrieval operations in a bore that enabling the entire process to be completed in a single trip. In one or more embodiments, which may be combined with other embodiments, the systems disclosed may include a hydraulically-set packer featuring a selective locking and unlocking mechanism that prevents unintended activation under high fluid pressure or flow rates, while allowing controlled activation through lower pressure or flow, mechanical manipulation, or a combination of both. In one or more embodiments, which may be combined with other embodiments, the hydraulically-set packer of the systems disclosed may be configured to be set and unset multiple times during a single trip within the borehole, and thus may improve flexibility and efficiency for a casing cutting and retrieval operation.

[0118] While one or more embodiments disclosed include a packer , such as the packers 130, 200, 300) that may be used in an assembly for a casing cutting and retrieval operation , such as the cutting and retrieval assembly 100 of FIGs. 1 A-1 F), it should be appreciated that embodiments of a packer , such as embodiments of one or more of the packers 130, 200, 300) are contemplated for use in other contexts and operations. For example, one or more embodiments of a packer described may be utilized for zonal isolation or pressure management to facilitate production from or injection into a subterranean borehole. As another example, one or more embodiments of a packer described may be utilized for borehole testing operations , such as drillstring testing, injections or falloff testing, or formation evaluation among others). As still another example, one or more embodiments of a packer described may be utilized for stimulation operations in a subterranean borehole, such as for hydraulic fracturing, acidizing, or chemical treatments, amongPATENTAttorney Docket No.: WBRE / 0012PCothers. Still other uses for embodiments of a packer as described are contemplated beyond these examples.

[0119] In one or more embodiments, which may be combined with other embodiments, a packer , such as embodiments of one or more of the packers 130, 200, 300, may be used in situations where multiple set and unset sequences of a packer are called for. Examples of such situations include, but are not limited to, isolation for testing an integrity of a casing string or wellbore, zonal isolation for wellbore remedial operations such as casing perforation, pumping lost circulation materials downhole, and production operations, such as during well stimulation.

[0120] In one or more embodiments, which may be combined with other embodiments, the actuation assembles utilized in the embodiments packers described , such as packers 130, 200, 300, may be utilized to actuate one or more components of other tools, systems, or assemblies. In one or more embodiments, which may be combined with other embodiments, the packers described , such as packers 130, 200, 300, may be configured to selectively place a packer piston in fluid communication with a throughbore by either tension or compression along a central axis , such as axis 205, during operations.

[0121] The preceding discussion is directed to various embodiments. However, one of ordinary skill in the art will understand that the examples disclosed have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

[0122] The drawing figures are not necessarily to scale. Certain features and components may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

[0123] In the preceding discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple”PATENTAttorney Docket No.: WBRE / 0012PCor “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection of the two devices, or through an indirect connection that is established via other devices, components, nodes, and connections. In addition, as used, the terms “axial” and “axially” generally mean along or parallel to a given axis (for example, central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the given axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. Further, when used (including in the claims), the words “about,” “generally,” “substantially,” “approximately,” and the like, when used to refer to a stated value, mean within a range of ±10% of the stated value.

[0124] While one or more embodiments have been shown and described, modifications thereof may be made by one skilled in the art without departing from the scope or teachings. The embodiments described are examples and are not limiting to the full scope of the disclosed concept. Many variations and modifications of the systems, apparatus, and processes described are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the operations in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before operations in a method claim are not intended to and do not specify a particular order to the operations but rather are used to simplify subsequent reference to such operations.

Claims

PATENTAttorney Docket No.: WBRE / 0012PCWhat is claimed is:

1. A packer for a subterranean borehole, the packer comprising:a throughbore;a body;a packing element;a packer piston; anda mandrel inserted into the body along a central axis, where the mandrel is configured to axially translate, relative to the central axis, under tension to selectively place the packer piston in fluid communication with the throughbore such that an increase in a pressure in the throughbore is configured to actuate the packer piston to expand the packing element.

2. The packer of claim 1 ,where the throughbore is defined in the mandrel,where the mandrel includes one or more first ports that extend from the throughbore to an annulus defined between the mandrel and the body, where the body includes one or more second ports that communicate the annulus with the packer piston, andwhere the mandrel is configured to axially translate under tension to selectively place the one or more first ports in fluid communication with the one or more second ports.

3. The packer of claim 2,where the mandrel includes a pair of axially spaced radial seals, and where the mandrel is actuatable between:a first position, under a first tension, in which the one or more second ports are aligned axially between the pair of axially spaced radial seals; anda second position, under a second tension that is greater than the first tension, in which the one or more second ports are positioned axially downhole of the pair of axially spaced radial seals.PATENTAttorney Docket No.: WBRE / 0012PC4. The packer of claim 1 , where the packer piston is configured to actuate in a downhole direction to expand the packing element.

5. The packer of claim 1 , where the packer piston is configured to actuate in an uphole direction to expand the packing element.

6. The packer of claim 1, further comprising a plunger that is inserted into the throughbore, where the plunger is configured to axially translate within the throughbore to selectively lock the mandrel to the body based on a pressure in the throughbore.

7. The packer of claim 6, further comprising one or more locking dogs positioned in one or more apertures extending radially through the mandrel, where the plunger is configured to axially translate based on a fluid pressure in the throughbore to radially expand the one or more locking dogs into one or more recesses defined on the body.

8. The packer of claim 7, where the plunger includes a first outer surface and a second outer surface, where the first outer surface has a greater outer diameter than the second outer surface, and where the plunger is actuatable between:a first position, under a first pressure in the throughbore, in which the one or more locking dogs are engaged with the second outer surface; and a second position, under a second pressure in the throughbore that is greater than the first pressure, in which the one or more locking dogs are engaged with the first outer surface, where the plunger is axially translated within the throughbore from the first position to the second position, and where the one or more locking dogs are expanded into the one or more recesses defined on the body when the plunger is in the second position.

9. A method of operating a packer in a subterranean borehole, the method comprising:PATENTAttorney Docket No.: WBRE / 0012PC(a) increasing a tension on the packer to place a throughbore of the packer in fluid communication with a packer piston of the packer; and (b) increasing a pressure in the throughbore, while maintaining the tension from (a), to actuate the packer piston and expand a packing element of the packer.

10. The method of claim 9, where the packer comprises a body and a mandrel inserted into the body along a central axis, and where (a) further comprises axially translating the mandrel relative to the body relative to the central axis.

11. The method of claim 10, where (a) further comprises communicating one or more first ports defined in the mandrel with one or more second ports defined in the body, where the one or more first ports are in fluid communication with the throughbore, and where the one or more second ports are in fluid communication with the packer piston.

12. The method of claim 11 , further comprising:(c) decreasing the tension on the packer after (b) to isolate the one or more first ports from the one or more second ports to maintain a pressure on the packer piston and an expansion of the packing element.

13. The method of claim 10, further comprising:(d) axially shifting a plunger in a first axial direction in the throughbore to expand one or more locking dogs through the mandrel and into the body to prevent axial translation of the mandrel relative to the body, before (a); and(e) axially shifting the plunger in a second axial direction in the throughbore to retract the one or more locking dogs and allow axial translation of the mandrel relative to the body, before (a).PATENTAttorney Docket No.: WBRE / 0012PC14. The method of claim 13, where (d) further comprises increasing the pressure in the throughbore, and where (e) further comprises decreasing the pressure in the throughbore.

15. The method of claim 10, where (a) comprises axially translating the mandrel in a first axial direction relative to the central axis, and where (b) further comprises axially translating the packer piston in a second axial direction relative to the central axis that is opposite the first axial direction.

16. The method of claim 10, where (a) comprises axially translating the mandrel in a first axial direction relative to the central axis, and where (b) further comprises axially translating the packer piston in the first axial direction relative to the central axis.

17. An assembly for cutting and retrieving a casing from a subterranean borehole, the assembly comprises:a casing cutter including one or more expandable blades;a spear including one or more expandable anchors; anda packer coupled to the spear and the casing cutter, where the packer comprises:a throughbore;a body;a packing element;a packer piston; anda mandrel inserted into the body along a central axis, where the mandrel is configured to axially translate, relative to the central axis, under tension to selectively place the packer piston in fluid communication with the throughbore such that an increase in fluid pressure in the throughbore is configured to actuate the packer piston to expand the packing element.

18. The assembly of claim 17, where the spear is coupled between the packer and the casing cutter.PATENTAttorney Docket No.: WBRE / 0012PC19. The assembly of claim 17, where the packer further comprises a plunger that is inserted into the throughbore, where the plunger is configured to axially translate, relative to the central axis, to selectively lock the mandrel to the body based on a pressure in the throughbore.

20. The assembly of claim 19, where the packer further comprises one or more locking dogs positioned in one or more apertures extending radially through the mandrel, where the plunger is configured to axially translate, relative to the central axis, based on a fluid pressure in the throughbore to radially expand the one or more locking dogs into one or more recesses defined on the body to thereby lock the mandrel to the body.

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