Retrieval of compressed packers from a wellbore

A packer assembly is located in a compacted wellbore and a method of relieving compression on the packer assembly are disclosed. An initial load path that exists when the packer assembly is in a set position is altered. The alteration of the load path relieves substantially all of the compression on the packer assembly. This causes a lower packer mandrel to move towards an upper packer mandrel. This upward movement shortens the distance between the upper packer mandrel and the lower packer mandrel, which removes the compressive forces on the packer assembly.

TECHNICAL FIELD

The present disclosure relates generally to a packer assembly and methods for relieving compression on a packer assembly located within a wellbore. The packer assembly can include a settable packer element. The packer assembly can also include slips that are engaged to the casing. When the packer assembly is to be retrieved, the packer element can be unset, and the slips can be disengaged from the casing. The compression at the bottom of the packer assembly can be relieved by changing the compression load path that was from the bottom of the packer mandrel to the slips. According to an embodiment, the packer assembly is used in an oil or gas well operation. Disengaging the slips allows the packer assembly to be retrieved from the wellbore.

DETAILED DESCRIPTION

As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

As used herein, a “fluid” is a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas

Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil, gas, or water is referred to as a reservoir. A reservoir may be located under land or off shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from the wellbore is called a reservoir fluid.

A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. The wellbore is drilled into a subterranean formation. The subterranean formation can be a part of a reservoir or adjacent to a reservoir. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered the region within approximately 100 feet radially of the wellbore. As used herein, “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.

A portion of a wellbore may be an open hole or cased hole. In an open-hole wellbore portion, a tubing string may be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.

It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device.

During well completion, it is commonly desired to seal a portion of an annulus so fluids will not flow through the annulus but rather flow through the tubing string or casing. By sealing the portion of the annulus, oil, gas, water, or combinations thereof can be produced in a controlled manner through the wellhead via the tubing string or casing. Different tools can be used to create seals in the well. Examples of such tools include packers and bridge plugs.

Packers can be utilized to seal the annulus in a wellbore. Typically, packers are used to anchor the tubing to the wellbore and to seal the tubing to the wellbore. A packer can be used in cased wellbore portions or open-hole wellbore portions. A packer can include an element that seals to the wellbore to isolate the portion of the wellbore and also slips that grip the inside of a casing or wall of the wellbore to anchor the packer to the casing or wellbore wall. Rubber elements are used to create a seal in the wellbore. A setting method can activate or energize the packing elements and slips while a releasing method can return the packer to the un-set position. A gravel pack packer can use a setting tool to apply compression to energize the packing element and slips. A hydraulic packer has an internal setting piston that is hydraulically actuated to apply the compression to energize the packing element and slips. A hydrostatic set packer has an atmospheric chamber that collapses with well hydrostatic pressure to supply the compressive forces needed to set the packer. A mechanical packer uses compression of the tubing string to apply the compressive force needed to energize the element and slips. All of these types of packers have a packer element that is a ring of elastomeric material fitted on the outside of a mandrel. The actuation of the packer axially squeezes the packer element to cause radial expansion of the packer element and seals the annulus. The actuation of the packer deploys the slips to grip and anchor the packer to the inside of the casing or wall of the wellbore.

A packer can be introduced into or run into the wellbore on a work string or on a production tubing during the course of treating and preparing the well for production. The packer can act as an isolation device. For example, the packer can be used to substantially seal the annulus between the outside of the production tubing and the inside of the casing or wall of the wellbore by blocking the movement of fluids through the annulus past the packer location. Packers can also be used as service tools.

A retrievable packer can typically include four main components: a mandrel or body, a packing or sealing element, a slip system that includes the slips and slip props for allowing the slips to engage the inner diameter (I.D.) of a casing or wall of a wellbore, and a releasing mechanism that can return the packer to a substantially un-set position. A portion of the slips generally contain teeth that allow the packer to engage with the I.D. of the casing or wall of the wellbore to set the packer in the wellbore. On occasion, it may become necessary to remove packers from the wellbore. For example, the well operator can require the retrieval of the packer to re-work the well or to change out the production tubing. To release the packer, a load device can be disengaged from the mandrel. This disengagement removes the transfer of compressive forces to the slip props and the lower part of the mandrel can move downward into the wellbore. This causes or allows the slip prop to also move downward such that the slip is disengaged, and the packer is released and can be retrieved. However, it can be difficult to release a packer if the packer is subjected to relatively large compressive forces in the wellbore.

Compaction of the formation can result from the extraction of hydrocarbons, fluids, sand, etc. during well production. The flow of these substances can result in subsidence such that the bottom of the wellbore can shrink upwards towards the bottom of the packer. In such instances, due to the compacted formation, the packer and associated completion equipment below the packer are subjected to a large amount of compression. As a result of the compression, it can become extremely difficult to retrieve the packer during a workover of the well due to the lower part of the mandrel being incapable of moving downward in the wellbore. The occurrence of compression can sometimes be predicted and additional equipment such as compaction joints or shear joints can be placed below the packer to compensate for the compressive forces. However, these other assemblies take up space and require additional tools or operations to release. They can also overly complicate well operations. Other invasive operations, such as milling the packer, or cutting the tubing string below the packer to relieve the compression, can also be performed in order to release and remove the packer from the wellbore.

Some of the drawbacks with using conventional methods to retrieve a compressed packer include: the well intervention operations can result in expensive production downtime; specialized personnel and tools can be needed to conduct these operations; and these operations can be invasive in nature. Currently, there are not any non-invasive methods to relieve the compressive forces on the packer to thereby release the slips from engagement with the I.D. of the tubing string or wall of the wellbore. Therefore, there is a need for a new packer retrieval mechanism/assembly and a non-invasive method of relieving compression from below a packer so that the packer can be retrieved from the wellbore.

It has been discovered that shortening the length of a portion of a packer mandrel, the packer can be released from a compressed wellbore. By being able to release the slips, the packer can be easily retrieved from the wellbore while minimizing production downtime due to well intervention/milling operations.

According to an embodiment, a novel method of relieving compression on a packer assembly located in a wellbore comprises: causing the length of the packer assembly to be shortened, wherein the packer assembly comprises: a packer mandrel, wherein the packer mandrel comprises an upper packer mandrel and a lower packer mandrel; and a sleeve, wherein the sleeve is sealably connected to the upper packer mandrel and the lower packer mandrel, wherein the sleeve is shifted upward such that the lower packer mandrel is released, and wherein the lower packer mandrel is moved upward relative to the upper packer mandrel.

The packer assembly further comprises: a slip system wherein the slip system is located on the outside of the packer mandrel, and wherein the slip system comprises: a slip; and a slip prop, wherein the slip prop is capable of supporting the slip such that the slip engages an inner diameter of a casing or a wall of the wellbore; and a load device, wherein the load device cooperates with the slip prop to support the slip, and wherein the load device is engaged with the packer mandrel when the packer assembly is in a set position.

The packer assembly further comprises a tailpipe relief assembly, wherein the tailpipe relief assembly comprises: a positioning device, wherein at least a portion of the positioning device is attached to the lower packer mandrel; and a positioning prop, wherein a first end of the positioning prop is capable of supporting at least a portion of the positioning device in a first position. The tailpipe relief assembly can further comprise an end cap, wherein the positioning device can be engaged with the end cap when the positioning device is in the first position. The tailpipe relief assembly can also comprise a housing, wherein the housing can be connected to the end cap, and wherein the housing is operatively connected to the slip prop.

According to another embodiment, a method of retrieving a packer assembly from a wellbore comprises: (A) locating a retrieving tool in the packer assembly, wherein the packer assembly comprises: a packer mandrel, wherein the packer mandrel comprises an upper packer mandrel and a lower packer mandrel; and a sleeve, wherein the sleeve is sealably connected to the upper packer mandrel and the lower packer mandrel, and wherein the retrieving tool is located inside a profile in the sleeve; and a load device, wherein the load device is engaged with the packer mandrel when the packer assembly is in a set position; and (B) unsetting the packer assembly, wherein unsetting the packer assembly comprises: applying an upward force on the retrieval tool, wherein application of the upward force shifts the sleeve upward and causes the load device to become disengaged from the packer mandrel; and disengaging the lower packer mandrel such that compression forces on the packer assembly are substantially relieved. The method further includes applying a downward force on the retrieval tool, wherein the application of the downward force causes the lock ring to engage the packer mandrel, and wherein the application of the downward force is transferred from the retrieval tool through the packer mandrel to the lock ring causing the lower slip prop to be moved a sufficient distance and such that the slip is incapable of being engaged with the inner diameter of the casing or the wall of the wellbore.

According to the present disclosure, the packer assembly is capable of being retrieved even when it is subjected to a relatively large amount of compression in the wellbore. The sleeve is shifted using, for example, via a retrieval tool. This application of an upward force on the packer mandrel followed by a subsequent downward force on the packer mandrel relieves the load on the slips such that the slips can be disengaged from the inner diameter (I.D.) of the casing or the wall of the wellbore. Additionally, the bottom end of the packer assembly can be shortened thereby relieving the compression below the packer assembly.

Turning to the Figures,FIG. 1depicts a well system10. The well system10can include at least one wellbore11. The wellbore11can penetrate a subterranean formation12. The wellbore11comprises a wall13. The subterranean formation12can be a portion of a reservoir or adjacent to a reservoir. The wellbore11can include a casing14. The wellbore11can include only a generally vertical wellbore section or can include only a generally horizontal wellbore section. One or more tubing strings, for example, a tubing string15can be installed in the wellbore11. The tubing string15can provide a conduit for fluids to travel from the formation to the surface of the wellbore11or vice versa. A packer assembly16can be run into the wellbore11. The packer assembly16can provide an annular seal between the outside of the tubing string15and the inside of the casing14or wall of the wellbore13to define zones17,18. The packer assembly16can also be used between the outside of a first tubing string and the inside of a second tubing string (not shown). The packer assembly16can be used to seal or “pack off” the wellbore11such that the flow path of fluids in the wellbore11can be redirected.

It should be noted that the well system10illustrated in the drawings and described herein is merely one example of a wide variety of well systems in which the principles of this disclosure can be utilized. For instance, the wellbore11can have a horizontal section and a vertical section. It should be clearly understood that the principles of this disclosure are not limited to any of the details of the well system10, or components thereof, depicted in the drawings or described herein. Furthermore, the well system10can include other components, such as, production tubing, screens, and other isolation devices not depicted in the drawing. According to the various embodiments, one or more packers can be introduced into multi-zone completions, between an inner and outer string, and in a vertical and/or horizontal section of the wellbore11. The packer assembly16can be installed in the wellbore11during well completion operations or well testing operations. The packer assembly can be located in a cased wellbore section or an open-hole wellbore section. There can also be more than one packer assembly located within the wellbore in a variety of location, for example in cased sections, open-hole sections, or combinations thereof.

Referring now toFIG. 2, according to one embodiment, the packer assembly16can be a gravel pack packer20that is used to support and retain gravel placed during gravel pack operations. In another embodiment, the packer assembly16can be a hydraulic packer (not shown) that can be set with the application of tubing pressure or a hydrostatic set packer (not shown) that can be set with the application of wellbore hydrostatic pressures. Any combination of setting methods can be employed to set the packer. An example of a gravel pack assembly20is the Sand Control Versa-Trieve® Packer, marketed by Halliburton Energy Services, Inc. The packer assembly16can include a body or packer mandrel21. The packer mandrel21can include an upper packer mandrel21aand a lower packer mandrel21b. The packer assembly16can also include a slip23. Any discussion of a particular component of an embodiment (e.g., a slip, a desired wellbore zone, etc.) is meant to include the singular form of the component and also the plural form of the component, without the need to continually refer to the component in both the singular and plural form throughout. For example, if a discussion involves “the lug41,” it is to be understood that the discussion pertains to one lug (singular) and two or more lugs (plural). The slip23can be biased outwardly away from a central, vertical axis of the packer mandrel21.

Referring toFIGS. 3A and 3B, the packer assembly16can include a body or packer mandrel21. The packer mandrel21can include an upper packer mandrel21aand a lower packer mandrel21b. The packer assembly16can also include a slip23and a packing or a sealing element22. The packing element22can be located on the outside of the upper packer mandrel21a. The packing element22can radially expand outwardly away from the mandrel to provide a substantially pressure tight seal in an annulus, for example between the outside of a tubing string and the inside of the casing when the packer assembly16is set or located in a desired zone in the wellbore11. The desired zone could be anywhere in the wellbore11including, for example, the riser in offshore applications. As described earlier, the packer assembly16can be subjected to compressive forces in the wellbore11.

The details of the packer assembly16that is run or located within a compacted wellbore will be further described. It is to be understood that as depicted in these and the ensuing figures, the packer assembly16is in a set or operating position. As described earlier, the packer assembly16can include a packer mandrel21. The packer mandrel21can allow fluids to flow from or into the subterranean formation via a conduit defined by a tubing string. While the packer mandrel21has been depicted in separate form, in other embodiments, the packer mandrel21can be an integral part of a tubing string.

The packer assembly16can include a slip system located on the outside of the packer mandrel21. The slip system includes a slip23. The slip23can be made from a single cylinder of material commonly referred to as a barrel slip, a set of slips retained in a groove on the slip prop commonly referred to as a dove-tail slip, or a slip retained by a housing with windows commonly referred to as a caged slip. The slip23can be located around a portion of the outside of the packer mandrel21and radially biased towards the outside of the packer mandrel21. The slip23can have teeth on its face. As used herein, the term “teeth” includes one or more elements that are capable of grippingly engaging an I.D. of a tubing string, or casing, or wall of the wellbore to retain the packer assembly16in a set position. The teeth can be sharp ridges machined onto the face of the slip23or sharp elements, for example, buttons or other geometric shapes that are attached to the face of the slip23. The slip system can further include a slip prop31. The slip prop can include an upper slip prop31band a lower slip prop31a. An upper and a lower end of each slip23can be formed having a conical or ramped surface. These surfaces are complementary to and can slidingly engage a parallel, ramped surface of the upper slip prop31band ramped surface of the lower slip prop31a, respectively. In one position, the slip23can be positioned substantially adjacent to the packer mandrel21and axially separated from the slip prop31so that the outer diameter (O.D.) of the slip23is less than or equal to the O.D. of the slip prop31. After the packer assembly16is run in the wellbore, it can be set. Setting the packer assembly16involves applying compression to the slip system to move the slip23axially towards and along the face of the slip prop31to move the slip23radially into engagement with the casing or wellbore and to allow the slip23to maintain engagement with the casing or wellbore wall. When the slip23is engaged with the casing or wellbore wall, the packer assembly16has substantially limited or no vertical movement within the wellbore. Setting the packer assembly16can further involve causing or allowing the packer elements to expand radially to form a pressure tight annular seal. The packer assembly can further include more than one slip system to facilitate setting of the packer assembly.

The slip prop31can support the slip23in an expanded position outward from the mandrel21such that the slip23engages the I.D. of the casing or the wall of the wellbore when the packer assembly16is set. The slip prop31can prevent the slip23from retracting and releasing from the casing or well bore once the packer assembly16is set. As used herein, the term “slip prop” can include a wedge, cone, or any device that can support the slip23when it is set.

The packer assembly16is capable of withstanding a relatively large amount of compression. While compressive forces hold the slip23securely in position such that it can be extremely difficult to disengage the slip23from its set position, according to the present disclosure, the slip prop31can also facilitate the release of the slip23and ensure re-setting of the slip23.

A load device33can be in engagement with the packer mandrel21. According to an embodiment, the load device33can facilitate the setting of the packer assembly16by cooperating with the lower slip prop31ato cause the slip23to engage the I.D. of a casing string or the wall of the wellbore. Although the term “load device” has been used herein, the term is also intended to include, without limitation, a load ring, a lock ring, a ring, a collet, a pin, one or more lugs, and any other suitable device. The load device33maintains the position of the housing49to the position of the upper mandrel21aby preventing relative movement and thereby maintaining the packer assembly16in the set position. The load device33cooperates with the lower slip prop31ato support the slip23in engagement with the I.D. of the casing or the wall of the wellbore. The load device33retains the necessary setting force, such as an initial compression force applied to the packer element and the slip system.

Referring toFIG. 3A, an axial setting force is applied to the setting sleeve38to axially compress the packing element22to cause it to expand to the I.D. of the casing or wall of the wellbore11. The axial force is transferred through the element22and into the upper slip prop31bto cause the slip system to engage the I.D. of the casing or wellbore wall. The packing element22is subjected to mechanical pressure that causes it to be squeezed into high contract stress to the casing or the wall of the wellbore11. The packing element22is retained on an upper end by a lock ring37that grips the packer mandrel21. A lower end of the packing element22pushes against the upper slip prop31band into the slip23. As the rubber pressure pushes up against the lock ring37that is gripping the packer mandrel21, the packer mandrel21transfers the stress to the load device33. The load device33transfers the force to the lower slip prop31aand into the slip23. The load device33keeps the packer assembly16in the set position by retaining the setting force from the lock ring and along the packer mandrel21.

Tubing forces, namely, tension and compression, can be transferred to the slip23through the packer mandrel21. Compression applied to the mandrel is transferred through the lock ring37to the packing element22and into the upper slip prop31band then into the slip. Tubing tension is transferred through the packer mandrel21to the load device33then to the lower slip prop31aand into the slip23. Similarly, compression forces below the packer assembly16can be transferred from the lower mandrel21bto the cage44to the lugs41to the end cap45to the housing49to the slip props31a/31band into the slip23.

In one embodiment, referring back toFIG. 3B, the packer assembly16can also include a lock ring32. Again, while the term “lock ring” has been used herein, the term is also intended to include, without limitation, a load device, a collet, a ring, a c-ring, a pin, one or more lugs, and any other suitable device. The lock ring32can include one or more ratchets or teeth on an inside surface that abuts a corresponding ratchet mating profile on the packer mandrel21. The lock ring32can be used in retrieving the packer assembly16by pulling the lower slip prop31aaway from the slip23as will be detailed later.

Referring now toFIG. 4, in one embodiment, the packer assembly16includes a sleeve46. When the packer assembly16is set, the load device33is held against the mandrel by the sleeve46. The sleeve46at least partially encloses or envelops the packer mandrel21. At least a portion of the sleeve46terminates in a sleeve shoulder46a. The sleeve46can be connected to the packer mandrel21and lower packer mandrel21bby a sealing element47aand47b. For example, the sleeve46can be connected to the packer mandrel21by one or more O-rings. The sleeve46can include a pre-configured mating profile34, such as a recessed profile. The mating profile34can engage with a matching profile of, for instance, a retrieval tool (not shown) when the packer assembly16and the retrieval tool are brought into cooperative alignment. After the slip23is released, the packer assembly16can be retrieved using the retrieval tool.

The packer assembly16includes the packer mandrel21and a lower packer mandrel21b. The lower packer mandrel21bcan be threadingly engaged with a tailpipe (not shown). The tailpipe can include tubing or other completion equipment that are run below the packer assembly16. The tailpipe is subjected to a large amount of compression when the packer assembly16is located within a compacted wellbore. According to one embodiment, the compression can be relieved or at least substantially relieved by activating a tailpipe relief assembly that is attached to the lower packer mandrel21b. The tailpipe relief assembly can include a positioning device attached to the lower packer mandrel21band a positioning prop, wherein a first end of the positioning prop is capable of supporting at least a portion of the positioning device in a first position, and wherein the portion of the positioning device is in the first position prior to causing the length of the packer assembly to be shortened (i.e., the packer is in the set position). The positioning device can include a cage44and a lug41, a collet, a c-ring, or a dog. The positioning prop can be a lug prop, a collet prop, a c-ring prop, or a dog prop. When the positioning device is in the first position, at least a portion of the positioning device can be operatively connected to the slip system. By way of example, for a collet, a finger of the collet can be connected to an end cap45and/or an outer housing49when the collet is in the first position. Although some of the discussion with reference to the figures discusses a cage, lug, and lug prop, it is to be understood that a collet or a dog and a collet prop or a dog prop could be used to relieve the compression on the packer assembly. A second end of the lug prop42terminates in a lug prop shoulder42a.

The tailpipe relief assembly can further include a housing49. The housing49can be threadingly connected to an end cap45and the housing49can be operatively connected to the lower slip prop31a. In one embodiment, the housing49is threadingly connected to the lower slip prop31a.

When the packer assembly is in the set position, force from an area below the packer is transferred via a load path from the lower mandrel21bto the slip system via the positioning device in the first position. By way of example, if the positioning device is a cage, lug, and lug prop, then the force can be transferred to the slip system via the lower mandrel to the cage44, to the lug41, to the end cap45, to the housing49, and to the slip system when the lug is in the first position. By way of another example, for a collet, the force can be transferred to the slip system via the lower mandrel to the collet, to the end cap and/or housing, to the slip system. In this manner, the force required to maintain the packer in the set position can be partially supplied by compressive forces below the packer.

According to an embodiment, and referring generally toFIGS. 4-8, a method of relieving compression on a packer assembly16located in a wellbore comprises shifting the sleeve46, thereby causing at least a portion of the positioning device to become disconnected from the slip system. For example, the lug41can become disengaged from the end cap45such that the lug is no longer operatively connected to the slip system via the end cap and/or housing. When the positioning device is disconnected from the slip system, at least some of the compression on the slip system is relieved.

When the packer assembly16has to be retrieved, such as during workover operations, a retrieval tool can be introduced into the packer assembly16. As mentioned earlier, the packer assembly16can be subjected to extremely large compressive forces in the wellbore. The retrieval tool can be anchored with a set of keys engaged inside the mating profile34on the sleeve46. Although the retrieval tool is anchored in position, it can be moved up or down by exerting an upward or downward force such as by pulling upward or pushing downward on the retrieval tool. As used herein, the relative term “upward” is used to indicate in a direction that is toward the wellhead. The relative term “downward” is used to indicate in a direction away from the wellhead. The mating profile34can be designed specifically such that it can only receive the retrieval tool and is not accidentally tripped by any other tool. When the retrieval tool is pulled upward, the sleeve46is also shifted upward by pulling up the mating profile34.

When the sleeve46is shifted upward, the load device33is uncovered and is disengaged from the packer mandrel21. The load device33can be biased radially to expand out of engagement with the packer mandrel21and is received into a load device recess or groove51. When the load device33is received in the load device recess51, the lower slip prop31ais no longer supported and can be moved downward when compression forces are not present. When the lower slip prop31ais moved downward, the slip23is no longer supported and is thereby disengaged from the I.D. of the casing or the wall of the wellbore. The packer mandrel21is free to travel upwards to release the force in the packing element and to allow the packer assembly16to substantially return to its run-in position. Accordingly, in one embodiment, the application of an upward force may be sufficient in itself to facilitate the release or unpropping of the slip23. When the slip23is released, the packer assembly16can be retrieved from the wellbore relatively easily and without the use of any invasive techniques.

According to another embodiment, the method includes the steps of: (i) releasing the load device33when the sleeve46is shifted upward (as described above) from engagement with the packer mandrel21and (ii) activating the tailpipe relief assembly to relieve tailpipe compression. Activation of the tailpipe relief assembly can happen (i) subsequent to the load device33being released, (ii) simultaneously with the release of the load device33, or (iii) prior to the release of the load device33. Irrespective of the sequence in which these steps occur, the compression on the packer assembly16can be relieved and the slip23can be disengaged from the I.D. of the casing or the wall of the wellbore.

According to one embodiment and as can be seen, for example inFIG. 5A, the upward force causes the positioning device to move to a second position, and wherein when the positioning device is in the second position, the load path is diverted away from the slip system. When the positioning device is in the second position, the lower packer mandrel21bcan move towards the upper mandrel. The movement into the second position can include causing the positioning prop (e.g., a lug prop42) to move upwards in the wellbore. The lug prop42moves upwards by the application of an upward force on the sleeve46via the shouldered connection of the sleeve to the second end of the lug prop. In one embodiment, the lug prop42acontinues to move upward within the cavity43. When the lug prop42acan move a sufficient distance d1within the cavity43, as depicted inFIG. 8, the positioning device (e.g., a lug41) can collapse. After collapsing, the positioning device can be disengaged from the end cap and/or housing. The distance d1can be designed to be sufficient enough to relieve either all, substantially all, or at least a portion of the tailpipe compression. Accordingly, distance d1is a “tailpipe relief distance.” When lug prop42traverses the tailpipe relief distance, the lug41is no longer supported in the expanded, first position and is released from the operative connection to the slip system. The tailpipe relief distance can be factored in when designing the dimensions of the cavity43.

When the sleeve46is shifted upward, such as, by pulling up on the retrieval tool, it causes the sleeve shoulder46ato come into telescopic connection with the lug prop shoulder42awithin the cavity43defined by at least a portion of an outer surface of the lower packer mandrel21band at least a portion of the sleeve46. As used herein, the term “cavity” can include a recess, slit, or any passage that can receive the movement of the lug prop42. The shouldered telescopic connection causes the lug prop42to move upwards along the lower packer mandrel21bsuch that the lug prop42no longer support the lug41in the expanded position. The lug41can then be disengaged from the end cap45.

Once the lug41is disengaged from the end cap45, the load path that existed when the packer was in the set position is altered. After disengagement, the lug41is no longer able to transfer the compressive load to the end cap45for further transfer up to the slip system. The alteration of the load path relieves at least a portion of the compression on the slip system. In another embodiment, substantially all the compression on the slip system is relieved by the alteration of the load path. The disengagement of the lug41from the end cap45can also cause the lower packer mandrel21band possibly the cage44, the lug41, and the lug prop42to move upwards. This upward movement shortens the distance between the upper packer mandrel21and the lower packer mandrel21b, which removes the compressive force on the tailpipe.

According to another embodiment, when an excessively large amount of compression is present in the wellbore, such as, due to the compaction of the formation, a method of relieving compression on the packer assembly involves utilizing the earlier mentioned lock ring32. As used herein, the relative terms “excess” or “excessively large amount” mean a larger than normal amount of compression in the wellbore and would be understood as such by a person of ordinary skill in the art. The lock ring32can be engaged with the packer mandrel21by a matching profile (not shown) machined on the packer mandrel21. The packer mandrel21can move upwards as the lock ring32is designed to ratchet or slip into and out of engagement with the packer mandrel21. The lock ring32will engage or grip the mandrel to resist downward movement of the packer mandrel21. The lock ring32can be activated by pulling up on the packer mandrel21. When activated, the lock ring32ratchets into the packer mandrel21. When a downward force is subsequently applied to the packer mandrel21, this downward force is transferred through the packer mandrel21to the lock ring32. The downward force causes the ratcheted lock ring32to be pulled or moved downwards. The downward force on the lock ring32is transferred through a lock ring face through to a housing face to the housing49. The downward force applied to the packer mandrel21is transferred through lock ring32to housing49and to the lower slip prop31a. When the lock ring32moves downwards, it can also pull the lower slip prop31adownward and out of engagement with the slips23. The downward force applied to the packer mandrel21must be greater than the compression forces on the tailpipe. After all of the compression force on the tailpipe has been removed or released, the retrieving tool may only have to overcome the friction between the slip23and the slip prop31. The lower slip prop31atravels the sufficient distance d2within a recess located within the sleeve46, as shown inFIG. 5B. The unsupported slip23can therefore, collapse out of engagement with the I.D. of the casing or the wall of the wellbore. As described earlier, when the slip23is released, the packer assembly16can be retrieved from the wellbore relatively easily and without the use of any invasive techniques.

Distance d2can be factored in when designing the dimensions of the recess. Ideally, the recess has dimensions such that when the lower slip prop31atraverses a distance d2in the recess, this distance is sufficient to release the slip23from engagement with the I.D. of the casing or the wall of the wellbore. The non-limiting embodiments described herein can minimize rig time involved in conducting expensive fishing operations to retrieve the packer assembly16, and in particular, when the packer assembly16is subjected to a large amount of compression.

The methods can include retrieving the packer assembly16from the wellbore. The packer assembly16can be retrieve after activating the tailpipe relief assembly as described previously. The retrieval can also include removing the packer from the wellbore after the compression on the packer assembly has been relieved.

It should be understood that, as used herein, “first,” “second,” “third,” etc., and “upper” and “lower” are arbitrarily assigned and are merely intended to differentiate between two or more positions, etc., as the case may be, and does not indicate any particular orientation or sequence. Furthermore, it is to be understood that the mere use of the term “first” does not require that there be any “second,” and the mere use of the term “second” does not require that there be any “third,” etc.