Multiple ramp compression packer

Systems and methods for remotely setting a downhole device. The system includes a base pipe having inner and outer radial surfaces and defining one or more pressure ports extending between the inner and outer radial surfaces. An internal sleeve is arranged against the inner radial surface and slidable between a closed position, where the internal sleeve covers the one or more pressure ports, and an open position, where the one or more pressure ports are exposed to an interior of the base pipe. A trigger housing is disposed about the base pipe and defines an atmospheric chamber in fluid communication with the one or more pressure ports. A piston port cover is disposed within the atmospheric chamber and moveable between blocking and exposed positions. A wellbore device is used to engage and move the internal sleeve into the open position by applying predetermined axial force to the internal sleeve.

BACKGROUND

The present invention relates to systems and methods used in downhole applications and, more particularly, to providing a seal in a casing annulus capable of stopping gas migration.

In the course of treating and preparing a subterranean well for production, downhole tools, such as well packers, are commonly run into the well on a conveyance such as a work string or production tubing. The purpose of the well packer is not only to support the production tubing and other completion equipment, such as sand control assemblies adjacent to a producing formation, but also to seal the annulus between the outside of the production tubing and the inside of the well casing or the well bore itself. As a result, the movement of fluids through the annulus and past the deployed location of the packer is substantially prevented.

SUMMARY OF THE INVENTION

The present invention relates to systems and methods used in downhole applications and, more particularly, to providing a seal in a casing annulus capable of stopping gas migration.

In some embodiments, a system for sealing a wellbore annulus is disclosed. The system may include a base pipe having inner and outer radial surfaces and defining an elongate orifice, and an opening seat arranged against the inner radial surface and having a setting pin coupled thereto and extending radially through the elongate orifice, the setting pin being configured to axially translate in a first direction within the elongate orifice as the opening seat axially translates. The system may further include a piston arranged on the outer radial surface and being coupled to the setting pin such that axial translation of the opening seat correspondingly moves the piston, the piston having a piston biasing shoulder, and a lower shoe extending about the outer radial surface and having a mandrel biasing shoulder. The system may also include a packer disposed about the outer radial surface and interposing the piston and the lower shoe, the packer having a first packer element adjacent the piston and a second packer element adjacent the lower shoe, and a wellbore device disposed within the base pipe and configured to engage and move the opening seat, wherein as the opening seat axially translates in the first direction the first and second packer elements are compressed against the piston and mandrel biasing shoulders, respectively, and the first packer element forms a first seal in the annulus and the second packer element forms a second seal in the annulus, and wherein the first and second seals define a cavity therebetween that traps fluid therein and provides a hydraulic seal.

In some embodiments, a method for sealing a wellbore annulus is disclosed. The method may include engaging an opening seat with a wellbore device, the opening seat being movably arranged within a base pipe having inner and outer radial surfaces and defining an elongate orifice, the opening seat further having a setting pin coupled thereto and extending radially through the elongate orifice, and applying a predetermined axial force on the opening seat with the wellbore device and thereby axially moving the opening seat and the setting pin in a first direction. The method may further include moving in the first direction a piston arranged on the outer radial surface, the piston being coupled to the setting pin such that axial translation of the opening seat correspondingly moves the piston, wherein the piston has a piston biasing shoulder, and engaging and compressing a first packer element with the piston biasing shoulder and thereby forming a first seal within the wellbore annulus. The method may also include engaging and compressing a second packer element with a mandrel biasing shoulder and thereby forming a second seal within the wellbore annulus, and forming a hydraulic seal in a cavity defined between the first and second seals.

In some embodiments, a system for sealing a wellbore annulus may be disclosed. The system may include a base pipe having inner and outer radial surfaces and defining an elongate orifice, and an opening seat arranged against the inner radial surface and having a setting pin coupled thereto and extending radially through the elongate orifice, the setting pin being configured to axially translate in a first direction within the elongate orifice as the opening seat axially translates. The system may also include a piston arranged on the outer radial surface and being coupled to the setting pin such that axial translation of the opening seat correspondingly moves the piston, the piston having a piston biasing shoulder, a lower shoe extending about the outer radial surface and having a mandrel biasing shoulder, and a first ramped collar arranged about the base pipe and interposing the piston and the lower shoe, the first ramped collar having a first ramp and an opposing second ramp, and a first biasing shoulder and an opposing second biasing shoulder. The system may further include a first packer element disposed about the base pipe and arranged between the piston and the first ramped collar, a second packer element disposed about the base pipe and arranged between the lower shoe and the first ramped collar, and a wellbore device disposed within the base pipe and configured to engage and move the opening seat, wherein as the opening seat axially translates in the first direction the first and second packer elements are compressed and the first packer element forms a first seal in the annulus and the second packer element forms a second seal in the annulus.

In some embodiments, a system for sealing a wellbore annulus may be disclosed. The system may include a base pipe having inner and outer radial surfaces, a hydrostatic piston arranged within a hydrostatic chamber defined by a retainer element arranged about the base pipe, the retainer element having a retainer shoulder, and a compression sleeve arranged about the base pipe and coupled to the hydrostatic piston with a stem element extending from the hydrostatic piston, the compression sleeve having a sleeve shoulder. The system may also include first and second packer elements arranged about the base pipe and interposing the retainer element and the compression sleeve, and a wellbore device disposed within the base pipe and configured to engage and move an opening seat arranged against the inner radial surface, wherein moving the opening seat triggers a pressure differential across the hydrostatic piston and forces the hydrostatic piston to pull the compression sleeve into contact with the second packer element and the retainer element into contact with the first packer element, and wherein the first and second packer elements are compressed and form first and second seals, respectively, in the annulus and further define a cavity therebetween, the cavity being configured to trap fluid therein and provide a hydraulic seal.

The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

DETAILED DESCRIPTION

The present invention relates to systems and methods used in downhole applications and, more particularly, to providing a seal in a casing annulus capable of stopping gas migration.

As will be discussed in detail below, several advantages are gained through the systems and methods disclosed herein. For example, the disclosed systems and methods initiate and set a downhole tool, such as one or more well packers or packer elements, in order to isolate the annular space defined between a completion casing and a base pipe (e.g., production string). The set packer is able to create a seal that prevents the migration of fluids through the annulus, thereby isolating the areas above and below. The packer may be set using hydraulic and/or mechanical means, and adjacent packer elements may provide one or more hydraulic seals in the annulus that prevent or otherwise eliminate the migration of gases at elevated pressures. To facilitate a better understanding of the present invention, the following examples are given. It should be noted that the examples provided are not to be read as limiting or defining the scope of the invention.

Referring toFIG. 1, illustrated is a cross-sectional view of an exemplary downhole system100configured to seal a wellbore annulus, according to one or more embodiments. The system100may include a base pipe102extending within a casing104that has been cemented in a wellbore (not shown) drilled into the Earth's surface in order to penetrate various earth strata containing hydrocarbon formations. The system100is not limited to any specific type of well, but rather may be used in all types, such as vertical wells, horizontal wells, multilateral (e.g., slanted) wells, combinations thereof, and the like. An annulus106may be defined between the casing104and the base pipe102. The casing104forms a protective lining within the wellbore and may be made from materials such as metals, plastics, composites, or the like. In at least one embodiment, the casing104may be omitted and the annulus106may instead be defined between the inner wall of the wellbore itself and the base pipe102.

The base pipe102may be coupled to or form part of production tubing. In some embodiments, the base pipe102may include one or more tubular joints, having metal-to-metal threaded connections or otherwise threadedly joined to form a tubing string. In other embodiments, the base pipe102may form a portion of a coiled tubing. The base pipe102may have a generally tubular shape, with an inner radial surface102aand an outer radial surface102bhaving substantially concentric and circular cross-sections. However, other configurations may be suitable, depending on particular conditions and circumstances. For example, some configurations of the base pipe102may include offset bores, sidepockets, etc. The base pipe102may include portions formed of a non-uniform construction, for example, a joint of tubing having compartments, cavities or other components therein or thereon. In some embodiments, at least a portion of the base pipe102may be profiled or otherwise characterized as a mandrel-type device or structure.

As illustrated, the system100may include at least one packer108disposed about the base pipe102. The packer108may be disposed about the base pipe102in a number of ways. For example, in some embodiments the packer108may directly or indirectly contact the outer radial surface102bof the base pipe102. In other embodiments, however, the packer108may be arranged about or otherwise radially-offset from another component of the base pipe102. The packer108may include a first packer element108aand a second packer element108b, having a spacer108cinterposing the first and second packer elements108a,b. As will be described in more detail below, the packer108may be configured to be compressed radially outward when subjected to axial compressive forces, thereby sealing the annulus in one or more locations.

The system100may further include an upper shoe110aand a lower shoe110bcoupled to and extending about the base pipe102. The upper and lower shoes110a,bmay be configured to axially bound the various components of the system100arranged about the outer surface102bof the base pipe102. In one or more embodiments, the lower shoe110bmay form an integral part of the base pipe102, such that it serves as a mandrel-type device that helps compress the packer108during operation. In other embodiments, as illustrated, the lower shoe110bmay bias against a shoulder112defined on the base pipe102, such that the lower shoe110bis substantially prevented from moving axially to the right, as indicated by arrow A.

With continued reference toFIG. 1, and additional reference toFIG. 1A, which provides an enlarged view of an indicated portion ofFIG. 1, the system100may further include a shear ring114, a lock ring housing116, a guide sleeve118, and a piston120. The shear ring114may be arranged axially adjacent the upper shoe110aand adapted to house one or more shear pins122. The shear pins122may extend partially into the base pipe102in order to maintain the components of the system100arranged about the outer radial surface102bin their axial placement until properly actuated. In some embodiments, eight shear pins122are employed and spaced about the outer radial surface102bof the base pipe102. As will be appreciated, however, more or less than eight shear pins122may be employed, without departing from the scope of the disclosure.

The lock ring housing116may be arranged axially adjacent the shear ring114and may house a lock ring124therein. In some embodiments, the lock ring housing116may be threaded onto the shear ring114and therefore able to move axially therewith. The lock ring124may be coupled or otherwise secured to the lock ring housing116using one or more lock pins126. In other embodiments, however, the lock ring housing116may be threaded onto the lock ring124, without departing from the scope of the disclosure.

In one or more embodiments, the lock ring124may define a plurality of ramped locking teeth128. In operation, the lock ring124may be configured to slidingly engage the outer surface102bof the base pipe102as the system100moves axially in the direction A. As the lock ring124translates axially, the ramped locking teeth128may be configured to engage corresponding teeth or grooves129defined on the outer surface102bof the base pipe102, thereby locking the lock ring124in its advanced axial position and generally preventing the system100from returning in the opposing axial direction.

The guide sleeve118may be arranged axially adjacent the lock ring housing116and configured to interpose or otherwise connect the lock ring housing116to the piston120. In some embodiments, the guide sleeve118may be threaded onto both the lock ring housing116and the piston120. One or more sealing components132may be configured to seal the radial engagement between the piston120and the guide sleeve118. In some embodiments, the sealing components132may be o-rings. In other embodiments, the sealing components132may be other types of seals known to those skilled in the art.

The piston120may include a piston biasing shoulder134aand a piston ramp136a. The piston ramp136amay be arranged axially adjacent the first packer element108aand configured to slidingly engage the first packer element108aas the packer108is being set. Likewise, the lower shoe110bmay define a mandrel biasing shoulder134band a mandrel ramp136barranged axially adjacent the second packer element108b. The mandrel ramp136bmay be configured to slidingly engage the second packer element108bas the packer108is being set.

The system100may further include an opening seat138axially movable and arranged within the base pipe102. The opening seat138may be disposed against the inner radial surface102aof the base pipe102and secured in its axial position therein using one or more setting pins140. Although only one setting pin140is shown inFIG. 1, it will be appreciated that any number of setting pins140may be used without departing from the scope of the disclosure. In at least one embodiment, five setting pins140may be employed in order to secure the opening seat138in its axial position within the base pipe102.

The setting pins140may be spaced circumferentially about the inner radial surface102aof the base pipe102. The setting pins140may extend through an axially elongate orifice144defined in the base pipe102in order to structurally couple the opening seat138to the piston120. For example, the setting pins140may extend between corresponding holes142defined in the piston120and corresponding holes130defined in the opening seat138. In some embodiments, the setting pins140are threaded into the holes142,130. In other embodiments, however, the setting pins140are attached to the piston120and/or the opening seat138by welding, brazing, adhesives, combinations thereof, or other attachment means.

In response to an axial force applied to the opening seat138in the direction A, the setting pins140may be correspondingly forced to translate axially within the elongate orifice144, thereby also forcing the piston120to translate in the direction A. However, as a result of the connective combination of the piston120, the guide sleeve118, the lock ring,116, and the shear ring114, the setting pins140are prevented from axially translating while the one or more shear pins122are intact or otherwise engaged with the base pipe102.

Referring now toFIG. 2, illustrated is the exemplary downhole system100in a compressed configuration or otherwise where the packer108has been properly set, according to one or more embodiments. In exemplary operation of the system100, a wellbore device202may be introduced into the well, within the base pipe102, and configured to engage and move the opening seat138in the direction A. In at least one embodiment, the wellbore device202is a plug, as known by those skilled in the art. In other embodiments, however, the wellbore device202may be another type of downhole device such as, but not limited to, a ball or a dart. In some embodiments, the wellbore device202may be configured to engage a profiled portion203defined on an upper end of the opening seat138. In other embodiments, however, the wellbore device202may be configured to engage any portion of the opening seat138, without departing from the scope of the disclosure.

Once the wellbore device202engages the opening seat138, a predetermined axial force in the direction A may be applied to the upper end of the wellbore device202in order to convey a corresponding axial force to the opening seat138and the one or more setting pins140coupled thereto. In some embodiments, the predetermined axial force may be applied to the wellbore device202by increasing fluid pressure within the base pipe102. For instance, the wellbore device202may be adapted to sealingly engage the opening seat138or otherwise substantially seal against the inner radial surface102aof the base pipe102such that a fluid pumped from the surface hydraulically forces the wellbore device202against the opening seat138. Increasing the fluid pressure within the base pipe102correspondingly increases the axial force applied by the wellbore device202on the opening seat138, and therefore increases the axial force applied to piston120via the setting pins140. Further increasing the fluid pressure within the base pipe102may serve to shear the shear pin(s)122and thereby allow the opening seat138and piston120to axially translate in the direction A.

In one or more embodiments, the predetermined axial force required to shear the shear pins122and thereby move the opening seat138and setting pins140in the direction A may be about 500 psi. In other embodiments, however, the predetermined axial force may be more or less than 500 psi, without departing from the scope of the disclosure. As will be appreciated, in other embodiments the predetermined axial force may be applied to the opening seat138in other ways, such as a mechanical force applied to the wellbore device202which transfers its force to the opening seat138.

As the opening seat138translates axially in the direction A, and the setting pins140translate within the elongate orifice144, the piston120is correspondingly forced to translate axially and into increased contact and interaction with the packer108. In particular, the first packer element108amay slidably engage and ride up the piston ramp136auntil coming into contact with the piston biasing shoulder134a. Likewise, the second packer element108bmay slidably engage and ride up the mandrel ramp136buntil coming into contact with the mandrel biasing shoulder134b. Upon engaging the respective biasing shoulders134a,b, and with continued axial movement in direction A, the first and second packer elements108a,bmay be compressed and extend radially to engage the inner wall of the casing104. In one or more embodiments, the system100is prevented from reversing direction, and thereby decreasing the radial compression of the packer108, by the ramped locking teeth128(FIG. 1A) that engage corresponding teeth or grooves (FIG. 1A) defined on the outer surface102bof the base pipe102. It will be appreciated, however, that other means of securing the system100in its compressed configuration may be used, without departing from the scope of the disclosure.

Accordingly, compressing the packer108between the piston120and the lower shoe110bserves to effectively isolate or otherwise seal portions of the annulus106above and below the packer108. As illustrated, the packer108may be configured to form a first seal204within the annulus106where the first packer element108aseals against the inner wall of the casing104. Likewise, a second seal206may be formed in the annulus106where the second packer element108bseals against the inner wall of the casing104. In operation, the first and second seals204,206may be configured to substantially prevent fluid migration between the upper and lower portions of the annulus106.

As the first and second seals204,206are generated, a cavity208may be formed between the compressed first and second packer elements108a,band extending axially across the spacer108c. The first and second packer elements108a,btrap fluid within the cavity208and as the elements108a,bare further compressed axially, the elastomeric material of each element108a,bmay compress the cavity208and thereby increase the fluid pressure therein. Accordingly, a third seal210may be generated within the cavity208and characterized as a hydraulic seal.

In at least one embodiment, a predetermined axial force of about 500 psi, as applied to the wellbore device202and correspondingly transferred to the piston120through the interconnection with the opening seat138, may result in a fluid pressure generated in the cavity208of about 10,000 psi or more. In other embodiments, pressures greater or less than 10,000 psi may be obtained within the cavity208, without departing from the scope of the disclosure. The increased pressures of the hydraulic third seal210may help the packer108prevent or otherwise entirely eliminate the migration of fluids (e.g., gases) through the packer108.

Referring now toFIG. 3, illustrated is another exemplary downhole system300configured to seal a wellbore annulus, according to one or more embodiments. The downhole system300may be similar in several respects to the downhole system100described above with reference toFIGS. 1 and 2, and therefore may be best understood with reference thereto, where like numerals indicate like components that will not be described again in detail. As illustrated, the system300may include a ramped collar302slidably arranged about the base pipe102and interposing the first and second packer elements108a,b. The ramped collar may include one or more sealing components303configured to seal the sliding engagement between the ramped collar302and the base pipe102. In some embodiments, the sealing components303may be o-rings. In other embodiments, however, the sealing components303may be other types of seals known to those skilled in the art.

The ramped collar302may further include a first ramp304aand an opposing second ramp304b, and a first biasing shoulder306aand an opposing second biasing shoulder306b. The piston120may define or otherwise provide a square piston shoulder308ajuxtaposed against the first packer element108a. Likewise, the lower shoe110bmay define or otherwise provide a square mandrel shoulder308bjuxtaposed against the second packer element108b. Axial translation of the piston120in the direction A inFIG. 3, as well as in one or more of the embodiments discussed below, may be realized in a manner substantially similar to the axial translation of the piston120as discussed above with reference toFIGS. 1 and 2, and therefore will not be discussed again in detail.

The first ramp304amay be arranged axially adjacent the first packer element108aand configured to slidably engage the first packer element108aas the square piston shoulder308apushes the first packer element108aaxially in the direction A. Likewise, the second ramp304bmay be arranged axially adjacent the second packer element108band configured to slidably engage the second packer element108bas the ramped collar302translates axially in the direction A and the square mandrel shoulder308bprevents the second packer element108bfrom moving in direction A.

Further axial movement of the piston120in direction A forces the first and second packer elements108a,binto engagement with the first and second biasing shoulders306a,b, respectively. Upon engaging the respective biasing shoulders306a,b, and with continued axial movement in direction A, the first and second packer elements108a,bare compressed and extend radially to engage the inner wall of the casing104. As a result, the first packer element108amay be configured to form a first seal310where the first packer element108aengages the inner wall of the casing104, and the second packer element108bmay form a second seal312where the second packer element108bengages the inner wall of the casing104.

As the first and second seals310,312are generated, a cavity314may be formed between the first and second packer elements108a,band extending axially across a portion of the ramped collar302. The first and second packer elements108a,btrap fluid within the cavity314and as the elements108a,bare further compressed axially, the elastomeric material of each element108a,bmay compress the cavity314and thereby increase the fluid pressure therein. Accordingly, a third seal316may be generated within the cavity314and characterized as a hydraulic seal, similar to the third seal210described above with reference toFIG. 2. It should be noted that the seals310,312, and316shown inFIG. 3are not depicted as compressed against the casing104as described above, but instead their general location is indicated.

Referring now toFIG. 4, illustrated is another exemplary downhole system400configured to seal a wellbore annulus, according to one or more embodiments. The downhole system400may be similar in several respects to the downhole systems100and300described above with reference thereto, and therefore may be best understood with reference toFIGS. 1-3, where like numerals indicate like components that will not be described again in detail. As illustrated, the system400includes the ramped collar302interposing the packer108and a third packer element402. Specifically, the first ramp304amay be arranged axially adjacent the third packer element402and configured to slidably engage the third packer element402as it is pushed axially in direction A by the square piston shoulder308a. The second ramp304bmay be arranged axially adjacent the first packer element108aand configured to slidably engage the first packer element108aas the ramped collar302translates axially in the direction A. The mandrel ramp136bof the lower shoe110bmay be arranged axially adjacent the second packer element108band configured to slidingly engage the second packer element108bas the packer108is being set.

Further axial movement of the piston120in direction A forces the third packer element402into engagement with the first biasing shoulder306a, the first packer element108ainto engagement with the second biasing shoulder306b, and the second packer element108binto engagement with the mandrel biasing shoulder134b. Upon engaging the respective shoulders306a,b,134b, and with continued axial force in direction A, the third, first, and second packer elements402,108a,bare compressed and extend radially to engage the inner wall of the casing104. As a result, the first, second, and third packer elements108a,b,402form first, second, and third seals404,406,408, respectively, at the location where each engages the inner wall of the casing104.

Moreover, as the first, second, and third seals404,406,408are generated, a first cavity410may be formed between the first and second packer elements108a,band extending axially across the spacer108c, and a second cavity412may be formed between the first and third packer elements108a,402and extending axially across a portion of the ramped collar302. The compressed packer elements108a,b,402trap fluid within the respectively formed cavities410,412and as the packer elements108a,b,402are further compressed axially, the fluid pressure in each cavity410,412increases to provide a hydraulic third seal414and a hydraulic fourth seal416, similar to the third seal210described above with reference toFIG. 2. It should be noted that the seals404,406,408,414, and416shown inFIG. 4are not depicted as compressed against the casing104as described above, but instead their general location is indicated.

Referring now toFIG. 5, illustrated is another exemplary downhole system500configured to seal a wellbore annulus, according to one or more embodiments. The downhole system500may be similar in several respects to the downhole systems100and300described above with reference toFIGS. 1-3, and therefore may be best understood with reference thereto, where like numerals indicate like components that will not be described again in detail. As illustrated, the system500includes a first packer502and a second packer504axially spaced from each other and disposed about the base pipe102. The first packer502may include a first packer element502aand a second packer element502b, having a spacer502cinterposing the first and second packer elements502a,b. The second packer504may include a third packer element504aand a fourth packer element504b, having a spacer504cinterposing the third and fourth packer elements504a,b.

The system500may further include the ramped collar302arranged between the first and second packers502,504. Specifically, the first ramp304amay be arranged axially adjacent and slidably engaging the second packer element502band the second ramp304bmay be arranged axially adjacent and slidably engaging the third packer element504a. Moreover, the first packer element502amay be arranged axially adjacent and slidably engaging the piston ramp136aand the fourth packer element504bmay be arranged axially adjacent and slidably engaging the mandrel ramp136b. As the piston120translates axially in the direction A, the first packer element502aeventually engages the piston biasing shoulder134a, which forces the second packer element502binto contact with the first biasing shoulder306aand thereby moves the ramped collar302. Axial movement of the ramped collar302in the direction A allows the third packer element504ato contact the second biasing shoulder306band the fourth packer element504bto contact the mandrel biasing shoulder134b.

Upon engaging the respective shoulders134a,b,306a,b, and with continued axial force in direction A, the first, second, third and fourth packer elements502a,b,504a,b, are compressed and extend radially to engage the inner wall of the casing104. As a result, the first, second, third and fourth packer elements502a,b,504a,bform first, second, third, and fourth seals506,508,510,512, respectively, at the location where each engages the inner wall of the casing104.

As the first, second, third, and fourth seals506,508,510,512are generated, a first cavity514may be formed between the first and second packer elements502a,band extending axially across the spacer502c, a second cavity516may be formed between the third and fourth packer elements504a,band extending axially across the spacer504c, and a third cavity518may be formed between the second and third packer elements502b,504and extending axially across a portion of the ramped collar302. Increased compression of the first, second, third, and fourth packer elements502a,b,504a,bincreases the fluid pressure within the first, second, and third cavities514,516,518, thereby forming fifth, sixth, and seventh seals520,522,524, respectively, each characterized as hydraulic seals similar to the third seal210described above with reference toFIG. 2. It should be noted that the seals506,508,510,512,520,522, and524shown inFIG. 5are not depicted as compressed against the casing104as described above, but instead their general location is indicated.

Referring now toFIG. 6, illustrated is another exemplary downhole system600configured to seal a wellbore annulus, according to one or more embodiments. The downhole system600may be similar in several respects to the downhole systems100and300described above with reference toFIGS. 1-3, and therefore may be best understood with reference thereto, where like numerals indicate like components that will not be described again in detail. As illustrated, the system600includes a first ramped collar602and a second ramped collar604slidably arranged about the base pipe102. The first and second ramped collars602,604may be similar to the ramped collar302described above with reference toFIG. 3. Specifically, the first ramped collar602may include a first ramp606aand an opposing second ramp606b, and a first biasing shoulder608aand an opposing second biasing shoulder608b. Moreover, the second ramped collar604may include a third ramp610aand an opposing fourth ramp610b, and a third biasing shoulder612aand an opposing fourth biasing shoulder612b.

A packer614having a first packer element614aand a second packer element614bmay interpose the first and second ramped collars602,604such that the first packer element614aslidably engages the second ramp606band the second packer element614bslidably engages the third ramp610a. As illustrated, the system600may further include a third packer element616and a fourth packer element618axially spaced from the packer614and arranged about the base pipe102. The third packer element616may be configured to slidably engage the first ramp606aand bias the square piston shoulder308a, and the fourth packer element618may be configured to slidably engage the fourth ramp610band bias the square mandrel shoulder308b.

As the piston120translates axially in the direction A, the square piston shoulder308aforces the third packer element616into engagement with the first biasing shoulder608a, which forces the first ramped collar602to likewise translate axially such that the first packer element614acomes into contact with the second biasing shoulder608b. Further axial movement of the first ramped collar602forces the packer614to translate axially until the second packer element614bengages the third biasing shoulder612a, which forces the second ramped collar604to translate axially such that the fourth packer element618comes into contact with the fourth biasing shoulder612bas it is biased on its opposite end by the immovable square mandrel shoulder308b. Upon engaging the respective shoulders308a,b,608a,b, and612a,b, and with continued axial force in direction A, the first, second, third, and fourth packer elements614a,b,616,618are compressed and extend radially to engage the inner wall of the casing104. As a result, the first, second, third, and fourth packer elements614a,b,616,618form first, second, third, and fourth seals620,622,624,626, respectively, at the location where each engages the inner wall of the casing104.

As the first, second, third, and fourth seals620,622,624,626are generated, a first cavity628may be formed between the first and second packer elements614a,band extend axially across the spacer614c, a second cavity630may be formed between the third and first packer elements616,614aand extend axially across a portion of the first ramped collar602, and a third cavity632may be formed between the second and fourth packer elements614b,618and extend axially across a portion of the second ramped collar604. Increased compression of the first, second, third, and fourth packer elements614a,b,616,618increases the fluid pressure within the first, second, and third cavities628,630,632, thereby forming fifth, sixth, and seventh seals634,636,638, respectively, each characterized as hydraulic seals similar to the third seal210described above with reference toFIG. 2. It should be noted that the seals620,622,624,626,634,636, and638shown inFIG. 6are not depicted as compressed against the casing104as described above, but instead their general location is indicated.

Referring now toFIG. 7, illustrated is another exemplary downhole system700configured to seal a wellbore annulus, according to one or more embodiments. The downhole system700may be similar in several respects to the downhole systems100and300described above with reference toFIGS. 1-3, and therefore may be best understood with reference thereto, where like numerals indicate like components that will not be described again in detail. As illustrated, the system700includes the ramped collar302interposing a first packer element702and a second packer element704such that the first ramp304aslidably engages the first packer element702and the second ramp304bslidably engages the second packer element704.

The system700may further include a shoulder ramp706interposing the second packer element704and a third packer element708. The shoulder ramp706may be axially offset from the ramp collar302and disposed about the base pipe102. Moreover, the shoulder ramp706may include a square shoulder710, an opposing biasing shoulder712, and a third ramp714, where the square shoulder710biases the second packer element704and the third ramp714slidably engages the third packer element708.

As the piston120translates axially in direction A, the square piston shoulder308aforces the first packer element702into engagement with the first biasing shoulder306a, which forces the ramped collar302to likewise translate axially such that the second packer element704comes into contact with the second biasing shoulder306b. Further axial movement of the ramped collar302, in conjunction with the immovable square mandrel shoulder308b, forces the shoulder ramp706to likewise translate axially until the third packer element708comes into contact with the biasing shoulder712of the shoulder ramp706. Upon engaging the respective shoulders308a,b,306a,b,710, and712, and with continued axial force in direction A, the first, second, and third packer elements702,704,708are compressed and extend radially to engage the inner wall of the casing104. As a result, the first, second, and third packer elements702,704,708form first, second, and third seals715,716,718, respectively, at the location where each engages the inner wall of the casing104.

As the first, second, and third seals715,716,718are generated, a first cavity720may be formed between the first and second packer elements702,704and extend axially across a portion of the ramped collar302, and a second cavity722may be formed between the second and third packer elements704,708and extend axially across a portion of the shoulder ramp706. Increased compression of the first, second, and third packer elements702,704,708increases the fluid pressure within the first and second cavities720,722, thereby forming fourth and fifth seals724,726, respectively, each characterized as hydraulic seals similar to the third seal210described above with reference toFIG. 2. It should be noted that the seals715,716,718,724, and726shown inFIG. 7are not depicted as compressed against the casing104as described above, but instead their general location is indicated.

Referring now toFIG. 8, illustrated is another exemplary downhole system800configured to seal a wellbore annulus, according to one or more embodiments. The downhole system800may be similar in several respects to the downhole systems100and300described above with reference toFIGS. 1-3, and therefore may be best understood with reference thereto, where like numerals indicate like components that will not be described again in detail. The downhole system800may be configured to compress the packer108and seal the annulus106using hydrostatic pressure. As illustrated, the system800may include a hydrostatic piston804housed within a hydrostatic chamber806. The hydrostatic chamber806may be at least partially defined by a retainer element808arranged about the base pipe102. One or more inlet ports810may be defined in the retainer element808and thereby provide fluid communication between the annulus106and the hydrostatic chamber806.

The piston804may include a stem portion804athat extends axially from the piston804and interposes the packer108and the base pipe102. The stem portion804amay be coupled to compression sleeve812having a sleeve ramp814and a sleeve shoulder816. The hydrostatic chamber806may contain fluid under hydrostatic pressure from the annulus106, and the hydrostatic piston804remains in fluid equilibrium until a pressure differential is experienced across the hydrostatic piston804, at which point the piston804translates axially in a direction B within the hydrostatic chamber806as it seeks pressure equilibrium once again.

As the hydrostatic piston804translates in direction B, the compression sleeve812coupled to the stem portion804ais forced toward the second packer element108band the second packer element108brides up the sleeve ramp814and biases the sleeve shoulder816. Likewise, the first packer element108amay ride up a retainer ramp818and bias a retainer shoulder820, each being defined on the retainer element808. As a result the packer is compressed radially and seals against the inner wall of the casing104.

The hydrostatic piston804may be actuated by introducing the wellbore device202(FIG. 2) into the base pipe102and moving the opening seat138in the direction A, as generally described above. Moving the opening seat138in direction A may trigger high pressure formation or wellbore fluids from the annulus106to enter the hydrostatic chamber806via the one or more inlet ports810defined in the retainer element808. As the hydrostatic piston804attempts to regain hydrostatic equilibrium, it will move axially in direction B, thereby compressing the packer108to form a first seal821within the annulus106where the first packer element108aseals against the inner wall of the casing104. Likewise, a second seal822may be formed in the annulus106where the second packer element108bseals against the inner wall of the casing104.

As the first and second seals821,822are generated, a cavity824may be formed between the compressed first and second packer elements108a,band extending axially across the spacer108c. Increased compression of the first and second packer elements108a,bincreases the fluid pressure within the cavity824, thereby forming a third seal826, characterized as a hydraulic seal similar to the third seal210described above with reference toFIG. 2. It should be noted that the seals821,822, and826shown inFIG. 8are not depicted as compressed against the casing104as described above, but instead their general location is indicated.

It will be appreciated that the various components of each system100,300-800may be mixed, duplicated, rearranged, combined with components of other systems100,300-800, or otherwise altered in various axial configurations in order to fit particular wellbore applications. Accordingly, the disclosed systems100,300-800and related methods may be used to remotely set one or more packers or packer elements. Setting the packer elements not only provides corresponding seals against the inner wall of the wellbore, but also creates hydraulic seals between adjacent packer elements. Because these hydraulic seals pressurize a trapped fluid, they exhibit an increased pressure threshold and therefore an enhanced ability to prevent the migration of fluids therethrough. Consequently, the annulus106is better sealed on either side of each hydraulic seal.

A method for sealing a wellbore annulus is also disclosed herein. In some embodiments, the method may include engaging an opening seat with a wellbore device. The opening seat may be movably arranged within a base pipe having inner and outer radial surfaces and defining an elongate orifice. The opening seat may further include a setting pin coupled thereto and extending radially through the elongate orifice. The method may also include applying a predetermined axial force on the opening seat with the wellbore device and thereby axially moving the opening seat and the setting pin in a first direction, and moving in the first direction a piston arranged on the outer radial surface. The piston may be coupled to the setting pin such that axial translation of the opening seat correspondingly moves the piston. The piston may also define or otherwise provide a piston biasing shoulder. The method may further include engaging and compressing a first packer element with the piston biasing shoulder and thereby forming a first seal within the wellbore annulus, and engaging and compressing a second packer element with a mandrel biasing shoulder and thereby forming a second seal within the wellbore annulus. The method may further include forming a hydraulic seal in a cavity defined between the first and second seals.

In some embodiments, applying the predetermined axial force on the opening seat may include applying fluid pressure against the wellbore device. In some embodiments, the method may further include shearing one or more shear pins that secure the piston against axial translation in the first direction. The method may also include slidingly engaging the first packer element with a piston ramp defined by the piston, and slidingly engaging the second packer element with a mandrel ramp. In one or more embodiments, the method also includes engaging and further compressing the first packer element with a first shoulder defined on a ramped collar arranged about the base pipe and interposing the first and second packer elements, and further engaging and further compressing the second packer element with a second shoulder defined on the ramped collar. Axial movement of the piston in the first direction forces the first and second packer elements into engagement with the first and second biasing shoulders, respectively.

In some aspects, a system for sealing a wellbore annulus defined between a base pipe and a casing is disclosed. The system may include a piston arranged on an outer radial surface of the base pipe, the piston having a piston ramp and a piston biasing shoulder, a lower shoe extending about the outer radial surface and having a mandrel ramp and a mandrel biasing shoulder, and a packer disposed about the base pipe and interposing the piston and the lower shoe, the packer having a first packer element adjacent the piston and a second packer element adjacent the lower shoe, wherein as the piston axially translates the first and second packer elements are compressed against the piston and mandrel biasing shoulders, respectively, and the first packer element forms a first seal against the casing in the annulus and the second packer element forms a second seal against the casing in the annulus, and wherein the first and second seals define a cavity therebetween that traps fluid within the cavity and thereby provides a hydraulic seal.

In some aspects a method for sealing a wellbore annulus defined between a base pipe and a casing is disclosed. The method may include axially translating a piston arranged on an outer radial surface of a base pipe, the piston having a piston biasing shoulder, engaging and compressing a first packer element with the piston biasing shoulder and thereby forming a first seal against the casing within the wellbore annulus, engaging and compressing a second packer element with a mandrel biasing shoulder and thereby forming a second seal against the casing within the wellbore annulus, and forming a hydraulic seal in a cavity defined between the first and second seals.

In some aspects, a system for sealing a wellbore annulus defined between a base pipe and a casing is disclosed. The system may include a piston arranged on an outer radial surface of the base pipe, the piston having a piston biasing shoulder, a lower shoe extending about the outer radial surface and having a mandrel biasing shoulder, a first ramped collar arranged about the base pipe and interposing the piston and the lower shoe, the first ramped collar having a first ramp and an opposing second ramp, and a first biasing shoulder and an opposing second biasing shoulder, a first packer element disposed about the base pipe and arranged between the piston and the first ramped collar, and a second packer element disposed about the base pipe and arranged between the lower shoe and the first ramped collar, wherein as the piston axially translates the first and second packer elements are compressed against the piston and mandrel biasing shoulders, respectively, and the first packer element forms a first seal against the casing in the annulus and the second packer element forms a second seal against the casing in the annulus, and wherein the first and second seals define a cavity therebetween that traps fluid within the cavity and thereby provides a hydraulic seal.

In some aspects, a system for sealing a wellbore annulus defined between a base pipe and a casing is disclosed. The system may include a retainer element arranged about a base pipe and defining a hydrostatic chamber that houses a hydrostatic piston having a stem portion that extends axially, the retainer element having a retainer ramp and a retainer shoulder, a compression sleeve arranged about the base pipe and coupled to the hydrostatic piston via the stem element, the compression sleeve having a sleeve ramp and a sleeve shoulder, and first and second packer elements arranged about the base pipe and interposing the retainer element and the compression sleeve, the first packer element being adjacent the retainer element and the second packer element being adjacent the compression sleeve, wherein as the hydrostatic piston axially translates, it pulls the compression sleeve into contact with the second packer element and the retainer element into contact with the first packer element, and wherein the first and second packer elements are compressed and form first and second seals against the casing, respectively, in the annulus and further define a cavity therebetween, the cavity being configured to trap fluid therein and provide a hydraulic seal.

In the following description of the representative embodiments of the invention, directional terms, such as “above,” “below,” “upper,” “lower,” etc., are used for convenience in referring to the accompanying drawings. In general, “above,” “upper,” “upward,” and similar terms refer to a direction toward the earth's surface along a wellbore, and “below,” “lower,” “downward” and similar terms refer to a direction away from the earth's surface along the wellbore.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended due to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. In addition, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.