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BACKGROUND 
       [0001]    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. 
         [0002]    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. 
         [0003]    Some well packers are designed to be set using complex electronics that often fail or may otherwise malfunction in the presence of corrosive and/or severe downhole environments. Other well packers require that the ambient conditions in the well be significantly altered in order to obtain adequate hydrostatic pressures to properly set the packer. While reliable in some applications, these and other methods of setting well packers add additional and unnecessary complexity and cost to the pack off process. Moreover, these conventional methods for setting the well packer are often only able to seal the annulus up to certain nominal pressures and thereafter are unable to prevent migration of fluids, such as gases, past the set well packer. 
       SUMMARY OF THE INVENTION 
       [0004]    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. 
         [0005]    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. 
         [0006]    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. 
         [0007]    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. 
         [0008]    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. 
         [0009]    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. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0010]    The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure. 
           [0011]      FIG. 1  illustrates a cross-sectional view of an exemplary downhole system, according to one or more embodiments disclosed. 
           [0012]      FIG. 2  illustrates a cross-sectional view of the downhole system of  FIG. 1  in an actuated configuration, according to one or more embodiments disclosed. 
           [0013]      FIG. 3  illustrates a cross-sectional view of another exemplary downhole system, according to one or more embodiments disclosed. 
           [0014]      FIG. 4  illustrates a cross-sectional view of another exemplary downhole system, according to one or more embodiments disclosed. 
           [0015]      FIG. 5  illustrates a cross-sectional view of another exemplary downhole system, according to one or more embodiments disclosed. 
           [0016]      FIG. 6  illustrates a cross-sectional view of another exemplary downhole system, according to one or more embodiments disclosed. 
           [0017]      FIG. 7  illustrates a cross-sectional view of another exemplary downhole system, according to one or more embodiments disclosed. 
           [0018]      FIG. 8  illustrates a cross-sectional view of another exemplary downhole system, according to one or more embodiments disclosed. 
       
    
    
     DETAILED DESCRIPTION 
       [0019]    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. 
         [0020]    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. 
         [0021]    Referring to  FIG. 1 , illustrated is a cross-sectional view of an exemplary downhole system  100  configured to seal a wellbore annulus, according to one or more embodiments. The system  100  may include a base pipe  102  extending within a casing  104  that has been cemented in a wellbore (not shown) drilled into the Earth&#39;s surface in order to penetrate various earth strata containing hydrocarbon formations. The system  100  is 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 annulus  106  may be defined between the casing  104  and the base pipe  102 . The casing  104  forms 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 casing  104  may be omitted and the annulus  106  may instead be defined between the inner wall of the wellbore itself and the base pipe  102 . 
         [0022]    The base pipe  102  may be coupled to or form part of production tubing. In some embodiments, the base pipe  102  may 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 pipe  102  may form a portion of a coiled tubing. The base pipe  102  may have a generally tubular shape, with an inner radial surface  102   a  and an outer radial surface  102   b  having 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 pipe  102  may include offset bores, sidepockets, etc. The base pipe  102  may 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 pipe  102  may be profiled or otherwise characterized as a mandrel-type device or structure. 
         [0023]    As illustrated, the system  100  may include at least one packer  108  disposed about the base pipe  102 . The packer  108  may be disposed about the base pipe  102  in a number of ways. For example, in some embodiments the packer  108  may directly or indirectly contact the outer radial surface  102   b  of the base pipe  102 . In other embodiments, however, the packer  108  may be arranged about or otherwise radially-offset from another component of the base pipe  102 . The packer  108  may include a first packer element  108   a  and a second packer element  108   b,  having a spacer  108   c  interposing the first and second packer elements  108   a,b.  As will be described in more detail below, the packer  108  may be configured to be compressed radially outward when subjected to axial compressive forces, thereby sealing the annulus in one or more locations. 
         [0024]    The system  100  may further include an upper shoe  110   a  and a lower shoe  110   b  coupled to and extending about the base pipe  102 . The upper and lower shoes  110   a,b  may be configured to axially bound the various components of the system  100  arranged about the outer surface  102   b  of the base pipe  102 . In one or more embodiments, the lower shoe  110   b  may form an integral part of the base pipe  102 , such that it serves as a mandrel-type device that helps compress the packer  108  during operation. In other embodiments, as illustrated, the lower shoe  110   b  may bias against a shoulder  112  defined on the base pipe  102 , such that the lower shoe  110   b  is substantially prevented from moving axially to the right, as indicated by arrow A. 
         [0025]    The system  100  may further include a shear ring  114 , a lock ring housing  116 , a guide sleeve  118 , and a piston  120 . The shear ring  114  may be arranged axially adjacent the upper shoe  110   a  and adapted to house one or more shear pins  122 . The shear pins  122  may extend partially into the base pipe  102  in order to maintain the components of the system  100  arranged about the outer radial surface  102   b  in their axial placement until properly actuated. In some embodiments, eight shear pins  122  are employed and spaced about the outer radial surface  102   b  of the base pipe  102 . As will be appreciated, however, more or less than eight shear pins  122  may be employed, without departing from the scope of the disclosure. 
         [0026]    The lock ring housing  116  may be arranged axially adjacent the shear ring  114  and may house a lock ring  124  therein. In some embodiments, the lock ring housing  116  may be threaded onto the shear ring  114  and therefore able to move axially therewith. The lock ring  124  may be coupled or otherwise secured to the lock ring housing  116  using one or more lock pins  126 . In other embodiments, however, the lock ring housing  116  may be threaded onto the lock ring  124 , without departing from the scope of the disclosure. 
         [0027]    In one or more embodiments, the lock ring  124  may define a plurality of ramped locking teeth  128 . In operation, the lock ring  124  may be configured to slidingly engage the outer surface  102   b  of the base pipe  102  as the system  100  moves axially in the direction A. As the lock ring  124  translates axially, the ramped locking teeth  128  may be configured to engage corresponding teeth or grooves (not shown) defined on the outer surface  102   b  of the base pipe  102 , thereby locking the lock ring  124  in its advanced axial position and generally preventing the system  100  from returning in the opposing axial direction. 
         [0028]    The guide sleeve  118  may be arranged axially adjacent the lock ring housing  116  and configured to interpose or otherwise connect the lock ring housing  116  to the piston  120 . In some embodiments, the guide sleeve  118  may be threaded onto both the lock ring housing  116  and the piston  120 . One or more sealing components  132  may be configured to seal the radial engagement between the piston  120  and the guide sleeve  118 . In some embodiments, the sealing components  132  may be o-rings. In other embodiments, the sealing components  132  may be other types of seals known to those skilled in the art. 
         [0029]    The piston  120  may include a piston biasing shoulder  134   a  and a piston ramp  136   a.  The piston ramp  136   a  may be arranged axially adjacent the first packer element  108   a  and configured to slidingly engage the first packer element  108   a  as the packer  108  is being set. Likewise, the lower shoe  110   b  may define a mandrel biasing shoulder  134   b  and a mandrel ramp  136   b  arranged axially adjacent the second packer element  108   b.  The mandrel ramp  136   b  may be configured to slidingly engage the second packer element  108   b  as the packer  108  is being set. 
         [0030]    The system  100  may further include an opening seat  138  axially movable and arranged within the base pipe  102 . The opening seat  138  may be disposed against the inner radial surface  102   a  of the base pipe  102  and secured in its axial position therein using one or more setting pins  140 . Although only one setting pin  140  is shown in  FIG. 1 , it will be appreciated that any number of setting pins  140  may be used without departing from the scope of the disclosure. In at least one embodiment, five setting pins  140  may be employed in order to secure the opening seat  138  in its axial position within the base pipe  102 . 
         [0031]    The setting pins  140  may be spaced circumferentially about the inner radial surface  102   a  of the base pipe  102 . The setting pins  140  may extend through an axially elongate orifice  144  defined in the base pipe  102  in order to structurally couple the opening seat  138  to the piston  120 . For example, the setting pins  140  may extend between corresponding holes  142  defined in the piston  120  and corresponding holes  130  defined in the opening seat  138 . In some embodiments, the setting pins  140  are threaded into the holes  142 ,  130 . In other embodiments, however, the setting pins  140  are attached to the piston  120  and/or the opening seat  138  by welding, brazing, adhesives, combinations thereof, or other attachment means. 
         [0032]    In response to an axial force applied to the opening seat  138  in the direction A, the setting pins  140  may be correspondingly forced to translate axially within the elongate orifice  144 , thereby also forcing the piston  120  to translate in the direction A. However, as a result of the connective combination of the piston  120 , the guide sleeve  118 , the lock ring,  116 , and the shear ring  114 , the setting pins  140  are prevented from axially translating while the one or more shear pins  122  are intact or otherwise engaged with the base pipe  102 . 
         [0033]    Referring now to  FIG. 2 , illustrated is the exemplary downhole system  100  in a compressed configuration or otherwise where the packer  108  has been properly set, according to one or more embodiments. In exemplary operation of the system  100 , a wellbore device  202  may be introduced into the well, within the base pipe  102 , and configured to engage and move the opening seat  138  in the direction A. In at least one embodiment, the wellbore device  202  is a plug, as known by those skilled in the art. In other embodiments, however, the wellbore device  202  may be another type of downhole device such as, but not limited to, a ball or a dart. In some embodiments, the wellbore device  202  may be configured to engage a profiled portion  203  defined on an upper end of the opening seat  138 . In other embodiments, however, the wellbore device  202  may be configured to engage any portion of the opening seat  138 , without departing from the scope of the disclosure. 
         [0034]    Once the wellbore device  202  engages the opening seat  138 , a predetermined axial force in the direction A may be applied to the upper end of the wellbore device  202  in order to convey a corresponding axial force to the opening seat  138  and the one or more setting pins  140  coupled thereto. In some embodiments, the predetermined axial force may be applied to the wellbore device  202  by increasing fluid pressure within the base pipe  102 . For instance, the wellbore device  202  may be adapted to sealingly engage the opening seat  138  or otherwise substantially seal against the inner radial surface  102   a  of the base pipe  102  such that a fluid pumped from the surface hydraulically forces the wellbore device  202  against the opening seat  138 . Increasing the fluid pressure within the base pipe  102  correspondingly increases the axial force applied by the wellbore device  202  on the opening seat  138 , and therefore increases the axial force applied to piston  120  via the setting pins  140 . Further increasing the fluid pressure within the base pipe  102  may serve to shear the shear pin(s)  122  and thereby allow the opening seat  138  and piston  120  to axially translate in the direction A. 
         [0035]    In one or more embodiments, the predetermined axial force required to shear the shear pins  122  and thereby move the opening seat  138  and setting pins  140  in 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 seat  138  in other ways, such as a mechanical force applied to the wellbore device  202  which transfers its force to the opening seat  138 . 
         [0036]    As the opening seat  138  translates axially in the direction A, and the setting pins  140  translate within the elongate orifice  144 , the piston  120  is correspondingly forced to translate axially and into increased contact and interaction with the packer  108 . In particular, the first packer element  108   a  may slidably engage and ride up the piston ramp  136   a  until coming into contact with the piston biasing shoulder  134   a.  Likewise, the second packer element  108   b  may slidably engage and ride up the mandrel ramp  136   b  until coming into contact with the mandrel biasing shoulder  134   b.  Upon engaging the respective biasing shoulders  134   a,b,  and with continued axial movement in direction A, the first and second packer elements  108   a,b  may be compressed and extend radially to engage the inner wall of the casing  104 . In one or more embodiments, the system  100  is prevented from reversing direction, and thereby decreasing the radial compression of the packer  108 , by the ramped locking teeth  128  that engage corresponding teeth or grooves (not shown) defined on the outer surface  102   b  of the base pipe  102 . It will be appreciated, however, that other means of securing the system  100  in its compressed configuration may be used, without departing from the scope of the disclosure. 
         [0037]    Accordingly, compressing the packer  108  between the piston  120  and the lower shoe  110   b  serves to effectively isolate or otherwise seal portions of the annulus  106  above and below the packer  108 . As illustrated, the packer  108  may be configured to form a first seal  204  within the annulus  106  where the first packer element  108   a  seals against the inner wall of the casing  104 . Likewise, a second seal  206  may be formed in the annulus  106  where the second packer element  108   b  seals against the inner wall of the casing  104 . In operation, the first and second seals  204 ,  206  may be configured to substantially prevent fluid migration between the upper and lower portions of the annulus  106 . 
         [0038]    As the first and second seals  204 ,  206  are generated, a cavity  208  may be formed between the compressed first and second packer elements  108   a,b  and extending axially across the spacer  108   c.  The first and second packer elements  108   a,b  trap fluid within the cavity  208  and as the elements  108   a,b  are further compressed axially, the elastomeric material of each element  108   a,b  may compress the cavity  208  and thereby increase the fluid pressure therein. Accordingly, a third seal  210  may be generated within the cavity  208  and characterized as a hydraulic seal. 
         [0039]    In at least one embodiment, a predetermined axial force of about 500 psi, as applied to the wellbore device  202  and correspondingly transferred to the piston  120  through the interconnection with the opening seat  138 , may result in a fluid pressure generated in the cavity  208  of about 10,000 psi or more. In other embodiments, pressures greater or less than 10,000 psi may be obtained within the cavity  208 , without departing from the scope of the disclosure. The increased pressures of the hydraulic third seal  210  may help the packer  108  prevent or otherwise entirely eliminate the migration of fluids (e.g., gases) through the packer  108 . 
         [0040]    Referring now to  FIG. 3 , illustrated is another exemplary downhole system  300  configured to seal a wellbore annulus, according to one or more embodiments. The downhole system  300  may be similar in several respects to the downhole system  100  described above with reference to  FIGS. 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 system  300  may include a ramped collar  302  slidably arranged about the base pipe  102  and interposing the first and second packer elements  108   a,b.  The ramped collar may include one or more sealing components  303  configured to seal the sliding engagement between the ramped collar  302  and the base pipe  102 . In some embodiments, the sealing components  303  may be o-rings. In other embodiments, however, the sealing components  303  may be other types of seals known to those skilled in the art. 
         [0041]    The ramped collar  302  may further include a first ramp  304   a  and an opposing second ramp  304   b,  and a first biasing shoulder  306   a  and an opposing second biasing shoulder  306   b.  The piston  120  may define or otherwise provide a square piston shoulder  308   a  juxtaposed against the first packer element  108   a.  Likewise, the lower shoe  110   b  may define or otherwise provide a square mandrel shoulder  308   b  juxtaposed against the second packer element  108   b.  Axial translation of the piston  120  in the direction A in  FIG. 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 piston  120  as discussed above with reference to  FIGS. 1 and 2 , and therefore will not be discussed again in detail. 
         [0042]    The first ramp  304   a  may be arranged axially adjacent the first packer element  108   a  and configured to slidably engage the first packer element  108   a  as the square piston shoulder  308   a  pushes the first packer element  108   a  axially in the direction A. Likewise, the second ramp  304   b  may be arranged axially adjacent the second packer element  108   b  and configured to slidably engage the second packer element  108   b  as the ramped collar  302  translates axially in the direction A and the square mandrel shoulder  308   b  prevents the second packer element  108   b  from moving in direction A. 
         [0043]    Further axial movement of the piston  120  in direction A forces the first and second packer elements  108   a,b  into engagement with the first and second biasing shoulders  306   a,b,  respectively. Upon engaging the respective biasing shoulders  306   a,b,  and with continued axial movement in direction A, the first and second packer elements  108   a,b  are compressed and extend radially to engage the inner wall of the casing  104 . As a result, the first packer element  108   a  may be configured to form a first seal  310  where the first packer element  108   a  engages the inner wall of the casing  104 , and the second packer element  108   b  may form a second seal  312  where the second packer element  108   b  engages the inner wall of the casing  104 . 
         [0044]    As the first and second seals  310 ,  312  are generated, a cavity  314  may be formed between the first and second packer elements  108   a,b  and extending axially across a portion of the ramped collar  302 . The first and second packer elements  108   a,b  trap fluid within the cavity  314  and as the elements  108   a,b  are further compressed axially, the elastomeric material of each element  108   a,b  may compress the cavity  314  and thereby increase the fluid pressure therein. Accordingly, a third seal  316  may be generated within the cavity  314  and characterized as a hydraulic seal, similar to the third seal  210  described above with reference to  FIG. 2 . It should be noted that the seals  310 ,  312 , and  316  shown in 
         [0045]      FIG. 3  are not depicted as compressed against the casing  104  as described above, but instead their general location is indicated. 
         [0046]    Referring now to  FIG. 4 , illustrated is another exemplary downhole system  400  configured to seal a wellbore annulus, according to one or more embodiments. The downhole system  400  may be similar in several respects to the downhole systems  100  and  300  described above with reference thereto, and therefore may be best understood with reference to  FIGS. 1-3 , where like numerals indicate like components that will not be described again in detail. As illustrated, the system  400  includes the ramped collar  302  interposing the packer  108  and a third packer element  402 . Specifically, the first ramp  304   a  may be arranged axially adjacent the third packer element  402  and configured to slidably engage the third packer element  402  as it is pushed axially in direction A by the square piston shoulder  308   a.  The second ramp  304   b  may be arranged axially adjacent the first packer element  108   a  and configured to slidably engage the first packer element  108   a  as the ramped collar  302  translates axially in the direction A. The mandrel ramp  136   b  of the lower shoe  110   b  may be arranged axially adjacent the second packer element  108   b  and configured to slidingly engage the second packer element  108   b  as the packer  108  is being set. 
         [0047]    Further axial movement of the piston  120  in direction A forces the third packer element  402  into engagement with the first biasing shoulder  306   a,  the first packer element  108   a  into engagement with the second biasing shoulder  306   b,  and the second packer element  108   b  into engagement with the mandrel biasing shoulder  134   b.  Upon engaging the respective shoulders  306   a,b,    134   b,  and with continued axial force in direction A, the third, first, and second packer elements  402 ,  108   a,b  are compressed and extend radially to engage the inner wall of the casing  104 . As a result, the first, second, and third packer elements  108   a,b,    402  form first, second, and third seals  404 ,  406 ,  408 , respectively, at the location where each engages the inner wall of the casing  104 . 
         [0048]    Moreover, as the first, second, and third seals  404 ,  406 ,  408  are generated, a first cavity  410  may be formed between the first and second packer elements  108   a,b  and extending axially across the spacer  108   c,  and a second cavity  412  may be formed between the first and third packer elements  108   a,    402  and extending axially across a portion of the ramped collar  302 . The compressed packer elements  108   a,b,    402  trap fluid within the respectively formed cavities  410 ,  412  and as the packer elements  108   a,b,    402  are further compressed axially, the fluid pressure in each cavity  410 ,  412  increases to provide a hydraulic third seal  414  and a hydraulic fourth seal  416 , similar to the third seal  210  described above with reference to  FIG. 2 . It should be noted that the seals  404 ,  406 ,  408 ,  414 , and  416  shown in  FIG. 4  are not depicted as compressed against the casing  104  as described above, but instead their general location is indicated. 
         [0049]    Referring now to  FIG. 5 , illustrated is another exemplary downhole system  500  configured to seal a wellbore annulus, according to one or more embodiments. The downhole system  500  may be similar in several respects to the downhole systems  100  and  300  described above with reference to  FIGS. 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 system  500  includes a first packer  502  and a second packer  504  axially spaced from each other and disposed about the base pipe  102 . The first packer  502  may include a first packer element  502   a  and a second packer element  502   b,  having a spacer  502   c  interposing the first and second packer elements  502   a,b.  The second packer  504  may include a third packer element  504   a  and a fourth packer element  504   b,  having a spacer  504   c  interposing the third and fourth packer elements  504   a,b.    
         [0050]    The system  500  may further include the ramped collar  302  arranged between the first and second packers  502 ,  504 . Specifically, the first ramp  304   a  may be arranged axially adjacent and slidably engaging the second packer element  502   b  and the second ramp  304   b  may be arranged axially adjacent and slidably engaging the third packer element  504   a.  Moreover, the first packer element  502   a  may be arranged axially adjacent and slidably engaging the piston ramp  136   a  and the fourth packer element  504   b  may be arranged axially adjacent and slidably engaging the mandrel ramp  136   b.  As the piston  120  translates axially in the direction A, the first packer element  502   a  eventually engages the piston biasing shoulder  134   a,  which forces the second packer element  502   b  into contact with the first biasing shoulder  306   a  and thereby moves the ramped collar  302 . Axial movement of the ramped collar  302  in the direction A allows the third packer element  504   a  to contact the second biasing shoulder  306   b  and the fourth packer element  504   b  to contact the mandrel biasing shoulder  134   b.    
         [0051]    Upon engaging the respective shoulders  134   a,b,    306   a,b,  and with continued axial force in direction A, the first, second, third and fourth packer elements  502   a,b,    504   a,b,  are compressed and extend radially to engage the inner wall of the casing  104 . As a result, the first, second, third and fourth packer elements  502   a,b,    504   a,b  form first, second, third, and fourth seals  506 ,  508 ,  510 ,  512 , respectively, at the location where each engages the inner wall of the casing  104 . 
         [0052]    As the first, second, third, and fourth seals  506 ,  508 ,  510 ,  512  are generated, a first cavity  514  may be formed between the first and second packer elements  502   a,b  and extending axially across the spacer  502   c,  a second cavity  516  may be formed between the third and fourth packer elements  504   a,b  and extending axially across the spacer  504   c,  and a third cavity  518  may be formed between the second and third packer elements  502   b,    504  and extending axially across a portion of the ramped collar  302 . Increased compression of the first, second, third, and fourth packer elements  502   a,b,    504   a,b  increases the fluid pressure within the first, second, and third cavities  514 ,  516 ,  518 , thereby forming fifth, sixth, and seventh seals  520 ,  522 ,  524 , respectively, each characterized as hydraulic seals similar to the third seal  210  described above with reference to  FIG. 2 . It should be noted that the seals  506 ,  508 ,  510 ,  512 ,  520 ,  522 , and  524  shown in  FIG. 5  are not depicted as compressed against the casing  104  as described above, but instead their general location is indicated. 
         [0053]    Referring now to  FIG. 6 , illustrated is another exemplary downhole system  600  configured to seal a wellbore annulus, according to one or more embodiments. The downhole system  600  may be similar in several respects to the downhole systems  100  and  300  described above with reference to  FIGS. 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 system  600  includes a first ramped collar  602  and a second ramped collar  604  slidably arranged about the base pipe  102 . The first and second ramped collars  602 ,  604  may be similar to the ramped collar  302  described above with reference to  FIG. 3 . Specifically, the first ramped collar  602  may include a first ramp  606   a  and an opposing second ramp  606   b,  and a first biasing shoulder  608   a  and an opposing second biasing shoulder  608   b.  Moreover, the second ramped collar  604  may include a third ramp  610   a  and an opposing fourth ramp  610   b,  and a third biasing shoulder  612   a  and an opposing fourth biasing shoulder  612   b.    
         [0054]    A packer  614  having a first packer element  614   a  and a second packer element  614   b  may interpose the first and second ramped collars  602 ,  604  such that the first packer element  614   a  slidably engages the second ramp  606   b  and the second packer element  614   b  slidably engages the third ramp  610   a.  As illustrated, the system  600  may further include a third packer element  616  and a fourth packer element  618  axially spaced from the packer  614  and arranged about the base pipe  102 . The third packer element  616  may be configured to slidably engage the first ramp  606   a  and bias the square piston shoulder  308   a,  and the fourth packer element  618  may be configured to slidably engage the fourth ramp  610   b  and bias the square mandrel shoulder  308   b.    
         [0055]    As the piston  120  translates axially in the direction A, the square piston shoulder  308   a  forces the third packer element  616  into engagement with the first biasing shoulder  608   a,  which forces the first ramped collar  602  to likewise translate axially such that the first packer element  614   a  comes into contact with the second biasing shoulder  608   b.  Further axial movement of the first ramped collar  602  forces the packer  614  to translate axially until the second packer element  614   b  engages the third biasing shoulder  612   a,  which forces the second ramped collar  604  to translate axially such that the fourth packer element  618  comes into contact with the fourth biasing shoulder  612   b  as it is biased on its opposite end by the immovable square mandrel shoulder  308   b.  Upon engaging the respective shoulders  308   a,b,    608   a,b,  and  612   a,b,  and with continued axial force in direction A, the first, second, third, and fourth packer elements  614   a,b,    616 ,  618  are compressed and extend radially to engage the inner wall of the casing  104 . As a result, the first, second, third, and fourth packer elements  614   a,b,    616 ,  618  form first, second, third, and fourth seals  620 ,  622 ,  624 ,  626 , respectively, at the location where each engages the inner wall of the casing  104 . 
         [0056]    As the first, second, third, and fourth seals  620 ,  622 ,  624 ,  626  are generated, a first cavity  628  may be formed between the first and second packer elements  614   a,b  and extend axially across the spacer  614   c,  a second cavity  630  may be formed between the third and first packer elements  616 ,  614   a  and extend axially across a portion of the first ramped collar  602 , and a third cavity  632  may be formed between the second and fourth packer elements  614   b,    618  and extend axially across a portion of the second ramped collar  604 . Increased compression of the first, second, third, and fourth packer elements  614   a,b,    616 ,  618  increases the fluid pressure within the first, second, and third cavities  628 ,  630 ,  632 , thereby forming fifth, sixth, and seventh seals  634 ,  636 ,  638 , respectively, each characterized as hydraulic seals similar to the third seal  210  described above with reference to  FIG. 2 . It should be noted that the seals  620 ,  622 ,  624 ,  626 ,  634 ,  636 , and  638  shown in  FIG. 6  are not depicted as compressed against the casing  104  as described above, but instead their general location is indicated. 
         [0057]    Referring now to  FIG. 7 , illustrated is another exemplary downhole system  700  configured to seal a wellbore annulus, according to one or more embodiments. The downhole system  700  may be similar in several respects to the downhole systems  100  and  300  described above with reference to  FIGS. 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 system  700  includes the ramped collar  302  interposing a first packer element  702  and a second packer element  704  such that the first ramp  304   a  slidably engages the first packer element  702  and the second ramp  304   b  slidably engages the second packer element  704 . 
         [0058]    The system  700  may further include a shoulder ramp  706  interposing the second packer element  704  and a third packer element  708 . The shoulder ramp  706  may be axially offset from the ramp collar  302  and disposed about the base pipe  102 . Moreover, the shoulder ramp  706  may include a square shoulder  710 , an opposing biasing shoulder  712 , and a third ramp  714 , where the square shoulder  710  biases the second packer element  704  and the third ramp  714  slidably engages the third packer element  708 . 
         [0059]    As the piston  120  translates axially in direction A, the square piston shoulder  308   a  forces the first packer element  702  into engagement with the first biasing shoulder  306   a,  which forces the ramped collar  302  to likewise translate axially such that the second packer element  704  comes into contact with the second biasing shoulder  306   b.  Further axial movement of the ramped collar  302 , in conjunction with the immovable square mandrel shoulder  308   b,  forces the shoulder ramp  706  to likewise translate axially until the third packer element  708  comes into contact with the biasing shoulder  712  of the shoulder ramp  706 . Upon engaging the respective shoulders  308   a,b,    306   a,b,    710 , and  712 , and with continued axial force in direction A, the first, second, and third packer elements  702 ,  704 ,  708  are compressed and extend radially to engage the inner wall of the casing  104 . As a result, the first, second, and third packer elements  702 ,  704 ,  708  form first, second, and third seals  715 ,  716 ,  718 , respectively, at the location where each engages the inner wall of the casing  104 . 
         [0060]    As the first, second, and third seals  715 ,  716 ,  718  are generated, a first cavity  720  may be formed between the first and second packer elements  702 ,  704  and extend axially across a portion of the ramped collar  302 , and a second cavity  722  may be formed between the second and third packer elements  704 ,  708  and extend axially across a portion of the shoulder ramp  706 . Increased compression of the first, second, and third packer elements  702 ,  704 ,  708  increases the fluid pressure within the first and second cavities  720 ,  722 , thereby forming fourth and fifth seals  724 ,  726 , respectively, each characterized as hydraulic seals similar to the third seal  210  described above with reference to  FIG. 2 . It should be noted that the seals  715 ,  716 ,  718 ,  724 , and  726  shown in  FIG. 7  are not depicted as compressed against the casing  104  as described above, but instead their general location is indicated. 
         [0061]    Referring now to  FIG. 8 , illustrated is another exemplary downhole system  800  configured to seal a wellbore annulus, according to one or more embodiments. The downhole system  800  may be similar in several respects to the downhole systems  100  and  300  described above with reference to  FIGS. 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 system  800  may be configured to compress the packer  108  and seal the annulus  106  using hydrostatic pressure. As illustrated, the system  800  may include a hydrostatic piston  804  housed within a hydrostatic chamber  806 . The hydrostatic chamber  806  may be at least partially defined by a retainer element  808  arranged about the base pipe  102 . One or more inlet ports  810  may be defined in the retainer element  808  and thereby provide fluid communication between the annulus  106  and the hydrostatic chamber  806 . 
         [0062]    The piston  804  may include a stem portion  804   a  that extends axially from the piston  804  and interposes the packer  108  and the base pipe  102 . The stem portion  804   a  may be coupled to compression sleeve  812  having a sleeve ramp  814  and a sleeve shoulder  816 . The hydrostatic chamber  806  may contain fluid under hydrostatic pressure from the annulus  106 , and the hydrostatic piston  804  remains in fluid equilibrium until a pressure differential is experienced across the hydrostatic piston  804 , at which point the piston  804  translates axially in a direction B within the hydrostatic chamber  806  as it seeks pressure equilibrium once again. 
         [0063]    As the hydrostatic piston  804  translates in direction B, the compression sleeve  812  coupled to the stem portion  804   a  is forced toward the second packer element  108   b  and the second packer element  108   b  rides up the sleeve ramp  814  and biases the sleeve shoulder  816 . Likewise, the first packer element  108   a  may ride up a retainer ramp  818  and bias a retainer shoulder  820 , each being defined on the retainer element  808 . As a result the packer is compressed radially and seals against the inner wall of the casing  104 . 
         [0064]    The hydrostatic piston  804  may be actuated by introducing the wellbore device  202  ( FIG. 2 ) into the base pipe  102  and moving the opening seat  138  in the direction A, as generally described above. Moving the opening seat  138  in direction A may trigger high pressure formation or wellbore fluids from the annulus  106  to enter the hydrostatic chamber  806  via the one or more inlet ports  810  defined in the retainer element  808 . As the hydrostatic piston  804  attempts to regain hydrostatic equilibrium, it will move axially in direction B, thereby compressing the packer  108  to form a first seal  821  within the annulus  106  where the first packer element  108   a  seals against the inner wall of the casing  104 . Likewise, a second seal  822  may be formed in the annulus  106  where the second packer element  108   b  seals against the inner wall of the casing  104 . 
         [0065]    As the first and second seals  821 ,  822  are generated, a cavity  824  may be formed between the compressed first and second packer elements  108   a,b  and extending axially across the spacer  108   c.  Increased compression of the first and second packer elements  108   a,b  increases the fluid pressure within the cavity  824 , thereby forming a third seal  826 , characterized as a hydraulic seal similar to the third seal  210  described above with reference to  FIG. 2 . It should be noted that the seals  821 ,  822 , and  826  shown in  FIG. 8  are not depicted as compressed against the casing  104  as described above, but instead their general location is indicated. 
         [0066]    It will be appreciated that the various components of each system  100 ,  300 - 800  may be mixed, duplicated, rearranged, combined with components of other systems  100 ,  300 - 800 , or otherwise altered in various axial configurations in order to fit particular wellbore applications. Accordingly, the disclosed systems  100 ,  300 - 800  and 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 annulus  106  is better sealed on either side of each hydraulic seal. 
         [0067]    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. 
         [0068]    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 embodiments, forming a hydraulic seal in the cavity further comprises pressurizing the cavity to a pressure of about 10,000 psi or more. 
         [0069]    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. 
         [0070]    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. 
         [0071]    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. 
         [0072]    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. 
         [0073]    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&#39;s surface along a wellbore, and “below,” “lower,” “downward” and similar terms refer to a direction away from the earth&#39;s surface along the wellbore. 
         [0074]    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.

Summary:
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.