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The present application is a U.S. National Stage patent application of International Patent Application No. PCT/US2012/045266, filed on Jul. 2, 2012, the benefit of which is claimed and the disclosure of which is incorporated herein by reference in its entirety. 
     TECHNICAL FIELD OF THE INVENTION 
     This invention relates, in general, to equipment utilized in conjunction with operations performed in subterranean wells and, in particular, to a packer assembly having sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies. 
     BACKGROUND OF THE INVENTION 
     Without limiting the scope of the present invention, its background will be described in relation to setting packers, as an example. 
     In the course of preparing a subterranean well for hydrocarbon production, one or more packers are commonly installed in the well. The purpose of the packers is to support production tubing and other completion equipment and to provides a seal in the well annulus between the outside of the production tubing and the inside of the well casing to isolate fluid and pressure thereacross. 
     Certain production packers are set hydraulically by establishing a differential pressure across a setting piston. Typically, this is accomplished by running a tubing plug on wireline, slick line, electric line, coiled tubing or another conveyance into the production tubing to a profile location. Fluid pressure within the production tubing may then be increased, thereby creating a pressure differential between the fluid within the production tubing and the fluid in the wellbore annulus. This pressure differential actuates the setting piston to expand the seal assembly of the production packer into sealing engagement with the casing. Thereafter, the tubing plug is retrieved to the surface such that production operations may begin. 
     As operators increasingly pursue production in deeper water offshore wells, highly deviated wells and extended reach wells, for example, the rig time required to set the tubing plug and thereafter retrieve the tubing plug can negatively impact the economics of the project, as well as add unnecessary complications and risks. To address these issues associated with hydraulically set packers, interventionless packer setting techniques have been developed. For example, a hydrostatically actuated setting module has been incorporated into the bottom end of a packer to exert an upward setting force on the packer piston. The hydrostatic setting module may be actuated by applying pressure to the production tubing and the wellbore at the surface, with the setting force being generated by a combination of the applied surface pressure and the hydrostatic pressure associated with the fluid column in the wellbore. 
     In operation, once the packer is positioned at the required setting depth, surface pressure is applied to the production tubing and the wellbore annulus until a port isolation device actuates, thereby allowing wellbore fluid to enter an initiation chamber on one side of the piston while the chamber engaging the other side of the piston remains at an evacuated pressure. This creates a differential pressure across the piston that causes the piston to move, beginning the setting process. Once the setting process begins, O-rings in the initiation chamber move off seat to open a larger flow area such that fluid entering the initiation chamber continues actuating the piston to complete the setting process. Therefore, the bottom-up hydrostatic setting module provides an interventionless method for setting packers as the setting force is provided by available hydrostatic pressure and applied surface pressure without plugs or other well intervention devices. 
     It has been found, however, that the bottom-up hydrostatic setting module may not be ideal for applications where the wellbore annulus and production tubing cannot be pressured up simultaneously. Such applications include, for example, when a packer is used to provide liner top isolation or when a packer is landed inside an adjacent packer in a stacked packer completion. In such circumstances, if a bottom-up hydrostatic setting module is used to set a packer above another sealing device, there is only a limited annular region between the unset packer and the previously set sealing device below. Therefore, when the operator pressures up on the wellbore annulus, the hydrostatic pressure begins actuating the bottom-up hydrostatic setting module to exert an upward setting force on the piston. When the packer sealing elements start to engage the casing, however, the limited annular region between the packer and the lower sealing device becomes closed off and can no longer communicate with the upper annular area that is being pressurized from the surface. Thus, the trapped pressure in the limited annular region between the packer and the lower sealing device is soon dissipated and may not fully set the packer. 
     Accordingly, a need has arisen for improved packer for providing a seal between a tubular string and a wellbore surface. In addition, a need has arisen for such an improved packer that does not require a plug to be tripped into and out of the well to enable setting. Further, a need has arisen for such an improved packer that is operable to be set without the application of both tubing pressure and annulus pressure. 
     SUMMARY OF THE INVENTION 
     The present invention disclosed herein comprises a packer assembly having sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies that is operable to provide a seal between a tubular string and a wellbore surface. The packer assembly of the present invention does not require a plug to be tripped into and out of the well to enable setting. In addition, the packer assembly of the present invention is operable to be set without the application of both tubing pressure and annulus pressure. 
     In one aspect, the present invention is directed to a packer assembly for use in a wellbore. The packer assembly includes a packer mandrel. A first piston is slidably disposed about the packer mandrel defining a first chamber therewith. An activation assembly is disposed about the packer mandrel initially preventing movement of the first piston. A first seal assembly is disposed about the packer mandrel and is operably associated with the first piston. A second piston is slidably disposed about the packer mandrel defining a second chamber therewith. A release assembly is disposed about the packer mandrel initially preventing movement of the second piston. A second seal assembly is disposed about the packer mandrel and is operably associated with the second piston such that actuation of the activation assembly allows a force generated by a pressure difference between the wellbore and the first chamber to shift the first piston in a first direction toward the first seal assembly to radially expand the first seal assembly and to actuate the release assembly and such that actuation of the release assembly allows a force generated by a pressure difference between the wellbore and the second chamber to shift the second piston in the first direction toward the second seal assembly to radially expand the second seal assembly. 
     In some embodiments, the activation assembly may include a housing section at least partially disposed about the packer mandrel that defines an activation chamber with the packer mandrel and the first piston. In these embodiments, a pressure actuated element may be positioned in a fluid flow path between the wellbore and the activation chamber initially preventing fluid flow therethrough until wellbore pressure exceeds a predetermined actuation pressure. Also, in these embodiments, a frangible member may initially couple the first piston to the housing section. In certain embodiments, the release assembly may include a release sleeve disposed about the packer mandrel that is operably associated with the first seal assembly. In these embodiments, a collet assembly may be disposed about the packer mandrel that initially prevents movement of the second piston. Also, in these embodiments, a frangible member may initially couple the release sleeve to the packer mandrel. In one embodiment, a first body lock ring disposed about the packer mandrel may be operable to prevent release of the first seal assembly after radial expansion of the first seal assembly. In other embodiments, at least one second body lock ring disposed about the packer mandrel may be operable to prevent release of the second seal assembly after radial expansion of the second seal assembly. 
     In another aspect, the present invention is directed to a method for setting a packer assembly in a wellbore. The method includes providing a packer assembly having a packer mandrel with first and second seal assemblies disposed thereabout; running the packer assembly into the wellbore; preventing movement of a first piston toward the first seal assembly with an activation assembly disposed about the packer mandrel; preventing movement of a second piston toward the second seal assembly with a release assembly disposed about the packer mandrel; actuating the activation assembly to allow a force generated by a pressure difference between the wellbore and a first chamber defined between the first piston and the packer mandrel to shift the first piston in a first direction toward the first seal assembly to radially expand the first seal assembly; and actuating the release assembly responsive to the shifting of the first piston to allow a force generated by a pressure difference between the wellbore and a second chamber defined between the second piston and the packer mandrel to shift the second piston in the first direction toward the second seal assembly to radially expand the second seal assembly. 
     The method may also include bursting a pressure actuated element responsive to an increase in wellbore pressure to a predetermined actuation pressure, pressurizing an activation chamber disposed between a housing section, the packer mandrel and the first piston, exposing a first piston area of the first piston to wellbore pressure, breaking a frangible member coupling the first piston to the housing section, breaking a frangible member coupling a release sleeve to the packer mandrel, radially inwardly compressing a collet assembly with the release sleeve and/or unlatching the second piston from the collet assembly. 
     In a further aspect, the present invention is directed to a packer assembly for use in a wellbore. The packer assembly includes a packer mandrel. A first piston is slidably disposed about the packer mandrel defining a first chamber therewith. An activation assembly is disposed about the packer mandrel initially preventing movement of the first piston. A seal assembly is disposed about the packer mandrel and is operably associated with the first piston. A second piston is slidably disposed about the packer mandrel defining a second chamber therewith. A release assembly is disposed about the packer mandrel initially preventing movement of the second piston such that actuation of the activation assembly allows a force generated by a pressure difference between the wellbore and the first chamber to shift the first piston in a first direction toward the seal assembly to radially expand the seal assembly and to actuate the release assembly and such that actuation of the release assembly allows a force generated by a pressure difference between the wellbore and the second chamber to shift the second piston in the first direction. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the features and advantages of the present invention, reference is now made to the detailed description of the invention along with the accompanying figures in which corresponding numerals in the different figures refer to corresponding parts and in which: 
         FIG. 1  is a schematic illustration of an offshore platform operating a plurality of packer assemblies having sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies in accordance with an embodiment of the present invention; 
         FIGS. 2A-2F  are cross-sectional views of consecutive axial sections of a packer assembly having sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies in accordance with an embodiment of the present invention in its running configuration; 
         FIGS. 3A-3F  are cross-sectional views of consecutive axial sections of a packer assembly having sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies in accordance with an embodiment of the present invention during the setting process; and 
         FIGS. 4A-4F  are cross-sectional views of consecutive axial sections of a packer assembly having sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies in accordance with an embodiment of the present invention in a set configuration. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     While the making and using of various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts, which can be embodied in a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention and do not delimit the scope of the present invention. 
     Referring initially to  FIG. 1 , a plurality of packer assemblies having sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies are being installed in an offshore oil or gas well that is schematically illustrated and generally designated  10 . A semi-submersible platform  12  is centered over a submerged oil and gas formation  14  located below sea floor  16 . A subsea conduit  18  extends from deck  20  of platform  12  to wellhead installation  22 , including blowout preventers  24 . Platform  12  has a hoisting apparatus  26  and a derrick  28  for raising and lowering pipe strings, such as work string  30 . 
     A wellbore  32  extends through the various earth strata including formation  14 . A casing  34  is secured within a vertical section of wellbore  32  by cement  36 . An upper end of a liner  38  is secured to the lower end of casing  34  by a suitable liner hanger. Note that, in this specification, the terms “liner” and “casing” are used interchangeably to describe tubular materials, which are used to form protective linings in wellbores. Liners and casings may be made from any material such as metals, plastics, composites, or the like, may be expanded or unexpanded as part of an installation procedure. Additionally, it is not necessary for a liner or casing to be cemented in a wellbore. 
     Work string  30  may include one or more packer assemblies  40 ,  42 ,  44 ,  46 ,  48  of the present invention that may be located proximal to the top of liner  38  or as part of the completion to provide zonal isolation. Packer assemblies  40 ,  42 ,  44 ,  46 ,  48  include sequentially operated hydrostatic pistons for interventionless setting of multiple seal assemblies. When set, packer assemblies  40 ,  42 ,  44 ,  46  isolate zones of the annulus between wellbore  32  and completion string, while packer assembly  48  provides a seal between tubular string  30  and casing  34 . In addition, the completion includes sand control screen assemblies  50 ,  52 ,  54  that are located substantially proximal to formation  14 . As shown, packer assemblies  40 ,  42 ,  44 ,  46  may be located above and below each set of sand control screen assemblies  50 ,  52 ,  54 . In this manner, formation fluids from formation  14  may enter sand control screen assemblies  50 ,  52 ,  54  between packer assemblies  40 ,  42 , between packer assemblies  42 ,  44  and between packer assemblies  44 ,  46 , respectively. 
     Even though  FIG. 1  depicts the packer assemblies of the present invention in a slanted wellbore, it should be understood by those skilled in the art that the present invention is equally well suited for use in wellbores having other directional configurations including vertical wellbore, horizontal wellbores, deviated wellbores, multilateral wells and the like. Accordingly, it should be understood by those skilled in the art that the use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well. Also, even though  FIG. 1  depicts an offshore operation, it should be understood by those skilled in the art that the packer assemblies of the present invention are equally well suited for use in onshore operations. 
     Referring now to  FIGS. 2A-2F , therein are depicted successive axial sections of a packer assembly having dual hydrostatic pistons for redundant interventionless setting that is representatively illustrated and generally designated  100 . Packer assembly  100  includes an upper adaptor  102  that may be threadably coupled to another downhole tool or tubular as part of a tubular string as described above. At its lower end, upper adaptor  102  is threadably coupled to an upper end of packer mandrel  104 . In the illustrated embodiment, packer mandrel  104  includes an upper packer mandrel section  106 , an upper intermediate mandrel section  108 , a lower intermediate mandrel section  110  and a lower mandrel section  112 , each of which is threadably coupled to the adjacent sections. Packer assembly  100  includes a lower adaptor  114  that is threadably coupled to a lower end of packer mandrel  104  and that may be threadably coupled to another downhole tool or tubular at its lower end to form part of a tubular string as described above. 
     Packer mandrel  104  includes a plurality of receiving profiles  116 ,  118 ,  120 ,  122 ,  124 ,  126 . Packer mandrel  104  also includes a plurality of sealing profiles  128 ,  130 ,  132 ,  134 , each of which includes multiple sealing elements such as O-rings or other packing elements. Positioned around an upper portion of packer mandrel  104  is an upper housing section  136 . Upper housing section  136  includes a connection ring  138 , an upper connector  140  and an upper activation assembly  142  that is threadably coupled to upper connector  140 . Upper activation assembly  142  includes a sealing profile  144  having multiple sealing elements to provide sealing engagement with packer mandrel  104 . Upper activation assembly  142  and packer mandrel  104  form an upper activation chamber  146  therebetween. Upper activation assembly  142  includes one or more radial fluid passageways  148  that are depicted as having pressure actuated elements such as rupture disks  150  disposed therein in  FIG. 2A . Upper activation assembly  142  also includes a pin groove  152  and a sealing profile  154  having multiple sealing elements. 
     Slidably disposed about packer mandrel  104  is an upper piston  156  that includes a plurality of threaded openings  158  and has a sealing profile  160  having multiple sealing elements. Upper piston  156  is initially coupled to upper activation assembly  142  by a plurality of frangible members depicted a shear screws  162 . In this configuration shown in  FIG. 2A , activation chamber  146  is defined between upper piston  156 , upper activation assembly  142  and packer mandrel  104 . At its lower end, upper piston  156  is threadably coupled to a body lock assembly  164  that includes a body lock ring  166  having teeth located along its inner surface for providing a gripping arrangement with packer mandrel  104 . A seal assembly  168 , depicted as expandable seal elements  170 ,  172 ,  174 , is slidably positioned around packer mandrel  104  between body lock assembly  164  and a release assembly  176 . In the illustrated embodiment, even though three expandable seal elements  170 ,  172 ,  174  are depicted and described, those skilled in the art will recognizes that a seal assembly of the packer of the present invention may have an alternate design including any number of seal elements. 
     Release assembly  176  includes a release sleeve  178  and a collet assembly  180 . Release sleeve  178  is initially coupled to packer mandrel  104  by a plurality of frangible members depicted shear screws  182 . Collet assembly  180  is supported between a pair of connection rings  184 ,  186 . Collet assembly  180  is initially coupled to an upper intermediate piston  188  that has a sealing profile  190  having multiple sealing elements. At its lower end, upper intermediate piston  188  is threadably coupled to a body lock assembly  192  that includes a body lock ring  194  having teeth located along its inner surface for providing a gripping arrangement with packer mandrel  104 . A seal assembly  196 , depicted as expandable seal elements  198 ,  200 ,  202 , is slidably positioned around packer mandrel  104  between body lock assembly  192  and a body lock assembly  204  that includes a body lock ring  206  having teeth located along its inner surface for providing a gripping arrangement with packer mandrel  104 . In the illustrated embodiment, even though three expandable seal elements  198 ,  200 ,  202  are depicted and described, those skilled in the art will recognizes that a seal assembly of the packer of the present invention may have an alternate design including any number of seal elements. 
     At its lower end, body lock ring  204  is threadably coupled to a lower intermediate piston  208  that has a sealing profile  210  having multiple sealing elements. Lower intermediate piston  208  is initially coupled to a release assembly  212 . Release assembly  212  includes a release sleeve  214  and a collet assembly  216 . Release sleeve  214  is initially coupled to packer mandrel  104  by a plurality of frangible members depicted shear screws  218 . Collet assembly  216  is supported between a pair of connection rings  220 ,  222 . A seal assembly  224 , depicted as expandable seal elements  226 ,  228 ,  230 , is slidably positioned around packer mandrel  104  between release assembly  214  and a body lock assembly  232  that includes a body lock ring  234  having teeth located along its inner surface for providing a gripping arrangement with packer mandrel  104 . In the illustrated embodiment, even though three expandable seal elements  226 ,  228 ,  230  are depicted and described, those skilled in the art will recognizes that a seal assembly of the packer of the present invention may have an alternate design including any number of seal elements. 
     At its lower end, body lock assembly  232  is threadably coupled to a lower piston  236  that has a sealing profile  238  having multiple sealing elements and a plurality of threaded openings  240 . Positioned around a lower portion of packer mandrel  104  is a lower housing section  242 . Lower housing section  242  includes a connection ring  244 , a lower connector  246  and a lower activation assembly  248  that is threadably coupled to lower connector  246 . Lower activation assembly  248  includes a sealing profile  250  having multiple sealing elements to provide sealing engagement with packer mandrel  104 . Lower activation assembly  248  and packer mandrel  104  form a lower activation chamber  252  therebetween. Lower activation assembly  248  includes one or more radial fluid passageways  254  that are depicted as having pressure actuated elements such as rupture disks  256  disposed therein in  FIG. 2E . Lower activation assembly  248  also includes a pin groove  258  and a sealing profile  260  having multiple sealing elements. Lower piston  236  is initially coupled to lower activation assembly  248  by a plurality of frangible members depicted shear screws  262 . In this configuration shown in  FIG. 2F , lower activation chamber  252  is defined between lower piston  236 , lower activation assembly  248  and packer mandrel  104 . 
     As best seen in  FIG. 2B , an atmospheric chamber  264  is disposed between upper piston  156  and packer mandrel  104  and more particularly between sealing profile  160  of upper piston  156  and sealing profile  128  of packer mandrel  104 . As best seen in  FIG. 2C , an atmospheric chamber  266  is disposed between upper intermediate piston  188  and packer mandrel  104  and more particularly between sealing profile  190  of upper intermediate piston  188  and sealing profile  130  of packer mandrel  104 . As best seen in  FIG. 2D , an atmospheric chamber  268  is disposed between lower intermediate piston  208  and packer mandrel  104  and more particularly between sealing profile  210  of lower intermediate piston  208  and sealing profile  132  of packer mandrel  104 . As best seen in  FIG. 2E , an atmospheric chamber  270  is disposed between lower piston  236  and packer mandrel  104  and more particularly between sealing profile  238  of lower piston  236  and sealing profile  134  of packer mandrel  104 . Preferably, atmospheric chambers  264 ,  266 ,  268 ,  270  are initially evacuated by pulling a vacuum. 
     Referring collectively to  FIGS. 2A-2F, 3A-3F and 4A-4F , the operation of packer assembly  100  will now be described. Packer assembly  100  is shown before, during and after activation and expansion of seal assemblies  168 ,  196 ,  224 , respectively, in  FIGS. 2A-2F, 3A-3F and 4A-4F . Packer assembly  100  may be run into a wellbore on a work string or similar tubular string to a desired depth and then set against a casing string, a liner string or other wellbore surface including an open hole surface. It is noted that during run in, movement of upper piston  156  is initially prevented as upper piston  156  is initially coupled to upper activation assembly  142  by shear screws  162  and due to the presence of rupture disks  150  in fluid passageways  148  of upper activation assembly  142  which prevent fluid pressure from entering upper activation chamber  146 . Movement of upper intermediate piston  188  is initially prevented by release assembly  176  as release sleeve  178  is initially coupled to packer mandrel  104  by shear screws  182  and collet assembly  180  is initially coupled to upper intermediate piston  188 . Movement of lower intermediate piston  208  is initially prevented by release assembly  212  as release sleeve  214  is initially coupled to packer mandrel  104  by shear screws  218  and collet assembly  216  is initially coupled to lower intermediate piston  208 . Movement of lower piston  236  is initially prevented as lower piston  236  is initially coupled to lower activation assembly  248  by shear screws  262  and due to the presence of rupture disks  256  in fluid passageways  254  of lower activation assembly  248  which prevent fluid pressure from entering lower activation chamber  252 . 
     Setting a accomplished by increasing the wellbore or annulus pressure surrounding packer assembly  100  to an actuation pressure sufficient to substantially simultaneously or sequentially burst rupture disks  150 ,  256 . For example, when the actuation pressure of rupture disks  256  is reached and rupture disks  256  burst, fluid pressure from the wellbore enters activation chamber  252  via fluid passageway  254 . The force generated by the fluid pressure acting on a lower surface of lower piston  236  breaks the shear screws  262  allowing lower piston  236  to move upwardly against any opposing force generated by pressure within atmospheric chamber  270 , which is preferably negligible. Lower piston  236  moves together with body lock assembly  232  to apply a compressive force against seal assembly  224 . When the compressive force reaches a predetermined level, shear screws  218  break allowing release sleeve  214  to shift upwardly relative to packer mandrel  104 . The upwardly moving release sleeve  214  contacts collet assembly  216  causing radial retraction of the collet fingers of collet assembly  216 , decoupling collet assembly  216  from lower intermediate piston  208 , as best seen in  FIG. 3D . 
     Preferably, at the same time, when the actuation pressure of rupture disks  150  is reached and rupture disks  150  burst, fluid pressure from the wellbore enters activation chamber  146  via fluid passageway  148 . The force generated by the fluid pressure acting on an upper surface of upper piston  156  breaks the shear screws  162  allowing upper piston  156  to move downwardly against any opposing force generated by pressure within atmospheric chamber  264 , which is preferably negligible. Upper piston  156  moves together with body lock assembly  164  to apply a compressive force against seal assembly  168 . When the compressive force reaches a predetermined level, shear screws  182  break allowing release sleeve  178  to shift downwardly relative to packer mandrel  104 . The downwardly moving release sleeve  178  contacts collet assembly  180  causing radial retraction of the collet fingers of collet assembly  180 , decoupling collet assembly  180  from upper intermediate piston  188 , as best seen in  FIG. 3C . 
     Thereafter, the hydrostatic pressure in the wellbore acts on lower piston  236 , lower intermediate piston  208 , upper piston  156  and upper intermediate piston  188 . Specifically, the hydrostatic pressure continues to act on a lower surface of lower piston  236  to upwardly shift lower piston  236  relative to packer mandrel  104 . This upward movement shifts body lock assembly  232 , seal assembly  224  and release sleeve  214  until further upward movement of release sleeve  214  is limited by connection ring  222 . A compressive force is then applied to seal assembly  224  between body lock assembly  232  and release sleeve  214  which causes radial expansion of seal elements  226 ,  228 ,  230 , as best seen in  FIG. 4E . The hydrostatic pressure also continues to act on an upper surface of upper piston  156  to downwardly shift upper piston  156  relative to packer mandrel  104 . This downward movement shifts body lock assembly  164 , seal assembly  168  and release sleeve  178  until further downward movement of release sleeve  178  is limited by connection ring  184 . A compressive force is then applied to seal assembly  168  between body lock assembly  164  and release sleeve  178  which causes radial expansion of seal elements  170 ,  172 ,  174 , as best seen in  FIG. 4B . 
     In addition, the hydrostatic pressure now acts on a lower surface of lower intermediate piston  208  operating against any opposing force generated by pressure within atmospheric chamber  268 , which is preferably negligible. This upward movement of lower intermediate piston  208  shifts body lock assembly  204 . At the same time, the hydrostatic pressure acts on an upper surface of upper intermediate piston  188  operating against any opposing force generated by pressure within atmospheric chamber  266 , which is preferably negligible. This downward movement of upper intermediate piston  188  shifts body lock assembly  192 . The simultaneous upward movement of body lock assembly  204  and downward movement of body lock assembly  192  applies a compressive force against seal assembly  196  which causes radial expansion of seal elements  198 ,  200 ,  202 , as best seen in  FIG. 4C . 
     In this manner, actuation of activation assembly  248  causes the sequential operation of lower piston  236  and lower intermediate piston  208  to set seal assemblies  224 ,  196 . Likewise, actuation of activation assembly  142  causes the sequential operation of upper piston  156  and upper intermediate piston  188  to set seal assemblies  168 ,  196 . Even though packer assembly  100  has been described as sequentially operating two pistons responsive to actuation of an activation assembly, it should be understood by those skilled in the art that any number of pistons could alternatively be operated in a sequential manner, for example, using multiple release assembly stages, without departing from the principle of the present invention. Once set, the sealing and gripping relationship between seal assembly  224  and the wellbore setting surface is maintained by body lock ring  234 , which prevents loss of compression on seal assembly  224 . Likewise, the sealing and gripping relationship between seal assembly  168  and the wellbore setting surface is maintained by body lock ring  166  which prevents loss of compression on seal assembly  168 . Similarly, the sealing and gripping relationship between seal assembly  196  and the wellbore setting surface is maintained by body lock rings  194 ,  206  which prevent loss of compression on seal assembly  224 . In this configuration, wellbore pressure above packer assembly  100  tends to further compress seal assembly  168  due to the downward force applied on upper piston  156 . Likewise, wellbore pressure below packer assembly  100  tends to further compress seal assembly  224  due to the upward force applied on lower piston  236 . Further, if a leak were to develop relative to seal assembly  168 , wellbore pressure above packer assembly  100  would tend to further compress seal assembly  196  due to the downward force applied on upper intermediate piston  188 . Likewise, if a leak were to develop relative to seal assembly  224 , wellbore pressure below packer assembly  100  would tend to further compress seal assembly  196  due to the upward force applied on lower intermediate piston  208 . 
     While this invention has been described with reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the invention will be apparent to persons skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.

Summary:
A packer for use in a wellbore includes a packer mandrel. First and second pistons are slidably disposed about the packer mandrel defining first and second chambers therewith. An activation assembly initially prevents movement of the first piston. A release assembly initially prevents movement of the second piston. First and second seal assemblies are disposed about the packer mandrel such that actuation of the activation assembly allows a force generated by a pressure difference between the wellbore and the first chamber to shift the first piston in a first direction toward the first seal assembly to radially expand the first seal assembly and to actuate the release assembly and, actuation of the release assembly allows a force generated by a pressure difference between the wellbore and the second chamber to shift the second piston in the first direction toward the second seal assembly to radially expand the second seal assembly.