Abstract:
A packer ( 80 ) for establishing sealing engagement with a surface disposed in a wellbore includes a packer mandrel ( 90 ) and a seal assembly ( 100, 102, 104 ) slidably disposed about the packer mandrel ( 90 ). The seal assembly ( 100, 102, 104 ) has a running position and a radially expanded sealing position. A piston ( 122 ) is slidably disposed about the packer mandrel ( 90 ) and operably associated with the seal assembly ( 100, 102, 104 ). A collet assembly  145  is disposed about the packer mandrel ( 90 ) and is releasably coupled to the piston ( 122 ) such that radially inwardly shifting at least portion of the collet assembly ( 145 ) decouples the collet assembly ( 145 ) from the piston ( 122 ) allowing the piston ( 122 ) to shift longitudinally relative to the packer mandrel ( 90 ) which operates the seal assembly ( 100, 102, 104 ) from the running position to the radially expanded sealing position, thereby setting the packer ( 80 ).

Description:
TECHNICAL FIELD OF THE INVENTION 
     This invention relates, in general, to packer setting mechanisms used in a wellbore that traverses a subterranean hydrocarbon bearing formation and, in particular, to an interventionless set packer and method for setting same. 
     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 treating and preparing a subterranean well for production, well packers are commonly run into the well on a conveyance such as a work string or production tubing. The purpose of the packer is to support production tubing and other completion equipment, such as sand control assemblies adjacent to a producing formation, and to seal the annulus between the outside of the production tubing and the inside of the well casing to block movement of fluids through the annulus past the packer location. 
     Production packers and other types of downhole tools may be run down on production tubing to a desired depth in the wellbore before they are set. Certain conventional production packers are set hydraulically, requiring that a pressure differential be created across a setting piston. Typically, this is accomplished by running a tubing plug on wireline, slick line, electric line, coiled tubing or another conveyance means through the production tubing down into the downhole tool. Then the fluid pressure within the production tubing is increased, thereby creating a pressure differential between the fluid within the production tubing and the fluid within the wellbore annulus. This pressure differential actuates the setting piston to expand the production packer into sealing engagement with the production liner or casing. Before resuming normal operations through the production tubing, the tubing plug must be removed, typically by retrieving the plug back to the surface of the well. 
     As operators increasingly pursue production completions in deeper water offshore wells, highly deviated wells and extended reach wells, the rig time required to set a tubing plug and thereafter retrieve the plug can negatively impact the economics of the project, as well as add unacceptable complications and risks. To address the issues associated with hydraulically-set downhole tools, an interventionless setting technique was developed. In particular, a hydrostatically-actuated setting module was designed to be incorporated into the bottom end of a downhole tool, and this module exerts an upward setting force on the downhole tool. 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 particular, a piston of the hydrostatic setting module is exposed on one side to a vacuum evacuated initiation chamber that is initially closed off to wellbore annulus fluid by a port isolation device, and the piston is exposed on the other side to an enclosed evacuated chamber generated by pulling a vacuum. 
     In operation, once the downhole tool is positioned at the required setting depth, surface pressure is applied to the production tubing and the wellbore annulus until the port isolation device actuates, thereby allowing wellbore fluid to enter the initiation chamber on the one side of the piston while the chamber engaging the other side of the piston remains at the 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, and the 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 downhole tools since the setting force is provided by available hydrostatic pressure and applied surface pressure without plugs or other well intervention devices. 
     However, 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. The production tubing can not be pressured up in either of these applications because the tubing extends as one continuous conduit out to the pay zone where no pressure, or limited pressure, can be applied. 
     In such circumstances, if a bottom-up hydrostatic setting module is used to set a packer above another sealing device, such as a liner hanger or another packer, for example, there is only a limited annular area between the unset packer and the 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 packer. However, when the packer sealing elements start to engage the casing, the limited annular area 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 area between the packer and the lower sealing device is soon dissipated and may or may not fully set the packer. 
     Therefore, a need has arisen for an interventionless operable to fully set a downhole tool, such as a packer, within a wellbore that is not dependent upon surface pressure being applied to the wellbore annulus to set the packer. 
     SUMMARY OF THE INVENTION 
     The present invention disclosed herein comprises an interventionless set packer that does not require the use of surface pressure being applied to the wellbore annulus for setting. 
     In one aspect, the present invention is directed to a packer for establishing a sealing engagement with a surface disposed in a wellbore. The packer includes a packer mandrel and a seal assembly that is slidably disposed about the packer mandrel. The seal assembly has a running position and a radially expanded sealing position. A piston is slidably disposed about the packer mandrel and is operably associated with the seal assembly. A collet assembly is disposed about the packer mandrel and is releasably coupled to the piston such that radially inwardly shifting at least portion of the collet assembly decouples the collet assembly from the piston allowing the piston to shift longitudinally relative to the packer mandrel which operates the seal assembly from the running position to the radially expanded sealing position, thereby setting the packer. 
     In one embodiment of the packer, the piston and packer mandrel define a chamber that is at a pressure lower than the pressure of the wellbore such as atmospheric pressure, a vacuum or the like. In another embodiment, the collet assembly includes a plurality of collet fingers. In this embodiment, the collet fingers may include radially outwardly extending protrusions that extend radially outwardly beyond an outer diameter of the piston. Also in this embodiment, the piston may include a detent formed in its inner surface for releasably engaging a tab of each of the collet fingers. 
     In another aspect, the present invention is directed to a packer for establishing a sealing and gripping engagement with a surface disposed in a wellbore. The packer includes a packer mandrel and a seal assembly that is slidably disposed about the packer mandrel. The seal assembly has a running position and a radially expanded sealing position. A slip assembly is slidably disposed about the packer mandrel. The slip assembly has a running position and a radially expanded gripping position A piston is slidably disposed about the packer mandrel and is operably associated with the seal assembly and the slip assembly. A collet assembly is disposed about the packer mandrel and is releasably coupled to the piston such that radially inwardly shifting at least portion of the collet assembly decouples the collet assembly from the piston allowing the piston to shift longitudinally relative to the packer mandrel which operates the seal assembly from the running position to the radially expanded sealing position and operates the slip assembly from the running position to the radially expanded gripping position, thereby setting the packer. 
     In one embodiment, a pair of wedges radially outwardly directs the slip assembly when the piston shifts longitudinally relative to the packer mandrel. In another embodiment, a pair of backup shoes is slidably disposed about the packer mandrel and is operably associated with the seal assembly. The backup shoes have a running position and a sealing position, wherein when the piston shifts longitudinally relative to the packer mandrel, the backup shoes are operated from the running position to the sealing position. 
     In a further aspect, the present invention is directed to a packer for establishing a sealing engagement with a surface disposed in a wellbore. The packer includes a packer mandrel and a seal assembly that is slidably disposed about the packer mandrel. The seal assembly has a running position and a radially expanded sealing position. A piston is slidably disposed about the packer mandrel and defines a chamber therewith. The chamber is at a pressure lower than a pressure in the wellbore. The piston is operably associated with the seal assembly. A collet assembly is disposed about the packer mandrel and is releasably coupled to the piston such that radially inwardly shifting at least portion of the collet assembly decouples the collet assembly from the piston allowing the pressure in the wellbore to shift the piston longitudinally relative to the packer mandrel which operates the seal assembly from the running position to the radially expanded sealing position, thereby setting the packer. 
     In yet another aspect, the present invention is directed to a method for setting a packer to establish a sealing engagement with a surface located in a wellbore. The method includes providing a profile disposed within the wellbore that is located relative to the surface, lowering the packer into the wellbore, engaging a collet assembly of the packer with the profile of the wellbore and responsive to the engaging, radially outwardly extending a seal assembly of the packer into sealing engagement with the surface. 
     The method may also include longitudinally sliding a piston relative to a packer mandrel, disengaging the collet assembly from the piston, engaging protrusions on collet fingers of the collet assembly with the profile of the wellbore and radially inwardly shifting at least a portion of the collet assembly with the profile of the wellbore. 
     In an additional aspect, the present invention is directed to a method for setting a packer to establish a sealing and gripping engagement with a surface located in a wellbore. The method involves providing a profile disposed within the wellbore that is located relative to the surface, lowering the packer into the wellbore, engaging a collet assembly of the packer with the profile of the wellbore and responsive to the engaging, radially outwardly extending a seal assembly of the packer into sealing engagement with the surface and radially outwardly extending a slip assembly of the packer into gripping engagement with the surface. 
    
    
     
       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 an interventionless set packer in accordance with the present invention; 
         FIGS. 2A-2C  are quarter-sectional views of an interventionless set packer in accordance with the present invention in its running configuration; 
         FIGS. 3A-3C  are quarter-sectional views of an interventionless set packer in accordance with the present invention in its set configuration; 
         FIG. 4  is a side view of a collet finger of an interventionless set packer in accordance with the present invention; 
         FIG. 5  is a side view of a collet finger having a larger protrusion and tab of an interventionless set packer in accordance with the present invention; 
         FIG. 6  is a side view of another collet finger having a smaller protrusion and tab of an interventionless set packer in accordance with the present invention; and 
         FIG. 7  is a quarter-sectional view of a collet assembly of an interventionless set packer in accordance with the present invention. 
     
    
    
     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. 
     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. 
     Referring initially to  FIG. 1 , several interventionless set packers in a completion string deployed in an offshore oil or gas well are schematically illustrated and generally designated  10 . A semi-submersible platform  12  is centered over 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 substantially tubular, longitudinally extending inner work string  30 . 
     Importantly, even though  FIG. 1  depicts a slanted well, it should be understood by one skilled in the art that the interventionless set packers of the present invention are equally well-suited for use in vertical wells, horizontal wells, multilateral wells and the like. Also, even though  FIG. 1  depicts an offshore operation, it should be understood by one skilled in the art that the interventionless set packers of the present invention are equally well-suited for use in onshore operations. 
     Continuing with  FIG. 1 , a wellbore  32  extends through the various earth strata including formation  14 . A casing  34  is cemented within a vertical section of wellbore  32  by cement  36 . An upper end of a liner  56  is secured to the lower end of casing  34  by any means commonly known, such as expandable liner hangers, and the like. 
     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, and may be segmented or continuous. Additionally, it is not necessary for a liner or casing to be cemented in a wellbore. Any type of liner or casing may be used in keeping with the principles of the present invention. 
     Liner  56  may include one or more packers  44 ,  46 ,  48 ,  50 ,  60  that may be located proximal to the top of liner  56  or at lower portion of liner  56  that provide zonal isolation to the production of hydrocarbons to certain zones of liner  56 . Packers  44 ,  46 ,  48 ,  50 ,  60  include and are actuated by the interventionless set packer setting mechanism of the present invention. When set, packers  44 ,  46 ,  48 ,  50 ,  60  isolate zones of the annulus between wellbore  32  and liner  56 . In this manner, formation fluids from formation  14  may enter the annulus between wellbore  32  and casing  34  in between packers  44 ,  46 , between packers  46 ,  48 , and between packers  48 ,  50 . 
     In addition, liner  56  includes sand control screen assemblies  38 ,  40 ,  42  that are located near the lower end of liner  56  and substantially proximal to formation  14 . As shown, packers  44 ,  46 ,  48 ,  50  may be located above and below each set of sand control screen assemblies  38 ,  40 ,  42 . 
     Referring now to  FIGS. 2A-2C  and  3 A- 3 C, detailed quarter-sectional views of successive axial portions of interventionless set packer  80  having an interventionless set packer setting mechanism are representatively illustrated. A lower mandrel  82  of liner  56  is coupled to packer  80  at an upper threaded connection  86 , and additional sections of liner  56  may be coupled at a lower threaded connection  162  when the overall assembly is conveyed into wellbore  32 . Mandrel  82  includes an inner central passageway  84  that extends through mandrel  82  and packer  80 . 
     A wedge  88  is disposed about a packer mandrel  90  and mandrel  82  and is coupled to mandrel  82  at upper threaded connection  86 . Wedge  88  has a camming outer surface that will engage an inner surface of a slip assembly  92 . As should be apparent to those skilled in the art, wedge  88  may have a variety of configurations including configurations having other numbers of wedge sections, such configurations being considered within the scope of the present invention. 
     Slip assembly  92  is located between wedge  88  and a wedge  94 . In one embodiment, slip assembly  92  may have teeth  93  located along its outer surface for providing a gripping arrangement with the interior of the well casing. As explained in greater detail below, when a compressive force is generated between wedge  88 , slip assembly  92 , and wedge  94 , slip assembly  92  is radially expanded into contact with the well casing. 
     Initially, relative movement between wedge  94  and slip assembly  92  is opposed by shear screw  96  attached to packer mandrel  90 . As discussed further below, shearing of shear screw  96  enables wedge  94  to move relative to slip assembly  92 . 
     Substantially adjacent to wedge  94  is an upper element backup shoe  98  that is slidably positioned around packer mandrel  90 . Additionally, a seal assembly, depicted as expandable seal elements  100 ,  102 ,  104 , is slidably positioned around packer mandrel  90  between upper element backup shoe  98  and a lower element backup shoe  106 . In the illustrated embodiment, three expandable seal elements  100 ,  102 ,  104  are shown; however, a seal assembly of the packer of the present invention may include any number of expandable seal elements. 
     Upper element backup shoe  98  and lower element backup shoe  106  may be made from a deformable or malleable material, such as mild steel, soft steel, brass, and the like and may be thin cut at their distal ends. The ends of upper element backup shoe  98  and lower element backup shoe  106  will deform and flare outwardly toward the inner surface of the casing or formation during the setting sequence as further described below. In one embodiment, upper element backup shoe  98  and lower element backup shoe  106  form a metal-to-metal barrier between packer  80  and the inner surface of the casing. 
     Another wedge  110  is disposed about packer mandrel  90 . Wedge  110  has a camming outer surface that will engage an inner surface of a slip assembly  112 . As should be apparent to those skilled in the art, wedge  110  may have a variety of configurations including configurations having other numbers of wedge sections, such configurations being considered within the scope of the present invention. 
     Initially, relative movement between wedge  110  and lower element backup shoe  106  is opposed by shear screw  108  attached packer mandrel  90 . As discussed further below, shearing of shear screw  108  enables wedge  110  to move lower element backup shoe  106  in an upwardly direction. 
     Slip assembly  112  is located between wedge  110  and a wedge  116 . In one embodiment, slip assembly  112  may have teeth  113  located along its outer surface for providing a gripping arrangement with the interior of the well casing. As explained in greater detail below, when a compressive force is generated between wedge  110 , slip assembly  112 , and wedge  116 , slip assembly  112  is radially expanded into contact with the well casing. 
     Initially, relative movement between wedge  116  and slip assembly  112  is opposed by shear screw  114  attached to packer mandrel  90 . As discussed further below, shearing of shear screw  114  enables wedge  116  to move relative to wedge  110 . 
     Packer mandrel  90 , wedge  116 , and a piston  122  form a cavity  118  for a hydraulically-actuated, top-down contingency access located internally of packer mandrel  90 . The inner surface of packer mandrel  90  may be configured to receive a punch-to-set tool (not shown) operable to punch a hole through the wall of the packer mandrel  90  in the vicinity of cavity  118  in the event additional or contingency pressure is required to operate packer mandrel  90 . The term “punch-to-set tool” may identify any device operable to perforate the packer mandrel  90 , including but not limited to chemical, mechanical and pyrotechnic perforating devices. The punch-to-set tool also acts as a tubing plug within the packer mandrel  90  as will be more fully described below. In another embodiment, the packer mandrel  90  includes a pre-punched port through the mandrel wall in the vicinity of cavity  118 , but this embodiment provides somewhat less control over the possible inadvertent setting expandable seal elements  100 ,  102 ,  104 . 
     A piston  122  is slidably disposed about packer mandrel  90  and coupled to wedge  116  through a threaded connection  120 . Piston  122  extends between wedge  116  and a collet assembly including one or more collet fingers  144 . One or more seals  124 ,  128  and centralizer ring  126  are located between packer mandrel  90  and the upper portion of piston  122  to provide a sealing relationship between packer mandrel  90  and piston  122 . Additionally, one or more seals  134 ,  138  and centralizer ring  136  are located between packer mandrel  90  and the lower portion of piston  122  to provide a sealing relationship between packer mandrel  90  and piston  122 . Centralizer rings  126 ,  136  are operable to properly position piston  122  about the packer mandrel  90  and form a uniformly shaped atmospheric chamber  130 . 
     Seals  124 ,  128 ,  134 ,  138  may consist of any suitable sealing element or elements, such as a single O-ring, a plurality of O-rings, as illustrated, and/or a combination of backup rings, O-rings, and the like. In various embodiments, Seals  124 ,  128 ,  134 ,  138  and/or centralizer rings  126 ,  136  comprise AFLAS® O-rings with PEEK back-ups for severe downhole environments, Viton O-rings for low temperature service, Nitrile or Hydrogenated Nitrile O-rings for high pressure and temperature service, or a combination thereof. 
     Atmospheric chamber  130  comprises an elongate cavity formed between packer mandrel  90  and piston  122 , and it is initially evacuated by pulling a vacuum. The vacuum in atmospheric chamber  130  acts against hydrostatic piston  122 . Seals  124 ,  128 ,  134 ,  138  are provided between packer mandrel  90  and piston  122  to seal off atmospheric chamber  130 . 
     In addition, piston  122 , packer mandrel  90 , and collet fingers  144  define a chamber  140  that facilitates the operation between collet fingers  144  and piston  122 . A detent  142  is formed on the inner surface of piston  122  near the lower end of cavity chamber  140  for releasably accepting a tab  164  of collet fingers  144 , as best seen in  FIGS. 4 and 7 . Collet fingers  144  are designed to engage with a protrusion or profile, such as the top of liner  56  or a protrusion or profile formed in an inner surface of liner  56 , casing, or wellbore  32 , for example. Packer  80  may further include a series of seals  150 ,  152 ,  154 ,  156 ,  158 ,  160  for providing additional sealing engagement between packer  80  and liner  56 , casing, or wellbore  32 . 
     Referring now to  FIG. 4 , detent  142  can be seen formed in the inner surface or wall of piston  122 . This figure illustrates a collet finger  144  having a protrusion  166  being engaged with a liner top  146  of liner  56  or other protrusion or profile, such as a casing or wellbore  32 . Although one collet finger  144  is shown with respect to  FIG. 4 , packer  80  may include numerous collet fingers  144 , as best seen in  FIGS. 2   b ,  3   b , and  7 . Collet finger  144  includes a protrusion  166  for engaging a surface of a liner top  146 , casing, or wellbore  32 . Protrusion  166  may be generally located anywhere on collet finger  144  such that it forces tab  164  inwardly as collet finger  144  contacts liner top  146 . 
     Detent  142  may be formed in the inner surface or wall of piston  122  such that it provides a unique profile or shape for engaging a particular tab  164  of collet finger  144 . Detent  142  has a depth that provides releasable engagement with tab  164  of collet finger  144  such that when protrusion  166  engages liner top  146 , collet finger  144  will move inwardly toward packer mandrel  90  thereby moving or collapsing tab  164  inwardly and disengaging with detent  142 , thus enabling piston  122  to slide upward as described further below, and as best seen in  FIGS. 3A-3B . 
     Referring now to  FIG. 5 , a collet finger  170  is shown having a larger profile protrusion  172  for engaging liner top  146 , casing or wellbore  32 . The profile of protrusion  172  facilitates engagement of liner top  146 , casing, or wellbore  32  that may be located a greater distance away from collet finger  170 . In addition, tab  182  is larger than that shown in  FIG. 4  to enable engagement with a deeper detent  142 . 
     Referring to  FIG. 6 , a collet finger  176  is shown having a smaller profile protrusion  178  for engaging liner top  146 , casing, or wellbore  32 . The profile of protrusion  178  facilitates engagement of liner top  146 , casing, or wellbore  32  that may be located a smaller distance away from collect finger  176 . In addition, tab  184  may also be similarly smaller than that shown in  FIG. 4  to enable engagement with a shallower detent  142 . 
     Referring back to  FIG. 1 , packers  44 ,  46 ,  48 ,  50  are shown located below liner top  146  of liner  56  for engaging with a tab, profile, or protrusion located proximal to their respective locations downhole in wellbore  32 . In this manner, one or more packers  44 ,  46 ,  48 ,  50 ,  60  may be set concurrently as inner work string  30  is lowered into position downhole. In one embodiment, collet fingers  144 ,  170 ,  176  may have different profiles of protrusion  166 ,  172 ,  178  such that the collet fingers  144  of the lowest position packer, such as those relating to packer  50  do not engage liner top  146 , casing, or wellbore  32  until it is near its engagement position downhole. Although, five packers  44 ,  46 ,  48 ,  50 ,  60  are shown, any number of packers may be used. For example, packer  50  may have collet fingers with a particular protrusion and tab size or profile, such as collet finger  176 , while packer  60  may have collet fingers, such as collet finger  170  with a larger protrusion and tab size or profile. 
     Referring to  FIG. 7 , collet assembly  145  of a packer  60  is depicted having fewer collet fingers  144  than that shown in  FIGS. 2B and 3B . Any of packers  44 ,  46 ,  48 ,  50 ,  60  may have the same or a different number of collet fingers  144 . As described above, any number of collet fingers  144  may be used on packer  80 . In addition, collet fingers  144  may be oriented or spaced radially apart so as to form a selective pattern for engaging a similarly shaped pattern or profile of the liner top  146 , casing, or wellbore  32 . In this embodiment, selective activation of one or more packers  80 , such as packers  44 ,  46 ,  48 ,  50 ,  60 , may be performed simultaneously as they each engage selectively with liner top  146 , casing, or wellbore  32 . The lower positioned packer  80  may slide through protrusions of liner top  146 , casing, or wellbore  32  that are located above the final position of the packer  80 . 
     Referring collectively to  FIGS. 2A-2C  and  3 A- 3 C the operation of packer  80  will now be described. Packer  80  is shown before and after activation and expansion of expandable seal elements  100 ,  102 ,  104 , and slip assemblies  92  and  112 , respectively in  FIGS. 2A-2C  and  3 A- 3 C. 
     Surface profiles may be manufactured or created in wellbore  32 , casing  34 , liner  56 , liner top  146 , or other downhole surfaces that are sized to activate a particular packer  80 . These surface profiles are positioned or created at locations desirable to set packer  80  prior to running packer  80  into wellbore  32 . These surface profiles are slightly different than their surrounding surface profiles to enable specific engagement with protrusions  166 ,  172 ,  178 . 
     In one instance, a surface profile may exist between liner top  146  and casing  34  as best seen in  FIG. 1 . The inner diameter of liner top  146  may be less than the diameter of casing  34  because it is located within casing  34 . The liner top  146  of liner  56  then may be used to activate packer  80 . 
     In operation, packer  80  of  FIGS. 2A-2C  may be run into wellbore  32  on inner work string  30  to a desired depth, for example, and then packer  80  may be set against casing  34 , liner  56 , or against wellbore  32 . In one embodiment, packer  80  may be used as a liner top isolation packer, such as packer  60  as best seen in  FIG. 1 . In particular, once liner  56  has been deployed and suspended from casing  34 , packer  80  may be run into wellbore  32  on production tubing or inner work string  30  using regular completion techniques. 
     As packer  80  approaches liner top  146  of liner  56 , collet fingers  144  engage liner top  146  that causes them to contract inwardly towards packer mandrel  90 , as best seen in  FIG. 3B . This contraction causes tab  164  to disengage with detent  142  of piston  122 . Once all of tabs  164  of packer  80  are disengaged with their respective detents  142 , piston  122  moves upward due to the low pressure or vacuum in atmospheric chamber  130 . 
     Once the shear force between piston  122  and packer mandrel  90  exceeds a predetermined amount, shear screw  114  shears allowing the upward force of piston  122  to act upon wedge  116  to move wedge  116  upward towards slip assembly  112 . As wedge  116  contacts slip assembly  112 , slip assembly  112  moves upwardly over wedge  110 , which starts to set slip assembly  112  against the inner surface of a setting surface, such as casing  34 . 
     As slip assembly  112  is extending outwardly toward the inner surface of casing  34 , it further moves upward causing an upward force on wedge  110 . Once the shear force between slip assembly  112 , wedge  110  and packer mandrel  90  exceeds a predetermined amount, shear screw  108  shears allowing wedge  110  to force lower element backup shoe  106  to begin to move upward relative to packer mandrel  90 . As piston  122 , wedge  116 , slip assembly  112 , wedge  110 , and lower element backup shoe  106  begin to move upward, expandable seal elements  100 ,  102 ,  104  begin to move upward and also to extend outwardly toward casing  34 . 
     The upward movement of expandable seal elements  100 ,  102 ,  104  forces upper element backup shoe  98  and lower element backup shoe  106  to flare outward toward casing  34  to provide a metal-to-metal seal in addition to the seal of expandable seal elements  100 ,  102 ,  104  between casing  34  and packer mandrel  90 , as best seen in  FIGS. 3A-3C . 
     Upon the upward and sealingly movement of lower element backup shoe  106 , expandable seal elements  100 ,  102 ,  104 , and upper element backup shoe  98 , an upward force is transmitted to wedge  94 . Once the shear force between wedge  94  and packer mandrel  90  exceeds a predetermined amount, shear screw  96  shears allowing the upward force of wedge  94  to act upon slip assembly  92 . As wedge  94  contacts slip assembly  92 , slip assembly  92  moves upwardly over wedge  88  and wedge  94 , which moves slip assembly  92  outwardly against the inner surface of casing  34 . As shown in  FIG. 1 , any number of packers  80  may be simultaneously or sequentially run and deployed, such as packers  44 ,  46 ,  48 ,  50 ,  60 . 
     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.