Patent Publication Number: US-7717183-B2

Title: Top-down hydrostatic actuating module for downhole tools

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   None. 
   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not applicable. 
   REFERENCE TO A MICROFICHE APPENDIX 
   Not applicable. 
   FIELD OF THE INVENTION 
   The present invention relates to interventionless, hydrostatically-actuated, top-down actuating and/or setting modules for downhole tools and methods of actuating and/or setting downhole tools within well bores. More particularly, the present invention relates to interventionless actuating and/or setting modules for downhole tools that provide no potential leak pathway between the production tubing and the well bore annulus, and methods of hydrostatically actuating and/or setting downhole tools without diminishing the hydrostatic actuating force. 
   BACKGROUND 
   A variety of downhole tools may be used within a well bore in connection with producing hydrocarbons. A production packer, for example, is one such downhole tool comprising resilient sealing elements and slips that expand outwardly in response to an applied force to engage the inside of a production liner or casing. In this way, the production packer provides a seal between the outside of a tubing upon which the packer is run into the well bore and the inside of a production liner or casing. The production packer performs a number of functions, including but not limited to: isolating one pressure zone of a well bore formation from another, protecting the production liner or casing from reservoir pressure and erosion that may be caused by produced fluids, eliminating or reducing pressure surging or heading, and holding kill fluids in the well bore annulus above the production packer. 
   Production packers and other types of downhole tools may be run down on production tubing to a desired depth in the well bore before they are set. Conventional production packers are then 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 well bore 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 well bore 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 well bore. 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 well bore 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 well bore annulus until the port isolation device actuates, thereby allowing well bore 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 well bore 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 well bore 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. Accordingly, a need exists for an interventionless hydrostatic setting apparatus operable to fully set a downhole tool within a well bore in response to surface pressure applied to the well bore annulus only. In an embodiment, this interventionless hydrostatic setting module should provide no potential for fluid leaks between the production tubing and the well bore annulus above the set downhole tool. 
   With respect to a hydraulically set packer, the operational life of the packer can be adversely affected when the setting force on the piston is dissipated such that the piston no longer exerts a setting force on the packer slips, wedges and resilient sealing elements after the downhole tool is set and the plug is removed from the production tubing. Under such circumstances, as the packer is mechanically and/or thermally loaded during its operational life, the resilient sealing elements expand and contract, but the slips and wedges are not urged to move in response to the loading. This expansion and contraction can cause the resilient sealing elements to become spongy and leak over time. Therefore, a need exists for an interventionless hydrostatic setting apparatus that substantially continually exerts a setting force to fully set the packer or other downhole tool throughout the operational life of the packer without diminishing the actuating force. 
   SUMMARY OF THE INVENTION 
   The present disclosure is directed to an interventionless, hydrostatic, top-down actuating apparatus for a downhole tool within a well bore. In an embodiment, a downhole tool comprises the actuating apparatus. In an embodiment, the actuating apparatus comprises no fluid communication pathway between a fluid flow bore extending through the actuating apparatus and the well bore surrounding the actuating apparatus. The present disclosure is also directed to an apparatus for actuating a downhole tool within a well bore comprising a mandrel having a solid wall surrounding a fluid flow bore extending longitudinally therethrough, the solid wall preventing fluid communication between the fluid flow bore and the well bore. 
   In another aspect, the present disclosure is directed to an apparatus for actuating a downhole tool within a well bore comprising an interventionless, hydrostatic, top-down actuating module connected above the downhole tool and having a fluid flow bore extending longitudinally therethrough surrounded by a wall that presents no potential fluid leak path between the fluid flow bore and the well bore above the downhole tool. The apparatus may further comprise a hydraulic, bottom-up contingency actuating module connected below the downhole tool and having a throughbore extending longitudinally therethrough in fluid communication with the fluid flow bore. In an embodiment, a solid wall surrounds the throughbore in the bottom-up contingency actuating module, thereby presenting no potential leak path between the throughbore and the well bore below the downhole tool, and a port is selectively generated through the solid wall to actuate the bottom-up contingency actuating module. 
   The present disclosure is further directed to an apparatus for actuating a downhole tool within a well bore comprising a cylindrical mandrel extending longitudinally through the downhole tool; an interventionless, hydrostatic, top-down actuating piston disposed about the mandrel and forming a first chamber and a second chamber therebetween; and a rupture disk that prevents fluid communication between the well bore and the first chamber until sufficient hydrostatic pressure is applied to the well bore to fail the rupture disk. The apparatus may further comprise an upper locking mechanism for locking the downhole tool in an actuated position after the top-down actuating piston is hydrostatically actuated to actuate the downhole tool into the actuated position. In an embodiment, the apparatus further comprises an anti-rotation clutch forming a connection between the top-down actuating piston and the upper locking mechanism when the top-down actuating piston is hydrostatically actuated to actuate the downhole tool. The apparatus may further comprise a hydraulic, bottom-up contingency actuating piston disposed about the mandrel. In an embodiment, the mandrel comprises an internal profile to receive a plug for hydraulically-actuating the bottom-up contingency actuating piston. The apparatus may further comprise a port generated through a wall of the mandrel to hydraulically-actuate the bottom-up contingency actuating piston. In an embodiment, the apparatus further comprises a lower locking mechanism for locking the downhole tool in an actuated position after the bottom-up contingency actuating piston is hydraulically actuated to actuate the downhole tool into the actuated position. 
   In yet another aspect, the present disclosure is directed to a packer comprising a cylindrical mandrel with a fluid flow bore extending longitudinally therethrough; an interventionless, hydrostatic, top-down setting apparatus disposed about the mandrel; and a plurality of packer sealing elements disposed about the mandrel below the top-down setting apparatus; wherein the packer provides no fluid communication pathway between the fluid flow bore and a well bore surrounding the packer above the packer sealing elements. 
   In still another aspect, the present disclosure is directed to a method of actuating a downhole tool to seal against a wall of a well bore comprising running the downhole tool to a desired depth within the well bore above a seal within the well bore, exerting a hydrostatic actuating force to actuate the downhole tool, and setting the downhole tool to seal against the wall of the well bore without diminishing the hydrostatic actuating force. 
   In an embodiment, a method of actuating a downhole tool within a well bore comprises connecting a top-down actuating module to the downhole tool, running the downhole tool to a desired depth within the well bore, pressuring up the well bore without pressuring up an internal flow bore extending through the top-down actuating module, hydrostatically actuating an upper piston of the top-down actuating module to exert an actuation force onto the downhole tool, and actuating the downhole tool into an actuated position. The method may further comprise maintaining the actuation force on the downhole tool after actuating the downhole tool. Hydrostatically actuating the upper piston may comprise opening a pathway into a first chamber of the top-down actuating module, filling the first chamber with a fluid from the well bore, exerting an actuating force on the piston due to the pressure differential between the first chamber and a second chamber. In an embodiment, opening the pathway comprises failing a rupture disk. The method may further comprise locking the downhole tool in the actuated position. The method may also comprise preventing the upper piston from rotating upon actuating the downhole tool. In an embodiment, the method further comprises connecting a hydraulic, bottom-up contingency actuating module to the downhole tool before running the downhole tool to the desired depth within the well bore. If the upper piston fails to exert an actuation force onto the downhole tool, the method may further comprise inserting a plug into a throughbore of the bottom-up contingency actuating module, pressuring up the throughbore, hydraulically actuating a lower piston of the bottom-up contingency actuating module to exert an actuation force onto the downhole tool, and actuating the downhole tool into an actuated position. In an embodiment, the method further comprises generating a port through a wall surrounding the throughbore to hydraulically actuate the lower piston. In various embodiments, the method further comprises landing the downhole tool within a tie-back component of a liner hanger at the desired depth within the well bore, or landing the downhole tool into another downhole tool at the desired depth within the well bore. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  provides a schematic side view, partially in cross-section, of a representative operating environment for a packer system employed within a well bore as a liner top isolation packer; 
       FIGS. 2A through 2D , when viewed sequentially from end-to-end, provide a cross-sectional side view of one embodiment of a packer system comprising an interventionless, hydrostatically-actuated, top-down actuating or setting module connected to a packer assembly, which in turn is connected to a hydraulically actuated, bottom-up contingency setting module; 
       FIG. 3  provides an enlarged cross-sectional end view, taken along Section  3 - 3  of  FIG. 2B , of one embodiment of an anti-rotation clutch; and 
       FIGS. 4A through 4C , when viewed sequentially from end-to-end, provide a cross-sectional side view of another embodiment of a packer system comprising an interventionless, hydrostatically-actuated, top-down actuating or setting module connected to a packer assembly. 
   

   NOTATION AND NOMENCLATURE 
   Certain terms are used throughout the following description and claims to refer to particular structural components. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. 
   Reference to up or down will be made for purposes of description with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the well and with “down”, “lower”, “downwardly” or “downstream” meaning toward the bottom end of the well, regardless of the well bore orientation. 
   As used herein, the terms “bottom-up” and “top-down” will be used as adjectives to identify the direction of a force that actuates a downhole tool, with “bottom-up” generally referring to a force that is exerted from the bottom of the tool upwardly toward the surface of the well, and with “top-down” generally referring to a force that is exerted from the top of the tool downwardly toward the bottom end of the well, regardless of the well bore orientation. 
   As used herein, the terms “hydraulic” and “hydraulically-actuated” will be used to identify conventional actuating or setting modules that are actuated by plugging a fluid flow bore therein and then applying pressure above the plug. 
   As used herein, the terms “hydrostatic” and “hydrostatically-actuated” will be used to identify actuating or setting modules that are actuated by applying pressure to the well bore without plugging a fluid flow bore therein, as distinguished from “hydraulic” and “hydraulically-actuated” conventional actuating modules. 
   As used herein, the term “rupture disk” will be used broadly to identify any type of actuatable device operable to selectively open a port, including but not limited to a rupture disk, a shifting sleeve, and a shear plug device, for example. 
   DETAILED DESCRIPTION 
   The present disclosure relates to interventionless actuating modules for downhole tools. In this context, the term “interventionless” is well understood by those of ordinary skill in the art. In an embodiment, the interventionless actuating module is operable to actuate a downhole tool without running another component into the well bore to contact or otherwise interact with the actuating module. In an embodiment, the interventionless actuating module is operable to actuate a downhole tool without making a separate trip into the well bore to initiate the actuation. In this regard, the interventionless actuating module does not require intervention means such as a tubing plug run into the well on a wireline, coiled tubing, electric line, slick line, or another conveyance means. 
     FIG. 1  schematically depicts one representative operating environment for a packer system  200 ,  600  that will be more fully described herein. In  FIG. 1 , the packer system  200 ,  600  is employed to provide liner top isolation in a production environment. A well bore  20  is shown penetrating a subterranean formation F for the purpose of recovering hydrocarbons. At least the upper portion of the well bore  20  may be lined with casing  25  that is cemented  27  into position against the formation F in a conventional manner. A liner hanger  60  sealingly engages the casing  25  to suspend a perforated production liner  40  within a lower well bore portion  30  adjacent a producing pay zone A of the formation F with perforations  32  extending therein. A tie-back connector or polished bore receptacle (PBR)  50  is disposed above the liner hanger  60  at the upper end of the perforated production liner  40  to receive the packer system  200 ,  600 . In particular, once the liner hanger  60  has been deployed to suspend the perforated production liner  40 , the packer system  200 ,  600  may be run into the well bore  20  on production tubing  10  using regular completion techniques and landed within the PBR  50 , which seals  55  against the lower end of the packer system  200 ,  600 . Then a packer assembly  400  of the packer system  200 ,  600  is set into sealing engagement with the casing  25 , as will be more fully described herein. In the liner top isolation configuration shown in  FIG. 1 , the packer system  200 ,  600  provides a back-up seal to the liner hanger  60  to ensure isolation of the upper well bore portion  35  from the lower well bore portion  30 , which is exposed to reservoir pressure from the producing pay zone A. 
   When the packer system  200 ,  600  is employed for liner top isolation as shown in  FIG. 1 , the packer assembly  400  may be set by conventional hydraulic methods using a tubing plug, or the packer assembly  400  may be set interventionlessly by applying hydrostatic pressure to the well bore  20  at the surface. However, because the production tubing  10  is in direct fluid communication with the perforated production liner  40  that extends into the lower well bore portion  30  where produced fluids flow in from the producing pay zone A through the perforations  32 , only limited hydrostatic pressure can be applied to the production tubing  10  at the surface. In particular, pressuring up the production tubing  10  would also pressure up the production liner  40  as well as the lower well bore portion  30  adjacent the pay zone A, and such pressure may cause irreparable damage to the formation F. 
   While the representative operating environment depicted in  FIG. 1  refers to a packer system  200 ,  600  operable for liner top isolation, one of ordinary skill in the art will readily appreciate that the packer system  200 ,  600  may also be employed in other applications where hydrostatic pressure may be applied only to the well bore  20 , but not the production tubing  10  at the surface. For example, the packer system  200 ,  600  may be employed within a stacked packer completion. It should also be understood that the packer system  200 ,  600  may be employed in applications where hydrostatic pressure can be applied to both the production tubing  10  and the well bore  20 . Further, the packer system  200 ,  600  may be used in any type of well bore  20 , whether on land or at sea, including deep water well bores; vertical well bores; extended reach well bores; high pressure, high temperature (HPHT) well bores; and highly deviated well bores. 
   The packer system  200 ,  600  may take a variety of different forms.  FIGS. 2A through 2D , when viewed sequentially from end to end, depict one embodiment of a packer system  200  comprising an interventionless, hydrostatically-actuated, top-down setting module  300 ; a packer assembly  400 ; and a hydraulically-actuated, bottom-up contingency setting module  500 ; all supported by a packer mandrel  210  extending internally therethrough. The packer mandrel  210  comprises an elongated tubular body member with a solid wall  220  surrounding a fluid flow bore  205  that extends longitudinally through the length of the packer mandrel  210 . The packer mandrel  210  may comprise an upper threaded box-end  215 , for example, to form a threaded connection to the production tubing  10  as shown in  FIG. 1 , and a lower threaded pin-end  225 , for example, to form a threaded connection  216  to a bottom sub  510  as shown in  FIG. 2D . The bottom sub  510  may comprise an upper box end that forms a hydraulic cylinder  511  as shown in  FIG. 2C  and a lower pin end  515  as shown in  FIG. 2D  for landing the packer system  200  into the PBR  50  as shown in  FIG. 1 . 
   Referring now to  FIGS. 2A and 2B , the interventionless, hydrostatically-actuated, top-down setting module  300  is disposed externally of the packer mandrel  210  above the packer assembly  400  and comprises a top sub  310 , a hydrostatic piston  320 , an initiation chamber  335 , an atmospheric chamber  330 , an upper lock ring housing  340 , and an upper lock ring  350 . The top sub  310  is connected via threads  312  to the packer mandrel  210  and via anti-preset screws  322  to the hydrostatic piston  320 . The initiation chamber  335  comprises a small gap formed between the packer mandrel  210  and the top sub  310 . The initiation chamber  335  is initially evacuated by pulling a vacuum and the vacuum in the initiation chamber  335  acts against an upper surface  321  of the hydrostatic piston  320 . A rupture disk  315  disposed in the top sub  310  initially blocks fluid entry into the initiation chamber  335  from the well bore  20 . O-ring seals  314 ,  316  are provided between the top sub  310  and the packer mandrel  210  and O-ring seals  324 ,  326  are provided between the top sub  310  and the hydrostatic piston  320  to seal off the initiation chamber  335 . 
   The atmospheric chamber  330  comprises an elongate cavity formed between the packer mandrel  210  and the hydrostatic piston  320 , and the atmospheric chamber  330  is initially evacuated by pulling a vacuum. The vacuum in the atmospheric chamber  330  acts against an actuating surface  323  of the hydrostatic piston  320 . Upper O-ring seals  332 ,  336  and lower O-ring seals  342 ,  346  are provided between the packer mandrel  210  and the hydrostatic piston  320  to seal off the atmospheric chamber  330 . Upper and lower centralizer rings  334 ,  344  are operable to properly position the hydrostatic piston  320  about the packer mandrel  210  and form a uniformly shaped atmospheric chamber  330 . Monitor spools with metal-to-metal seats  212 ,  214  are provided between the hydrostatic piston  320  and the packer mandrel  210  for reliability testing of the O-ring seals  314 ,  316 ,  324 ,  326  surrounding the initiation chamber  335  and the O-ring seals  332 ,  336 ,  342 ,  346  surrounding the atmospheric chamber  330  at the surface. In various embodiments, the O-rings  314 ,  316 ,  324 ,  326 ,  332 ,  336 ,  342 ,  346  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. In an embodiment, the packer system  200  is rated for an operating temperature range of 40 to 450 degrees Fahrenheit. 
   Positioned below the hydrostatic piston  320  is an upper lock ring housing  340  that secures an upper lock ring  350  to the packer mandrel  210 . Set screws  342  are employed to keep the upper lock ring  350  from rotating within the upper lock ring housing  340 . The upper lock ring  350  comprises a plurality of downwardly angled teeth  352  that engage and interact with a corresponding saw-tooth profile  230  on the packer mandrel  210 . Such a saw-tooth profile  230  is also commonly referred to as a “phonograph finish” or a “wicker”. Due to the interaction of the downwardly angled teeth  352  and the saw-tooth profile  230  on the packer mandrel  210 , the upper lock ring housing  340  and the upper lock ring  350  are designed to move downwardly but not upwardly with respect to the packer mandrel  210 , and these components  340 ,  350  lock the packer assembly  400  in a set position when the hydrostatic piston  320  actuates, as will be more fully described herein. 
   Referring now to  FIGS. 2B and 2C , the packer assembly  400  is positioned externally of the packer mandrel  210  between the top-down setting module  300  and the bottom-up contingency setting module  500 . The packer assembly  400  comprises an upper slip  410 , an upper wedge  420 , an upper element support shoe  430 , an upper element backup shoe  435 , one or more resilient sealing elements  440 ,  450 ,  460 , a lower element support shoe  470 , a lower element backup shoe  475 , a lower wedge  480  and a lower slip  490 . The upper slip  410  forms a sliding engagement  412  with the upper lock ring housing  340  and forms a sliding engagement  414  with the upper wedge  420 , which is initially connected via shear pins  422  to the packer mandrel  210 . Similarly, the lower slip  490  forms a sliding engagement  492  with a lower lock ring housing  540  and forms a sliding engagement  494  with the lower wedge  480 , which is initially connected via shear pins  482  to the packer mandrel  210 . In an embodiment, the upper and lower slips  410 ,  490  comprise C-ring slips manufactured from low yield AISI grade carbon steel to allow for easier milling. In an embodiment, the slips  410 ,  490  may also be case-carburized with a surface-hardening treatment to provide a hard tooth surface operable to bite into high yield strength casing. 
   In an embodiment, the packer assembly  400  comprises a three-piece resilient sealing element system with a soft center element  450  formed of 70 durometer nitrile and hard end elements  440 ,  460  formed of 90 durometer nitrile. In an embodiment, the harder end elements  440 ,  460  provide an extrusion barrier for the softer center element  450 , and the multi-durometer packer elements  440 ,  450 ,  460  seal effectively in high and low pressure applications, as well as in situations where casing wear is more evident in the packer setting area. The upper and lower element support shoes  430 ,  470  and the upper and lower element backup shoes  435 ,  475  enclose the resilient sealing elements  440 ,  450 ,  460  at the upper and lower ends, respectively, and provide anti-extrusion back up to the resilient sealing elements  440 ,  450 ,  460 . In an embodiment, the upper and lower element support shoes  430 ,  470  comprise yellow brass and the upper and lower element backup shoes  435 ,  475  comprise AISI low yield carbon steel. 
   Referring now to  FIGS. 2C and 2D , the hydraulically-actuated, bottom-up contingency setting module  500  is positioned externally of the packer mandrel  210  below the packer assembly  400  and comprises a hydraulic piston  520 , a lower lock ring housing  540 , and a lower lock ring  550 . The hydraulic piston  520  is disposed externally of the packer mandrel  210  and extends between the packer mandrel  210  and the hydraulic cylinder  511  of the bottom sub  510  to which the hydraulic piston  520  initially connects via shear screws  524 . An upper end  521  of the hydraulic piston  520  connects via threads  542  and set screws  522  to the lower lock ring housing  540 , and a lower end  523  of the hydraulic piston  520  sealingly engages the packer mandrel  210  via O-rings  514 ,  518  and sealingly engages the bottom sub  510  via O-rings  512 ,  516 . A recess  530  is provided within the bottom sub  510  below the lower end  523  of the hydraulic piston  520 . An internal profile  240  within the flow bore  505  of the bottom sub  510  is configured to receive a punch-to-set tool (not shown) operable to punch a hole through the wall  220  of the packer mandrel  210  in the vicinity of the recess  530  in the event the bottom-up contingency setting module  500  will be operated to set the packer assembly  400 . The term “punch-to-set tool” may identify any device operable to perforate the packer mandrel  210 , 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  210  as will be more fully described below. In another embodiment, the packer mandrel  210  includes a pre-punched port through the mandrel wall  220  in the vicinity of the recess  530 , but this embodiment provides somewhat less control over the possible inadvertent setting of the hydraulic piston  520 . 
   Positioned above the hydraulic piston  520  is a lower lock ring housing  540  that secures a lower lock ring  550  to the packer mandrel  210 . Set screws  552  are employed to keep the lower lock ring  550  from rotating within the lower lock ring housing  540 . The lower lock ring  550  comprises a plurality of upwardly angled teeth  554  that engage and interact with a corresponding saw-tooth profile  235  on the packer mandrel  210 . Due to the interaction of the upwardly angled teeth  554  on the lower lock ring  550  and the saw-tooth profile  235 , also known as a “phonograph finish” or a “wicker”, on the packer mandrel  210 , the lower lock ring housing  540  and the lower lock ring  550  are designed to move upwardly but not downwardly with respect to the packer mandrel  210 . These components  540 ,  550  act to lock the packer assembly  400  in a set position when the hydraulic piston  520  actuates, as will be more fully described herein. 
   In operation, the packer system  200  of  FIGS. 2A through 2D  may be run into a well bore  20  on production tubing  10  to a desired depth, for example, and then the packer assembly  400  may be set against casing  25  or against an open borehole wall. Under most circumstances, the packer assembly  400  will be set interventionlessly using the hydrostatically-actuated, top-down setting module  300 . However, should the top-down setting module  300  fail to operate properly, the packer assembly  400  may also be set hydraulically via the hydraulically-actuated, bottom-up contingency setting module  500 , which requires intervention from the surface. 
   In one embodiment, the packer system  200  of  FIGS. 2A through 2D  may be used as a liner top isolation packer, such as shown in  FIG. 1 . In particular, once the liner hanger  60  has been deployed to suspend the perforated production liner  40  adjacent the producing pay zone A, the packer system  200  may be run into the well bore  20  on production tubing  10  using regular completion techniques and landed within the PBR  50 , which seals  55  against the lower end  515  of the bottom sub  510  that lands therein. Then the packer assembly  400  is set by expanding the resilient sealing elements  440 ,  450 ,  460  into engagement with the casing  25 , thereby providing a back-up seal to the liner hanger  60  to ensure isolation of the upper well bore portion  35  from the lower well bore portion  30 , which is exposed to reservoir pressure from the producing pay zone A. 
   To set the packer assembly  400  interventionlessly using the hydrostatically-actuated, top-down setting module  300 , pressure is applied to the fluid column in the well bore  20  at the surface without applying pressure to the fluid within the production tubing  10 . As the hydrostatic pressure within the well bore  20  increases, the rupture disks  315  control initiation of the setting motion of the hydrostatic piston  320 . In particular, the rupture disks  315  are designed to rupture or fail to open a flow path into the initiation chamber  335  when the rupture disks  315  are exposed to a specific pressure differential. The specific pressure differential is established when the absolute pressure, namely the ambient hydrostatic pressure at the setting depth associated with the column of fluid in the well bore  20  plus the applied surface pressure, reaches a predetermined value, and the backside of the rupture disk  315  is exposed to a lower pressure within the initiation chamber  335 . When the absolute pressure reaches the predetermined value, the rupture disks  315  will rupture to allow fluid from the well bore  20  to flow into the initiation chamber  335 . As the fluid from the well bore  20  flows into the initiation chamber  335 , this fluid pressure acts on the upper surface  321  of the hydrostatic piston  320  while the actuating surface  323  of the hydrostatic piston  320  is in communication with the atmospheric chamber  330  at a lower pressure. Thus, a pressure differential is created across the hydrostatic piston  320  that exerts a downward force against the hydrostatic piston  320 . When the downward force is sufficient to overcome the anti-preset screws  322 , the anti-preset screws  322  shear and the piston  520  starts to move downwardly to begin the setting process. 
   The larger volume atmospheric chamber  330  provides the force necessary to set the packer assembly  400 . In particular, as the hydrostatic piston  320  moves downwardly into engagement with the upper lock ring housing  350 , the atmospheric chamber  330  allows the hydrostatic piston  320  to exert a sufficient downward force to move the upper lock ring housing  340 , the upper slip  410 , and the upper lock ring  350 . This downward force drives the upper slip  410  up and over the upper wedge  420  to engage the casing  25 . Continued movement shears the shear pin  422  in the upper wedge  420  and allows further compression of the resilient sealing elements  440 ,  450 ,  460  to form a seal against the casing  25 . As the resilient sealing elements  440 ,  450 ,  460  compress, the shear pin  482  in the lower wedge  480  shears and the lower wedge  480  is driven under the lower slip  490  to drive it outwardly into engagement with the casing  25 . As shown in  FIG. 2C , the lower slip  490  is forced outwardly against the casing  25  because it engages the lower lock ring housing  540 , which is prevented from moving downwardly by the lower lock ring  550  comprising upwardly facing teeth  554  engaging a corresponding saw-tooth profile  235  on the packer mandrel  210 . The interaction between the lower lock ring  550  and the packer mandrel  210  allow movement of the lower lock ring housing  540  only in the upward direction. 
   When the packer assembly  400  is set, the upper element shoe  430  and the upper element backup shoe  435  as well as the lower element shoe  470  and the lower element backup shoe  475  work together to mechanically maintain the squeeze force on the resilient sealing elements  440 ,  450 ,  460  and create an element extrusion barrier when the packer assembly  400  is fully set. In addition, the upper lock ring  350  engages the saw-tooth profile  230  of the packer mandrel  210  to lock the packer assembly  400  in the set position via the upper lock ring housing  340 . In particular, as the upper lock ring  350  is forced down, the downwardly facing teeth  352  of the upper lock ring  350  slide up and over the corresponding saw-tooth profile  230  on the packer mandrel  210  during the packer assembly  400  setting process. The interaction between the downwardly facing teeth  352  of the upper lock ring  350  and the saw-tooth profile  230  on the packer prevents any upward movement of the upper lock ring  350  and upper lock ring housing  340 . Therefore, the upper lock ring  350  holds the upper lock ring housing  340  in the set position to continue exerting a force on the packer assembly  400  components to squeeze the resilient sealing elements  440 ,  450 ,  460  into engagement with the surrounding casing  25 . 
   In addition, due to the configuration of the packer system  200 , the actuating force will continue acting on the hydrostatic piston  320  to exert a setting force on the packer assembly throughout its service life due to the hydrostatic actuating pressure within the well bore  20 . 
   Therefore, when the packer assembly  400  is mechanically and/or thermally loaded during its operational life, the resilient sealing elements  440 ,  450 ,  460  will not be the only components to expand and contract and thereby become spongy to leak over time. Instead, as the interventionless, hydrostatically-actuated, top-down setting module  300  substantially continually exerts a setting force to fully set the packer assembly  400 , the hydrostatic actuating pressure from the well bore  20  exerted on the hydrostatic piston  320  is not diminished. Thus, the hydrostatic piston  320  will continue providing a setting force on the slips  410 ,  490 ; the wedges  420 ,  480 ; and the resilient sealing elements  440 ,  450 ,  460 . 
   Referring again to  FIGS. 1 and 2A  through  2 D, when the packer assembly  400  of the packer system  200  is expanded into sealing engagement with the casing  25 , the packer assembly  400  functions to isolate the upper well bore portion  35  from the lower well bore portion  30  that is exposed to reservoir pressure. In an embodiment, the packer system  200  presents no potential fluid communication leak paths between the production tubing  10  and the upper well bore portion  35  due to O-rings or other elastomeric seals. In particular, the packer system  200  of  FIGS. 2A through 2D  comprises a packer mandrel  210  formed of a solid wall  220  with no ports or flow paths extending therethrough, thereby eliminating concerns about O-rings or other elastomeric seals that may allow leaks. Specifically, since there are no ports through the solid wall  220  of the packer mandrel  210 , there are no potential leak pathways between the production tubing  10  and the well bore  20 , especially into the upper well bore portion  35  above the packer assembly  400 . 
   In the method described above, setting of the packer assembly  400  was accomplished without surface intervention via hydrostatic pressure. However, surface intervention may be required should the hydrostatically-actuated, top-down setting module  300  fail to actuate as expected, which could possibly occur if the atmospheric chamber  330  fills with fluid from the well bore  20  due to leaky O-ring seals. In that event, referring now to  FIGS. 2C and 2D , an optional hydraulically-actuated, bottom-up setting module  500  may be provided within the packer system  200  for setting the packer assembly  400  with intervention from the surface as a contingency. To operate the setting module  500 , a punch-to-set tool (not shown) is run down into the well bore  20  on wireline, coiled tubing, or another intervention means through the packer mandrel flow bore  205  into the bottom sub flow bore  505  and into sealing engagement with the internal profile  240 . Then the punch-to-set tool punches a hole through the wall  220  of the packer mandrel  210  in the vicinity of the recess  530  below the hydraulically-actuated piston  520 . The punch-to-set tool also forms a plug within the bottom sub flow bore  505  such that surface pressure can be applied through the production tubing  10  since the plug isolates the fluid within the production tubing  10  from the perforated production liner  40  below. Pressuring up on the production tubing  10  also pressures up the packer mandrel flow bore  205  and allows fluid to flow into the recess  530 . The pressure differential between the fluid in the recess  530  and the fluid in the well bore  20  exerts an upward force against the hydraulic piston  520 . When the upward force is sufficient to overcome the shear screws  524  between the hydraulic piston  520  and the bottom sub  510 , the shear screw  524  will shear and the hydraulic piston  520  starts to move upwardly to begin the setting process. 
   As the hydraulic piston  520  moves upwardly, the lower lock ring housing  540  connected thereto via threads  542  and set screws  522  will also move upwardly. As the lower lock ring housing  540  moves upwardly, the lower slip  490  and the lower lock ring  550  will also move upwardly. This upward force drives the lower slip  490  up and over the lower wedge  480  to engage the casing  25 . Continued movement shears the shear pin  482  in the lower wedge  480  and allows further compression of the resilient sealing elements  440 ,  450 ,  460  to form a seal against the casing  25 . Referring now to  FIGS. 2B and 2C , the resilient sealing elements  440 ,  450 ,  460  compress, the shear pin  422  in the upper wedge  420  shears and the upper wedge  420  is driven under the upper slip  410  to drive it outwardly into engagement with the casing  25 . The upper slip  410  is forced outwardly against the casing  25  because it engages the upper lock ring housing  340 , which forms a connection with the packer mandrel  210  that prevents upward movement. In particular, the upper lock ring housing  340  is prevented from moving upwardly by the upper lock ring  350  interacting with the packer mandrel  210 , which allows movement of the upper lock ring housing  340  only in the downward direction. 
   When the packer assembly  400  is set, the upper element shoe  430  and the upper element backup shoe  435  as well as the lower element shoe  470  and the lower element backup shoe  475  work together to mechanically maintain the squeeze force on the resilient sealing elements  440 ,  450 ,  460  and create an element extrusion barrier when the packer assembly  400  is fully set. In addition, the lower lock ring  550  engages the profile  235  of the packer mandrel  210  to lock the packer assembly  400  in the set position via the lower lock ring housing  540 . In particular, as the lower lock ring  550  is forced up, the upwardly facing teeth  554  of the lower lock ring  550  slide up and over the corresponding saw-tooth profile  235  on the packer mandrel  210  during the packer assembly  400  setting process. The interaction between the upwardly facing teeth  554  of the lower lock ring  550  and the saw-tooth profile  235  on the packer mandrel  210  prevents any downward movement of the lower lock ring  550  and lower lock ring housing  540 . Therefore, the lower lock ring  550  holds the lower lock ring housing  540  in the set position to continue exerting a force on the packer assembly  400  components to squeeze the resilient sealing elements  440 ,  450 ,  460  into engagement with the surrounding casing  25 . Once the packer assembly  400  is set, the tubing plug provided by the punch-to-set tool must be removed, such as by retrieval to the surface, to resume normal operations. 
   Referring now to  FIGS. 2B and 3 , it may be desirable to remove the packer system  200  from the well bore  20 , such as by milling. To perform a milling removal operation, the production tubing  10  is disconnected from the packer system  200  and removed from the well bore  20 . Then a milling tool is run down onto the packer system  200  to begin milling away the packer system  200 . The milling tool mills the packer system  200  components downwardly until it mills away at least a portion of the upper slip  410  and/or the upper wedge  420  to loosen the packer system  200  for removal. However, the hydrostatic piston  320  is not connected or threaded to any other component in the non-actuated configuration shown in  FIG. 2B , and therefore, the hydrostatic piston  320  is likely to catch on the mill and rotate with it instead of being milled away. Therefore, an anti-rotation clutch  700  is provided for interconnecting the hydrostatic piston  320  with the upper lock ring housing  340  in the actuated position. In particular, as best shown in  FIG. 3 , the lowermost end of the hydrostatic piston  320  comprises a series of dogs  325  separated by gaps  327 , and the dogs  325  are designed to matingly engage corresponding grooves  345  formed within the uppermost end of the upper lock ring housing  340 , as best shown in  FIG. 2B . When the hydrostatic piston  320  interconnects with the upper lock ring housing  340  via the anti-rotation clutch  700 , then milling operations can be completed down to the upper slip  410  and/or upper wedge  420 . 
   Referring now to  FIGS. 4A through 4C , a second embodiment of a packer system  600  is depicted comprising many of the same features as the packer system  200  of  FIGS. 2A through 2D , with like components having like reference numerals. The packer system  600  of  FIGS. 4A through 4C  is a less complex version of the packer system  200  of  FIGS. 2A through 2D  in that it includes the interventionless, hydrostatically-actuated, top-down setting module  300  and the packer assembly  400 , but eliminates the contingency hydraulic setting module  500  that requires surface intervention. As shown in  FIG. 4C , the bottom sub  510  and the lower lock ring housing  540  are also eliminated, and a fixed housing component  640  that connects via threads  642  to the exterior of the packer mandrel  210  is provided below the lower slip  490 . The operation of the hydrostatically-actuated, top-down setting module  300  to set the packer assembly  400  is identical to that described above with respect to the packer system  200  of  FIGS. 2A through 2D . However, the lower slip  490  is prevented from downward movement by the fixed housing component  640  rather than the lower lock ring housing  540 . 
   Setting a downhole tool, such as a packer assembly  400 , in one trip into the well bore  20  using an interventionless, hydrostatically-actuated, top-down setting module  300  as described above is more cost effective and less time consuming than setting a downhole tool using conventional hydraulic methods that require making one or more trips into the well bore  20  to insert and remove a tubing plug. The top-down setting module  300  will also provide sufficient actuating force to completely set a packer assembly  400 , even when hydrostatic pressure can only be supplied to the well bore  20  and not the production tubing  10 , and the actuating force is not diminished during the setting process. The foregoing descriptions of specific embodiments of the packer systems  200 ,  600  and the methods for setting packer assemblies  400  within a well bore  20  have been presented for purposes of illustration and description and are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Obviously many other modifications and variations are possible. In particular, the specific type of downhole tool, or the particular components that make up the downhole tool could be varied. For example, instead of a packer assembly  400 , the downhole tool could comprise an anchor or another type of plug. Further, the downhole tool may be a permanent tool, a recoverable tool, or a disposable tool, and other removal methods besides milling the downhole tool may be employed. For example, one or more components of the downhole tool may be formed of materials that are consumable when exposed to heat and an oxygen source, or materials that degrade when exposed to a particular chemical solution, or biodegradable materials that degrade over time due to exposure to well bore fluids. In other embodiments, the downhole tool may include frangible components allowing for tool removal by explosive charge. Many other removal methods are possible. 
   While various embodiments of the invention have been shown and described herein, modifications may be made by one skilled in the art without departing from the spirit and the teachings of the invention. The embodiments described here are exemplary only, and are not intended to be limiting. Many variations, combinations, and modifications of the invention disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the description set out above, but is defined by the claims which follow, that scope including all equivalents of the subject matter of the claims.