You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    The invention relates generally to packer setting devices. In particular aspects, the invention relates to the design of devices for setting packers using hydrostatic wellbore fluid pressure. 
         [0003]    2. Description of the Related Art 
         [0004]    Packers are used to create a seal within the annulus of a wellbore between an interior tubular string and the wall of the wellbore. Packers incorporate an elastomeric sealing element that can be radially expanded to set the packer. The packer may also incorporate one or more metallic slip elements that create a mechanical anchorage between the interior tubular string and the wellbore. Commonly, packers are mechanically set by applying an axial force to the sealing element and slip elements to cause them to be expanded radially outwardly and into engagement with the surrounding wellbore wall. A setting tool can be used to do this. Alternatively, fluid can be pumped down the flowbore of the interior tubular string and the fluid pressure used to axially compress the packer element. 
         [0005]    Another method of setting the packer device is by use of hydrostatic pressure. U.S. Pat. No. 6,843,315 issued to Coronado et al., for example, describes a hydrostatically-set packer device having a composite sealing element with large radial expansion capabilities for use in through tubing and open hole applications. This patent is owned by the assignee of the present invention and is, therefore, incorporated by reference. The hydrostatic pressure of the column of fluid within the wellbore is used to provide the setting force for compressing the packer element. However, there are difficulties with the design of setting devices that are used in very deep wells due to the presence of high hydrostatic pressures. In particular, hydrostatic pressures of 20,000 psi or greater are problematic. With such ambient pressures, the setting mechanism can be prone to premature actuation and setting of an associated packer. In addition, certain components of setting devices, such as large volume chambers, are prone to crushing damage at great depths. 
         [0006]    The present invention addresses the problems of the prior art. 
       SUMMARY OF THE INVENTION 
       [0007]    The invention provides devices and methods for actuating a downhole tool, such as a packer, using hydrostatic pressure as an actuating force. In a preferred embodiment, a packer setting device is used that includes a compressible fluid chamber. In one described embodiment, the compressible fluid chamber preferably includes a plurality of small-diameter hydrostatic chambers that are filled with a compressible fluid at a relatively low or atmospheric pressure. In another embodiment, the compressible fluid chamber comprises a helically coiled tube. In addition, the setting device includes an incompressible fluid chamber that is filled with a volume of substantially incompressible fluid and initially separated from the compressible fluid chamber by a trigger device. 
         [0008]    In operation, the packer setting device provides a buffered setting mechanism as the substantially incompressible fluid is selectively flowed into the compressible fluid chamber to compress the compressible fluid. This fluid transfer causes movement of the setting sleeve so that the associated packer device is set within the wellbore. The substantially incompressible fluid is preferably metered into the compressible fluid chamber along a tortuous, fluid-restrictive flow path to limit the rate of flow of fluid thereby preventing an undesired rapid setting. 
         [0009]    In one embodiment the trigger mechanism is a frangible rupture disc that is destroyed by increasing hydrostatic pressure within the wellbore annulus. In another embodiment, the trigger device is a valve that is actuated from the surface. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0010]      FIG. 1  presents a side, cross-sectional view of an exemplary wellbore having a production string with a packer and packer setting device constructed in accordance with the present invention. 
           [0011]      FIG. 2  is a side cross-sectional view of the packer setting device and associated packer in an unactuated condition within a wellbore. 
           [0012]      FIG. 3  is an enlarged side cross-sectional view of upper portions of the packer setting assembly shown in  FIGS. 1 and 2  in an unactuated position. 
           [0013]      FIG. 3A  is an enlarged side cross-sectional view of lower portions of the packer setting assembly shown in  FIGS. 1 and 2  in an unactuated condition. 
           [0014]      FIG. 4  is an axial cross-sectional view taken along lines  4 - 4  in  FIG. 3 . 
           [0015]      FIG. 5  is an axial cross-sectional view taken along lines  5 - 5  in  FIG. 3 . 
           [0016]      FIG. 6  is an enlarged side cross-sectional view of upper portions of the packer setting assembly shown in  FIGS. 1 ,  2 , and  3 , now in an actuated condition. 
           [0017]      FIG. 6A  is an enlarged side cross-sectional view of lower portions of the packer setting assembly shown in  FIGS. 1 ,  2 , and  3 A, now in an actuated condition. 
           [0018]      FIG. 7  is an axial cross-section of upper portions of the packer setting assembly taken along lines  7 - 7  in  FIG. 5 . 
           [0019]      FIG. 8  is a side, cross-sectional view of an alternative embodiment for a packer setting assembly in accordance with the present invention wherein the compressible fluid chamber is formed of a spiral-wrapped tube. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0020]      FIG. 1  illustrates an exemplary wellbore  10  that has been drilled through the earth  12  and lined with casing  14  to define an axial flowbore  16  along its length. The flowbore  16  contains a hydrocarbon production string  18  that extends downward therethrough from the surface  20 . Those of skill in the art will understand that the production string  18  is suspended within the wellbore  10  by a wellhead (not depicted). An annulus  21  is defined between the production string  18  and the casing  14 . 
         [0021]    The production string  18  includes a packer setting device  22  that is constructed in accordance with the present invention. A mechanically-set packer device  24  is affixed to the packer setting device  22 . The packer device  24  is moveable between set and unset positions, as is known in the art, by the application of axial force in order to force slips and/or seals radially outwardly from the packer device  24  and into engagement with the flowbore  16  of the wellbore  10 . 
         [0022]      FIG. 2  illustrates the interconnection of the packer setting device  22  to the packer device  24 . Generally, the packer setting device  22  includes a central internal mandrel  26  having upper and lower threaded ends  28 ,  30 . The upper threaded end  28  is interconnected to a top sub  32  which, in turn, is interconnected with the production string  18  above the packer device  24  while the lower threaded end  30  is secured to a central body sub  32  of the packer device  24 . The packer setting device  22  also includes a setting sleeve  34  that radially surrounds the internal mandrel  26  and is axially moveable with respect thereto. The setting sleeve  34  presents a lower end  36  that abuts a compression setting ring  38  on the packer device  24 . Axial movement of the setting ring  38  upon inner sub  41  will set a packer element  40  on the packer device  24 . 
         [0023]      FIGS. 3 ,  3 A,  4 ,  5 ,  6 , and  6 A illustrate further details of the packer setting device  22  in greater detail. As can be seen from  FIG. 3 , the interior mandrel  26  of the packer setting device  22  defines an interior flowbore  44 . Upper and lower outer housings  46 ,  48  radially surround the inner mandrel  26 . The upper and lower outer housings  46 ,  48  are affixed to each other via threaded connection  50 . The upper housing  46  contains a pair of axial bores  52 ,  54  that are located on diametrically opposite sides of the housing  46 . The bores  52 ,  54  are preferably created by drilling from the upper axial end  56  of the upper housing  46 . The upper end of each chamber  52 ,  54  is sealed with a pipe plug  58 . As can be seen with further reference to  FIG. 4 , each axial chamber  52 ,  54  is interconnected with an axial fluid pathway  60  by a lateral flow passage  62 . The lateral flow passage  62  may be created by drilling laterally inwardly and then closing the outer portion of the drilled passage with a plug  64 , as depicted in  FIG. 4 . A flow plug  66  is moveably disposed within each bore  52  and  54 , and during run-in, prior to actuation, each flow plug  66  blocks its respective lateral passage  62 , as shown in  FIG. 3 . A trigger mechanism  70  is disposed in each bore  52 ,  54  below the flow plug  66  and blocks the passage of fluid through the bore. In a currently preferred embodiment, the trigger mechanism is a frangible rupture disc, of a type known in the art, which is designed to block the passage of fluid flow through the bore  52  or  54  and which is designed to fail and rupture in response to a sufficiently high predetermined fluid pressure differential within the bore  52 ,  54 . In an alternate embodiment, the trigger mechanism  70  comprises an electronically actuated valve, also of a type known in the art that initially blocks fluid flow through the bore  52  or  54  and can be opened from the surface  20  to permit fluid flow through the bore  52  or  54 . The axial fluid pathway  60  extends downwardly through the upper outer housing  46  to an annular channel  74  that is defined between the upper and lower outer housings  46 ,  48 . The use of two (or more) bores  52 ,  54  and, therefore, two separate trigger devices  70  is currently preferred in order to allow for redundancy. 
         [0024]    The structure of the lower outer housing  48  is best understood by reference to  FIGS. 3 ,  5  and  7 .  FIG. 5  is an axial cross-section of the housing  48  and indicates by lines  3 - 3  and  5 - 5  how the side cross-sectional views of  FIGS. 3 and 5  are taken.  FIGS. 3 and 5  illustrate that there are two hydrostatic piston chambers  76  defined within the body of the lower outer housing  48 . Each of the piston chambers  76  is blocked from fluid communication with the annular channel  74  at its upper end by a plug  78 . However, an opening  80  is provided that allows fluid communication between each piston chamber  76  and the annulus  21  surrounding the setting device  22 . In addition, the lower end of each piston chamber  76  has a fluid outlet  82 . A piston  84  is moveably disposed within each piston chamber  76 . 
         [0025]      FIG. 7  shows a different side cross-section of the lower outer housing  48  that is taken along lines  7 - 7  in  FIG. 5 . As illustrated a plurality of axial repository blind bores  86  are formed in the body of the housing  48  and disposed in a spaced relation about the circumference of the housing  48 . The blind bores  86  are in fluid communication at their upper ends with the annular channel  74 . It is currently preferred that, prior to run-in, the blind bores  86  be filled with air at atmospheric pressure. It is noted that during run-in and prior to actuation, the repository blind bores  86  remain at atmospheric pressure due to the presence of the trigger devices  70 , which initially isolate the bores  86  from wellbore hydrostatic pressure. 
         [0026]    A narrow annular chamber  88  is defined between the interior mandrel  26  and the upper and lower outer housings  46 ,  48  and setting sleeve  34 . The lower end of the chamber  88 , visible in  FIG. 3A , adjoins a fluid drain chamber  90  that is formed between the setting sleeve  34  and the interior mandrel  26 . Fluid pathways  92  place the upper end of annular chamber  88  in fluid communication with both bores  52 ,  54 . In addition, fluid outlets  82  of the piston chambers  76  are in fluid communication with the annular chamber  88 . The lower end of the larger chamber  90  is enclosed by outwardly-projecting flange  93  and sealed by fluid seal  94 . The upper end of the chamber  90  has a shoulder  89  that projects inwardly from the setting sleeve  34 . The chambers  90  and  88  are, prior to run-in, filled with a substantially incompressible fluid. It is currently preferred that, prior to run-in, a hydraulic fluid, such as a viscous oil, be used to fill the chambers  90  and  88 . This incompressible fluid will also be present within the fluid outlets  82  and piston chambers  76  below the pistons  84 . In addition, the incompressible fluid will be present within the fluid pathways  92  and the lower ends of bores  52  and  54 , below the trigger devices  70 . It is noted that pistons  84  are in communication with both the wellbore fluid and the substantially incompressible fluid. 
         [0027]    Referring now to  FIG. 3 , a body lock ring assembly  96 , of a type known in the  20  art, is provided to ensure one way, ratchet-type motion of the outer housings  46 ,  48  and the affixed setting sleeve  34  with respect to the central mandrel  26 . The body lock ring assembly  96  includes a C-ring member  98  that is disposed within a recess  100  between the lower outer housing  48  and the inner mandrel  26 . The radial interior surface  102  of the ring member  98  is corrugated with one-way teeth in a manner known in the art so as to ensure that the housings  46 ,  48  and setting sleeve  34  move axially downwardly with respect to the interior mandrel  26 , but not axially upwardly. Fluid within the annular chamber  88  will be able to bleed past the body lock ring assembly  96  because the assembly  96  is not fluid tight and contains at least one break in continuity to form C-ring member  98 . The lower end of the interior mandrel  26  of the packer setting device  22  is affixed by threaded connection  104  to the inner sub  41  of the packer device  24 . 
         [0028]    The packer setting device  22  is operated to set the packer  24  within the wellbore  10  in the following manner. In the instance in which the trigger devices  70  are rupture discs, fluid pressure is increased from the surface  20  within the annulus  21 . The increase in annulus pressure will be communicated through openings  80  and into the piston chambers  76  of the packer setting device  22 . The increased pressure within the piston chambers  76  will act upon the pistons  84  and urge them downwardly within the piston chambers, as depicted in  FIG. 6 . As the pistons  84  move downwardly, they increase the pressure of the hydraulic fluid that is enclosed within the fluid pathways  92  and annular chambers  88  and  90 . Once the annulus pressure reaches a predetermined level that is sufficient to rupture the rupture discs  70 , the enclosed hydraulic fluid will flow from the chamber  88  through fluid passages  92  and into the lower ends of both bores  52 ,  54 . In so doing, the hydraulic fluid urges the flow plugs  66  upwardly within the bores  52 ,  54  to unblock the lateral passages  62  (see  FIG. 6 ). Once the lateral passages  62  are unblocked, displaced hydraulic fluid can flow through those passages  62  to axial pathway  60  and into the annular channel  74 . From the annular channel  74 , the hydraulic fluid will enter the lower-pressure blind bores  86  and thereby compress the compressible fluid that is within each of the bores  86 . As the hydraulic fluid enters the repository bores  86 , it is drained from the annular chamber  90 , and this draining action draws the setting sleeve  34  axially downwardly with respect to the interior mandrel  26  and the inner sub  41  of the affixed packer device  24 . The escape of incompressible fluid from the chamber  90  creates a suction effect that essentially draws the shoulder  89  downwardly toward flange  93  and, as a result, setting sleeve  34  moves downwardly with respect to the interior mandrel  26 . This suction force is further used as a setting force as the lower end  36  of the setting sleeve  34  contacts the compression ring  38  and urges it downwardly. The lower end  36  of the setting sleeve  34  contacts the compression setting ring  38  and urges it downwardly, thereby axially compressing and setting the packer element  40  of the packer device  24 . The body lock ring assembly  96  ensures that this downward movement occurs in a ratchet-type one-way fashion.  FIGS. 6 and 6A  illustrate the set position of the setting device  22 . 
         [0029]    In an embodiment wherein the trigger devices  70  are electronically actuated valves, the setting process is essentially the same. However, in order to begin the setting process, there is no need to pressurize the annulus  21 . Instead, the trigger device valves  70  are actuated from the surface  20  to an open position which will allow the incompressible fluid below them to urge the flow plugs  66  upwardly within the bores  52 ,  54  to unblock the lateral passages  62 . The incompressible fluid will then be urged into the blind bores  76  under the impetus of hydrostatic wellbore pressure. 
         [0030]    It is noted that the hydraulic fluid that is enclosed within the chambers  88  and  90  must traverse a tortuous path made up of small flow area fluid passages  92 ,  62  and  60  as well as annular channel  74  before it enters the blind bores  86 . The use of this tortuous, flow-restrictive path ensures that setting force is increased gradually within the setting device  22  and does not result in rapid or premature setting of the affixed packer  24 . 
         [0031]    The packer setting tool  22  can be considered to have a compressible fluid chamber which is made up of the plurality of blind bores  86 , the annular channel  74  interconnecting the blind bores  86 , the axial passages  60 , lateral passages  62 . Prior to run-in, the compressible fluid chamber is filled with a compressible fluid, such as air, and this compressible fluid chamber is separated from the incompressible fluid by the trigger devices  70 . The incompressible fluid is initially stored within an incompressible fluid storage volume that is made up, in this described embodiment, of the chambers  88  and  90  as well as the fluid passages  82 , and  92  and the portion of the piston chambers  76  below the pistons  84 . Upon actuation of the trigger devices  70 , the incompressible fluid is released from the storage area and allowed to flood the compressible fluid chamber. 
         [0032]      FIG. 8  depicts portions of an alternative packer setting tool  22 ′. The packer setting device  22 ′ is constructed and operates in the same manner as the packer setting device  22  except as noted herein.  FIG. 8  illustrates a modified upper housing  46 ′ and lower housing  48 ′. As with the housing  46 , the upper housing  46 ′ includes an axial bore  52  that is closed with pipe plug  58 . Fluid passageway  92  interconnects the lower end of the bore  52  with the chamber  88 , and there is a flow plug  66  and trigger device  70  present within the bore  52 . It is noted that, in this embodiment, there is preferably only a single axial bore  52 . Bore  54  is not present. 
         [0033]    The lower housing  48 ′ defines an annular chamber  110  that contains a tube  112  that is wound in a helical fashion to create coils  114  within the chamber  110 . The tube  112  has a closed lower end  116 . The open end  118  of tube  112  is interconnected with the fluid passageway  60 . 
         [0034]    The upper housing  46 ′ also defines within its annular body a plurality of piston chambers  120  (two are shown). The piston chambers  120  have a piston  122  moveably disposed therewithin. Pipe plug  124  blocks the upper axial end of each piston chamber  120  while a lateral fluid opening  126  permits fluid communication with the annulus  21 . A fluid passageway  128  extends from the lower end of each piston chamber  120  to the annular chamber  88 . A substantially incompressible fluid is contained within an incompressible fluid chamber that is formed of the portions of piston chambers  120  below the pistons  122 , fluid passages  120 , the annular chambers  88  and  90  as well as the fluid passageway  92  and the portion of bore  52  below the trigger device  70 . 
         [0035]    A compressible fluid chamber is formed by the helical tube  112  and fluid passageways  60  and  62 . The helical tube  112  is filled with a compressible fluid prior to run-in. The compressible fluid is at a pressure that is lower than the substantially incompressible fluid will be when in the wellbore  10 . The compressible fluid will preferably be at approximately atmospheric pressure when the compressible fluid chamber is filled at the surface  20 . The substantially incompressible fluid is, during run-in and prior to setting, at a pressure that is greater than that of the compressible fluid within the tube  112  since the wellbore hydrostatic fluid is able to exert its ambient hydrostatic pressure upon the substantially incompressible fluid via the pistons  122 . 
         [0036]    In operation, the packer setting device  22 ′ is actuated to set the packer  24  by actuating the trigger device  70 , in a manner described previously. When the trigger device  70  is actuated, the substantially incompressible fluid is flowed, under the impetus of ambient wellbore hydrostatic pressure acting upon pistons  122 , into the compressible fluid chamber to flood the compressible fluid chamber. The packer device  24  is then set by movement of the setting sleeve  34  relative to the interior mandrel  26 , as described previously. 
         [0037]    It is noted that in both packer setting devices  22  and  22 ′, the compressible fluid chamber and the incompressible fluid chambers are defined outside of the interior mandrel  26 , thereby allowing thru-tubing operations to be conducted through the flowbore  44  before, during and after packer setting. 
         [0038]    Those of skill in the art will recognize that numerous modifications and changes may be made to the exemplary designs and embodiments described herein and that the invention is limited only by the claims that follow and any equivalents thereof.

Summary:
A packer setting device provides a buffered setting mechanism as a substantially incompressible fluid is selectively flowed into a compressible fluid chamber to compress a compressible fluid. This fluid transfer causes movement of a setting sleeve so that an associated packer device is set within a wellbore.