Abstract:
An isolation system having: an isolation string, wherein the isolation string has a packing assembly which secures the isolation string in a wellbore casing, wherein the isolation string has a production screen which allows production fluid to pass into the isolation string; an isolation sleeve which slides within the isolation string between open and closed positions, wherein the open position allows fluid communication between the production screen and an interior portion of the isolation string and the closed position prevents fluid communication between the production screen and an interior portion of the isolation string, wherein the isolation sleeve comprises at least one isolation valve which is coupled within the isolation sleeve, wherein the at least one isolation valve is movable between open and closed positions; a locking device which locks and unlocks the isolation sleeve in an open position, wherein the locking device comprises a trigger that secures the isolation sleeve to the isolation string before the trigger is activated and releases the isolation sleeve from the isolation string after the trigger is activated, wherein the trigger comprises: a piston collar having a solid cylindrical portion attached to the isolation sleeve and a finger portion having at least one finger, wherein the at least one finger has a head at a distal end; and at least one recess in the isolation string, wherein the head of the at least one finger is engaged in the at least one recess; a cylindrically shaped pop lock positioned adjacent the head of the at least one finger so that the head is between the pop lock and the recess, wherein the pop lock secures the head relative to the recess; and a latch attached to the service tool which couples with the pop lock, wherein the trigger is activated by removing the pop lock from the position adjacent the head; and an activation tool which allows the isolation sleeve to move to a closed position, wherein the activation tool is a piston driven by a hydrostatic chamber which comprises lower pressure within the hydrostatic chamber than without, and wherein the piston moves the isolation sleeve from the open to the closed position.

Description:
CONTINUATION STATEMENT 
     This application claims priority to U.S. Provisional Application No. 60/085,620, filed May 15, 1998. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to the field of isolation systems and gravel pack assemblies for use in a wellbore. More particularly, the invention provides an improved system and method for zone isolation following gravel pack completions installed in a wellbore. 
     2. Description of the Prior Art 
     Typical prior art isolation systems involve intricate positioning of tools which are installed down-hole after the gravel pack. An example of this type of system is available from Baker. This system utilizes an anchor assembly which is run into the well bore after the gravel pack. The anchor assembly is released by a shearing action, and subsequently latched into position. 
     Certain disadvantages have been identified with these systems. For example, prior conventional isolation systems have had to be installed after the gravel pack, thus requiring greater time and extra trips to install the isolation assemblies. Also, prior systems have involved the use of fluid loss control pills after gravel pack installation, and have required the use of thru-tubing perforation or mechanical opening of a wireline sliding sleeve to access alternate or primary producing zones. Since multiple trips into the well are required for gravel pack and isolation, these systems are time consuming methods and provide less flexibility and reliability. 
     An example of an isolation washpipe for well completions is disclosed in U.S. Pat. No. 5,343,949, incorporated herein by reference. In this system, there is an expansion joint which is used to push a closing sleeve into a closed position over the production screen. 
     More recently, isolation systems have been developed which do not require the running of tailpipe and isolation tubing separately. Instead, the system uses the same pipe to serve both functions: as tailpipe for circulating-style treatments and as production/isolation tubing. An example of this type of isolation system is disclosed in U.S. Pat. No. 5,865,251, incorporated herein by reference. An isolation sleeve is installed inside the production screen at surface and placed in the wellbore simultaneously with the service tool. The isolation sleeve is thereafter controlled in the wellbore by means of the inner service string. This system is adapted for well control purposes and for well bore fluid loss control. It combines simplicity, reliability, safety and economy, while also affording flexibility in use. 
     However, &#39;251 provides only small orifices for circulation of the gravel pack fluid through the isolation sleeve. Further, &#39;251 allows debris to become trapped between the production screen and the isolation sleeve. Further, because the washpipe extends through the isolation sleeve during the gravel pack operation, there is the possibility that debris will become lodged between the isolation sleeve and the wash pipe. This debris could cause the washpipe to hang or jam upon withdrawal so that the entire service string is permanently lodged in the isolation sleeve. Therefore, there is a need for a system which allows the isolation sleeve to be closed without a washpipe extending through the isolation sleeve. Further, there is a need for an isolation sleeve which does not allow debris to become accumulated between the isolation sleeve and the production screen and which allows fluid to freely pass through the isolation sleeve during the gravel pack operation. 
     SUMMARY OF THE INVENTION 
     The present invention is a system and method for providing full fluid flow through the production screen during a gravel pack operation and which does not allow debris to accumulated between the isolation system and the production screen. Further, the isolation system is closeable immediately upon completion of the gravel pack operation by the service tool which performed the gravel pack. Closure of the isolation system may even be accomplished without a wash pipe extending through the isolation system. The system comprises an activation tool which allows the isolation system to operate between the open and closed positions. 
     According to one aspect of the invention, there is provided an isolation system having: an isolation string, wherein the isolation string has a packing assembly which secures the isolation string in a wellbore casino, wherein the isolation string has a production screen which allows production fluid to pass into the isolation string; an isolation sleeve which slides within the isolation string between open and closed positions; a locking device which locks and unlocks the isolation sleeve in an open position; and an activation tool which allows the isolation sleeve to move to a closed position, wherein the open position allows fluid communication between the production screen and an interior portion of the isolation string and the closed position prevents fluid communication between the production screen and an interior portion of the isolation string. 
     According to a further aspect of the invention, there is provided an isolation system having: an isolation string, wherein the isolation string has a packing assembly which secures the isolation string in a wellbore casing, wherein the isolation string has a production screen which allows production fluid to pass into the isolation string; an isolation sleeve which slides within the isolation string between open and closed positions, wherein the open position allows fluid communication between the production screen and an interior portion of the isolation string and the closed position prevents fluid communication between the production screen and an interior portion of the isolation string, wherein the isolation sleeve comprises at least one isolation valve which is coupled within the isolation sleeve, wherein the at least one isolation valve is movable between open and closed positions; a locking device which locks and unlocks the isolation sleeve in an open position, wherein the locking device comprises a trigger that secures the isolation sleeve to the isolation string before the trigger is activated and releases the isolation sleeve from the isolation string after the trigger is activated, wherein the trigger comprises: a piston collar having a solid cylindrical portion attached to the isolation sleeve and a finger portion having at least one finger, wherein the at least one finger has a head at a distal end; and at least one recess in the isolation string, wherein the head of the at least one finger is engaged in the at least one recess; a cylindrically shaped pop lock positioned adjacent the head of the at least one finger so that the head is between the pop lock and the recess, wherein the pop lock secures the head relative to the recess; and a latch attached to the service tool which couples with the pop lock, wherein the trigger is activated by removing the pop lock from the position adjacent the head; and an activation tool which allows the isolation sleeve to move to a closed position, wherein the activation tool is a piston driven by a hydrostatic chamber which comprises lower pressure within the hydrostatic chamber than without, and wherein the piston moves the isolation sleeve from the open to the closed position. 
     According to an even further aspect of the invention, there is provided a process for isolating a production zone within a well, the process having the steps of: installing an isolation string and a service tool simultaneously within the well adjacent the production zone, wherein the isolation string comprises an isolation sleeve; locking the isolation sleeve in an open position during the installing an isolation string, wherein the open position allows fluid communication between the production screen and an interior portion of the isolation string; unlocking the isolation sleeve with the service tool; and moving the isolation sleeve to a closed position, wherein the closed position prevents fluid communication between the production screen and an interior portion of the isolation string. 
     Other and further features and advantages will be apparent from the following description of presently preferred embodiments of the invention, given for the purpose of disclosure and taken in conjunction with the accompanying drawings. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The present invention is better understood by reading the following description of non-limitative embodiments, with reference to the attached drawings wherein like parts in each of the several figures are identified by the same reference character, and which are briefly described as follows. 
     FIGS. 1A and 1B are cross sectional views of a service tool with a locking stick joint, in the run-in position in combination with an isolation string, of the present invention; 
     FIGS. 2A and 2B are cross sectional views of a service tool with a locking stick joint in the set position, in combination with an isolation string, of the present invention; 
     FIG. 3 is a cross sectional view of an alternative embodiment of a service tool with a locking stick joint in the run-in position, in combination with an isolation string, of the present invention; 
     FIG. 4 is a cross sectional view of an alternative embodiment of a service tool with a locking stick joint in the set position, in combination with an isolation string, of the present invention; 
     FIG. 5 is a cross sectional view of the sleeve components of the locking stick joint of the present invention; 
     FIGS. 6 (A-G) through  12  (A-J) represent cross sectional views of an alternative isolation system in various stages of operation of the present invention; 
     FIGS. 13 through 15 represent enlarged cross sectional views of the alternative isolation system of the present invention; and 
     FIG. 16 represents a cross sectional view of an additional alternative isolation system of the present invention. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     Referring now to the drawings, the details of preferred embodiments of the present invention are graphically and schematically illustrated. Like elements in the drawings will be represented by like numbers, and similar elements will be represented by like numbers with a different lower case letter suffix. 
     Referring now to FIGS. 1A and 1B, a first embodiment of the invention is illustrated in which depict a cross sectional view of a service tool  10  in combination with an isolation string  20  inside of a well casing  5 . The service tool  10  and isolation string  20  are designed to work in tandem to perform completion functions and leave the production zone in an isolated state for subsequent production. The service tool  10  comprises a crossover assembly  40 , a fracture port assembly  41 , and an activation tool. In embodiment depicted in FIGS  1 A and  1 B, the activation tool is a locking slick joint  30 . Significant characteristics of this first embodiment are that there is no wash pipe which extends below the service tool  10  and through the isolation string  20 . Also, the locking slick joint  30  may be manipulated to open a through channel which allows fluid to travel from below the service tool  10 , up through the channel in the service tool  10 , and up through the service string. This prevents the service tool  10  from becoming “stuck” in the isolation string  20  after closure of the concentric isolation sleeve  21  due to vacuum pressure below the service tool  10 . The service tool  10  is first described and then the isolation string  20 . 
     Near the top of the significant portion of the service tool  10 , there is the crossover assembly  40  which is typical of those known in the art. An example is disclosed in Rebardi et al. U.S. Pat. No. 5,865,251. The crossover assembly  40  provides control of fluid flow paths in cooperation with other components inserted into the wellbore. It has an inner pipe  44  that extends for a portion of the proximal part of an outer pipe  46 . The proximal end of the outer pipe  46  has outer holes  47  which allow fluid communication from the exterior of the outer pipe  46  to the interior. The inner pipe  44  defines a central lumen  48  which communicates through an aperture  45  to the exterior of the outer pipe  46  at a location intermediate the length of the outer pipe  46 . As is known, the cross over assembly is used during gravel pack operations to deposit “gravel” between a production screen  26  of the isolation string  20  and perforations  52  in the well casing  5 . 
     The fracture port assembly  41  defines a fracture port chamber  42  in communication with a plurality of fracture ports  43  which provide fluid communication with the locking slick joint  30 . The fracture port assembly  41  may be shifted between an open position and a closed position. In the open position, fluid is allowed to flow through the fracture ports  43  during circulation of the gravel pack fluids. When it is desirable to fracture a production zone, the fracture port assembly  41  is shifted to a closed position so that the fracture ports  43  are closed. In the closed position, high pressure may be generated below the fracture port assembly  41  to fracture a production zone, as is well known. 
     The locking slick joint  30  comprises a locking slick joint outer sleeve  31 , a locking slick joint female sleeve  32 , and a locking slick joint male sleeve  33 . The locking slick joint outer sleeve  31  is positioned around the outer radius of the locking slick joint female sleeve  32  and secures the locking slick joint female sleeve  32  around the locking slick joint male sleeve  33 . A recess  35  is located on the outer radius of the locking slick joint male sleeve  33  formed to receive the mating ledge  34 . The mating ledge  34  is located along a proximal, open end  36  of the locking slick joint female sleeve  32 . Attached to the distal, closed end  37  of the locking slick joint female sleeve  32  is the locking slick joint tip  38 . The locking slick joint male sleeve  33  is hollow in the inside and defines an annular passage  60 . At the center of the annular passage  60  there is a locking slick joint plug  61  which extends, in the run-in position (see FIGS.  1 A and  1 B), from the distal end of the service tool  10  where the locking slick joint  30  is attached, through the center of the annular passage  60 , and through a tip aperture  62 . Within the tip aperture  62  there are tip seals  63  which completely seal the locking slick joint tip  38  when the locking slick joint plug  61  is in the tip aperture  62 . In the extended position (see FIGS. 2A and 2B) the locking slick joint  30  provides a fluid passage from below the service tool  10  to above, as is described more fully below. 
     The isolation system of the present invention is comprised of an isolation string  20 , a concentric isolation sleeve  21 , an upper packer  18 , and a lower packer  19 . The isolation string  20  is formed to have an outer diameter capable of being positioned inside the well casing  5  and formed to have an inner diameter capable of receiving the service tool  10  inside the inner diameter of the isolation string  20 . The isolation string  20  is comprised of an upper seal bore  15 , a lower seal bore  16 , an isolation pipe  23  a production screen  26 , and a base seal bore  17 . The upper packer  18  is positioned concentrically around the upper seal bore  15  of the isolation string  20 , and the lower packer  19  is positioned concentrically around the base seal bore  17  of the isolation string  20 ; on opposite ends of the isolation string  20 . The upper packer  18  and the lower packer  19  prevent fluid flow adjacent each packer in the region bounded by the outer radius of the isolation string  20  and the inner radius of the casing  5 . The concentric isolation sleeve  21  is comprised of an isolation string collar  22 , which is axially connected to an isolation tube  29 . Affixed to the inner radius of the concentric isolation sleeve  21  are isolation sliding sleeves  24 . Positioned on the outer radius of the isolation tube  29  are exterior concentric seal assemblies  28 . The exterior concentric seal assemblies  28  are formed to provide a sealing surface between the outer radius of the isolation tube  29  and downhole of the base seal bore  17 . The concentric isolation sleeve  21  is positioned within the isolation string  20 , proximate to the production screen  26 . 
     FIGS. 3 and 4 illustrate an alternative concentric isolation sleeve  21   a . The alternative concentric isolation sleeve  21   a  is comprised of an isolation tube  29   a  which is open at one end, and connected at its other end to an isolation string collar  22   a . Seal assemblies  28   a  are positioned on the outer radius of the isolation tube  29   a . A glass disk  39  is positioned inside the isolation tube  29   a  and prevents fluid flow through the isolation tube  29   a . The alternative concentric isolation sleeve  21   a  is typically used on the producing zone that is located furthest downhole, i.e. no additional hydrocarbon producing zones exist past the point where the alternative concentric isolation sleeve  21   a  will be positioned. 
     Operation of the locking slick joint tool is typically performed during a gravel pack operation. Since gravel pack operations are well known in the art, a detailed description of gravel pack operations will not be provided herewith. A description of such operations is provided in Rebardi et al., U.S. Pat. No. 5,865,251, incorporated herein by reference. After gravel pack operations have been completed, and it is desired to isolate the section of the well that has been gravel packed or fractured, the locking slick joint tool is adjusted from the run-in position to the set or extended position. 
     The change in position is accomplished by retracting the service tool  10  up the well hole until the locking slick joint outer sleeve  31  contacts a shoulder of the lower seal bore  16 . Additional force is then applied in retracting the service tool  10  until the locking slick joint outer sleeve  31  is moved along the locking slick joint female sleeve  32  towards the locking slick joint tip  38 . Moving the locking slick joint outer sleeve  31  towards the locking slick joint tip  38  allows the mating ledge  34  of the locking slick joint female sleeve  32  to move out of the recess  35  formed on the outer radius of the locking slick joint male sleeve  33 . Once the mating ledge  34  of the locking slick joint female sleeve  32  is moved out of the recess  35  the force being applied to retract the service tool  10  will slide the locking slick joint female sleeve  32  along the locking slick joint male sleeve  33 , thereby extending the locking slick joint tool into the set position. The locking slick joint  30  is locked in the set position when the mating ledge  34  snaps into upper set recess  64  (see FIG.  5 ). The locking slick joint  30  is further held in the set position by lower mating ledge  65  which snaps into lower set recess  66 . The lower mating ledge  65  is firmly held in the lower set recess  66  by the locking slick joint outer sleeve  31  when the outer sleeve  31  is moved into a lock position (see FIG.  2 B). The locking slick joint outer sleeve  31  is shown in an unlock position in FIG.  5 . 
     If it is desired not to actuate the concentric isolation sleeve  21  after the locking slick joint  30  has been placed in the set position, the locking slick joint  30  may be returned to its original run-in position. This is done by pulling up on the service tool  10  to draw the locking slick joint  30  up through the lower seal bore  16  and slacking back off to push the locking slick joint  30  back through the lower seal bore  16  from above. Since the locking slick joint outer sleeve  31  indicates on the lower seal bore  16 , this action slides the outer sleeve  31  from a lock position (see FIG. 2B) to an unlock position (see FIG.  5 ). As the locking slick joint  30  moves further through the lower seal bore  16 , this action dislodges the mating ledge  34  and lower mating ledge  65  from the upper set recess  64  and the lower set recess  66 , respectively. The locking slick joint female sleeve  32  then slides axially along the locking slick joint male sleeve  33  until the mating ledge  34  snaps into recess  35 . The locking slick joint outer sleeve  31  then squeezes through the lower seal bore  16  and the locking slick joint  30  is fully returned to the run-in position. 
     If it is desired to actuate the concentric isolation sleeve  21 , the locking slick joint  30  is placed in the set position as described above. Once the locking slick joint tool is in the set position (see FIGS.  2 A and  2 B), the service tool  10  is then moved downward towards the concentric isolation sleeve  21 . As seen in FIGS. 2 and 4, the locking slick joint tip  38  contacts the isolation string collar  22  (or  22   a ) and forces the concentric isolation sleeve  21  downward until the exterior concentric seal assemblies  28  are in contact with the base seal bore  17 . In the case of the alternative embodiment, the exterior concentric seal assemblies  28   a  contact the intermediate seal bore  17   a . Engaging the exterior concentric seal assemblies  28  (or  28   a ) with the base seal bore  17  (or intermediate seal bore  17   a ) prevents flow from the perforations  52  into the well bore  84 , thereby isolating the hydrocarbon producing zone adjacent the perforations  52 . 
     With the production zone completely scaled, the service tool  10  is withdrawn from the isolation string  20  by simply retracting the service string up through the wellbore. Since the locking slick joint plug  61  is withdrawn from the tip aperture  62  when the locking slick joint  30  is in the set position  30 , a fluid flow channel is created within the service tool  10 . As the service tool  10  is withdrawn, fluid flows from outside the service tool  10 , above the upper packer  18 . In particular, fluid flows through the outer holes  47  to the interior of the outer pipe  46  of the crossover assembly  40 . This fluid then flows to the fracture port chamber  42  of the fracture port assembly  41 . Next, the fluid passes through the fracture ports  43  (if the ports are open as shown in FIG. 2A) and into the annular passage  60  of the locking slick joint  30 . Finally, the fluid flows from the annular passage  60 , through the tip aperture  62 , and into the space within the closed concentric isolation sleeve  21  (see FIG.  2 B). This prevents the service tool  10  from “sticking” in the isolation string  20  due to a vacuum created below the service tool  10  when removal of the service string is attempted. 
     If hydrocarbons are later desired to be produced from the zone adjacent the perforations  52  the isolation sliding sleeves  24  can be moved until the isolation sliding sleeve apertures  25  are in alignment with the isolation tube apertures  27 . If the perforations  52  are located next to the alternative concentric isolation sleeve  21   a  then the glass disk  39  will can be broken thus allowing fluid flow through the glass disk  39  into the well bore  84 . The glass disk  39  may be broken by hydraulic pressure, dropping a ball, acoustics, intelligent methods, etc. 
     At any time after the production is isolated with the isolation string  20  as described above, the isolation string  20  of the first embodiment of the invention may be withdrawn from the wellbore with a separate retrieval tool which run into the wellbore on a subsequent trip. 
     FIGS. 6 (A-G) through  12  (A-J) depict, in cross sectional view, a second embodiment of the invention. In this embodiment, the activation tool is a release tool  100 . This second embodiment also comprises a hydrostatic chamber  104  which enables movement of the isolation sleeve  102  from an open to a closed position upon release of the sleeve by the release tool  100 . A trigger is used to hold the isolation sleeve  102  in an open position, until the trigger is activated to allow the hydrostatic chamber  104  to push the isolation sleeve  102  into a closed position. FIGS. 6A through 6G illustrate the invention at the initial stage of operation. FIGS. 7A through 7G illustrate the invention at a subsequent stage of operation and so forth. These stages of operation will be described more fully below. Briefly, the isolation sleeve  102  is shown in an open position in FIGS. 10E-10J and shown in a closed position in FIGS. 11E-11J. 
     The isolation system of the second embodiment is comprised of an isolation string  101 , and a service tool  138 . Like the first embodiment, the service tool  138  and isolation string  101  are run into the wellbore simultaneously. Once the production screen  26  of the isolation string  101  is adjacent the perforated portion of the casing, the isolation string  101  is set in the casing with an upper packer  18  and a lower packer (not shown). 
     In the second embodiment of the invention, the service tool  138  is similar to that of the first embodiment in that the upper or proximal parts comprise devices necessary for the gravel pack processes. In a lower or more distal portion of the service tool  138 , the release tool  100  is attached (see FIG.  6 C). The release tool  100  is connected to the service tool  138  by a release tool shear pin  142 . Of course, since the release tool  100  is connected to the service tool  138 , the release tool  100  is positioned within the isolation string  101  in the run-in position and during gravel pack procedures. In the embodiment shown, a wash pipe  112  extends from the distal or lower end of the service tool  138 . In the run-in position, the end of the wash pipe  112  extends to about the bottom of the production screen  26 ; the remainder of the service tool  138  is above the production screen  26 . 
     The isolation string  101  is secured to the well casing (not shown) by packers in a manner that is usual and customary in the art. In a lower portion of the isolation string  101  there is a production screen  26  (see FIGS.  8 G- 8 H). Inside the isolation string  101  and adjacent the production screen  26 , there is an isolation sleeve  102  (see FIGS.  8 E- 8 H). The isolation sleeve  102  comprises a piston  126 , a hydraulic dampener  118 , seal tubing  124 , and a wrap screen  128 . All of these parts are axially connected to form an elongated tubular section. 
     In this embodiment, the trigger is comprised of a piston collar  106  that is secured to the upper portion of the piston  126 , and is positioned on the outer radius of the piston  126 , thus forming a band between the isolation string  101  and the piston  126  (see FIGS.  6 E- 10 E). A more detailed drawing of the piston collar  106  is shown in FIG. 13. A lower section  106   a  of the piston collar  106  is completely cylindrical while the upper portion  106   b  of the piston collar  106  has a plurality of upwardly projecting fingers  107 . At the upper distal ends of the fingers  107 , the fingers  107  each have a head  107   a  with threads thereon which mate with threads on shoulder  105  of the isolation string  101 . The heads  107   a  of the fingers  107  are impinged against the shoulder  105  of the isolation string  101  by a pop lock  108 . By impinging the heads  107   a  against the isolation string  101 , the isolation sleeve  102  is secured to the isolation string  101 , thereby preventing axial movement of the isolation sleeve  102  with respect to the isolation string  101 . If the pop lock  108  is moved vertically from within the fingers  107  of the piston collar  106 , the heads  107   a  are released and the piston collar  106  and the rest of the isolation sleeve  102  connected thereto are free to slide within the isolation string  101 . The lower portion  106   a  of the piston collar  106  occupies a space between the isolation string  101  and the piston  126 . Seals  109  are placed between the piston collar  106  and the isolation string  101 , and between the piston  126  and the piston collar  106 . 
     The outside diameter of the piston  126  is smaller than the adjacent inside diameter of the isolation string  101  so that the space between forms a hydrostatic or atmospheric chamber  104  (see FIGS.  8 E- 8 F). The top end of the hydrostatic chamber  104  is sealed by the piston collar  106  as described above. The lower end of the hydrostatic chamber  104  is sealed by a ring seal  119  (see FIGS.  6 F- 12 F). The ring seal  119  has seals on its inner diameter and outer diameter surfaces for sealing against the piston  126  and the isolation string  101 , respectively. Since the piston  126  and the isolation string  101  are assembled at the surface before the system is lowered into the wellbore, the air inside the hydrostatic chamber  104  is at or close to standard atmospheric pressure. Once lowered into the wellbore, surrounding pressures become significantly greater than standard atmospheric pressure. This pressure differential provides a closure force for sliding the isolation sleeve  102  into a closed position as described below. 
     The seal tubing  124  of the isolation sleeve  102  defines the section of the isolation sleeve  102  that is downhole of the ring seal  119  and “seals” the inside of the isolation sleeve  102  from fluid flow through the production screen  26  (see FIG.  8 F- 8 H). According, a particular section of the isolation sleeve  102  could be defined as the piston  126  during one stage of operation, and defined as seal tubing  124  during a subsequent stage of operation (see FIG.  8 F- 12 F). Below the seal tubing  124 , the wrap screen  128  extends to form the lowest most distal end of the isolation sleeve  102 . In the open position, seal tubing seals  130  engage the seal surface  157  to ensure that all production fluids flow through the wrap screen  128 . A hydraulic dampener  118  is located below the hydrostatic chamber  104  between the seal tubing  124  and the isolation string  101  (see FIGS.  8 G- 12 G). The hydraulic dampener  118  serves to regulate the speed at which the isolation sleeve  102  closes upon release by the pop lock  108 . The hydraulic dampener  118  comprises two parts, a dampening ring  151  and a lock ring  152 , both of which are secured to the outer diameter of the seal tubing  124 . When locked, these rings are unable to slide in the axial direction relative to the seal tubing  124 . When locked in the position shown in FIGS. 8G-12G, fingers with heads (similar to the piston collar  106  described above) of the dampening ring  151  are positioned so that the heads protrude into an annular slot in the outside diameter of the seal tubing  124 . The lock ring  152  is placed around the heads of the dampening ring  151  to secure the heads in the slot. The outer diameters of the dampening and lock rings  151  and  152  are slightly smaller than the inside diameter of the adjacent portion of the isolation string  101 . This difference in diameters allows a small amount of fluid to pass from below the hydraulic dampener  118  to above while the isolation sleeve  102  slides from the open to the closed position. Since fluid flow is restricted through the narrow annular space, movement of the isolation sleeve  102  is restricted. This reduces opportunities for the isolation sleeve  102  to become damaged during closure. 
     The process for isolating the production zone after the gravel pack operation will now be described. 
     FIGS. 6A through 6G illustrate as position of the service tool  138  relative to the isolation string  101  immediately after “gravel” is packed around the outside of the production screen  26 . In fact, since the service tool  138  has been pulled up relative to the isolation string  101 , the gravel pack sleeve  153  is closed (see FIG.  6 B). 
     In FIGS. 7A through 7G, the service tool  138  is shown in a reversing position. As is known in the art, completing fluid is cycled down the outside of the service tool  138  to flush the gel/propant of the gravel pack procedure back up through the inside of the service tool  138 . In this position, gravel pack collet  154  has indicated on a gravel packer shoulder  155  so the operator will know the exact location of the service tool  138 . After completion of the reversing procedure, the operator pulls the service tool  138  further up in the wellbore until the release tool indicator collet  144  indicates against the seal port shoulder  136  (see FIG.  7 C). When the release tool indicator collet  144  contacts the seal port shoulder  136  the service tool  138  operator is informed as to the location of the release tool  100 . Continued upward force on the service tool  138 , against the unmoving seal port  136 , causes the release tool shear pin  142  to fracture thereby freeing the release tool  100  from the service tool  138  allowing the release tool  100  to “free float” inside the well bore (see FIG.  8 D). 
     The position of the devices immediately after release of the release tool  100  is shown in FIG. 8A-8J. Due to the force of gravity, the release tool  100  has fallen in the space between the wash pipe  112  and the isolation string  101 . 
     In FIGS. 9A-9J, the release tool  100  is shown reattached to the service tool  138 . To reattach the release tool  100  to the washpipe  112  of the service tool  138 , the service tool  138  is raised until a wash pipe collet  114  contacts a release tool capture collet  116  (see FIG.  9 C). The service string  138  is raised until the release tool indicator collet  144 , which is on the outside diameter of the release tool  100 , indicates against the seal port shoulder  136  on the isolation string  101 . Continued upward movement of the service tool  138  results in the wash pipe collet  114  fully mating with the release tool capture collet  116  to secure the release tool  100  to the wash pipe  112 . This position is shown in greater detail in FIG.  14 . 
     In FIGS. 10A-10J, the service tool  138  is again set down in the wellbore to activate the trigger. In this embodiment, the service tool  138  is lowered to a position where the release tool  100  is inserted into the upper rim of the pop lock  108  (see FIG.  10 E). The service tool  138  comprises a release tool latch  140  which contacts the pop lock  108  (FIG.  10 E). The upper ring of the pop lock  108  has a pop lock lip  111  which is engaged by a release tool latch  140  on the release tool  100 . When the release tool latch  140  is inserted into the pop lock lip  111 , the parts snap into engagement so that the opposing shoulders of the parts prevent slippage of the parts when the service tool  138  is again pulled back up the wellbore. These parts are shown in greater detail in FIG.  14 . With the release tool  100  and the pop lock  108  engaged, the operator closes the isolation sleeve  102  to isolate the gravel packed production zone by pulling the service tool  138  further up the wellbore. This action pulls the pop lock  108  upward relative to the piston collar  106  to release the fingers  107  of the piston collar  106  as described above. Shearing the pop lock shear pin  110  disengages the pop lock  108  from the isolation string  101  thus allowing the pop lock  108  to slide upward with the release tool  100 . The isolation sleeve  102  is forced downward by gravitational forces in addition to the pressure differential between the wellbore pressure and the standard atmospheric pressure inside the hydrostatic chamber  104 . 
     In alternative embodiments, a trigger is activated by any means known in the art. For example, different mechanical tools may be used to release a latch sleeve to unlock the isolation sleeve similar to the trigger shown in the second embodiment of the invention. Next, hydraulic pressure sensitive devices may be used as a trigger so that the operator controls the trigger through downhole pressure differentials. Further, a ball seat trigger is possible so that the trigger is activated by a dropped ball. A still further illustrative embodiment uses intelligent methods, such as acoustics, pressure signals, battery packs, electronics, etc. to communicate with and activate a trigger. Examples of intelligent methods are disclosed in patent disclosures WO 96/10123 and U.S. Pat. No. 5,558,153, incorporated herein by reference. 
     Referring again to the second embodiment shown in FIGS. 11A-11J, the tool positions are shown immediately after the released isolations sleeve  102  has moved to a closed position. At the end of the isolation sleeve&#39;s  102  downward stroke threads located on lower, more distal end of the outside diameter of the piston collar  106  mate with threads formed on the inner radius of the C-ring  134  (see FIG.  11 F). Mating the threads on the outer radius of the piston collar  106  with the threads on the inner radius of the C-ring  134  secure the isolation sleeve  102  in the isolating position. In the closed position, lower seals  156  on the seal tubing  124  engage with the seal surface  157  in the isolation string  101  (see FIG.  11 I). This isolates the lower end of the production screen  26  while the upper end is isolated by the ring seal  119  (see FIG.  11 F). In the isolating position, the isolation sleeve  102  prevents fluid flow from the production zone through the production screen  26 . 
     With the isolation sleeve  102  in the closed position, the service tool  138  is ready for removal from the isolation string  101 . In this second embodiment of the invention, the washpipe  112  is long enough for the service tool seal  160  to clear the upper packer  18  (see FIG. 10A) when the release tool  100  engages the pop lock  108  (see FIG.  10 E). When the isolation sleeve  102  becomes closed, this clearance prevents a vacuum from developing below the service tool  138 . As noted above, if a vacuum develops below the service tool  138 , the service tool  138  will be effectively stuck in the isolation string  101 . 
     In FIGS. 12A-12J, the isolation sleeve  102  is again shown in a closed position. Further, the service tool  138  is removed and a removal tool  120  is inserted in the wellbore (see FIG.  12 F). Should it become necessary or desirable to raise the isolation sleeve  102  in the future, a piston collet  103  is provided on the inner radius of the top of the piston  126  for mating with a removal tool  120 . Of course, if the isolation sleeve  102  is to be removed, the hydraulic dampener  118  must be unlocked from the isolation sleeve  102 . This is accomplished by pulling the isolation sleeve  102  upward relative to the isolation string  101  until the lock ring  152  indicates against the ring seal  119 . Upon indication, the lock ring  152  will slide relative to the dampening ring  151  to release the dampening ring  151  from the isolation sleeve  102 . The isolation sleeve  102  may then be taken from the wellbore. 
     FIG. 16 depicts a third embodiment of the invention in cross sectional view. While this embodiment uses a hydrostatic chamber to close the isolation sleeve  202  as described above, it does not utilize a release tool  100 . Instead, the alternative pop lock  208  has a relatively smaller inner diameter. Similar to the second embodiment, this embodiment is assembled at the surface before the service tool and isolation string is placed in the wellbore. This prior assembly allows the wash pipe (not shown) to extend below the alternative pop lock  208 . The wash pipe of this embodiment is equipped with a wash pipe latch  240  (shown in FIG. 14) which catches the alternative pop lock  208  as the wash pipe  112  is pulled up in the wellbore. In all other respects, this embodiment is the same as the second embodiment. 
     When it is desirable to produce from the isolated zone, a production string is inserted in the wellbore to mate with the isolation string  101 . Then the isolation sleeve  102  may be perforated as is know in the art, or sleeve valves placed on the seal tubing  124  may be operated from a closed to open positions. Sleeve valves are described in U.S. Pat. No. 5,865,251, the disclosure of which is incorporated herein by reference. 
     According to a fourth embodiment of the invention, there is provided a service tool  10  similar to that of the first embodiment (see FIGS.  1 A- 2 B). At the distal end of the service tool  10  there is a locking slick joint  30  similar to that of the first embodiment. However, this fourth embodiment of the invention has a release tool  100  attached to the distal end of the locking slick joint  30 . The isolation sleeve  102  comprises a piston  126 , a hydraulic dampener  118 , and seal tubing  124  as in the second embodiment. Further, the piston  126  is driven by a hydrostatic chamber  104  as described above. Therefore, rather than pushing the isolation sleeve  102  with the locking slick joint  30 , the isolation sleeve  102  is activated by lowering the release tool  100  with the locking slick joint  30  to trip a trigger. Of course, the trigger releases the piston  126  which pushes the isolation sleeve  102  to a closed position. An advantage of this embodiment is that there is no need for a wash pipe  112  to extend below the locking slick joint  30 . Also, the reliability of the hydrostatic chamber  104  ensures complete closure of the isolation sleeve  102 . It is also possible to use various isolation sleeves with this fourth embodiment of the invention, including: the concentric isolation sleeve  21  shown in FIG.  1 B and having isolation sliding sleeves  24 , and the concentric isolation sleeve  21   a  having a glass disk  39  shown in FIG.  3 . 
     According to a fifth embodiment of the invention, the service tool  138  has a configuration similar to that shown relative to the second embodiment. In this fifth embodiment, the washpipe is removed and the service tool  138  is modified to allow fluid to pass through the service tool  138  immediately subsequent closure of the isolation sleeve  102  by a hydrostatic chamber  104 . The modification could be to provide a mechanism to open the fracture valve  161  (see FIG. 7B) when the release tool  100  is positioned adjacent the pop lock  108 . Other means for opening a passage within the service tool  138  are also possible as known by persons of skill in the art. 
     The present invention, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes in the details of procedures for accomplishing the desired results will readily suggest themselves to those skilled in the art, and which are encompassed within the spirit of the invention and the scope of the appended claims. 
       5  well casing 
       10  Service tool 
       15  upper seal bore 
       16  lower seal bore 
       17  base seal bore 
       17   a  Intermediate seal bore 
       18  upper packer 
       19  lower packer 
       20  Isolation string 
       21  Concentric isolation sleeve 
       22  Isolation string collar 
       24  Isolation sliding sleeves 
       25  Isolation sliding sleeve apertures 
       26  Production screen 
       27  Isolation tube apertures 
       28  Exterior concentric seal assemblies 
       29  Isolation tube 
       30  Locking slick joint 
       31  Locking slick joint outer sleeve 
       32  Locking slick joint female sleeve 
       33  Locking slick joint male sleeve 
       34  Mating ledge 
       35  Recess 
       36  open end 
       37  closed end 
       38  Locking slick joint tip 
       39  glass disk 
       40  Crossover assembly 
       41  Fracture port assembly 
       42  Fracture port chamber 
       43  Fracture ports 
       44  inner pipe 
       45  Aperture 
       46  outer pipe 
       47  outer holes 
       48  central lumen 
       52  Perforations 
       60  Annular passage 
       61  Locking slick joint plug 
       62  tip aperture 
       63  tip seals 
       64  upper set recess 
       65  lower mating ledge 
       66  lower set recess 
       84  well bore 
       100  Release tool 
       101  Isolation string 
       102  Isolation sleeve 
       103  piston collet 
       104  Hydrostatic chamber 
       105  Shoulder 
       106  piston collar 
       106   a  lower section 
       106   b  upper portion 
       107  Fingers 
       107   a  Head 
       108  poplock 
       109  Seals 
       110  pop lock shear pin 
       111  pop lock lip 
       112  wash pipe 
       114  wash pipe collet 
       116  Release tool capture collet 
       118  Hydraulic dampener 
       119  ring seal 
       120  Removal tool 
       124  seal tubing 
       126  Piston 
       128  wrap screen 
       130  seal tubing seals 
       134  C-ring 
       136  seal port shoulder 
       138  Service tool 
       140  Release tool latch 
       142  Release tool shear pin 
       144  Release tool indicator collet 
       151  Dampening ring 
       152  lock ring 
       153  gravel pack sleeve 
       154  gravel pack collet 
       155  gravel packer shoulder 
       156  lower seals 
       157  seal surface 
       160  Service tool seal 
       161  Fracture valve 
       202  Isolation sleeve 
       208  Alternative pop lock 
       240  wash pipe latch