Abstract:
A well packing system and method for operating a well packing system wherein an isolation string assembly has a lower circulation valve with lateral flow ports that are operated to an open position without the use of shifters on a wash pipe. The isolation string assembly is incorporated into a well packing assembly within a wellbore and includes an upper sleeve tool that provides selective production of fluids through the frac pack assembly. In addition, the isolation string includes a lower circulation valve having a sliding sleeve that is shiftable from an open position to a closed position upon receipt of a suitable pressure differential. This configuration is particularly valuable for permitting monitoring of pressure or other conditions in the annulus of the wellbore portion being packed during packing operations. Further, the lower circulation valve tool can be used to selectively allow fluid returns during the packing operation.

Description:
[0001]     This application is a continuation of U.S. patent application Ser. No. 11/117,982 filed Apr. 29, 2005. 
     
    
     BACKGROUND OF THE INVENTION  
       [0002]     1. Field of the Invention  
         [0003]     The invention relates generally to isolation assemblies used in fracturing/gravel packing, or “frac pack,” systems.  
         [0004]     2. Description of the Related Art  
         [0005]     Because hydrocarbon production wells are often drilled into unconsolidated formations, sand and fines from those formations will tend to enter the production tubing along with the produced fluids. To prevent this, it has become relatively standard practice to run a fracturing and gravel packing treatment, commonly referred to as a “frac pack,” within the wellbore prior to production. During the fracturing treatment, the production zone is stimulated by creating fractures in the formation rock and flowing proppant material into the fractures to keep the fractures from closing. During the gravel packing operation the annulus surrounding the screen assembly is filled with gravel or another granulated material. This material forms a barrier around the screen and provides a filter to help prevent sand and fines from the formation from entering the production tubing string.  
         [0006]     A conventional frac pack system includes a screen assembly that is placed in the wellbore near the unconsolidated formation. The screen assembly radially surrounds a wash pipe, and both the screen assembly and wash pipe are connected, at their upper ends, to a service tool. The usual service tool includes a production packer and a cross-over tool, which are connected to a work string that extends downwardly from the surface. The work string is used to position the screen assembly in the wellbore. Packers provide fluid sealing. The frac pack system can be placed into a “squeeze” configuration, wherein no fluids return to the surface. In this configuration, fracturing fluid is passed through the cross-over tool, into the annulus and then into the formation. Alternately, the frac pack system can be placed into a “circulation” position to allow flow through the wash pipe back to the surface. Gravel packing slurry is then flowed in through the cross-over tool to gravel pack the annulus around the screen assembly. When gravel packing is completed, the service tool is detached from the screen assembly and withdrawn from the wellbore, leaving the gravel packed screen assembly and packer in place. Further details concerning the construction and operation of frac pack systems in general are provided in U.S. Pat. No. 6,789,623 issued to Hill, Jr. et al. This patent is owned by the assignee of the present invention and is incorporated herein by reference.  
         [0007]     Traditional frac pack systems have utilized an isolation string that is installed inside the production screen at the surface and is controlled in the wellbore by an inner service string. Typically, the isolation string has two or more sliding sleeve valves that are shifted between open and closed positions mechanically by a shifting tool carried on the wash pipe. One problem with the use of wash pipe-based mechanical shifters is that the wash pipe is relatively weak and provides a point of potential failure where it passes through the isolation string. Additionally, it is time consuming, and thus costly, to have to make up a string of wash pipe to operate the sleeve valves.  
         [0008]     One alternative to the use of wash pipe to operate the sleeve valves in the isolation string is described in U.S. Pat. No. 6,397,949 issued to Walker et al. In Walker&#39;s system, the isolation string uses one or more pressure activated control valves that are moveable between three functional positions: closed-locked, closed-unlocked, and open-unlocked. It is an intended feature of Walker&#39;s system to ensure simultaneous opening of all of the valves within the isolation string. Walker contends that, if all the valves did not open at once, a single open valve would eliminate the pressure differential needed to open all of the other sleeves. Thus, Walker&#39;s system does not appear to permit conditions of the gravel packing operation to be monitored through the flowbore during the gravel packing operation when all the valves are closed.  
         [0009]     Another wash pipe-less system is described in U.S. Patent Publication No. US 2003/0178198 A1 (Turner et al.). In the described system, the isolation string includes a pressure activated control valve and an object activated control valve. These control valves are each operated in a different manner. The object activated control valve is operated using a ball or other object that is dropped into the flowbore. The pressure activated control valve (PACV) is initially run into the wellbore in a closed-locked configuration. When access to a nearby production zone is desired, a predetermined pressure differential is applied between the casing annulus and the internal annulus to shift an inner sleeve in the PACV to a closed-unlocked configuration. Subsequently, the PACV is moved to an open-unlocked configuration by a reduction in fluid pressure.  
         [0010]     The present invention addresses the problems of the prior art.  
       SUMMARY OF THE INVENTION  
       [0011]     The invention provides an improved frac pack system and method for operating a frac pack system. In further aspects, the invention provides an improved isolation string assembly having a lower circulation valve with lateral flow ports that are operated to an open position without the use of shifters on a wash pipe. In a preferred embodiment, the isolation string assembly is incorporated into a frac pack assembly within a wellbore and includes an upper sleeve tool that provides selective circulation of fluids through the frac pack assembly. In addition, the isolation string includes a lower circulation valve having a sliding sleeve that is shiftable from an open position to a closed position upon receipt of a suitable pressure differential. This configuration is particularly valuable for permitting monitoring of pressure or other conditions in the annulus of the wellbore portion being packed during frac pack operations. Further, the lower circulation valve tool can be used to selectively allow fluid returns prior to production occurring.  
         [0012]     In operation, the frac pack system with isolation string assembly is placed into a wellbore and landed within a packer. A production packer on the frac pack system is set and tested. The frac pack assembly is placed into the squeeze configuration and, thereafter, a circulating configuration. When circulation is completed, the annulus above the production packer is evacuated. The setting tool portion of the frac pack system is then partially withdrawn so that reverse circulation can occur. Next, the lower circulating valve is shifted to its closed position. The setting tool portion of the frac pack system is withdrawn and a standard production tubing string is run into the screen assembly. The upper sleeve tool is then shifted to an open position so that production can occur. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0013]     For a thorough understanding of the present invention, reference is made to the following detailed description of the preferred embodiments, taken in conjunction with the accompanying drawings, wherein like reference numerals designate like or similar elements throughout the several figures of the drawings and wherein:  
         [0014]      FIG. 1  is a side, cross-sectional view of an exemplary frac pack system constructed in accordance with the present invention with the service tool portion being run into a wellbore.  
         [0015]      FIG. 2  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now with the production packer having been set.  
         [0016]      FIG. 3  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now in the squeeze position.  
         [0017]      FIG. 4  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now in a circulating configuration.  
         [0018]      FIG. 5  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now in an evacuation configuration.  
         [0019]      FIG. 6  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now in a reverse circulation configuration.  
         [0020]      FIG. 7  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now with the lower circulation valve of the isolation string in the process of being closed.  
         [0021]      FIG. 8  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now with an upper completion string having been run.  
         [0022]      FIG. 9  is a side, cross-sectional view of the frac pack system shown in  FIG. 1 , now with production occurring.  
         [0023]      FIG. 10  is a side, partial cross-sectional view of an exemplary lower circulation valve used in the frac pack system shown in  FIGS. 1-9 .  
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0024]      FIGS. 1-9  depict an exemplary frac pack system, generally shown at  10 , that is being operated within a wellbore  12 . The wellbore  12  with casing  13  is disposed within the earth  14  through a hydrocarbon-bearing formation  16  from which it is desired to produce. Perforations  18  penetrate the surrounding formation  16 . A packer  20  has previously been run and set within the wellbore  12  at the lower end of the formation  16 . In  FIG. 1 , the frac pack system  10  is being lowered into the wellbore  12  on a work string  22  to be landed into the packer  20 . The frac pack system  10  includes a setting tool of a type known in the art and shown schematically at  24 . A production packer  26  is affixed to the lower end of the setting tool  24 . The production packer  26  may be of any known type suitable for use in a frac pack application. One suitable packer for use as the production packer  26  is the model “SC-2” packer that is available commercially from Baker Oil Tools of Houston, Tex. During run-in, as illustrated in  FIG. 1 , the production packer  26  is in an unset position.  
         [0025]     Below the production packer  26  is a blank pipe  28  having an interior axially sliding sleeve  30  for selectively opening lateral fluid ports  32  in the blank pipe  28 . A gravel pack cross-over tool  34  is located radially inside of the blank pipe  28  and carries a shifter  160  for opening or closing the sliding sleeve device  30 . The cross-over tool  34  includes a reduced diameter fluid flow path  38  with a ball seat  40  within.  
         [0026]     The setting tool  24 , cross-over tool  34 , reduced diameter flow path  38 , and ball seat  40  collectively form the service tool portion  42  of the frac pack system  10 . The service tool portion  42  is used to run a solids placement portion  44  of the system  10  into the wellbore  12 , and land it into the lower packer  20 . The solids placement portion  44  of the frac pack system  10  includes the blank pipe  28 , sleeve  30 , cross-over tool  34 , and sliding sleeve shifter  160 . Additionally, the solids placement portion  44  includes an isolation string  46  with a radially surrounding screen  48 . Secured to both the isolation string  46  and the screen  48  is a landing nipple  50  that is shaped and sized to seat into lower packer  20 .  
         [0027]     The isolation string  46  includes an upper sleeve tool  52  and a lower circulation valve  54 . The upper sleeve tool  52  is preferably a CMP™ Defender non-elastomeric sliding sleeve (product family no. H81082), which is available commercially from Baker Oil Tools of Houston, Tex. The upper sleeve tool  52  is a sliding sleeve valve assembly that allows selective fluid communication between its interior flowbore  56  and the annulus  58  that is formed between the isolation string  46  and the surrounding screen  48 . It is noted that the upper sleeve tool  52  has three operating positions: closed-locked, closed-unlocked, and open-unlocked. When run into the wellbore  12 , the upper sleeve tool  52  is in a closed-locked position.  
         [0028]     A number of annuli and flowpaths are also defined within and by the frac pack system  10 . An upper annulus  60  is defined between the wellbore casing  13  and work string  22  above the production packer  26 , while a lower annulus  62  is defined between the casing  13  and blank pipe  28  in between packers  20  and  26 . An upper axial flowbore  64  is defined within the work string  22  and merges into the reduced diameter flowpath  38 . The lower end of the reduced diameter flowpath  38  has a lower axial fluid opening  66  and a lateral fluid pathway  68 . A central flowbore  70  is defined within the cross-over tool  34  and has a lower opening  72 .  
         [0029]     A flapper-type check valve  74  is retained within the central flowbore  70 . The check valve  74  is of a type known in the art for allowing one-way flow within a flowbore. Typically, the valve  74  has a hinged flapper member that is biased to a closed position, as is known in the art. When closed, the flapper valve  74  will block fluid from flowing downwardly through the flowbore  70 .  
         [0030]     An exemplary lower circulation valve  54  is shown in detail in  FIG. 10 . The lower circulation valve  54  includes a valve body  90  that is made up of a top sub  92  that is threadedly connected to a tubular upper body  94 . The upper body  94  contains a plurality of restricted flow area lateral metering ports  96  that permit fluid communication between the lower annulus  62  and the flowbore  98  that is defined within the valve body  90  and the isolation string  46 . The metering ports  96  are sized to permit a predetermined amount of fluid flow through them. The lower end of the upper body  94  is threadedly connected to a lower body  100  which, in turn is connected to bottom sub  102 . The top sub  92  and bottom sub  102  have threaded end connections  104 ,  106 , respectively, for interconnection with other portions of the isolation string  46 . Radially within the valve body  90  is a sleeve member  108  that is axially moveable within the valve body  90  between an open position (depicted in  FIG. 10 ) and a closed position. The sleeve member  108  has lateral fluid ports  110  that are aligned with the metering ports  96  when the sleeve member  108  is in the open position. Annular fluid seals  112 ,  112   a  are located on each axial side of the ports  110 . The sleeve member  108  has an upper axial end  114  that is formed to engage a stop shoulder  116  formed on the interior of the valve body  90  when the sleeve member  108  is moved to its closed position. In the closed position, the sleeve member  108  is shifted axially upwardly so that the upper axial end  114  engages the shoulder  116 . In this closed position, the interior ports  110  are not aligned with the metering ports  96 , and the lower seal  112   a  is located between the metering ports  96  and the ports  110  to prevent fluid communication between them. The lower end of the sleeve member  108  presents an annular fluid pressure receiving area  118 .  
         [0031]     In a preferred embodiment, the lower circulating valve  54  has a frangible shear member  120 , such as a shear screw, that releasably secures the sleeve member  108  in the open position shown in  FIG. 10 . Additionally, a radially outwardly biased C-ring  122  is located in an exterior groove  124  on the sleeve member  108 . The valve body  90  includes an interior radial recess  126 .  
         [0032]     The lower circulating valve  54  has two positions: open and closed-locked. The lower circulating valve  54  is run into the wellbore  12  in the open position, which is depicted in  FIG. 10 . The open position allows monitoring of pressure and other conditions within the lower annulus  62  during a frac pack operation. As will be described in further detail shortly, circulation may also be conducted through the circulation valve  54  during the frac pack operation. The valve  54  is then closed prior to conducting primary production through the upper sleeve tool  52  during later production operations. When the sleeve member  108  is moved to its closed position, fluid pressure is increased within the flowbore  98  so that the increased internal pressure bears upon the pressure receiving area  118 . The valve  54  is, of course, open at this point so that fluid may be communicated through the aligned ports  110 ,  96  to the lower annulus  62 . However, because the ports  96  are metering ports with a restricted flow area, they only permit a certain amount of fluid to pass through at a given time. Therefore, increasing the fluid pressure within the flowbore  98  at a great enough rate will still produce a sufficiently high pressure differential between the flowbore  98  and lower annulus  62  to shear the shear member  120  and urge the sleeve member  108  upwardly. Pumping into the flowbore  98  at a sufficiently high rate (i.e., 4 barrels per minute or so) will build sufficient pressure differential to shift the sleeve member  108 . The C-ring  122  will expand radially outwardly and partially into the recess  126 , there by locking the valve  54  into its closed position.  
         [0033]     Referring once again to  FIGS. 1-9 , overall operation of the frac pack system  10  is now described. In  FIG. 1 , the frac pack system  10  is being run into the wellbore  12  and the landing nipple  50  is landed into the lower packer  20 . In  FIG. 2 , the upper production packer  26  has been set by dropping a ball  130  into reduced diameter bore  38  to land within the ball seat  40 . Increased fluid pressure behind the ball  130  will set the upper packer  26 .  
         [0034]     In  FIG. 3 , the frac pack system  10  has been placed into the squeeze position lateral fluid pathway  68  has been opened above the ball  130  and permits fracturing fluid or a solids-containing fluid from the surface to pass from the flowbore  64  outwardly and into the lower annulus  62 , as depicted by arrows  132 . The pumped fluid or slurry enters the lower annulus and perforations  48 .  
         [0035]     In  FIG. 4 , the frac pack system  10  has been placed in a circulating configuration by opening the flapper valve  74  to permit fluid returns to the surface via the lower circulation valve  54  into flowbores  98  and  70  as shown by arrows  134 . The fluid returns  134  exit the cross-over tool  34  via lateral openings  136  and enter the upper annulus  60  where they can flow to the surface of the well for extraction. Fluid within the lower annulus  62  can enter the isolation string  46  via the aligned ports  110 ,  96  of the lower circulation valve  54 . The upper annulus  60  can also be isolated using surface valves as is known in the art to prevent extraction of fluids. With the upper annulus  60  isolated, conditions within the lower wellbore  62  surrounding the screen  48  and proximate the perforations  18  can be monitored by measurements of the upper annulus  60  pressure from the surface of the well or, alternatively, by placing a suitable condition-measuring sensor, of a type known in the art, into the lower flowbore  98  of the isolation string  46  itself.  
         [0036]     Referring now to  FIG. 5 , the frac pack system  10  is now placed into an evacuation configuration to help clear the cross-over tool  34 . To accomplish this, the setting tool portion  24  of the frac pack system  10  is shifted upward to expose lateral ports  138  in the cross-over tool  34 . The flapper valve  74  is closed. Cleaning fluid, indicated by arrows  140 , is circulated down the upper annulus  60  and enters the cross-over tool  34  via lateral openings  136 . From there, the cleaning fluid  140  flows outwardly through ports  138  and returns upwardly through fluid pathway  68  to the reduced diameter flowpath  38 . From there, it returns to the surface via flowbore  64 .  
         [0037]      FIG. 6  depicts the frac pack system  10  in a reverse circulation configuration wherein the setting tool portion  24  of the frac pack system  10  has been raised within the wellbore  12  so that the fluid pathway  68  is located above the production packer  20 . Fluid, indicated by arrows  142 , is flowed downwardly through the upper annulus  60  and then flows radially inwardly through the fluid pathway  68  to the flowbore  64  wherein it can return to the surface.  
         [0038]      FIG. 7  illustrates the step of closing the lower circulating valve  54 . As shown by the arrows  144 , pressurized fluid is pumped down the upper annulus  60 , through the blank pipe  28  and into the flowbore  98  of the isolation string  46 . This pressure increase will, as described previously, cause the sleeve member  108  of the lower circulating valve  54  to be shifted axially upwardly to its closed position, thereby closing off fluid flow through the lower circulating valve  54  from the lower annulus  62  into the flowbore  98 . Hydrostatic pressure is maintained within the flowbore  98  and reservoir  16  is effectively isolated from flow while the service tool portion  42  of the frac pack system  10  is withdrawn from the wellbore  12  and a standard production tubing string  150  (see  FIG. 8 ) is run into the wellbore  12  to become seated within production packer  26  and seal bore  36 .  
         [0039]     Once the production tubing string  150  has been run, fluid pressure is applied within the wellbore  12  so that the upper sleeve tool  52  can move from its closed-locked position to a closed-unlocked position. As fluid pressure within the wellbore  12  is reduced, the upper sleeve tool  52  can move from its closed-unlocked position to an open-unlocked position thereby allowing production fluid to flow from the perforations  18  through placed gravel (not shown) in the lower annulus  62  and screen  48  and further through the upper sleeve tool  52  to interior flowbore  98 . From there, the production fluid, indicated by arrows  152 , flows upwardly through the production tubing  150  to the surface of the well.  
         [0040]     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.