Abstract:
A system and method for actuating a shut-off valve in a wellbore wherein the shut-off valve element can be positively closed before the pump is removed from the well. A hydraulic actuator component is operably associated with the shut-off valve to provide for selective isolation of the well by positive closing of the valve prior to removal of the pump and opening of the valve after replacement of a pump within the wellbore. The hydraulic actuator component has a balanced hydraulic design wherein the valve closure element may be moved toward an open or closed position by flow of hydraulic fluid through first and second hydraulic lines. When a repaired pump or replacement pump is placed into the well, the actuator is stabbed into a packer element to seat it. The hydraulic actuator assembly is then operated to open the shut-off valve, thereby reestablishing well operation.

Description:
[0001]     The present application claims the priority of U.S. Provisional patent application Ser. No. 60/499,903 filed Sep. 3, 2003. 
     
    
     BACKGROUND OF THE INVENTION  
       [0002]     1. Field of the Invention  
         [0003]     The invention relates generally to systems and methods for shutting in and isolating a production reservoir in association with the operation of pulling a failed artificial-lift pump from a well.  
         [0004]     2. Description of the Related Art  
         [0005]     During the later stages of production of hydrocarbons from a wellbore, downhole artificial lift pumps are often used to help assist hydrocarbons from the well. Unfortunately, these pumps occasionally suffer breakdowns or malfunction and tend to have a lifespan of only 2-3 years, in any case. When a pump become non-operational, the pump is pulled from the wellbore and either repaired or replaced with a new pump during a workover of the well. In order to remove the pump from the wellbore, it is necessary to close off, or isolate, the well below the pump against fluid flow. If the well remains live while the pump is being removed, pressurized fluid could be forced to the surface very quickly, resulting in a dangerous situation at the wellhead and potentially reducing the ability of the well to produce further.  
         [0006]     One technique for isolating a well is to “kill” the well by introducing fluids, such as seawater, at the surface of the well to increase the hydrostatic pressure within the well to a point where it is higher than the formation pressure. The problem with this technique is that it is usually undesirable to introduce fluids into the formation below, as such may reduce the quality and quantity of production fluid that may be obtained from the well later.  
         [0007]     A second method for isolating the well is to provide a shut-off valve below the pump that is being removed and then to close the shut-off valve as the pump is removed from the well. A conventional shut-off valve arrangement is a sliding sleeve valve having lateral fluid openings with an internal sleeve that is axially moveable between positions that open and close against fluid communication. A sliding sleeve cut-off valve of this type is described in, for example, U.S. Pat. No. 5,156,220 issued to Forehand et al. and U.S. Pat. No. 5,316,084 issued to Murray et al. Each of these patents are owned by the assignee of the present invention and are hereby incorporated by reference. A shut-off valve assembly of this type is also available commercially from the Baker Oil Tools division of Baker Hughes Incorporated as the Model “CMQ-22” Sliding Sleeve.  
         [0008]     Typically, the valve element of the sliding sleeve valve is closed solely by the action of removing the pump. The pump has a stinger extending downwardly therefrom with a shifting collet on the lower end. The shifting collet is formed to engage the sleeve element of the sliding sleeve valve. When the pump is pulled from the wellbore, a tubing hanger pressure seal at the surface of the well is breached. The shifting collet is then pulled upwardly and moves the sleeve member of the sliding sleeve valve upwardly as well. When the repaired pump or replacement pump is to be disposed into the well, the stinger with shifting collet is secured to the lower end of the repaired/replaced pump. As the pump is run into the wellbore, the shifting collet once more engages the sleeve element of the sliding sleeve valve and, this time, moves the sleeve element axially downwardly within the valve to open the lateral fluid ports to fluid communication.  
         [0009]     This procedure for opening and closing the shut-off valve, while simple, presents practical problems. Because the well is live, there is typically a significant pressure differential across the shut-off valve. The inventors have recognized that, if the valve is not positively closed at the time the pump is removed, pressure may escape from the well below the pump. With the procedure where the sleeve element is closed by pulling the pump from the well, the valve is not fully closed until the pump is raised some distance within the wellbore, thereby permitting such an escape of pressure.  
         [0010]     The present invention addresses the problems of the prior art.  
       SUMMARY OF THE INVENTION  
       [0011]     The invention provides an improved system and method for actuating the shut-off valve wherein the shut-off valve element can be positively closed before the pump is removed from the well. In described embodiments, an actuator component is operably associated with the shut-off valve to provide for selective isolation of the well by positive closing of the valve prior to removal of the pump and opening of the valve after replacement of a pump within the wellbore. In one preferred embodiment, the hydraulic actuator component has a balanced hydraulic design wherein the valve closure element may be moved toward an open or closed position by flow of hydraulic fluid through first and second hydraulic lines. Following closure of the shut-off valve to close off the well, the pump may be removed by simply pulling it from the well. When a repaired pump or replacement pump is placed into the well, the actuator assembly is stabbed into a packer element to seat it. The hydraulic actuator assembly is then operated to open the shut-off valve, thereby reestablishing well operation. Alternatively, the actuator component is an electrically operated actuator.  
         [0012]     A number of alternative exemplary embodiments of the invention are described for integration of the actuator component into the production string. In alternative embodiments, differing stinger assemblies are used to engage the actuator with the sleeve valve. Additionally, the actuator assembly may be configured to be reversibly landed upon a sleeve valve assembly.  
         [0013]     The systems and methods of the present invention may be used to retrofit present systems and to supplement existing shut-off valves and packer assemblies to provide for improved operation.  
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0014]     The advantages and further aspects of the invention will be readily appreciated by those of ordinary skill in the art as the same becomes better understood by reference to the following detailed description when considered in conjunction with the accompanying drawings in which like reference characters designate like or similar elements throughout the several figures of the drawing and wherein:  
         [0015]      FIG. 1  is a side, cross-sectional view of an exemplary production assembly containing a pump, shut-off valve and valve actuator constructed in accordance with the present invention;  
         [0016]      FIG. 2  depicts the production assembly shown in  FIG. 1  with the shut-off valve now in a closed position;  
         [0017]      FIG. 3  depicts the production assembly of  FIGS. 1 and 2  with following removal of the pump and hydraulic actuation assembly;  
         [0018]      FIGS. 4   a ,  4   b , and  4   c  are detail drawings depicting the reversible interengagement of collet fingers with the profile of the sleeve valve element;  
         [0019]      FIG. 5  is a side, cross-sectional view of an alternative embodiment for an exemplary production assembly constructed in accordance with the present invention;  
         [0020]      FIG. 6A  is a side, partial cross-section view of a further alternative embodiment for an exemplary production assembly constructed in accordance with the present invention; and  
         [0021]      FIG. 6B  is a side, partial cross-section view of a further alternative embodiment for an exemplary production assembly constructed in accordance with the present invention. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0022]      FIG. 1  depicts an exemplary wellbore  10  that has been drilled through the earth  12  and into a formation  14  from which it is desired to produce hydrocarbons. The wellbore  10  is cased by metal casing  16 , and a number of perforations  18  penetrate the casing  16  to extend into the formation  14  so that production fluids may flow from the formation  14  into the wellbore  10 . The wellbore  10  has a late-stage production assembly, generally indicated at  20 , disposed therein by a tubing string  22  that extends downwardly from the surface of the wellbore  10  and defines an internal axial flowbore  24  along its length. An annulus  26  is defined between the production assembly  20  and the wellbore casing  16 . For the sake of clarity and brevity, descriptions of most threaded connections between tubular elements, elastomeric seals, such as o-rings, and other well-understood techniques are omitted in the description that follows.  
         [0023]     At its upper end, the production assembly  20  includes an artificial lift pump, such as electrical submersible pump  28  that is of a type known in the art for pumping hydrocarbons to the surface of a well. Because the structure and operation of electrical submersible pumps is well known, they will not be described in detail here. It is noted, however, that the pump  28  includes a motor section  30  and an inlet section  32  having lateral fluid flow ports  34  therein. At its lower end, the pump  28  is secured to a ported sub  36  that also contains a plurality of lateral fluid flow ports  38  therein. A power conduit  31  extends from the surface of the well  10  to provide electrical power to the motor section  30 . The lower end of the ported sub  36  is affixed to a hydraulic actuation assembly  40 , the structure and function of which will be described in detail shortly. Alternatively, the actuation assembly may be electrically driven, for example, by tapping off of the power conduit  31 .  
         [0024]     The hydraulic actuation assembly  40  is secured at its lower end to a packer assembly  42 . It is noted that there is a separable snap-latch connection  43  between the lower end of the hydraulic actuation assembly  40  and the packer assembly  42 . The snap-latch connection  43  is of a type known in the art to allow for a snap-in connection to a threaded end piece and reversible release by application of a sufficient tensional load, such as, for example 8,000 to 12,000 lbs. tension. Typically, such connections are provided by a collected end with exterior wickers that are shaped and sized to reversibly reside within the threads of a box-type end joint. An example of a suitable snap-latch connection for this application is that used in the Model E™ Snap-Latch Seal Assembly available commercially from the Baker Oil Tools division of Baker Hughes Incorporated.  
         [0025]     The packer assembly  42  is shown having a packing element  44 , which is set against the casing  16  to secure the production assembly  20  in place within the wellbore  10 . The packer assembly  42  may comprise any of a number of packer assemblies known in the art for anchoring a tool within a wellbore and providing a fluid seal. One suitable packer assembly for this application is the SC-2™ Packer that is available commercially from the assignee of the present invention, Baker Hughes, Incorporated. The setting operation of such devices is well known by those of skill in the art and, therefore, will not be discussed in any detail herein.  
         [0026]     A sliding sleeve shut-off valve assembly  46  is secured to the lower end of the packer assembly  42 . A bull plug  48  is secured to the lower end of the shut-off valve assembly  46 . The shut-off valve assembly  46  has an outer tubular housing  50  that defines a sleeve valve chamber  52  within. A generally tubular internal sleeve valve element  54  is located within the chamber  52  and is axially translatable within the housing  50 . The upper end of the sleeve valve element  54  includes an annular profile  56 . The outer housing  50  of the valve assembly  46  includes a plurality of lateral fluid openings  58 . Additionally, the sleeve valve element  54  includes a number of fluid apertures  60 . In this embodiment, the fluid apertures  60  are located below the profile  56  on the sleeve valve element  54 . The sleeve valve element  54  is in an open position in  FIG. 1 , wherein the fluid apertures  60  of the sleeve valve element  54  are aligned with the lateral fluid openings  58  of the housing  50 , thereby permitting hydrocarbon fluids from the formation  14  to pass into the valve assembly  46 . The sleeve valve element  54  will be in a closed position, as depicted in  FIG. 2 , when the sleeve valve element  54  has moved to a position wherein its apertures  60  are no longer aligned with the fluid openings  58  of the housing  50 . In a closed position, fluid cannot enter the valve assembly  46  due to blockage by the sleeve valve element  54 .  
         [0027]     The hydraulic actuation assembly  40  mentioned previously includes a tubular outer housing  62  having an upper axial end  64  that is threadedly secured to the ported sub  36  above and an opposite lower axial end that includes the separable snap-latch connection  43  mentioned earlier. The outer housing  62  of the actuation assembly  40  defines a generally cylindrical interior volume  66  therewithin. First and second hydraulic control lines  68 ,  70  extend from the surface of the wellbore  10  and are secured to nozzles or fixtures (not shown) upon the outer housing  62  of the hydraulic actuation assembly  40 . The control lines  68 ,  70  are fluid conduits, of a type known in the art, that carry pressurized hydraulic fluid from the surface of the wellbore  10  to selectively transmit the pressurized fluid into the interior volume  66  of housing  62 . Control of the flow of pressurized fluid is provided at the surface of the wellbore  10 . Alternatively, the hydraulic supply system (not shown) may be located at an intermediate downhole location and control lines  68 , 70  connected thereto. The hydraulic supply system may be connected to and powered by a controller (not shown) at the surface.  
         [0028]     A reciprocable stinger member  72  is retained within the hydraulic chamber  66  and is used to operate the shut-off valve  46 . The stinger member  72  includes an upper piston portion  74  and an affixed lower working portion  76  that extends downwardly from the piston portion  74 . The upper piston portion  74  divides the hydraulic chamber  66  into first and second fluid chambers  78 ,  80 . The first hydraulic control line  68  communicates fluid into or out of the first fluid chamber  78  while the second hydraulic control line  70  communicates fluid into or out of the second fluid chamber  80 . Each of the fluid chambers  78 ,  80  is made fluid-tight by the use of o-rings and other fluid sealing members that are known in the art. The piston portion  74  is moved axially within the hydraulic chamber  66  by the addition and removal of fluid from the respective fluid chambers  78 ,  80 . Flowing pressurized fluid through the first control line  68  and into the first hydraulic chamber  78  and allowing fluid to flow from the second hydraulic chamber  80  outwardly through the second control line  70  will cause the piston portion  74  to move upwardly within the outer housing  62 . Conversely, flowing pressurized fluid through the second control line  70  and into second hydraulic chamber  80  and flowing fluid from the first hydraulic chamber  78  through the first control line  68  will move the piston portion  74  downwardly within the housing  62 . Alternatively, the piston may be operated in one direction by flowing pressurized hydraulic fluid into one of the hydraulic chambers and have a spring return mechanism (not shown) for returning the piston to its original position when the pressurized fluid is vented from the pressurized hydraulic chamber. The spring mechanism may be a mechanical spring and/or a pressurized gas spring of a kind known in the art.  
         [0029]     The working portion  76  of the stinger member  72  includes a tubular sleeve  82  and a set of collet fingers  84  that extend axially therefrom. The distal end of each collet finger  84  has a radially outwardly protruding engagement portion  86  that is shaped and sized to engage the profile  56  of the sleeve valve element  54 . A central axial flowbore  88  is defined along the length of the stinger member  72 . The collet fingers  84  are capable of flexing radially inwardly, in a manner that is well known, to accomplish engagement between the engagement portions  86  and the profile  56 . Conversely, a sufficiently high axial load, will be sufficient to cause the engagement portions  86  to be released from engagement with the profile  56 . When the hydraulic actuator assembly  40  is seated upon the packer assembly  42 , as shown in  FIG. 1 , the tubular sleeve  82  of the stinger member  72  extends through the packer assembly  42 , and the engagement portions of the collet fingers  84  are engaged with the profile of the sleeve valve element  54 .  
         [0030]     Although the engagement portions  86  of the collet fingers  84  and profile  56  of the sleeve valve element  54  are shown schematically in  FIGS. 1-3 ,  FIGS. 4   a ,  4   b , and  4   c  depict aspects of their design and operation in greater detail. As shown there, the engagement portion  86  of the collet finger  84  includes an angled lower face  86   a  and angled upper face  86   b . An exemplary profile  56  features an inwardly projecting ridge  56   a  with an angled upper face  56   b  and angled lower face  56   c . An annular recess  56   d  is located below the angled lower face  56   c  and a stop face  56   e  located directly below the recess  56   d .  FIGS. 4   a - 4   c  illustrate the process of engaging the engagement portion  86  of a collet  84  with the complimentary profile  56 . The lower face  86   a  of the engagement portion  86  encounters the upper angled face  56   b  of the profile  56  and the collet  84  is deflected radially inwardly ( FIG. 4   b ) as the engagement portion  86  slides over the ridge  56   a  of the profile  56 . Once past the ridge  56   a , the engagement portion  86  snaps outwardly to reside within the recess  56   d  below. Engagement of the lower face  86   a  with the stop face  56   e  of the profile  56  will preclude the engagement portion  86  from moving any further downwardly with respect to the sleeve valve element  54 . Release of the engagement portion  86  from the profile  56  is accomplished by exerting a sufficient upward tensional force upon the collet  84 . The upper angled face  86   b  of the engagement portion  86  will slide upon the face  56   c  of the profile  56  as the collet  84  is deflected inwardly. The engagement portion  86  will pass over the ridge  56   a  and return to its released position illustrated in  FIG. 4   a . It is noted that a sufficient tensional force for releasing the collet  84  from the profile  56  should be approximately the same force as that required to release the snap-latch connection  43 . The collet engagement arrangement described above is intended as an example, and not as a limitation. One skilled in the art will appreciate that the collet fingers could be located on the sleeve valve element  54  and the engagement profile could be located on the bottom of the tubular sleeve  82 .  
         [0031]     As configured in  FIG. 1 , in a landed and normally operational position, the production assembly  20  provides a flow path for hydrocarbons that enter the wellbore  10  from the formation  14  via perforations  18 . The sleeve valve element  54  is in an open position so that hydrocarbons within the wellbore  10  below the packer element  44  can enter the valve assembly  46  via fluid openings  58  and aligned apertures  60 . Under impetus of the pump  28 , the hydrocarbons are then flowed upwardly through the central axial flowbore  88  of the stinger member  76 . Upon exiting the axial flowbore  88 , the hydrocarbons pass radially outwardly through the flow ports  38  in the ported pipe  36 , bypass the motor portion  30  of the pump  28  and then enter the fluid inlets  34  of the inlet section  32  of the pump  28 . From there, the hydrocarbon fluids are pumped to the surface of the wellbore  10  via the flowbore  24  of tubing string  22 .  
         [0032]     When it becomes necessary to repair or replace the pump  28 , the shut-off valve  46  is first moved to a closed position, as illustrated in  FIG. 2 . To close the shut-off valve  46 , pressurized hydraulic fluid is pumped through control line  68  and into the first hydraulic chamber  78 , thereby urging the piston portion  74  upwardly within the volume  66  of the housing  62 . Fluid present within the second hydraulic chamber  80  is permitted to escape via control liner  70 . As the piston portion  74  is moved upwardly, the collet fingers  84  pull the sleeve valve element  54  upwardly to positively close the shut-off valve  46  and isolate the well.  
         [0033]      FIG. 3  illustrates the production assembly  20  following closing of the shut-off valve  46  and during subsequent removal of the pump  28  from the wellbore  10 . The tubing string  22  is pulled upwardly, thereby causing the snap-latch connection  43  to separate so that the housing  62  of the hydraulic actuator  40  is pulled away from the packer assembly  42  below. Additionally, the engagement portions  86  of the collet fingers  84  become disengaged from the profile  56  of the sleeve valve  54 . The pump  28  and hydraulic actuator  40  are then removed from the wellbore  10 .  
         [0034]     When it is time to replace the repaired/new pump  28  into the wellbore  10 , the hydraulic actuation assembly  40  is secured to the lower end of the new/repaired pump  28  and both are made up to the tubing string  22 . The tubing string  22  is then lowered into the wellbore  10  until the snap-latch  43  secures the hydraulic actuator  40  to the packer assembly  42  and the collet fingers  84  snap in to engage the profile  56  of the sleeve valve element  54 . When this is done, the production assembly  20  is once again in the configuration depicted in  FIG. 2 , with the shut-off valve  46  remaining in the closed position.  
         [0035]     The production assembly  20  is then opened up to permit production of hydrocarbon fluids from the formation  44 . Pressurized hydraulic fluid is pumped through the second control line  70  and into the second hydraulic chamber  80 . The piston portion  74  is moved downwardly within the housing  62  of the hydraulic actuator  40  and, consequently, the sleeve valve element  54  is moved downwardly to once again align the fluid apertures  60  with the fluid openings  58  so that hydrocarbons may enter the shut-off valve  46  and be pumped to the surface upon subsequent operation of the pump  28 .  
         [0036]     Referring now to  FIG. 5 , an alternative embodiment for a production assembly  20 ′is shown. In this embodiment, the fluid openings  60  of the sleeve valve element  54 ′ are located above the profile  56 ′, which is located proximate the lower end of the sleeve valve element  54 ′. The hydraulic actuator assembly  40 ′ has been modified to allow for engagement of the lower profile  56 ′ as well as for fluid flow radially outside of the modified stinger member  72 ′. Except where indicated otherwise, structure and operation of the production assembly  20 ′ is the same as that of the production assembly  20  described earlier. The hydraulic actuator assembly  40 ′ features an inner housing  90 , in addition to the outer housing  62  described earlier. The inner housing  90  is suspended from the pump  28  and encloses the piston portion  74 ′ of the modified stinger member  72 ′. First and second hydraulic chambers  78 ,  80  are defined inside of the inner housing  90 . The first and second control lines  68 ,  70  extend through the outer housing  62  as well as the inner housing  90  to provide fluid communication with the first and second hydraulic chambers  78 ,  80 . The modified stinger member  72 ′ also includes a working portion prong  92  that extends downwardly from the piston portion  74 ′ through the packer assembly  42 . The lower end of the prong  92  has an affixed shoe member  94  with radially extending engagement portions  96  that are shaped and sized to engage the profile  56 ′ of the sleeve valve element  54 ′ in a manner similar to the engagement portions  86  described previously.  
         [0037]     When the production assembly  20 ′ is in a producing configuration, as shown in  FIG. 5 , hydrocarbons flow into the shut-off valve  46 ′ and upwardly through the packer assembly  42 . Flow occurs through the hydraulic actuator  40 ′ outside of the inner housing  90  and within the outer housing  62  and then through the ports  38  of ported pipe  36  and into the inlets  34  of pump  28 .  
         [0038]     Referring now to  FIG. 6A , a further alternative embodiment for a production assembly  20 ″ is depicted in partial cross-section. In this construction, the producing formation (not shown) is located below a production packer  100  that seals against casing  16  to secure a section of production tubing  102  within the wellbore  10 . The production tubing  102  is secured, at its upper end, to a pipe segment  104  having lateral fluid apertures  106  and that is sealed at its upper end by a wireline-set plug  108 . A shut-off valve, having the design of either valve  46  or  46 ′ described earlier, is secured to the pipe segment  104  above the plug  108 . An exterior shroud  110 , of a type known in the art, radially surrounds and is secured to the pipe segment  104  and valve  46  or  46 ′ so that fluid passing upwardly through the pipe segment  104  may pass outwardly through apertures  106  and then radially inwardly into the shut-off valve  46 , 46 ′ via exterior openings  58  when the shut-off valve  46 , 46 ′ is in an open position. The remainder of the fluid flow path will be the same as that described earlier with respect to the previous embodiments. In an alternative embodiment, see  FIG. 6B , a production assembly  20 ′″ provides a non-shrouded assembly that operates similar to that of  FIG. 6A . Here, however, plug ( 108 ) is located above flow ports  58  and tubular  104  is solid (not perforated).  
         [0039]     A hydraulic actuation assembly, having either the configuration of assembly  40  or  40 ′ described earlier, is reversibly secured upon the upper end of the shut-off valve  46 ,  46 ′ in order to operate the shut-off valve  46 ,  46 ′. It is noted that the stinger member of the hydraulic actuation assembly  40 ,  40 ′ will be considerably shortened in this embodiment, as compared to the previously described embodiments since the stinger need not pass through an intervening packer. Additionally, the design of the actuation assembly (either that or  40  or  40 ′) is dependent upon the location of the profile  56 ,  56 ′ upon the sleeve valve element  54 ,  54 ′ within the shut-off valve  46 ,  46 ′.  
         [0040]     It can be seen that, in each instance described above, the present invention provides a production assembly that has a lower production portion with a shut-off valve, such as a sleeve valve, that is selectively moveable between open and closed positions. In addition, the production assembly has an upper production portion that can be selectively landed upon and removed from the lower production portion. The upper production portion includes a fluid pump and a stinger assembly for engagement of the shut-off valve and movement of the valve between open and closed positions. Also, the upper production portion includes a hydraulic actuator for movement of the stinger assembly.  
         [0041]     The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the invention.