Patent Publication Number: US-2007119599-A1

Title: Interventionless Reservoir Control Systems

Description:
This application is a continuation of U.S. patent application Ser. No. 10/783,404 filed Feb. 20, 2004, which claims the priority of U.S. Provisional Patent Application No. 60/516,882 filed Nov. 3, 2003. 
    
    
     BACKGROUND OF THE INVENTION 1. Field of the Invention  
      The invention relates generally to systems and methods for selectively isolating, or closing of a portion of a wellbore. 2. Description of the Related Art  
      During operation of a hydrocarbon production well, it is sometimes necessary to close off, or “kill,” the well below a certain point, against fluid flow. If the well remains live while, for example, a 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. One technique 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.  
      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.  
      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.  
      The present invention addresses the problems of the prior art.  
     SUMMARY OF THE INVENTION  
      The invention provides improved systems and methods for positively closing off a section of wellbore and, thereby providing reservoir control. Systems and methods are described for selectively closing off a section of a wellbore to fluid communication. The wellbore completion section may then be reopened to fluid communication upon reconnection of the upper completion section to the lower completion section. Advantageously, the systems and methods of the present invention generally preclude fluid communication between the annulus of the upper completion section and the flowbore of the lower completion section until the lower completion section is closed off to fluid flow.  
      In one preferred embodiment described herein, a reservoir control valve assembly is provided having upper and lower sliding sleeves that are incorporated into the upper and lower completion sections of a reservoir completion. The upper sliding sleeve is selectively opened by increased annulus pressure, so that fluid flow may be prevented until it is desired to begin flow, thereby affording positive control over the reservoir completion. The lower sliding sleeve is actuated by removal of the upper completion section from the lower completion section and by replacement of the upper completion section upon the lower completion section.  
      A second preferred reservoir control system is described wherein the reservoir control valve assembly includes a valve body that incorporates both an inner and an outer sliding sleeve. The outer sleeve is opened by an increase in annular pressure within the wellbore. The inner sleeve is opened by manipulation of the upper completion section to cause a stinger member to actuate the inner sleeve.  
      The systems and method of the present invention are interventionless in the sense that there is no need to utilize a wireline or coiled tubing-run device to open of close off the lower completion section prior to pulling the upper completion section from the wellbore.  
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
      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:  
       FIG. 1  is a side, cross-sectional view of an exemplary wellbore with a gravel packed section and a completion string disposed therein.  
       FIG. 2  is an enlarged side, cross-sectional view of the reservoir control system within the wellbore shown in  FIG. 1 .  
       FIG. 3  is a side, cross-sectional view of the reservoir control system shown in  FIG. 2 , now with the upper sliding sleeve in an open position.  
       FIG. 4  is a side, cross-sectional view of the reservoir control system shown in  FIGS. 2 and 3  now with the lower sliding sleeve having been moved to a closed position.  
       FIG. 5  is a side, cross-sectional view of the reservoir control system shown in  FIGS. 2, 3 , and  4  now with the upper completion having been fully separated from the lower completion.  
       FIG. 6  is a side, cross-sectional view of the reservoir control system shown in  FIGS. 2-5 , wherein the lower sliding sleeve has been stuck in a closed position.  
       FIG. 7  is a schematic side, cross-sectional view of an alternative reservoir control system constructed in accordance with the present invention wherein there is a gravel-packed section and a completion string disposed within the wellbore.  
       FIG. 8  is a schematic side cross-sectional view of the reservoir control system shown in  FIG. 7  wherein the upper completion portion has been landed atop the lower completion portion.  
       FIG. 9  depicts the reservoir control system of  FIGS. 7 and 8  now with the inner sliding sleeve opened.  
       FIG. 10  illustrates the reservoir control system of  FIGS. 7-9  now with the outer sliding sleeve opened to permit fluid flow upwardly into the upper completion portion.  
       FIG. 11  illustrates the reservoir control system of  FIGS. 7-10  now with the upper completion portion being removed from the wellbore.  
       FIGS. 12   a - 12   f  are a quarter-section view of an exemplary reservoir control valve used within the system described with respect to  FIGS. 7-11 .  
       FIGS. 13   a - 13   f  are a quarter-section view of an exemplary reservoir control valve used within the system described with respect to  FIGS. 7-11 , now with the control valve now actuated to open an inner sliding sleeve.  
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       FIG. 1  depicts an exemplary wellbore  10  that has been drilled through the earth  12  to a hydrocarbon-bearing formation  14 . The wellbore  10  includes a production tubing-run reservoir completion string  16  disposed therein and extending to the surface (not shown) of the wellbore  10 . An annulus  18  is defined between the completion string  16  and the interior wall  20  of the wellbore  10 . The completion string  16  consists of an upper completion portion  22  and a lower completion portion  24 , which are reversibly interconnected to one another via a reservoir control valve assembly, generally indicated at  25 , the details of which will be described in further detail shortly.  
      The lower completion portion  24  includes an apertured or screened sub  26  that is disposed adjacent the formation  14 . Perforations  28  in the formation  14  help ensure flow of hydrocarbons from the formation  14  into the sub  26 . An axial flowbore  32  is defined along the length of the upper and lower completion portions  22 ,  24 . Gravel  34  is packed within the annulus  18  surrounding the sub  26  below a packer assembly  30 . During normal operations, hydrocarbons are flowed from the formation  14  into the sub  26  and generally along the flowbore  32  to the surface of the wellbore  10 .  
      Turning now to  FIGS. 2, 3 ,  4  and  5 , details of the reservoir control valve assembly  25  and surrounding components are more clearly depicted in a schematic fashion. The upper completion portion  22  includes a tubing string  36  that extends to the surface of the wellbore  10 . An electric submersible pump  38  is secured to the lower end of the tubing string  36 . The pump  38  is of a type known in the art for flowing hydrocarbons along a production string and includes a motor section  40  and inlet section  42 . The inlet section  42  contains a number of fluid inlets  44  that permit passage of fluid from the annulus  18  into the inlet section  42 , wherein it may be transmitted to the surface of the wellbore  10  via the tubing string  36 . An electrical cable  46  extends downwardly from the surface of the wellbore  10  and supplies electrical power to the motor section  40  of the pump  38 .  
      A perforated sub  48  is secured to the lower end of the pump  38 . The sub  48  includes a plurality of lateral fluid flow ports  50  disposed therethrough and an upper sliding sleeve  52 , which radially surrounds the perforated sub  48  and is axially moveable thereupon to selectively cover and uncover the ports  50 . Thereby permitting fluid communication between the annulus  18  and the radial interior of the perforated sub  48 . When the reservoir control valve assembly  25  is initially placed into the wellbore  10 , the sleeve  52  is in a closed position, as shown in  FIG. 2 , wherein the ports  50  are covered by the sleeve  52  against fluid flow therethrough. The sliding sleeve  52  is actuatable by increasing fluid pressure within the annulus  18 . Increased annular pressure bears upon the piston surface  54  at the upper end of the sleeve  52  to move the sleeve  52  downwardly to the position depicts in  FIG. 3 , thus opening the ports  50 .  
      An anchor device  56  is secured to the lower end of the perforated sub  48 . The anchor device  56  is a snap-in, snap-out anchoring body  58  with a stinger  60  that extends downwardly therefrom. The anchoring body  58  is shaped and sized to reside within a complimentary-shaped receptacle  62 . The anchoring body  58  is seated and removed by snapping the body  58  into and out of the receptacle in a manner known in the art. One suitable anchor device for this application is the Model E Snap-In, Snap-Out Anchor that is available commercially from Baker Oil Tools of Houston, Texas. A set of annular elastomeric seals  61  radially surrounds the anchoring body  58  and establishes a fluid seal between the body  58  and the receptacle  62 .  
      The receptacle  62  is defined within a reservoir control valve  64  which includes, below the receptacle  62 , a tubular sub  66  having a number of lateral fluid flowports  68  disposed therethrough. An axially moveable lower sliding sleeve  70  is retained within the sub  66 . The sliding sleeve  70  is initially disposed within the sub  66  in a first position, shown in  FIG. 2 , wherein the sleeve  70  does not cover the ports  68  and, thereby, permits fluid to pass through the ports  68 . The sleeve  70  is moveable to a second position (shown in  FIG. 3 ) wherein the sleeve  70  covers the ports  68  and thereby blocks fluid flow therethrough. The stinger  60  of the anchor device  56  is equipped with an outwardly projecting profile  72  that is located initially beneath the lower axial end of the sliding sleeve  70 . Below the sliding sleeve  70 , the tubular sub  66  is closed off to fluid flow therethrough by a flowbore plug  74 . The flowbore plug  74  may be of any suitable type. One such suitable plug for this use is the “Extreme” Sur-Set™ plug that is available commercially from Baker Oil Tools of Houston, Tex. Additionally, the tubular sub  66  contains lower lateral fluid ports  76 . The lower end of the tubular sub  66  is secured to an anchor member  78  that, in turn, is seated within the packer assembly  30 .  
      The reservoir control valve  64  also includes an outer shroud  80  that radially surrounds that tubular sub  66 . An annular space  82  is defined between the shroud  80  and the tubular sub  66 . The shroud  80  also includes a fluid opening  84  that is initially closed against fluid flow by a frangible rupture member, such as a burst disc,  86 . The frangible member  86  is designed to rupture upon encountering a sufficiently high, predetermined pressure differential.  
      In operation, the lower completion section  24  is preplaced within the wellbore  10  and the gravel  34  packed into the annulus  18  using well known conventional techniques. The packer assembly  30  is set within the wellbore  10  to close off the annulus  18  below the packer assembly  30 . At this point, the upper completion section  22  is run into the wellbore  10  until the anchor  78  is seated and secured within the packer assembly  30 , thereby connecting the upper completion section  22  to the lower completion section  24 . When this is done, the components of the completion string  16  are in the configuration shown in  FIG. 2  wherein the upper sliding sleeve  52  is closed and the lower sliding sleeve  70  is in an open position. In this configuration, no flow of fluid is possible upward to the surface of the wellbore  10  due to the upper sliding sleeve  52  being in a closed position. One advantage of the system and methods of the present invention, then is that of positive reservoir control, wherein no flow is permitted until the system is positively opened for flow.  
      When it is desired to begin flow of fluid to the surface of the wellbore  10 , the upper sliding sleeve  52  is opened. To accomplish this, the tubing string  36  is pressurized. Fluid pressure is thereby also increased in the annulus  18  because of the fluid communication provided by the fluid openings  44  in the pump  38 . Increased fluid pressure is brought to bear upon the piston area  54  of the upper sleeve  52 , and the sleeve  52  is moved to the open position illustrated in  FIG. 3 . The pump  38  is then energized in order to flow hydrocarbons from the formation  14  upward through the completion string  16 . Hydrocarbon production fluid flows into the lower completion section  24  through apertured sub  26  and then upwardly into through the packer assembly  30  into the tubular sub  66 . Due to the presence of the plug  74 , the production fluid must exit the tubular sub  66  via fluid flowports  76 , as arrows  88  illustrate. Because the lower sliding sleeve  70  is in the open position, the lateral flowports  68  are open to allow the production fluid to reenter the tubular sub  66 , as illustrated by arrows  90 . The production fluid flows up to the perforated sub  48  and then radially outwardly through perforations  50 . The production fluid bypasses the motor section  40  of the pump  38  and enters the inlet section  42  of the pump  38  through fluid inlets  44  to the production tubing  36 . This flowpath is illustrated by arrow  92 .  
      The reservoir control valve assembly  25  also provides a mechanism for effectively closing off the lower completion  24  portion of the wellbore  10  while the upper completion portion  22  is removed. This may become necessary if it is required to, for example, replace or repair the pump  38 . It is desired that fluid communication between the upper annulus  18  and the flowbore of the lower completion section  24  during or following separation of the upper and lower completion sections  22 ,  24 . Fluids within the upper annulus  18  might enter the flowbore of the lower completion section  24  and, thereby undesirably enter the formation  14 . One advantage of exemplary systems and methods of the present invention is that they permit the lower completion to be positively closed without annulus fluids entering the flowbore of the lower completion section  24 .  FIG. 4 , shows the initial stage of separation between the upper completion section  22  and the lower completion section  24 .  FIG. 5  shows a later stage of separation between the two sections  22 ,  24 . To separate the upper and lower completion sections  22 ,  24 , the tubing string  36  is pulled upwardly causing the anchoring body  58  of the anchor member  56  to snap out of the receptacle  62  of the reservoir control valve assembly  25 . The radially outward projection  72  of the stinger  60  engages the lower axial end of the lower sliding sleeve  70  and, as the tubing string  36  is pulled upwardly, the sleeve  70  is moved upwardly to its closed position wherein the flowports  68  are closed to fluid flow, as  FIG. 4  shows. It is noted that the presence of seals  61  still ensures a fluid seal between the anchoring body  58  and receptacle  62  at this point. As a result, there is no fluid communication from the annulus  18  into the radial interior of the tubular sub  66  until the lower sleeve  70  is closed. When the lower sleeve  70  is closed, as shown in  FIG. 4 , the plug  74  and sleeve  70  completely block fluid transmission into the lower completion section  24 . Following closure of the sleeve  70 , further upward pulling of the tubing string  36  will disconnect the stinger  60  from the lower sleeve  70 . The stinger  60  is typically colleted, allowing it to flex radially inwardly to a degree, in a manner well known to those of skill in the art. Therefore, when the tubing string  36  is pulled further upwardly, the stinger  60  will flex inwardly allowing the outward projection  72  to become free of engagement with the lower axial end of the sleeve  70 . Once free of this engagement, the upper completion section  22  may be pulled entirely free of the lower completion portion, as depicted in  FIG. 5 .  
      Prior to reinserting and reconnecting the upper and lower completion sections  22 ,  24 , the upper sliding sleeve  52  is closed at the surface of the wellbore  10 . Once the upper and lower completion sections  22 ,  24  are reconnected, the upper sliding sleeve  52  may be reopened via an increase in annulus pressure, as previously described. Reinsertion and reconnection of the upper completion section  22  to the lower completion section  24  should automatically reopen the lower sleeve  70 . As the upper completion section  22  is lowered into the wellbore, the anchoring body  58  will snap into the receptacle  62 . During this process, the outward projection  72  of the stinger  60  will engage the upper axial end of the sleeve  70  and slide it from the closed position, shown in  FIG. 5 , to the open position, shown in  FIG. 3 , to once again establish fluid flow into the lower completion section  24 . It is noted that, as the upper completion section  22  is reinserted into the lower completion section  24 , a fluid seal is first established between the anchoring body  58  and the receptacle  62  via seals  61  prior to opening the lower sliding sleeve  70 . This sealing ensures that there is no premature flow of annulus fluids into the lower completion  24 .  
      If the lower sliding sleeve  70  should fail to open, as intended, the burst disc  86  may be ruptured by increasing fluid pressure within the upper portion of the annulus  18  to a level that is great enough to rupture the disc  86  and, thereby, permit fluid to flow through the fluid opening  84 . This will provide an additional pathway for fluid to pass between the flowbores of the upper and lower completion sections  22 ,  24 .  FIG. 6  depicts this situation. In the event that the lower sleeve  70 is stuck in the closed position, fluid pressure within the upper annulus  18  would be increased to a level sufficient to rupture the burst disc  86 , thereby allowing fluid communication through the opening  84  in the shroud  80 . Fluid can then pass from the lower completion section  24  through flowports  76  into annular space  82  and then radially outwardly to the annulus  18  through opening  84 , as arrows  96  depict. From the annulus  18 , the production fluid is then drawn into the fluid inlets  44  of the pump  38  and transmitted to the surface of the wellbore  10  via the tubing string  36 . Thus, the fluid opening  84  in the shroud  80  and the burst disc  86  provide an emergency fluid pathway that may be opened in the event of a failure of the lower sleeve  70  to reopen.  
      Turning now to  FIGS. 7-11  as well as  12   a - 12   f  and  13   a - 13   f , there is shown an alternative reservoir control assembly  100  constructed in accordance with the present invention.  FIGS. 7, 8 ,  9 ,  10  and  11  are schematic views of the reservoir control system in various stages of operation within the wellbore  10 .  FIGS. 12   a - 12   f  and  13   a - 13   f  depict the exemplary reservoir control assembly  100  and associated components in quarter cross-section so that the interoperation of the various components may be appreciated. Referring first to the schematic views ( FIGS. 7-11 ), the overall structure and operation of the reservoir control assembly  100  will be described. The reservoir control assembly  100  is affixed within an upper completion section  102  below an electrical submersible pump  104 . The lower completion section  106  includes the perforated pipe  24  and gravel packed section  34 . The packer  30  has an upwardly-extending latching portion  108  for landing and releasably securing an anchor member thereto.  
      Generally speaking, the reservoir control assembly  100  includes a generally cylindrical valve body  110  having an axial fluid passage  112  defined therein. The valve body  110  includes a radial fluid flow port  114  and carries an exterior sliding sleeve valve member  116  that is selectively moveable between two positions. In the first position (shown in  FIG. 7 ), the flow port  114  is blocked by the sleeve valve member  116  as against fluid communication. In the second position, the sleeve valve member  116  does not block fluid communication through the flow port  114 . Additionally, the valve body  110  includes an inner sliding sleeve valve member  118  that is also moveable between positions in which the valve member  118  respectively blocks and does not block the port  114  against fluid flow. The axial fluid passage  112  of the valve body  110  includes a plug member  120  therewithin to block axial flow of fluid through the passage  112  above the level of the port  114 . The upper end of the valve body  110  is provided with an upper latch assembly  122  for interconnection of the valve body  110  to production tubing segments in the upper completion section  102 . The lower end of the valve body  110  presents an anchoring portion  124  that is shaped and sized to be complimentary to the latching portion  108  of the packer device  30 . The valve body  110  also includes a stinger assembly  126  (visible in the detailed views of  12   a - 12   f  and  13   a - 13   f ) that is used to move the inner sleeve member  118  between its closed and open positions, in a manner that will be described in detail shortly.  
       FIG. 7  illustrates running in of the upper completion section  102  with the reservoir control assembly  100  affixed thereto. In  FIG. 8 , the anchoring portion  124  of the reservoir control assembly  100  has been landed into the latching portion  108  of the lower completion section  106 . In this position, no fluid production from the lower completion section  106  occurs. The plug  120  within the assembly  100  blocks upward flow of fluid. After landing the assembly  100 , fluid flow may be started by moving both the inner and outer sleeve members  118 ,  116  to unblock the port  114 .  
      First, the inner sleeve  118  is moved downwardly by surface controlled manipulation of the upper completion  102  string (i.e., pushing downwardly upon the production tubing). The stinger assembly  126  will cause the inner sleeve  118  to open (see  FIG. 9 ). The outer sleeve  116  is then moved to an open position to fully unblock port  114 . It is noted, however that the outer sleeve  116  may be opened either before or after the inner sleeve  118  is opened.  
      To open the outer sleeve  116 , fluid pressure is increased from the surface inside of the upper completion  102  tubing string. Fluid pressure exits the openings  128  in the fluid pump  104  and enters the annulus  130 . The pressurized fluid bears upon an annular piston area  132  (see e.g.,  FIG. 12   d ) to urge the outer sleeve  116  upwardly (see  FIG. 10 ).  FIGS. 12   d  and  13   d  depict the assembly  100  after the outer sleeve  116  has already been moved upwardly to a position to where it does not block the port  114 . Prior to such movement, the piston area  132  would lie proximate ridge  134  shown in  FIG. 12   d , and the body of the sleeve  116  would, thereby, block the port  114 .  
      Once the outer sleeve  116  is moved upwardly to unblock the port  114 , fluid flow and production may occur from the lower completion section  106 . As the flow arrows in  FIG. 10  depict, production fluid will flow radially outwardly through the port  114  and into the annulus  130 . From there, the production fluid can enter the fluid inlets  128  of the pump  104  and, from there, upward through the upper completion section  102  to the surface of the wellbore  10 . If necessary to obtain good flow, the pump  104  is actuated to assist movement of the production fluid to the surface of the wellbore  10 .  
      When it is desired to cease production from the lower completion section  102 , the pump  104  is stopped, and the upper completion section  102  is pulled upwardly. The stinger assembly  126  will engage and move the inner sleeve  118  so that it once again blocks fluid communication through the port  114 . Further upward pulling of the upper completion section  102  will cause the valve body  110  to separate so that the upper latch assembly  122  and the stinger assembly  126  are removed, leaving the anchoring portion  124 , plug  120  and sleeves  116 , 118  within the wellbore  10  and secured to the packer device  30 . Fluid flow out of the lower completion section  106  is now blocked by the plug  120  and the closed inner sleeve  118 .  
      If it is desired to reestablish production from the lower completion section  106 , the upper completion section  102  may be reinserted into the wellbore  10  and the stinger assembly  126  reinserted into the portion of the valve body  110  that has been anchored to the packer device  30 . The stinger assembly  126  will reopen the port  114  by moving the inner sleeve  118  downwardly to a position where it no longer blocks the port  114 . Fluid flow, as illustrated in  FIG. 10 , will be reestablished.  
       FIGS. 12   a - 12   f  and  13   a - 13   f  provide a detailed illustration of an exemplary reservoir control assembly  100  so that further details of its construction and operation may be seen. In  FIGS. 12   d , the assembly  100  is shown with the outer sleeve  116  moved to a position so that it does not block the port  114  from a position (shown in dashed lines) wherein the sleeve  116  does block the port  114 . The outer sleeve  116  moves to its open position once the fluid pressure within the annulus  130  applied to the annular piston area  132  exceeds the shear value of the shear pin  134 , which secures the outer sleeve  116  to a retaining ring  136  upon the valve body  110 . Annulus pressure opening of the outer sleeve  116  is similar to that used in the CMP™ Defender sliding sleeve completion tool, available from Baker Oil Tools of Houston, Tex.  
      The inner sleeve  118  is initially closed (see  FIG. 12   d ) so that the port  114  is blocked. The stinger assembly  126  presents an engagement end  138  that contacts and engages a sleeve release ring  140 . The sleeve release ring  140  has an inner engagement shoulder  142  for receiving the engagement end  138  of the stinger assembly  126 . The sleeve release ring  140  also features a radially outer lug recess  144  and a lower sleeve-contacting end  146 . The inner sleeve  118  includes a lug opening  148 , and lug  150  resides within. Valve body  110  also includes a radially-inwardly facing lug recess  152 . Initially, the lug  150  is disposed within the lug recess  152 , as  FIG. 12   c  depicts. The lug  150  is trapped within the outer lug recess  144  by body of the release ring  140 . At this point, the lug  150  prevents the inner sleeve  188  from moving with respect to the valve body  110 . As the stinger assembly  126  is moved downwardly, the outer lug recess  144  becomes aligned with the lug  150 , and the lug  150  moves into the recess  144 . The sleeve member  118  may now move axially with respect to the valve body  110  (see  FIG. 13   c ). When the sleeve member  118  is moved axially downwardly, under impetus of the stinger assembly  126 , a fluid opening  154  in the sleeve member  118  is moved adjacent the port  114 , thereby opening the port  114  to fluid passage therethrough.  
      Upward movement of the upper completion section  102  will cause the stinger assembly  126  to reclose the port  114  against fluid communication before the upper completion section  102  is separated from the lower completion section  106 . As the stinger assembly  126  is moved upwardly, upward-facing engagement shoulder  156  (see  FIG. 13   c ) on the lower end of the stinger assembly  126  will engage a downward-facing shoulder  158  on the sleeve release ring  140 . The sleeve release ring  140  will urge the sleeve  118  upwardly as well, due to the interconnection provided by the lug  150 . Further upward movement of the upper completion section  102  will remove the upper latch assembly  122  and the stinger assembly  126  from the other components of the valve assembly  100 , leaving them in place in the wellbore  10 .  
      Those of skill in the art will understand that the reservoir control assembly  100  is, in many ways, preferable to the control assembly  25  described earlier, since, for example, it eliminates the need for an outer shroud, such as the shroud  80  used in the first embodiment.  
      It can be seen that the invention provides systems and methods for selectively closing off a section of a wellbore to fluid communication. The wellbore completion section may then be reopened to fluid communication upon reconnection of the upper completion section to the lower completion section. In the first described embodiment, a secondary fluid pathway may be opened in the event of a failure of the closed wellbore completion section to reopen in the intended manner. Advantageously, the systems and methods of the present invention generally preclude fluid communication between the annulus  18  of the upper completion section  22  and the flowbore of the lower completion section  24  until the lower completion section  24  is closed off to fluid flow.  
      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.