Patent Publication Number: US-2013233563-A1

Title: Well isolation control system and method

Description:
BACKGROUND 
     In the drilling, completion and Carbon Dioxide sequestration arts there are times during the life of the operation that various subsystems must be removed from a borehole for repair, replacement or reconfiguration. Such activities generally are intertwined with a host of regulatory and procedural steps, requirements, prohibitions, etc. The art has developed over the years many systems and methods to remove strings from a borehole while carefully threading their way through the morass of issues. Many of these systems and methods work well for their intended purposes. With ever changing technology and realities, however, the art is unabatingly in the pursuit of additional systems and methods that function to overcome new challenges or reduce costs or complexity with respect to removal of systems or subsystems from the downhole environment. 
     SUMMARY 
     An isolation and control system including a valve; a stroker operative to shift the valve between open and closed positions; and at least one control line operative to pressurize the stroker responsive to tubing pressure. 
     A method for isolation and control in a borehole including running a plug having a pathway defined therein that leads to tubing pressure at one end and to the at least one control line at the other end to a system including a valve; a stroker operative to shift the valve between open and closed positions; and at least one control line operative to pressurize the stroker responsive to tubing pressure; pressurizing a tubing string connected to the system including a valve; a stroker operative to shift the valve between open and closed positions; and at least one control line operative to pressurize the stroker responsive to tubing pressure; shifting the stroker with the tubing pressure through the at least one control line; and closing the valve. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike: 
         FIG. 1  is a cross sectional schematic view of a system disclosed herein in a first position; 
         FIG. 2  is a cross sectional schematic view of a system disclosed herein in a second position; 
         FIG. 3  is a cross sectional schematic view of a system disclosed herein in a third position; 
         FIG. 4  is a cross sectional schematic view of a system disclosed herein in a fourth position; 
         FIG. 5  is a cross sectional schematic view of a system disclosed herein in a fifth position. 
     
    
    
     DETAILED DESCRIPTION 
     A system  10  is illustrated and described that reduces costs and materials while improving efficiency of the system. Further the system enables a method disclosed hereinbelow to effectively and reliably remove a pump from a downhole environment while adhering to all appropriate best practices and regulatory requirements. The system will be described first to ease understanding of the method. 
     Arbitrarily starting at the downhole end of the system  10  depicted in  FIG. 1 , a bull plug  12  is mounted at a downhole end of a tail pipe  14  of a valve  16 . As illustrated the valve  16  is a sliding sleeve but other valves could be substituted. The valve is actuable with a stoker tool  18  that comprises a shifting sleeve  20  and a hydraulic actuator  22 . The shifting sleeve  20  includes an engagement configuration  24  that disengageably engages the sliding sleeve  16  to move the same to an open or a closed position depending upon the direction of actuation from the hydraulic actuator  22 . The shifting sleeve  20  further includes openings  26  to allow fluid passage therethrough when the valve  16  is open. 
     It is well to note that the valve  16  is located downhole of a permanent packer  28  and that the shifting sleeve  20  extends from uphole of the packer  28  to the valve  16  downhole of the packer  28 . The hydraulic actuator  22  is landed on the packer  28  at seat  30 . When the system is removed from the borehole, the hydraulic actuator is unseated from the packer, leaving the packer and valve in place and the shifting sleeve  20  is pulled up through the center of the packer  28  with the rest of the system as it is being retrieved. The packer and the valve, then, are what contains the formation fluid within the formation when the system is conditioned to close in the well and remove the system. 
     Adjacent the hydraulic actuator  22  is a perforated sub  32  through which fluids may flow and which spaces the hydraulic actuator  22  from an electronic submersible pump (ESP)  34  (as illustrated) or other pumping arrangement such as a sucker rod, etc. The ESP  34  or other pumping arrangement includes one or more inlets  36  and one or more outlets  38 . Adjacent the ESP  34  is a control nipple  40 . The nipple  40  presents at least one and as shown two control line connections  46  and  48  for at least one control line and as shown two control lines: a closing control line  42  and an opening control line  44 , respectively. The connections extend through the body of the nipple and open to the inside surface at an inside dimension thereof. Without additional structure, the connections labeled as  46  and  48  would both be open to tubing pressure. The control nipple does not however leave the connections open to tubing pressure but rather receives a production/isolation sleeve  50  that blocks both of the control line connections  46  and  48  thereby dead heading the control lines  42  and  44  and hydraulically locking the hydraulic actuator  22 . The production/isolation sleeve  50  includes a retrieval feature  52  in order to be retrieved selectively. 
     In the condition illustrated in  FIG. 1  and described above, the system is capable of being on production. The valve  16  is hydraulically locked open by the hydraulic actuator, whose control lines  42  and  44  are dead headed at the production/isolation sleeve. Hydrocarbons or other target fluid is passed from the formation through the open valve  16 , through the shifting sleeve  20  and through the inside of actuator  22 . The fluid will then move radially outwardly through the holes in perforated sub  32  to the annulus  54 . The fluid then enters inlets  36  of the pumping arrangement  34  and is pumped up the tubing string  56 . 
     The configuration as illustrated and described provides for significant benefits to operation of a borehole system as will become more apparent below during discussion of the method of use of the well isolation system described above. The Well isolation system provides further benefits in that the cost of the system is significantly lower than other tools having control line operated hydraulic actuators due to the reduction in length of control lines and the associated reduction in hardware and risks associated with extended length control lines. Finally, the system as described allows the use of tubing pressure to actuate the hydraulic actuator. 
     The well isolation system described above is particularly suited to facilitate repair or replacement of an ESP (or other arrangement or system) while being in compliance with all regulations and yet still avoid damage to the formation. 
     Considering  FIGS. 1 and 2  simultaneously, use of the system and the method for controlling the borehole while removing the tubing and pumping arrangement, is addressed. In  FIG. 2 , it is to be appreciated that the production/isolation sleeve  50  has been removed. The well is being taken off production and is being readied for additional operations related to the replacement of the ESP or other pumping arrangement. Removal of the production/isolation sleeve is done via slickline or similar run from surface and using the retrieval feature  52  to engage and retrieve the production/isolation sleeve. It is to be noted that while slickline is specifically referred to ubiquitously herein, this is exemplary and any other string capable of producing similar results of pulling and running portions of the system  10  is contemplated. Running and retrieving slickline (or other string) is known to the art and need not be shown. 
     The production and isolation sleeve  50  is replaced with closing plug  60  run into position on another slickline run. The closing plug  60  is an interface member that allows the use of tubing pressure to interact with the relatively short control lines  42  and  44  to effect changes in the position of the stroker  18  and thereby the position of the valve  16 . Closing plug  60  as will be appreciated in  FIG. 2  comprises two pathways therein. Closing pathway  62  provides fluid communication between tubing  56  and an annular space  64  created by the closing plug  60 , between the closing plug  60  and the nipple  40 . Connection  46  is in fluid communication with this annular space  64  and hence tubing pressure is communicated to control line  42 . Through this pressure (and fluid) pathway, the actuator  22  can be employed to shift the shifting sleeve  20  simply by pressuring up on the tubing string from surface. With such configuration the benefit of not having a full length control line is realized without any reduction is function of the stroker  18 . More specifically, fluid and its accompanying pressure is forced into chamber  66  of hydraulic actuator  22  thereby moving piston  68  in a direction associated with causing the shifting sleeve  20  to close the valve  16 . In the configuration shown in  FIG. 2 , this direction is uphole. The direction could, of course, be reversed if desired or required.  FIG. 2  shows chamber  66  much enlarged by inflow of fluid relative to the position shown in  FIG. 1  while chamber  70  has become much smaller. The fluid in chamber  70  is forced through control line  44  to closing plug  60 . The fluid will pass through connection  48  and annular space  72  created by and between the closing plug  60  and the nipple  40 . A dump pathway  74  is presented in closing plug  40  that connects through the annular space  72  to the connection  48  and to the ID outlet of the ESP  34  to dump excess fluid during the closing operation. 
     At this point the valve  16  is closed and testing to prove this condition can commence. It is desirable to test the condition for at least three reasons. First, closure of valve  16  in conjunction with the packer  28  and bull plug  12  provide a mechanical pressure barrier to facilitate safe removal of the system; second, it is undesirable to lose target produced fluids at the surface due to a leaking valve and third, it is undesirable to allow Kill fluid to enter the formation, where it is likely to deleteriously affect future production. To test the valve, pressure is bled off the well. Tubing  56  pressure is then monitored looking for any increase. If pressure rises, then the formation is still producing through the valve, packer or bull plug meaning that the valve is not fully closed or the listed components are otherwise incapable of holding pressure from the formation. In such case other remediating action may be needed. If pressure does not rise, the valve is indeed closed and it, the bull plug and the packer are holding pressure from below. In some cases, the operator may end testing here but in others there may be an interest in testing from above. This will test packer  28 , valve  16  and bull plug  12  as did the test from below but will also test the casing integrity as well. If such is desired, the operator may optionally increase pressure in the column from surface and monitor for bleed down. Assuming at least the first test is successful, meaning that the valve has been successfully closed, the method can be continued. 
     The closing plug  60  is pulled on slick line, the production/isolation sleeve is run on slickline back to the nipple  40  and then kill weight fluid is added to the well in sufficient volume and density to overbalance formation pressure thereby preventing the production of fluid from the well should the valve  16  fail. The kill fluid is applied though the tubing  56  and makes its way to the inside of the valve  16  where it will stop and apply a pressure that is at least calculated to exert greater pressure on the valve than the formation pressure). Accordingly, the system prevents formation fouling by the kill fluid while still allowing the kill fluid to be used to meet regulations or function as a backup. The well is safe and the Christmas tree can be disconnected, which action will be undertaken at this point and the blow out preventer (BOP) installed. Christmas trees and BOPs are well known in the art and require no explanation. 
     The removable portion of the system  10  is now in condition to be pulled to surface as shown in  FIG. 3 . This includes nipple  40 , ESP  34 , perforated sub  32 , hydraulic actuator  22  and shifting sleeve  20 . Whatever is to be done with these components at surface may be done and then the system reset for the trip back into the hole. The system  10 , likely with a new ESP  34  is configured with the production/isolation sleeve in place within the nipple  40  and the shifting sleeve  20  at the fully closed position as illustrated. The hydraulic actuator  22  is hydraulically locked with the chamber  66  enlarged and chamber  70  collapsed. The locking is due to the production/isolation sleeve  50  dead-heading the control lines  42  and  44 . 
     The removable portion of the system is now re-run to depth and stabbed back into the packer  28 . The valve  16  is still closed and the kill weight fluid is still in place so the BOP can be removed and the Christmas tree reinstalled. A portion of the kill weight fluid is pumped out of the well, that portion ensuring that the remaining kill fluid exerts a pressure on the valve  16  of less than formation pressure so that upon opening of the valve, the kill weight fluid will not penetrate the formation but rather, formation fluid will immediately begin to slowly move through the valve. Subsequently, the production/isolation sleeve  50  is retrieved on slickline through the reinstalled Christmas tree and another slickline run replaces the production/isolation sleeve  50  with an opening plug  76 . 
     The opening plug  76  is similar to the closing plug  60  discussed above but reverses the connection of the control lines  42  and  44  with respect to tubing pressure and dumping duty. The opening plug  76  creates similar annular spaces for fluid communication but communicates tubing fluid/pressure to control line  44  thereby allowing applied tubing pressure from surface to actuate the hydraulic actuator  22  by introducing fluid into chamber  70  and urging the shifting sleeve  20  to move the valve  16  to the open position. Fluid from chamber  66  is routed through control line  42  to a dump pathway in the opening plug and into the outlet of the ESP  34 . Once the valve  16  has been fully opened, the opening plug  76  is retrieved again on slick line using the fishing neck  78  and the production/isolation sleeve  50  is re-run into the well. The ESP is tested, fluid level monitored and the well can then be put on production. The remaining kill weight fluid will be produced from the well along with the target fluids.