Patent Application
20130233563
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.
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.
The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
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
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
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
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
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
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.
