Abstract:
An actuating apparatus for a downhole valve including a tubular body, which includes an axial bore that extends through the body. The actuating apparatus also includes an operating member that is adapted to move relative to the tubular body. The movement of the operating member relative to the tubular body is between a first position and a second position such that fluid contained within a reservoir is displaced when such a downhole valve is actuated. The actuating apparatus is adapted to be fluidly coupled to the downhole valve.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     The present application claims priority to United Kingdom Patent Application No. GB1117502.3, filed Oct. 11, 2011, and titled VALVE ACTUATING APPARATUS, the contents of which are expressly incorporated herein by reference. 
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to valve actuating apparatus operable to actuate a downhole valve assembly. In particular, the present invention relates to a valve actuating apparatus that provides a contingency/back-up device operable to actuate a downhole valve that has failed to operate. 
     2. Description of the Related Art 
     Well completion involves various downhole procedures prior to allowing production fluids to flow thereby bringing the well on line. One of the downhole procedures routinely carried out during well completion is pressure testing where one downhole section of the well is isolated from another downhole section of the well by a closed valve mechanism such that the integrity of the wellbore casing/liner can be tested. 
     Well completion generally involves the assembly of downhole tubulars and equipment that is required to enable safe and efficient production from a well. In the following, well completion is described as being carried out in stages/sections. The integrity of each section may be tested before introducing the next section. The terms lower completion, intermediate completion and upper completion are used to describe separate completion stages that are fluidly coupled or in fluid communication with the next completion stage to allow production fluid to flow. 
     Lower completion refers to the portion of the well that is across the production or injection zone and which comprises perforations in the case of a cemented casing such that production flow can enter the inside of the production tubing such that production fluid can flow towards the surface. 
     Intermediate completion refers to the completion stage that is fluidly coupled to the lower completion and upper completion refers to the section of the well that extends from the intermediate completion to carry production fluid to the surface. 
     During testing of the intermediate completion stage the lower completion is isolated from the intermediate completion by a closed valve located in the intermediate completion. When the integrity of the tubing forming the intermediate completion section is confirmed the upper completion stage can be run-in. 
     Generally the completion stages are run-in with valves open and then the valves are subsequently closed such that the completion stages can be isolated from each other and the integrity of the production tubing and the well casing/wall can be tested. 
     Typically, the valves remain downhole and are opened to allow production fluids to flow. By opening the valves the flow of production fluids is not impeded. 
     In the event that a valve fails to open, for example where the valve or an actuating mechanism operable to open the valve becomes jammed, remedial action is generally required because a failed valve effectively blocks the production path. 
     Remedial action often involves removing the valve. The valve may be removed by milling or drilling the valve out of the wellbore to provide a free flowing path for production fluid. 
     It will be appreciated that resorting to such remedial action can result in costly downtime because production from the well is stopped or delayed. The remedial action may result in damage to the well itself where milling or drilling the valve or valves from the wellbore may create perforations in the production tubing or the well casing or well lining. As a result such actions would preferably be avoided. 
     In the above the importance of opening a valve to allow production to flow has been discussed. However, in the situation of a producing well requiring workover it is equally important to be able to isolate sections of the well to stop/halt production flow. 
     Workover requires that the well is shut-in below the surface or the well must first be killed. 
     Often in preparation for workover the completion assembly is removed, however, sometimes due to the placement of a packer in the well, for example a permanent packer, it can be problematic to remove a completion string for workover. Therefore, an alternative to retrieving the completion string is to isolate the well by shutting off production by closing a downhole valve. Conventionally, control lines from surface facilitate fluid communication downhole to the valves in order to close the valves. 
     However, in the event that the valve fails to close other operations to prepare the well for workover may be implemented such as killing the well. A well can be killed by using reverse circulation or by pumping heavy weight fluids into the well. It is desirable to provide a downhole device such that production downtime due to a failed valve is reduced. 
     It is further desirable to provide an actuating apparatus that provides a secondary actuating mechanism operable to actuate a failed valve located in the wellbore. 
     BRIEF SUMMARY OF THE INVENTION 
     A first aspect of the present invention provides an actuating apparatus for a downhole valve; the actuating apparatus comprises: 
     a tubular body comprising an axial bore extending through the body; 
     an operating member adapted to move relative to the tubular body; and 
     a reservoir adapted to contain fluid; 
     wherein the operating member is movable relative to the tubular body between a first position and a second position to displace fluid contained within the reservoir and thereby actuate a downhole valve, wherein the actuating apparatus is adapted to be fluidly coupled to the downhole valve. 
     The operating member may be arranged within the axial bore of the tubular body. 
     The operating member may comprise a sleeve. 
     The reservoir may be defined by an annulus region defined between the operating member and the tubular body. The reservoir may comprise an inlet port and an outlet port. The outlet port may be fluidly coupled to a downhole valve. 
     The actuating apparatus may further comprise a piston member. 
     The operating member may comprise a piston member. 
     The piston member may be arranged to compress and displace fluid contained in the reservoir via the outlet port of the reservoir to the inlet port of a downhole valve such that the downhole valve may be actuated. 
     Movement of the operating member may compress and displace the fluid by action of the piston member on the fluid such that the downhole valve is actuated. Displacement of the fluid from the reservoir and actuation of the downhole valve may occur simultaneously. 
     The piston member may be arranged on a downhole side of the reservoir. 
     Movement of the operating member may be in either direction. For example, movement of the operating member in an uphole or downhole direction may displace fluid (by action of the piston member) in a generally downhole direction such that a downhole valve is actuated. 
     Fluid communication between the actuating apparatus and the downhole valve may be provided by a conduit extending from the outlet port to the downhole valve. The conduit may be contained within a downhole completion. 
     The operating member may comprise a coupling member. The coupling member may be configured to mechanically engage with a corresponding coupling member of a downhole tool such as a stinger or shifting tool. 
     Removal of the downhole tool, in a generally uphole direction may cause engagement of the coupling member of the downhole tool with the coupling member of the operating member such that the operating member may slide relative to the tubular body. Extraction of the downhole tool in conjunction with the operating member may move the operating member such that the downhole valve is actuated. 
     The coupling member of the downhole tool and the coupling member of the operating member may disengage following successful actuation of the downhole valve. 
     The downhole valve may be located downhole of the actuating apparatus. 
     The actuating apparatus according to embodiments of the present invention may provide a secondary actuator that is operable to actuate a valve that has failed to operate in response to primary actuation. 
     The actuating apparatus according to the present invention may be operable to open or close a downhole valve. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
       Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: 
         FIG. 1  is a schematic representation of a wellbore assembly comprising an actuating apparatus in accordance with an embodiment of the present invention; 
         FIG. 2  is a schematic representation of the actuating apparatus in accordance with an embodiment of the present invention; and 
         FIG. 3  is a schematic representation of the actuating apparatus in the operating configuration. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Referring to  FIG. 1 , a partial longitudinal view of a wellbore completion arrangement  100  is illustrated. The wellbore completion arrangement  100  comprises a downhole valve assembly  10 , an actuating apparatus  12  and a packer assembly  14 . 
     In the illustrated example, a wellbore  16  is lined with a casing  18 , which in the illustrated embodiment is held in place with cement  20 . 
     The downhole valve assembly  10 , the actuating apparatus  12  and the packer assembly  14  are all run into the wellbore as part of the well completion assembly  100  on a stinger (not illustrated). The actuating apparatus  12  and the downhole valve assembly are connected by a conduit  49  that allows for hydraulic actuation of the downhole valve  10  in the event that it fails to actuate due to primary actuation. 
     For illustrative purposes,  FIG. 1  does not indicate any specific form or type of downhole valve assembly  10 . Suitable valve assemblies  10  will be discussed further below with respect to the action of the actuating apparatus  12  according to embodiments of the present invention. 
     The packer assembly  14  provides a seal in the annulus region  15 , which is defined by the space between the outside of the production tubing  22  and the inside of the casing  18 . 
     In the illustrated embodiment the downhole valve assembly  10  is run-in in an open configuration and is subsequently closed when it has reached its location downhole. Once closed, fluid pressure can be applied from above the downhole valve assembly  10  to check the integrity of the production tubing  22 . Following successful testing, the downhole valve assembly  10  can be opened again such that production fluid can flow unimpeded through the downhole valve assembly  10  when the well is brought on line. 
     “The downhole valve assembly  10  can be opened by a suitable primary actuating apparatus  11 , which may include, for example, fluid pressure from control lines to the surface, mechanical actuation components or remote electronic actuation components. Examples of suitable valves are ball valves, flapper valves and sleeve valves.” 
       FIG. 2  illustrates a schematic representation of an actuating apparatus  12  according an embodiment of the present invention. The actuating apparatus  12  provides a secondary actuator operable to close a downhole valve  10  (see  FIG. 1 ) that has failed to close under primary actuation, such as by applying fluid pressure via control lines from surface. 
     The actuating apparatus  12  according to an embodiment of the present invention comprises a tubular body  30 , which includes an axial bore  32  between an inlet end  34  and an outlet end  36 . The inlet  34  and the outlet  36  each comprise a threaded connection  38 ,  40  for attachment to the production tubing  22  (see  FIG. 1 ) of a downhole assembly. 
     The actuating apparatus  12  also comprises an operating sleeve  42  which is movable relative to the body  30  as described further below with reference to  FIG. 3 . 
     The body  30  and the sleeve  42  are assembled coaxially such that an annular reservoir  44  is defined between them. The annular reservoir  44  contains hydraulic fluid which is compressed and displaced upon displacement of the sleeve  42  due to the action of removal of the stinger (not illustrated). 
     The body  30  includes an outlet port  46  on the outside of the body  30  and an inlet port  48  open to the inside of body  30 , where the inlet port  48  is arranged to receive fluid from the annular reservoir  44  upon displacement of the sleeve  42  due to the action of removal of the stinger. 
     The outlet port  46  is in fluid communication with a conduit  49  that fluidly couples the annular reservoir  44  of the actuating apparatus  12  with the downhole valve assembly  10  in a region downhole of the actuating apparatus  12 . 
     The operating sleeve  42  moves by the action of retrieval/withdrawal of a stinger (not illustrated) from the completion assembly  100 . 
     The stinger (not illustrated) includes a mechanical coupling device such as collet fingers that are operable to engage with the profiled section  50  of the sleeve  42  such that the stinger engages with and pulls the sleeve  42  as the stinger is pulled in an uphole direction from the completion assembly  100 . The sleeve  42  reaches a stop  52  inside the body  30 , at which point the stinger can be disengaged from the sleeve  42 . 
     The sleeve  42  moves from the position illustrated in  FIG. 2  to the position illustrated in  FIG. 3 . As the sleeve  42  moves, by action of the stinger, fluid is displaced from the annular reservoir  44  through the inlet port  48  and out of the outlet port  46  such that fluid pressure is applied downhole to close the downhole valve  10  that has failed to close under primary actuation. 
     The sleeve  42  incorporates a piston member  54  that acts to compress and displace the fluid such that the downhole valve  10  can be closed or opened if the actuation is reversed. 
     The actuating apparatus includes a return port  51 . The return port  51  provides a path for fluid that is displaced from the downhole valve  10  upon actuation of the valve via the actuating apparatus  12 . 
     In the situation where the valve  10  is closed by the actuating apparatus  12  and subsequent to closing the valve  10  by action of the actuating apparatus  12  a pressure test may be carried out, for example, by applying tubing pressure  56  (as illustrated in  FIG. 3 ) from an uphole region of the valve  10  to ensure that the valve  10  is fully closed and to ensure that the well is shut off. When it is established that the well is shut off, the stinger can be fully withdrawn to allow workover operation to begin. 
     The axial bore  32  of the actuating apparatus  12  is permanently open such that it does not impede flow in a producing well and also during preparation for workover, where the axial bore  32  facilitates application of fluid pressure to the downhole valve  10  such that the status of the well is assured before proceeding with workover. 
     Following workover, it may be the case that the well is to resume production. Therefore, the axial bore  32  again does not impede flow when the valve  10  is opened again. 
     In summary, the embodiment described above may be used in preparation of a well for workover of a well. The actuating apparatus  12  provides a back-up and contingency device that offers reassurance and certainty that downhole valves are closed such that a well is ready for workover. 
     While specific embodiments of the present invention have been described above, it will be appreciated that departures from the described embodiments may still fall within the scope of the present invention.