Wellbore injection system

Abstract

A wellbore injection system comprises a tubing hanger mountable within a wellbore tubular, an injection conduit supported by the tubing hanger to extend into the wellbore tubular, and an injection valve mountable within the wellbore tubular and arranged in fluid communication with the injection conduit. The injection valve is removable from the wellbore tubular independently of the tubing hanger and injection conduit.

Claims

1. A wellbore injection system, comprising: a tubing hanger mountable within a wellbore tubular; an injection conduit supported by the tubing hanger to extend into the wellbore tubular; an injection valve mountable within the wellbore tubular and arranged in fluid communication with the injection conduit; a delivery conduit in fluid communication with the injection valve, the delivery conduit providing fluid communication from a source of injection fluid to the injection conduit; and an injection fluid interface member for facilitating fluid communication between the delivery conduit and the injection valve; wherein the injection valve is removable from the wellbore tubular independently of the tubing hanger and injection conduit, and wherein the injection fluid interface member is releasably secured to the tubing hanger.

2. The wellbore injection system according to claim 1, wherein the injection valve permits the flow of fluid in only one direction therethrough.

3. The wellbore injection system according to claim 1, wherein the injection valve is mounted within the wellbore tubular via a releasable valve connection arrangement.

4. The wellbore injection system according to claim 1, wherein the injection valve is releasably mounted within the wellbore tubular via the tubing hanger.

5. The wellbore injection system according to claim 1, wherein the injection valve is releasably secured or securable to the tubing hanger via a connection with the injection conduit.

6. The wellbore injection system according to claim 1, wherein the injection valve is mounted within the wellbore tubular to define a space therebetween for accommodating fluid flow therealong.

7. The wellbore injection system according to claim 1, comprising a valve connection arrangement for facilitating connection between the injection valve and the injection conduit.

8. The wellbore injection system according to claim 1, wherein the delivery conduit extends from surface.

9. The wellbore injection system according to claim 1, wherein in use, the delivery conduit extends externally of the wellbore tubular.

10. The wellbore injection system according to claim 1, wherein the delivery conduit is coupled to a port or port system extending through a wall of the wellbore tubing to facilitate communication of injection fluid to the internally mounted injection valve.

11. The wellbore injection system according to claim 10, wherein the port or port system extends through the tubing hanger to facilitate communication of injection fluid to the injection valve.

12. The wellbore injection system according to claim 1, wherein the injection fluid interface member is mounted within the wellbore tubular via a releasable connection arrangement.

13. The wellbore injection system according to claim 1, wherein the injection fluid interface member is mounted within the wellbore tubular via the tubing hanger.

14. The wellbore injection system according to claim 1, wherein the injection fluid interface member defines a first port configurable in fluid communication with the delivery conduit.

15. The wellbore injection system according to claim 14, wherein the injection fluid interface member defines a second port configurable in fluid communication with the injection valve.

16. The wellbore injection system according to claim 14, wherein an injection flow path extends between the first and second ports, such that fluid received from the delivery conduit may be diverted through the interface member to the injection valve.

17. The wellbore injection system according to claim 1, wherein the injection valve is secured to the injection fluid interface member.

18. The wellbore injection system according to claim 1, wherein the injection fluid interface member comprises a bypass flow path extending therethrough for facilitating fluid flow along the wellbore tubular while the wellbore injection system is mounted therein.

19. The wellbore injection system according to claim 1, comprising a subsurface safety valve mountable within the wellbore tubular.

20. The wellbore injection system according to claim 19, wherein the subsurface safety valve is mounted above the injection valve.

21. The wellbore injection system according to claim 19, wherein the subsurface safety valve is retrievable independently of the tubing hanger and/or the injection conduit.

22. The wellbore injection system according to claim 19, wherein the subsurface safety valve is retrievable independently of the injection valve.

23. The wellbore injection system according to claim 19, wherein the subsurface safety valve is retrievable independently of the injection fluid interface member.

24. The wellbore injection system according to claim 19, wherein the subsurface safety valve is mounted within the wellbore tubular via a releasable connection arrangement.

25. The wellbore injection system according to claim 19, wherein the subsurface safety valve is mounted within the wellbore tubular via the tubing hanger.

26. The wellbore injection system according to claim 19, wherein the subsurface safety is coupled to the injection fluid interface member.

27. The wellbore injection system according to claim 19, wherein the subsurface safety valve is in fluid communication with the delivery conduit such that injection fluid also functions as a source of fluid power for operation of the subsurface safety valve.

28. The wellbore injection system according to claim 27, wherein the injection fluid delivery conduit comprises multiple branches, with at least one branch in communication with the injection valve, and at least one other branch in fluid communication with the subsurface safety valve.

29. The wellbore injection system according to claim 27, comprising an injection fluid diverter arrangement for diverting at least a portion of injection fluid from the delivery conduit to the injection valve, and at least a portion of the injection fluid from the delivery conduit to the subsurface safety valve.

30. The wellbore injection system according to claim 29, wherein the injection fluid diverter arrangement comprises an injection fluid chamber or chamber system which receives injection fluid from the delivery conduit, wherein the subsurface safety valve and the injection valve are in fluid communication with the injection fluid chamber or chamber system.

31. The wellbore injection system according to claim 30, wherein the injection fluid chamber or chamber system is at least partially defined by the tubing hanger.

32. A downhole system, comprising: a tubing hanger mountable within a wellbore tubular; an injection conduit supported by the tubing hanger to extend into the wellbore tubular; an injection valve mountable within the wellbore and arranged in fluid communication with the injection conduit; a delivery conduit in fluid communication with the injection valve, the delivery conduit providing fluid communication from a source of injection fluid to the injection conduit; and an injection fluid interface member for facilitating fluid communication between the delivery conduit and the injection valve; a subsurface safety valve mountable within the wellbore tubular; wherein the injection valve is removable from the wellbore independently of the tubing hanger and injection conduit, and wherein the injection fluid interface member is releasably secured to the tubing hanger.

33. A wellbore workover method, comprising retrieving an injection valve of a system according to claim 1 from a wellbore tubular by disconnecting the injection valve from an injection conduit, wherein the injection fluid conduit is supported by a tubing hanger.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) These and other aspects will now be described, by way of example only, with reference to the accompanying drawings, in which:

(2) FIG. 1 is a diagrammatic illustration of a production wellbore system, which incorporates an injection system according to aspects of the present invention;

(3) FIG. 2 is a diagrammatic illustration of individual components within the wellbore system of FIG. 1;

(4) FIG. 3 is a bottom view of an injection fluid interface member first illustrated in FIG. 2;

(5) FIG. 4 is a view of the wellbore system of FIG. 2, configured for simultaneous injection and production; and

(6) FIG. 5 is a view of the wellbore system of FIG. 2, illustrating a tubing hanger and capillary string remaining in place within the wellbore following removal of a safety valve and injection valve.

DETAILED DESCRIPTION OF THE DRAWINGS

(7) FIG. 1 provides a diagrammatic illustration of a production wellbore system, generally identified by reference numeral 10, which includes a wellbore injection system 12 according to aspects of the present invention. The wellbore system 10 includes a drilled bore 14, wherein in the exemplary embodiment shown an upper bore section 14a is lined with casing 16, whereas a lower bore section 14b is open hole. A wellbore tubular string, in this case a production tubing string 18 extends from a topside facility, in this case a wellhead 20, to a production zone 22 of a subterranean reservoir. The lower end 18a of the production tubing string 18 includes a number of ports or perforations 24 which facilitate inflow of fluids from the production zone 22, in the direction of arrows 26, and subsequent production towards the wellhead 20, illustrated by arrows 28. Produced fluids are then delivered through a topside production conduit 30, for example to a pipeline or storage facility.

(8) The injection system 12 is configured to permit simultaneous injection and production within the same wellbore system 10. The injection system 12 includes an injection conduit, which may be referred to as a capillary conduit 32 which extends between upper and lower regions of the production tubing 18. The capillary conduit is in fluid communication with a delivery conduit 34 which extends along an annulus 36 formed between the production tubing 18 and the wellbore casing 16, The delivering conduit 34 extends to the wellhead 20, and in in fluid communication with an injection fluid supply line 38.

(9) During use, injection fluid is delivered, via the supply line 38, delivery conduit 34 and capillary conduit 32, to be injected into the lower end of the production tubing string 18 generally in the region of the production zone 22. The injection fluid may be selected to provide any suitable effect. However, in the embodiment shown the injection fluid is selected to assist in the production of fluids from the production zone towards the surface. For example, the injection fluid may be arranged to form a foam upon contact with water located at the production zone 22. This foam may facilitate improved production. In particular, such foaming agents may facilitate improved gas production.

(10) The injection system 12 further includes a series of one-way valves to prevent backflow to surface through the injection system. In particular, the injection system 12 includes a first valve arrangement 40 coupled to an upper region of the capillary conduit 32, and a second valve arrangement 42 coupled to a lower region of the capillary conduit 32.

(11) A more detailed, yet still diagrammatic, illustration of the injection system 12 is provided in FIG. 2. The injection system 12 includes a tubing hanger 50 which is mechanically secured to the production tubing via a releasable connector system 52, and sealed via seals 54, 56. The tubing hanger 50 includes a tubing interface 58 for engaging and supporting the capillary string 18, while still permitting bypass of production fluids via hanger bypass ports 61.

(12) The tubing hanger includes a tubular structure 60 which is generally concentrically aligned within the production tubing 18, wherein the seals 54, 56 are positioned to provide sealing between the tubular structure 60 and the production tubing 18.

(13) The tubular structure 60 together with the production tubing 18 and seals 54, 56 define a chamber system, wherein the delivery conduit 34 is in fluid communication with the chamber system 62 via a port 64 through the wall of the production tubing 18. As such, injection fluid from the delivery conduit may be delivered into the chamber system 62.

(14) The injection system 12 in the embodiment shown includes a subsurface safety valve, generally identified by reference numeral 66, positioned within the tubular structure 60 of the tubing hanger 50, specifically above the tubing interface 58 of the tubing hanger 60. The subsurface safety valve 66 is mechanically connected to the tubular structure 60 via a suitable releasable connector 68, and as such the subsurface safety valve 66 is mounted within the production tubing string 18 via the tubing hanger 50.

(15) The subsurface safety valve includes a housing 69 and a pivoting flapper 70 mounted relative to the housing 69 and shown in FIG. 2 in a closed position. Although not illustrated, the flapper includes a biasing arrangement, such as a torsion spring, which biases the flapper 70 towards its illustrated closed position. An axially moveable flow tube 72 is mounted within the housing, and a spring member 74 acts between the housing 69 and flow tube 72 to bias the flow tube 72 in an upper direction, to the position shown in FIG. 2, in which the flow tube 72 does not interfere with the flapper 70, allowing the flapper to remain in its illustrated closed position.

(16) A hydraulic chamber 76 is defined between the flow tube 72 and housing 69, wherein the hydraulic chamber 76 is in fluid communication with the chamber system 62 via respective ports 78, 80 formed in the housing 69 of the safety valve 66 and the tubular structure 60 of the tubing hanger 50. As will be described in more detail below, fluid pressure acting in the hydraulic chamber 76 will cause the flow tube 72 to move downwards, compressing the spring 74 and causing the flapper 70 to pivot to an open position. Removal or reduction of fluid pressure will permit the spring 74 to return the flow tube 72 to its original position, allowing the flapper 70 to again close. Furthermore, the flapper will be positively held closed by pressure from below.

(17) A fluid interface member 82 is sealingly mounted within the production tubing string 18, specifically within the tubular structure 60 of the tubing hanger 50, above the tubing interface 58, and is threadedly secured to a lower end of the subsurface safety valve 66, and thus supported by said valve 66. The fluid interface member 82 includes a first port 84 in a side wall thereof which is arranged in fluid communication with the chamber system 62 via port 86 in the tubular structure 60 of the tubing hanger 50. The fluid interface member 82 further includes a second port 88 in an axial end face thereof, with a fluid path 90 extending between the first and second ports.

(18) The fluid interface member 82 includes a bypass flow path 91 arranged to permit production fluids to bypass said interface member. With additional reference to FIG. 3, which shows the form of the interface member 82 from below, the bypass flow path 91 is generally C-shaped, extending around the central second port 88.

(19) The first valve arrangement 40, which may be referred to as a first injection valve arrangement, is secured, for example by a threaded connection, to the interface member 82, such that the first injection valve arrangement 40 is in fluid communication with the second port 88 of the interface member 82.

(20) The first injection valve arrangement 40 includes a one-way check or crack valve 92. Further, the first injection valve arrangement 40 is coupled to the capillary conduit 32 via a releasable stab-in type connection 94.

(21) The second valve arrangement 42, which may be defined as a second injection valve arrangement, is mounted on the lower end of the capillary conduit 32 and in the embodiment shown includes a pair of series mounted one-way check or crack valves 96, 98.

(22) The wellbore injection system 12 is shown in FIG. 2 in a non-injecting and non-producing configuration, which is achieved by zero or insufficient injection fluid pressure provided via the delivery conduit 34. However, when injection and production is required, an operator will increase the injection fluid pressure. In this respect, FIG. 4 illustrates the injection system 12 when configured for simultaneous injection and production.

(23) Specifically, injection fluid will flow, under pressure, into the chamber system 62, with pressure communicated, via ports 78, 80 to the hydraulic chamber 76 of the subsurface safety valve 66, causing the flow tube 72 to move axially downwards and cause the flapper 70 to open, to thus support production.

(24) Also, injection fluid will flow from the chamber system 62, through the fluid interface member 82, through the first injection valve arrangement 40, through the capillary conduit 32, and finally through the second injection valve arrangement 42 before existing into the wellbore. If injection pressure is ever reduced or ceased, whether intentionally or due to some failure, the subsurface safety valve 66 will again close, and the first and second injection valve arrangements 40, 42 will prevent any reverse flow.

(25) In some cases it may be necessary to retrieve components of the injection system 12, for example for inspection, repair and/or replacement. For example, the first injection valve arrangement 40 may in some cases become compromised, for example due to wear of valve seats/seals, blockage by debris or the like. Particular sensitivities to failure modes may be present when high pressures and/or low volumetric flow rates need to be accommodated, for example when a very small valve opening may need to be continuously maintained when in use.

(26) The present invention may be advantageous in that retrieval of the first valve arrangement 40 may be achieved independently of the tubing hanger 50, and thus of the capillary conduit 32. That is, the injection system 12 is arranged to permit the first valve arrangement 40 to be removed/replaced while leaving the capillary conduit 32 in place. Otherwise, as in prior known arrangements, the entire length of the capillary conduit, which can extend for thousands of meters, may need to be retrieved.

(27) In this respect, if the first valve arrangement 40, or indeed the subsurface safety valve 66 or fluid interface member 82 need to be retrieved, this may be achieved by use of an appropriate retrieval tool or system, as known in the art, for example wireline and/or tubing retrieval systems. The retrieval system may latch or otherwise connect to the subsurface safety valve, and be operated to release this from the tubing hanger 50, permitting the safety valve 66 and connected interface member 82 and first valve arrangement 40 to be retrieved to surface, with the first injection valve arrangement 40 being released from the capillary conduit 32 at the releasable stab-in type connection 94. This will leave the tubing hanger 50 and capillary conduit 32 in place, as illustrated in FIG. 5.

(28) Nevertheless, should the tubing hanger and/or capillary conduit 32 ever need to be retrieved, this of course is still possible by suitable retrieval of the tubing hanger, for example by wireline, coiled tubing retrieval or the like.

(29) It should be understood that the embodiments described above are merely exemplary and that various modifications may be made thereto without departing from the scope of the present invention. For example, in the illustrated embodiment the tubing hanger includes a tubular structure within which other components of the injection system are located. However, in other embodiments one or more components may be directly located within the wellbore tubular (e.g., production tubing).

(30) Further, in other embodiments the subsurface safety valve may not be present. Also, in some cases the injection system may be utilised in a wellbore which does not support simultaneous production, for example in an exclusive injection well.