Cable Hanger with Integrated Internal Tree Cap

Abstract

A cable hanger for use in a tree of a well including a bore includes a body and first and second barrier systems located on the body. The first barrier system includes a first seal configured to seal against the bore of the tree to establish a pressure barrier, and a first latching mechanism, wherein upon actuation, is configured to engage the tree and hold the cable hanger in place in the tree. The second barrier system includes a second seal configured to seal against the bore of the tree, and a second latching mechanism, configured such that upon actuation, it engages the tree and holds the cable hanger in place in the tree. The cable hanger further includes at least one of a hydraulic line or an electrical conductor extending through a portion of the body.

Description

CONTEXT

This section is intended to provide relevant contextual information to facilitate a better understanding of the various aspects of the described embodiments. Accordingly, it should be understood that these statements are to be read in this light and not as admissions of prior art.

Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates a hydrocarbon-bearing formation. Once a wellbore is drilled, various forms of well completion components may be installed to control and enhance the efficiency of producing the various fluids from the reservoir. One piece of equipment that may be installed is an electric submersible pump (ESP). ESPs provide a form of “artificial lift” by decreasing the pressure at the bottom of the well below the pump. The pressure differential allows more production fluid to be pumped from the well compared to natural recovery. ESPs may be deployed in both subsea and non-subsea completions.

ESPs are typically suspended from the wellhead by production tubing. In some applications the ESP is suspended in the well by means of a power cable with armor wires. The suspension system includes a cable hanger with the ESP and cable suspended therefrom and an internal tree cap. Typically, the cable hanger is landed into the wellhead by a running tool. The cable hanger is configured to form a first pressure barrier with the wellhead against the pressure of the well. After the cable hanger is set, the running tool is detached from the cable hanger and used to land an internal tree cap on top of the cable hanger, which provides a second pressure barrier. The landing of the cable hanger and internal tree cap and setting of the two pressure barriers requires two running trips.

Additionally, to function, ESPs is provided with electric power and/or hydraulics. Thus, a connection might be made between separate parts of the suspension system, including between the cable hanger and the internal tree cap. In oilfield operations, it is desirable to minimize the number running trips as well as the number of connections needed.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 depicts a well completion featuring a cable hanger with integrated tree cap, in accordance with one or more embodiments;

FIG. 2 depicts a detailed view of an ESP suspension system, including a cable hanger with integrated tree cap, in accordance with one or more embodiments;

FIG. 3 depicts a perspective view of the cable hanger with integrated tree cap, in accordance with one or more embodiments;

FIG. 4A depicts a cross-sectional view of the cable hanger with integrated tree cap in an unlatched position, in accordance with one or more embodiments;

FIG. 4B depicts a cross-sectional view of the cable hanger with integrated tree cap with one latch actuated, in accordance with one or more embodiments;

FIG. 4C depicts a cross-sectional view of the cable hanger with integrated tree cap with both latches actuated, in accordance with one or more embodiments;

FIG. 5A depicts a detailed cross-section view of a hydraulic coupler of the cable hanger with integrated tree cap in a closed position, in accordance with one or more embodiments;

FIG. 5B depicts a detailed cross-section view of the hydraulic coupler in an open position, in accordance with one or more embodiments;

FIG. 6A illustrates a hydraulic connector bonnet disengaged from the hydraulic coupler, in accordance with one or more embodiments;

FIG. 6B depicts the hydraulic coupler actuated by the hydraulic connector bonnet, in accordance with one or more embodiments; and

FIG. 7 illustrates a pressure compensation section of the cable hanger, in accordance with one or more embodiments.

DETAILED DESCRIPTION

Embodiments of the present disclosure provide a cable hanger with an integrated internal tree cap that can be set within a tree of a well by a single running trip. In some embodiments, the cable hanger provides a dual barrier system against well pressure, and includes electrical and hydraulic lines running therethrough, removing the need for subsea electric or hydraulic connections between a separate internal tree cap and cable hanger.

Referring to the drawings, FIG. 1 depicts a well completion 100 featuring a cable hanger 116 with an integrated internal tree cap as a part of an ESP suspension system, in accordance with one or more embodiments. The cable hanger 116 is landed and installed inside a bore 118 of a production tree 104 and an ESP 108 is suspended therefrom via a suspension cable. The well completion 100 further includes a wellhead 110 configured to suspend a casing 112, production tubing 120 and an external tree cap 114 to provide additional environmental barrier. The production tree 104 may be a subsea production tree or a land based production tree. In one or more other embodiments, the tree 104 may be an injection tree. In one or more other embodiments, other types of downhole tools can be suspended from the cable hanger.

FIG. 2 depicts a detailed view of an embodiment of an ESP suspension system 200, including the cable hanger 116. At a downhole end, the cable hanger 116 is coupled to an upper cable termination 206 which is coupled to the suspension cable 106 leading to the ESP 108 (FIG. 1). At an uphole end, the cable hanger 116 is coupled to the external tree cap 114 and an ROV cap 204. Electrical power and hydraulics are delivered to the ESP 106 through the cable hanger 116, the upper cable termination 206, and the suspension cable 106.

FIG. 3 depicts a perspective view of the cable hanger 116, in accordance with one or more embodiments. The cable hanger 116 includes a body with a first barrier system 302 and a second barrier system 304 located thereon, providing a dual barrier system. The first barrier system 302a includes a first seal 304a configured to seal against the bore 118 of the production tree 104 to establish a pressure barrier. The first barrier system 302a also includes a first latching mechanism 306a, such as latching dogs, wherein upon actuation, is configured to engage the production tree 104 and hold the cable hanger 116 in place in the production tree 104 Similarly, the second barrier system 302b includes a second seal 304b configured to seal against the bore 118 of the production tree 104 to establish a pressure barrier. The second barrier system 302b also includes a second latching mechanism 306b, such as latching dogs, wherein upon actuation, is configured to engage the production tree 104 and hold the cable hanger 116 in place in the production tree 104. The latching mechanisms 306 help resist the upward well pressuring pushing up on the cable hanger 116.

The cable hanger 116 further includes one or more hydraulic couplers 310 oriented at an angle to the longitudinal axis of the cable hanger 116 and configured to provide access to hydraulic lines within the cable hanger 116. In one or more embodiments, the cable hanger 116 also includes an alignment feature 312 configured to position the cable hanger 116 within the production tree 104 in a particular orientation, such that certain features of the cable hanger 116 are aligned with certain features of the production tree 104. As illustrated in FIG. 3, the alignment feature 312 may be a helix shape formed on the outside of the cable hanger 116 which engages and follows a corresponding guide feature in the production tree 104 to rotate the cable hanger 116 into the desired orientation within the production tree 104.

FIGS. 4A-4C depict cross-sectional views of the cable hanger 116 in various states, in accordance with one or more embodiments. FIG. 4A depicts the cable hanger 116 in an unlatched position, in which the first latch 306a and the second latch 306b are both in the unactuated position. In the unactuated position, the latches 306 are recessed towards the tool and disengaged from the production tree.

FIG. 4B depicts the cable hanger 116 with the first latch 306a actuated and in the engaged position, in which the first latch 306a is urged outwards towards the production tree 104. The latches 306 may have grooves and ribs which latch onto a complementary shape on the production tree 104, thereby axially locking the cable hanger 116 in place with the production tree. In the one or more embodiments, the first latch 306a is engaged by pushing a first actuation sleeve 402 from a disengaged position to an engaged position, in which a portion of the first actuation sleeve 402 slides underneath the first latch 306a and pushes the latch 306a outward and into engagement with the production tree 104. In one or more embodiments, pushing of the actuation sleeve 402 is done by a force applied by the running tool, such as via a hydraulic piston. When the first latch 306a is actuated, the first barrier system 302a is set and can be pressure tested.

FIG. 4C depicts the cable hanger 116 in which both the first and second latches 306 are actuated and in the engaged position. The second latch 306b may also have grooves and ribs which engage with a complementary shape on the production tree, further axially locking the cable hanger 116 onto the production tree. In one or more embodiments, the second latch 306b is engaged by pushing a second actuation sleeve 404 from a disengaged position to an engaged position, in which the second actuation sleeve 404 slides under the second latch 306b and pushes the latch 306b outward into engagement with the production tree 104. Pushing of the second actuation sleeve 404 can be done by a force applied by the running tool, such as via a hydraulic piston. When the second latch 306b is actuated, the second barrier system 302b is set and can be pressure tested.

In one or more embodiments, either of the actuation sleeves 402, 404 may form a part of the housing of the cable hanger 116. In one or more embodiments, the latches 306 can be actuated individually by varying the amount of force needed to actuate each of the latches 306. For example, the first actuation sleeve 402 may require less force than the second actuation sleeve 404 to slide into the engaged position. Thus, a first force may be applied, setting the first latch 306a but not the second latch 306b, and a second larger force can be applied subsequently, setting the second latch 306b.

Engagement of the latches 306 with the production tree 104 keeps the cable hanger 116 in place within the production tree 104, resisting well pressure or any other forces pushing upward on the cable hanger 116. The seals 304 provide pressure barriers against well pressure. Once the first latch 306a is engaged, the first barrier system 302a is set and can be tested without detaching the cable hanger 116 from the running tool. When the second latch 306b is engaged, the second barrier system 302b is set and can be tested as well.

Since the first barrier system 302a and the second barrier system 302b are both located on the same body, they are landed with the cable hanger 116 in a single running trip. The first and second latching mechanisms 306 can also be actuated, and the first and second barrier systems 302 set, during said single running trip without detaching the cable hanger 116 from the running tool, thereby providing a dual barrier system in less rig time compared to conventional system which requires at least two running trips. Additionally, the first barrier system 302a and the second barrier system 302b can be individually tested during said single running trip as well.

The cable hanger 116 further includes at least one electrical conductor 406 extending at least partially therethrough. The electrical conductor 406 may terminate at electrical connectors 408 configured to couple the conductor 406 to other equipment on either side of the cable hanger 116. In one or more embodiments, the electrical connectors 408 may be wet-mate connectors or dry-mate connectors. The electrical conductor 406 may be used to provide power and communication to the ESP through the cable hanger 116.

The cable hanger 116 further includes a hydraulic line 410 extending through at least a portion of the cable hanger 116, including an uphole portion 410a and a downhole portion 410b. The hydraulic line 410 may be used to provide hydraulic fluids to the ESP through the cable hanger 116. In one or more embodiments, the hydraulic line 410 may terminate at a wet-mate connector. The electrical conductor 406 and the hydraulic line 410 can be tested prior to detaching from the running tool. Because the cable hanger 116 includes a dual barrier system 302 provided on a single tool that can be landed in a single running trip, this eliminates the need for an additional electrical and/or hydraulic connection that would otherwise be needed to couple the two separate tools that would conventionally be needed to establish dual barriers.

The hydraulic line 410 is in fluid communication with a hydraulic coupler 310, which is located on the side of the cable hanger 116 such that the hydraulic coupler 310 can be accessed without accessing the ends of the cable hanger. The hydraulic coupler 310 provides an access point to the hydraulic line 410 for supplying hydraulic fluid or administering hydraulic control. The uphole portion 410a of the hydraulic line 410 is in fluid communication with an uphole side of the hydraulic coupler 310 and the downhole portion 410b of the hydraulic line 410 is in fluid communication with a downhole side of the hydraulic coupler 310.

FIGS. 5A and 5B depict cross-section views of the hydraulic coupler 310, in accordance with one or more embodiments. Specifically, FIG. 5A illustrates the hydraulic coupler 310 in a closed position and FIG. 5B illustrates the hydraulic coupler 310 in an open position. The hydraulic coupler 310 connects the uphole portion 410a of the hydraulic line 410 with the downhole portion 410b of the hydraulic line 410. Specifically, the hydraulic coupler 310 includes an uphole port 512 and a downhole port 514. The uphole port 512 is in fluid communication with the uphole portion 410a of the hydraulic line 410 and the downhole port 514 is in fluid communication with the downhole portion 410b of the hydraulic line 410. In the closed position, the hydraulic coupler 310 only couples the uphole 410a and downhole portions 410b in fluid communication, and does not permit external access to the hydraulic line 410. In the open position, the hydraulic coupler 310 provides external access from outside the cable hanger 116 to the hydraulic line 410.

The hydraulic coupler 310 includes a body 502 with a chamber 504 in which a sleeve 506 is located. The sleeve 506 engages a spring 508 which abuts an end 510 of the chamber 504. The sleeve 506 is slidable within the chamber 504 via compression of the spring 508. In the closed position, as illustrated in FIG. 5A, the sleeve 506 is held by the spring 508 in a position in which the sleeve 506 blocks external access to the chamber 504, thereby blocking external access to the hydraulic line 410 of the cable hanger 116 while permitting fluid communication between the uphole portion 410a and the downhole portion 410b. Specifically, fluid can flow from the uphole portion 410a of the hydraulic line into the uphole port 512, through the chamber 510, and into the downhole portion 410b of the hydraulic line 410 via the downhole port 514, as indicated by arrow 516 FIG. 5A.

The hydraulic coupler 310 can be operated via a hydraulic connector bonnet 600 on the production tree 104, as shown in FIG. 6A and 6B. Because of the alignment feature 312 (FIG. 3), the hydraulic coupler 310 is aligned with the hydraulic connector bonnet 600 when landed into the production tree 104. The hydraulic connector bonnet 600 may be bolted or otherwise secured to the production tree 104. The hydraulic connector bonnet 600 provides an interface for opening and closing the hydraulic coupler 310 and accessing the hydraulic line 410 of the cable hanger 116 from outside of the production tree. Specifically, the hydraulic connector bonnet 600 provides a hydraulic channel 602 that can be coupled to a hydraulic source or control panel (not shown), which may be located on an ROV, at the surface, or elsewhere.

The hydraulic connector bonnet 600 includes an actuation stem 604 coupled to a plug nose 606 configured to push in the sleeve 506 of the hydraulic coupler 310 when actuated to establish fluid communication with the coupler 310. FIG. 6A illustrates the hydraulic coupler 310 in a closed position, in which the plug nose 606 is disengaged from the hydraulic coupler 310.

FIG. 5B illustrates a detailed view of the hydraulic coupler 310 in the open position. FIG. 6B illustrates the hydraulic coupler 310 in the open position as actuated by the hydraulic bonnet 600. In the open position, the hydraulic bonnet 600 is engaged with the hydraulic coupler 310, in which the sleeve 506 is pushed further into the chamber 504 by the plug nose 606 when actuated by the actuated stem 604, thereby compressing the spring 508. The shuttle piston 610 of the hydraulic bonnet 600 is consequently pushed back. The plug nose 606 isolates port 512 and at the same time opens a shuttle pin valve of the nose plug 606, allowing flow of hydraulic fluid and communication with control line 410b as shown by arrows 608 in FIG. 6b and arrows 518 of FIG. 5b. The actuation stem 604 may be actuated in various ways, such as being turned by a remote operated vehicle (ROV). Thus, access to the hydraulic line of the cable hanger 116 can be provided via the production tree 104.

FIG. 7 illustrates a pressure compensation section of the cable hanger 116. Specifically, the cable hanger 116 includes a pressure compensation diaphragm 702 located in an approximate middle region of the cable hanger 116. The pressure compensation diaphragm 702 is configured to compensate the internal pressure inside the cable hanger 116 between two pressure barriers 302a, 302b through fluid ports 704.

A method of deploying a tool (FIG. 1) downhole using the cable hanger 116 includes lowering the tool downhole, in which the tool is suspended from the cable hanger 116, and landing the cable hanger 116 within a production tree 104. In one or more embodiments, then landing the cable hanger 116, a hydraulic coupler 310 of the cable hanger is aligned with a hydraulic connector bonnet 600 of the production tree 104. The cable hanger 116 includes the first actuatable barrier system 302a and the second actuatable barrier system 302b configured to establish dual pressure barriers and hold the cable hanger within the production tree 104. The method further includes actuating the first barrier system 302a and actuating the second barrier system. Lowering of the tool, landing of the cable hanger 116, actuating of the first and second barrier systems 302 are performed during a single running trip. In one or more embodiments, the method further includes testing the first barrier system 302a during the said running trip and before actuation of the second barrier system 302b. The method may further include delivering power, communications, hydraulics, or any combination thereof, to the tool through the cable hanger 116. The method may also include accessing a hydraulic line 410 of the cable hanger 116 via the hydraulic connector bonnet 600. The tool may be an ESP or other downhole tool.

This discussion is directed to various embodiments of the invention. The drawing figures are not necessarily to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function, unless specifically stated. In the discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. In addition, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. The use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components.

Reference throughout this specification to “one embodiment,” “an embodiment,” or similar language means that a particular feature, structure, or characteristic described in connection with the embodiment may be included in at least one embodiment of the present disclosure. Thus, appearances of the phrases “in one embodiment,” “in an embodiment,” and similar language throughout this specification may, but do not necessarily, all refer to the same embodiment.

Although the present invention has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims.

Claims

1. A cable hanger for use in a tree of a well including a bore, comprising:

a body;

a first barrier system located on the body, comprising a first seal configured to seal against the bore of the tree to establish a pressure barrier; and a first latching mechanism, configured such that upon actuation, it engages the tree and holds the cable hanger in place in the tree;

a second barrier system located on the body, comprising: a second seal configured to seal against the bore of the tree; and a second latching mechanism, configured such that upon actuation, it engages the tree and holds the cable hanger in place in the tree; and

at least one of a hydraulic line or an electrical conductor extending through a portion of the body.

2. The cable hanger of claim 1, wherein the first and second latching mechanisms are actuatable during a single running trip, and wherein the first barrier system is testable during the running trip.

3. The cable hanger of claim 1, further comprising a hydraulic coupler located on the body, the hydraulic coupler configured to provide external access to the hydraulic line.

4. The cable hanger of claim 1, wherein the hydraulic coupler is moveable between a closed position and an open position in which external access to the hydraulic line is established.

5. The cable hanger of claim 1, further comprising an alignment feature configured such that the cable hanger is alignable relative to the tree as the cable hanger is landed.

6. The cable hanger of claim 5, further comprising a hydraulic coupler configured to provide external access to the hydraulic line, and wherein the hydraulic coupler is aligned with a hydraulic connector bonnet when oriented relative to the tree.

7. The cable hanger of claim 1, further comprising a wet-mate connector coupled to the electrical conductor, hydraulic line, or both.

8. A well completion, comprising:

a tree; and

a cable hanger located within the production tree, the cable hanger comprising: a body; a first barrier system located on the body, comprising a first seal configured to seal against the tree to establish a first pressure barrier; and a first latching mechanism, configured such that upon actuation, it engages the tree and holds the cable hanger in place in the tree; a second barrier system located on the body, comprising: a second seal configured to seal against the tree to establish a second pressure barrier; and a second latching mechanism, configured such that upon actuation, it engages the tree and holds the cable hanger in place in the tree; and at least one of a hydraulic line or an electrical conductor extending through a portion of the body.

9. The cable hanger of claim 8, wherein the first and second latching mechanisms are actuatable during a single running trip, and wherein the first barrier system is testable during the running trip.

10. The well completion of claim 8, wherein the cable hanger comprises a hydraulic coupler aligned with a hydraulic connector bonnet of the tree, and wherein the hydraulic coupler is coupled to the hydraulic line of the cable hanger.

11. The well completion of claim 10, wherein the hydraulic connector bonnet couples the hydraulic line of the cable hanger with a hydraulic source.

12. The well completion of claim 8, further comprising a downhole tool suspended from the cable hanger.

13. The well completion of claim 12, wherein the downhole tool is an ESP and the tree is a subsea production tree.

14. The well completion of claim 8, wherein at least one of the tree and the cable hanger comprises an alignment feature configured to position the cable hanger with respect to the tree during landing of the cable hanger.

15. A method of deploying a tool downhole in a well, comprising:

lowering the tool downhole, wherein the tool is suspended from a cable hanger;

landing the cable hanger within a tree, wherein the cable hanger comprises a first actuatable barrier system and a second actuatable barrier system configured to establish dual pressure barriers and hold the cable hanger within the tree;

actuating the first barrier system;

actuating the second barrier system; and

wherein lowering the tool, landing the cable hanger, actuating the first barrier system, and actuating the second barrier system are performed during a single running trip.

16. The method of claim 15, further comprising testing the first barrier system during the single running trip and before actuation of the second barrier system.

17. The method of claim 15, further comprising delivering power, communications, hydraulics, or any combination thereof, to the tool through the cable hanger.

18. The method of claim 15, further comprising aligning a hydraulic coupler of the cable hanger with a hydraulic connector bonnet of the tree.

19. The method of claim 18, further comprising accessing the hydraulic line of the cable hanger via the hydraulic connector bonnet.

20. The method of claim 15, wherein the tool comprises an electrical submersible pump (ESP) and the tree is a subsea production tree