ELECTRICAL WET-MATE CONNECTIONS

Abstract

Electrical cables are attached to an outer surface of production tubing. The electrical cables are configured to be connected at a first end to a topside electrical power supply. Electrical contacts are attached to a second end of the electrical cables. The contacts are at a downhole end of the production tubing.

Claims

1. A wellbore stinger comprising: production tubing; electrical cables attached to an outer surface of the production tubing, the electrical cables configured to be connected at a first end to a topside electrical power supply; and electrical contacts attached to a second end of the electrical cables, the contacts being at a downhole end of the production tubing.

2. The wellbore stinger of claim 1, wherein the electrical cables are sized to deliver sufficient electrical power to drive an electric submersible pump at full load.

3. The wellbore stinger of claim 1, wherein a downhole end of the production tubing is configured to be received by a polished bore receptacle installed within a wellbore.

4. The wellbore stinger of claim 3, wherein the downhole end of the production tubing comprises a clocking feature configured to align the electrical contacts with corresponding contacts within the polished bore receptacle.

5. A method comprising: receiving an electric submersible pump by a wellbore, the electric submersible pump being secured within the wellbore by a packer; receiving a polished bore receptacle by the electric submersible pump, the polished bore receptacle comprising electrical contacts within an inner surface of the polished bore receptacle; and receiving a stinger by the polished bore receptacle, the stinger comprising: production tubing; electrical cables attached to an outer surface of the production tubing, the electrical cables configured to be connected at a first end to a topside electrical power supply; and electrical contacts attached to a second end of the electrical cables, the contacts being at a downhole end of the production tubing.

6. The method of claim 5, further comprising: exchanging electrical power by the electric submersible pump by the electrical cables and contacts; and producing fluid by the electric submersible pump.

7. The method of claim 5, further comprising: releasing, by the polished bore receptacle, the stinger.

8. The method of claim 7, further comprising releasing, by the wellbore, the stinger, the polished bore receptacle, and the electric submersible pump remaining secured within the wellbore.

9. The method of claim 8, wherein the stinger is a first stinger, the method further comprising: receiving a second stinger by the polished bore receptacle after releasing the first stinger by the wellbore.

10. The method of claim 8, further comprising servicing the stinger after the stinger is released from the wellbore.

11. The method of claim 10, further comprising: receiving the stinger by the polished bore receptacle after releasing the stinger by the polished bore receptacle.

12. A wellbore system comprising: a stinger comprising: production tubing; electrical cables attached to an outer surface of the production tubing, the electrical cables configured to be connected at a first end to a topside electrical power supply; and electrical contacts attached to a second end of the electrical cables, the contacts being at a downhole end of the production tubing; a polished bore receptacle configured to receive and retain a downhole end of the stinger; and an electric submersible pump downhole of the polished bore receptacle.

13. The wellbore system of claim 12, wherein the electrical cables are sized to deliver sufficient electrical power to drive an electric submersible pump at full load.

14. The wellbore system of claim 12, wherein the polished bore receptacle is uphole of a packer assembly, the packer assembly securing the electric submersible pump within the wellbore.

15. The wellbore system of claim 12, wherein the polished bore receptacle is downhole of a tubing hanger supporting the stinger.

16. The wellbore system of claim 12, wherein the downhole end of the production tubing comprises a clocking feature configured to align with a corresponding feature of the polished bore receptacle, the clocking features configured to align the electrical contacts of the stinger with corresponding electrical contacts of the polished bore receptacle.

17. The wellbore system of claim 12, wherein the electrical cables are a first set of electrical cables, further comprising a second set of electrical cables extending between the electrical contacts within the polished bore receptacle and the electric submersible pump.

18. The wellbore system of claim 12, wherein casing within the wellbore is seven inch casing or greater.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0024] FIG. 1 is a schematic diagram of an example well system.

[0025] FIGS. 2A-2B are schematic diagrams of a bottomhole assembly and wet-mate connector used with the example well system.

[0026] FIG. 3 is a flowchart of an example method that can be used with aspects of this disclosure.

[0027] Like reference numbers and designations in the various drawings indicate like elements.

DETAILED DESCRIPTION

[0028] Electric submersible pumps are typically connected to power cables by penetrators. Penetrator failure can occur during tubing hanger installation. Such a failure requires the un-setting of packers to fix or replace the penetrator. This results in pulling essentially all components (tubing, hangers, electric submersible pump, packers, etc.) from the wellbore and reinstalling them. Such an operation is extensive and results in delays and extended non-production time.

[0029] This disclosure relates to a downhole arrangement that decouples the electrical penetrations of the electrical submersible pump from the installation of tubing and hangers. The electric submersible pump is installed and secured within the wellbore with a packer. A polished bore receptacle, with electrical contacts, attached to, and uphole of, the electric submersible pump. The production tubing is arranged as a stinger with electrical cables attached to the outside of the production tubing and electrical contacts at a downhole end of the tubing corresponding with the electrical contacts of the polished bore receptacle. In such an arrangement, changing out the production tubing has little to no impact on the electric submersible pump penetrations.

[0030] FIG. 1 is a schematic diagram of an example well system 100. The well system 100 includes a wellbore 102 formed in a geologic formation 104. Extending into the wellbore 102 is a production string 106, also referred to as production tubing. The production string 106 directs fluids from the geologic formation to a topside facility 108. The topside facility 108 includes pumps, compressors, separators, and any other facilities necessary to condition fluids produced from the geologic formation 104. At a downhole end of the production string 106 is an electric submersible pump 110. The electric submersible pump 110 assists in flowing the produced fluid up the production string 106 towards the topside facility 108. The electric submersible pump 110 is downhole of a polished bore receptacle 112 and is secured within the wellbore 102 by a packer 114. The polished bore receptacle 112 allows for the production string 106 to be installed and removed without removing the electric submersible pump 110. In some implementations, the polished bore receptacle 112 is downhole of a tubing hanger 116 supporting the production tubing 106. While illustrated as a vertical wellbore for simplicity, the wellbore 102 can be a deviated or horizontal wellbore without departing from this disclosure. In some implementations, the concepts described herein are applicable with well casing diameters of seven inches or greater; however, other casing diameters can be used without departing from this disclosure.

[0031] FIGS. 2A-2B are schematic diagrams of a bottomhole assembly 200 and wet-mate connector 202 used with the example well system 100. The bottomhole assembly 200 includes the packer 114, the electric submersible pump 110, and the downhole end of the production string 106, colloquially referred to as a stinger 204. The stinger 204 (production tubing 106) includes electrical cables 206a attached to an outer surface of the production tubing 106. The electrical cables 206a can be attached to the production tubing in a variety of ways, for example, by clamps 207. The electrical cables 206a are configured to be connected at a first, uphole end to an electrical power supply at the topside facility 108 (FIG. 1). The electrical cables 206a are sized to deliver sufficient electrical power to drive the electric submersible pump 110 at full load. At a downhole end of the production tubing 106 are electrical contacts 210a electrically coupled and attached to a second, downhole end of the electrical cables 206a. In some implementations, the electrical contacts 210a include a pin or brush style contact configured to contact a corresponding groove, protrusion, or other longitudinally oriented contact. In some implementations, the electrical contacts 210a include brush contacts. In some implementations, the electrical contacts include annular contacts. In such an implementation, clocking the stinger may not be necessary. Regardless of the type of contacts used, the electrical contacts 210a and 210b are ruggedized to withstand a wellbore environment.

[0032] The polished bore receptacle 112 is configured to receive and retain a downhole end of the stinger 204. Similarly, the downhole end of the production tubing 106 is configured to be received by a polished bore receptacle 112 installed within the wellbore 102. That is, the polished bore receptacle 112 and the stinger 204 define profiles configured to mate with one another. In some implementations, the downhole end of the production tubing 106 includes a clocking feature 208 configured to align with a corresponding feature of the polished bore receptacle 112. In such implementations, the clocking is used to align the electrical contacts 210a with corresponding contacts 210b within the polished bore receptacle 112. Such a clocking feature can include a slot and groove.

[0033] A second set of electrical cables 206b extends between the electrical contacts within the polished bore receptacle 112 and the electric submersible pump 110. The second set of electrical cables are sized to deliver sufficient electrical power to drive the electric submersible pump 110 at full load.

[0034] FIG. 3 is a flowchart of an example method 300 that can be used with aspects of this disclosure. At 302, the electric submersible pump 110 is received by the wellbore 102. The electric submersible pump 110 is secured within the wellbore 102 by a packer 114. At 304, the polished bore receptacle 112 is received by the electric submersible pump. The polished bore receptacle includes electrical contacts within an inner surface of the polished bore receptacle 112. In some implementations, the polished bore receptacle 112 is received by the electric submersible pump 110 prior to the electric submersible pump 110 being received by the wellbore 102. At 306, a stinger 204 is received by the polished bore receptacle 112. The stinger includes production tubing configured to direct production fluids from the electric submersible pump 110 towards the topside facility 108. Electrical cables 206a are attached to an outer surface of the production tubing 106 and are configured to be connected at a first end to an electrical power supply, for example, at the topside facility 108. At the downhole end of the stinger 204, electrical contacts 210a are attached to the second end of the electrical cables 206a.

[0035] During operation, electrical power is exchanged between the electric submersible pump and the electrical cables and contacts. Fluid, such as hydrocarbons, are produced by the electric submersible pump in response to the electrical power exchange.

[0036] At some point during the life of the wellbore, the stinger is released by the polished bore receptacle. The stinger is then released by the wellbore. That is, the stinger 204 is removed from the wellbore 102 and the polished bore receptacle 112. As such, the polished bore receptacle 112 and the electric submersible pump 110 remain secured within the wellbore 102. Such an operation can occur due to routine maintenance, or to repair something within the well.

[0037] In some instances, the stinger 204 is serviced after the stinger 204 is released or removed from the wellbore 102. The stinger 204 is then reinstalled after servicing. That is, the stinger 204 is received by the polished bore receptacle 112 after releasing the stinger 204 by the polished bore receptacle 112. In some instances, the stinger 204 cannot be serviced, salvaged, or otherwise reused. In such instances, a second stinger is installed in lieu of the first, original stinger 204. That is, the second stinger 204 is received by the polished bore receptacle after the first stinger 204 is removed or released from the wellbore 102. In some implementations, the first stinger 204 and the second stinger are substantially identical.

[0038] While this disclosure contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features specific to particular implementations. Certain features that are described in this disclosure in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or a variation of a subcombination.

[0039] Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. Moreover, the separation of various system components in the implementations described above should not be understood as requiring such separation in all implementations, and it should be understood that the described components and systems can generally be integrated together in a single product or packaged into multiple products.

[0040] Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims. In some cases, the actions recited in the claims can be performed in a different order and still achieve desirable results. In addition, the processes depicted in the accompanying figures do not necessarily require the particular order shown, or sequential order, to achieve desirable results