WO2016200847A1

WO2016200847A1 - Dual artificial lift system

Info

Publication number: WO2016200847A1
Application number: PCT/US2016/036278
Authority: WO
Inventors: Diego A. Narvaez
Original assignee: Schlumberger Technology Corporation; Schlumberger Canada Limited; Services Petroliers Schlumberger; Schlumberger Technology B.V.
Priority date: 2015-06-09
Filing date: 2016-06-08
Publication date: 2016-12-15

Abstract

A technique facilitates production of fluids from a subterranean reservoir. A dual artificial lift system is disposed in a wellbore and comprises production tubing disposed along the wellbore. The dual artificial lift system also comprises a first artificial lift system located in the wellbore externally of the production tubing. Additionally, internal tubing, e.g. coiled tubing, is disposed along an interior of the production tubing. A second artificial lift system is attached to the internal tubing at a location downhole of the first artificial lift system. The second artificial lift system may be operated to produce well fluids up to the first artificial lift system for further production to the surface.

Description

PATENT APPLICATION

DUAL ARTIFICIAL LIFT SYSTEM

CROSS-REFERENCE TO RELATED APPLICATION

[0001] The present document is based on and claims priority to U.S. Provisional

Application Serial No.: 62/173,239, filed June 9, 2015, which is incorporated herein by reference in its entirety.

BACKGROUND

[0002] Oil and gas wells utilize a borehole drilled into the earth and subsequently completed with equipment to facilitate production of the desired fluids from a reservoir. In certain unconventional wells, the wellbore comprises three sections in the form of a vertical section which extends from the surface to a kick off point and then a curved section which leads to a horizontal section. The horizontal section may be located across a pay zone of the reservoir.

[0003] Sometimes, the vertical section is drilled and completed with a relatively larger diameter casing. The curved and horizontal sections may then be completed with a relatively smaller diameter liner. The smaller diameter liner provides a reduction in cross-sectional area that tends to limit the depth at which an artificial lift system, e.g. an electric submersible pumping system, can be set in the borehole. Additionally, the curved section may be constructed with a short radius to optimize cost and area of contact with the pay zone. Due to these restrictions, the electric submersible pumping system often is set in the vertical section above the kick off point which limits the drawdown. SUMMARY

[0004] In general, a system and methodology facilitate production of fluids from a subterranean reservoir. A dual artificial lift system is disposed in a wellbore to enhance the capability for producing fluids from a variety of reservoir locations. The dual artificial lift system comprises production tubing disposed in a wellbore and a first artificial lift system, e.g. an electric submersible pumping system, located in the wellbore externally of the production tubing. Additionally, internal tubing, e.g. coiled tubing, is disposed along an interior of the production tubing. A second artificial lift system, e.g. a gas lift system, is attached to the internal tubing at a location downhole of the first artificial lift system. During operation, the dual lift systems are utilized together to improve lifting and production of well fluid.

[0005] However, many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0006] Certain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:

[0007] Figure 1 is a schematic illustration of an example of a dual artificial lift system, according to an embodiment of the disclosure; [0008] Figure 2 is a schematic illustration of another example of a dual artificial lift system, according to an embodiment of the disclosure; and

[0009] Figure 3 is a flow diagram illustrating an example of a methodology for utilizing a dual artificial lift system to facilitate production of well fluid, according to an embodiment of the disclosure.

DETAILED DESCRIPTION

[0010] In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

[0011] The present disclosure generally relates to a system and methodology which facilitate production of fluids from a subterranean reservoir. The system and methodology may be used in a variety of wells, including unconventional wells which have a wellbore with a vertical section, a curved section, and a horizontal section extending across a pay zone of the subterranean reservoir. In some applications, a first artificial lift system, e.g. an electric submersible pumping system, is disposed in the vertical section of the wellbore and a second artificial lift system, e.g. a gas lift valve, is disposed in the horizontal section of the wellbore. In this type of application, the electric submersible pumping system may be located above the kick off point where the vertical section is connected with the curved section of the wellbore. The artificial lift systems may be used in cooperation to facilitate production of well fluid from the horizontal section, to the vertical section, and up to a surface collection location.

[0012] According to an embodiment, a dual artificial lift system comprises production tubing disposed in the wellbore. In this example, an electric submersible pumping system is located in the wellbore externally of the production tubing and above the kick off point. Coiled tubing or other suitable internal tubing is disposed along an interior of the production tubing and is coupled with a gas lift valve located in the horizontal section. Thus, the gas lift valve is attached to the coiled tubing at a location downhole of the electric submersible pumping system. During production, the gas lift valve is operated by delivering lift gas through the gas lift valve. The gas lift valve, in turn, operates to produce well fluids up to the electric submersible pumping system for further production to the surface.

[0013] In some embodiments, the dual artificial lift system utilizes an electric submersible pumping system deployed from a Y-tool and positioned above the kick off point externally of the production tubing. The dual artificial lift system also comprises a gas lift system deployed down to the horizontal section of the wellbore, e.g. to a distal end of the coiled tubing. By way of example, the coiled tubing may be routed down through the production tubing, through the Y-tool, and into the horizontal section. Lift gas may then be injected through the coiled tubing to power the gas lift system. The gas lift system effectively acts as a booster system which lifts well fluid from the horizontal section of the wellbore to at least the kick off point. From this region, the electric submersible pumping system is operated to pump the well fluid and to lift it to a desired surface location.

[0014] The lift gas used to produce the well fluid up to the electric submersible pumping system flows upwardly with the well fluid along a lower annulus between the coiled tubing and the production tubing until released to the electric submersible pumping system. At least some of the lift gas may then be allowed to flow upwardly along a flow path between the production tubing and a surrounding casing while the electric submersible pumping system pumps the remaining well fluid mixture. By way of example, the well fluid may be pumped upwardly along an upper annulus between the coiled tubing and the production tubing. In this example, a packer may be used to isolate this upper annulus from the lower annulus. However a variety of flow paths may be utilized for the fluids, e.g. for the well fluid and lift gas. [0015] The dual artificial lift system may be used to effectively increase drawdown. For example, the system enables increasing the drawdown so the drawdown is close to the total vertical depth of the well. In some applications, this may amount to approximately 650 feet or more of additional total vertical depth drawdown below the kick off point. This available, additional drawdown is helpful in optimizing production from a variety of wells, particularly production during the latter part of the life of a well.

[0016] Referring generally to Figure 1, an embodiment of a system 20 for use in a well 22, e.g. an unconventional well, is illustrated. In this embodiment, well 22 is an unconventional well and includes a wellbore 24 having a vertical section 26, a curved section 28, and a horizontal section 30. A kick off point 32 marks the transition from the vertical section 26 to the curved section 28.

[0017] In the embodiment illustrated, the vertical section 26 of wellbore 24 may be lined with a casing 34, e.g. a production casing. Additionally, a liner 36 may be suspended from a lower end of casing 34 and may extend through the curved section 28 and into the horizontal section 30 of wellbore 24. In some applications, more than one liner 36 may be used to span the curved section 28 and the horizontal section 30.

Additionally, the liner 36 may be perforated along, for example, horizontal section 30, to facilitate entry of well fluids from the pay zone of a surrounding formation 38.

[0018] With additional reference to Figure 1, the well system 20 also may comprise a production tubing 40 disposed within casing 34 and within liner 36. In other words, the production tubing 40 may extend down along wellbore 24 through vertical section 26, curved section 28, and into horizontal section 30. A packer 42, e.g. a casing packer, may be positioned between production tubing 40 and well casing 34. The packer 42 may be set against the interior surface of casing 34 to provide a seal between production tubing 40 and casing 34 and to support production tubing 40 inside casing 34. Depending on the application, packer 42 may be set in casing 34 above the top of liner 36 or packer 42 may be set at the top end of liner 36. Additionally, some embodiments may terminate the production tubing 40 at packer 42. [0019] In the example illustrated, a first artificial lift system 44, e.g. an electric submersible pumping system 46, is disposed in the vertical section 26 of wellbore 24 externally of production tubing 40. For example, the electric submersible pumping system 46 may be positioned in vertical section 26 above packer 42 and laterally offset from production tubing 40 as illustrated. In the specific example illustrated, the electric submersible pumping system 46 is coupled with a Y-tool 48. Additionally, the interior of production tubing 40 is in fluid communication with the Y-tool 48. Depending on the application, the Y-tool 48 may have a variety of configurations but one example is the Y- tool Sub Assembly available from Schlumberger Technology Corporation of Houston Texas. The electric submersible pumping system 46 may have a variety of configurations and components including, for example, a submersible motor, a submersible pump powered by the submersible motor, a motor protector, and a pump intake.

[0020] As illustrated, the production tubing 40 may comprise a perforated section

50, e.g. a perforated tubing joint, which may be used to direct fluid to electric

submersible pumping system 46. For example, the perforated section 50 may be used to direct well fluid produced from a second artificial lift system 52, e.g. a gas lift system 54 having a gas lift valve 56, as described in greater detail below. The perforated section 50 may be positioned at a suitable location, such as a location above, below, or at the same height as electric submersible pumping system 46. It should be noted the casing packer 42 may be used to isolate portions of the wellbore 24 above and below the packer 42 and externally of production tubing 40 to accommodate different pressures caused by, for example, gas lift system 54.

[0021] An internal tubing 58, e.g. coiled tubing, extends along an interior of production tubing 40 down through vertical section 26, curved section 28, and into horizontal section 30 of wellbore 24. A packer 60 may be positioned between internal tubing 58 and the surrounding production tubing 40 and may be selectively actuated into sealing engagement with the inside surface of production tubing 40. The packer 60 may be used to secure the internal tubing 58 within production tubing 40 and to isolate portions of an annulus 62 above and below the packer 60. In the illustrated example, packer 60 is set above perforated section 50 within production tubing 40.

[0022] Gas lift system 54 may be coupled with the internal tubing/coiled tubing

58 at a position within horizontal section 30. However, the gas lift system 54 also may be positioned at locations within curved section 28 or vertical section 26 of wellbore 24. In the specific example illustrated, the gas lift system 54 is positioned at a downhole, distal end of coiled tubing 58 at a location within horizontal section 30.

[0023] During operation of the illustrated embodiment of system 20, a lift gas 64 is injected into well 22 down through coiled tubing 58 and through gas lift valve 56 of gas lift system 54. When the lift gas 64 passes through gas lift valve 56, it mixes with well fluid in the horizontal section 30 of wellbore 24. A mixture 66 of lift gas 64 and well fluid flows along a downhole portion 68 of annulus 62 which is between coiled tubing 58 and production tubing 40. The mixture 66 travels uphole until it reaches perforated section 50 and packer 60. The mixture 66 is then directed out through perforated section 50 into a production annulus 70 located between production tubing 40 and casing 34 above casing packer 42.

[0024] A portion 72 of the lift gas 64 may separate from the mixture 66 and continue traveling upwardly along the production annulus 70 to, for example, a surface location. The well fluid and remaining lift gas are prevented from flowing back downhole by casing packer 42 and are able to accumulate above casing packer 42 in proximity to electric submersible pumping system 46. The electric submersible pumping system 46 may be operated to pump this remaining fluid 74, e.g. well fluid or a mixture of well fluid and remaining lift gas, to a surface collection location or other desired location. For example, the fluid 74 may be pumped through Y-tool 48 and into a portion 76 of annulus 62 disposed above packer 60 and between coiled tubing 58 and production tubing 40. The fluid 74 flows upwardly along annulus portion 76 to the surface collection location or other desired location. [0025] Depending on the parameters of a given application and/or environment, well system 20 may be installed in well 22 according to various procedures. By way of example, the production tubing 40, casing packer 42, and Y-tool 48 may be run downhole into cased, vertical section 26 of wellbore 24. Once the production tubing 40 is properly positioned, packer 42 may be set to form a seal between the exterior of production tubing 40 and the interior of well casing 34. The electric submersible pumping system 46 may be positioned downhole, set in the vertical section 26, and attached to Y-tool 48.

[0026] Subsequently, the coiled tubing 58 and the gas lift system 54 may be inserted down through the production tubing 40 and fed into the horizontal section 30 of wellbore 24. The packer 60 may be moved downhole or deployed with coiled tubing 58 and then set once coiled tubing 58 is properly positioned within production tubing 40. In this example, the packer 60 is set between an exterior of coiled tubing 58 and an interior of production tubing 40 to isolate uphole portion 76 of annulus 62 from downhole portion 68 of annulus 62. The lift gas 64 may then be injected downhole through the interior of coiled tubing 58, and the electric submersible pumping system 46 may be operated in conjunction with gas lift system 54 to produce well fluid to a desired collection location, e.g. a surface collection location.

[0027] Referring generally to Figure 2, another embodiment of well system 20 is illustrated as deployed in well 22. Many of the components in the embodiment illustrated in Figure 2 are the same or similar as those components in the embodiment illustrated in Figure 1 and have been labeled with the same reference numerals. However, the first artificial lift system 44, e.g. electric submersible pumping system 46, does not produce fluid 74 through Y-tool 48. In this embodiment, the Y-tool 48 has been omitted and the well fluid mixture 74 is pumped to a surface collection location or to another desired location via a dedicated tubing 78. However, various other flow paths may be provided for directing fluid 74 from the electric submersible pumping system 46 to the desired collection location. In this embodiment, the first artificial lift system 44 is again positioned externally of production tubing 40 at a location laterally offset from

production tubing 40 within the vertical section 26 of wellbore 24. [0028] It should be noted that features and configurations of the embodiments illustrated and described herein may be changed or adjusted according to the parameters of a given application. For example, the curved section 28 of wellbore 24 may include a tangent section. Additionally, the total vertical depth down to kick off point 32 as well as the total vertical depth between kick off point 32 and horizontal section 30 may vary from one well to another. In a specific example, the kick off point 32 may be at a total vertical depth of about 10,000 feet and the total vertical depth distance between kick off point 32 and horizontal section 30 may be about 650 feet. These depths are simply given as an example, however, and various applications may utilize other kick off point locations as well as other depths, e.g. other depths for locating the first artificial lift system 44 and the second artificial lift system 52.

[0029] In some embodiments, the gas lift system 54 may be constructed to both lift the fluid mixture 66 to the packer 60 and to provide head for overcoming the back pressure of fluid above packer 60 in production annulus 70. In some applications, the dedicated tubing 78 may be in the form of coiled tubing. Additionally, the electric submersible pumping system 46 may be deployed by a variety of conventional techniques to the desired location within vertical section 26 while using coiled tubing 58 to deliver lift gas 64 through the horizontal section 30 to gas lift system 54.

[0030] In some embodiments, the perforated section 50 may comprise a sliding sleeve 80 which may be selectively actuated to open or close off the flow from inside tubing 40 to production annulus 70. By way of example, the sliding sleeve 80 may be actuated mechanically, electrically, electro-mechanically, or by other suitable actuating mechanisms. In some embodiments, the packer 60 may be replaced by a mechanical sealing mechanism or other suitable mechanism for providing the desired isolation along annulus 62.

[0031] Referring generally to Figure 3, an embodiment of a methodology used to provide dual artificial lift is illustrated in flowchart form. In this embodiment, a wellbore is initially provided with cased vertical section 26 and horizontal section 30, as represented by block 82. The vertical section may be coupled at kick off point 32 to curved section 28 which extends to horizontal section 30. In this embodiment, production tubing 40 is run downhole into the wellbore 24 with Y-tool 48 and casing packer 42, as represented by block 84. As described above, devices other than Y-tool 48 may be used to facilitate flow of well fluid uphole to a desired collection location. The casing packer 42 is then set between the production tubing 40 and the casing 34 of cased vertical section 26, as represented by block 86.

[0032] The electric submersible pumping system 46 also is deployed into the cased vertical section 26 of wellbore 24 and is located above casing packer 42 externally of the production tubing 40, as represented by block 88. The coiled tubing 58 or other internal tubing is then installed through the interior of the production tubing 40 until the coiled tubing 58 extends into horizontal section 30 of wellbore 24, as represented by block 90. Gas lift system 54 with gas lift valve 56 is located along the coiled tubing 58 and horizontal section 30, as indicated by block 92. In some embodiments, the gas lift system 54 may be coupled to a distal end of coiled tubing 58 and deployed downhole with the coiled tubing 58.

[0033] The inwardly positioned packer 60 is then set between the production tubing 40 and the coiled tubing 58 at a position above casing packer 42, as represented by block 94. At this stage, the gas lift valve 56 and the electric submersible pumping system 46 may be operated to produce well fluid, as represented by block 96. For example, lift gas 64 may be pumped down through coiled tubing 58 and through gas lift valve 56 to produce well fluid from formation 38 up to perforated section 50 and out into production annulus 70 surrounding electric submersible pumping system 46. Some of the lift gas 64 originally mixed with the well fluid may flow upwardly through production annulus 70, and the remaining well fluid mixture 74 is pumped by electric submersible pumping system 46 through Y-tool 48 and up annulus 62 to a desired surface collection location or other location. [0034] However, the methodology as well as the system configuration can be adjusted according to the parameters of a given application and/or environment. For example, the first artificial lift system 44 may comprise a variety of electric submersible pumping systems or other systems for lifting production fluids to the desired collection location. Similarly, the second artificial lift system 52 may comprise a variety of gas lift systems or other systems employed to lift well fluids above the kick off point and to the first artificial lift system. The Y-tool 48 may be replaced with direct tubing or with other types of components for directing well fluid to the appropriate upward flow path. Tubing 40 as well as internal tubing 58 may be constructed with a variety of tubing types and sizes, and packers 42, 60 may vary in size and configuration according to the type of overall well system 20 and according to the type of environment in which it is employed. Other components of well system 20 and the configuration of well system 20 also may be changed or adjusted to accommodate a given operation.

[0035] Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

Claims

CLAIMS claimed is:

A system for use in a well, comprising: a dual artificial lift system deployed downhole in a wellbore, the dual artificial lift system comprising:

a production tubing disposed in the wellbore;

a Y-tool in fluid communication with the production tubing;

an electric submersible pumping system in fluid communication with the Y-tool and disposed outside the production tubing at a position laterally offset of the production tubing;

a coiled tubing disposed inside the production tubing; and a gas lift valve in fluid communication with the coiled tubing to receive lift gas via the coiled tubing.

The system as recited in claim 1, further comprising a packer disposed between the production tubing and the coiled tubing.

The system as recited in claim 2, or in the Y-tool is in fluid communication with the production tubing above the packer to deliver a pumped well fluid into an annulus between the production tubing and the coiled tubing.

The system as recited in claim 1, wherein an end of the coiled tubing is located downhole from the electric submersible pumping system and is coupled with the gas lift valve.

The system as recited in claim 1, further comprising an additional packer disposed about an exterior of the production tubing.

6. The system as recited in claim 1, wherein the production tubing comprises a perforated section located below the packer. 7. The system as recited in claim 4, wherein the coiled tubing and the production tubing extend into a horizontal wellbore section of the wellbore. 8. The system as recited in claim 5, wherein the additional packer is disposed

between the production tubing and a surrounding well casing. 9. The system as recited in claim 8, wherein an annulus between the production tubing and the well casing provides a flow path to the surface for at least a portion of the lift gas. 10. A system, comprising: a dual artificial lift system disposed in a wellbore having a cased vertical section and a horizontal section, the dual artificial lift system comprising:

production tubing disposed in the wellbore;

a first artificial lift system disposed in the cased vertical section and external to the production tubing;

internal tubing disposed in an interior of the production tubing; and a second artificial lift system attached to, and in fluid

communication with, the internal tubing, wherein the internal tubing extends into the horizontal section. 11. The system as recited in claim 10, wherein the first artificial lift system comprises an electric submersible pumping system and the second artificial lift system comprises a gas lift system. 12. The system as recited in claim 11, wherein the dual artificial lift system further comprises a Y-tool in fluid communication with the electric submersible pumping system and the production tubing, and wherein the internal tubing comprises coiled tubing, the dual artificial lift system further comprising a packer disposed between the production tubing and the coiled tubing. 13. The system as recited in claim 12, wherein the Y-tool is in fluid communication with the production tubing above the packer. 14. The system as recited in claim 13, further comprising an additional packer disposed between the production tubing and the cased vertical section. 15. The system as recited in claim 14, wherein the production tubing additionally comprises a perforated section. 16. The system as recited in claim 15, wherein the perforated section is positioned below the packer that is disposed between the production tubing and the coiled tubing. 17. A method, comprising: providing a wellbore having a cased vertical section and a horizontal section;

running production tubing, a Y-tool attached to production tubing, and a casing packer into the wellbore;

setting the casing packer between the production tubing and the cased vertical section;

deploying an electric submersible pumping system in the cased vertical section of the wellbore above the casing packer and external to the production tubing;

installing coiled tubing through an interior of the production tubing such that the coiled tubing extends into the horizontal section of the wellbore; locating a gas lift valve along the coiled tubing and in communication with the coiled tubing at a position in the horizontal section of the wellbore; and

setting a packer between the production tubing and the coiled tubing above the casing packer.

18. The method as recited in claim 17, further comprising providing the production tubing with a perforated section located below the packer.

19. The method as recited in claim 18, further comprising using a Y-tool to direct a pumped fluid from the electric submersible pumping system to an annulus between the coiled tubing and the production tubing.

20. The method as recited in claim 18, further comprising injecting a lift gas through the gas lift valve to produce a well fluid up to the electric submersible pumping system.