EP4584475A1

EP4584475A1 - Esp recirculation system with gas separation

Info

Publication number: EP4584475A1
Application number: EP23875529.2A
Authority: EP
Inventors: Daniel LEMOS; Leandro NEVES; Jorge Luiz BIAZUSSI
Original assignee: Baker Hughes Oilfield Operations LLC
Current assignee: Baker Hughes Oilfield Operations LLC
Priority date: 2022-10-05
Filing date: 2023-10-05
Publication date: 2025-07-16
Also published as: EP4584475A4; WO2024076701A1

Abstract

A submersible pumping system is designed to handle the production of two-phase fluids from a subterranean well. In some embodiments, the pumping systems include a combination of elements that are configured to separate gas from the two-phase fluid and provide a recirculated stream of liquid-dominant fluid to the intake of the pumping system. The pumping system includes a gas handler pump, a production pump and a liquid separator. In some embodiments, the pumping system also includes a gas separator. In other embodiments, the pumping system is encapsulated such that the motor, gas handler pump, production pump and liquid separator are contained within a common capsule. The disclosed pumping systems can be configured for onshore or offshore applications.

Description

ESP RECIRCULATION SYSTEM WITH GAS SEPARATION

Related Applications

[001] This application claims the benefit of United States Provisional Patent Application Serial No. 63/413,595 filed October 5, 2022 entitled, “ESP Recirculation System with Gas Separation,” the disclosure of which is herein incorporated by reference.

Field of the Invention

[002] This invention relates generally to the field of downhole pumping systems, and more particularly to systems and methods for optimizing pumping operations in wells with a high gas-to-liquid ratio.

Background

[003] Submersible pumping systems are often deployed into wells to recover petroleum fluids from subterranean reservoirs. Typically, a submersible pumping system includes a number of components, including an electric motor coupled to one or more pump assemblies. Production tubing is connected to the pump assemblies to deliver the wellbore fluids from the subterranean reservoir to a storage faci li ty on the surface. In many cases, the pump assemblies are multistage centrifugal pumps that include a plurality of stages, with each stage including a stationary diffuser and a rotary impeller that is connected to a shaft driven by the electric motor.

[004] Hydrocarbon fluids produced from subterranean wells often include liquids and gases. Although both may be valuable, the multiphase flow may complicate recovery efforts. For example, naturally producing wells with elevated gas fractions may overload phase separators located on the surface. This may cause gas to be entrained in fluid product lines, which can adversely affect downstream storage and processing. [005] In wells in which artificial lift solutions have been deployed, excess amounts of gases and solids in the wellbore fluid can present problems for downhole equipment that is primarily designed to produce liquid-phase products. In particular, a high gas-to-liquid ratio ("GLR") or gas volume fraction C'GVE”) may adversely impact efforts to recover liquid hydrocarbons with pumping equipment. Liquid "slugging" occurs when large pockets of gas alternated with liquid slugs develop while the fluid flows to surface.

[006] The centrifugal forces exerted by downhole turbomachinery tend to separate gas from liquid, thereby increasing the chances of gas interference or vapor lock. Downhole gas separators have been used to remove gas before the wellbore fluids enter the pump. In operation, wellbore fluid is drawn into the gas separator through an intake. A lift generator provides additional lift to move the wellbore fluid into an agitator. The agitator is typically configured as a rotary paddle that imparts centrifugal force to the wellbore fluid. As the wellbore fluid passes through the agitator, heavier components, such as oil and water, are carried to the outer edge of the agitator blade, while lighter components, such as gas, remain close to the center of the agitator. In this way, modem gas separators take advantage of the relative difference in specific gravities between the various components of the two-phase wellbore fluid to separate gas from liquid. Once separated, the liquid can be directed to the pump assembly and the gas vented from the gas separator.

[007] Although generally effective, these prior art downhole gas separators may nonetheless be insufficient for wells with very high gas volume fractions. There is, therefore, a need for an improved gas separator system that provides gas separation functionality over an extended range of applications. Summary of the Invention

[008] In some embodiments, the present disclosure is directed to a submersible pumping system for producing a fluid from a wellbore through production tubing to a wellhead, where the pumping system includes a gas handler pump, a motor that drives the gas handler pump, and a gas separator connected upstream from the gas handler pump. The gas separator is configured to discharge a primarily gaseous stream into the wellbore. The pumping system further includes a liquid separator connected downstream from the discharge of the gas handler pump. The liquid separator is configured to discharge a primarily liquid stream into the wellbore. The pumping system also includes a production pump downstream from the liquid separator.

[009] In other embodiments, the present disclosure is directed at a submersible pumping system for producing a fluid from a wellbore through production tubing to a wellhead, where the pumping system includes a capsule that encapsulates the pumping system, an intake, a gas handler pump downstream from the intake, a production pump connected to the production tubing, and a liquid separator connected between the gas handler pump and the production pump. The liquid separator is configured to discharge a primarily liquid stream into capsule in proximity to the intake and to provide the production pump with a reduced gas fraction fluid. The pumping system includes a motor that drives the gas handler pump and the production pump.

[010] In yet other embodiments, the present disclosure is directed to a submersible pumping system for producing two-phase fluids from a well located beneath a body of water through production tubing to a production platform located on the surface of the body of water. In these embodiments, the submersible pumping system includes a first pump subassembly that includes a first intake, a first gas handler pump downstream from the first intake, a first production pump downstream from the first gas handler pump, and a first liquid separator connected between the first gas handler pump and the first production pump. The first liquid separator is configured to recirculate a primarily liquid stream to the first intake and to provide the first production pump with a reduced gas fraction fluid. The first pump subassembly further includes a first motor that drives the first gas handler pump and the first production pump and a first capsule that encapsulates the first intake, the first gas handler pump, the first production pump, the first liquid separator and the first motor.

[Oi l] In some embodiments, the underwater submersible pumping system further includes a second pump subassembly that also includes a second intake, a second gas handler pump downstream from the second intake, a second production pump downstream from the second gas handler pump and connected to the production tubing, a second liquid separator connected between the second gas handler pump and the second production pump, a second motor that drives the second gas handler pump and the second production pump, and a second capsule that encapsulates the second intake, the second gas handler pump, the second production pump, the second liquid separator and the second motor. The second liquid separator is configured to recirculate a primarily liquid stream to the second intake and to provide the second production pump with a reduced gas fraction fluid.

Brief Description of the Drawings

[012] FIG. 1 depicts an electric submersible pumping system constructed in accordance with a first embodiment of the present disclosure.

[013] FIG. 2 depicts an electric submersible pumping system constructed in accordance with a second embodiment of the present disclosure. [014] FIG. 3 depicts an electric submersible pumping system constructed in accordance with a third embodiment of the present disclosure.

[015] FIG. 4 depicts an electric submersible pumping system constructed in accordance with a fourth embodiment of the present disclosure, where the electric submersible pumping system is a skid-mounted variant suited for deployment in an underwater environment.

[016] FIG. 5 depicts an embodiment of the electric submersible pumping system of FIG. 4 in which both pump subassemblies include a liquid recirculation system.

[017] FIG. 6 depicts an embodiment of the electric submersible pumping system of FIG. 4 in which only the first pump subassembly includes a liquid recirculation system.

Writen Description

[018] As used herein, the term "petroleum" refers broadly to all mineral hydrocarbons, such as crude oil, gas and combinations of oil and gas. The term “fluid” refers to both gases and liquids and the term “two-phase” refers to a fluid that includes a mixture of gases and liquids. It will be appreciated by those of skill in the art that, in the downhole environment, a two-phase fluid may also carry solids and suspensions. Accordingly, as used herein, the term “two-phase” not exclusive of fluids that contain liquids, gases, solids, or other intermediary forms of matter.

[019] FIG. 1 depicts a pumping system 100 attached to production tubing 102. The pumping system 100 and production tubing 102 are disposed in a wellbore 104, which is drilled for the production of a fluid such as water or petroleum. The production tubing 102 connects the pumping system 100 to a wellhead 106 located on the surface. Although the pumping system 100 is primarily designed to pump petroleum products, it will be understood that the present invention can also be used to move other fluids. It will also be understood that, although each of the components of the pumping system are primarily disclosed in a submersible application, some or all of these components can also be used in surface pumping operations. Although the pumping system 100 is disclosed in a vertical deployment, it will be appreciated that the pumping system 100 can also be deployed in horizontal and other non-vertical wellbores.

[020] For the purposes of the disclosure herein, the terms “upstream” and “downstream” shall be used to refer to the relative positions of components or portions of components with respect to the general flow of fluids produced from the wellbore. “Upstream” refers to a position or component that is passed earlier than a “downstream” position or component as fluid is produced from the wellbore 104. The terms “upstream” and “downstream” are not necessarily dependent on the relative vertical orientation of a component or position. It will be appreciated that many of the components in the pumping system 100 are substantially cylindrical and have a common longitudinal axis that extends through the center of the elongated cylinder and a radius extending from the longitudinal axis to an outer circumference. Objects and motion may be described in terms of axial, longitudinal, lateral, or radial positions within components in the pumping system 100.

[021] In the embodiment depicted in FIG. 1, the pumping system 100 includes a gas handler pump 108, a motor 110, a seal section 112, a production pump 114, a gas separator 116 and a liquid separator 118. The seal section 112 is connected to a dow nstream end of the motor 110. The seal section 112 is positioned between the motor 110 and the gas separator 116. The gas handler pump 108 is located between the gas separator 116 and the liquid separator 118. In the embodiment depicted in FIG. 1, the production pump 1 14 is connected to a downstream end of the liquid separator 118.

[022] The seal section 112 shields the motor 110 from mechanical thrust and accommodates the expansion of motor lubricants during operation. The seal section 112 and motor 110 can be presented as a single, integrated unit or as two distinct components connected together. The motor 110 receives electrical power through a power cable 120 connected to a power source and motor drive system on the surface. When energized, the motor 110 transfers torque to the gas handler pump 108, production pump 114 and other rotating components within the pumping system 100. The motor 110 can be an induction motor or a permanent magnet motor. The motor pumping system 100 optionally includes a gauge or sensor 122 that is configured to measure various conditions in the wellbore 104, including but not limited to temperature, pressure, vibration, and operating conditions within the motor 110. The annular space surrounding the pumping system 100 and production tubing 102 in the wellbore 104 is referred to herein as the wellbore annulus 124.

[023] In the embodiment depicted in FIG. 1, the pumping system 100 includes an intake 126 between the seal section 112 and the gas separator 116. The intake 126 provides a path for fluids from the wellbore annulus 124 to enter the pumping system 100. In some embodiments, the intake 126 is integrated into the gas separator 116. In other embodiments, the intake 126 is presented as an independent component connected between the gas separator 116 and the seal section 112, as illustrated in FIG. 1.

[024] The gas separator 116 is generally configured to remove a portion of the gas from the two-phase fluid entering the pumping system 100 through the intake 126. The gas separator 116 includes an internal phase separation mechanism 128 (shown in cutaway view) and a gas discharge 130. The internal phase separation mechanism 128 can be an active agitator system driven by a shaft connected to the motor 110 (as shown), or a passive, vortex-inducing element that relies on the movement of fluid by the pump 108, or a combination of active (driven) and passive separation systems. In each case, the internal phase separation mechanism 128 can be configured to induce a rotation of the multiphase fluid which tends to force heavier liquids radially outward while lighter gases remain nearer to the axial center of the first stage gas separator 122. The internal phase separation mechanism 128 can include a crossover 132 or similar device to direct the lighter gaseous components from the interior of the first stage gas separator 122 to the gas discharge 130, while permitting the denser fluids to pass through the crossover 132 into the intake 114 of the gas handler pump 108.

[025] Thus, wellbore fluids are drawn into the gas separator 116 through the intake 126, where the internal phase separation mechanism 128 separates the gaseous and liquid components. Gas released by the internal phase separation mechanism 128 is discharged through the gas discharge 130 into the wellbore annulus 124. The remaining liquid and entrained gaseous components are directed from the gas separator 116 to the gas handler pump 108. In exemplar}' embodiments, the connection between the gas separator 116 and the gas handler pump 108 is closed such that fluids from the wellbore 104 must pass through the gas separator 116 before entering the gas handler pump 108.

[026] The gas handler pump 108 is a multistage centrifugal pump that includes a plurality of stages that each include a stationary diffuser and a rotatable impeller connected to a pump shaft driven by the motor 110. The impellers and diffusers within the gas handler pump 108 can be configured to homogenize and reduce the volume of gas entrained in the fluid discharged from the gas separator 116. The gas handler pump 108 increases the pressure of the pumped fluids in accordance with well-established pump mechanics in which kinetic energy is imparted to the fluid by the rotating impellers, which is then converted in part to pressure head by the stationary diffusers. As the pressure of the fluid increases through the successive stages of the gas handler pump 108, the gases and liquids are blended together and the increased pressure reduces the volume of gases entrained in the fluid.

[027] The pressurized fluids are forced from the gas handler pump 108 into the liquid separator 118. The liquid separator 118 can be connected directly to the gas handler pump 108 or through intermediate components. The liquid separator 118 includes an internal phase separation mechanism 134. an axial gathering tube 136 and a recirculation tube 138. The internal phase separation mechanism 134 can be an active agitator system driven by a shaft connected to the motor 110 (as shown), or a passive, vortex-inducing element that relies on the movement of fluid by the pump 108 (as depicted in FIG. 3), or a combination of active (driven) and passive separation systems. In each case, the internal phase separation mechanism 134 can be configured to induce a rotation of the multiphase fluid which tends to force heavier liquids outward while lighter gases remain nearer to the axial center of the liquid separator 124.

[028] The axial gathering tube 136 collects a portion of the lighter fluids present in the central part of the liquid separator 118 and directs these fluids to the production pump 114. A portion of the heavier components forced radially outward by the internal phase separation mechanism 134 are passed into the recirculation tube 138. The recirculation tube 138 directs the denser liquid-dominant fluids with minimal gas content toward the lower end of the pumping system 100, or the motor 110, the gas separator 116, the intake 126 or gas handler pump 108. In exemplary' embodiments, the recirculation tube 138 includes a recirculation tube discharge 140 that is located in close proximity to, or connected with, the intake 126. Placing the recirculation tube discharge 140 near the motor 110 may aid in convectively cooling the motor 110. In each case, directing a recirculated flow of liquid-enriched fluids to the intake 126 further reduces the overall gas fraction of fluids entering the intake f26 and reduces the risk that the gas handler pump 108 or production pump 114 lose prime during a slugging event.

[029] Thus, the pumping system 100 relies on both the gas separator 116 and the liquid separator 118, where the gas separator 116 separates excess gas from a multiphase wellbore fluid and discharges the excess gas to the wellbore annulus 124 through the gas discharge 130. The liquid separator 118 separates denser liquids from the fluid discharged by the gas handler pump 108 and returns a portion of the liquid- enriched fluid to the intake 126 through the recirculation tube 138. In this way, the gas separator 116, the gas handler pump 108 and the liquid separator 118 cooperate to provide a fluid phase management system with a partial liquid recycle that ultimately improves the performance of the production pump 114 by reducing the gas fraction of the fluid entering the production pump 114.

[030] Turning to FIG. 2, shown therein is a second embodiment of the pumping system 100 in which the liquid separator 118 further includes a control valve 142 that can be selectively actuated to block or reveal the recirculation tube 138 from the liquid separator 118. In a first position, the control valve 142 permits fluid in the liquid separator 118 to enter into the recirculation tube 138. In a second position, the control valve 142 prevents fluid from entering the recirculation tube 138. When the control valve 142 blocks the recirculation tube 138, all of the fluid discharged by the liquid separator 118 is directed into the production pump 114. In some embodiments, the control valve 142 is a hydraulically-actuated sliding sleeve that receives a control signal, i.e., an increase or decrease in pressure, from a control module 144 located on the surface through a control line 146. In other embodiments, the control valve 142 is electrically, pneumatically, or mechanically actuated. In some embodiments, the control valve 142 is automatically controlled in response to a change in the gas content present in the liquid separator 118. In some embodiments, the control valve 142 permits proportional control with a range of throttled positions between full open and full closed.

[031] In some embodiments, the control valve 142 is controlled by a unified control system that also controls the operation of the motor 110 with inputs provided by the sensor 122. For example, if the sensor 122 detects the presence of a large gas slug, the sensor can inform the control module 144. which can place the control valve 142 in an open state to permit liquid-enriched fluids to be recirculated to the pump 108 through the recirculation tube 138.

[032] Turning to FIG. 3, shown therein is a third embodiment of the pumping system 100. In the embodiment depicted in FIG. 3, the pumping system 100 includes a closed capsule 148 that encapsulates the motor 110, seal section 112, intake 126, gas handler pump 108, liquid separator 118, and production pump 114. The capsule 148 includes a bottom intake tube 150 that admits fluid from the wellbore 104 into the capsule 148. The capsulel48 permits the pumping system 100 to be used in a variety⁷ of applications, including in “sumped"’ applications in which the motor 110 is located below the perforations that place the wellbore 104 in fluid communication with the surrounding producing geologic formations. In this embodiment, the pumping system 100 does not include the gas separator 116, unless the capsule 148 includes a venting mechanism for releasing gas discharged inside the capsule 148 by the gas separator 116. In some embodiments, the capsule 148 is replaced by upper and lower packers that are positioned above and below the pumping system 100 to isolate the pumping system 100 within the wellbore 104.

[033] Turning to FIG. 4, shown therein is an embodiment in which the pumping system 100 is configured for deployment in connection with the recovery of fluids when the wellbore 104 is located in an offshore or other underwater environment. In this embodiment, the pumping system 100 is mounted on a skid assembly 152 that is designed to deploy the pumping system 100 on the floor of the body of water. The pumping system 100 is connected to the wellhead 106 through an intake line 154. As illustrated in FIG. 4, the wellbore 104 can include a separate artificial lift system 156, which may include a separate electric submersible pumping system (as shown). The pumping system 100 delivers the pumped fluids from the wellbore 104 to a production platform 158 through the production tubing 102.

[034] Turning to FIGS. 5 and 6, shown therein are depictions of the pumping system 100 from FIG. 4. In the embodiment depicted in FIG. 5, the pumping system 100 includes two pump subassemblies 160a, 160b that each include a motor 110, a seal section 112, a gas handler pump 108, an intake 126, a liquid separator 118, and a production pump 114, which are encapsulated in a capsule 148. The two pump subassemblies 160a, 1 0b are connected to one another by a common manifold 162. In some embodiments, the production pump 114 of the first pump subassembly 160a is connected to the manifold 162, which in turn is connected to the capsule 148 of the second pump subassembly 160b. In each pump subassembly 160a, 160b, the liquid separators 118 optionally include a control valve 142 that can be toggled to adjust the recirculation of liquid-dominant fluids within the capsules 148 to reduce the gas fraction of fluids entering the intakes 126. In each pump subassembly 160a, 160b, the combination of the gas handler pumps 108, the liquid separators 116 and the recirculation tubes 138 cooperate to minimize the risk of gas lock caused by surges of gas from the wellbore 104. It will be appreciated that in certain embodiments, the pumping system 100 includes a single pump subassembly 160 and that in other embodiments the pumping system 100 includes two or more pump subassemblies 160 connected together through two or more manifolds 162.

[035] In the embodiment depicted in FIG. 6, the first pump subassembly 160a includes the motor 110, seal section 112, intake 126, liquid separator 118, gas handler pump 108. and production pump 114, which are encapsulated in a capsule 148. However, unlike the embodiment depicted in FIG. 5, the second pump subassembly 160b does not include the gas handler pump 108 or the liquid separator 118. In this embodiment, the gas management function is managed by the first pump subassembly 160a and the liquid separator 118 and gas handler pump 108 are not required in the second pump subassembly 160b.

[036] It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed. It will be appreciated by those skilled in the art that the teachings of the present invention can be applied to other systems without departing from the scope and spirit of the present invention.

Claims

What is claimed is:

1. A submersible pumping system for producing a fluid from a wellbore through production tubing to a wellhead, the pumping system comprising: a gas handler pump; a motor that drives the gas handler pump; a gas separator connected upstream from the gas handler pump, wherein gas separator is configured to discharge a primarily gaseous stream into the wellbore; a liquid separator connected downstream from the discharge of the gas handler pump, wherein the liquid separator is configured to discharge a primarily liquid stream into the wellbore; and a production pump downstream from the liquid separator.

2. The submersible pumping system of claim 1, wherein the liquid separator comprises a recirculation tube that discharges the primarily liquid stream into the wellbore in a location below the gas handler pump.

3. The submersible pumping system of claim 2, wherein the liquid separator comprises a control valve that selectively blocks fluids from entering the recirculation tube.

4. The submersible pumping system of claim 1, wherein the stage gas separator comprises: a gas discharge in fluid communication with the wellbore; an internal phase separation mechanism; and a crossover configured to direct gases separated by the internal phase separation mechanism to the gas discharge.

5. The submersible pumping system of claim 4, wherein the internal phase separation mechanism is driven by the motor.

6. The submersible pumping system of claim 1, wherein the liquid separator comprises: an internal phase separation mechanism; a recirculation tube; and an axial gathering tube, wherein the axial gathering tube is configured to remove lighter fluids through the production tubing while diverting heavier fluids to the recirculation tube.

7. The submersible pumping system of claim 6, wherein the recirculation tube is configured to discharge the heavier fluids into the wellbore in a location below the gas handler pump.

8. The submersible pumping system of claim 6, wherein the liquid separator comprises a control valve that selectively blocks fluids from entering the recirculation tube.

9. A submersible pumping system for producing a fluid from a wellbore through production tubing to a wellhead, the pumping system comprising: a capsule that encapsulates the pumping system; an intake; a gas handler pump downstream from the intake; a production pump connected to the production tubing; a liquid separator connected between the gas handler pump and the production pump, wherein the liquid separator is configured to discharge a primarily liquid stream into capsule in proximity to the intake and to provide the production pump with a reduced gas fraction fluid; and a motor that drives the gas handler pump and the production pump.

10. The submersible pumping system of claim 9, wherein the capsule includes a bottom intake tube.

11. The submersible pumping system of claim 9, wherein the liquid separator comprises a recirculation tube that discharges the primarily liquid stream into the capsule upstream from the gas handler pump.

12. The submersible pumping system of claim 11, wherein the liquid separator comprises a control valve that selectively blocks fluids from entering the recirculation tube.

13. The submersible pumping system of claim 12, wherein the liquid separator comprises: an internal phase separation mechanism; and an axial gathering tube, wherein the axial gathering tube is configured to remove lighter fluids through the production tubing while diverting heavier fluids to the recirculation tube.

14. The submersible pumping system of claim 13, wherein the internal phase separation mechanism is driven by the motor.

15. The submersible pumping system of claim 14, wherein the internal phase separation is a passive separation mechanism that comprises a plurality of spiraled flights.

16. A submersible pumping system for producing two-phase fluids from a well located beneath a body of water through production tubing to a production platform located on the surface of the body of water, the submersible pumping system comprising: a first pump subassembly, wherein the first pump subassembly comprises: a first intake; a first gas handler pump downstream from the first intake; a first production pump downstream from the first gas handler pump; a first liquid separator connected between the first gas handler pump and the first production pump, wherein the first liquid separator is configured to recirculate a primarily liquid stream to the first intake and to provide the first production pump with a reduced gas fraction fluid; a first motor that drives the first gas handler pump and the first production pump; and a first capsule that encapsulates the first intake, the first gas handler pump, the first production pump, the first liquid separator and the first motor.

17. The submersible pumping system of claim 16, wherein the submersible pumping system further comprises: a second pump subassembly, wherein the second pump subassembly comprises: a second intake; a second production pump connected to the production tubing; a second motor that drives the second production pump; and a second capsule that encapsulates the second intake, the second production pump, and the second motor.

18. The submersible pumping system of claim 17, wherein the first production pump and the second capsule are each connected to a common manifold.

19. The submersible pumping system of claim 17, wherein the second pump subassembly further comprises: a second gas handler pump upstream from the second production pump; and a second liquid separator connected between the second gas handler pump and the second production pump, wherein the second liquid separator is configured to recirculate a primarily liquid stream to the second intake and to provide the second production pump with a reduced gas fraction fluid.

20. The submersible pumping system of claim 17, wherein the first and second pump subassemblies are each attached to a common skid assembly.